TABLE OF CONTENTS

1 PRESSURE BASICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 2 KICK FUNDAMENTALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 3 DETECTION OF KICKS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 4 KICK THEORY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 5 PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 6 WELL CONTROL BASICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 7 WELL CONTROL METHODS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 8 COMPLICATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 9 FLUIDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-1 10 SURFACE EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-1 11 SUBSEA WELL CONTROL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11-1 12 SPECIAL TOPICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-1 13 REMEDIAL OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-1 14 SUBSURFACE EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-1 15 COILED TUBING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15-1 16 SNUBBING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16-1 17 WIRELINE UNITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17-1 18 MMS REGULATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18-1 19 SIMULATOR EXERCISES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19-1 GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G-1 INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1 ILLUSTRATION/PHOTO CREDITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-7

WCS – Well Control School expresses thanks to all companies and individuals contributing to this text. Material contained here, by general consensus of those involved in the course development, is based on the best sources of knowledge available to the authors. WCS does not warrant or guarantee any procedures or information presented in this text. By the very nature of the oil industry, procedures, equipment, standards and practices vary widely. It is not the intent of WCS to endorse policies and procedures, but rather to communicate to readers generally accepted practices.

© NOVEMBER 2002 WCS – WELL CONTROL SCHOOL

ALL RIGHTS RESERVED

PHONE: 5O4•361•8282 FAX: 5O4•361•5551

EMAIL: staff@wellcontrol.com WEBSITE: www.wellcontrol.com

WELL CONTROL SCHOOL • 2600 MOSS LANE • HARVEY, LOUISIANA 7OO58

INTRODUCTION

This manual was compiled for use as the primary text for blowout prevention courses conducted around the world by WCS – Well Control School. Its scope is broad, and recommendations or suggestions of good practices are designed to

meet or exceed the training requirements established by the U.S. Minerals Management Service (MMS) and the International Association of Drilling Contractors (IADC), as well as to address the knowledge base necessary to competently perform many of the skills required by the International Well Control Forum (IWCF). Additionally, WCS hopes that field personnel will find the book a useful and practical onsite reference, covering a wide range of accepted well control practices.

Every effort has been made to use standard or universal terminology. Still, common usage varies among different segments of the industry. The drilling hand’s drillpipe becomes the workover hand’s tubing. Terms remain consistent throughout chapters and meanings should be apparent within the context of the topic discussions.

The chapters of this book are arranged in the order of presentation for our MMS certified Drilling Well Control course, however each section of the manual stands alone. Candidates enrolled in courses other than drilling, for instance Workover/Well Servicing, may find themselves directed to sections of the text that appear to be out of sequence. This is unavoidable due to the comprehensive nature of the manual.

Numerical values and units of measure appear in the English system. Metric equivalents are enclosed in parentheses following the English value. Tables used for metric conversions in the text appear in Chapter Eighteen.

The mathematical formulas in Chapter Eighteen are presented lineally, that is, in the order in which values and operatives are entered into a hand-held calculator. In some cases this form of presentation may differ from accepted written mathematical formats. Our goal is for the learner to arrive at the correct answer in the simplest and most direct way regardless of his or her educational background.

A glossary, portions of the MMS publication CFR 30 which apply to well control and training regulations and special topics are also included. These chapters are intended to provide technical reference and useful information for industry workers across disciplines.

Although the manual is not intended to be a work of science, WCS is indebted to many engineers and scientists throughout the industry for technical advice and assistance. It is impossible to acknowledge on an individual basis all the companies and personnel who contributed materials to this compilation. It is our sincere hope that their thanks will come by way of the knowledge that in some way we have all helped to avert that greatest of all oilfield tragedies, the blowout. ö

CHAPTER

1

Remember to think

downhole. The concepts

provided in this section

cover the foundations for

good well control.

PRESSUREBASICS

U nderstanding pressure and pressure relationships is important if we are to understand well control. By defi-

nition, pressure is the force that is exerted or placed on a unit of area, such as pounds per square inch (psi). The pressures that we deal with daily in the oil industry include fluid, formation, friction and mechanical. When certain pressure limits are exceeded, disastrous consequences can result, including blowouts and/or the loss of life.

FLUID PRESSURE

What is a fluid? A fluid is simply some-thing that is not solid and can flow. Water and oil are obviously fluids. Gas is also a fluid.

1-1

CHAPTER 11-2

Under extreme temperature and/or pressure almost anything will become fluid. Under some conditions salt or rock become fluid. For our purposes, fluids that we will consider are those normally associated with the oil industry, such as oil, gas, water, muds, packer fluids, brines, completion fluids, etc.

Fluids exert pressure. This pressure is the result of the density of the fluid and the height of the fluid column. Density is usually mea-sured in pounds per gallon (ppg) or kilograms per cubic meter (kg/m³). A heavy fluid exerts more pressure because its density is greater.

The force or pressure that a fluid exerts at any given point is usually measured in pounds per square inch (psi) or in the metric system, bar. To find out how much pressure a fluid of a given density exerts for each unit of length, we use a pressure gradient.

A pressure gradient is normally expressed as the force which the fluid exerts per foot (meter) of depth; it is measured in pounds per square inch per foot (psi/ft) or bars per meter (bar/m). To get the pressure gradient we must convert the fluid’s density in pounds per gal-lon to pounds per square inch per foot (or kilograms per cubic meter, kg/m³ to bar/m).

DENSITY CONVERSION FACTOR

The conversion factor used to convert density to pressure gradient in the English system is 0.052. In the metric system, it is 0.0000981. Remember that the definition of pressure gradient is the pressure increase per unit of depth due to its density. For our text, we will use pounds per gallon (ppg) to measure density and feet (ft) for depth measurements in the English system and kilograms per cubic meter (kg/m³) to measure density and meters (m) for depth measurements in the metric system.

The way 0.052 is derived is by using a one-foot cube (one foot wide by one foot long by one foot high). It takes about 7.48 gallons to fill the cube with fluid. If the fluid weighs one pound per gallon, and you have 7.48 gallons, then the total weight of the cube is 7.48 pounds, or 7.48 pounds per cubic foot. The weight of one of these square inches, one foot in height, can be found by dividing the total weight of the cube by 144:

7.48 ÷ 144 = 0.051944 The conversion factor 0.052 is commonly

used for oilfield calculations.

Pressure

Fluid

Pressure(Force)

Pressure(Force) What is pressure?

Pressure:1: the force

per unit area that is exerted

on a surface.2: the force that a fluid

exerts when it is in some way

confined within a vessel.

PRESSURE BASICS1-3

PRESSURE GRADIENT

To find the pressure gradient of a fluid, multiply the density of the fluid by 0.052; or in metrics, by 0.0000981.

Pressure Gradient = Fluid Density × Conversion FactorSo the pressure gradient of a 10.3 ppg (1234 kg/m³) fluid can be found by multiplying the fluid weight by the conversion factor.

Pressure Gradientpsi/ft = Fluid Densityppg × Conversion Factor = 10.3 ppg × 0.052 = 0.5356 psi/ft

Pressure Gradientbar/m = Fluid Densitykg/m³ × Conversion Factor = 1234 kg/m³ × 0.0000981 = 0.1211 bar/m

EXAMPLE 1What is the pressure gradient of a fluid with a density of 12.3 ppg (1474 kg/m³)?

Pressure Gradientpsi/ft = Fluid Densityppg × Conversion Factor = 12.3 X 0.052 = 0.6396 psi/ft

Pressure Gradientbar/m = Fluid Densitykg/m³ × Conversion Factor = 1474 X 0.0000981 = 0.1446 bar/m

PROBLEM 1A

What is the pressure gradient of a fluid that weighs 9.5 ppg (1138 kg/m³)?

Pressure Gradientpsi/ft =Fluid Densityppg X Conversion Factor

Pressure Gradientbar/m =Fluid Densitykg/m³ X Conversion Factor

PROBLEM 1B

What is the pressure gradient of fresh water which weighs 8.33 ppg (998 kg/m³)?

If a fluid weighsone pound per gallon, the

weight of one square inch in a one foot length is 0.052 lbs.

1'

1'

1'

To calculate pressure at the bottom of a well use true vertical depth.

1-4

TVD VS. MD

Once we know how to find pressure exerted per foot, we can calculate the hydrostatic pressure at a given depth. All we have to do is multiply the pressure gradient by the number of feet to that vertical depth. Here we have to learn the distinction between measured depth (MD) and true vertical depth (TVD).

In the illustration below you can see that the depth straight down (the way that gravity pulls) for both wells is 10,000 ft (3048 m). Well A has a measured depth of 10,000 ft (3048 m), and a true vertical depth of 10,000 ft (3048 m). Since gravity pulls straight down, along a true vertical (straight down) path, to calculate the pressure at the bottom of the hole we use the 10,000 ft (3048 m) depth.

Well B has a measured depth of 11,650 ft (3550.92 m), and its true vertical depth is 10,000 ft (3048 m). Gravity still pulls straight down, not along the path of the well. You would have a vertical depth of 10,000 ft (3048 m) from the surface straight down to where the well ended. Therefore, to calculate the pressure at the bottom of Well B, you have to use the true vertical depth of 10,000 ft (3048 m).

The illustration on page 1-5 offers another way of looking at the difference between true vertical depth and measured depth. In this illustration, we have a picture of square blocks, 15 by 10. Count how many blocks the well covers. This represents the measured depth of the well. Now, count the blocks from the bottom of the well, straight up to surface. The numbers of these blocks represent true vertical depth.

HYDROSTATIC PRESSURE

Hydrostatic pressure is the total fluid pressure created by the weight of a column of fluid, acting on any given point in a well. Hydro means water, or fluid, that exerts pressure like water, and static means not moving. So hydrostatic pressure is the pressure created by the density and height of a stationary (not moving) column of fluid.

We already know how to calculate a pressure gradient from the fluid’s weight. Hydrostatic pressure can be calculated from a pressure gradient to a given point:

Hydrostatic Pressure =Pressure Gradient × DepthTVD

Or, it may be calculated by:

Hydrostatic Pressure = Fluid Density × Conversion Factor × DepthTVD

MD and TVD

10,000'

10.0 PPG M

UD

Well A Well B

10.0 PPG MUD 11, 650' MD

True vertical depth vs. measured depth.

Hydrostatic pressure:

force exerted by a body of

fluid at rest; increases

directly with the weight and

length of the fluid column.

CHAPTER 1

1-5

EXAMPLE 2

What is the hydrostatic pressure at the bottom of a well which has a fluid density of 9.2 ppg (1102 kg/m³), a MD of 6,750’ (2057.4 m) and a TVD of 6,130’ (1868.42 m)?

Remember, the formula for calculating hydrostatic pressure is:

Hydrostatic Pressurepsi = Fluid Densityppg × Conversion Factor × Depthft, TVD = 9.2 × 0.052 × 6,130 = 2,933 psi

Hydrostatic Pressurebar = Fluid Densitykg/m³ × Conversion Factor × Depthm, TVD = 1102 × 0.0000981 × 1868.42 = 201.99 bar

PROBLEM 2A

Find the hydrostatic pressure at the bottom of a well with a 9.7 ppg (1162 kg/m³) fluid in it and a MD of 5,570’ (1697.74 m) and TVD of 5,420’ (1651.02 m).

Hydrostatic Pressurepsi = Fluid Densityppg × 0.052 × Depthft, TVD

Hydrostatic Pressurebar = Fluid Densitykg/m³ × 0.0000981 × Depthm, TVD

PROBLEM 2B

Find the hydrostatic pressure at 4,300’ (1310.64 m) TVD, of a well with fluid density of 16.7 ppg (2001 kg/m³). The well has a MD of 14,980’ (4565.9 m) and a TVD of 13,700’ (4175.76 m).

The above equations for fluid gradient and hydrostatic pressure are basic to understanding the fundamentals of pressure in wells. To prevent the well from flowing, fluid pressure in the

well must at least equal the formation pressure.

Although a gauge placed at the bottom of a fluid column would read the hydrostatic pressure of that column, it also would read the atmospheric pressure exerted on the column. This pressure varies with weather conditions and elevation and is normally considered 14.7 psi or 15 psi (approximately one bar) at sea level. If a gauge has a unit notation of psig, it includes the atmospheric column above it. If gauge reads in psig, it has been calibrated to subtract the atmospheric column above it.

MD

TVD

True vertical depth vs.

measured depth.

Atmospheric pressure at sea level is about 15 psi; the metric equivalent is approximately one bar.

PRESSURE BASICS

GAUGE/ATMOSPHERIC PRESSURE

U-TUBE

It is often helpful to visualize the well as a U-tube (see above). One column of the tube represents the annulus and the other column represents the pipe in the well. The bottom of the U-tube represents the bottom of the well.

In most cases, there are fluids creating hydrostatic pressures in both the pipe and annulus. Atmospheric pressure can be omitted, since it works the same on both columns. If there were 10 ppg (1198 kg/m³) fluid in both the pipe and annulus, hydrostatic pressures would be equal and the fluid would be static on both sides of the tube.

However, what will happen if fluid in the annulus is heavier than the fluid in the string? The heavier fluid in the annulus exerting more pressure downward will flow into the string, displacing some of the lighter fluid out of the string, causing a flow at surface. The fluid level will fall in the annulus, equalizing pressures.

When there is a difference in the hydro-static pressures, the fluid will try to reach balance point. This is called U-tubing, and it explains why there is often flow from the

pipe when making connections. This is often evident when drilling fast because the effective density in the annulus is increased by cuttings.

Another example of U-tubing is when a slug is pumped. The heavier slug is designed to allow tubing to pull dry by falling to a level below the average length of stand pulled. The depth where the slug will fall and the amount of fluid that U-tubes from the well can be calculated using the following equations:

Gain In Pits =(Slug Weight – Annulus Weight) ×Volume of Slug ÷ Annulus Weight

Distance of Drop =Gain in Pits ÷ Pipe Capacity

EXAMPLE 3What will be the gain in the pits, and how far will the slug fall if the mud weight is 10 ppg (1198 kg/m³), the pipe’s capacity is 0.0178 bbl/ft (0.00929 m³/m)? The volume of the slug is 30 bbls (4.77 m³) and weighs 11 ppg (1318 kg/m³).

Annulus

U–Tube Analogy

Annulus

String

String Higher densityfluid

U–Tubing

U–Tubing

U-tubing:the tendency

of liquids to seek a pressure balance point

in an open well.

CHAPTER 11-6

Gain In Pitsbbls = (Slug Weightppg – Annulus Weightppg) × Volume of Slugbbls ÷ Annulus Weightppg

= (11 – 10) × 30 ÷ 10 = 1 × 30 ÷ 10 = 3 bblsDistance of Dropft = Gain In Pitsbbls ÷ Pipe Capacitybbls/ft

= 3 ÷ 0.0178 = 168.5 ft

Gain In Pitsm³ = (Slug Weightkg/m³ – Annulus Weightkg/m³) × Volume of Slugm³ ÷ Annulus Weightkg/m³

= (1318 - 1198) × 4.77 ÷ 1198 = 120 X 4.77 ÷ 0.00929 ÷ 1198 = 0.478 m³

Distance of Dropm = Gain In Pitsm³ ÷ Pipe Capacitym³/m

= 0.478 ÷ 0.00929 = 51.45 m

PROBLEM 3What will be the gain in the pits, and how far will the slug fall if the mud weight is 11.6 ppg (1390 kg/m³), the pipe’s capacity is 0.00579 bbl/ft (0.00302 m³/m)? The volume of the slug is 15 bbls (2.39 m³) and weighs 12.4 ppg (1486 kg/m³). Gain In Pitsbbls = (Slug Weightppg – Annulus Weightppg) × Volume of Slugbbls ÷ Annulus Weightppg

Distance of Dropft = Gain In Pitsbbls ÷ Pipe Capacitybbls/ft

Gain In Pitsm³ = (Slug Weightkg/m³ – Annulus Weightkg/m³) × Volume of Slugm³ ÷ Annulus Weightkg/m³

Distance of Dropm = Gain In Pitsm³ ÷ Pipe Capacitym³/m

Two important characteristics of reservoir rocks are porosity, tiny openings in rock (far left) and permeability, the connection of these holes which allows fluids to move (near left).

Porosity is the measurement of void space within a rock, expressed as a percentage.

PRESSURE BASICS1-7

1-8

FORMATION CHARACTERISTICS

Porosity and permeability, along with pres-sure differences, must be considered if we are to understand well control. A reservoir rock looks solid to the naked eye. A microscopic examina-tion reveals the existence of tiny openings in the rock. These openings are called pores. The porosity of the rock is expressed as a percentage. It is the ratio of void (pore) space to solid volume. Another characteristic of a reservoir rock is that it must be permeable. That is, the pores of the rock must be connected so hydro-carbons can move between them. Otherwise the hydrocarbons remain locked in place and cannot flow into a well.

FORMATION PRESSURE

Formation pressure is the pressure within the pore spaces of the formation rock. This pressure can be affected by the weight of the overburden (rock layers) above the formation, which exerts pressure on both the grains and pore fluids. Grains are solid or rock material, and pores are spaces between grains. If pore fluids are free to move, or escape, the grains lose some of their support and move closer together. This process is called compaction.

Normally pressured formations exert a pressure equal to a vertical column of native fluid from the formation to surface. The pressure gradient of the native fluid usually ranges from 0.433 psi/ft (0.0979 bar/m) to 0.465 psi/ft (0.1052 bar/m), and varies depending on the geologic region. Formations pressured in this range are designated normal, depending on the area. For simplicity, this text will designate a gradient of 0.465 psi/ft (0.1052 bar/m) as normal. In normally pressured formations most of the overburden weight is supported by the grains that make up the rock. When the overburden increases with depth, pore fluids are free to move and the amount of pore space is reduced due to compaction.

Abnormally pressured formations exert pressure greater than the hydrostatic pressure (or pressure gradient) of the contained formation fluid. When abnormally pressured formations develop, during the compaction phase, the pore fluid movement is restricted or stopped. The pore fluid pressure increases, generally exceeding 0.465 psi/ft (0.1052 bar/m). The result causes the increasing overburden weight to be partially supported by pore fluid rather than by the rock grains. Such formations may require working fluid densities up to, and sometimes greater than, 20 ppg (2397 kg/m³) to control them.

Abnormal pressures may be caused in other ways, including the presence of faults, salt domes, uplifting, and differences in elevation of underground formations. In many regions, hundreds of feet of pre-existing rock layers (overburden) have been stripped off by erosion. At the new, shallower depths this loss from erosion can cause the pressure to become abnormal, above 0.465 psi/ft (0.1052 bar/m), or 8.94 ppg (1072 kg/m³).

When a normally pressured formation is raised toward the surface while prevented from losing pore fluid in the process, it will change from normal pressure (at a greater depth) to abnormal pressure (at a shallower depth). When this happens, and then you drill into the formation, mud weights of up to 20 ppg (2397 kg/m³) may be required for control. This process accounts for many of the shallow, abnormally pressured zones in the world.

In areas where faulting is present, salt layers or domes are predicted, or excessive geothermal gradients are known, drilling operations may encounter abnormal pressure. An abnormally pressured formation can often be predicted using well history, surface geology, downhole logs or geophysical surveys.

Subnormally pressured formations have pressure gradients lower than fresh water, or less than 0.433 psi/ft (0.0979 bar/m). Naturally occurring subnormal pressure can be developed when the overburden has been stripped away, leaving the formation exposed at the surface.

Fracture pressure is the

amount of pressure it takes to permanently

deform the rock structure of a

formation.

CHAPTER 1

1-9

Depletion of original pore fluids through evaporation, capillary action and dilution produces hydrostatic gradients below 0.433 psi/ft (0.0979 bar/m). Subnormal pressures may also be induced through depletion of formation fluids.

FRACTURE PRESSURE

Fracture pressure is the amount of pressure it takes to permanently deform (fail or split) the rock structure of a formation. Overcoming formation pressure is usually not sufficient to cause fracturing. If pore fluid is free to move, a slow rate of entry into the formation will not cause fractures. If pore fluid cannot move out of the way, fracturing and permanent deformation of the formation can occur.

Fracture pressure can be expressed as a gradient (psi/ft), a fluid density equivalent (ppg), or by calculated total pressure at the formation (psi). Fracture gradients normally increase with depth due to increasing overburden pressure. Deep, highly compacted formations can require very high fracture pressures to overcome the

existing formation pressure and resisting rock structure. Loosely compacted formations, such as those found offshore in deep water, can fracture at low gradients. Fracture pressures at any given depth can vary widely because of the geology of the area.

FORMATION INTEGRITY TESTS

An accurate evaluation of a casing cement job as well as of the formation is extremely important during the drilling of a well and for subsequent work. The information resulting from Formation Integrity Tests (FIT) is used throughout the life of the well and also for nearby wells.

Casing depths, well control options, formation fracture pressures and limiting fluid weights may be based on this information. To determine the strength and integrity of a formation, a Leak Off Test (LOT) or a Formation Integrity Test (FIT) may be performed. Whatever the name, this test is first: a method of checking the cement seal between casing and the formation, and second: determining the pressure and/or fluid weight the test zone below the casing can sustain.

Whichever test is performed, some general points should be observed. The fluid in the well should be circulated clean to ensure it is of a known and consistent density. If mud is used for the test, it should be properly conditioned and gel strengths minimized. The pump used should be a high-pressure, low-volume test or cementing pump. Rig pumps can be used if the rig has electric drives on the mud pumps, and they can be slowly rolled over. If the rig pump must be used and the pump cannot be easily controlled at low rates, then the leak-off technique must be modified. It is a good idea to make a graph of the pressure versus time or volume for all leak-off tests as shown in the illustrations on the next page.

IntegrityTest

Casing

Cement

CementTest

Formation

The information resulting from formation integrity testsis used throughout the life of a well.

PRESSURE BASICS

LEAK-OFF TEST (LOT)

A leak-off test is performed to estimate the maximum pressure or mud weight (fluid density) that the test point can withstand before formation breakdown or fracture occurs.

LEAK-OFF TECHNIQUE 1The well is pressured in increments of 100

psi (6.9 bar) or fluid is pumped into the well in approximately one-half barrel (0.079 m³) increments of volume. After each increase in pressure, the pump is stopped and the pressure is held for about 5 minutes. If the pressure holds, the next increment is tested. If the pressure does not hold, the well is pressured again. The test is completed when the pressure will not hold after several attempts, or if the well will not pressure up any further.

LEAK-OFF TECHNIQUE 2The choke is opened on the manifold and

the pump is started at an idle. The choke is closed to increase the pressure in increments of 100 psi (6.9 bar). At each interval of pressure, the fluid volume in the pits is watched until it is certain that no fluid is being lost to the formation. The test is complete at the pressure where fluid is continuously being lost to the formation. Some fluid will be lost at each pressure increase. If this technique is to be

used, a small tank should be used so large amounts of fluid are not forced into the formation. Circulating frictional pressure losses which are present in this technique add more unseen pressure on the formation tested, which will give slightly different results (lower fracture pressures) than technique number 1.

LIMITED INTEGRITY TEST

A limited formation integrity test (limited FIT), also called a jug test, is performed when it is not acceptable to cause the formation to fracture. It may also be used on wells drilled in developed fields. In such cases, operators have good data concerning formation strength and do not expect to approach fracture pressures. In the limited formation integrity test, the wellbore is pressured to a predetermined pressure or fluid weight. If the formation can withstand the applied pressure, the test is called good.

Both tests, Limited FIT and LOT, have their good and bad points. In the Limited FIT, the formation is not broken down, however, the maximum pressure before the formation starts to accept fluid is not determined. In the LOT, the pressure where the formation starts accepting fluid is determined, but there is a possibility of fracturing the formation.

Increments of VolumeGenerally about 20 Gal (75 Liters) Cumulative Volume Pumped Increments of Pressure

PRES

SURE

SURF

ACE

PRES

SURE

(PSI

)

PRES

SURE

TIME PUMP STROKES TIME

Increments of Pressure Weight

Stop Here

Stop Here

Pressure ~vs~ Time or Volume for Leak-off Tests

Slack in System

Shut-In

Time

Pit Limit

Shut PumpsDown

InstantaneousShut-in Pressure

End of Test

A

BD

C

E

Pressure vs time or volume for leak-off tests

Jug test:limited

formation integrity test,

often performed when risk of

formation damage is high.

CHAPTER 11-10

Estimated Integrity Fluid Densityppg = (Test Pressurepsi ÷ 0.052 ÷ Depth of Testft, TVD) + Test Fluid Densityppg

Est. Integrity Fluid Densitykg/m³ = (Test Pressurebar ÷ 0.0000981 ÷ Depth of Testm, TVD) + Test Fluid Densitykg/m³

Test fluid density is seldom used throughout the entire well. If the fluid density changes, then the surface pressure that may damage the formation should be re-calculated. To find the new estimated integrity pressure with a different density fluid:

Est. Integrity Pressurepsi = (Est. Integrity Fluid Densityppg – Present Fluid Densityppg) × Depth of Testft, TVD × 0.052

Est. Integrity Pressurebar = (Est. Int. Fluid Densitykg/m³ – Present Fluid Densitykg/m³) × Depth of Testm, TVD × 0.0000981

EXAMPLE 4

Solve the following equations for the formation's estimated integrity fluid density (maximum fluid weight without causing formation damage), and the estimated integrity pressure that may cause damage with a different fluid density using the following data. Note: When doing the following exercises, decimals in the answers should not be rounded up. Safety against formation fracture lies in the lower values.

The well has a TD of 11,226' (3421.68 m) and a Casing Shoe set at 5,821' (1774.24 m) TVD. The Leak Off Test Pressure was 1,250 psi (86.19 bar), with a Leak Off Test Fluid of 9.6 ppg (1150 kg/m³). The Present Fluid Wt. is 10.1 ppg (1210 kg/m³).

First find the Estimated Integrity Fluid Density:

Estimated Integrity Fluid Densityppg = (Test Pressurepsi ÷ 0.052 ÷ Depth of Testft, TVD) + Test Fluid Densityppg

= (1,250 ÷ 0.052 ÷ 5,821) + 9.6 = 4.1 + 9.6 = 13.7 ppg.

Est. Integrity Fluid Densitykg/m³ = (Test Pressurebar ÷ 0.0000981 ÷ Depth of Testm, TVD) + Test Fluid Densitykg/m³

= (86.19 ÷ 0.0000981 ÷ 1774.24) + 1150 = 495 + 1150 = 1645 kg/m³

FLUID DENSITY/PRESSURE

The total pressure applied causes leak off or formation damage. This is usually a combination of the hydrostatic pressure of a fluid plus an additional pressure, such as pump pressure on a leak off test. The applied pressure raises the

total pressure against the formation. From test data, calculations estimate the integrity fluid density. This is the total pressure, represented as fluid density, above which leak off or formation damage may occur. This may also be called the maximum allowable mud weight or frac mud weight. The calculations to find the estimated integrity fluid density follow.

When computing formation integrity values decimals in the results are not rounded up.

PRESSURE BASICS1-11

1-12

In formation integrity calculations, it is more conservative to not round up. So, in the previous calculations 4.1 ppg was used instead of 4.13 ppg (495 kg/m³ instead of 495.19 kg/m³).

In this example, the present mud weight is higher than the test mud weight so we must solve for the present estimated integrity pressure.

Estimated Integrity Pressurepsi

= (Est. Integrity Fluid Densityppg – Present Fluid Densityppg) × Depth of Testft, TVD × 0.052

= (13.7 – 10.1) × 5,821 × 0.052

= 1,089 psi

Estimated Integrity Pressurebar

= (Est. Int. Fluid Densitykg/m³ – Pres. Fluid Densitykg/m³) × Depth of Testm, TVD × 0.0000981

= (1645 – 1210) × 1774.24 × 0.0000981

= 75.71 bar

PROBLEM 4What is the estimated integrity fluid density and estimated integrity pressure that may damage the formation for a well with an MD of 12,000’ (3657.6 m), TVD of 10,980’ (3346.7 m). The Casing Shoe is at 8,672’ (2643.23 m) TVD. The Leak Off Test Pressure was 1,575 psi (108.59 bar) with a Leak Off Test Fluid Density of 11.1 ppg (1330 kg/m³), and the Present Fluid Density is 11.6 ppg (1390 kg/m³).

First, solve for the estimated integrity fluid density:

Estimated Integrity Fluid Densityppg= (Test Pressurepsi ÷ 0.052 ÷ Depth of Testft, TVD) + Test Fluid Densityppg

Estimated Integrity Fluid Densitykg/m³

= (Test Pressurebar ÷ 0.0000981 ÷ Depth of Testm, TVD) + Test Fluid Densitykg/m³

Second, solve for the present estimated integrity pressure:

Estimated Integrity Pressurepsi= (Est. Integrity Fluid Densityppg – Present Fluid Densityppg) × Depth of Testft, TVD × 0.052

Estimated Integrity Pressurebar= (Est. Int. Fluid Densitykg/m³ – Pres. Fluid Densitykg/m³) × Depth of Testm, TVD × 0.0000981

Often a chart is generated to post on the rig floor showing incremental mud weight increases and the estimated integrity pressures with each. To do so, calculate the gain in hydrostatic pressure for an increment of 0.1 ppg (11.98 kg/m³).

Hydrostatic Pressure = Fluid Weight Increase × Conversion Factor × DepthTVD

The estimated integrity pressure that may be applied is reduced by the hydrostatic pressure increase gained by each increase in mud weight. A chart beginning with the present mud weight up to integrity fluid density versus integrity pressure can then easily be prepared.

If fluid density is changed,

surface pressure that may

damage the formation must be recalculated.

CHAPTER 1

1-13

EXAMPLE 5

Prepare a chart of Estimated Integrity Pressure on surface for mud weights

ranging from 10.1 to 11.1 ppg (1222 to 1330 kg/m³). The Casing Shoe

depth is 5,821’ (1774.24 m) TVD and Estimated Integrity Pressure for

present fluid weight 10.1 ppg (1210 kg/m³) is 1,250 psi (86.19 bar). First,

find the increase in hydrostatic pressure for 0.1 ppg (11.98 kg/m³):

Hydrostatic Pressurepsi = Fluid Wt. Inc.ppg × 0.052 × Depthft, TVD = 0.1 × 0.052 × 5,821 = 30 psi

Hydrostatic Pressurebar = Fluid Wt. Inc.kg/m³ × 0.0000981 × Depthm, TVD = 11.98 × 0.0000981 × 1774.24 = 2.09 bar

Based on the gain in hydrostatic pressure, subtract this value from the

calculated Estimated Integrity for each corresponding increase in mud

weight.

PROBLEM 5

Prepare a chart of Estimated Integrity Pressure on surface for mud weights ranging from 11.7

to 12.6 ppg (1402 to 1510 kg/m³). The Casing Shoe depth is 8,672’ (2,643.23 m) TVD and

the Estimated Integrity Pressure for present fluid weight 11.6 ppg

(1390 kg/m³) is 1,352 psi (93.22 bar).

Hydrostatic Pressurepsi = Fluid Wt. Inc.ppg × 0.052

× Depthft, TVD

Hydrostatic Pressurebar = Fluid Wt. Inc.kg/m³ × 0.0000981

× Depthm, TVD

Next, fill in chart at right.

Alternate terms such as fracture mud weight, and either MASP (Maximum Allowable Surface Pressure) or MAASP (Maximum Allowable Annular Surface Pressure) are also used for estimated integrity fluid density and estimated integrity pressure. If such terms and information are used as limiting factors and without proper understanding of limiting pressures vs. maintaining control of the well, serious well control complications can result. If this information is used during a well kill operation you must also take kick position, distribution and density into account.

Estimated Integrity Pressure on Surface Fluid Estimated Fluid Estimated Density Integrity Press. Density Integrity Press. (ppg) (psi) (kg/m3) (bar)

Estimated Integrity Pressure on Surface Fluid Estimated Fluid Estimated Density Integrity Press. Density Integrity Press. (ppg) (psi) (kg/m3) (bar)

10.1 1250 1210 86.19

10.2 1220 1222 84.1

10.3 1190 1234 82.01

10.4 1160 1246 79.92

10.5 1130 1258 77.83

10.6 1100 1270 75.74

10.7 1070 1282 73.65

10.8 1040 1294 71.56

10.9 1010 1306 69.47

11.0 980 1318 67.38

11.1 950 1330 65.29

PRESSURE BASICS

EMW = (Pressure ÷ Conversion Factor ÷ Depth of InterestTVD) + Present Fluid Density

EXAMPLE 6What is the EMW for a zone with an MD depth of 3,120’ (950.97 m) and TVD of 3,000’ (914.4 m) when the well is shut in with 375 psi (25.86 bar) registering on the casing gauge? Present Fluid Density is 8.8 ppg (1055 kg/m³).

EMWppg = (Pressurepsi ÷ 0.052 ÷ Depth of Interestft, TVD) + Present Fluid Densityppg

= (375 ÷ 0.052 ÷ 3,000) + 8.8

= 2.4 + 8.8

= 11.2 ppg

EMWkg/m³ = (Pressurebar ÷ 0.0000981 ÷ Depth of Int.m, TVD) + Present Fluid Densitykg/m³

= (25.86 ÷ 0.0000981 ÷ 914.4) + 1055

= 288 + 1055

= 1343 kg/m³

PROBLEM 6

What is the EMW for a zone with a MD of 7,320’ (2231.14 m) and TVD of 6,985’ (2129.03 m) if the estimated choke and friction pressures total 730 psi (50.33 bar)? The Present Fluid Density is 13.8 ppg (1654 kg/m³).

EMWppg = (Pressurepsi ÷ 0.052 ÷ Depth of Interestft, TVD) + Present Fluid Densityppg

EMWkg/m³ = (Pressurebar ÷ 0.0000981 ÷ Depth of Interestm, TVD) + Present Fluid Densitykg/m³

EQUIVALENT MUD WEIGHT

From the previous discussions, it should be apparent that any applied pressure raises the total pressure at a given point. If the applied pressure is known, then it can be calculated to an equivalent weight.

Alternatively, if a zone must be pressure tested to an equivalent weight, then calculations

may be performed to determine the test pressure. The equivalent mud weight (EMW) is also the summation of all pressures (hydrostatic pressure, choke or back pressure, applied pressure, kick pressure, circulating pressure losses, etc.) at a given depth or zone and is expressed as a fluid density. If these pressures are known or can be estimated, the EMW can be calculated as follows:

Frictional resistance:

the opposition to flow created by a fluid when it flows through

a line or other container.

CHAPTER 11-14

To determine how much applied pressure is required to test to a pre-determined EMW

at a given depth:

Test Pressurepsi = (EMWppg – Present Fluid Densityppg) × 0.052 × Depth Testedft, TVD

Test Pressurebar = (EMWkg/m³ – Present Fluid Densitykg/m³) × 0.0000981 × Depth Testedm, TVD

EXAMPLE 7

How much test pressure should be used to test a formation with a MD of 5,890’ (1795.27 m) and

a TVD of 5,745’ (1751.08 m) to an equivalent fluid density of 13.4 ppg (1606 kg/m³)? The Present

Fluid Density is 9.1 ppg (1090 kg/m³).

Test Pressurepsi = (EMWppg – Present Fluid Densityppg) × 0.052 × Depth Testedft, TVD

= (13.4 – 9.1) × 0.052 × 5,745

= 4.3 × 0.052 × 5,745

= 1285 psi

Test Pressurebar = (EMWkg/m³ – Present Fluid Densitykg/m³) × 0.0000981 × Depth Testedm, TVD

= (1606 – 1090) × 0.0000981 × 1751.08

= 88.64 bar

PROBLEM 7

How much test pressure should be used to test a formation with a MD of 7,590’ (2313.43 m) and

a TVD of 7450’ (2270.76 m) to an equivalent fluid density of 14.3 ppg (1714 kg/m³)? The Present

Fluid Density is 8.9 ppg (1067 kg/m³).

Test Pressurepsi = (EMWppg – Present Fluid Densityppg) × 0.052 × Depth Testedft, TVD

Test Pressurebar = (EMWkg/m³ – Present Fluid Densitykg/m³) × 0.0000981 × Depth Testedm, TVD

Most pressure loss will occur circulating down the string and through restrictions such as jet nozzles.

PRESSURE BASICS1-15

1-16

PRESSURE–LOSSES/CIRCULATING

Friction is the resistance to movement. It takes force, or pressure, to overcome friction to get anything to move. Friction has to be overcome to lift pipe, move fluid, or even to walk. How much friction is present to overcome depends upon many factors. These include density or weight, type and roughness of the surfaces making contact, surface area, thermal and electrical properties of the surfaces and direction and velocity of the objects.

The amount of force used to overcome friction is called frictional loss and can be measured in many ways. Torque, drag (amps, foot-pounds, horsepower) and force (psi or bar) to move fluid are a few. Thousands of psi (bar) of pressure can be lost to the well’s

circulating system as fluid is pumped through surface lines, down the string, and up the annulus. The pressure on the pump is actually the amount of friction that must be overcome to move fluid throughout the wellbore at a given flow rate. Most of the pressure loss will occur when circulating down the string and through restrictions such as jet nozzles. Pressure losses also occur in other parts of the circulating system, such as when the choke is used to hold back pressure on the casing side during well killing operations. When fluid finally returns to the pits it is under atmospheric, or almost zero, pressure.

When the well is being circulated, bottomhole pressure is increased by the amount of friction overcome in the annulus. When pumps are shut off, wellbore pressure is reduced because no frictional force is being overcome.

Casing

Bit

900

Flowline

TANK

30002950

Standpipe

Drill Pipe

Pump0

CirculatingPressure

Bottomhole pressure:

1: pressure exerted by a

column of fluid in the wellbore.

2: formation pressure at

depth of interest.

CHAPTER 1

1-17

Since friction adds pressure to the wellbore, it increases the effective weight, or the equivalent circulating density (ECD). The total value is the equivalent of bottomhole pressure with the pump on. If pressure in a permeable formation is closely balanced by ECDs, a well could flow when the pump is turned off. Data obtained from logging while drilling tools (LWD) can be used to get an accurate reading of annular pressure, which may be used to determine ECD.

BOTTOMHOLE PRESSURE

Pressure is imposed on the walls of the hole. The hydrostatic of the fluid column accounts for most of the pressure, but pressure to move fluid up the annulus also acts on the walls. In larger diameters, this annular pressure is small, rarely exceeding 200 psi (13.79 bar). In smaller diameters it can be 400 psi (27.58 bar) or higher. Backpressure or pressure held on the choke also increases bottomhole pressure, which can be estimated by adding up all the known pressures acting in, or on, the annular (casing) side. Bottomhole pressure can be estimated during the following activities.

WELL STATICIf no fluid is moving, the well is static.

The bottomhole pressure (BHP) is equal to the hydrostatic pressure (HP) on the annular side. If shut in on a kick, bottomhole pressure is equal to the hydrostatic pressure in the annulus plus the casing (wellhead) pressure.

NORMAL CIRCULATIONDuring circulation, the bottomhole pressure

is equal to the hydrostatic pressure on the annular side plus the annular pressure loss (APL).

ROTATING HEADDuring circulating with a rotating head

the bottomhole pressure is equal to the hydrostatic pressure on the annular side, plus the annular pressure loss, plus the rotating head backpressure.

CIRCULATING A KICK OUTBottomhole pressure is equal to hydrostatic

pressure on the annular side, plus annular pressure loss, plus choke (casing) pressure. (For subsea, add choke line pressure loss.)

PUMP

BHP = HP

Well StaticWell staticNormal Circulation

PUMP

BHP = HP + APL

Normal circulation Circulation with Rotating Head

BHP = HP + APL + Rotating Head Back Pressure

PUMP

RotationHead

Circulation with rotating head Kick Circulation

BHP = HP + APL + Choke Press

PUMP

BOPStack

Kick circulation

Hydrostatic pressure is controlled by careful monitoring and control of fluid weight.

PRESSURE BASICS

MOVING PIPE –SURGE/SWAB

The total pressure acting on the wellbore is affected by pipe movement upwards or downwards. When tripping out swab pressure is created, reducing the pressure on the wellbore. Swabbing occurs because the fluid in the well does not drop as fast as the string is being pulled. This creates a suction force and reduces the pressure below the string. This force can be compared to a plunger in a syringe, with formation fluid being pulled into the wellbore.

When lowering the string too fast, surge pressure is created because the fluid does not have a chance to get out of the way. Since liquids do not compress to any appreciable degree, pressure throughout the well can increase and cause leak-off or fracture. Both surge and swab pressures are affected by the rate of pipe movement, clearances between pipe and hole and fluid properties.

While it is often impossible to avoid these pressures, they can be minimized by slowing the tripping speed. Calculations are available to estimate maximum trip speed and surge and swab pressures, but these calculations are outside the scope of this manual.

TRIP/SAFETY MARGINS

Unless there is an excess of fluid weight to compensate for swabbing, formation fluid can enter the well and a kick can occur. The trip margin is an estimated increase in fluid density prior to a trip to compensate for loss of circulation pressure (ECD). A safety margin also compensates for swabbing pressures as pipe is pulled from the well.

Using fluid density adjustments for a trip or safety margin requires good judgement. Too large a margin can cause lost circulation. Too small a margin may allow the well to kick. The margin depends on hole size, condition, pipe pulling speed, fluid and formation properties.

DIFFERENTIAL PRESSURE

The difference between the formation pressure and bottomhole hydrostatic pressure is differential pressure. These are classified as overbalanced, underbalanced and balanced.

OVERBALANCEDOverbalanced means the hydrostatic

pressure exerted on the bottom of the hole is greater than the formation pressure:

HP > FP

UNDERBALANCED Underbalanced means the hydrostatic

pressure exerted on the bottom of the hole is less than the formation pressure:

HP < FP

Swab

Fluid Properties

Pipe Movement

Sand

SwabPressure

Swabbing occurs because

the fluid in the well does not

drop as fast as the string is

being pulled.

CHAPTER 11-18

BALANCED Balanced means the hydrostatic pressure

exerted on the bottom of the hole is equal to the formation pressure:

HP = FPMost wells are drilled, and worked, in bal-

anced to overbalanced conditions. If circulating or drilling, friction and cuttings contribute to the effective pressure on bottom.

SUMMARY

There are two main opposing pressures in a well. These are the fluid column hydrostatic pressure and the formation pressure. If one pressure overcomes the other, then a kick or lost circulation may occur.

Since hydrostatic pressure is a function of the density of the working fluid in the well, its value may be controlled. By making careful calculations and by manipulating the formula for hydrostatic pressure, it is possible to test cement jobs, to estimate formation integrity, to project maximum mud weights and to control kicking wells.

Kicks and blowouts are prevented by peo-ple who are able to work quickly and decisively under stress. An important part of the train-ing required for blowout prevention is an understanding of pressure concepts and the ability to perform accurate calculations. t

OverbalancedHP > FP

UnderbalancedHP < FP

B alancedHP = F P

Differential pressure is the difference between formation pressure and bottomhole hydrostatic pressure.

Kicks are prevented by people able to work quickly and decisively under stress.

PRESSURE BASICS1-19

CHAPTER

2

An understanding of

pressure indicators,

warning signs and why

kicks occur can

significantly decrease

chances of kicks.

KICKFUNDAMENTALS

A kick is the unwanted influx of formation fluids into the wellbore. The results of a kick include lost operation time,

hazardous operation with high pressure and gas, and possible equipment losses (from stuck pipe to rig loss) during attempts to regain control of the well. If recognized and controlled in time, the kick can be handled and removed from the well safely. If the kick is allowed to continue, it may no longer be able to be controlled. This is said to be a blowout or uncontrolled kick.

Since a kick may happen at any time, we must be able to recognize, identify and react to all kick warning signs. These signs indicate either that the conditions for a kick exist or that the well may be kicking. It makes sense that all possible means should be used to prevent kicks.

2-1

CHAPTER 22-2

PREDICTING FORMATION PRESSURE

The best way to avoid a well kick is to have a fluid in the hole that is heavy enough to control formation pressures but light enough to avoid lost circulation. In many parts of the world, pressures and temperatures at any depth can be predicted with reasonable confidence. However, crews must be alert to unexpected changes in pressure regardless of how safe, or routine, the current operation may be.

Pressure in a normally pressured formation is roughly equal to that exerted by a column of formation fluid extending from the formation to surface, or between 0.433 and 0.465 psi/ft (0.098 and 0.105 bar/m). In this manual, we use the term abnormal pressures to mean a gradient greater than 0.465 psi/ft (0.105 bar/m).

Abnormal pressures are not uncommon in many parts of the world. For example, abnormally high pressures are common along the U.S. Gulf Coast, and abnormally low pressures are found in some areas in West Texas, the Rocky Mountains, and many Northeast states.

Geological conditions directly affect the formation pressures. Wells drilled into

subsurface traps or structures that contain oil and gas may encounter abnormally high pressure. While the driller, toolpusher and operator’s representative are not exploration geologists, they are expected to be alert. They must be aware that abnormal pressure can be encountered at any depth and time. A trained, experienced crew is prepared for the unexpected.

Well pressures can be predicted from three sources of information. Historical, seismic and geologic data may be used prior to drilling. While the well is being drilled, changes in drilling parameters may indicate changes in pressure and formations. Log data obtained with logging tools while drilling is valuable.

HISTORICAL DATA

Historical information from offset wells in the area is one of the better methods for determining potential trouble. Mud records and drilling reports can give a good general indication of drilling conditions. These records, with the application of geological and seismic background data can provide significant information on potential problems.

Wireline

Drilling

GeologyThree ways to predict formation

pressure

Drilling recordsfrom offset

wells can help predict

formation pressure.

KICK FUNDAMENTALS2-3

SEISMIC INTERPRETATIONS

The science of seismology involves creating sound waves that penetrate the subsurface rock layers. Sound waves are reflected back from each formation and recorded by instruments that measure the intensity and nature of the reflections. By interpreting measurements, exploration geologists are able to deduce the shape and extent of subsurface formations, especially using 3D computer enhanced seismic plots. With this information, drilling programs for predicting potentially pressured zones can be developed accurately and safely.

GEOLOGICAL DATA

The geologic preplanning of the well looks at the general geology of the area. Certain geological conditions cause abnormal pressures and hazardous drilling, and they need to be noted in the well planning. A few of the most common conditions associated with subsurface pressure changes are faults, anticlines, salts, massive shale, charged zones or depleted zones.

FAULTS

When the drillbit crosses a fault, a significant change in pressure gradients may exist, resulting in a kick or lost circulation. Faults are often crossed deliberately in order to find oil and gas accumulations. Directional and horizontal drilling often cross fractures and faults, and the chances of drilling into a kick or losing circulation are high.

ANTICLINES

Anticlines are geological structures which are domed upward. Rock layers that were thrust up from greater depths often form these anticline structures. Higher pressures previously contained in the deeper burial position are preserved. For this reason, these anticline structures are often targeted.

When drilling on a structural high of the anticline, high pressures should be anticipated. In addition, when deepening confirmation and production wells, or sidetracking, remember that the initial well may have been drilled on a flank (side), and by deepening or sidetracking, unexpected pressures could be encountered.

A faulted formation An anticlinal structure

Cap

Subnormal

Normal

NormalAbnormal

Abnormal

Anticlines are geologic structures that have been thrust upward toward the surface.

CHAPTER 22-4

SALTS

In many areas of the world, thick, nearly pure layers of salt are present. Often, salt is forced upward into the overlying formations to form salt domes. Under the pressure of the overburden, salt exhibits plastic flow ability, not allowing pore fluids to migrate through it. Because of this, formations beneath a salt layer are commonly overpressured. Pierced layers or formations are usually sealed by the salt and lifted up, leading to migration of oil and gas. These zones may have pressure in excess of the surrounding formations.

MASSIVE SHALE

Thick, impermeable shales restrict the upward movement of pore fluids. As more layers of overburden were accumulated, formation pressures became abnormal, not allowing for the normal compaction and cementing process. Shale sections formed under these conditions may be mobile or plastic, as they exhibit abnormal pressure when drilled, and will refill the hole when the bit is withdrawn. High fluid densities are often required to control these shales, and may require special casing programs.

Overpressured shale will have a lower density and may drill faster due to the lack of normal compaction and hardness. A cap, or seal, of hardened rock often indicates the top of pressured shales. After the cap is drilled, the shale usually becomes progressively softer as pressure increases, resulting in increased penetration rates.

Permeable rocks (sandstone) below such shales are generally overpressured also, due to the lack of escape routes for pore fluid as the overburden weight increases.

CHARGED ZONES

Shallow sands and formations exhibiting abnormal pressure are termed charged zones. Charged zones may be naturally occurring as the result of upward migration of pore fluids from a deeper zone, or they can be man-made. Poor or inadequate primary cement jobs, damaged, or corroded casing and tubulars and infield flood projects can lead to charged zones.

Modern geophysical techniques may define shallow charged zones. Such zones are often called bright spots. Normal pressures from a deeper formation, when encountered at shallow depths, are usually difficult to control.

Sand &ShaleInterbedded

Massive Shale

Sandstone

StructuralPressure

NormalPressure

ImpermeableZone

Massive shale as a transition zone.

SaltAbnormal Pressure

Normal Pressure

Cap

Abnormal Pressure

Salt domes are common gulf coast structures.

High pressures are often

associated with salt domes.

KICK FUNDAMENTALS2-5

DEPLETED ZONES

Zones that have been depleted often have pressures that are lower than normal (subnormal). When encountering one of these zones, severe lost circulation may occur. If the fluid level falls, hydrostatic pressure will be reduced. This may allow another zone – or even the depleted zone – to flow.

These conditions can occur where a well was previously drilled. Often there is no offset data available from wells that may have been drilled in the area. Incomplete local history or poor offset well records can be dangerous.

PRESSURE INDICATORS – DRILLING

The following are the most common signs of formation pressure changes. These signs must be recognized by rig crews and relayed to supervisors. Communication is vital because many of these signs also have other meanings.

w Change in rate of penetration

w Change in shape, size, amount of cuttings

w Increase in rotary torque

w Increase in drag

w Sloughing shale

w Increase in gas content

w Variations from normal “d” exponent

w Increase in flowline temperature

w Decrease in shale density

w Increase in chloride content

Not all of the above indicators may be present at any one time. Rig personnel should be able to recognize these indicators as possible signs of drilling into higher pressures.

PENETRATION RATE CHANGE

An increase in the rate of penetration is one of the most widely accepted methods of determining changes in pore pressure. Normally, there is a decrease in drilling rate with depth. This decrease, which results from increased hardness and density of the rock, is also controlled by the difference between hydrostatic pressure and pore pressure.

A change in the drilling rate could be an indicator of increasing formation pressure. The drilling rate changes when penetrating an abnormally pressured zone because the

Fractures ToHigher Zones

Old AbandonedWell

New WellOld Field

Normal Pressure

Man-made high pressure zones Abnormally pressured formations can be identified by electric logs.

Rig crews need to be on the lookout for – and report immediately – any formation pressure change indicators.

CHAPTER 22-6

formation contains more fluids and is softer. The increasing formation pressure will also reduce the overbalance at the bottom of the hole. This means the cuttings will break loose under the bit more easily.

A gradual increase or no change in the drilling rate when it should be decreasing can also be signs of increasing formation pressures. The abrupt increase is usually called a drilling break and an abrupt decrease is called a reverse break. Either can be a sign of drilling into another formation that may allow a well kick. When formation pressures change from normal to abnormal as the well is deepened, the area across the change is called a “transition zone.” While drilling a transition zone the mud weight should be maintained as close to formation pressure as possible. A change in pore pressure will then be reflected in the drilling rate. Any extra heavy mud weight will increase the differential pressure and reduce the drilling rate. This will hide the drilling rate increase normally seen as the result of pressure increases.

There are, however, things other than pore pressure which affect rate of penetration, including formation changes, hydraulics, rotary

speed, fluid properties, bit type, weight on bit, bit condition and mud weight.

As previously mentioned, any formation changes present a serious interpretation prob-lem. In general, a sudden large change in drilling rate may indicate a formation change.

CUTTINGS CHANGES: SHAPE,SIZE, AMOUNT, TYPE

Cuttings are rock fragments chipped, scraped or crushed away from a formation by the action of the bit. The size, shape and amount of cuttings depend largely on formation type, bit type, weight on the bit, bit dullness and the pressure differential (formation versus fluid hydrostatic pressures).

The size of the cuttings usually decreases as the bit dulls during drilling if weight on bit, formation type and the pressure differential, remain constant. However, if the pressure differential changes (formation pressure increases), even a dull bit could cut more effectively, and the size, shape and amount of cuttings could increase.

On the left: shale cuttings from a normally pressured zone. On the right: shale cuttings from a transition zone.

Transition zone:the term used to describe a

change in formation

pressure, e.g., from normal

to abnormal.

KICK FUNDAMENTALS2-7

TORQUE/DRAG INCREASE

During a normal drilling operation rotary torque gradually increases with depth. This is the result of wall contact of the drillstring on the wellbore.

Increased formation pressure causes larger amounts of cuttings to enter the wellbore as the bit’s teeth take larger bites into the formation. The increased amount of shale tends to stick, impede bit rotation, or pile up around the collars. An increase in torque over several hundred feet is a good indicator of a pressure increase.

When drilling in a balanced or near balanced situation, an increase in drag occurs while making connections in an abnormally pressured zone. This increase can be due to the extra cuttings that enter the wellbore and pile up around or above the collars. Torque and drag may also increase because the formation is soft, which could cause the hole to close around the drill collars and bit.

SLOUGHING SHALE/HOLE FILL

As the formation pressure becomes greater than the mud column pressure, the mud column becomes less effective in supporting the walls of the hole, and eventually the shale begins to spall or sloughs off the sides of the wellbore. Sloughing shale is not an either/or situation, but depends upon the degree of underbalance and other factors such as the dips in the formations, compaction, cementing of the sand grains, internal stress, etc.

Sloughing shale affects drilling by causing tight hole, fill on bottom, and eventually can cause the drillpipe, or other tools to become stuck. Sloughing shale is not always the result of abnormal pressures. It is often attributed to other causes, so the possibility of abnormal pressures may be overlooked. When pressure is the cause of popping, heaving, or sloughing shale, its shape will be long, splintery, and sharply curved.

0.5in to 1.5in

SCALE

FRONT SIDE

BLOCKY,RECTANGULARSHAPES

MAY BE STRIATED

FRONT SIDE

DELICATE SPIKY SHAPE

CONCAVE SURFACEPLANPLAN

Typical shale cavingproduced by stress relief

(b)Typical shale caving producedby underbalanced conditions

(a)

TYPICALLYCRACKED

When pressure is the cause of sloughing shale, its shape will be long, splintery and curved.

CHAPTER 22-8

Prior to any kind of trip the hole is usually circulated clean, meaning cuttings are removed from the well to prevent complications. If an abnormal pressured formation is penetrated, it is not unusual to find significant amounts of fill when trying to get back to bottom. This can be due to insufficient hydrostatic to prevent the walls from sloughing or popping into the wellbore. It should be pointed out that lack of pressure is not the only cause of this but could be an indicator of insufficient pressure.

GAS CONTENT INCREASE

An increase in the gas content of a drilling fluid is a good indicator of abnormally pressured zones. However, gas cutting is not always the result of an underbalanced condition and a correct understanding of gas cutting trends is important.

DRILL GAS

When a porous, non-permeable formation containing gas is drilled, cuttings containing gas are circulated up the hole. Hydrostatic pressure on these particles is reduced as they circulate up the hole. Gas in cuttings expands

and releases to the mud system, cutting the weight. In such cases, increasing the mud weight will not stop the gas cutting. This condition can be verified by stopping the drilling operation and circulating bottoms up. The amount of gas should decrease significantly or stop.

CONNECTION OR TRIP GAS

While drilling with minimum mud weight, the swabbing effect of the upward pipe movement during a connection or trip can swab formation gases and fluids into the wellbore. This is generally referred to as trip gas or connection gas, and when these gases increase, formation gases may be increasing, or the pressure differential (mud to formation pressure) is changing.

BACKGROUND GAS

The best example of background gas is in West Texas where the low permeable Permian age Red Beds are drilled with water. The formation pressure in these beds is equivalent to about 16 ppg (1917 kg/m³) mud. The Red Beds have gas, but very low permeability. The result is that the mud is gas cut all the time, and causes particularly bad trip gas.

10500

10550

10600

10650

GAS UNITS

CONNECTION

OFF SCALE

Flowline gas must be

monitored carefully.

An increase in the gas

content of a drilling fluid

may indicate abnormal pressure.

KICK FUNDAMENTALS2-9

When you are using gas in the drilling fluid as an indicator of abnormal pressures, a gas detector unit is necessary. A trend of the background and/or connection gas can be noted as the drilling operation progresses. Both background and connection gas should be watched carefully and taken as a possible warning of increasing pore pressure.

VARIATIONS FROM “D” EXPONENT

The “d” exponent method of detecting and predicting abnormal pressures while drilling is sometimes used. Calculation of the “d” exponent is simple and requires no special equipment. The required information, which should be available on the rig site, is penetration

Modern LWD tools use mud pulse telemetry to collect formation data.

An accurate plot of the “d” exponent can help predict mud weights required for safe drilling.

CHAPTER 22-10

rate, rotary rpms, weight on bit and hole diameter. The “d” is then calculated (by computer program, slide rule or nomograph) and then plotted on semi-log paper. A change in the slope of the line is an indicator of pressured zones. Improvements in plotting techniques have refined the method to the extent that now required mud weights in many areas can be routinely predicted with an accuracy of from 0.2 to 0.5 ppg (24 to 60 kg/m³) of the mud weight. Properly used, this information can reduce well kicks and, just as importantly, reduce the use of unnecessarily heavy mud that lowers drilling rate and increases drilling cost.

MWD AND LWD

The MWD (measurement while drilling) and LWD (logging while drilling) tools are a sophisticated arrangement of electronic instruments. Directional drilling, and formation evaluation information can be gathered and recorded in a real time manner, depending on the configuration and type of tool. Measured parameters such as formation resistivity, torque, temperature, downhole pressure, and acoustic responses, can be used to identify changes in drilling conditions and influx detection. The responses of the parameters vary according to the fluid system (water or oil based), and some interpretation of signals is necessary.

Electricity is generated to power the tool by a turbine or impeller in the string assembly. Specific pump rates are required to provide

proper power for the tool. Depending on the type of tool, once information is gathered it can be transmitted by wireline, fluid pulses (pressure waves), electromagnetic waves or acoustic waves. The pulses are received by sophisticated sensors on surface and then relayed to computers that decode or translate the pulses into useable information.

SHALE DENSITY DECREASE

Shales that are normally pressured have undergone normal compaction and their densities increase uniformly with depth. This uniform increase allows shale density to be predicted. Any reduction from the trend can be interpreted as a zone of higher pore pressure since high pressure shales are less dense than normal pressured shales. This occurs as a result of pore fluids trapped in shale sections during the compaction process.

Problems clouding the field usefulness of shale density pressure prediction lie in the methods for measuring shale density. Three methods are commonly used. They are:

LWD techniques

provide real time info of

well conditions.

MWD and LWD tools gather

data that can be used to

predict formation pressure.

KICK FUNDAMENTALS2-11

w Variable density liquid column

w Mud balance density

w MWD (measurement while drilling) logging techniques.

Determining the source depth of the shale cuttings is not easy, and the selection and preparation of the cuttings for measurement depends largely on the experience of the person making the measurement.

FLOWLINE TEMPERATURE INCREASE

The seal at the top of a transition zone limits the movement of water. So above normal temperatures occur in both the transition zone and in the zone of higher pressure below. If a normal trend of flowline temperature is plotted, a change of 2 to 6 degrees or more per 100 feet (30.48 m) above this trend can be an indication of a transition zone.

In addition to indicating a pore pressure change, changes in flowline temperature may also be attributed to:

w A change in circulation rate

w A change in solids content of mud

w A change in mud chemistry

w A change in drilling practices.

The temperature curves (shown below), although not always definitive, are an additional indicator that help in the decision to stop drilling or increase present mud weight.

Offshore, as the water depth increases, the ability to use the temperature plot decreases. It can be rendered useless by the cooling effect of the water unless the temperature at the stack can be monitored. In deep water, the surface temperature of the drilling mud returning may remain constant throughout the operation.

CHANGE IN CHLORIDE CONTENT

Changes in the salt or chloride ion content of the drilling fluids are a valid pressure indicator. If insufficient pressure exists formation seepage or flow may enter the wellbore and mingle with the drilling fluid. This

will change the chloride content of the mud. Depending on the existing chloride content of the mud, an increase or decrease may be determined based on whether the formation fluid’s salt content is higher or lower. However, changes are difficult to establish unless there is a close control of the mud checks. Most methods currently available to make chloride ion tests are inadequate to show subtle changes. In fresh water/bentonite muds, increases in chloride content will cause an increase in the funnel viscosity and flow properties.

9

10

11

12

110100 120 130Flow - Line Temperature (°F)

Dep

th (1

,000

ft)

TransitionZone

An increase in flowline temperature could be an indication that formation pressure is increasing.

Changes in flowline temperature can be used with other indicators to help identify transition zones.

CHAPTER 22-12

LOGGING PRESSURE INDICATORS

The normal electric log or induction log measures the electrical resistivity of the formation. Since abnormally pressured shale formations generally have more water, they are less resistive than drier, normally pressured formations. The resistivity change can be measured and formation pressure calculated.

The acoustic or sonic log measures the sound velocity or interval transit time of the formation. High-pressure shale formations that have more water have lower sound velocity and a resulting higher transit time. Calculations can be made to determine the formation pressure and porosity from these measurements.

The density log measures the density of the formation based on radioactive measurements. High-pressure shale formations have less density and calculations can be made to determine formation pressure.

CAUSES OF KICKS

Any time the formation pore pressure is greater than the pressure exerted by the column of fluid in the well, formation fluid can flow into the well. This can occur from one or a combination of reasons.

The most common causes of kicks follow.

w Insufficient fluid density

w Poor tripping practices

w Improper hole fill while tripping

w Swabbing/surging

w Lost circulation

w Abnormal pressure

w Obstructions in the wellbore

w Cementing operations

w Special situations, including:

ú Excessive drilling rate through gas sand

ú Excessive water loss of drilling fluid

ú Drilling into an adjacent well

ú Charged formations

ú Obstructions in wellbore

ú Testing BOPs

ú Trapped gas below BOPs

ú Loss of subsea riser

ú Secondary recovery projects

ú Water flushes

ú Drill stem testing (DST)

ú Underbalanced drilling – failure to maintain adequate backpressure

ú Platform leg

INSUFFICIENT FLUID DENSITY

Insufficient fluid density, or fluid not heavy enough to control the formation, is a common cause of kicks. The fluid in the wellbore must exert enough hydrostatic pressure to equal the formation pore pressure. If the fluid’s hydrostatic is less than formation pressure the well can flow.

Probably the most common reason for insufficient fluid density is drilling into unexpected abnormally pressured formations. This situation can arise when unpredictable geological conditions are encountered, such as drilling across a fault that abruptly changes the formation being drilled. Insufficient fluid density can also be the result of misinterpreting normal drilling parameters (ROP, gas content, shale density, etc.) used as guides to weight up mud. (This usually means the transition zone was missed and the first permeable formation caused the kick.)

Mishandling mud at the surface accounts for many instances of insufficient fluid density. Opening the wrong valve on the pump suction manifold and allowing a tank of light weight fluid to be pumped; bumping the water valve so more water is added than intended; washing off shale shakers; or clean up operations - can all affect fluid density.

Once a formation has

been drilled the pore pressure

may be determined by

electric logs.

KICK FUNDAMENTALS2-13

Rainwater may find its way into the circulating system, greatly affecting density and severely altering the fluid’s properties. Also cutting back the weight of the fluid in the well can be dangerous because you are intentionally adding water to the system while circulating. If too much water is added, or the fluid’s density becomes too low, the well may start to flow. However, since the crew is mixing and adding volume to the pits, a gain from the flowing well may be hard to detect.

It is good practice to add known or measured volumes when mixing. If the water used to cut the fluid’s density can be taken from a tank with a known volume, then the amount of water taken from that tank should equal the gain in the pits. If there is more gain than can be accounted for, the well may be flowing. Notify proper rig personnel when mixing, adding or transferring fluid in the pits.

Other causes of improper fluid density include changing out the present fluid in the well for fracturing or acid jobs, spotting large pills, or changing to perforating, completion or packer fluids.

TRIPPING OUT

Perhaps the leading cause of kicks results from pulling pipe out of the well. Many factors come into play during a trip. Simply put, either you don’t have adequate fluid weight to hold the formations back, or pressure was reduced in the wellbore during the trip to allow an influx.

Under normal activities if circulation can be stopped prior to the trip out without taking a kick, then a kick should not occur during tripping. A factor that is often not considered is the frictional force exerted on the formation by fluid circulation. This is called annular pressure loss (APL), and may represent the equivalent circulating density (ECD) of over 1 ppg (120 kg/m³) of weight material. Once the pumps are shut down, circulating pressure is

lost and bottomhole pressure is reduced to the hydrostatic pressure of the fluid in the annulus. This reduction in bottomhole pressure may allow the well to start kicking.

Before starting a trip, always watch the hole to see if the well is flowing after the pumps are shut down. Company policy may dictate 5 to 30 minutes to just watch the well. This is time well spent if it prevents a kick and the complications that may result.

If proper time is given to make sure the well is not flowing, and then a kick is taken on the trip out, it is assumed that something that happened while pulling the pipe started the kick. The vast majority of these kicks are due to swabbing/surging.

SWABBING AND SURGING

Whenever pipe is moved through fluid, both swab and surge forces are present. The direction of pipe travel dictates the dominant force, swab or surge. When pipe travels upwards, (for example, a trip out of the hole) swab pressure is dominant. Fluid often cannot fall down between the pipe and wellbore as fast as the pipe is being pulled upwards. So a reduction in pressure is created under the pipe allowing formation fluid to feed in until the pressure reduction stops. This is called swabbing. If enough fluid is swabbed in, it may lighten the total hydrostatic enough for the well to begin to flow. The analogy of pulling a plunger in a syringe illustrates this concept.

Surge pressure is also present as pipe is being tripped out of the hole, but usually has less effect than swabbing. Fluid surrounding the pipe (especially above bottomhole assembly) must get out of the way by moving upwards around the pipe and up the hole. If the pipe is pulled too fast, not all of the fluid can move out of the way. A pressure buildup may occur, leading to losses and hydrostatic reduction.

On the trip out, three main things – the clearance, fluid properties and the rate of pipe movement – affect swabbing and surging.

Before starting a trip, observe the well carefully to make sure it doesn’t flow when the pumps are shut down.

CHAPTER 22-14

CLEARANCE

One of the most important factors in swab pressure development is the clearance between the pipe (tubing, drillpipe, collars, stabilizers or tools) and the wellbore (open or cased hole). The smaller the clearance, the more restriction fluid must overcome to flow. Wells with tight areas, swelling formations, sloughing formations, or wells prone to balling tools decrease clearance and increase the chance for swabbing in a kick. While it is usually not possible to control these factors, proper tripping practices, such as reduced tripping speeds, minimize the chance of swabbing an influx into the well. Factors compounding and reducing clearance include restrictions between the string and wellbore or casing, such as swelled formations, collapsed casing, or a balled up bit. These problems are not usually known until it is too late. Keep in mind that the clearance between pipe and casing may be smaller than thought. This increases the chance of swabbing in a kick, or surging the well.

OTHER FACTORSAFFECTING CLEARANCE

SALT AND SWELLING FORMATIONS

Some examples of clearance problems from formations are salt and swelling. Salt is plastic. Depending on the pressure being imposed on it, the clearance in the wellbore can be reduced once the pump has been turned off (loss of circulating pressure and also lateral pressure on the wellbore). Salts have been known to close in around the string giving it just enough clearance for circulation. In addition, clays swell when exposed to water, narrowing the string to wellbore clearance, and increasing the chance for the well to be swabbed in. With reduced clearance during the trip out, stabilizers and bottomhole assemblies could stick or cause severe swabbing.

BALLING

Balling refers to materials (barite, fluid, formation matter, wall cake) gathered around a bit, stabilizer, tool joint or any part of the string. This gathering increases effective OD at that point and reduces clearance between the string and hole. As clearance narrows, this problem may be seen as an increase in torque (more balled up pipe-to-formation contact) and/or an increase in pick-up weight from drag due to the well contact and lifting of the mud column.

PULLING INTO SHOE

It is a shame that some drillers learn the hard way the double jeopardy associated with casing shoes. First, there is the possibility of a stabilizer or tool catching on the casing shoe, which may result in rig damage, the pipe being parted, or the shoe pulled in and pipe stuck. Second, there is the reduction of clearance as the bottomhole assembly is pulled up into the casing. Clearance complications can also happen when any part of the string, or bottomhole assembly, becomes balled.

AN EXAMPLE:The casing is assumed to be gauge, but the

open hole may have a washout factor ranging from 5% to 150%. For example, the ID of the casing is 8.835” (224.41 mm) and you pull 8 1⁄2” (215.9 mm) stabilizers that are balled up to an OD of 10 1⁄2” (266.7 mm). Once the balled up stabilizers enter the casing shoe, the excess mud around the stabilizers will shear off. Now the stabilizers, balled up with cuttings and mud, will have an OD that is roughly the same as the ID of the casing. It is similar to pulling a swab into the casing.

Prior to pulling off bottom, each driller should calculate the number of feet or the number of stands of pipe pulled prior to the bottomhole assembly entering the casing shoe. Always reduce speed when entering the casing shoe and be alert. Always keep an especially close monitor on hole fill.

Swabbing can occur if

pipe is pulled from a well faster than

the fluid can fall below it.

KICK FUNDAMENTALS2-15

HOLE ANGLE AND DOGLEGS

When pulling up through deviated wells and dogleg areas, remember that the BHA is dragged against the top portion of the wellbore. This may result in the pipe and BHA picking up debris (balling) and reducing clearance. This reduced clearance makes it harder for fluid to fall back down around the assembly. During drilling operations, cuttings will tend to fall or stay on the low side of deviated holes and doglegs, reducing the ID and making it tight when pulling out.

BOTTOMHOLE ASSEMBLY LENGTH

The longer the reduced clearance area, the greater the chance for swabbing. It stands to reason that 500’ (152.4 m) of collars will not contribute as much to swabbing as 1,000’ (304.8 m) of collars.

NUMBER OF STABILIZERS

As in the case above, a pendulum bottomhole assembly with one stabilizer will not swab as much as a packed hole assembly with several stabilizers. As the number of stabilizers increases, so does the chance of balling and swabbing.

TOOLS RUN

Extra care should be taken when pulling tools that create small clearances. The larger the OD of the tool, the greater the chance for swabbing. In open hole operations severe balling can result. Swabbing effects are minimal when pulling smaller OD tools such as stingers, or open ended and small diameter pipe, since the clearances are greater.

FLUID PROPERTIES

Since swabbing depends on the lifting and flowing of fluid from where it was before pipe was moved, the properties of the fluid are critical. The following properties are important: viscosity, gel strength, density and water loss.

VISCOSITYViscosity, or readiness of a fluid to flow,

is perhaps the most critical of all factors in swabbing. If fluid is thick or viscous, it has a difficult time flowing down as pipe is pulled upwards. When fluid’s viscosity is high, slower pulling speeds are needed to allow fluid to fall back down around smaller clearances. By tripping out slowly, according to calculations, minimal bottomhole pressure losses occur. This reduces the potential for the well to swab or flow. The funnel viscosity test should be checked in order to determine if the fluid is in good enough condition to begin the trip. If the hole and/or fluid have problems, the mud may have to be conditioned in the hole before starting the trip.

GEL STRENGTHGel strength is the attraction of solids

particles to each other. A strong attraction resists flow from static conditions and increases swab pressures. If fluid has progressive gel strength, upward pulling of pipe can also produce surge pressures upward. This pressure may cause weak zones to take fluid, lowering the hydrostatic head and contributing to the kick mechanism.

DENSITYIf the mud density is too high and causes

seepage or loss of fluid into the formation, it can effectively push the pipe into the side of the hole. Cuttings, wall cake, and other debris can be collected by stabilizers, or other downhole tools. This can reduce clearance and create a swabbing effect. When mud densities are too low, bottomhole tools tend to scrape the sides of the wellbore due to swelling formations. They can collect debris and reduce clearance.

In some instances if the overbalance is high enough, the swabbing potential may decrease.

WATER LOSSThe advantages of high water loss muds

include faster penetration rates. Disadvantages include sticking problems due to thick, gummy wall cakes reducing the ID of the hole that increase the chance of swabbing.

Fluids with high gel strengths increase the likelihood of swabbing on trips.

CHAPTER 22-16

RATE OF PIPE MOVEMENT

The rate of pipe movement directly affects swab and surge pressures. The faster the pipe travels the greater the swab and surge pressures and the higher the potential for swabbing in an influx. Chances of swabbing in a kick (and/or breaking down the formation) will increase with trip speed.

One misconception is that once the bit enters the shoe, the well can no longer be swabbed and trip speed tends to increase. We need to remember that there is the potential to have a smaller clearance inside the casing than the open hole.

IMPROPER HOLE FILL

Whenever the fluid level in the hole drops, the hydrostatic pressure exerted by the fluid also drops. When the hydrostatic pressure falls below the formation pore pressure, the well may flow.

Pipe may be pulled dry or wet depending on conditions. If it is pulled dry it is due to a heavy slug that was pumped in the string prior to the trip, pushing out a length of the lighter fluid in the pipe. As the pipe is pulled, the slug will fall again, so subsequent stands will also pull dry. Depending on practices, the slug may affect the fill up on the first five to ten, or more, of the stands of pipe pulled. If tripping out begins too soon after pumping the slug, the pipe could pull partially wet if the slug is not given time to seek its level.

During a dry trip out of the hole, the volume of steel pipe being removed results in a corresponding drop in wellbore fluid. The hole must be refilled to maintain sufficient hydrostatic pressure to control formation pressure.

If the pipe is pulling wet (fluid remains in the pipe), and a mud bucket is used to drain away from the hole, trip tank or pits, then the combined volume of the steel pipe and the internal capacity of the pipe are removed. This results in a larger amount of fluid being required to fill the hole than when pulling dry pipe. However, if the mud bucket drains back into the hole, trip tank or pits, then the amount to fill would be the same as pulling dry pipe (providing mud bucket does not leak).

If a mud bucket is not used, it is difficult to account for spillage on the rig floor, decreasing the quantity of fluid that should be returned to the mud system and measured. If not all of the wet pipe’s fluid can be recovered, divert the fluid away from the active or measured pit volume and use the calculations for wet pipe.

Coiled tubing units are an exception. As the coiled tubing is extracted from the well, the tubing displacement and capacity are removed from the well. The coil stays loaded with fluid unless it is displaced with nitrogen prior to tripping out. Coiled tubing can circulate as the pipe is extracted, reducing chances for swab and keeping the hole full.

It should be noted that many tables do not have the correct data to use for trip calculations because they omit the tool joints and upsets. These tables simply list the size of the tube, and nominal weight per foot, for example, 5” OD (127 mm), 19.5 ppf (29.02 kg/m), as well as the capacities and displacements.

Manufacturers’ pipe data is accurate, but charts and tables may be confusing because there are many combinations of thread forms, tool joint ODs, IDs and lengths and a wide variety of capacity/displacement numbers. Pipe range also affects the adjusted weight per foot. API RP7G illustrates the methodology for calculating accurate pipe displacement and gives correct charts and tables.

The rate of pipe movement

directly affects swab or surge

pressures.

KICK FUNDAMENTALS2-17

To calculate the volume to fill the well when tripping dry pipe out:

Barrels to Fill = Pipe Displacementbbls/ft × Length Pulledft

m³ to Fill = Pipe Displacementm³/m × Length Pulledm

To calculate the volume to fill the well when tripping wet pipe out:

Barrels to Fill = (Pipe Displacementbbls/ft + Pipe Capacitybbls/ft) × Length Pulledft

m³ to Fill = (Pipe Displacementm³/m + Pipe Capacitym³/m ) × Length Pulledm

EXAMPLE 1How many barrels will it take to fill the annulus if 15 dry joints (assume each joint is 31’ [9.45 m]) of 4 1/2” (114.3 mm) drillpipe, with 0.00639 bbls/ft (0.00333 m³/m) displacement, were pulled from 9 5/8” (244.5 mm) casing having an ID of 8.755” (222.38 mm)?

Barrels to Fill = Pipe Displacementbbls/ft × Lengthft

= 0.00639 × (15 × 31)

= 0.00639 × 465

= 2.97 bbls

m³ to Fill = Pipe Displacementm³/m × Lengthm

= 0.00333 × (15 × 9.45) = 0.00333 × 141.75 = 0.47203 m³

PROBLEM 1AHow many barrels (m³) will it take to fill the annulus if 15 joints of 5” (127 mm) drillpipe (31’ [9.45 m] per joint, 0.007593 bbls/ft [0.00396 m³/m] displacement, 0.01776 bbl/ft [0.00926 m³/m] capacity) were pulled from 9 5/8” (244.5 mm) casing having an ID of 8.375” (212.73 mm)?

PROBLEM 1BHow many barrels (m³) will it take to fill the annulus if 15 joints of 2 7/8” (73.03 mm) production tubing (31’ [9.45 m] per joint, 0.00236 bbls/ft [0.00123 m³/m] displacement, 0.00579 bbl/ft [0.00302 m³/m] capacity) were pulled from 9 5/8” (244.5 mm) casing having an ID of 8.375” (212.73 mm)?

When tripping out dry, the volume of steel removed from the well must be replaced with an equal volume of fluid.

CHAPTER 22-18

To accurately measure the fluid, use a trip tank or pump stroke counter system. Filling the hole with a trip tank, if one is available, is preferred since the trip tank has a small, easily measured volume. However, the pump stroke counter system may also be used. To calculate the number of strokes to fill up the hole:

Strokes to Fill = Barrels to Fill ÷ Pump Outputbbls/stk

Strokes to Fill = m³ to Fill ÷ Pump Outputm³/stk

EXAMPLE 2How many strokes will it take to fill the hole with 2.97 bbls (0.472 m³) using a triplex pump with an output of 0.127 bbl/stk (0.0202 m³/stk).

Strokes to Fill = Barrels to Fill ÷ Pump Outputbbls/stk

= 2.97 ÷ 0.127

= 24 stks

Strokes to fill = m³ to fill ÷ Pump outputm³/stk

= 0.472 ÷ 0.0202 = 24 stks

Note: Since the strokes were a fraction higher than a whole number (i.e., 23.4), strokes are rounded up to the next highest number.

PROBLEM 2AHow many strokes will it take to fill the hole with a triplex pump with an output of 0.105 bbl/stk (0.0167 m³/stk), when 15 joints (31 feet [9.45 m] per joint) of 5” (127 mm) drillpipe, (0.007593 bbl/ft [0.00396 m³/m] displacement, 0.01776 bbl/ft [0.00926 m³/m] capacity) were pulled dry from 9 5/8” (244.5 mm) casing having an ID of 8.375” (212.73 mm)?

PROBLEM 2BHow many strokes will it take to fill the annulus with a triplex pump with an output of 0.049 bbl/stk (0.0078 m³/stk), if 15 joints of 2 7/8” (73.03 mm) production tubing (31’ [9.45 m] per joint, 0.00236 bbls/ft [0.00123 m³/m] displacement, 0.00579 bbl/ft [0.00302 m³/m] capacity) were pulled wet from 7” (177.8 mm) casing having an ID of 5.92” (150.37 mm)?

It should be noted that pump strokes never come out exact because of the lag time for mud to flow down the flowline and move the flow sensor. During this lag time the pump stroke counter continues to count. This adds around 5 to 10 (or more) strokes to the fill up.

Good practices and also certain regulatory bodies require that the well be filled every five stands of pipe pulled, or before the decrease in hydrostatic pressure equals 75 psi (5.17 bar), whichever comes first.

Measuring fill-up by pump strokes

is not perfectly accurate due

to the lag time as the fluid runs

through the flowline.

KICK FUNDAMENTALS2-19

To calculate the amount of dry pipe that may be pulled before a 75 psi (5.17 bar) reduction in hydrostatic pressure occurs:

Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft

– Pipe Displ.bbl/ft) ÷ Pipe Displ.bbl/ft

Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid densitykg/m³) × (Csg. Cap.m³/m

– Pipe Displ.m³/m) ÷ Pipe Displ.m³/m

EXAMPLE 3How many feet of dry 4 1/2” (114.3 mm) drillpipe with a displacement of 0.00597 bbls/ft (0.00311 m³/m) and a capacity of 0.01422 bbls/ft (0.00742 m³/m), could be pulled from 9 5/8” (244.48 mm) casing having an ID of 8.835” (224.41 mm) and a capacity of 0.07583 bbl/ft(0.03955 m³/m) with a fluid density of 12.5 ppg (1498 kg/m³) prior to a bottomhole pressure drop of 75 psi (5.17 bar) occuring?

Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft

– Pipe Displ.bbl/ft) ÷ Pipe Displ.bbl/ft

= (75 ÷ 0.052 ÷ 12.5) × (0.07583 – 0.00597) ÷ 0.00597

= 115.4 × 0.06986 ÷ 0.00597

= 1,350.4 ft

Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid Densitykg/m³) × (Csg. Cap.m³/m

– Pipe Displ.m³/m) ÷ Pipe Displ.m³/m

= (5.17 ÷ 0.0000981 ÷ 1498) × (0.03955 – 0.00311) ÷ 0.00311 = 35.18 × 0.03644 ÷ 0.00311 = 412.2 m

Note: It should be pointed out that in this example, even though 1,350.4 ft (412.2 m) of tubing could be pulled prior to a 75 psi (5.17 bar) decrease in hydrostatic pressure, regulations may require a limit on stands that may be pulled prior to fill up.

PROBLEM 3AHow many feet of dry 5” (127 mm) drillpipe with a displacement of 0.00709 bbls/ft (0.0037 m³/m) and a capacity of 0.01776 bbl/ft (0.00926 m³/m), a casing capacity of 0.056 bbl/ft (0.02921 m³/m) and with a fluid density of 13.8 ppg (1654 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring?

Trip tanks provide an accurate means of monitoring hole fill-up on trips.

CHAPTER 22-20

PROBLEM 3BHow many feet of dry 2 7/8” (73.03 mm) tubing with a displacement of 0.00224 bbl/ft (0.00117 m³/m) and a capacity of 0.00578 bbl/ft (0.00302 m³/m), a casing capacity of0.036 bbl/ft (0.00188 m³/m) with a fluid density of 14.3 ppg (1714 kg/m³) could be pulledprior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring?

To calculate the amount of wet pipe that may be pulled before a 75 psi (5.17 bar) reduction in hydrostatic pressure occurs:

Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft

– Pipe Displ.bbl/ft – Pipe Cap.bbl/ft) ÷ (Pipe Displ.bbl/ft + Pipe Cap.bbl/ft)

Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid Densitykg/m³) × (Csg. Cap.m³/m

– Pipe Displ.m³/m – Pipe Cap.m³/m) ÷ (Pipe Displ.m³/m + Pipe Cap.m³/m)

EXAMPLE 4 How many feet of wet 4 1/2” (114.3 mm) drillpipe with a displacement of 0.00597 bbls/ft (0.00311 m³/m) and a capacity of 0.01422 bbls/ft (0.00742 m³/m), could be pulled from 9 5/8” (244.48 mm) casing having an ID of 8.835” (222.41 mm) and a capacity of 0.07583 bbl/ft (0.03955 m³/m) with a fluid density of 12.5 ppg (1498 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring?

Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft – Pipe Displ.bbl/ft – Pipe Cap.bbl/ft) ÷ (Pipe Displ.bbl/ft + Pipe Cap.bbl/ft)

= (75 ÷ 0.052 ÷ 12.5) × (0.07583 – 0.00597 – 0.01422) ÷ (0.00597 + 0.01422)

= 115.4 × 0.05564 ÷ 0.02019

= 318.5 ft

Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid Densitykg/m³) × (Csg. Cap.m³/m

– Pipe Displ.m³/m – Pipe Cap.m³/m) ÷ (Pipe Displ.m³/m + Pipe Cap.m³/m) = (5.17 ÷ 0.0000981 ÷ 1498) × (0.03955 – 0.00311 – 0.00742) ÷ (0.00311 + 0.00742) = 35.18 × 0.02902 ÷ 0.01053 = 97.1 m

PROBLEM 4AHow many feet of wet 5” (127 mm) drillpipe with a displacement of 0.00709 bbls/ft (0.0037 m³/m) and a capacity of 0.01776 bbl/ft (0.00926 m³/m), a casing capacity of 0.056 bbl/ft (0.00291 m³/m) and with a fluid density of 13.8 ppg (1654 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring?

Good practices dictate that a

well be filled after five stands

of drillpipe (or one stand of

collars) are pulled out of

the hole.

KICK FUNDAMENTALS2-21

PROBLEM 4B

How many feet of wet 2 7/8” (73.3 mm) tubing with a displacement of 0.00224 bbl/ft (0.00117 m³/m) and a capacity of 0.00578 bbl/ft (0.00302 m³/m), a casing capacity of 0.036 bbl/ft (0.01878 m³/m) and with a fluid density of 14.3 ppg (1714 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring?

The fill up tally (volume or strokes) should be accumulated on the trip out as an overall check on fill. If tally is not close to calculated strokes or volume, a problem could exist. Often the well takes or gives fluid to the wellbore during trips. This is neither lost circulation nor a kick. It should be standard practice to maintain trip records on the rig. If formation seepage or fluid loss occurs, comparison with prior records is the only way to accurately predict hole fill volumes. Properly maintained trip records are invaluable in preventing kicks and showing how much fluid was lost to the formation.

When out of the hole, the well should be monitored and kept full. If the hole is taking fluid and fluid level is allowed to drop, hydrostatic pressure will drop also. In some cases (as in subnormal pressured zones), it may be necessary to maintain the static fluid

level at a level below surface to maintain a balanced condition. The fluid level should be maintained downhole by trickling fluid from measured tanks into the well and continuously monitoring.

The importance of keeping the hole full cannot be emphasized enough. On wells with shallow gas conditions, a small drop in hydrostatic and/or swab pressures can start the well flowing. At shallow depths, gas can be to the rig floor before a preventer has time to close. It is of the utmost importance to use proper hole fill techniques under these conditions.

Remember that the displacement of collars is five to ten times as great as the displacement of the drillpipe or tubing. Failure to fill up for each collar removed could drop the fluid level enough to start the well flowing.

Trip log while tripping in the hole; accurate trip records are a must on every job.

StandNo.

Starting TripTank Reading

Finish TripTank Reading

Difference Theoretical(Calculated)

Trend(Difference)

AccumulatedTrend

Remarks (Comment when change ofpipe, problems, etc.)

67 5 8.7 3.7 3.7 - - Starting in with collars

66 8.7 12.3 3.6 3.7 -.1

65 12.3 14.2 1.9 3.7 -1.8 -1.9

64 14.2 16.9 2.7 3.7 -1 -2.9 Slowing speed down, possible surge

63 16.9 20.6 3.7 3.7 - -2.9 Fill collars and monitored hole - ok

62 20.6 22.1 1.5 2.43 -.93 -3.83 Running collars in

61 22.1 25.3 3.2 2.43 +.77 -3.06

60 25.3 27.6 2.3 2.43 -.13 -3.19 Filled up hevi-wate

Running in with pipe

55 27.6 36.9 9.3 11.5 -2.2 -5.39 Slowing down run in speed

50 36.9 44.2 7.3 11.5 -4.2 -9.59 Still losing, emptied trip tank

45 0 12.7 12.7 11.5 +1.2 -8.39

44 12.7 27 14.3 11.5 +2.8 -5.59 Stop trip and check for flow

On a trip back in, do not assume the well is dead until bottoms up has been circulated.

CHAPTER 22-22

TRIPPING IN

In most cases after tripping out of the well with no indication of any influx, it is assumed that everything is okay and that tripping in should be no problem. But there are times when kicks are discovered after starting back into the well. On the trip back in, never assume the well is dead until you are back on bottom and have circulated bottoms up.

SURGE PRESSURES

Any time pipe is moved in the well, surge or swab pressures are present. On the trip back in, surge pressures are dominant. As pipe is being tripped into the hole, the fluid ahead of the pipe must get out of the way by moving upwards around the pipe. If the pipe is lowered too fast and not all of the fluid ahead of the pipe can move out of the way, a piston effect is exerted by the pipe pressurizing the wellbore ahead of the pipe.

If this pressure is great enough, lost circulation, formation breakdown or casing failure may occur, resulting in a loss of fluid and dropping hydrostatic pressure. If the reduction in hydrostatic pressure is below formation pressure, the well may start to flow. The same factors that increase the risk of swabbing increase surge pressures. These are: clearance, fluid properties and the rate of pipe movement.

CLEARANCE

As with swabbing, a critical factor affecting surge pressure while going into the hole is the amount of space between whatever is being run and the casing walls or wellbore. Several factors compound and reduce clearance.

w Casing vs. open holew Ballingw Salt or swelling formationsw Length of BHAw Number of stabilizersw Tools being run

CASING VS. OPEN HOLE

Presumably, casing is a gauged hole, but open hole is not. Depending on the amount of washout, open hole may have a larger ID than the casing. Drillers tend to trip at a faster rate in casing, and slow down in open hole, thinking most problems will occur in open hole. The rationale is that casing has a larger ID than open hole and there are no bridges or ledges in casing, so speed can be increased.

Look at it this way. Suppose the casing ID is 8.835” (224.41 mm) the bit 8.5” (215.9 mm), and the hole has washed out to 10.5” (266.7 mm). While tripping in casing the clearance between bit and stabilizers is 0.1675” (4.25 mm). In the open hole clearance is 1” (25.4 mm). That is 5.9 times more clearance in the open hole than casing.

If speed increases, while using a fluid with high viscosity and/or gel strength, surge pressure increases dramatically. To minimize problems, trip the pipe at a steady rate. Remember, this steady rate will vary with different tools and hole conditions.

BALLING

If balling was noted on the trip out, it can also be a complication on the trip in. The pipe should have been cleaned when coming out. However, when the bit, BHA and pipe contact wall cake and other materials in the open hole, balling may occur. This will reduce clearance and increase surge pressure.

SALT OR SWELLING FORMATIONS

When the BHA is run into a place in the well where the ID has been reduced, high surge pressure may be created. This causes loss of fluids into a weak formation. Whenever pipe is tripped out and tight areas are noticed, it should be noted on the driller’s report. In addition, the information should be relayed to the Company representative, toolpusher and other drillers. Going through tight spots can also cause BHA balling and increase surge/swab pressure from that point on.

The drilled hole may have a

larger ID than the casing due

to hole washout.

KICK FUNDAMENTALS2-23

LENGTH OF BHALike swabbing, surge pressure is increased

due to bottomhole assembly length. The longer the BHA, the longer the narrow corridor in which the fluid must flow upwards. This increases pressure below the bit to a greater degree than shorter BHA strings.

NUMBER OF STABILIZERS

The number of stabilizers complicates clearance. When stabilizers, which may be balled up, interrupt the narrow corridor between the collars and hole, the clearance decreases dramatically, and the amount of surge/swab pressure increases.

TOOLS BEING RUN

Surge pressure can be increased by many different tools: packers, bits, overshots or washpipe. Drillers tend to forget that surge and swab pressure also increases if a float or backpressure device is in the string. When tripping into a well, fluid has three routes it can take. Fluid can be displaced up the hole, move into a formation or go through the bit nozzles and up the string. When running a float, this path has been eliminated and surge pressure increases. A weep hole in the float will not greatly reduce surge pressure.

Remember: any time tools are run which reduce hole clearance, surge can occur.

FLUID PROPERTIES

When out of the hole, mud or fluid in the hole becomes stationary. Fluid thickening can occur under static conditions due to two factors. These are gel strength and water loss. Gel strengths develop in the mud because of tiny electrical charges that each molecule of mud possesses. These charges attract (like charges repel and opposite charges attract) and result in flocculation. Flocculation is the mud thickening by its attraction to itself. When the mud is stirred these tiny charges shear

apart and the fluid flows more readily. Also, while downhole, water loss to the formation is occurring. This dehydrates the mud and makes it thicker and less likely to flow. Periodically breaking circulation or pumping several minutes helps minimize surge pressure by keeping the fluid above the bit in better flow condition.

As pipe is tripped in, it displaces fluid that flows upward. This can lead to increased surge/swab pressure, which is akin to creating a higher equivalent mud weight (EMW) at various depths. This higher EMW could be sufficient to lead to fluid loss or break down a weaker formation and start a kick.

The water loss of the fluid can also lead to further complications. If the mud is dehydrating, the effective density is increasing. The amount of surge pressure needed to create losses is reduced as effective mud density increases. In addition, mud will lose part of its water phase, depositing more solids along the wellbore. This increases the chances for balling when the pipe contacts the walls.

SPEED

The most important factor affecting surge/swab pressure is the rate of pipe movement. One of the most obvious signs that surging is occurring is fluid coming over the top of a tool joint while tripping in with no float or backpressure valve. You know pipe is being tripped in too fast if the elevators are several feet (m) below the tool joint.

Steel will only displace fluid so fast. In addition, from a safety standpoint, the faster you trip, the more risk you run of injuring someone. It has been proven that there is little trip time difference between a steady rate and running wide open when coupled with downtime from damaged equipment.

Speed combined with BHA length, stabilizers, floats, packers, fluid properties and smaller diameters increase surge pressures.

When long bottomhole assemblies are run, swab and surge pressures increase.

CHAPTER 22-24

IMPROPER DISPLACEMENT

The amount of fluid displaced depends on what is run into the well. If the same string is run back into the well, the displacements should equal the amount of volume the hole took on the trip out. If the BHA is changed, or if the string is changed out, displacements will vary accordingly. If a float is used and pipe is not filled, what happens to the displacement?

Some companies use a trip tank coming out but nothing going back in. If a gravity-fed trip tank is used, it is above the flowline and can’t be used to measure displacement on the trip back in. The gain/loss gauge can be used in its place.

Too much fluid displaced over several stands is a good indication of getting something from a source other than pipe run in. If not enough fluid is displaced, then speed could be a factor surging fluid into the formation. Kicks have been caused by a surge that breaks down a formation, lowering the hydrostatic pressure and causing another zone to flow. Trip records must be kept on the job site for future reference. Displacements must be calculated prior to and monitored during the trip in. These calculations are essentially the same as calculating volume to fill up the hole on the trip out.

To calculate displacement (gain) while tripping in with no float or backpressure device:

Displacementbbls =Pipe Displacementbbls/ft × Length Runft

Displacementm³ =Pipe Displacement m³/m × Length Pulledm

With a float or backpressure device closed:

Displacementbbls = (Pipe Displacementbbls/ft

+ Pipe Capacitybbls/ft) × Length Runft

Displacement m³= (Pipe Displacement m³/m

+ Pipe Capacity m³/m ) × Length Runm

Although the above discussion used drillpipe as the example, anything being moved through fluid in the hole can cause swab/surge pressure. Wireline, tubing, tools, packers, pipe, collars, anything – if moved fast enough – can do a great deal of damage. It does not matter where in the hole you are (top, bottom or in between) these forces are present and can cause problems. Good practice dictates using good judgement on tripping and wireline speeds. Remember that the jobs that take the longest are usually the ones where hurry up and get things done are policy.

Preventing kicks on the trip out of the well is a serious matter. The following topics pertain to the entire trip, from the beginning to back on bottom drilling.

TRIP SUPERVISION

Not too long ago, the following procedure was followed when it was time to trip pipe. Offshore, the operator and toolpusher went to bed, as did the logging hands and mud engineer. On land rigs, these workers simply left the location. Most supervisors felt they were only needed during drilling operations and remedial efforts, and as a result, many well control events took place.

There are now numerous operators and contractors who require that a representative (toolpusher and/or company man) be present on the rig floor throughout the entire tripping process. Other companies require supervision when the first 15 stands of pipe are pulled, and from when the BHA begins to be pulled through the rotary table until it is out or the bit clears the rotary table bushings. Running in the hole requirements are the same: BHA through rotary and 15 stands off bottom. Some operators require a tourpusher so there is supervision 24 hours a day, regardless of the operation. You can never be too safe. In a critical time, two heads are better than one.

One obvious sign of surging is mud flowing

over the top of a tool joint while running into the well.

KICK FUNDAMENTALS2-25

TRIP RECORDS

A trip record is a critical but often overlooked part of tripping. It provides a means of measuring the amount of fluid it took to fill the hole due to the removal of steel volume (pipe). Trip records should also provide for monitoring the well while tripping out (gains or losses) and the amount of fluid displaced from the well on the trip in. All fluids should be measured. The two means of measuring this volume are trip tanks and pump strokes.

TRIP TANKS

The trip tank is the best and most accurate means of measuring the amount of fluid the hole is taking. Although we tend to measure and record the number of barrels every five stands, we should also break the trip down into stages prior to pulling the collars through the rotary table. Calculations of the theoretical barrels (m³) to fill each stage, as well as the total theoretical number of barrels (m³) to each stage, should be performed and checked against actual barrels (m³).

A trip tank hand will often round off the volume it took to fill the hole. If accurate measurements are not made a kick may enter the wellbore and not be noticed. So, in addition to recording barrels (m³) per five stands, a trip record for the entire trip should be made.

These figures can be checked against the trip tank gain/loss gauge readings. It can be further checked with the pit volume totalizer (PVT). If the hole takes less to fill, shut in the well and check for pressure. If pressure builds, but there is no flow when the choke is opened, the decision may be made to strip back in.

PUMP STROKES

Many rigs do not have a trip tank; they use pump strokes to measure fluid to fill the well. Although not as precise as trip tanks, the number of strokes to fill (plus strokes to flow down flowline and register against the flow sensor) can establish a trend. Once established, any major deviation from the average number of strokes should alert the driller that a downhole problem may exist. As in the example with the trip tank, a similar theoretical chart using pump strokes (versus volume) can be established and checked against actual strokes. The volume should be double-checked using the gain/loss gauge and your PVT.

TRIP MARGINS

There is a misconception that a trip margin and a slug are the same. However, there are important differences between the two.

Trip log while tripping out of the hole

StandNo.

Starting TripTank Reading

Finish TripTank Reading

Difference Theoretical(Calculated)

Trend(Difference)

AccumulatedTrend

Remarks (Comment when change ofpipe, problems, etc.)

5 50 48.5 1.5 3.56 -2.06 -2.06 Pull DP Off bottom - may be balled

10 48.5 42.9 5.6 3.56 +2.04 -.02 Seems ok

15 42.9 39.2 3.7 3.56 +.14 .12

20 39.2 35.9 3.3 3.56 -.26 -.14

25 33.2 30.5 2.7 3.56 -.86 -.96 Possible swab

30 33.2 32.3 .9 3.56 -2.66 -3.62 Hole not taking proper fluid, stop

Trip and check for flow

Since all wells act differently, it is good practice to compare trip data with previous trip records.

CHAPTER 22-26

A slug will not increase the bottomhole pressure prior to a trip. A minimal hydrostatic pressure increase occurs only when the slug falls out of the pipe.

A trip margin is an increase in the hydrostatic pressure of mud that compensates for the reduction of bottomhole pressure due to loss of circulating pressure and/or swabbing effects of pulling pipe. This reduction is also influenced by the fluid’s viscosity and gel strength.

LOST CIRCULATION

Any time the fluid level in the well falls so does the hydrostatic pressure. If the hydrostatic pressure of the fluid falls below formation pressure, the well may start to flow.

MUD VS. COMPLETION FLUIDS

The majority of wells are drilled overbalanced, or close to their balance point, with drilling mud. Drilling mud has a lot of viscosity in order to support and clean the hole of cuttings. This mud property resists the fluid going into the formation. The particles (usually bentonite) that give mud carrying capacity are generally larger than the formation’s pore spaces and block the majority of the fluid phase of the mud from entering into the formation. As a result, higher mud weights can be used with a minimum of fluid loss.

Many drilling rigs are carrying the well through completion. In the completion phase of the well, clear fluids are used to minimize the risk of formation damage and blockage.

TRIP MARGIN EXAMPLE:

TVD 8,640' (2633.47 m) fluid weight 9.1 ppg (1090 kg/m3), formation pressure 4,050 psi (279.25 bar). Present overbalanced margin is 38 psi (2.62 bar). In order to obtain a 75 psi (5.17 bar) trip margin, prior to the trip a heavier fluid density should be circulated throughout the annulus. This can be calculated by:

Trip Marginppg = (Margin Neededpsi – Present Marginpsi) ÷ 0.052 ÷ Depthft, TVD

= (75 – 38) ÷ 0.052 ÷ 8,640

= 0.08 ppg

Trip Marginkg/m3 = (Margin Neededbar – Present Marginbar) ÷ 0.0000981 ÷ Depthm, TVD

= (5.17 – 2.62) ÷ 0.0000981 ÷ 2633.47

= 9.87 kg/m³

In this example, prior to tripping, you need to increase the fluid weight to a 9.2 (1102 kg/m3). This extra margin will give an 83 psi (5.72 bar) increase in bottomhole hydrostatic pressure. In some geographical areas, trip margins may not be needed due to low permeability of the formations. In other areas, they are needed. Exercise caution when selecting a margin.

A slug will not increase the bottomhole

pressure prior to a trip.

KICK FUNDAMENTALS2-27

Clear fluids usually have a low viscosity. They also have been filtered to remove particles that would block the formation pore spaces. If a clear fluid is used, and that fluid exerts more hydrostatic pressure than the formation’s pressure, there is nothing to slow fluid loss and severe lost circulation may occur.

CIRCULATING PRESSURE

Many times the wellbore fluid level seems to be stable, but when circulating a decrease in fluid volume is seen. This is because of the extra pressure exerted on the formation while in the circulating mode. When the pump is moving fluid throughout the well, friction must be overcome. This friction adds to the bottomhole pressure. If the friction pressure and the hydrostatic pressure of the mud exceed the formation pressure, then partial or total lost circulation may occur.

SURGE PRESSURE

Surge pressures can be created from pipe movement exerting a piston effect on the formation. These pressures may cause formation breakdown and/or lost circulation. Small clearances between the bottomhole assembly and casing and the speed of pipe going into the hole should be considered.

It is not desirable to lose fluid to the formation. The well may kick from a reduction in hydrostatic, and the fluid invading the formation’s pore spaces may block or reduce productivity once the well is completed. When fluid is lost it may induce a water drive into the formation, forcing gas back into the well, thus reducing the pressure exerted on the formation and allowing the well to flow.

OTHER CAUSES OFABNORMAL PRESSURE

Abnormal pressures may be encountered in any area where the pressure gradients are higher than normal. Abnormal pressure may develop in a zone for a number of reasons. These include:

w Inadequate cement bonding that allows pressure from one zone to migrate or feed to and pressure up another;

w Formations charged through overbalanced drilling or by underground blowouts;

w Zones that are charged from injection projects such as steam injection, water or fire flooding, CO2 or gas injection projects;

w Casing failure or leaks;

w Formation fracture from one zone to another, whether naturally occurring or man made (excessive frac jobs).

Additionally, higher than expected pressures are often the result of bad information or faulty testing during drilling, testing or completion operations. It should be evident that higher than expected pressures can occur. So every well should be treated with respect. It cannot be stressed enough that is it necessary to expect the unexpected and have some plan of action if the unexpected happens.

WELLBORE OBSTRUCTIONS

When a wellbore obstruction exists, it must be remembered that pressure may be trapped below it. If drilling or milling through something blocking the wellbore (such as a packer, cement plug, collapsed casing or bridged over wellbore), extreme care must be used. The

Poor cement bonds can result in formation fluids seeping from one zone to another.

CHAPTER 22-28

crew must be aware of this possibility and be prepared to take immediate action. The well may be lined up through the choke manifold and drilled under a more controlled state in case of a kick.

One example to illustrate this danger is a gas well that was plugged and abandoned, but is now being redrilled. A 7,000’ (2133.6 m) TVD well with a pore pressure of 7.4 ppg (887 kg/m³) would have a formation pressure of 2,693 psi (185.68 bar) and would pressure the wellbore below the plug. If a cement plug was set at 2,000’ (609.6 m) and we were drilling through it with oil emulsion mud that weighs 7.4 ppg (887 kg/m³), the drilling fluid would exert a hydrostatic of 769 psi (53.02 bar). Once the bit clears through the cement, you will have quite a bit more formation pressure (about three times as much) than fluid pressure. Here there is 2,693 psi (185.68 bar) upward force against 769 psi (53.02 bar) of downward pressure. What do you think will happen? In reality, the weight of the formation fluid will reduce the upward force a bit at that depth (depending on the density of the reservoir fluid), but it will surely be greater than the mud’s hydrostatic.

RIG EQUIPMENT DIFFICULTY OR FAILURE

Rig equipment is usually designed for harsh working conditions. It is always subjected to wear and tear. The best designed piece of equipment eventually wears out, even with the best of preventive care. The winter weather, saltwater environments, exposure to H2S, or corrosive formation fluid, rig moves, etc., all take a toll on equipment.

Many blowouts have occurred because equipment failed. It may be the failure of just one piece of equipment that leads to an uncontrollable situation.

For example, if the pump went down while we were circulating and conditioning the fluid

in the hole, circulating pressure imposed on the formation would be lost. The well may begin to slowly feed in. Since it does not appear to be flowing, the crew turns to the problem of getting the pump back online.

Who’s watching the well? As the well begins to flow, it picks up momentum, faster and faster, until it cannot be safely controlled. As the preventer is closing, the force of the well’s fluid may cut the sealing elements and result in failure of the BOP. If the BOP successfully closed, a reused ring or bad seal in the stack may start to leak and get out of hand.

Remember: just because you have found one problem, don’t assume that it is the only one. Always maintain a watch on the well and the BOP equipment.

Regular testing of equipment on a well, whether weekly or according to regulations, is essential to provide maximum safety. You can’t predict when something will fail. It is better to get a failure during a test than when you are counting on the equipment to save your life.

CEMENTING OPERATIONS

Kicks that occur while cementing are the result of reducing the mud column pressure during the operation. Several wells have been lost because of improperly designed cementing programs. Many more have been lost by a failure to follow the program. Different events can lead to a reduction of the hydrostatic pressure below the formation pressure.

w A spacer or flush is pumped ahead of the cement. If it is not of adequate density, the well may begin to flow.

w The density of the cement must not be great enough to cause lost circulation.

w If lightweight cement is used, pressure across the choke may be held to compensate. If inadequate pressure is held, the well may flow. Too much pressure

Unexpected high pressures

may be trapped below packers or other downhole

obstructions.

KICK FUNDAMENTALS2-29

and lost circulation may occur. A pressure/ pump schedule should be utilized and choke pressure adjusted accordingly.

w Cement will dehydrate as it sets up. This may reduce the effective hydrostatic, allowing the well to flow. Often the cement is designed to set in stages to minimize this effect.

w Cement heats up as it hardens. This may cause expansion of tubulars. As it cools, a micro-annulus can be created giving a channel allowing fluid movement.

w There have been instances where the casing float equipment has failed.

The well should be closely monitored during all phases of the cementing operation. The BOPs should not be nippled down until you are sure that the well will not flow.

UNUSUAL KICK SITUATIONS

It should be apparent that there is no way to drill a well without the threat of a kick. Following are a few conditions/operations that have led to kicks or blowouts.

DRILLING INTO AN ADJACENT WELL

There have been numerous cases where another well has been penetrated and a kick taken from the other well. Platform/template drilling using multiple well paths obviously has a high potential. These events have also been reported in areas with no visible wells and where poor records didn’t warn of prior wells. If the annulus of the well drilled into is filled with a heavy packer fluid, it may U-tube into

A well-trained crew is the only sure method of kick recognition.

Wells have been lost due to kicks taken during cement jobs.

CHAPTER 22-30

the well being drilled. If the well drilled into is pressured, an extreme increase in flow may result. Wells that have little annulus fluid or that have been abandoned may have little or no annulus fluid and signs of losses may occur. Avoidance through a proper well program should minimize this threat.

TESTING BOPS

There are several considerations during the testing of BOPs that are often overlooked and might lead to a kick.

Attention is focused on the actual testing process, not on observing the well. If the testing procedures take several hours to complete, what is the status of the well? Is there pressure building up below the test tool? Was the casing valve below the BOP stack left open in order to avoid pressure buildup? Is the well flowing through this open valve? Is the well taking fluid? These questions should be kept in mind and the well monitored.

Often on platform operations, the BOP stack on the wellhead/tree may be 60 to 90 ft. (18.29 to 27.43 m) or more from the riser to the flowline. If the stack is tested, it is common practice to drain the riser line before testing with water. This can result in a significant drop in the hydrostatic pressure. A loss of 10 ppg (1198 kg/m³) over 90 ft. (27.43 m) would equal 47 psi (3.24 bar). This pressure loss may allow the well to flow.

DRILL STEM TESTS (DST)

The DST is essentially a temporary comple-tion of a producing zone. Formation fluids and formation pressure are allowed into the well and the DST test string. If not treated as a kick, this may lead to the well flowing after the DST has been completed. Some important considerations include:

Will reverse circulation be used? If so, has any kick fluid migrated up the annulus that will not circulate into the tubing? The annulus should be treated as active.

It is possible that the bypass tool may be above the influx fluid. Circulating may not displace the influx totally from the well.

If a positive choke is used for the DST, the orifice (bean) may be so small that circulating becomes impractical. If reverse circulating is to be attempted, it may plug easily. Consideration must also be given to this circumstance and, if it plugs, what well control method will be employed.

UNDERBALANCED DRILLING

If underbalanced drilling is used in non-producing formations to increase penetration rates, what happens when a producing formation is encountered? Influx flow potential is high. Producing depths should be known and kick warning signs closely monitored.

PLATFORM LEG

There have been several unexpected blowouts from support mechanisms. Jacking a rig up or setting a platform on top of unmarked pipelines have caused a few. And abandoning a platform and pulling the support beams driven with several hundred feet penetration has provided a channel for shallow gas to surface.

SUMMARY

When it comes time to shut in the well, a correct decision must be made quickly. There may be no time to get a second opinion. The well is building up momentum while you are figuring out what to do. When in doubt, shut in the well. The cost of a shut in versus the potential loss of resources, equipment and human life is insignificant.

Once the decision is made to shut in the well, do it quickly and according to procedures. Wells have been lost because there have been no set procedures or poor procedures that led to indecision and the wrong path of action.

A drillstem test may be

considered a temporary

completion of a production zone.

KICK FUNDAMENTALS2-31

Procedures for shutting in the well should be set, known and followed.

Inexperienced crews need to be trained on the proper procedures for shutting in a well. Once they are trained, each member should practice until proficient. The crew should be rotated among job assignments so they become familiar with everyone’s job responsibilities. Not everyone is always present, so everyone should know correct procedures to shut in the well. Drills should be performed on a weekly basis, unless regulations dictate otherwise, to make sure everyone is familiar with and proficient at their job.

Blowouts are prevented by crews able to detect the well is kicking and take proper action to shut in the well. This requires training, practice and experience from crews able to react quickly and calmly under pressure.

Kick detection techniques are all subject to interpretation or erroneous measurements. With these limitations, prediction techniques are still worthwhile because the best way to kill a kick is to avoid it. Prediction techniques are usually reliable and if all methods are intelligently applied, chances are good that some indicators will be obvious. To avoid a well kick fluid weight must be heavy enough to

dominate formation pressures without losing circulation or repressing drilling rate. Prediction of high pressures encountered when drilling can be measured in three ways. They can be predicted from geological and seismic evidence before the well is drilled. Increasing or decreasing pressures affect drilling, and changes in drilling conditions can alert the driller that the pressure exerted by the mud column is too low. Mud logging techniques can warn of increasing pressures and can be used to monitor formation pressures. Finally, MWD and wireline logs can be interpreted to give formation pressures.

The important thing to remember is that kicks can occur at any time. Kicks and blowouts have occurred during all operations. While some regions have a lower risk factor than others, they are still at risk.

Kick prevention requires planning. Set the procedures to shut in the well and develop contingency plans in case something goes wrong.

What you expect, what you anticipate and what you are prepared for keep you out of trouble. What you don’t expect, don’t anticipate and are not prepared for can cause the loss of life, equipment and property. t

Blowouts are prevented by well-trained,knowledgeable crews.

CHAPTER

3

Minimizing the

amount of influx

significantly increases

the chances of

a successful well

control operation.

I n order to detect a kick in its earliest stages, we must be aware of the indicators that can warn us that the well is flowing.

If one or more of these warning signs is observed, it should be assumed that the well could be flowing. The correct action at this point is to check for flow. If the well is flowing, but we are not pumping, that is a sure sign that a kick is in progress. However, in certain areas a ballooning effect is common. That is, the well will flow for a considerable length of time before stabilizing. Field experience will dictate exact techniques for flowchecks on any well. Never try to explain warning signs as being another type of problem until it is proven that the well is not kicking. In some regions, warning signs that would be an indicator of a kick are considered normal for that area. Always assume the well is kicking until it can be proven otherwise.

3-1

DETECTIONOF KICKS

CHAPTER 31-23-2

PENETRATION RATE CHANGE

An abrupt change in the rate of penetration usually indicates a formation change, often encountered while drilling. Many things, including bit type, affect penetration rate. The term drilling break has been used when penetration rate increased, indicating a low-density formation. If a drilling break was encountered, a flowcheck was performed. With today's newer PDC/TSP bits, a slowdown or decrease in penetration rate may be experienced in low-density formations. Now drillers may not only perform flowchecks for drilling breaks, but for reverse drilling breaks as well. When in doubt, flowcheck the well each time a new formation is encountered or the rate of penetration changes.

FLOW RATE INCREASE

When the pump is running at a constant rate, it displaces a fixed amount of fluid into the well every minute. Since the injection rate of fluid into the well is constant, the rate of fluid return should also be constant. The rate of flow at surface is measured. Formation fluid may be feeding in if an increase in fluid volume is seen (more flows out than we pump in) while the pump rate has not changed

False indications of high flow can be due to large pieces of formation or junk getting hung up under paddle type flow sensors. Regardless, a flowcheck should be performed until it has been proven that the well is not flowing.

VOLUME GAIN

Formation fluid entering the well will displace or kick fluid out of the hole, resulting in a gain in pit volume. The increase in total pit volume warns the crew that a kick may be occurring. All circulating tanks should be measured and marked so additional increases will be promptly noticed. Pit-volume totalizer systems (PVTs) are required by regulations and operators for many activities and in various areas. They will keep track of the total volume of mud in the active mud system. In addition, both audible and visual alarms can be set to activate at desired gains (for kicks) and losses (for lost returns).

Near right: a geolograph

records real time events for future

use.

Far right: a change in rate of

penetration; note the drilling break

at approximately 8 and150 feet.

Penetration rate: feet per hour at

which the drill bit deepens the

wellbore.

DETECTION OF KICKS1-33-3

Flow check while drilling:• stop rotating• pick up off bottom• shut down the pump(s)• observe the well carefully

time then it must be assumed the formation is kicking and the well must be shut in. A flowcheck is one early way a kick can be detected. Any of the other indicators will come later.

There can be cases of flow from the annulus not due to the formation kicking. These include:

1. Charging pumps that did not shut down when rig pumps were turned off.

2. U-tubing of heavier fluid in the string to the annulus. This is most frequent when some gas cutting of returns at surface has been experienced. A favorite method of rig hands to check for U-tubing is to hit the pipe with a hammer. If the pipe has a hollow ring, U-tubing is indicated. If it has more of a dull thud, the pipe is full of mud dampening the sound, so there is no U-tubing. Another indication of U-tubing is that the rate of annular flow decreases appreciably after only a few barrels

3. Flowback of mud due to ballooning. Ballooning has been attributed to mud being lost into fractures or elasticity of the formation

Notify proper rig personnel when transferring fluids. Also, use measured quantities of material when adjusting the fluid density or adding chemicals. In this way, additional increases can be tracked and excess or unexpected gains recognized.

It should be cautioned that pit levels may be difficult to use as kick indicators when mixing, transferring or in certain formations that have hydrating clays adding volume to the system.

FLOW – PUMP OFF

Whenever a drilling break or a reverse break is encountered, it is recommended that the driller stops drilling immediately and performs a flowcheck. The flowcheck is performed by stopping rotation, picking up the pipe to connection height, shutting down the mud pumps and watching for flow from the annulus after allowing for the usual drainback. If flow ceases, then drilling will probably be resumed. If the flow persists after the usual drainback

Return Flow Rate Check

far left, a float type pit level sensorleft, a flow rate sensorbelow, an influx of formation fluid will cause an increase in flow from the well

3-4CHAPTER 3

PIT

Well

Flowing

with

Pump

Off

Well flowing with pump off

that balloons the wellbore by the annular friction pressure. When the pumps are stopped, the annular friction pressure is removed. This allows either the fracture to close up and squeeze mud back into the wellbore or the ballooned wellbore to return to its original size. The flowback can be quite extensive.

If this is the first incident of ballooning encountered at this location, it must be treated as a genuine kick and must be circulated out as a kick. Ballooning may be indicated by low shut-in pressures, i.e. pressures below annular friction pressure loss. Shut-in drillpipe pressure would be nearly the same as shut-in casing pressure and would show no increase due to gas migration. When circulated out, the mud returns will not show any appreciable gas, oil or water contamination.

Maintaining a mud gain/loss log may be helpful in determining the existence of ballooning since flowback should equal mud loss. Mud loss can be difficult to detect because of mud making formations and also because of mud mixing operations.

If ballooning is suspected, the Driller's Method is preferred to circulate the first bottoms up, to avoid mud weight increase usually caused by other methods. Mud weight increase will probably increase the ballooning effect.

Slower circulating rates (and consequently less circulating pressure) should be considered because this equates lower annular pressures

and minimizes the amount of ballooning. After the first bottoms up has been circulated out, the shut-in pressures should be lower than on the initial shut in. This is because the annular friction pressure loss will be lower at the kill rate than at the drilling pump rate.

If ballooning is suspected after the first circulation, slowly bleed volume from the annulus. Carefully observe the flow rate to see if flow decreases appreciably after a few barrels, thereby indicating ballooning and not a kick.

Obviously, ballooning must always be treated with caution. It can present a confusing situation that consumes considerable rig time.

Circulating a deep, hot hole with cold fluid can give the appearance of flow as the cold fluid heats and expands.

SPEED/PRESSURE CHANGE

An influx of formation fluid will usually decrease the density of the fluid column. As this occurs, the hydrostatic pressure exerted by the fluid column decreases. As the annular hydrostatic decreases, the mud in the string tends to U-tube into the annulus. When this occurs, the pump pressure will decrease and an increase in pump speed may be noted. This effect will also be aided by the expansion of gas upwards, lifting some of the fluid and further reducing the fluid column's total pressure.

Pit Gain

Gain in VolumeAn increase in pit volume may indicate that the well is flowing.

Ballooning: the tendency of

some formations to apparently

accept drilling fluid when

circulating, then give it back

when the pump is shut down.

3-5DETECTION OF KICKS

It should be noted that the initial surface indication could be a momentary increase in pump pressure. The pump pressure is seldom noticed because of the short duration, but it has been seen on some pump pressure charts after a kick was detected. This was followed by a gradual decrease in pump pressure accompanied by an increase in pump speed.

This same drop in pump pressure and increase in pump speed is also characteristic for pumping a slug or, when there is a hole in the string, commonly referred to as a washout. In either case, a flowcheck must be performed to determine if a kick is in progress.

GAS/OIL SHOWS – CIRCULATING

In many areas and activities, a gas detector is required to monitor the fluid returning from the well, and to help detect abnormal pressure trends. When an increase in gas is detected, oil or gas may be feeding in because of insufficient pressure imposed on the well. While it is true that gas-cut mud rarely starts a kick, if severe or shallow enough, it may cause a further decrease in hydrostatic pressure. As more gas feeds in and expands, the hydrostatic pressure will continue to drop until the well starts to flow.

Some zones exhibit a slow feed-in of formation fluid and rarely will cause a well

to blow out. However, a kick is the unwanted feed-in of formation fluid. Gas/oil shows could be indicators of a kick, and should be treated as such. Circulating through the choke may be wise to safely remove gas or oil away from the work area.

Besides mechanical means of observing returns, a rig may use a shaker hand. The shaker hand is able to observe the mud and determine if it is gas-cut, or if signs of formation oil are in the returns.

IMPROPER FILL AMOUNTS

Tripping out of the hole may be the most hazardous time on a rig and one of the most common causes of kicks. Contributing factors include: loss of circulating pressures, swabbing effect of pulling pipe, and improper fill-up that reduces hydrostatic pressure. With these factors working against us, a trip tally of stands pulled versus fluid to fill, plus visual verification is imperative. Often regulations require the use of mechanical devices to accurately determine the hole fill on trips. Also, the amount of fluid it takes to fill the hole for specific lengths (e.g., five stands of drillpipe) of both wet and dry pipe as well as the length of pipe pulled before a reduction in hydrostatic pressure (e.g., 75 psi or 5.17 bar) is reached must be posted.

Gas

Un

its

Depth

Oil inReturn

Increase in Gas

An increase in gas and signs of oil in pits

2

60

4 2

60

43000

50001000

3000

50001000

TRU-VUEUnitized Pressure Gauge

Pump Speed80

Pump Speed88

Change in pump pressure/speed due to a kicking well

If the well is not taking the proper amount of fluid to fill we can assume that formation fluid is invading the wellbore.

CHAPTER 31-63-6

If the well is not taking the proper amount of fluid we can assume that formation fluid is invading the well (or that we are losing fluid if it is taking excess fluid to fill the hole). However, it must be cautioned that proper data must be used for calculating the steel displacement and internal capacity values. Trip book records should be kept onsite and used to confirm that the hole is taking at least as much mud as on previous trips. Often prior records may indicate an excess of as much as twenty five percent. If prior records are available, the first indication of a kick while tripping out will be that the hole takes less to fill than recorded at that depth on previous trips.

STRING WON’T PULL DRY

When tripping out, it is possible for the formation fluid to enter the well at a rate great enough to prevent the fluid inside the pipe from falling. Also, when a flow begins it may be easier for the flow to enter the string, when pulling large diameter tools and packers, than to flow around them. If the string should pull dry at first, but then it begins to pull wet later, the trip should be suspended. A full opening safety valve should be installed on the pipe, and well conditions evaluated.

KICKS – OUT OF THE HOLE

Well kicks occurring when out of the hole often began during the trip out but were not noticed. The kick may have started during the early part of the trip out. More likely, the kick started when the hole was not filled frequently enough towards the end of the trip or while handling the collars.

Similar situations may occur during lengthy logging, wireline or fishing operations. Frequent trips in and out of the hole with these tools can swab formation fluids into the well, causing a kick.

The indicator of a kick when out of the hole is flow from the well. When out of the hole, it is good practice to close the blind rams and monitor pressure at the choke. Closing the blind rams prevents objects from falling into the wellbore and will prevent flow if the choke is in the closed position.

If the choke is closed, it is a good idea to have a pressure sensitive alarm to monitor pressure buildup on the shut-in system. If the choke is left open, a watch should be set to check for flow from the choke manifold. The pit alarm should be set to its lowest alarm setting.

Regardless of the procedure, never open the BOPs to rig personnel until the area below has been vented to a safe location.

Trip log while tripping out of the hole

Kicks noticed while out of

the hole usually are the result of

the trip out.

Stand Starting Trip Finish Trip Difference Theortical Trend Accumulated Remarks (Comment when change No. Tank Reading Tank Reading (Calculated) (Difference) Trend of pipe, problems, etc.)

5 50 48.5 1.5 3.56 -2.06 -2.06 Pull DP off bottom - may be balled

10 48.5 42.9 5.6 3.56 +2.04 -0.2 Seems OK

15 42.9 39.2 3.7 3.56 +.14 .12

20 39.2 35.9 3.3 3.56 -.26 -.14

25 33.2 30.5 2.7 3.56 -.86 -.96 Possible swab

30 33.2 32.3 .9 3.56 -2.66 -3.62 Hole not taking proper fluid, stop

Trip and check for flow

DETECTION OF KICKS1-73-7

Often in workover operations, and in areas where lost circulation is a problem, circulation across the stack – pumping from and returning to the same tank – will ensure the well stays full. If this system is used, alarms for gain and loss should be set on the circulating tank.

DISPLACEMENT – TRIP INAs pipe is run into the well, it should

displace fluid out equal to pipe's displacement if no floats are in use. If pipe is lowered too fast, fluid may be forced into the formation ahead of the pipe due to surge pressures. This can result in lowering the fluid column and reduction of hydrostatic pressure. If this decrease lowers the pressure exerted by the fluid to a point below formation pressure, well will begin to flow.

With an influx in the hole, more volume will be displaced out of the hole than the pipe's displacement. This is due to gas expansion and/or a flowing well.

Proper tripping procedures cannot be overemphasized. The well should be monitored continuously. If the fluid displaced out does not match the displacement of pipe going in, there is a problem. The fluid being displaced out of the hole should always be measured.

STRING WEIGHT CHANGE

The fluid in the hole provides buoyancy. This means that the string weight of the pipe in the fluid decreases by an amount equal to the weight of the fluid displaced by the pipe. The heavier the fluid (or the higher its density), the more buoyancy the fluid will provide. If a string weight increase is noticed, the increase could be due to an influx of formation fluid decreasing the density of the fluid surrounding the pipe. As the fluid density decreases, the ability of the fluid to provide buoyancy is reduced, resulting in an increase of weight that will be noticed at surface. This weight increase may be noticeable depending on the amount of influx, the influx density and the length it occupies. Generally, in a larger wellbore this will not be as pronounced as in a smaller diameter wellbore.

If there is a decrease in string weight, the decrease could be due to formation fluids forcing upwards against the pipe. The well should be shut in without delay and control procedures evaluated.

Swab

Kicks While Out of Hole Kicks whileout of the hole

Flow check while tripping:• stop trip• set pipe in slips• stab full opening safety valve and close• observe the well carefully

3-8CHAPTER 3

WirelineUnit

KICKS WHILE LOGGINGOR WIRELINING

Well kicks that occur while logging and during wireline activities are the result of:

• The swabbing action of the tools being pulled through a tight section of hole.

• The swabbing effect of tools being pulled too fast.

• Failing to keep the hole full during such activities.

A major concern is that the kick may have been allowed to progress. It may become quite large before someone notices it or makes the decision to shut the well in. Always monitor the hole and keep it full.

Consideration should always be given to the use of a wireline lubricator. A lubricator long enough to encompass the tools will allow the string to be pulled from the well, if a kick occurs, without having to cut the wireline to shut in the well.

KICKS WHILE RUNNING CASING

Kicks that occur while running casing are similar to kicks while tripping. An important point to remember about kicks while running casing is that rig operations are oriented to running casing, not to detecting a well kick or shutting in a well.

When running casing, a well kick can be detected by observing that the flow of displaced mud does not stop between joints of casing. Be sure to use the flow sensor and pit volume totalizer while running casing. Good procedures require that calculations be made for the displacement of the casing and couplings. A log comparing theoretical and actual displaced volumes will help to determine that proper volumes are being displaced. If a kick is detected, the well should be shut in using casing rams or the annular preventer. A circulating swage should be available on the rig floor to

Right: using a lubricator can prevent blowouts.

Below: casing operations.

While running casing the focus

is not on kick detection.

Remember to monitor returns

and check against

calculations.

3-9DETECTION OF KICKS

fit the casing being run. A high pressure, low torque valve should be made up on the swage, checked for proper operation and noted on the drilling report prior to running.

Caution should be used if the annular preventer is to be closed. Closing pressures should be checked against collapse ratings of larger and lower grades of casing.

KICKS WHILE CEMENTING

Kicks that occur while cementing are the result of reducing the mud column pressure during the operation. This reduction of mud column pressure can result from light cement slurries, lost circulation, improperly weighted spacer or the mechanics of the cement setting up.

When pumping cement the flow sensor should be monitored for increases. Pit volume increases and cement displaced should be monitored to make sure volume of mud displaced is essentially equal to cement volume pumped.

Another complication is that once the top plug has bumped, nipple down procedures may

begin and if flow is noticed, it is often attributed to temperature expansion. Regulations may dictate time requirements prohibiting nippling down activities and allowing the cement to set. Under no circumstance should stack be nippled down until the possibility of a kick is eliminated. If the well does flow, conventional circulating techniques cannot be used. So techniques such as bullheading, lubricate and bleed or volumetric procedures must be considered.

SUMMARY

Kick detection is everybody's responsibility. Rigs have been lost because of a failure to alert the supervisors that the well may be flowing. It is important to recognize warning signs of kicks. If one or more of these warning signs are present, the crew and rig are in danger. Always take the time to check these signs to determine if the well is kicking. Remember, a sure sign that a kick is in progress is if the well flows with the pump off. We must check for flow. Proper action to shut the well in may be the next step. t

Cementing unit

A sure sign that a kick is in progress is if the well flows with the pump off.

CHAPTER

4

Influx behavior

differs depending

on the type of kick,

the well geometry

and the fluid

in the well.

W hat is a kick? A kick is simply the displacement of fluid at the top of a hole by an unwanted influx of

formation fluid. A kick should not occur if the hydrostatic pressure of the fluid is at least slightly in excess of the formation pressure.

A BLOWOUT IS ANUNCONTROLLED KICK

A kick that is not recognized, or is allowed to continue, will unload the fluid from the well. When a kick takes place, and it is not recognized, or if no action is taken, then it could develop into a blowout. It will blow out the fluid, and hence its name. If the well unloads from one zone into another formation, that is called an underground blowout. When a kick

4-1

KICKTHEORY

CHAPTER 44-2

1. Calculate estimated kick length: Estimated kick length = Pit Gain ÷ Annular Capacity (at kick position)2. Calculate approximate density: Kick Density = MW – ([SICP – SIDPP] ÷ [Kick Length × Conversion Factor])

EXAMPLE 1Calculate the estimated density of the influx given the following information.

SITP = 400 psi (27.58 bar) SICP = 600 psi (41.37 bar) Hole Size = 8 1/2" (215.9 mm)Collar Size = 6 1/2" (165.1 mm) O.D. Mud Wt = 11.8 ppg (1414 kg/m³) Pit Gain = 15 bbls (2.38 m³)Annular Capacity Around Collars = 0.029 bbls/ft (0.01513 m³/m)

Estimated Kick Lengthft = Pit Gainbbls ÷ Annular Capacitybbls/ft = 15 ÷ 0.029 = 517 ft

Estimated Kick Lengthm = Pit Gainm³ ÷ Annular Capacitym³/m = 2.38 ÷ 0.01513 = 157.3 m

Kickppg = MWppg – ([SICPpsi – SIDPPpsi] ÷ [Kick Lengthft × 0.052]) = 11.8 – ([600 – 400] ÷ [517.24 × 0.052]) = 11.8 – (200 ÷ 26.896) = 11.8 – 7.436 = 4.36 or 4.4 ppg

Kickkg/m³ = MWkg/m³ – ([SICPbar – SIDPPbar] ÷ [Kick Lengthm × 0.0000981]) = 1414 – ([41.37 – 27.58] ÷ [157.3 × 0.0000981]) = 1414 – (13.79 ÷ 0.0154) = 1414 – 895.45 = 518.55 kg/m³

takes place, action must be taken by the crew quickly to bring the well under control.

The effects and behavior of kicks must be understood in order to prevent kicks from turning into blowouts. A gas kick must be allowed to expand as it comes up, with most of the expansion near the surface. Uncontrolled or no expansion of a gas kick will create problems that can lead to a blowout.

Gas can migrate and increase wellbore pressure if a well is left shut in. Because of this, shut-in pressures need to be monitored. When the well is shut in, bleed-off procedures should be used to allow gas expansion, or until killing procedures can be started.

For matters of simplicity and basic understanding, kicks will be presented as a single coherent volume. In reality, the influx may spread several hundred or thousand feet (meters) throughout the wellbore.

DETERMINING THE NATUREOF INTRUDING FLUID

It is helpful to know if intruding fluid is gas or liquid (oil/water). This is approximated by calculating the density of intruding fluid assuming the difference between shut in pressures (Shut In Drillpipe/Casing Pressures) is due to the difference in densities over the kick length.

To determine fluid type in the wellbore, measure pit gain in barrels as accurately as possible. This is an indicator of kick size. (Exclude circulating volume from surface equipment, such as fluid cleaning/mud mixing equipment, if shut down prior to measuring pit gain.) Kick length is calculated by dividing barrels gained by the annular capacity between the wellbore and pipe, and from its length, the density can be estimated using the calculations below.

Kick:displacement

of fluid from the top of a well by

an unwanted influx of

formation fluid.

KICK THEORY4-3

THE GENERAL GAS LAW

P1 × V1 =

P2 × V2

T1 × Z1 T2 × Z2

P1 = The original absolute pressureV1 = The original volumeT1 = The original absolute temperatureZ1 = The variation from perfect compressibility of the gas at P1 and T1(P, V, T, Z)2 = Values at any other conditionsIgnoring T and Z the equation becomes

P1 × V1 = P2 × V2

For our purposes we generally ignore T, temperature, and Z, compressibility. T is not typically used in the equation since we cannot simultaneously measure temperature along all points of the well. Z describes the deviation of a gas from an ideal or perfect gas. Gases encountered in the field are mixtures. For example, hydrogen is an ideal gas, but is often associated as a compound gas such as methane, CH4, or hydrogen sulfide, H2S. The compound gas prevents expansion and compression from being perfectly proportional to pressure and temperature.

The general gas law shows that if a gas is not allowed to expand, pressure remains the same except for variations due to temperature and the compressibility factor. This means if a gas bubble from the bottom of the hole comes to surface without being allowed to expand, it would still have the same pressure as it had at the hole bottom. The pressurized gas would then pressurize the well to a point where equipment failure, formation breakdown or lost circulation could occur. This is why a gas kick cannot be killed by keeping pit volume constant or by pumping in one barrel (0.159 m³) for every barrel (0.159 m³) that comes out of the well.

In reality, pressures are not as high as might be expected due to the effect of temperature. When gas comes up the hole, it cools. It further cools if it is allowed to expand. As the gas cools, the pressure of the gas reduces. One further item that is not in the general gas law is the solubility of gas. When gas dissolves into fluid it reduces the volume of free gas. Therefore, ultimate pressures at the surface are reduced.

If gas rises to the surface and expands without any control, the gas would occupy so much volume in the annulus that it would push large amounts of fluid out of the hole and reduce bottomhole pressure. Between not allowing gas to expand and allowing free expansion of the gas,

The density of salt water is generally between 8.5 and 10.0 ppg (1019 and 1198 kg/m³) while the density of gas is less than 2.0 ppg (240 kg/m³). If the density is between 2.0 ppg and 8.5 ppg (240 and 1019 kg/m³), then the intruding fluid is a mixture of gas, oil and water.

Understanding the difference between gas and liquid kicks will allow certain problems to be handled in different ways. By calculating the kick density, we may find the influx to be either liquid or gas. In reality, it must be noted that some gas may exist with either oil or water. Most kicks are a mixture of more than one fluid and all kicks should be treated as gas kicks unless there is good reason to believe otherwise.

GAS IN THE WELLBORE –WATER BASED MUDS

Gas is a compressible fluid. The volume it occupies depends on the pressure imposed on it. If pressure increases, volume decreases. Volume/ pressure relationships vary for different types and mixtures of gases. However, the behavior of natural gas can be approximated using an inverse proportionality. This means that doubling pressure will compress the gas to about half the original volume. Reducing pressure by half will double the original volume.

Gas is lighter than liquid, therefore migration may occur whether or not the well is shut in. Although gas may separate into smaller bubbles, most discussions describe a kick as a single slug of gas. The generalities of gas behavior in the wellbore should be understood and anticipated to maintain control of a gas kick.

THE GENERAL GAS LAW

The general gas law states that the pressure in gas is related to the volume that the gas is allowed to occupy. Temperature changes and variation from a perfect gas modify this relationship. See the following chart.

Treat all kicks as if they were gas kicks.

CHAPTER 44-4

well control procedures have been developed that control expansion of the gas, and proper control of gas expansion is essential to any successful well control procedure.

GAS EXPANSION

When gas enters the hole, its effect on the wellbore depends on how the gas will be handled. Incorrect handling of a gas kick can result in hazardous consequences. This has been evident throughout oilfield history. Even today, there are many practices and viewpoints on how to kill a well. The following examples show how gas in the wellbore act and illustrates the best solution to these problems. For simplicity, gas will be treated as a single slug and the effects of temperature, compressibility, fluid type and solubility are ignored in the following examples.

NO EXPANSION

In a 10,000 foot (3048 m) well containing 10 ppg (1198 kg/m³) fluid, a barrel (0.159 m³) of gas is swabbed in on a connection. The well

is shut in and the gas bubble is allowed to migrate to surface (or is circulated to surface holding pit volume constant). In other words, the gas will not be allowed to expand. For the sake of simplicity, ignore the effects of temperature and compressibility although they affect the answer.

The bottomhole pressure exerted by the column of fluid is 5,200 psi (358.54 bar) and the volume of gas is 1 barrel (0.159 m³). If gas migrated halfway up the hole, the hydrostatic pressure above the gas bubble will only be 2,600 psi (179.27 bar). However, the pressure of the gas bubble will still be at 5,200 psi (358.54 bar), according to the general gas law. The annular pressure at surface would be 2,600 psi (179.27 bar), the difference in the pressure of the gas bubble and the hydrostatic pressure of the fluid above the gas bubble. Bottomhole pressure will be the hydrostatic pressure plus the casing pressure or 7,800 psi (537.81 bar). When the bubble reaches the surface, the surface pressure will be 5,200 psi (358.54 bar) and the bottomhole pressure 10,400 psi (717.08 bar). This is equivalent to a 20 ppg (2397 kg/m³) fluid. In most cases, before gas reaches the surface, a breakdown of the weaker formations would occur or the casing could burst, limiting our kill options.

0 PSI 1300 PSI 2600 PSI 3900 PSI 5200 PSI

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

5200 PSI 6500 PSI 7800 PSI 9100 PSI 10400 PSI

SurfacePressure

BottomholePressure

0 BarrelGain

Pits0

BarrelGain

0 BarrelGain

0 BarrelGain

0 BarrelGain

1 bbl

1 bbl

1 bbl

1 bbl

1 bbl

No gas expansion

Do not try to kill a well

by maintaining constant pit

volume.

KICK THEORY4-5

There are two lessons to be learned from the no expansion example: Do not try to kill a well with a constant pit volume; and do not allow a well to stay shut in for a long time if pressures are continuing to rise. Rising pressures probably mean gas migrating up the hole. If pressures rise, keep tubing pressure constant by using proper bleed-off procedures at the choke.

UNCONTROLLED EXPANSION

The opposite of not allowing the gas to expand is to circulate the gas out without holding any backpressure on it. Again, one barrel (0.159 m³) of gas is swabbed into the wellbore. This time the well is not shut in and the pump has started to circulate the bubble out of the hole. From the gas law, when the gas has reached half-way up the hole, it expands to two barrels (0.318 m³). Three quarters of the way up the hole, the gas expands to four barrels (0.636 m³). Another halfway up the hole from that point, the gas expands to eight barrels (1.272 m³). A question or two should be forming by this time: If the bubble is expanding, and displacing fluid from the well, how much

hydrostatic pressure has been lost? Can this loss of hydrostatic pressure cause the well to flow? By this time more gas is probably entering the wellbore, expanding, displacing more fluid, and allowing a faster flow. The well is on its way to blowing out. With uncontrolled expansion, it has been said that 90% of the expansion potential will occur in the top 10% of the wellbore.

CONTROLLED EXPANSION

If pumping out a gas kick with controlled expansion, gas must be allowed to expand to maintain bottomhole pressure equal to, or slightly above, formation pressure. Pit volume must be allowed to increase. When following normal well kill methods (Driller’s, Wait and Weight, Concurrent), more fluid is allowed to come out than is pumped in, allowing gas to expand. The choke operator holds a backpressure allowing gas to expand enough so the hydrostatic pressure in the well plus backpressure equals a value that is about equal to formation pressure. Normal well kill methods allow controlled gas expansion as gas is being pumped to surface. (See example on next page.)

0 PSI 0 PSI 0 PSI 0 PSI 0 PSI

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

5200 PSI 5197 PSI 5190 PSI 5170 PSI ? PSI

SurfacePressure

BottomholePressure

0 BarrelGain

.3 BarrelGain

1 BarrelGain

3+BarrelGain

350+ BarrelGain

Pits

1 bbl

1.3 bbl

4 bbl

350 bbl

2 bbl

Uncontrolled gas expansion

Rising pressures in a closed well probably mean that gas is migrating toward the surface.

CHAPTER 44-6

GAS MIGRATION

A watch should always be kept on shut-in pressures. Pressures may rise as gas migrates up through the well’s fluid when shut in. Gas migration can increase the wellbore pressures until formation or equipment breakdown occurs. This may result in formation damage or an underground blowout.

Keep tubing or drillpipe pressure constant at planned pressures. The tubing or drillpipe pressure gives the best indication to bottomhole pressure changes because it usually contains a known and consistent fluid (as opposed to the fluid in the annulus, contaminated by cuttings and influx fluid). If this pressure is kept constant, bottomhole pressure is also constant. This may require choke manipulation to adjust pressure and is discussed in the Well Control Methods chapter.

If tubing or drillpipe pressure cannot be used, such as if un-ported backpressure valves are in the string or if the bit is plugged or pipe is out of the hole, then casing pressure must be used until the problem can be solved. If casing pressure is held constant, a volume of

fluid will be bled from the well. This must be carefully measured since this fluid was contributing to hydrostatic pressure and casing pressure must be allowed to increase to compensate for this loss. Following are some equations that will help in gas migration and bleed-off procedures.

PROBLEM 1Use the following information to calculate

hydrostatic pressure lost.As surface pressure is maintained at the

proper pressure, a six barrel (0.954 m³) gain was noted in the trip tank. Fluid weight is 13.0 ppg (1558 kg/m³) and the well has a 9 5/8” (244.5 mm) hole with 4 1/2” (114.3 mm) drillpipe (annular capacity, 0.070 bbls/ft [36.51 m³/m]).

Hydrostatic Pressure Lost =(Barrels Gained ÷ Annular Capacity)× (Conversion Factor × Fluid Density)

PROBLEM 2Use the following information to calculate

the pressure at surface that would be needed to replace the hydrostatic pressure of a fluid

0 PSI 7 PSI 14 PSI 28 PSI 185 PSI

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

5200 PSI 5200 PSI 5200 PSI 5200 PSI 5200 PSI

SurfacePressure

BottomholePressure

0 BarrelGain

.3 BarrelGain

1 BarrelGain

3 BarrelGain

27 BarrelGain

Pits

1 bbl

1.3 bbl

2 bbl

4 bbl

27 bbl

Controlledgas expansion

Gas migration in a shut in well

can increase pressure in a

well and cause an underground

blowout.

KICK THEORY4-7

as it is bled from the well. The same formula used in problem 1 is applied to determine the amount of surface pressure that would have to be applied if hydrostatic is lost.

Gas is being controlled during migration up the 9-5/8” (244.5 mm) hole with 4-1/2” (114.3 mm) drillpipe. Ten barrels (1.59 m³) of 13.0 ppg (1558 kg/m³) fluid have been bled, and the annular capacity is 0.070 bbls/ft (36.51 kg/m³).

Surface Pressure Increase =(Barrels Gained ÷ Annular Capacity)× (Conversion Factor × Fluid Density)

LIQUID KICKS

Oil, water and saltwater are nearly incompressible. They will not expand to any appreciable extent as pressure on them is reduced. Because of this property, their pumping and return rates will be essentially equal. If a liquid kick will not expand as it is circulated out of the hole, the casing pressure will not increase as is anticipated with a gas kick (provided no further influx is permitted). With constant bottomhole pressure kill methods the hydrostatic pressure on the annular side will change due to variations in well geometry. Casing pressure will also change, due to choke adjustments, as the heavier mud replaces both original fluid and kicking fluid. These changes are not nearly as pronounced as changes with a gas kick in the well.

When compared with gas, liquid kicks do not migrate to any appreciable extent. If the liquid kick does not migrate, shut-in pressures will not increase (from migration) to the same extent as seen on a gas kick.

Most water influxes will contain some solution gas that will make the surface pressures form the same pattern encountered during a gas kick, but to a lesser degree. It is important to treat every kick as if it were a gas kick.

GAS IN THE WELLBORE – OIL/SYNTHETIC OIL BASED MUDS

The behavior of gas kicks in oil based fluid is different from kicks in water based fluid. Gas that enters a wellbore which contains oil based fluid will go into solution. It is estimated that the majority (60 percent or more) of gas that enters the wellbore will go into solution. Synthetic oil based mud will exhibit the same gas absorption characteristics as regular oil based mud, but to a lesser extent, depending on the synthetic mud’s composition.

It is more difficult to recognize that a kick has been taken with oil based fluid. With water based fluid, the pit gain would reflect the size of a gas influx. For example, if the well were shut in with a 10 barrel (1.59 m³) pit gain, this would be the result of a 10 barrel (1.59 m³) influx of gas. With oil based fluid, the same 10 barrel (1.59 m³) gas kick would cause a pit gain of only 2 to 3 barrels (0.318 to 0.477 m³). This inconsistent pit gain can disguise the severity of the kick.

Once shut in, the gas in solution will not migrate to any appreciable extent, thereby giving the appearance of a liquid kick. The assumption that the kick is oil or saltwater should not be made if oil based fluid is being used. The influx will not expand as it is circulated until the kick nears the surface.

When the gas comes out of solution, it will expand rapidly. If the well is being circulated, this will result in a sudden unloading of the fluid above the gas as it expands. If the kick is being circulated through the choke, this rapid expansion will require choke adjustments to maintain a constant bottomhole pressure. The choke operator should anticipate the change from a liquid to a gas as the kick nears the surface and should be prepared to make the necessary adjustments.

Usually, liquid kicks will not migrate up a well to any appreciable extent.

CHAPTER 44-8

ESTIMATED MAXIMUM SURFACEPRESSURE FROM A KICK

It is impossible to estimate the maximum surface pressure that might be expected from a poorly handled well kick, because the pressure is regulated with the pump and choke. If the kick fluid is gas and is allowed to migrate to surface without the pressure being relieved, then pressure on surface (providing nothing fails downhole or on surface) could be between one-half and two-thirds of the formation pressure that produced the gas. Solubility of the kick fluid in the fluid system and temperature will generally reduce the size of the influx and therefore reduce pressure. Kick composition, solubility of the wellbore fluid, and exact kick sizes, are never exactly known.

Generally, the maximum surface pressure from a gas kick killed by the Driller’s Method will be greater than the maximum pressure from the Wait and Weight Method. This pressure will be somewhat more than the original Shut in Tubing Pressure. Maximum pressure from the Concurrent Method will fall somewhere between the Driller’s and Wait and Weight Methods.

EFFECTS OF KICK POSITION

A major concern in well control is avoiding lost circulation. During a kick, the pressure at any weak point in the wellbore is equal to the hydrostatic pressure above the point plus the casing pressure at surface. Often the weak point is near the casing seat. If a procedure of maintaining constant bottomhole pressure is followed (while circulating a kick or allowing the gas to rise), pressures at the weak point will rise only until the gas reaches the weak point.

Once the kick fluid rises above the weak point, the hydrostatic pressure exerted to the weak point decreases. This is because the kick

fluid’s hydrostatic pressure is usually lower than the mud or fluid in use, hence a reduced hydrostatic pressure. Note that surface pressure may continue to increase to compensate for lost hydrostatic as the gas expands and displaces fluid from the well. From this point until the kick is at the surface, pressures on the weak point will not change unless a heavier fluid is circulated above the weak zone. It should be remembered that it is the total pressure against the weak point, not just the pressure seen on the surface, which causes formation failure.

Another basic point about pressures in the wellbore needs to be understood. The kill fluid equation, as shown in the Well Control Basics chapter, shows how to replace shut-in surface pressure with a heavier fluid weight in the wellbore. This means that if a kick can be shut in without losing returns, the hole should hold the heavier fluid without losing returns.

The figures illustrate this important point in understanding well control problems. After the kick is pumped up into the casing, the danger of lost circulation is reduced because pressure at the casing shoe stabilizes or is reduced.

KICK SIZE

It is important to remember that the longer it takes to recognize a kick and start control procedures the larger a kick will be and the harder it will be to control. The larger the kick, the higher the casing pressure. A few general rules determine the maximum pressure to expect. They are:

• Casing pressure increases with the magnitude and size of the kick.

• Formation and circulating pressures increase with well depth.

• Circulating pressures increase with fluid weight increase.

• Surface pressures are lowest with saltwater and increase with gas kicks.

Larger kicks increase pressures

throughout the well, increasing the potential for complications.

KICK THEORY4-9

• The method of killing the well affects the surface pressure. Increasing the fluid weight before circulating may help minimize surface casing pressure.

• Gas migration while the well is shut in can increase surface pressures to near formation pressure.

• Safety margins and extra fluid weight during kill operations can cause higher circulating pressures.

MORE THAN ONE KICK

If proper constant bottomhole pressure (BHP) is not maintained when circulating an influx out, a second kick may occur. After circulating kill fluid back to surface, the pump should be shut down and the well shut in. If pressure is observed on casing, there is a possibility that a second kick has been taken. A second circulation is sometimes required to get the influx out because of inefficient hole displacement and stringing out of the influx. This should not be confused with a second kick. The main causes of secondary kicks are:

• Improper start up procedures after being shut in.

• Improper tubing pressure versus pump strokes (circulating rate).

• Gas or mud exiting through the choke.

• Human error – incorrectly responding to mechanical problems such as washouts, plugging, etc.

GAS CUTTING

Gas cutting of fluid, even if apparently severe, creates only a small reduction in bottomhole pressure. A small influx from the bottom of the hole can severely gas cut fluid at the surface due to the compressible nature of gas causing great expansion near the surface.

When a small quantity of gas is circulated halfway up the well, the hydrostatic pressure of the fluid will be halved. The volume of gas will double, but will have practically no effect on the hydrostatic pressure of the entire column. When the gas reaches another halfway, the gas will double again, still with practically no effect on bottomhole pressure. Each time the gas is

Effects of Kick Position0

0

1600

420

3020

449

3048

477

3077

481

3059

Effects ofkick position

If bottomhole pressure remains constant, the danger of lost circulation is reduced after the kick is pumped up into the casing.

CHAPTER 44-10

Improper start-up procedures

after shutting in may result in

a secondary kick.

circulated halfway up the hole from the last point the volume will double. When near the surface, these halfways become closer together, resulting in a rapid increase in gas volume.

The total effect may be severe gas cut fluid at the surface, but downhole the effects are almost negligible. An example is in a 20,000 ft (6096 m) well with 18 ppg (2157 kg/m³) fluid, the bottomhole pressure is over 18,000 psi (1241.05 bar). If the gas cutting at surface shows a 9 ppg (1078 kg/m³) fluid, bottomhole pressure may be reduced from 50 to 100 psi (3.45 to 6.99 bar). This depends on the type(s) of gas. The reduction usually will not cause a kick, but gas cutting does warn of existing or potential problems.

Gas cutting can be a significant problem while drilling shallow wells. Depending on the reduction of overall hydrostatic, kicks and shallow blowouts have occurred from gas cutting. Generally, once surface casing is set, this problem is minimized.

GAS BEHAVIORAND SOLUBILITY

The behavior and solubility of different gases in fluids are complex issues. The type of fluid in use, the pressure, temperature, pH and the types and ratios of gases encountered all affect solubility. Also, the time that the gas is exposed to the liquid would have to be known if specifics of solubility and influx behavior were to be accurately determined.

However, if the discussion is narrowed to general fluid types (water, oil or synthetic oil based) and single common gas (methane, H2S or CO2), generalities may be derived.

• If enough pressure is exerted, gas may be compressed to a liquid state. If a liquid gas kick is taken, kicking fluid will not migrate or expand to any appreciable extent until it is circulated to a point where the gas can no longer stay in liquid form. Once it reaches

20,000

10,000

8,000

6,000

4,000

2,000

1,000

0 20 40 60 80 100 120

10%

CU

T

25%

CU

T

33.3

% C

UT

50%

CUT

10 L

B/G

AL

CU

T TO

9 L

B/G

AL

10 L

B/G

AL

CU

T TO

7.5

LB

/GA

L

18 L

B/G

AL

CU

T TO

16.

2 LB

/GA

L

18 L

B/G

AL

CU

T TO

13.

5 LB

/GA

L10

LB/

GAL

CUT

TO

6.6

6 LB

/GAL

18 L

B/G

AL C

UT T

O 1

2 LB

/GAL

18 L

B/G

AL C

UT T

O 9

LB/

GAL

10 L

B/G

AL C

UT T

O 5

LB/

GAL

(After Obrien & Goins, 1960)

CHANGE IN BHP - PSI

DEP

TH -

FEET

Gas cut mud does not usually

cause much reduction in BHP.

KICK THEORY4-11

Both methane and hydrogen sulfide are soluble in oil based fluids.

its bubble point, the gas will expand rapidly to the volume it should occupy.

• Solubility changes with variables such as temperature, pH, pressure and type of fluid.

• Methane and hydrogen sulfide are more soluble in oil than water based solutions.

• Changes in conditions (i.e., pressure) may allow gas to break back out and result in unexpected expansion that may lead to the fluid unloading from that point upwards.

SUMMARY

The effects and behavior of kicks must be known in order to prevent kicks from turning into blowouts. Gas and water kicks will act differently. Gas must be allowed to expand, with most of the expansion occuring near the

surface. Uncontrolled or no expansion will create problems that can lead to blowouts. If a kick is taken, remember that kick size is in proportion to the alertness of the crew. Larger kicks cause higher pressure, and may result in difficulty in killing the well. Remember that gas will migrate up a wellbore, so shut-in pressures need to be monitored and wells should not be shut in for long periods of time. Use bleed-off procedures in order to allow expansion until well killing procedures begin.

If oil or synthetic oil based fluids are used, gas kicks are harder to detect, as much of the kick may go into solution. If using oil based fluids, flow checks should last for a longer time than checks on well in which water based fluids are used. Adjust pit alarms to the smallest value possible and assume that a pit gain is from an influx until it can be proven otherwise. t

WEIGHT OF MUD GOING IN

HOLE

14 LB / GAL MUD

16 LB / GAL MUD

12 LB / GAL MUD

10 LB / GAL MUD

18

17

16

15

14

13

12

11

10

8

9

7

60 5 10 15 20 25 30

GAS CUTTING CAUSED BY DRILLING GAS SANDSW

EIGH

T OF

MUD

RET

URNS

AT

SURF

ACE

- LBS

/ GA

L

DRILLING RATE – FT / HR

Gas cutting caused by drilling gas sands

CHAPTER

5

Procedures must

be written on a

per-well basis and

detailed for the

type of rig

and operation.

PROCEDURES

T his chapter covers various procedures and topics and is presented to offer examples of typical rig activities. Please

note that generalities are covered, not specifics. Procedures must be written on a per-well basis and detailed for the type of rig and operation. Crew assignments may also change on different wells or activities and must be individually addressed.

SHUTTING THE WELL IN

Once a kick has been detected, the well should be controlled according to correct procedures. Shut-in procedures require common sense. At times of excitement or emergency, there must be strong control and discipline on the rig floor. Drills, planned procedures and

5-1

CHAPTER 55-2

strong supervision are the keys to successfully controlling the well. Once a kick has been detected, the well should be shut in as quickly as possible. The reasons for shut-in procedures include:

w To protect the crew and rig

w To stop the influx of formation fluid into the wellbore

w To allow shut-in pressures to be determined

w To provide an opportunity to organize the kill procedure.

There is no such thing as a small kick or a small flow. Either can rapidly develop into a blowout. All flows must be recognized as potential blowouts. When in doubt as to whether the well is flowing or not – shut it in.

Shut-in procedures may vary considerably, depending on company policy, the type of rig and the size of the crew. However, the basics of shutting a well in do not change. A preventer must be closed to stop the flow. There are debates as to which method is the proper one to use, a hard or soft shut in, or a modification of either. It is not the intention of this manual to advocate one or the other of these methods. All wells are different, and procedures should be decided upon, posted, known and practiced on an individual well or activity basis.

FLOW CHECK PROCEDURES

A flow check consists of observing a well with pumps shut off to determine whether it is flowing. Sometimes flow checks are performed as standard company policy, perhaps prior to pulling pipe off bottom, at casing shoe or prior to pulling collars. They are also performed at the driller's discretion from changes in drilling parameters, or at the request of supervisors, the mud logger or crew members noting kick indicators. Flow checks are performed by direct observation, flow sensor equipment or volumetrically. If the well is flowing, shut-in procedures should begin immediately.

Depth, fluid type, formation permeability, degree of underbalance and other factors affect how long to observe the well during the flow check. The check should be long enough to determine if the well is flowing or static.

SHUT-IN PROCEDURESWITH PIPE ON BOTTOM

The chart and accompanying illustrations assume a kick while drilling is noted from the flow check sequence and shut in is required.

GENERAL FLOW CHECK PROCEDURES

FLOW CHECK WHILE DRILLING FLOW CHECK WHILE TRIPPING

1. Alert the crew 1. Alert the crew

2. Pick up off the bottom and 2. Set slips so the last tool joint is at clear uppermost tool joint normal working level above rig floor

above the rig floor 3. Install full open safety valve

3. Stop the rotary in open position

4. Shut off pump 4. Observe the well for flow

5. Observe the well for flow Note: Make flow check prior to pulling BHA through BOPs. If the well is flowing, shut-in procedures should begin immediately.

Flow check:observing a well with pumps shut off to determine

whether or not it is flowing.

PROCEDURES5-3

HARD SHUT IN MODIFIED SHUT IN SOFT SHUT IN (CHOKE CLOSED) (CHOKE CLOSED) (CHOKE OPEN)

1. Open choke line valve on stack 1. Close designated BOP 1. Open choke line valve on stack

2. Close designated BOP 2. Open choke line valve on stack 2. Close designated BOP

3. Notify company personnel 3. Notify company personnel 3. Close choke, watching casing 4. Read and record SIDPP 4. Notify company personnel 4. Read and record SIDPP pressure and SICP each minute and SICP each minute to ensure limitations are not exceeded or pressure trapped 5. Read and record SIDPP and SICP each minute

Closed

Open

Hard Shut In

2 Close

Open3 Monitor & record

1

Modified Shut In

1 Close

Open 3 Monitor & record

2

Soft Shut In

2 Close

Open4 Once choke closed monitor & record

1

3

Close while monitoring pressure

Close

CloseClosed

Shut-inWell

Shut-In Procedures with Pipe on Bottom

Shut-in procedures vary from job to job but the basics do not change:• protect the crew• stop the flow• gain time• read pressures

CHAPTER 55-4

SHUT-IN PROCEDURESWHILE TRIPPING

The illustration above and the chart on the facing page both assume a kick during a trip has been noted from the flow check sequence and shut in is required.

Closed

1Hard Shut In

3 Close

Open

4 Monitor & record

2

1Modified Shut In

2 Close

Open3

1Soft Shut In

3 Close

Open 5 Once choke closed monitor

& record2

4

Close while monitoring

Close

CloseClosed

Open

4 Monitor & record

Shut-inWell

MODIFICATIONS TO SHUT IN

Under certain circumstances, modifications will need to be made to the standard shut-in procedures. Examples of some of these circumstances follow.

Shut-In Procedures

While Tripping

Top drive systems employ

a remotely operated FOSV which is always

made up on the drive.

PROCEDURES5-5

SHUT IN ON TRIP WITH TOP DRIVE

The kelly is not used on rigs equipped with top drive systems. Once the well has been shut in, it is recommended that a pup joint or a single be installed between the top drive and full opening safety valve (FOSV) stabbed on the string. Then open the valve. If flow through the string prevented installation of the safety valve, the top drive may be stabbed and made up directly on the drillpipe.

Top drive systems employ a remotely operated FOSV which is always made up on the top drive. If a kick is suspected, the pipe can be set in the slips, the top drive lowered and spun up on the string. The FOSV is then closed. At shallow depths, where time is especially critical, this technique offers great advantages over conventional rotary kelly systems.

SPACING OUT

Surface Stacks: It is not desirable to close a ram preventer around a tool joint. Preventing this requires knowing the distance from RKB (Rotary Kelly Bushing, rig floor) to components in the BOP stack. The average length of pipe in use should also be known. The driller and crew should know the approximate length of pipe above the rotary table in order to prevent the annular and rams from closing around a tool joint. Exact lengths should be used if the pipe is to be hung off on a set of ram preventers.

Subsea Stacks: Spacing out on floating operations can be more of a problem. Great water depths, tidal changes and sea conditions complicate spacing out and hanging off, especially since many subsea BOP systems are taller than the average length of pipe used. Accurate measurement of each joint and stand is a must.

Water depth, tidal changes and sea conditions can complicate spacing out and hanging off on floating operations.

HARD SHUT IN(CHOKE CLOSED)

1. Install FOSV in the open position, close valve

2. Open choke line valve on stack

3. Close designated BOP

4. Notify company personnel

5. Pick up and install kelly or circulating swage, open FOSV. If no float is in use, make sure surface equipment is full before opening FOSV

6. Read and record SIDPP and SICP each minute

MODIFIED SHUT IN(CHOKE CLOSED)

1. Install FOSV in the open position, close valve

2. Close designated BOP

3. Open choke line valve on stack

4. Notify company personnel

5. Pick up and install kelly or circulating swage, open FOSV. If no float is in use, make sure surface equipment is full before opening FOSV

6. Read and record SIDPP and SICP each minute

SOFT SHUT IN(CHOKE OPEN)

1. Install FOSV in the open position, close valve

2. Open choke line valve on stack

3. Close designated BOP

4. Close choke while watching casing pressure to ensure pressure limitations are not exceeded or pressure trapped

5. Notify company personnel

6. Pick up and install kelly or circulating swage, open FOSV. If no float is in use, make sure surface equipment is full before opening FOSV

7. Read and record SIDPP and SICP each minute.

CHAPTER 55-6

Typically the upper annular is used to shut in the well. Once shut in, if exact spacing is unknown due to a trip or above factors, pull pipe slowly and monitor the weight indicator and accumulator flow meter. Weight should increase slightly as the tool joint is stripped through the annular. As it goes through, the annular will use more fluid to maintain closure pressure against the pipe body. Spacing can then be calculated.

Once spacing has been verified, close the hang off rams. Hang off using the drillstring compensator and close the ram locks. If possible, bleed off pressure between the closed ram and annular, then open the annular.

SHUT IN ON COLLARS

One of the more critical shut-in situations develops when collars are pulled through the rotary. The annular preventer is typically used, but situations complicating the shut-in process must be considered, such as the use of spiral collars or the lack of a float or backpressure valve. In addition, there is the possibility the influx may be close to surface; if pressure on shut in acting upwards is greater than the weight of the collars acting downward, the well may try to eject the collars when shut in is attempted.

Often the collars have a different thread size and/or type. The proper crossover subs must be available on the rig floor, made up with a safety valve and ready for installation. The procedures for making and picking up this assembly must be addressed.

A plan of action should be decided upon and questions, such as the following, answered.

w Is it safer to pull the remaining collars or install the crossover/safety valve assembly?

w On shut in, if the collars begin to be ejected from the well, will a choke be used to relieve pressure below the annular? (Remember that this may also allow more influx to enter the well.)

w If drill collars must be dropped, how will this be done?

An important consideration on any trip is the location of collars in the derrick. They should be racked in a manner not blocking the drillpipe in the event pipe must be run back in the hole.

KICKS WHILE OUT OF HOLE

There are many philosophies as to what to do with regard to kick detection when out of the hole. Possibilities include closing the blind ram (choke closed or open), closing a pipe ram and covering the rotary. All present different problems in kick detection while out of the hole, but these problems can be solved by monitoring the hole or pressure gauges and implementing contingency procedures. Generally:1. If the blind rams are closed and choke

open: monitor the choke for flow.2. If the blind rams and choke are closed:

monitor the casing (annulus) pressure gauge for pressure buildup. Some operators have a policy, when the bit clears the rotary, of opening the HCR, closing the remote choke, filling the hole and closing the blind rams. If gas was swabbed into the well during a trip, then there will be an increase in surface pressure after a period of time depending on migration rates.

3. If the pipe rams are closed: monitor the flowline for flow.

Note: Just because there is no flow from the wellbore does not mean that there is not a kick in the well. If technique 2 above is used in areas where temperatures drop below freezing, lining up on a choke could freeze the mud and plug the choke, giving a false reading. Prior to opening the blinds in techniques 1 and 2 above, ensure that the choke is open to vent the stack and check that personnel are clear of the wellbore. Gauges have been known to be inaccurate or not register low pressure. If technique 3 above is used, closing pipe rams on an open hole may keep large junk from falling into the well and allow you to see if the well is flowing, but may also damage ram front-packer seals or reduce the operating life of the pipe rams.

If a well is shut in with drill

collars in the rotary, it is

possible that well pressure will force the

pipe out of the well.

PROCEDURES5-7

When flow is detected while out of the hole, the well should be shut in. This stops the influx, allows pressures to be determined and provides time to decide the next course of action. Most operators will use stripping and volumetric techniques to run pipe to bottom while maintaining bottomhole pressure control.

Where formation characteristics are well known (i.e., a tight formation not exhibiting a high flow rate), and where the danger of gas to the surface is minimal, the decision to run

several stands of pipe back into the hole may be considered. It must be understood that running pipe back into an open and active well is dangerous and has lead to several disasters. It can result in significantly higher surface pressure than if the well were shut originally. If an underbalanced condition exists, additional influx will continue entering the well and will accelerate the rate of flow as more mud is displaced. Also, gas migration and upward displacement of the kick by stinging the pipe into the influx may reduce the effective

Kicks taken while running casing are extremely dangerous.

If a kick is detected while out of the hole, most operators will use stripping techniques to run pipe to bottom.

CHAPTER 55-8

Flaring gason a floating

operation.

hydrostatic pressure, thereby accelerating or allowing additional influx to enter. And, if the well has to be shut in while running pipe, there may not be enough pipe weight to overcome the force of the kick. Pipe rams should be closed to prevent the well from forcing pipe out of the hole. If collars were run, pipe rams will not prevent the collars from unloading from the well. Under no circumstances should pipe be run into the well (BOPs open) if a significant flow is present or if there is gas at surface.

SHUT IN WHILE RUNNING CASING

The main objective in a closing sequence is to close off the smallest and most vulnerable flow path first. The inner diameter of the string is typically the smaller diameter compared with

the annulus, and is usually shut off first. The opposite situation exists while running casing, when the annulus should be shut in first.

Prior to running casing, BOPs should be equipped with casing rams and pressure tested. A circulating swage with a high pressure/low torque valve must be made up, positioned near the rotary table and installed immediately after the BOPs have closed, in case the float equipment fails during a well control event. Floating rigs should have a crossover from the casing to drillpipe to allow the string to be hung off if necessary. Closing pressure on annular preventers should be checked against the collapse pressure of the casing and adjusted if necessary before running casing. An alternate to this on surface stack rigs is to lower a joint of casing into the annular, bleed all pressure off the annular pressure regulator and gradually increase the closing pressure 100 psi (6.89 bar)

Under no circumstances

should pipe be run into an

open well if a significant

flow is present.

PROCEDURES5-9

at a time until closure around the casing is obtained. From this point an additional 100 to 200 psi (6.89 to 13.79 bar) should be sufficient to form a seal. Again, before adding the seal pressure, check against the collapse pressure. If additional pressure is required to obtain a seal, adjust the pressure regulator.

SHUT IN WITHBRAIDED WIRELINE

Wireline operations typically employ a lubricator if there is a possibility of pressure at the surface during the operation. The lubricator assembly typically consists of a stuffing box, grease injectors, lubricator joints or tube bodies, blowout preventers and a bleed or pump-in valve (high pressure/low torque). The equipment may be nippled differently, depending on the application. Equipment may be:

w Flanged up to an annular preventer

w Secured inside annular preventer or rams

w Made up to a gauge flange (crown valve) on a Christmas tree.

Close cooperation between the rig crew and the wireline crew is essential if kicks are to be detected and handled properly. A suggested shut in sequence follows.

1. Notify the wireline operator to cease operations.

2. The driller closes the bleed or pump in valve.

3. Wireline BOPs are closed manually or by a hydraulic hand pump. The driller should designate the floorhand(s) to perform this task. It should be noted that two wireline ram type BOPs can be used, the bottom preventer inverted. The bottom ram in this situation is used as a high-pressure seal against grease that will be injected between the two closed rams to provide a viscous grease seal against the braided wireline.

4. Notify supervisors that the well is shut in.

5. There must be a means to cut the wireline should the need arise. This can be accomplished with wireline shear rams and a hydraulic hand pump (on the rig floor) or a set of shear or blind/shear rams in the BOPs. Safety valves (FOSV and Master) should not be used, as they are not designed for this type of service.

HANDLING GAS AT THE SURFACE

Until the nature of the kick has been determined, the entire rig should be alerted to the possibility of the presence of toxic and/or explosive gases. All assigned personnel should check gas detectors, breathing and warning devices for proper operation. Once the well has been shut in, the responsible personnel should immediately check out the wellhead, BOPs, manifolds, choke and kill lines, etc., for possible leaks. Offshore rigs should post a watch for signs of gas around the rig. Should leaks be detected, report them immediately.

In addition, during the kill operation the above items need to be checked frequently. If a gas leak is observed, report it immediately – do not try to stop it before notifying supervisors. Make sure that the gas is not toxic. If tightening a connection to repair leaks, a brass hammer should be used to prevent sparks.

On shut in, align the choke to the gas separator. Make certain that the separator is functioning properly. During circulation, monitor the separator for pressure buildup and blowby. Ascertain that the degasser is operating correctly and the pits are aligned correctly. Confirm that the downwind vent and flare lines are open and the igniter is operational. If a derrick flare line must be used, then caution must be exercised to ensure that any liquids or heavy gases, which could be toxic and/or explosive, do not settle on the rig.

Extinguish all potential sources of ignition, including welding activities, engines and equipment not necessary to the operation.

Close cooperation between the rig crew and the wireline crew is important if kicks are to be handled properly during wireline operations.

CHAPTER 55-10

DIVERTER PROCEDUREWHILE DRILLING

Diverters are BOPs (usually of the annular type) which are designed to protect the rig from shallow blowouts by closing off the well under the rig, while allowing the influx to evacuate safely through the blooey line(s) below the preventer. Diverter procedures must be implemented quickly because the time from kick detection until the kick reaches surface may be minimal. The warning signs of a shallow gas kick include:

w An increase in flow (usually quite dramatic)

w Mud coming over the bell nipple and/or the rig floor

w Loss of standpipe pressure and increase in pump strokes.

Remember that all of the signs will happen rapidly, so the diverter procedure must be known and undertaken quickly.

EXAMPLE PROCEDURE

1. Do not shut pump(s) down. (Loss of mud volume as the well unloads will result in loss of equivalent circulating density [ECD] and will reduce bottomhole pressure, causing the well to unload at a higher rate.)

2. Chain down the brake.

3. Open downwind diverter line.

4. Close the diverter packer. Most rigs have coupled the diverter line and diverter packer together to ensure a correct closing sequence.

5. Pump at maximum rate with drilling fluid, seawater or heavy mud from reserve pits. Should you decide to continue using drilling fluid, remember that it may soon be depleted, forcing the switch to seawater or another source of fluid.

6. Set a watch observing the diverter system for signs of failure. Set a watch for signs of broaching around the rig.

Wind direction is an important

consideration when gas is

vented at the surface.

Diverter procedures

must be implemented

quickly.

PROCEDURES5-11

At the pre-spud meeting the diverter procedure should be thoroughly discussed and understood by the drillers, roughnecks and derrickmen to insure that everyone knows the procedure as well as their duties and responsibilities. Drills should be practiced until the crew is proficient at this procedure.

DIVERTER PROCEDUREWHILE TRIPPING

EXAMPLE PROCEDURE

1. Open downwind diverter line.

2. Install FOSV in open position, close valve.

3. Close preventer. (A ram may be used instead of the annular to prevent pipe from traveling upwards.)

4. Install kelly, chicksan or top drive.

5. Open safety valve.

6. Pump at maximum rate with mud, or switch to seawater, heavy mud or reserve pit.

Note: Steps 1, 2 and 3 should be done as quickly as possible. As soon as the crew sets the slips and the driller chains the brake, the FOSV should be stabbed and closed by the crew as the driller closes the ram.

ROTATING HEAD PROCEDURE

The rotating head is often used for air drilling and in areas where a large amount of background gas is present. The rotating head allows us to drill or circulate while flaring gas and returning the mud to the pits. A procedure to divert the well might be:

1. Increase closing pressure (depending on the type of well).

2. Speed up pumps to increase ECD, but use caution not to produce too much back-pressure which could exceed pressure limitations of the system.

PRE-PLANNING AND DRILLS

Pre-planning and drills on the rig are necessary to prepare for expected and unexpected events. Pre-planning should take all expected operations into account and set a well control plan of action. Unexpected events frequently occur. Forethought must be given to unusual situations and a plan of action should be defined. Once a plan of action is established, the crew should familiarize themselves with it. Drills should be designed to ensure that everyone knows their responsibilities. Many drills cannot be performed without complications, and the drills are often different from the actual procedure. For example, a diverter drill might require the driller to go to the diverter console where he would not shut in the well, but rather explain the procedure of opening the downwind diverter line and closing the diverter packer. Then he would to go to the pump control, and explain the process of bringing the pump to full rate. Other drills can be initiated by raising the float in the mud pits or the flowline sensor paddle. The elapsed time for the drill is measured until everyone is in position to shut in the well. Drills should be practiced as if the event were real.

Drills may be announced or unannounced and typically take place at times that will not interfere with the current activity. Evacuation drills rarely include the driller if the bit is in the well and are often announced so personnel will not overreact, panic or injure themselves. Trip drills are frequently practiced, but not until the BHA has been pulled into the casing.

CREW RESPONSIBILITIES

Many factors may affect the size of the crew required for a given job. Each crew member should know his station and job responsibilities for well control activities. Specific activities can require specialists, such as casing, cementing, or logging crews, who add to the active on-duty personnel roster, thereby altering the general assigned responsibilities.

Drills may be announced or unannounced and usually take place at times that will not interfere with current activity.

CHAPTER 55-12

Remember that the primary responsibility of each member is to keep the lines of communication open. The individual responsibilities shown below are representative of what must be done, and the person who typically performs the tasks during well control events. The following list provides an example only and does not in any way recommend or represent policy.

DRILLER

w Primary responsibility is kick detection and verificationw Shut in the wellw Notify supervisorw Organize crew for kill operationw Remains at drilling console to run rig and

rig pump during kill operation

TOOLPUSHER/RIG MANAGER

w Responsible for rig and personnelw Verifies proper on and off tour crew

deployment, notifies barge engineer or vessel captain of well control operationsw May be responsible for operating the choke

or to designate choke operatorw Coordinates kill operation with company

representative

COMPANY REPRESENTATIVE

w Organizes kill operationw Has overall responsibility unless rig has

offshore installation manager (OIM)w Briefs crew, oversees operations and makes

sure crew knows their responsibilitiesw Notifies and keeps communications open

with officew May be responsible for operating the choke

or designating a choke operator

BALLAST/BARGE ENGINEER

w Notifies support vessels of operationsw Stands by in control room for instructionsw Monitor fluid transfers

DERRICKHAND/ASSISTANT DRILLER

w Goes to pit area, aligns gas separator, degasser and pits

w Works with mud engineer to supervise mixing crew and to ensure rig and mixing pumps are functioning and aligned properly

ROUGHNECKS (DEPENDENT ON THEIR DESIGNATION)

w Report to assigned well control station (rig floor, pumproom, choke console, etc.)w Follow instructions of driller

ELECTRICIAN/MECHANIC

w Assists mechanic/motorman if requiredw Stands by for orders

MUD ENGINEER

w Goes to pitsw Supervises weighting operationsw Maintains constant properties and

fluid density

ROUSTABOUTS

w Go to mud or pump room and follow instructions of supervisor

MOTORMAN

w Shuts off all non-essential equipmentw Ensures rig power throughout operationw Goes to assigned station for well control

operationsw Stands by for orders and to shut down rig

CEMENTER

w Reports to cement unitw Lines up to pump cementw Stands by for orders

SUBSEA ENGINEER (FLOATING OPERATIONS)w Reports to rig floor to inspect subsea panelw Checks for possible problemsw Stands by for orders from rig manager

SERVICE PERSONNEL

w Go to assigned stations for well control operationsw Stand by for orders

Each crew member must

know his station and duties for

well control activities and

keep the lines of communication

open.

PROCEDURES5-13

COMMUNICATIONS

Perhaps one of the most important aspects of any activity is communications. This seemingly simple subject is actually very complex. It may be broken into three distinct components, each with responsibilities and plans of action and how to communicate:

Before the job: Safety meetings are common to communicate to all crew members what activities and goals will be performed and accomplished during the workday. The safety meetings should discuss risk analysis and detail areas of concern as well as corrective plans of action and how to relay information that you are responsible for. Remember that you are part of the team and you need to know what is expected of you. If you have questions regarding the operation, this is a safe time to get them answered. Non-routine activities should be discussed, and any additional personnel brought in to become familiar with what is expected of them, as well as how they will affect your responsibilities. When in doubt, ask questions.

During the Job: There is a basic chain of command to follow orders to perform the day's activities. Each team member has certain responsibilities and must report to a supervisor. However, if anything out of the ordinary is noted, it should be immediately reported. For effective communications, someone has to transfer information, and someone has to listen and acknowledge that it has been received! Poor communications in your work environment can lead to disaster.

Changeover and documentation: When relief arrives, they should be thoroughly briefed on everything that transpired during the workday. Changeover or handover notes should include information about what you accomplished, where the job is standing at this point, any problems or complications that occurred as well as the normal parameters (e.g., depths, tools run, pump rates and pressures, bit/mill rpm, depths, weight, torque, drag, gains or losses, fluid properties, etc.) that were experienced during your tour. Remember that is not just the driller or unit operator that has a relief. Inform your relief what happened, what you are watching for and what to expect. After

Carefully planned close-in procedures are an essential component of well control operations.

Risk analysis and goodcommunicationsminimize problems and increase safety. Work as a team.

CHAPTER 55-14

changeover, personnel in supervisory roles are usually required to document or report on the day's activity.

Crew change is an especially important time for good changeover notes. Many companies have a staggered crew change policy to ensure that someone is on hand and familiar with the prior week's events at all times.

ACCUMULATOR AND BOP TEST

The accumulator system is the key to success in the control of a kick. Unless the system is functioning correctly, the BOP closure sequence and operation of other well control equipment may not be possible. Therefore a thorough and successful test is essential. The following procedures (excerpts from API RP 53) are a general guideline only and should not be confused with any government, state or company policy. For specific test procedures always refer to the manufacturer's procedures and to appropriate regulations.

On surface preventers, the closing system should be capable of closing each ram preventer within 30 seconds and should not exceed 30 seconds for annular preventers smaller than 20 inches (508 mm) or 45 seconds for ones larger than 20 inches (508 mm). For subsea preventers each ram should close within 45 seconds and annular preventers within 60 seconds.

CLOSING UNIT REQUIREMENTS

The closing unit pump capability test should be conducted on each well before pressure testing the BOP stack. A typical test would entail:

1. Position a joint of drillpipe/tubing in the BOP stack.

2. Isolate the accumulators from closing unit manifold by closing the necessary valves.

3. If the pumps are powered by air, isolate rig air system from the pumps. A separate closing unit air storage tank or a bank of nitrogen bottles should be used to power the pumps during this test. If a dual power source system is used, each power supply should be tested separately.

4. Simultaneously turn the control valve for the annular preventer to the closing position and turn the control for the hydraulically controlled (HCR) valve to the open position.

5. Record the time in seconds for the pumps to close the annular preventer, to open the hydraulically controlled (HCR) valve and record the pressure that is remaining. API recommends that this time should not exceed two minutes.

6. Close the hydraulically controlled (HCR) valve and open the annular preventer. Open the accumulator system to the closing unit, charge the accumulator system to its proper operating pressure, and record the time required to do this.

Testing the casing string

FromCement Unit

From Mud Pumps

Annular

PipeRAM

BlindRAM

PipeRAM

If the accumulator system is not

functioning correctly, BOP

closure may not be possible.

PROCEDURES5-15

ACCUMULATOR CLOSING TEST

This test should be performed on a per well basis prior to testing the BOP stack. A typical test procedure follows.

1. Position a joint of drillpipe/tubing in the BOP stack.

2. Close power supply to accumulator pumps.

3. Record the initial accumulator pressures. Adjust the annular regulator to 1500 psi (103.42 bar) or designated pressure.

4. Depending on policy, perform the functions that are required (e.g., API requires the minimum standard to close the annular, one pipe ram and the hydraulic choke line valve).

5. Record the time required for accumulators to close. Record the final accumulator pressure. It should not be lower than

200 psi (13.79 bar) above the precharge

pressure.

(Note: some regulatory agencies require that a minimum of 200 psi (13.79 bar) above precharge remain after closing all BOPs.)

6. After preventers have been opened, recharge accumulator system to designed operating pressure and record time

for complete power up.

BOP INSPECTION AND TESTING

Before hydraulically testing a preventer, check the following:

1. Verify wellhead type, rated working pressure.

2. Check for wellhead bowl protector (wear bushing).

Testing the blowout preventer on a typical surface stack

3. Verify the preventer type and rated working pressure.

4. Verify drilling spool, spacer spool and valve types and rated working pressures.

5. Verify ram placement in preventers and pipe ram size.

6. Verify drillpipe/tubing connection size and type in use.

7. Open casing valve during test, unless pressuring the casing or hole is intended.

8. Test pressure should not exceed the manufacturer's rated working pressure for body or seals of assembly being tested.

9. Test pressure should not exceed the values for collapse and internal yield pressures tabulated for the appropriate drillpipe/tubing used. Do not exceed tensile strength of pipe.

10. Verify the type and pressure rating of

pump and preventer tester to be used.

FromCement Unit

From Mud Pumps

Annular

PipeRAM

BlindRAM

PipeRAM

Test pressurethrough drill

For specific equipment test procedures, always consult manufacturer’s guide as well as local regulations.

CHAPTER 55-16

RAMS AND CIRCULATING SPOOLS

At a minimum the inspections and tests should include the following:

1. Visually inspect the body and ring grooves (vertical, horizontal or ram bore) for damage, wear and pitting.

2. Check studs and nuts for correct size/type.

3. Check size/type of ring joint gaskets.

4. Visually inspect ram preventer.

a. Wear, pitting and/or damage to bonnet or door seal areas or grooves, ram bores, ram connecting rods and operating rods.

b. Packer wear, cracking, excessive hardness.

c. Measure ram and ram bore to check for maximum vertical clearance according to manufacturer's specifications. The clearance is dependent on type, size and trim of the preventers.

d. If preventer has secondary seals, inspect secondary seals and remove plugs to expose plastic injection ports used for secondary sealing purposes. Remove the plastic injection screw and check valve in this port. (Some rams have a release packing regulating valve that will need to be removed.) Probe the packing to

ensure it is soft and not energizing the seal. Remove and replace the packing if necessary.

5. Hydraulically test with water as follows:a. Connect closing line(s) to preventer(s).b. Set preventer test tool on drillpipe/

tubing below preventers if testing preventer with pipe rams.

c. Check for closing chamber seal leaks by applying closing pressure to close rams and check for fluid leaks by observing opening line ports. Closing pressure should be equivalent to manufacturer's recommended operating pressure for preventer's hydraulic system.

d. Release closing pressure, remove closing lines and connect opening lines.

e. Check for opening chamber seal leaks by applying opening pressure to open rams. Check for fluid leaks by observing closing line ports. Opening pressure should be equivalent to manufacturer's recommended operating pressure for the preventer's hydraulic system.

f. Release opening pressure and reconnect closing lines.

g. Low pressure test: check for ram packer leaks at low pressure by closing rams with 1,500 psi (103.42 bar) operating pressure

All wellhead equipment

tests should be documented.

A visual inspection is

an important part of

BOP tests.

PROCEDURES5-17

(or per manufacturer procedures) and apply pressure under rams of 200 to 300 psi (13.79 to 20.68 bar) with blowout preventer test tool installed (if testing preventer containing pipe rams). Hold for required time. Check for leaks. If ram packer leaks, check for worn packers and replace if necessary. If preventer is equipped with an automatic locking device, check it for proper adjustment according to specifications. Continue test until successful result is obtained.

h. High pressure test: check for ram packer leaks by increasing pressure slowly to the rated working pressure of preventer. Hold for required time while checking for leaks. If packer leaks, check worn packers and replace as necessary. If preventer is equipped with automatic locking devices, check them for proper adjustment in accordance with specifications. Continue testing until a successful result is obtained.

i. Test connecting rod for adequate strength by applying pressure as recommended by the manufacturer with rams closed and BOP rated working pressure under rams.

j. Release opening pressure and release pressure under rams.

k. Repeat steps a - j for each set of rams.l. Test blind rams in the same manner as

pipe rams with test plug installed and test joint removed.

ANNULARS AND DIVERTERS

Inspections and tests should include visual inspections and hydraulic tests.

THOROUGH VISUAL INSPECTION

w Face of preventer head/cap for off-center wear, pitting and damage, especially in ring grooves and bolt/stud holes.

w Body for wear and damage.

w Vertical bore for wear and damage from pipe and tools.w Slotted body sleeve for pitting and damage.

Look through slots in base of inner liner

for accumulations of cuttings that might prevent full movement of the piston.w Packer element for wear, cracking, excessive

hardness, correct elastomer composition.w Bolting – both studs and nuts for proper

type, size and condition.w Where possible, inspect ring joint gaskets

for proper type, size and condition.

HYDRAULIC TEST1. Connect closing line to preventer.2. Set test tool on drillpipe/tubing below preventer.3. Test seals between closing chamber and

wellbore and between closing chamber and opening chamber by applying the recommended closing pressure. If other chambers are located between wellbore and operating chamber, these seals should also be tested.

4. If pressure holds, proceed to step 13.a. If pressure does not hold and no fluid

is running out of the opening chamber, the seal between the closing chamber and the wellbore or other operating chamber is leaking. Proceed to step 11.

b. If fluid is coming out of the opening chamber, indicating the seal between the closing chamber and opening chamber is leaking, proceed to step 5.

5. Release closing pressure.6. Install plug in opening chamber, or if

opening line is equipped with a valve, install opening line and close valve.

7. Test seals between the closing chamber, operating chambers, and wellbore by applying recommended closing pressure. Observe to see that pressure holds.

8. Release closing pressure.9. Remove plug in opening chamber and

install opening line or open valve in opening line.

10. Apply 1,500 psi (103.42 bar) closing pressure.11. Apply 1,500 psi (103.42 bar) wellbore

pressure. (Use lower pressure for lower rated equipment.)

12. Bleed closing pressure to 1,000 psi (68.95 bar).

Always perform low pressure tests prior to high pressure tests.

CHAPTER 55-18

13. To test the seal between the wellbore and closing chamber, close the valve on the closing line and disconnect the closing line from the valve on closing unit side of valve. Install pressure gauge on closing unit side of valve and open valve. If this seal is leaking, the closing line will have pressure greater than 1,000 psi (68.95 bar). Caution: if the closing line does not have a valve installed, the closing line should not be disconnected with pressure trapped in the closing chamber.

14. Release wellbore pressure.

15. Release closing pressure.

16. To test the seals between the opening chamber and the closing chamber and between the opening chamber and the piston, apply the recommended opening pressure. If the pressure holds, proceed to step 21.a. If pressure does not hold and no fluid

is running out of the closing chamber opening, the seal between the opening chamber and piston is leaking. Verify this visually. Proceed to step 21.

b. If fluid is coming out of the closing chamber opening, indicating the seal between the opening and the closing chamber is leaking, proceed to step 17.

17. Release opening pressure.

18. Install closing line and block flow (close valve in closing line, if available).

19. Apply 1,500 psi (103.42 bar) opening pressure. If the pressures do not hold, the seal between the opening chamber and the preventer head is leaking. Verify this visually.

20. Release opening pressure and replace necessary seals. Refer to step 22.

21. Release opening pressure, replace closing line, and replace necessary seals.

22. If the closing line has a valve installed, make certain that the valve is open at the end of the test. NOTE: This procedure tests all seals except the seal between the wellbore and the opening chamber. This seal should be tested in the

bottom annular preventer if two annular preventers are being used when a stack is nippled up on an annular preventer (for snubbing, etc.). It can be tested to rated working pressure by running a test joint and plug, closing an upper preventer, removing the opening line, and pressuring the preventer stack up to 1,500 psi (103.42 bar) maximum or by closing an upper preventer and annular preventer, removing the opening line, and pressuring up between preventers.

Once systems have passed all the required tests, make sure to check manifold and annular pressure regulators. Most systems require 1,500 psi (103.42 bar) manifold pressure. The initial closing pressure regulated to the annular depends on several factors. If either pressure is incorrect the regulators must be adjusted, either remotely or manually.

CHRISTMAS TREE TESTING

Trees are classified according to various factors, such as rated working pressure, corrosion, H2S gas and their proximity to other pressure equipment. Depending upon the classification, hydrostatic or gas and hydrostatic tests may be required prior to putting the well on line. If mixed pressure rated components are used, the tree should be tested to the lower rated pressure. Testing usually consists of several pressure holding periods with test time requirements varying according to the tree classification, as well as regulations and policies. The tree body, inlets and outlets – as well as all seals – must be tested. Both sides of bi-directional valves should be tested, one side at a time.

For plug valves, when test pressure is on each side of the plug, the plug should be moved at least two times. Unidirectional valves should have pressure applied in the direction indicated on the body, except for check valves which would be tested on the downstream side with the opposite end open to the atmosphere.

Testing should be methodical,

performed to specifications and

documented.

PROCEDURES5-19

SUMMARY

Once a kick is detected, the well must be shut in according to correct rig procedures. Procedures must be known prior to beginning any well. Modifications to procedures may be made on a case-by-case basis. Common sense usually dictates the alternative solutions as things change. Safety procedures must be developed, known and practiced. Once the BOPs are shut, other areas from the pumps to manifolds and all lines in between should be inspected to ensure the well is shut in and there are no leaks. In cases where the BOP stack is in an enclosed area, or in a cellar where toxic gases may accumulate, respirators should always be worn when working near equipment. Weather conditions, crew changes, toxic fluids, and equipment changes from job to job all may dictate changes in shut-in procedures. These changes must be practiced until the crew is familiar with and proficient at their respective tasks. The consequences of a blowout – fire, pollution, toxic gases, loss of life or resources – dictate that kick detection and shut-in

procedures be a priority during any operation.Practice “What if” thinking. What if

someone is not present at his job assignment? What if equipment will not function properly, or fails altogether? What if other complications arise? Alternate plans and courses of action should be anticipated and practiced in well control drills and discussed with the crew. Fear of the unknown will cause panic. Fear of the known leads to cautious, yet decisive, actions.

When operators move from rig to rig and the contractor works for different companies, shut-in procedures, killsheets and general procedures may differ. Proper procedures for all activities should be discussed and understood by all parties. While the basic shut-in procedures have been covered in this section, remember that extra procedural steps for safety, rig type and company policy are often added.

Too often, emphasis is placed on quickly shutting in the well. If confronted with a flowing well, act but do not overreact. An extra moment taken to do things right the first time may result in a little more kick taken, but this is preferable to panic leading to improper shut-in procedures, mistakes or accidents. t

Wellhead equipment should be tested according to its lowest rated component.

An extra moment taken to shut a well in correctly may result in more influx, but this is preferable to a tragic accident resulting from panic.

CHAPTER

3CHAPTER

6

A good understanding

of basic mathematics

is required for

every well control

operation.

WELL CONTROLBASICS

6-1

T he basic mathematics of well control requires straightforward calculations. Addition, subtraction, multiplication,

division and squaring are commonly used. Pressure, fluid density and volume calculations are also necessary. These calculations and principles will provide answers to many well control problems. This section will introduce the mathematics of well control and will illustrate sections of the worksheets to simplify the calculations.

CIRCULATING CONSTANTBOTTOMHOLE PRESSURE METHODS

After wells are shut in, and formation fluid flow stopped, the bottomhole pressure soon equals the formation pressure. Additional pressure must be held to prevent more formation fluid flow

CHAPTER 66-2

while circulating out the kick. At the same time, excessive bottomhole pressure must be avoided to prevent loss of circulation.

If an influx is to be circulated and removed from the well, it requires circulating the kick while maintaining the bottomhole pressure. Procedures for doing this are called Constant Bottomhole Pressure Methods.

There are choices as to when to circulate out the kick and when to weight up. Either may be done first, or both may be done at the same time, but bottomhole pressure must always be kept at or slightly above the formation pressure. Methods with either choice are the same.

Based on the order of kick circulation and weight up, the following are the most common Constant Bottomhole Pressure Methods.w Driller’s Method – circulate kick out of the

well and then weight up pits and wellborew Wait And Weight Method – weight up pits

and then circulate kick, maintaining weightw Concurrent Method – circulate kick and

build weight at the same timeThese methods have relative advantages and

disadvantages which are discussed separately in the following chapter. They must be fully understood before the appropriate method is selected.

PUMP

PIT

Surface Line Volume 3.5 bbls

Pump #1: 6" X 16" Duplex, Output .157 bbls/stk

Pump #2: 5 1/2" X 16" Duplex, Output .126 bbls/stk

Maximum Pump Pressure3,950 psi

BOP Stack Rating 10,000 psi

Volume in Active Pits 500 bbls

Surface Line Volume 3.5 bbls

Present Mud Weight 12.5 bbls

Reserve Pit Mud Weight 14.7 bbls

TVD 5000 ft, MD 5000 ft

Integrity/Leak-off Test Mud Weight 9.1 ppg

Integrity/Leak-off Test Pressure 1,570 psi

Depth of Test (Shoe or Weak Zone) TVD 5,030 ft

Well Depth: TVD 10,000 ft MD 10,000 ft

CASING

Outside Diameter 9 5/8", Inside Diameter 8.835"

Weight 40 lbs/ft, Grade N-80

Internal Yield (100%) 5,750 psi

Length TVD 5000 ft, MD 5000 ft

DRILL PIPE

Outside Diameter 4.5", Inside Diameter 3.826"

Weight 16.6 lbs/ft

Capacity .01422 bbls/ft

Total Length 9,000 ft

DRILL COLLARS

Outside Diameter 6 1/2", Inside Diameter 2.8125"

Capacity .00768 bbls/ft

Total Length 1,000 ft

Hole Size 8 1/2" bit

ANNULAR

RAM

RAM

RAM

HCR

WCS exercise for

chapter

A record of essential

information should be kept

available for well control

situations.

WELL CONTROL BASICS6-3

NON-CIRCULATINGCONSTANT BOTTOMHOLEPRESSURE METHODS

There are several techniques that relate pressure to the fluid volume released from the well. The Volumetric and Lubricate/Bleed are two such techniques providing control without circulating on bottom.

PRE-RECORDED INFORMATION

A record of essential information needs to be kept to kill or maintain control of a well. This record must be as accurate as possible. Calculations must be performed to find other information for pressure control and kill operations. WCS killsheets are easy to follow and use. This may seem simplistic at times, but it is probably the most thorough approach.

MD FTINCHES FT BBLS/FT LBS/FTWeightCapacity per FootLengthInside Diameter Total Drill String

Length(DP & DC)

DRILL PIPE

INCHES INCHES FT BBLS/FT INCHES TVD FTTrue Vertical Depth

(to Bit)Hole SizeCapacity per FootLengthInside DiameterOutside Diameter

DRILL COLLARS / HOLE SIZE

INCHES INCHES TVD FT MD FT PSI @ 100%Internal YieldWeight & GradeMeasured DepthTrue Vertical DepthInside DiameterOutside Diameter

CASING

LINER X STROKE BBLS/STK LINER X STROKE BBLS/STK PSI BBLSSurface Line VolumeMaximum Pump

PressureOutput _____%EFFPump #2Output _____%EFFPump #1

XX

PUMPS / SURFACE LINES

PPG PPG PPG PSI TVD FT BBLSVolume in Active PitsDepth of Test

(Shoe or Weak Zone)Integrity/Leak-off

PressureIntegrity/Leak-off Test Mud Weight

Reserve Mud WeightPresent Mud Weight

MUD

WELL DATACOMPLETED BY: WELL NAME

INCHESOutside Diameter

Calculations using the prerecorded data provide the information for pressure control and kill operations.

CHAPTER 66-4

*1029.4 is the conversion factor from cylindrical inches diameter to barrels/foot ([π × D² ÷ 4] × [12 inch/ft ÷ 231 in³/gal ÷ 42 gal/bbl]). In drilling applications, 1029.4 is often rounded to 1029. For smaller tubulars, 1029.4 should be used to obtain results that require greater accuracy.

In the metric system to find m³/m, mm diameters must be converted to m (divide mm by 1000) prior to using equation π × D² ÷ 4.

**0.7854 is derived from π ÷ 4 = 0.7854

The bbls/ft (m³/m) is often carried out to five decimal places for accuracy. The smaller the tubular sizes, the higher degree of accuracy that is warranted – especially when displacing or pumping treating fluids.

EXAMPLE 1

What is the capacity per foot (m) of 4.5" (114.3 mm) OD, 3.826" (97.18 mm) ID drillpipe?

Capacitybbls/ft = ID² ÷ 1029.4

= (3.826)² ÷ 1029.4

= 14.6383 ÷ 1029.4

= 0.01422 bbls/ft

Capacitym³/m = (IDmm ÷ 1000)² × 0.7854 = (97.18 ÷ 1000)² × 0.7854 = (0.0972)² × 0.7854 = 0.00945 × 0.7854 = 0.00742 m³/m

PROBLEM 1

What is the capacity per foot (m) of 2 7/8" (73 mm) OD, 2.441" (62 mm) ID production tubing?

To find out how much volume is between two points, multiply the capacity per foot (m) by the length between the points:

Volume = Capacity × Length

Volumebbls = Capacitybbls/ft × Lengthft

Volumem³ = Capacitym³/m × Lengthm

VOLUME CALCULATIONS

Most well control activities require circulating or, at a minimum, pumping a certain volume. Once volume has been determined, the time or strokes to pump volume may be calculated from pump rate.

To calculate capacity per foot (m):

Capacitybbls/ft = ID² ÷ 1029.4*

Capacitym³/m = (IDmm ÷ 1000)² × 0.785**

The smaller the tubing size, the

higher the degree

of decimal accuracy is

warranted when computing

volumes.

WELL CONTROL BASICS6-5

TIME/STROKES TO BIT/END OF TUBING

In all well-killing methods involving weighting up the fluid, the amount of time or strokes from the pump to the bit or the end of tubing (EOT) must be known. (Units that use small pumps may measure volume pumped in barrels or cubic meters per minute rather than strokes per minute.) In reality, the use of strokes to bit is more accurate, since a mud pump is a positive displacement pump. Below is the equation and a sample problem.

Strokes to Bit/EOT = String Volume ÷ Pump Output

Strokes to Bit/EOT = String Volumebbls ÷ Pump Outputbbls/stk

Strokes to Bit/EOT = String Volumem³ ÷ Pump Outputm³/stk

(9) Drill Pipe, Drill Collar Volumes

Drill Pipe Length Capacity per Foot in DP Volume in Drill Pipe Drill Collar Length Capacity per Foot in DC

x = xFT BBLS/FT BBLS FT BBLS/FT BBLS

Volume In Drill Collars

=

(10) Strokes Surface to Bit

Volume in Drill Pipe Volume in Drill Collars Surface Line Volume Drill String Volume Pump Output

+ + ÷BBLS BBLS BBLS BBLS BBLS/STK STKS

STKS Surface to Bit

==

Drill String Volume & Stroke Calculations

EXAMPLE 2How much volume is in 9,000' (2743.2 m) of pipe? (use pipe from Example 1)

Volumebbls = Capacitybbls/ft × Lengthft

= 0.01422 × 9,000

= 128 bbls

Volumem³ = Capacitym³/m × Lengthm

= 0.00742 × 2743.2

= 20.35 m³

PROBLEM 2How much volume is in 6,000' (1828.8 m) of pipe? (use pipe from Problem 1)

For strings with different size inner diameters, the above calculations to determine capacity and volume would be performed for each size and totaled. If a different fluid density will be pumped, the surface line capacity (usually known or given) should be included in the total string volume.

String Volume = Volume in Drillpipe/Tubing + Volume in Collars + Surface Line Volume

When using methods which require weighting up, the workstring volume must be determined.

CHAPTER 66-6

EXAMPLE 3

How many strokes will it take from the pump to the bit using the following information?

Drillpipe Capacity = 0.01422 bbl/ft (0.00742 m³/m)

Drillpipe Length = 9,000 ft (2743.2 m)

Drill Collar Capacity = 0.00768 bbls/ft (0.004 m³/m)

Drill Collar Length = 1,000 ft (304.8 m)

Surface Line Volume = 3.5 bbls (0.557 m³)

Pump output = 0.157 bbls/stk (0.02496 m³/stk)

Pump rate = 30 stks/min

Strokes to Bit/EOT = String Volumebbls ÷ Pump Outputbbls/stk

Stks = (Drillpipe Volbbls + Drill Collars Volbbls + Surface Line Volbbls) ÷ Pump Outputbbls/stk

= ([0.01422 × 9,000] + [0.00768 × 1,000] + 3.5) ÷ 0.157

= (128 + 7.7 + 3.5) ÷ 0.157

= 139.2 ÷ 0.157

= 886 stks

Strokes to Bit/EOT = String Volumem³ ÷ Pump Outputm³/stk

Stks = (Drillpipe Volm³ + Drill Collars Volm³ + Surface Line Volumem³) ÷ Pump Outputm³/stk

Stks = ([0.00742 × 2743.2] + [0.004 × 304.8] + 0.557) ÷ 0.02496

Stks = (20.353 + 1.219 + 0.557) ÷ 0.02496

Stks = 22.13 ÷ 0.02496

Stks = 886 stks

Time to displace the volume can be calculated by:

Time = Strokes ÷ Pump ratestks/min

= 886 ÷ 30

= 29.5 minutes

MD FT BBLS/FT BBLS BBLS/STK

Tubing LengthSurface to EOT

Capacity per Footin Tubing

Tubing VolumeSurface to EOT

Pump Output

STKS

Strokes Surfaceto EOT

x = ÷ =

Tubing Volume/Strokes (Surface to End of Tubing, E.O.T.)

EOT: the accepted

abbreviation for the term

end of tubing.

WELL CONTROL BASICS6-7

Time may also be calculated from volume and pump output. If the pump speed is 30 stk/min, and it has an output of 0.157 bbls/stk (0.0249 m³/stk), then the rate per minute would be:

Pump Rate = Pump Speed × Pump Output

Pump Ratebbls/min = Pump Speedstkump Outputbbls/stk

= 30 × 0.157

= 4.71 bbls/minute

Pump Ratem³/min = Pump Speedstks/min × Pump Outputm³/stk

= 30 × 0.0249 = 0.7485 m³/minute

Then, volume to pump divided by rate per minute will give time:

Time = Volume to Pump ÷ Rate per Minute

Timemin = Volume to Pumpbbls ÷ Rate per Minutestks/min

= 139.2 ÷ 4.71

= 29.5 minutes

Timemin = Volume to Pumpm³ ÷ Rate per Minutestks/min = 22.13 ÷ 0.7485 = 29.5 minutes

PROBLEM 3How many strokes and how much time will it take from the pump to the EOT using the following information?

Production Tubing Capacity = 0.00579 bbl/ft (0.00302 m³/m)

Production Tubing Length = 6,000 ft (1828.8 m)

Surface Line Capacity = 1.5 bbls (0.24 m³)

Pump output = 0.049 bbls/stk (0.00779 m³/stk)

Pump rate = 40 stks/min

ANNULAR CAPACITIES, VOLUMES & STROKES

The following equations will show how to calculate annular capacities in barrels per foot (m³/m), volumes in barrels (m³) and pump strokes necessary to displace that volume. Once the total amount of barrels in the annulus is known, time/strokes to displace that volume may be calculated.

Annular geometry is dependent on the sizes of drilled hole, casing and tubulars. It is possible to have several different sizes or diameters between the pipe and casing or open hole. Each different geometry has a different bbls/ft (m³/m) that should be calculated. Once each capacity per foot (m) is known, multiplying each by the length of that section gives the volume that may be contained.

Annular geometry:describes various annular volumes within one well: e.g., casing, open hole, open hole with tubulars.

CHAPTER 66-8

Adding each section’s volume together will give the total annular volume.

EXAMPLE 4

Calculate the annular volume and required strokes to circulate bottoms up.

Casing ID = 8.835” (224.4 mm), length = 5,000’ (1523.93 m)

Drillpipe OD = 4.5” (144.3 mm), length = 9,000’ (2743.2 m)

Drill collar OD = 6.5” (165.1 mm), length = 1,000’ (304.8 m)

Hole size = 8.5” (215.9 mm)

MD = 10,000’ (3048 m)

Pump = 0.157 bbls/stk (0.02496 m³/stk)

Pump rate = 30 stks/min

Bottoms up:used to

describe the time or pump

strokes required to move fluid from the well

bottom to the surface.

Total Strokes Surface to Surface

STKSStrokes Surface to Bit

STKSStrokes Bit to Surface

STKSStrokes Surface to Surface

+ =

Strokes Bit to Casing Shoe

Volume Between DP & OH

Volume Between DC & OH

Pump OutputBBLS BBLS BBLS/STK STKS

Strokes Bit to Casing Shoe

+ ÷ =B C

Strokes Bit to Surface

Annular Volume Pump OutputBBLS BBLS/STK STKS

Strokes Bit to Surface

÷ =E

Volume Between DP & CSG

Volume Between DP & OH

Volume Between DC & OH

+ +

D. Total Annular Volume

Volume in Choke Line (Subsea Only)

(See back of Kill Sheet)

+BBLS BBLS BBLS BBLS BBLS

Total Annular Volume

=ECBA

Annular Capacities and Volumes

ID of CSG Squared OD of DP Squared

– ÷

A. Annular Volume Between Drill Pipe (DP) and Casing (CSG)

Capacity per Foot Between DP & CSG

Length of DP in CSG(Measured Depth)

xCSG ID2 DP OD2 1029.4

FT BBLSVolume Between

DP & CSG

==A

Hole Size Squared OD of DP Squared

– ÷

B. Annular Volume Between Drill Pipe (DP) and Open Hole (OH)

Capacity per Foot Between DP & OH

Length of DP in OH

xOH2 DP OD2 1029.4 . __ __ __ __BBLS/FT FT BBLS

Volume Between DP & OH

==B

Hole Size Squared OD of DC Squared

– ÷

C. Annular Volume Between Drill Collars (DC) and Open Hole (OH)

Capacity per Foot Between DC & OH

Length of DC in OH

xOH2 DC OD2 1029.4

FT BBLSVolume Between

DC & OH

==C

Annular Volume & Stroke Calculations

D

. __ __ __ __BBLS/FT

. __ __ __ __BBLS/FT

WELL CONTROL BASICS6-9

In this example there are 3 different geometries: A. Drillpipe in Casing, B. Drillpipe in Open Hole, and C. Drill Collars in Open Hole. The lengths to use for the calculations follow.

A. Drillpipe in Casing = MD Length of Casing

Drillpipe in Casing = 5,000’

Drillpipe in Casing = 1523.93 m

B. Drillpipe in Open Hole = MD of Hole – MD of Casing – Length of Drill Collars

Drillpipe in Open Hole = 10,000 – 5,000 – 1,000 = 4,000’ Drillpipe in Open Hole = 3047.85 – 1523.93 – 304.79 = 1219.13 m

C. Drill Collars in Open Hole = Length of Drill Collars

Drill Collars in Open Hole = 1,000’

Drill Collars in Open Hole = 304.79 m

To calculate the annular capacity the formula is similar to the one used to calculate internal capacity, except that diameters are larger and you must subtract out the volume displaced by the string and bottomhole assembly (BHA). In each section there is a larger diameter OD, which is either the hole diameter or the inner diameter of the casing. Subtracting out the total cross sectional inner diameter (ID) volume displaced by the pipe or BHA, use its outside diameter. Once the bbls/ft (m³/m) capacity for each geometry has been calculated, multiply it by the length of that section.

Annular Capacitybbls/ft = (OD² – ID²) ÷ 1029.4

Annular Capacitym³/m = ([OD ÷ 1000]² – [ID ÷ 1000]²) × 0.785

A. Annular Capacitybbls/ft Between Drillpipe & Casing = (OD² – ID²) ÷ 1029.4 = (8.835² – 4.5²) ÷ 1029.4 = (78.057 – 20.25) ÷ 1029.4 = 57.807 ÷ 1029.4 = 0.05616 bbls/ftMultiply this by the length to get volume:Annular Volumebbls/ft Between Drillpipe & Casing = Annular Capacitybbls/ft × Lengthft = 0.05616 × 5,000 = 280.8 bbls Annular Capacitym³/m Between Drillpipe & Casing = ([OD ÷ 1000]² – [ID ÷ 1000]²) × 0.785 = ([224.4 ÷ 1000]² – [114.3 ÷ 1000]²) × 0.785 = (0.05036 – 0.01306) × 0.785= 0.0373 × 0.785 = 0.02928 m³/mMultiply this by the length to get volume:

Annular Volumem³/m Between Drillpipe & Casing = Annular Capacitym³/m × Lengthm = 0.02928 × 1523.93 = 44.6 m³

Capacity refers to units of volume per length, e.g., bbls/ft. Volume refers to total contents, e.g., barrels.

CHAPTER 66-10

B. Annular Capacitybbls/ft Between Drillpipe & Open Hole = (OD² – ID²) ÷ 1029.4 ` = (8.5² – 4.5²) ÷ 1029.4

= (72.25 – 20.25) ÷ 1029.4

= 52 ÷ 1029.4

= 0.05051 bbls/ftMultiply this by the length to get volume:

Annular Volumebbls/ft Between Drillpipe & Open Hole = Annular Capacitybbls/ft × Lengthft

= 0.05051 × 4,000

= 202 bbls

Ann. Cap.m³/m Between Drillpipe & Open Hole = ([OD ÷ 1000]² – [ID ÷ 1000]²) × 0.785 = ([215.9 ÷ 1000]² – [114.3 ÷ 1000]²) × 0.785

= (0.04661 – 0.01306) × 0.785 = 0.03355 × 0.785 = 0.02634 m³/m

Multiply this by the length to get volume: Annular Volumemm³/m Between Drillpipe & Open Hole = Annular Capacitym³/m × Lengthm = 0.02634 × 1291.13 = 32.1 m³

C. Annular Capacitybbls/ft Between Drill Collars & Open Hole = (OD² – ID²) ÷ 1029.4 = (8.5² – 6.5²) ÷ 1029.4

= (72.25 – 42.25) ÷ 1029.4

= 30 ÷ 1029.4

= 0.02914 bbls/ftMultiply this by the length to get volume:

Annular Volumebbls/ft Between Drill Collars & Open Hole = Annular Capacitybbls/ft × Lengthft

= 0.02914 × 1,000

= 29.1 bbls

Ann. Cap.m³/m Between Drill Collars & Open Hole = ([OD ÷ 1000]² – [ID ÷ 1000]²) × 0.785

= ([215.9 ÷ 1000]2 – [165.1 ÷ 1000]²) × 0.785 = (0.04661 – 0.02726) × 0.785 = 0.01935 × 0.785 = 0.01519 m³/m

Multiply this by the length to get volume: Annular Volumem³/m Between Drill Collars & Open Hole = Annular Capacitym³/m × Lengthm = 0.01519 × 304.89 = 4.6 m³

To divide by 1000, simply

move the decimal point

three places to the left.

WELL CONTROL BASICS6-11

Once the volume of each section is known, add them together to calculate the total annular volume. The total annular volume is: A. bbls (m³) between drillpipe and casing plus B. bbls (m³) between drillpipe and open hole plus C. bbls (m³) between drill collars and open hole, or:

Total Annular Volume = A + B + C

Total Annular Volumebbls = Abbls + Bbbls + Cbbls

= 280.8 + 202 + 29.1

= 511.9 bbls

Total Annular Volumem³ = Am³ + Bm³ + Cm³ = 44.6 + 32.1 + 4.6 = 81.3 m³

To calculate strokes for bottoms up, or in this case Bit to Surface, divide the annular volume by the pump output.

Strokes Bit to Surface = Annular Volume ÷ Pump Output

Strokes Bit to Surfacestks = Annular Volumebbls ÷ Pump Outputbbls/stk

= 511.9 bbls ÷ 0.157 bbls/stk

= 3,260 stks

Strokes Bit to Surfacestks = Annular Volumem³ ÷ Pump Outputm³/stk = 81.3 m³ ÷ 0.02496 m³/stk = 3259 stks

The time required to displace the annulus would be:

Time = Annular Volume ÷ Rate per Minute

Time = Annular Volumebbls ÷ Rate per Minutebbls/min

= 511.9 ÷ 4.71

= 108.6 minutes

Time = Annular Volumem³ ÷ Rate per Minutem³/min = 81.3 ÷ 0.7485 = 108.6 minutes

PROBLEM 4Calculate the annular volume, required strokes and time to circulate bottoms up.

Casing ID = 5.920” (150.37 mm)Production Tubing OD = 2.875” (73.03 mm)Circulating Depth = 6,000’ (1828.7 m)Pump Output = 0.049 bbls/stk (0.00078 m³/stk)

Tip: when using a calculator be sure to check the window after your entry. Remember: garbage in = garbage out, every time.

CHAPTER 66-12

KILL RATES ANDKILL RATE PRESSURES

In many well control situations, you must be able to not only prevent the formation from flowing, but also circulate kick fluid from the well. Where possible, a predetermined kill rate and kill pressure (KRP) should be taken with the pump. Determining this circulating pressure is critical and cannot be stressed enough.

The circulating or kill rate pressures are often called by various other names such as slow circulating rates (SCR), slow pump rates (SPR), reduced circulating rate, etc., but they are all the same. This is the pressure required to overcome the friction in the circulating system at a given (slow) pump rate.

Because mud (fluid) properties and other well parameters can affect kill rate pressures, it is very important that kill rates and kill rate pressures are taken on a regular basis.

Kill rate pressures should be taken:

w If fluid density or flow properties change;w When changes are made to bit (e.g., jet

nozzle sizes) and BHA, and also drilling assembly weight changes;w When 500+ ft (152 m) of new hole drilled;w Each tour; andw After pump repair.

There are several different approaches to taking a KRP. In typical scenarios they are taken approximately one-sixth to one-half the normal drilling or circulating rate. Another method is to use the idle speed of the pump, then a series progressing up from there. Many drilling rigs simply use 20, 30 and 40 stks/min. In addition, some operators require the driller to find the circulating rate at specific pressure (e.g., 200, 300, 400 psi, etc. [13.8, 20.68, 27.6 bar, etc.]).

Pump speed is critical. Pump pressure is dependent on this speed, and a slight change in speed may drastically affect circulating pressure. Most drilling and workover rigs use pump stroke counters, which also measure pump rate. Pumps that do not use stroke counters should record gear and rpm used to take KRP, and the volume pumped per minute determined.

Kill Rates (Slow Pump Rate)and Pump Pressures (3 Different Rates)

Measure at beginning of each tour, after drilling 500 feet and after each mud weight and viscosity change.

STKS/MIN

Kill Rate Speed

PSI

Kill RatePump Pressure

=PUMP#1

STKS/MIN

Kill Rate Speed

PSI

Kill RatePump Pressure

=PUMP#1

STKS/MIN

Kill Rate Speed

PSI

Kill RatePump Pressure

=PUMP#2

STKS/MIN

Kill Rate Speed

PSI

Kill RatePump Pressure

=PUMP#1

STKS/MIN

Kill Rate Speed

PSI

Kill RatePump Pressure

=PUMP#2

STKS/MIN

Kill Rate Speed

PSI

Kill RatePump Pressure

=PUMP#2

Kill Rate Pressure:pressure required to overcome the

friction in the circulating

system at a given (slow) pump rate.

WELL CONTROL BASICS6-13

Generally, the circulating rate should be chosen to minimize potential complications. A slow kill rate is chosen for the following reasons.w It is easier to increase the mud weight

smoothly when pumping at slow rates.w Choke reaction time is increased with

higher rate.w It is less likely pump rating will be exceeded.w High pressure surges are less likely to occur.w Higher annular friction pressure (especially

in subsea, slim hole, and through tubing applications) could result in formation damage/failure and loss of returns.w Higher annular friction could increase the

chances of differentially sticking the string.w Complications may develop when gas

reaches surface.

Since kill rate pressures are needed in well killing, ideally they should be taken through the kill manifold and choke. When taking them through the bell-nipple (open BOP), the kill rate pressure will not reflect the actual pressure required circulating from the BOPs through the choke/kill line, manifold, through the choke, separator system and back to pits. Since the choke line friction is small on most surface-stack rigs, crews typically take them through the bell-nipple and ignore this friction. However, on critical wells this pressure should be known and taken into consideration.

Accurate gauges are necessary. If there is a difference between the kill rate pressure on the driller’s console and the pressure on the choke panel, choke panel pressure should be used. If the pressure variance is great enough, an additional calibrated gauge should be used.

To calculate pump rate in bbls/min (m³/min):

Bbls/min = stks/min × Pump OutputPump #1, 0.157 bbls/stk (0.02496 m³/stk), 30 stk/min = 1,000 psi (68.95 bar)

Pump #2, 0.126 bbls/stk (0.02003 m³/stk), 30 stk/min = 550 psi (37.9 bar).

Use Pump #1 to kill well.

SHUT IN PRESSURES –SIDPP, SITP, SICTP

When the well is shut in, the drillpipe or tubing is simply a gauge stem that reaches to the bottom of the hole. This pressure gauge is a surface gauge that would read the bottomhole pressure if the drillpipe were empty. But since the drillpipe is not empty, the gauge shows the difference between the bottomhole pressure and the hydrostatic pressure exerted by the column of mud in the drillpipe.

Mathematically, SIDPP is represented by:

SIDPP = Formation Pressure – Hydrostatic Pressure of Mud in Drillstring

Since the shut in drillpipe pressure (SIDPP) (shut in tubing pressure [SITP] in workover, or shut in coiled tubing pressure [SICTP]) is used to calculate formation pressure, kill weight mud and initial circulating pressure, it is important that it is accurate.

A word of caution about shut in drillpipe pressures: The assumption is made that the shut in drillpipe pressure is correct, and should generally be lower than the shut in casing pressure. It is possible to have a higher shut in drillpipe pressure than casing pressure if the overall density of the fluids in the annulus is heavier than in the drillpipe.

Shut In Drillpipe Pressure PSI

Shut In Tubing Pressure PSI

Usually kill rate pressure is recorded from the gauge on the remote choke panel.

CHAPTER 66-14

If shut in drillpipe pressure seems unreasonably high or low, it could be due to one of the following reasons:

w With a large kick, the pipe may U-tube and be partly empty;

w Pressures were trapped;

w Float in string;

w May have read the pressure too soon, before formation pressure had time to stabilize; or

w May have read the pressure too late, showing the effect of gas migration.

Some operators have a standard procedure of bleeding a small (1/4 bbl [approximately 0.04 m³] or less) amount of mud from the casing to check for trapped pressure. In the event of trapped pressure, the expected response would be drillpipe pressure dropping below original (and incorrect) SIDPP. However, if the drillpipe pressure returns to the value, the original SIDPP was correct. SICP after an initial drop could be slightly higher due to gas expansion, or allowing more influx.

It is good practice, upon shut in, to begin recording both shut in pressures. They should be recorded at least once a minute until the pressure difference between readings slows and appears to stabilize. If the influx is gas, and the viscosity of the fluid is low, pressure stabilization may not occur. If a pressure chart is available, it may be used to determine where pressures stabilize versus the effect of kick migration.

SICP, SIWHP

Shut in casing pressure (SICP) or shut in wellhead pressure (SIWHP) is also a crucial pressure to determine. When a kick occurs, formation fluids enter the wellbore. Since the formation fluid is usually lighter than the mud or fluid in the annulus, it reduces the overall pressure exerted in the annulus. The total hydrostatic pressure in the annulus is typically less than the hydrostatic pressure in the drillstring because the mud in the annulus is either fluid cut or replaced by formation fluid. This has the effect of reducing effective mud weight, reducing mud column length or both. Since the formation pressure is pushing against both sides (drillstring and annulus) and the hydrostatic of the annulus is less, a higher SICP generally occurs. However, if the hydrostatic of the annular fluid, cuttings and influx is greater than the string’s, then SICP will be less than SIDPP.

Mathematically, SICP is represented by:

SICP = Formation Pressure – Hydrostatic Pressure of Mud in Annulus – Hydrostatic Pressure of Influx

The weight of cuttings may increase the hydrostatic pressure of mud in the annulus.

KILL FLUID

The kill fluid, or kill weight mud is the mud weight that is needed to balance the well’s hydrostatic pressure with formation pressure. Kill fluid must circulate throughout the hole before drilling operations can be resumed. Depending on the method used to kill the well (Driller’s, Wait and Weight, or Concurrent) will determine when the kill fluid is pumped. Following is the equation and example problem for determining kill weight mud. The answer is in ppg (m³/m), and carried one number to the right of the decimal point. In most instances, it is rounded up to the next higher tenth.

Shut In Casing Pressure PSI

Shut In Casing Pressure PSI

Shut in pressure values should be recorded about once

every minute until the

pressures stabilize.

WELL CONTROL BASICS6-15

PROBLEM 5Calculate the kill fluid density.

SIDPP = 300 psi (20.69 bar)

TVD = 10,000’ (3048 m)

Present Mud Weight = 12.5 ppg (1498 m³/m)

Kill Weight Mud = ______ ppg ( ______m³/m)

If the kill weight mud calculates to 13.07 ppg (1566 m³/m), the kill weight mud should be 13.1 ppg (1570 m³/m).

CIRCULATING TO KILL THE WELL

To prevent additional influx while killing the well, bottomhole pressure (BHP) must be kept at or slightly higher than formation pressure. Additionally, it is more efficient to circulate the influx out. The combination of several pressures – hydrostatics, annular circulating friction pressure and pressure held on the choke – maintains well control during this time. We must have an understanding of what pressure to hold and the relationship of circulating different fluid densities.

INITIAL CIRCULATING PRESSURE

The initial circulating pressure (ICP) is the combination of the shut-in drillpipe pressure plus the pressure necessary to circulate fluid at a given rate. It is the shut in drillpipe pressure, which is necessary to hold back the kicking formation, and the kill rate pump pressure that is necessary to move fluid through the well.

PROBLEM 6Calculate the initial circulating pressure.

ICP = SIDPP + KRPKill Rate Pressure = 1,000 psi (68.95 bar)SIDPP = 300 psi (20.69 bar)

ICP = _______ psi ( _______ bar)

Required Kill Mud Weight

0.052True Vertical Depth(to Bit or Kick Zone)

Present Mud Weight

PSI

SIDPP

TVD FT PPG PPG

Kill Mud Weight

÷ ÷

Kill Mud & Pressure Considerations

+ =

PSI0.052

TVD FT PPGKill Fluid Density

÷Formation Pressure Depth to Perforations

Top/Middle/Bottom

÷=

Kill Fluid Density

Initial Circulating Pressure (ICP)

PSI

SIDPP

PSI

Kill Rate Pump Pressure

ICP PSI

Initial Circulating Pressure

+ =

Proper kill mud weight is dependent upon an accurate SIDPP value.

CHAPTER 66-16

FINAL CIRCULATING PRESSURE

The final circulating pressure (FCP) is the circulating or kill rate pressure mathematically corrected for heavier fluid. This pressure should be held from the time kill fluid is at the bit until the annulus is filled with the kill fluid.

PROBLEM 7Calculate the final circulating pressure.

Kill Rate Pressure = 1,000 psi (68.95 bar)TVD = 10,000’ (3048 m)SIDPP = 300 psi (20.69 bar)Present Mud Wt. = 12.5 ppg (1498 kg/m³)

FCP = _______ psi ( _______ bar)

INTERMEDIATE PRESSURES

What happens to pump pressure when you circulate fluid of a different density? Heavier fluid generally requires more pressure to circulate due to an increase in friction. You would expect circulating pressure to increase

as you pump a kill fluid in the well. However, because of the slugging effect due to gain of hydrostatic pressure from kill fluid, a decrease in circulating pressures is generally seen once kill fluid starts down the string.

GRAPHING PRESSURE DROP

A certain amount of plotting and arithmetic is required when circulating a kill fluid. The Circulating Pressure Graph shows what happens to tubing or drillpipe pressure for the interval of time when new heavier mud weight is being pumped down the string. The graph shows that the Initial Circulating Pressure gradually changes to the Final Circulating Pressure over the period of time and/or strokes required to displace the string.

1. To prepare the graph, plot the Initial Circulating Pressure at the point on the left margin of the graph.

2. Across the bottom of the graph fill in the number of pump strokes below each five-minute interval of time, until you reach the time or pump strokes required to displace the string. Multiply stroke rate (spm) by minutes to get the total strokes.

3. Draw a line vertically up the graph, based on the time and/or pump strokes required to displace the string as shown on the bottom line of the graph.

Final Circulating Pressure (FCP)

PSI

Kill Rate Pump Pressure

PPG

Kill Mud Weight

PPG

Present Mud Weight

FCP PSI

Final Circulating Pressure

x ÷ =

1300 1257 1215 1172 1130 1087 1048 0 150 300 450 600 750 886 0 5 10 15 20 25 29.5

2000

1000

DRILL PIPE PRESSURE SCHEDULE

ICP FCPStrokes

Time

If the pump rate is constant we can expect

circulating pressure to

decrease as the kill fluid

is pumped to the bit.

WELL CONTROL BASICS6-17

4. On the line that you have drawn, plot the Final Circulating Pressure.

5. Connect the points representing the Initial and Final Circulating Pressure.The completed graph shows the pressure

that must be held on the tubing or drillpipe gauge, using the choke, at any time during the first phase of the kill operation.

PROBLEM 8Fill in the pressure chart.

ICP = 1,300 psi (89.7 bar)Time to Bit = 29.5 min.FCP =1,048 psi (72.3 bar)Strokes to Bit = 886 stksKill Rate = 30 stks/min

PRESSURE CHART

Some operators prefer to keep a chart of the circulating pressures versus the time or pump strokes. To prepare a chart:

1. The top of the stroke section is 0, with the bottom of the stroke section being strokes to bit. Divide strokes to bit by 10, this will be the checkpoint while kill weight mud is being pumped to the bit. So the box under 0 will be 1/10 of strokes to bit, the next one equals 2/10 of strokes to bit, etc. The result of the stroke column should be 10 evenly spaced stroke checkpoints.

Pressure Chart

Strokes or VolumeTheoretical Drill Pipe

PressureActual Drill Pipe Pressure Casing Pressure

Pit VolumeDeviation

0 ICP

BIT FCP

Stks Surf to Bit Strokes per Step Initial Circ Pressure Final Circ Pressure PSI per Step÷ 10 = – ÷ 10 =

A pressure/ volume schedule enables us to maintain a constant bottomhole pressure while circulating out a kick.

CHAPTER 66-18

2. The first block under pressure should be ICP and the final block, FCP. Subtract FCP from ICP and divide by 10. This will represent the pressure drop per checkpoint.

Strokes to Bit = 886 stksICP = 1,300 psi (89.63 bar)FCP = 1,048 psi (72.26 bar)

Graphing or charting to determine the drillpipe or tubing pressure while pumping kill fluid, i.e., ICP to FCP, follows standard methods taught in all well control schools and used in the field. This will result in holding some excess backpressure above what it takes to balance formation pore pressure. The reason for this excess backpressure is that the heavier kill mud is treated as if it occurred uniformly throughout the total length of the string.

The actual distributions of friction pressure due to kill mud are as follows:

1. Drillpipe will have the lowest psi/ft change.

2. Drill collars will be higher than drillpipe due to smaller diameter and smaller bbls/ft.

3. Most of the additional friction pressure will occur at one point: the jet nozzles of the bit.

4. Annular friction loss due to kill and original fluid is also treated as if it occurred in the string.

The two graphs below show a comparison between actual drillpipe pressure distribution and the results obtained by simple methods. As you can see, at rates under 2.5 bbls/min (0.397 m³/min) and required mud weight increases of less than 1.0 ppg (119.8 kg/m³), the excess backpressure would be quite small, 50 psi (3.45 bar) or less. At pump rates of 5 bbl/min (0.795 m³/min) and/or mud weight increases above 1.0 ppg (119.8 kg/m³) the extra pressure could amount to as much as 200 psi (13.8 bar) and would be a consideration in selecting slower pump rates if lost circulation has been experienced. Also, this could serve as another reason for not intentionally holding too much extra backpressure over what it is calculated, as we already have some safety factor built into the system.

psi 700bar 48.3

psi 600bar 41.4

psi 500bar 34.5

psi 400bar 27.6

psi 300bar 20.7 100 200 300 400

FCP = 370psibar 25.5

Pump Strokes

DP

Pre

ssu

re

AnnularBit JetsDrill Collars

Drill Pipe

Standard Method

Actual Drill Pipe Pressure Distribution

ICP = 696psibar 48

Drill Pipe

psi 1600bar 110.3

psi 1500bar 103.4

psi 1400bar 96.5

psi 1300bar 89.6

psi 1200bar 82.7 100 200 300 400

ICP = 1589psibar 109.6

FCP = 1397psibar 96.3

Annular Friction

Pump Strokes

DP

Pre

ssu

re

Bit Jets

Drill Collars

Standard Method

Actual Distribution of Pressure Drop

Use lower kill rate speeds to

minimize excessive pressure if

standard ICP to FCP pressure chart is used.

A-10 WELL

2.5 BPM (.397 m³/min)1.0 Kick Intensity (119.6 g/l)

A-10 WELL

5.0 BPM (.795 m³/min)1.0 Kick Intensity (119.6 g/l)

WELL CONTROL BASICS6-19

DRILLING ANNULARPRESSURE CONSIDERATIONS

Regulations often require that the maximum pressure at surface beneath the BOPs be posted near the driller’s station. It must be calculated for each subsequent casing string. This pressure consideration is generally based on one of three different values.

w Casing Burst Pressure

w BOP Stack Limits

w Pressure that may cause formation damage.

If casing or BOP Stack limits the pressure that can be put on the well, the crew must be careful not to exceed that value. It is seldom that this limit occurs because well programs generally require that both the casing string and the BOPs handle any pressure encountered. However, in field use, casing and equipment are subject to wear, fatigue and corrosion damages that may lead to less than optimum performance and pressure ratings.

During a well control procedure there is a possibility that formation damage, lost circulation or an underground blowout may result if the estimated integrity pressure is exceeded. This is only a surface pressure estimate (a decision reference point, not an absolute stopping point) and each well control effort should be based on the conditions unique to that well.

Casing depth, formation integrity, present and kill fluid density, kick position and imposed surface pressures are all factors that affect this pressure consideration.

PROBLEM 9Fill in the pressure considerations.

Depth of Test = 5,030’ (1533 m)

Present Mud Weight = 12.5 ppg (1497 kg/m³)

Leak Off Test Mud = 9.1 ppg (1092 kg/m³)

Leak Off Test Pressure = 1,570 psi (108.25 bar)

Casing Internal Yield (100%) = 5,750 psi (396.46 bar)

BOP Stack Test = 10,000 psi (689.5 bar)

Casing Internal Yield

PSI @ 100%Casing Internal Yield Safety Factor

(.70 or less)

PSIAdjusted Casing Yield

x =

PSIIntegrity/Leak-off

Pressure

0.052TVD FT

Depth of Test (Shoe or Weak Zone)

PPGIntegrity/Leak-off Test Mud Weight

PPGEstimated Integrity

Fluid Density

÷ ÷ + =

PSIBOP Test Pressure

=

Pressure ConsiderationsEstimated Formation Integrity/Leak-off/Fracture Fluid Density (Mud Weight)

PPGEstimated Integrity

Fluid Density

PPGPresent Mud Weight

TVD FTDepth of Test

(Shoe or Weak Zone)

0.052PSI

Estimated IntegrityPressure

– x x =

Estimated Formation Integrity Pressure (With Present Mud Weight)

B.O.P. Test Pressure

Each well control effort should be based on conditions unique to that well.

CHAPTER 66-20

TUBULAR PRESSURECONSIDERATIONS

Many operations performed within existing tubulars must consider burst and collapse limitations. A safety factor is decided upon (based on age, wear, corrosion and other damage) and the tubing derated or adjusted from its original specifications. Examples of this follow.

Adjusted Casing Internal Yield =Casing Internal Yield × Safety Factor

Adjusted Tubing Internal Yield = Tubing Yield × Safety Factor

Adjusted Tubing Collapse =Tubing Collapse × Safety Factor

PSI PSI

Casing Internal Yield Safety Factor(.70 Or Less)

Adjusted Casing Yield

x =

Casing Internal Yield

Tubing Collapse Safety Factor(.70 Or Less)

Adjusted Tubing Collapse

PSI PSIx =

Tubing Collapse

Tubular Pressure Considerations

PSI PSI

Tubing Yield Safety Factor(.70 Or Less)

Adjusted TubingInternal Yield

x =

Tubing Yield

Bullhead Pressure ChartVolume in BBLSStrokes Estimated Max.

Static PressureVolume in

GALSActual Tubing

PressureCasing Pressure Pump Rate Notes

0 0 0Initial

Kill Point

Overdisplace

Final

Internal yield:the pressure

value which, if applied inside

the tubular, will cause the pipe

to burst.

WELL CONTROL BASICS6-21

FORMATION PRESSURECONSIDERATIONS

If an existing well is to be killed prior to subsequent operations, pressure imposed against the formation may increase the time and costs to bring it back to production. Field calculations may be performed to determine allowed static pressures to minimize the risk of overpressuring the well while attempting a kill.

The approximate average hydrostatic of the produced fluids in the production string can be determined by:

Average Hydrostatic Pressure in Tubing = Formation Pressure – Initial Shut in Pressure

Then, the maximum pressure that may be applied (based on existing data) is:

Initial Estimated Maximum Pressure on Tubing = Estimated Formation Integrity Pressure (Fracture Pressure) – Average Hydrostatic Pressure in Tubing

As kill fluid is pumped down the production string, the amount of static surface pressure that may be imposed prior to incurring damage decreases. Once kill fluid is to the formation, a final static pressure may be calculated:

PPGEstimated Integrity

Fluid Density

0.052TVD FTDepth to PerforationsTop/Middle/Bottom

PSIEstimated Formation

Integrity Pressure

x x =

Estimated Formation Integrity Pressure (Fracture)

PSIFormation Pressure

PSIInitial Shut In

Tubing Pressure

PSIAverage Hydrostatic

Pressure in Tubing

– =

Average Hydrostatic Pressure in Tubing

Formation Pressure Considerations

PSIEstimated Formation

Integrity Pressure

PSIAverage Hydrostatic

Pressure in Tubing

PSIInitial Estimated Max.

Pressure on Tubing

– =

Initial Estimated Maximum Pressure on Tubing (Static)

PPGKill Fluid Density

0.052TVD FTDepth to PerforationsTop/Middle/Bottom

PSIKill Fluid Hydrostatic

Pressure

x x =

Kill Fluid Hydrostatic Pressure

PSIEstimated Formation

Integrity Pressure

PSIKill Fluid Hydrostatic

Pressure

PSIFinal Estimated Max. Pressure On Tubing

– =

Final Estimated Maximum Pressure on Tubing (Static)

PSIInitial Max. Pressure

on Tubing(Lesser of #3 or #6)

PSIFinal Max. Pressure

on Tubing(Lesser of #3 or #8)

10Number of “Steps”

PSI/STEPPSI per “Step”

– ÷ =

Pressure Consideration PSI per “Step”

If formation pressure is known, average hydrostatic pressure can be estimated, once the producing well is shut in.

CHAPTER 66-22

Final Estimated Max Pressure On Tubing = Estimated Formation Integrity Pressure (Fracture Pressure) – Kill Fluid Hydrostatic

A chart may be prepared to document volume vs. pressure. This chart (p. 116) is simple to complete like the drilling pressure chart.

Volume calculations to the kill point must also be completed prior to operations. The volume calculations and an over displacement (if required) are prepared.

Circulating friction increases as the kill fluid is pumped down the string. This increases surface pressure and pressure within the tubing. Sudden pressure increases may burst the tubing, or be an indication of complications developing. Keep good notes. Be prepared to shut down if a problem occurs.

More complex calculations may be required on a critical well, including the effects of circulating friction.

Estimated Barite RequirementsTotal Volume In Active System

BBLSVolume in Active Pits

BBLSDrill String Volume

BBLSTotal Annular Volume

BBLSVolume Between DP &

Riser (Subsea Only)

BBLSTotal Volume

in Active System

+ + + =

Sacks Per 100 Barrels

35PPG

Kill Mud Weight

– =

PPGKill Mud Weight

PPGPresent Mud Weight

14.7– x ÷SXS/BBL

Sacks per Barrel

=

Total Barite Required

BBLSTotal Volume in Active System

SXS/BBLSacks per

Barrel

SXSTotal Barite Required

x =

Volume Increase Due To Barite Addition

SXSTotal Barite Required

14.7BBLS

Volume Increase

÷ =

Required Mixing Rate

SXS/BBLSacks per

Barrel

BBLS/MINCirculating Rate

SXS/MINRequired Mixing Rate

x =

Dilution of Reserve Mud With Water

PPGKill Mud Weight

8.33– =

PPGMud Weight in

Reserve Pit

PPGKill Mud Weight

BBLSVolume inReserve Pit

– x ÷BBLS

Volume of Waterto Add

=

1,500 lbs of barite added to the system

will increase the volume by about 1 barrel.

WELL CONTROL BASICS6-23

BARITE REQUIREMENTS

If kill fluid is used, consider the total barite required, amount on location and the required mixing rate. These calculations follow:

1. Bbls in Active Pits = 600 bbls (95.4 m³)

2. Bbls in Annulus = 509 bbls (80.9 m³)

3. Bbls in Drillstring = 139 bbls (22.1 m³)

4. Present Mud Wt = 12.5 ppg (1498 kg/m³)

5. Kill Weight Mud = 13.1 ppg (1569 kg/m³)

6. Mud Weight, Reserve Pit =14.7 ppg (1761 kg/m³)

7. Reserve Pit Volume = 150 bbls (23.8 m³)

8. Kill Rate = 4.71 bbls/min (0.748 m³/min)

9. Strokes to Bit = 886 stks

10. Kill Rate = 30 stks/min

SUMMARY

Well killing basics are not difficult, but they are vital. If we didn’t know how to apply the basics, well killing would have to rely on the SWAG (or scientific wild-ass guess) method. Prerecorded information – such as kill rates, kill rate pressures and maximum allowables – must be gathered. The more information that you know about the kick, the shut-in conditions and your equipment, the better your chances are of performing a successful kill in the shortest time.

And remember: station bills and job responsibilities are vital to any rig operation. All organizing and directing activities should be completed well in advance of a kick. t

Accurate information is vital to performing a successful kill in the shortest time.

CHAPTER

3CHAPTER

7

Basic mathematics

are required

for every well

control operation

WELL CONTROLMETHODS

7-1

T here are many techniques for controlling a well. Whether a kick has occurred during drilling or workover

or whether a live well must be controlled, the basics are the same. These methods maintain bottomhole pressure at a desired level, typically at or above the formation’s pressure in order to prevent further influx of formation fluid. In live wells, it is not always desirable to kill the well, but rather to control the pressure at a manageable and safe level. Some techniques provide for circulating a fluid to remove kicking fluid or bringing the well to the desired level of pressure control. Other pump techniques allow fluid to be pumped into a well, with no returns taken at the surface. Non-pumping techniques allow pressure control of the formation and/or allow stripping into or out of a well. These techniques all have common goals:

CHAPTER 77-2

shut-in pressures are known and correct control procedures have been implemented until the kill operation can begin (unless otherwise noted).

DOCUMENTING WELL CONTROL

During any well control operation data collection and documentation are valuable tools, helping to organize the operation and lend confidence to those on the job. The crew can know what is going on and feel in control of a situation. But proper documentation is one of the most neglected aspects of well control operations. Clear and concise records are essential to ensure proper pressure is maintained and that trends can be identified and evaluated. Unusual occurrences should be documented. Solutions to many complications are evident when good records illustrate the problem.

Circulating pressures, volumes pumped (often expressed in pump strokes), fluid properties (e.g., density and viscosity), pit changes, and choke position should be noted. The chart below is an example of what should be recorded at a minimum.

controlling the kicking or producing formation and avoiding lost circulation. The difference in these methods occurs if fluid weight is increased and if the well will be circulated. The principles in this chapter are well established and work equally well in all applications (drilling, workover, completion) when warranted.

This chapter discusses various Constant Bottomhole Pressure Methods of controlling the well and methods for choke response. If the goal is to remove kicking fluid, there are two techniques to prevent additional influx. The first is to add enough backpressure on the present fluid column to equal formation pressure. The second is to hold enough backpressure and displace the original fluid in the well with a fluid that is dense enough to equal or exceed formation pressure.

Note: Shut In Drillpipe Pressure (SIDPP), Shut In Tubing Pressure (SITP) and Shut In Coiled Tubing Pressure (SICTP) all refer to the same pressure, the pressure on the pump side of the U-tube. Shut In Casing Pressure (SICP) and Shut In Wellhead Pressure (SIWHP) refer to the pressure on the choke side of the U-tube. Although these terms are interchangeable, the most common usage based on specific applica-tions is presented. In addition, techniques presented in this section assume that correct

Well Control Operation Data Sheet

STROKES OR THEORETICAL ACTUAL PRESSURE ADJUSTMENT ACTUAL FLUID IN FLUID OUT CHOKE POS. PIT TIME VOLUME CIRC. PRESS. CIRC. PRESS. +/- PSI @ STKS ADJ. PRES. AFTER CASING PRESS. WT. VIS WT. VIS % OPEN LEVEL REMARKS

Proper documentation

is one of the most neglected

aspects of well control operations.

WELL CONTROL METHODS7-3

PUMP

PIT

ANNULAR

RAM

RAM

RAM

HCR

CASING

OD – 9-5/8”ID – 8.835”WEIGHT – 40 lbs/ftGRADE – N-80INTERNAL YIELD (100%) – 5,750 psiLENGTH TVD – 5,000 ftLENGTH MD – 5,000 ft

THIS WELL DATA WILL BE USED IN THIS CHAPTER UNLESS OTHERWISE NOTED.

PUMP #1 – 6” × 16” Duplex OUTPUT – 0.157 bbls/stkPUMP #2 – 5-1/2” × 16” Duplex OUTPUT – 0.126 bbls/stk

MAXIMUM PUMP PRESSURE – 3,950 psi

BOP STACK RATING – 10,000 psi

VOLUME IN ACTIVE PITS – ? bbls

SURFACE LINE VOLUME – 3.5 bbls

PRESENT MUD WEIGHT – 12.5 ppg

RESERVE PIT MUD WEIGHT – 11.7 ppg

DRILLPIPE

OD – 4-1/2”ID – 3.826”

WEIGHT – 16.6 lbs/ftCAPACITY – 0.01422 bbls/ft

LENGTH – 9,450 ft

DRILL COLLARS

OD – 6-1/2”ID – 2.8125”

CAPACITY – 0.00768 bbls/ftLENGTH – 550 ft

HOLE SIZE – 8-1/2” bitwith 3 10/32 jets

WELL DEPTH

TVD – 10,000 ftMD – 10,000 ft

INTEGRITY/LEAK-OFF TESTMUD WEIGHT – 10.0 ppg

INTEGRITY/LEAK-OFF TESTPRESSURE – 1,600 psi

DEPTH OF TEST(SHOE OR WEAK ZONE)TVD – 5,030 ft

1. USE PUMP #1

KILL RATE SPEED – ________ spm

PUMP PRESSURE – ________ psi

2. STROKES TO DISPLACE TUBING – 905 stks

3. STROKES FOR BOTTOMS UP – 3,323 stks

4. STROKES, TOTAL CIRCULATION – 4,228 stks

PUMP #1 SLOW PUMP RATE

PRESSURE SPM BPM (PSI) 16 2.50 350 24 3.75 770 32 5.00 1,350

USE PUMP #1 AT 24 SPM

SIDP – 520 psi

SICP – 820 psi

ICP – 1,290 psi

FCP – 832 psi

KICK SIZE – 16 bbls

CHAPTER 77-4

Pressure maintained at or through the

choke - controls pressure

throughout the well.

CIRCULATING TECHNIQUES

There are three common circulating methods used in well control. They are the Driller’s Method, the Wait and Weight Method and the Concurrent Method.

The differences between these are when to circulate the kick from the well, and when to pump the kill fluid if it is decided that the well will be killed. They are all constant bottomhole pressure methods. This means that after the well is shut in, until the time the well is killed, pressure at the bottom of the well must be maintained at, or slightly above, the formation pressure. If this can be accomplished without lost circulation or equipment failure, the well can be killed without taking further influx.

The following must be thoroughly known prior to starting any well control technique.

CHOKE RESPONSE

An understanding of what to expect is essential for any well control operation. Pressure maintained at or through the choke, controls pressure throughout the well. Improper responses can lead to additional influx, formation, and/or equipment failures.

There are several critical times when proper action must be taken.

w Pump start up: As the pump is brought on line, a pressure increase felt throughout the system will be imposed. As pressure on the casing begins to increase, the choke must be rapidly opened from a closed position to allow fluid to bleed through, but only opened enough so that pressure remains constant. If wellbore pressure increases too much, losses or damage to the formation may occur. If pressures are allowed to decrease below the shut in value, additional influx may occur. This is explained in more detail later in this section.

w Proper choke adjustments: Once the pump is running at correct rate, adjustments to maintain proper circulating pressure are made by choke adjustments. If drillpipe pressure is thought to be too high, determine excess amount as accurately as possible. This is the amount of pressure that must be bled from the casing pressure by choke adjustment. Determine the casing pressure to be bled in order to correct circulating pressure. The determination may be made by calculator, line increment on the gauge, or in your head. Only when this is known, carefully adjust the setting of the

Determining Choke Adjustment

PUMP

Determine Choke Adjustment

Determine C hoke

A djus tement

Adjust Choke Slowly by Determined Pressure

A djus t C hoke S lowly by

Determined P res s ure

Make Sure Change Transits

Make S ure C hange

T rans its

PUMP PUMP

Determining choke adjustment

WELL CONTROL METHODS7-5

Pressure and circulating rate changes are felt throughout the well’s entire circulating system.

choke towards a more open position. If the circulating pressure is too low, the same

procedure is used, except the choke will be adjusted towards a more closed position.

w Perhaps one of the more common mistakes is watching the choke position indicator gauge and assuming that each increment will adjust the pressure by the same amount. Flow rate and pressure losses through an orifice are not linear. As the choke orifice is increased or decreased the choke indicator scale does not represent set pressure adjustments. The indicator scale only shows the relative position of the choke and which way the choke is moving – open or closed. Pressure adjustments should be carefully made using gauge pressure, not the indicator.

w Gas at choke: Fluid type, flow rate, and choke sizes are related to maintaining correct pressures. If a different fluid type goes through the choke, its frictional coefficient and flow rate will either increase or decrease. This is the case when gas hits or follows fluid through the choke. An abrupt decrease in pressure across the choke may occur. If this happens, pressure will decrease throughout the well, potentially causing another kick.

w Pressures should be recorded throughout the operation. If pressure abruptly decreases, consult the recorded value and immediately adjust the choke towards the more closed position until the last recorded value is obtained. Give proper lag time to correct pressure throughout system, and readjust as needed.

w As gas (which has very low density) exits through choke, liquid replaces it. This subsequently results in an increase in circulating pressure on drillpipe. Determine amount of the increase on drillpipe, and adjust choke toward a more open position to bring drillpipe pressure back to planned value. This step may be repeated several times while circulating gas through choke.

w Fluid following gas through choke: Gas requires a much smaller opening or orifice size to maintain the same pressure as a

liquid. When fluid following gas hits the choke, it results in an abrupt increase in friction and pressure buildup. This increase in pressure may cause formation failure. Immediately consult the recorded pressure chart and adjust the casing pressure to the last recorded value (prior to fluid hitting choke) by adjusting the choke towards the more open position. Give proper lag time to correct pressure throughout system, and readjust as needed.

w Pump shut down: If the well is still live (i.e., no kill fluid is to be pumped) and the well must be shut in, the objectives are to not trap excessive pump pressure or allow additional formation fluid to feed in. When the pump speed is decreased, circulating pressure decreases and flow across the choke decreases. If the casing pressure begins to decrease, adjust the choke towards the more closed position to maintain the last recorded value prior to taking the pump off line. As pump speed is reduced again, pressure will again decrease and more choke adjustment is necessary. Once the pump is stopped, the choke may have to be closed rapidly to maintain a planned pressure. If pressure falls below planned values, additional influx may occur. On the other hand, high pressures may lead to formation breakdown.

LAG/TRANSIT TIME

Imagine the well’s circulating system as a U-tube. This means that the casing and standpipe pressure are closely related and pressure signals and circulating rate changes are felt throughout the entire U system. In well control, this is an important concept. Tubing or drillpipe pressure reports on downhole pressure. If drillpipe pressure changes from planned values (to maintain constant bottomhole pressure), it must be corrected. This is accomplished by varying the amount of choke pressure on surface.

When choke pressure is altered, a pressure wave is initiated that will be felt throughout the circulating system. It will not produce an immediate response on the drillpipe pressure

CHAPTER 77-6

gauge, but will lag behind. This transit delay should be taken into account before another attempt is made to alter drillpipe pressure.

A rule of thumb can be applied: Wait approximately two seconds for every 1,000’ (304.8 m) of string length that is in the well. On a 10,000’ (3048 m) well, for example, it takes approximately twenty seconds for a pressure change made on the choke to be seen on the drillpipe or tubing gauge. This is approximately ten seconds for the change to travel from the choke down the annulus to the end of the drillpipe, and another ten seconds for the change to travel up the drillpipe and back to surface. On deeper wells a considerable amount of time may pass before the change is felt throughout the system. If additional changes are made during this lag time, overcorrecting may occur resulting in additional influx or lost circulation.

The rule of thumb is an approximation to establish lag time. Once a correction is made, find the approximate time delay that it takes to see the change, and make a note of the time difference. It should be pointed out that many things affect this time delay. The compressibility of gas will slow this response time down. Factors such as circulating rate,

fluid type and fluid compressibility will also have an effect. The point is to realize that responses are not instantaneous.

BRINGING A PUMP ONLINE

Mistakes can be made when choosing pump rates to circulate out a kick. Pump start-up procedure is also a critical time. Remember, a slower pump rate results in less annular friction and minimizes pressure against the formation. As hydraulic diameter and capacity between pipe and casing decreases, so should the pump rate. Too high a rate may result in over-pressuring formation to the point of damage or fracture. And when gas reaches the surface, separator equipment may become overloaded. The extra circulating time at slower rates may be worth it when compared to complications that may result.

Below are some suggestions for simplifying the first few minutes of a kill operation. Remem-ber that we must maintain a constant bottomhole pressure while bringing the pump on line.

1. Communications. Make sure communication between pump and choke operator are good and that they have discussed how they are going to react to each other’s operation.

2 Pressure Pulse goes opposite way

3 Pressure change registers on kill manifold pressure gauge

1 Choke position change

4 - 8 Pressure change transits through system

9 Pressure change registers on pump gauge after transit time

PUMP

7

8

6

4

5

Choke adjustment

Too high a pump rate may result

in over-pressuring a formation to

the point of damage or

fracture.

WELL CONTROL METHODS7-7

2. Start pump slowly. Pumps should be brought up to speed slowly, or in stages. This process should take several minutes and should have been discussed prior to pump start up. Rigs with mechanical pumps, constant speed pumps or rigs without a hydraulic choke run additional risk of formation or equipment failure. On rigs with mechanical pumps, the pump cannot be brought on line slowly. Its slowest speed is at idle, which is often the kill rate. If a manual choke is used, it may not be able to open or close fast enough during pump start up. Start up procedure in either case is to open the choke immediately prior to pump startup. This may allow the well to flow and another influx occur, but it is preferable to breaking down a formation from uncontrolled pressure surges. After pump is up to speed, casing pressure should be adjusted back to the value it had before pump start up.

Another possibility is to equip the standpipe with a bypass choke. This would be opened prior to starting the pump.

The pump is then brought on line and the bypass choke gradually closed to divert more fluid down the string. This controls the flow of fluid similar to rigs that can bring a pump online as slow/fast as desired to minimize pressure surges or reductions in pressure felt throughout the well.

3. Hold casing pressure constant initially. Casing (choke) pressure should be held constant (at correct shut in value) while bringing up the pump to kill rate speed. The exception to this is cases where high annular/choke/kill line friction pressures are present. This case is discussed in the Complications section. If casing pressure is allowed to drop when bringing a pump up to speed, bottomhole pressure will also drop. This may result in more kick influx. If the pump is brought on line and the choke is not opened or operated quickly enough, a rapid increase in pressure may lead to formation and/or well equipment breakdown. Either should be avoided, but a secondary kick is preferable to formation and well equipment failure.

Choke Operator

Holds choke pressure

according to proper value

Pump Controller

Brings pump online slowly or in stages as directed

Communication

PUMP

If casing pressure is allowed to drop when bringing a pump up to speed, the bottomhole pressure will also drop.

CHAPTER 77-8

Remember casing pressure is backpressure. As soon as the pump is on line and running at kill rate speed, return the casing pressure to its proper value.

4. The Circulating Pressure seen on the pump gauge is typically called the Initial Circulating Pressure or ICP. This is a combination of pressure to circulate the well at a given rate and prevent the well from flowing. Mathematically, it can be expressed as ICP = SIDPP + KRP, where SIDPP is the shut in drillpipe pressure and KRP is the pump pressure at the desired kill rate. If proper start up procedures are used and there is a significant difference between the actual ICP value and the calculated value, decisions should be made whether to use the actual value or to shut down, evaluate and begin again.

5. Maintain Kill Rate. Once the kill rate speed is chosen, it should not be changed. If pump speed is changed, then calculations such as the initial circulating pressure, final circulating pressure, and the pressure chart or graph must be changed as well.

DRILLER’S METHOD

The Driller’s Method is a technique used for circulating formation fluids out of well with or without killing the well. It is often used to remove kicks swabbed in during a trip out of the hole. The Driller’s Method is simple and straightforward. It is important to understand the techniques and ideas used in the Driller’s Method because other methods of well control incorporate many of its principles.

In certain cases however, the Driller’s Method may cause somewhat higher casing pressures than do other techniques and requires more time to kill the well. It is ideally suited for tripping applications. Once back to bottom the annular fluid column is circulated and the influx removed. It is also used where no weighting material is needed or available. In addition, it is used to remove gas kicks where high migration rates can cause shut in problems. It may also be used where personnel and/or equipment resources are limited. However, it is not often used on wells where lost circulation is anticipated or expected.

PUMP START UP & CHOKE PRESSURE

Before Startup

Bringing Pump Online

Surface SubseaPump at Kill Rate Speed

Pump start up and choke

pressure

Once the kill rate speed is chosen, it

should not be changed.

WELL CONTROL METHODS7-9

In the Driller’s Method, first the kick is circulated out of the hole. Then, if the well is underbalanced, replace the fluid in the hole with a fluid exerting more pressure than the kicking formation.

Following is the Driller’s Method procedure:

1. Well is shut in after the kick.

2. Record Stabilized Shut In Drillpipe (SIDPP) and Shut In Casing Pressures (SICP).

3. Kick is immediately circulated out of hole.

4. When this is finished, well may be shut in a second time.

5. If necessary, fluid weight is increased.

6. Well is circulated a second time with new, heavier fluid to regain hydrostatic control.

EXAMPLE PROBLEM

The well is shut in after a kick and the SIDPP, SICP, and kick size recorded. Using well data from page 7-3 and the following information, the Driller’s Method will be explained.

Kill Rate Speed is 24 spmKill Rate Pressure is 770 psi (53.09 bar)Pump, 6” × 16” (152.4mm × 406.4mm) duplexFluid Weight in Hole 12.5 ppg (1498 kg/m³)

SIDPP is 520 psi (35.85 bar)SICP is 820 psi (56.54 bar)

START CIRCULATION

Bring pump up to kill rate speed (24 spm) while maintaining casing or backpressure constant. (Or at planned pressure versus pump rate, as is the case in subsea and slim hole.) This will maintain the bottomhole pressure, prevent the well from flowing, and minimize chances for formation damage to occur. In this example, after the pump is brought to speed, the casing value should be adjusted to 820 psi (56.54 bar).

FIRST CIRCULATION

When the pump is running at the Kill Rate Speed and casing pressure has been adjusted with the choke to its correct value (same pressure as when well was shut in, and at planned values for subsea and slim hole), the control point is shifted to the drillpipe pressure gauge. The drillpipe pressure at this time is called the Circulating Pressure (CP), or in other methods Initial Circulating Pressure (ICP). It is the combination of the SIDPP, and the pump pressure at this pump speed. In this example, the Circulating Pressure is 1,290 psi (88.95 bar).

Rate, Stks/min

0Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

0

520 820

Hold casing pressure constant when bringing pump online.

Maintaining bottomhole pressure prevents the well from flowing while minimizing the chance of formation damage.

CHAPTER 77-10

The Circulating Pressure is held constant by using the choke, and the pump rate is kept constant at the Kill Rate Speed until the kick is circulated out of the hole. If the kick is gas, pressure adjustments may be necessary to maintain the proper Circulating Pressure. Generally speaking as the kick expands, it displaces fluid and results in lost hydrostatic pressure, which is compensated for by increasing casing pressure. If the kick is pure salt water or oil, few pressure adjustments are required.

PRESSURE ADJUSTMENTS

As the kick is being circulated, maintain drillpipe pressure according to planned pressure.

If the drillpipe pressure is incorrect, it must be adjusted to its proper value. To do this, determine the amount of pressure (high or low) that must be corrected. Do not estimate. Small changes less than 50 psi (3.45 bar) are typically not considered, unless low or excess pressures are critical. The amount of pressure needed, must be added to or taken away from the casing

value (backpressure). Lag time should be taken into account for this pressure change to be reflected on the drillpipe gauge. Remember that a rule of thumb for this lag time is to wait approximately two seconds per thousand feet of well depth. Many factors affect lag time, so only after an adequate amount of time should another correction be considered if a response is not seen.

THE KICK AT SURFACE

On gas kicks, casing pressure first, and then drillpipe pressure (after the lag time for changes from one gauge to another) will start to drop as the kick starts coming through the choke.

Once pump is at planned circulating speed, circulating pressure is noted. This is the pressure to maintain.

Rate, Stks/min

24Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

22

1290 820

Pump

Rate, Stks/min

24

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

1200

870

If pressure falls below where it should be, an adjustment

should be made.

A rule of thumb for lag time is to wait about two seconds

per thousand feet of well

depth.

WELL CONTROL METHODS7-11

The choke must be quickly adjusted to bring casing pressure back to the value it had before the gas hit the choke. It is advisable to keep a written record of the casing pressure as a reference. After the casing pressure is brought back to the proper value, and after the proper amount of time for pressure to stabilize throughout the system, then switch back to the drillpipe gauge pressure and make necessary corrections. When fluid following the kick goes through the choke, casing pressure may increase. Again, adjust casing pressure to its last recorded value.

ONCE KICK IS REMOVED

If the fluid weight has to be increased after the kick has been circulated out, there are two basic options. The first is to shut the well in again. The control point is again the casing pressure while slowing down and stopping the pump. It must be held constant as the pump rate changes. If casing pressure is allowed to drop below the SICP another kick could be taken (if well is underbalanced). If all the influx has been removed, the hydrostatic in the annulus should equal the hydrostatic in the drill

1: for pressure adjustments first determine how much pressure is needed.2: then adjust casing pressure by only that amount.3: allow proper lag time and reevaluate.

Casing PressureTubing Pressure

Tubing Pressurewill increaseaftercasing pressureis increased (920)

Rate, Stks/min

24Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

3000

Pressure needs tocome up 100 psi

Casing PressureTubing Pressure

(820)

IncreaseCasing byamount low

Casing PressureTubing Pressure

(820-920)

When gas begins exiting through the choke, casing pressure may begin to change.

1

2 3

If casing pressure is allowed to drop below the original SICP another kick could be taken.

CHAPTER 77-12

string. Both pressures should be approximately the same, close to the original SIDPP value. If pressures are not close, another influx may have entered the well. Also, monitor for pressure buildup. This is a sign that another influx entered the well and is migrating.

The second option is to keep circulating. If possible, align to a smaller pit to continue circulating while pits will be weighted with a kill fluid. This technique may lessen the chances for sticking by keeping the fluid moving.

In either case, at this point a minimum of

two calculations need to be performed: the Kill Weight Fluid and the Strokes to Bit.

If bottomhole pressure is kept constant as kill fluid is pumped to bit, circulating pressure changes. In order to determine what circulating pressure to hold, a pressure chart of pump strokes vs. pressure should be prepared. This requires more calculations. Once kill fluid reaches the bit, circulating pressure at that point is held constant throughout remainder of the operation. For that reason, it is called the Final Circulating Pressure or FCP. Calculations

1: if casing pressure is allowed to

abruptly decrease2: so will drillpipe/

tubing pressure given lag time

3: to prevent this from happening, if

casing pressure begins to change quickly

adjust the choke4: if you react properly,

drillpipe/tubing pressure fluctuations

will be minimal.

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Pump

Rate, Stks/min

0

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

3400

520 520

1

2

3

4

If the well is to be shut in,

maintain casing pressure at least

equal to the original shut in

drillpipe/tubing pressure.

If bottomhole pressure is kept constant as kill

fluid is pumped to the bit, the

circulating pressure

changes.

WELL CONTROL METHODS7-13

for these are explained further in the Well Control Basics chapter. But, in this example, kill weight fluid will be 13.5 ppg (1618 kg/m³) and FCP 832 psi (57.37 bar). Fluid weight in the active pit needs to be increased to 13.5 ppg (1618 kg/m³) before the second circulation is started.

STARTING SECOND CIRCULATION

The start up procedure for the second circulation is identical to the start up procedure on the first, except for the numerical value pressure held on the casing. If no additional influx was taken, the SICP should essentially equal the original degree of underbalance (SIDPP). Once fluid weight has been increased, circulation should again start by maintaining casing pressure constant at planned values, 520 psi (35.85 bar) in this example. When the pump is at Kill Rate Speed (24 spm) and you are holding the casing pressure constant, you will be starting to displace the lighter fluid in the drill string.

It is necessary to follow a prepared pressure vs. stroke chart and make the adjustments as required. This safeguards against a secondary kick occurring while kill fluid is circulated. If a secondary kick had already occurred, correct pressures are maintained.

A second option is to hold casing pressure constant (only if certain that no influx is in the wellbore) until kill weight fluid reaches the bit. In this example, it takes 905 strokes. Drillpipe pressure will change as kill weight fluid displaces old fluid. Do not maintain drillpipe pressure constant at this time. It should be changing due to both friction pressure changes and the hydrostatic pressure changes as the original fluid is displaced by kill fluid. A prepared pressure vs. stroke (or volume) chart will indicate the appropriate value.

Maintain casing pressure as pump is brought online.

Rate, Stks/min

24Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

22

520

Rate, Stks/min

24Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

905

520832

Maintain proper pressure as kill fluid is

pumped to the bit.

A pressure vs. stroke chart will help safeguard against a secondary kick while kill fluid is circulated.

CHAPTER 77-14

KILL WEIGHT FLUID REACHES BIT

By the time the drillpipe is full of kill weight fluid (905 strokes), circulating pressure should have gradually changed from the original circulating pressure (commonly referred to as Initial Circulating Pressure, ICP) to the calculated Final Circulating Pressure (FCP). The pressure should be 832 psi (57.37 bar) in this example. Circulation continues maintaining FCP constant until the kill weight fluid reaches the surface. As kill fluid is pumped up the annulus, an increase in hydrostatic pressure causes the drillpipe pressure to increase. Choke adjustments are made as necessary to maintain FCP. Gradually, all the backpressure is removed as the kill fluid (increasing the annular hydrostatic pressure) is circulated up the annulus.

Once kill weight fluid reaches surface, well can be shut in for the third time. Drillpipe and casing pressure should be zero. If, after 15 to

30 minutes, the pressure is zero, the well may be dead. Open choke to see if there is any flow. If pressures are not zero, or if flow is detected, start circulating again. The problem may be that kill weight fluid is not consistent throughout the well. Another kick may be in the hole or perhaps an insufficient kill fluid was used. Even if the well is dead be aware that trapped pressure can exist under closed BOP. Always protect personnel when opening closed BOPs.

DRILLER’S METHOD KILL REVIEW

1. The well is shut in.2. Record Shut in Drillpipe/Casing pressures.3. Circulation is started by holding casing

pressure constant until pump is at kill rate.4. When pump speed is at kill rate, drillpipe

pressure is recorded and kept constant with choke adjustments as necessary. Drillpipe pressure should be the sum of SIDPP and kill rate pump pressure.

5. The drillpipe pressure and pump rate are kept constant until the kick is circulated out of the hole.

6. Then the well is shut in (or circulated) and the fluid weight increased.

7. A heavier fluid is prepared and circulation is started again. Either a pressure chart is followed or the casing pressure is kept constant (assuming no additional influx) until the drillpipe is full of new heavy fluid.

8. When the drillpipe is full of heavy fluid FCP should be maintained until the annulus has been displaced with kill fluid.

As the annulus fills with kill fluid, a trend of gradually adjusting the choke to maintain correct circulating pressures is noted. Casing pressure should decline to a negligible value providing additional influx was not taken.

Rate, Stks/min

24Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

4200

832

Rate, Stks/min

0Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

5400

It may take more strokes than calculated to get a consistent kill

fluid at surface, after which the pumps should be shut off, the well shut in and monitored for pressure

buildup. If no pressure buildup is seen, the well should be dead.

Always protect personnel

when opening closed BOPs.

WELL CONTROL METHODS7-15

WAIT AND WEIGHT METHOD

The Wait and Weight Method is a compromise of the various advantages and disadvantages inherent in the different constant BHP methods. The Wait and Weight Method kills the kick in the shortest time and keeps the wellbore and surface pressures lower than any other method. It requires good mixing facilities for weighting the fluid, full crews, and additional supervisory help. All are available on most marine rigs and on deep or geo-pressured land operations. For some companies this is the preferred method for killing a well.

In the Wait and Weight Method, the well is shut in after a kick. The stabilized pressures and kick size are recorded. The fluid weight is increased before starting to circulate, thus the name, Wait and Weight. Then the fluid is circulated through the well, maintaining the correct weight and pressures while killing the well.

In actual practice, it is rare to kill a well in one circulation because of inefficient fluid displacement in the annulus. This is true with any well-killing method.

Following is the Wait and Weight procedure:1. The well is shut in after the kick.2. Stabilized Shut In Drillpipe (SIDPP) and Shut In

Casing Pressures (SICP) recorded.3. Pits weighted to calculated kill fluid weight.4. When pits are weighted, circulation begins.5. A prepared circulating pressure chart is followed,

kill fluid circulated through well.

EXAMPLE PROBLEMOnce again we will use the example on

page 7-3. Well is shut in after a kick and the following information recorded. Kill Rate Speed = 24 spm

Kill Rate Pressure = 770 psi (53.09 bar)

Pump, 6” × 16” (152.4 mm × 406.4 mm) Duplex

Fluid Weight in Hole 12.5 ppg (1498kg/m³)

SIDPP = 520 psi (35.85 bar)

SICP = 820 psi (56.54 bar)

Strokes to Displace Drillpipe = 905 strokes

Strokes for Bottoms up = 3,323 strokes

Strokes for Total Circulation = 4,228 strokes

BRINGING THE PUMP ONLINEOnce kill rate speed is chosen, it should

not be changed. If pump speed is changed, then calculations such as initial, intermediate and final circulating pressure must be recalculated.

Rate, Stks/min

0Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

0

520 820

Hold casing pressure constant when bringing pump online.

It is rare to kill a well in one circulation, due to inefficient fluid displacement in the annulus.

CHAPTER 77-16

In this example, casing pressure is 820 psi (56.54 bar) and should be held while bringing the pump up to kill rate speed.

If the casing pressure is allowed to drop when bringing a pump up to speed, the bottomhole pressure will also drop. This may result in more kick influx. If the pump is brought on line and the choke is not opened, or operated quickly enough, then a rapid increase in pressure may lead to formation and/or well equipment breakdown.

Remember that casing pressure is backpressure. As soon as the pump is on line and running at kill rate speed, return casing pressure to its proper value.

STARTING CIRCULATION

When pump is up to kill rate speed and casing pressure is adjusted with choke to same pressure it had prior to pump start up, control is shifted to drillpipe pressure, at this time called Initial Circulating Pressure (ICP). It is merely the combination of the SIDPP and pump pressure at that speed. In the example above, the ICP is 1,290 psi (88.95 bar).

PRESSURE SCHEDULE

During the timeframe or number of pump strokes that the kill fluid takes to fill the drillpipe, drillpipe pressure should decrease from the Initial Circulating Pressure (ICP) to the Final Circulating Pressure (FCP).

Once pump is at planned circulating speed,Initial Circulating Pressure is noted.

8201290

Pressure needs tocome up 100 psi

Casing PressureTubing Pressure

(820)(732-832)

Give proper lag time and reevaluate.

It is your responsibility to maintain correct circulating pressure as the kill fluid is pumped to the bit (ICP and FCP) and up the annulus

(maintaining FCP). Pressure adjustments should be made accordingly.

832 830

IncreaseCasing byamount low

Casing PressureTubing Pressure

(820-920)(650)

Casing PressureTubing Pressure

Tubing Pressurewill increaseaftercasing pressureis increased

(920)(732-832)

If pressure falls below where it should be, an adjustment should be made. Determine how much pressure is needed

for the adjustment.

Adjust casing pressure by only that amount.

1

2

3

The initial circulating

pressure is the combination of

the SIDPP and pump pressure at that speed.

WELL CONTROL METHODS7-17

When drillpipe is full of kill weight fluid (905 strokes), the drillpipe pressure gauge should be showing Final Circulating Pressure (832 psi [57.37 bar]). Hold that pressure constant on drillpipe pressure gauge until kill fluid weight is circulated throughout the well and pumps are shut down after the kill operation.

PRESSURE ADJUSTMENTS

As the kick is being circulated, maintain drillpipe pressure according to planned pressure.

If the drillpipe pressure is incorrect, it must be adjusted to its proper value. To do this, determine the amount of pressure (high or low)

that must be corrected. Do not estimate. Small changes less than 50 psi (3.45 bar) typically are not considered unless low or excess pressures are critical.) The amount of pressure needed, must be added to or taken away from casing value (backpressure). Lag time should be taken into account for this pressure change to be reflected on drillpipe gauge. A rule of thumb for this lag time is to wait approximately two seconds per thousand feet of well depth. Many factors affect lag time, so only after an adequate amount of time should another correction be considered if a correction is not seen.

THE KICK AT SURFACE

On gas kicks, casing pressure first, and then drillpipe pressure (after the lag time for changes from one gauge to another) will start to decrease as the kick starts coming through the choke. The choke must be quickly adjusted to bring casing pressure back to the value it had before the gas hit the choke. It is advisable to keep a written record of the casing pressure as a reference. After the casing pressure is brought back to the proper value, and after the proper amount of time for pressure to stabilize throughout the system, control switches back to the drillpipe gauge for necessary pressure corrections. When the liquid following the kick goes through the choke, casing pressure will begin to increase. Again, adjust casing pressure to its last recorded value.

Casing PressureTubing Pressure

(832)

Casing PressureTubing Pressure

(832)

832 1300

As gas begins exiting through choke, casing pressure may begin to change.

Casing PressureTubing Pressure

(250)

Casing PressureTubing Pressure

(832)

So will drillpipe/tubing pressure.

Correct action prevents additional influx: if casing pressure begins to change, quickly adjust the choke.

If you react properly, drillpipe/tubing pressure fluctuations will be minimal.

Don’t let this happen: If casing pressure decreases,

2

3

4

5

1

When fluid following the kick goes through choke, casing pressure will begin to increase.

CHAPTER 77-18

In our example, we try to stabilize casing pressure at 1,200 psi (82.74 bar) to maintain drillpipe pressure at 832 psi (57.37 bar).

CONTINUE CIRCULATION

Once the kick is out of the well maintain Final Circulating Pressure, 832 psi (57.37 bar), until kill weight fluid reaches the surface.

SHUTTING BACK IN

If circulating pressures have not fallen below planned values and the kick has been removed, then the well can be shut in again. Drillpipe and casing pressures should be zero (give 15 to 30 minutes). If the pressure is zero, the well is dead. If it is not zero, start circulating again. The problem may be that the kill weight fluid density is not consistent throughout the well or maybe another kick is in the well.

If the well is dead, and BOP will be opened, be aware that trapped pressure can exist.

WAIT AND WEIGHT KILL REVIEW

1. The well is shut in after a kick and stabilized SIDPP, SICP and kick size information recorded.

2. The first calculation should be kill fluid density.

3. The rest of the worksheet is filled out while the fluid density in the pits is increased.

4. When ready to circulate, the pump is brought to kill rate speed while maintaining proper casing (backpressure) with the adjustable choke.

5. Maintain drillpipe (or tubing) pressure according to the pressure chart. All pressure adjustments begin with adjustment of casing (backpressure) from the choke. Every pressure adjustment should be recorded.

6. When heavy fluid reaches the bit, maintain drillpipe (or tubing) pressure at the Final Circulating Pressure until kill weight fluid returns to surface.

7. When gas, or liquid following the gas, starts to go through the choke, casing pressure must be stabilized at the last recorded value. Once pressures stabilize, then drillpipe (or tubing) pressure must be adjusted and kept at its proper value until the well has been killed.

As the annulus fills with kill fluid, a trend of gradually adjusting the choke to maintain correct circulating pressures is noted. Casing pressure should decline to a negligible value providing additional influx was not taken.

Rate, Stks/min

24Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

4200

832

Rate, Stks/min

0Pump

Pump PressureDrillpipe / Tubing / Standpipe

Choke PressureCasing / Wellhead

STROKES

Stroke Counter

5400

It may take more strokes than calculated to get a consistent kill

fluid at surface, after which the pumps should be shut off, the well shut in and monitored for pressure

buildup. If no pressure buildup is seen, the well should be dead.

When using the wait and weight method the first

calculation should be kill fluid density.

WELL CONTROL METHODS7-19

EXAMPLE PROBLEM

Note: The procedure outlined below is for use in straight holes where measured depths are essentially the same as true vertical depths. As with procedures for Wait and Weight and Driller's Methods, special treatment required by high angle holes can be found later in this chapter. The same well and kick data used in the previous examples for the Driller's Method and Wait and Weight Method will now be used in the following Concurrent Method.

1. The well has been shut in on a kick. Kick size, stabilized shut in drillpipe (SIDPP) and casing pressures (SICP) are recorded on a worksheet. At this time sufficient data is available to perform standard well control calculations.

Kill Mud Weight (KMW)ppg = (SIDPPpsi ÷ TVDft ÷ 0.052) + Original Mud Weight (OMW)ppg

= (520 ÷ 10,000 ÷ 0.052) + 12.5

= 13.5 ppg

Kill Mud Weight (KMW)kg/m³ = (SIDPPbar ÷ TVDm ÷ 0.0000981) + Original Mud Weight (OMW)kg/m³

= (35.85 ÷ 3048 ÷ 0.0000981) + 1498

= 1618 kg/m³

CONCURRENT METHOD

The Concurrent Method, which involves weighting up fluid while in the process of circulating out the kick, has also been called the Circulate and Weight Method or Slow Weight-up Method. It is a primary constant bottomhole pressure well killing method.

To execute the Concurrent Method some bookkeeping and calculations are required while in the process of circulating out the kick because there may be several different fluid weights in the string at irregular intervals. Because some of the calculations must be done on the fly, operational personnel have often opted for either the Driller’s or the Wait and Weight Method, dismissing the Concurrent Method as too complicated.

The following discussion and examples demonstrate how the necessary data collection and subsequent calculations can be simply accomplished. It is not such a formidable task as to cause a summary dismissal of the Concurrent Method from consideration. Normally the data keeping is centralized at the choke operator’s panel on the rig floor.

The necessary data collection can prove to be a valuable tool in that it can help organize the kill operations and lend confidence to those on the job. In short, they can know what is going on and feel in control of the situation. Two extra columns of recorded data are needed in addition to what is normally kept (namely, pressure changes required as fluid weight changes versus when the different fluid enters the string and will reach the bit).

Some operators require Concurrent Method data to be recorded even if they intend to use the Driller’s or the Wait and Weight Method. In this way, with the necessary data always available, the Concurrent Method can be resorted to in case of problems in the fluid weighting-up process without shutting down and then re-establishing circulation. (It is during start-up and shut-down that either lost circulation or secondary kicks are most apt to occur.) Therefore, in view of the potential advantages offered by the Concurrent Method, it is recommended that adequate records be kept during the process of circulating out any kick. A sample worksheet is used in this section and is offered as a guide.

Some operators require concurrent method data to be recorded even if they intend to use other methods.

CHAPTER 77-20

A. Initial Circulating Pressure (ICP)psi = SIDPPpsi + Kill Rate Pressure (KRP)psi

= 520 + 770

= 1290 psi

Initial Circulating Pressure (ICP)bar = SIDPPbar + Kill Rate Pressure (KRP)bar = 35.85 + 53.09 = 88.08 bar

B. Final Circulating Pressure (FCP)psi = KRPpsi × KMWpsi ÷ OMWppg

= 770 × 13.5 ÷ 12.5

= 832 psi

Final Circulating Pressure (FCP)bar = KRPkg/m³ × KMWbar ÷ OMWkg/m³ = 53.09 × 1618 ÷ 1498 = 57.34 bar

C. Drill string internal volume (usually expressed in pump strokes).

D. Circulating drillpipe pressure must be adjusted from the ICP to FCP as heavier fluid weights are pumped to the bit. Usually the pressure adjustments are calculated as psi per point of fluid weight.

Density/Pressure Correction Adjustment psi/pt = (ICP – FCP) ÷ ([KMW – OMW] ÷ 10)

= (1290 – 832) ÷ ([13.5 -12.5] ÷ 10)

= 45.8 psi/pt

Density/Pressure Correction Adjustment bar/10 kg/m³ = (ICP – FCP) ÷ ([KMW – OMW] ÷ 10) = (88.08 – 57.34)÷ ([1618 – 1498] ÷ 10) = 0.023 bar/10 kg/m³

Note: drillpipe pressure schedule can be expressed graphically as shown.

2. Circulation is started by pumping original fluid weight, taking returns through choke which is controlled so as to hold casing pressure constant as detailed in the Bringing the Pump Online portion of this chapter.

3. After the pump has been brought up to the desired kill rate with choke backpressure held at the stabilized shut in casing pressure, note and record the initial circulating pressure, ICP. Compare it with the calculated ICP and if there is a difference of more than 50 psi (3.45 bar), investigate.

4. Holding drillpipe pressure at established ICP and pump rate as in Step 3, start weighting up the active pits. As each point of fluid weight increase (one point equal one tenth of a pound per gallon) starts into drillpipe, the choke operator should be informed. The time and total pump stroke count along with new fluid weight going in is recorded on the data form. The number of strokes to get this heavier fluid to the bit is calculated (by adding total drill string internal capacity expressed in pump strokes to the total stroke count when the new fluid weight was started in) and recorded on the worksheet. When this heavier fluid reaches the bit the choke is adjusted by Density/Pressure Correction Adjustment amount, which in this example is 45.8 psi/pt (0.023 bar/10kg/m³).

Adjust circulating drillpipe pressure

from the ICP to FCP as heavier

fluid weights are pumped to

the bit.

WELL CONTROL METHODS7-21

5. The described choke adjustments in Step 4 are repeated as each point of fluid weight increase reaches the bit. After the final kill fluid is at the bit, the drillpipe pressure should be at the calculated final circulating pressure which should be maintained until kill weight fluid is recovered in the returns at the surface. With the well full of kill weight fluid, check to see if the well is dead.

Using the Concurrent Method as outlined will result in some extra backpressure above that which is required to balance formation pore pressure. This is because no decrease in drillpipe pressure is allowed for the heavier fluid until it reaches the bit. In most cases, this should not be a problem because it only amounts to 100 psi (6.89 bar) or less. However, if fluid weight can be increased rapidly, or in the case of deep wells, it may be desirable to control the rate of fluid weight increase to limit the amount of backpressure.

In the example problem, if all increments of required weight increase were inside the string before a pressure adjustment decrease was due, the excess backpressure would amount to approximately 275 psi (18.96 bar). One way to prevent this excess backpressure would be

to only weight up part way, say to 12.8 ppg (1534kg/m³), then hold the weight going in at 12.8 ppg (1534 kg/m³) until it clears the bit. The appropriate circulating pressure should then be 1,060 psi (73.87 bar) and excess backpressure would be limited to less than 100 psi (6.89 bar).

The advantages of the Concurrent Method are summarized below.w Circulation may begin immediately

after stabilized surface pressures have been determined. This may keep the pipe free as well as prevent the need for employing the Volumetric Method to avoid excessive surface pressure build up due to gas migration that might occur during the time required to weight up the fluid pits for the Wait and Weight Method.w Circulation may continue throughout

kill operation since no shut in periods are required for fluid pit weight up. This can be beneficial in those wells where circulation helps keep the pipe free and helps prevent the hole from packing off around the drill string.w There are no planned pump shut-downs

and start-ups (as in other methods) thus reducing the likelihood of a secondary kick or of exerting excessive backpressure that could result in lost circulation.

1200

1000

1300

1100

800

900

DRILL PIPE PRESSURE SCHEDULE

New Mud Wt. In. ppg

FCP = 832

New Mud Wt. In @ Strokes

New Mud Wt. @ Bit - Strokes

DP Press - New Mud @ Bit - psi

ICP = 1290

12.50

9051290

12.650

9551244

12.7

1198

12.829011951153

12.9

1107

13.0

1061

13.1530

14351015

13.2770

1675969

13.3

924

13.4890

1795878

13.510101915832

Pressure chart for the concurrent

method

Using the concurrent method may result in extra backpressure above that required to balance the formation.

CHAPTER 77-22

w The Concurrent Method provides a systematic method of dealing with fluid weight variations, either heavier or lighter, without interrupting circulation. These techniques can be applied during the Driller’s or Wait and Weight Methods as a way of fine-tuning the amount of

backpressure to be held, ensuring that no additional formation fluid feeds in, or that no formation break down occurs. This could be especially beneficial on those rigs with limited fluid mixing capability and the fluid weight increase is 1.0 ppg (119 kg/m³) or more.

Well Control Operation Data Sheet STROKES THEORETICAL ACTUAL PRESSURE ADJUSTMENT ACTUAL FLUID IN FLUID OUT CHOKE POSITION PIT TIME OR VOLUME CIRC. PRESS. CIRC. PRESS. +/- PSI @ STKS ADJ. PRES. AFTER CASING PRESS. WT. VIS WT. VIS % OPEN LEVEL REMARKS

0200 Shut In 520 820 12.5 48 12.5 5555 0 +16 Took kick, stabilized SI pressures

0205 50 1290 820 12.5 50 12.5 57 40 +16 Start circ thru choke @ 24 spm

0210 170 1290 -46 1075 1244 820 12.6 52 12.5 60 40 +16 12.6 start in hole

0215 290 1290 -92 1195 1152 830 12.8 54 12.5 58 40 +16 12.8 start in hole

0225 530 1290 -136 1435 1016 840 13.1 56 12.5 58 38 +17 13.1 start in hole

0235 770 1290 -46 1675 970 850 13.2 58 12.5 60 36 +18 13.2 start in hole

0245 890 1290 --92 1795 878 870 13.4 58 12.5 60 36 +19 13.4 start in hole

0250 1010 1290 -46 1915 832 870 13.5 56 12.5 58 35 +20 13.5 start in hole

0253 1075 1244 860 13.5 54 12.5 58 40 +22 1st DP press. adj. at 12.6 @ bit

0258 1195 1152 860 13.5 54 12.5 6 42 +23 2nd DP press. adj. at 12.8 @ bit

0303 1435 1016 865 13.5 52 12.5 54 44 +24 3rd DP press. adj. at 13.1 @ bit

0318 1675 970 870 13.5 52 12.5 54 45 +26 4th DP press. adj. at 13.2 @ bit

0328 1915 878 870 13.5 52 12.5 54 46 +28 5th DP press. adj. at 13.4 @ bit

0333 2500 832 880 13.5 54 12.5 54 50 +29 6th DP press. adj. at 13.5 @ bit

0400 2750 932 +136 3405 900 13.2 54 12.5 54 55 +31 Barite line plugged. 13.2 In.

0438 3300 832 -136 3655 1250 13.5 54 0 25 +80 Mud In back to 13.5

0500 3405 968 200 13.5 54 12.5 50 70 0 12.5 ppg @ choke

0505 3655 832 350 13.5 52 12.5 60 65 0 DP Press adjust for 13.2 @ bit

0515 3810 832 150 13.5 52 12.5 50 85 0 13.5 back at bit

0522 120 13.5 52 100 0 13.5 back @ surface

Recording information is necessary in the concurrent method.

WELL CONTROL METHODS7-23

DEVIATED/HORIZONTAL CONSIDERATIONS

Technology improvements in tools, instruments and techniques have made horizontal drilling routine in some areas. However, for many years well control problems associated with high angle, directional wells were largely ignored. Although the physics of well control don’t change, there are considerations when dealing with kicks in highly deviated wells.

Considerations for constant bottomhole pressure methods in high angle wells are:

w Friction pressure calculations based on measured depths

w Hydrostatic pressure calculations based on true vertical depths

w Selection of best well control method.

The Wait and Weight Method uses a table of calculated values to predetermine changes in the drillpipe gauge pressure as kill weight fluid is pumped from the surface to the bit. These changes are caused mainly by two variables:

w Gaining kill weight fluid down the string, which will decrease pressure.

w Additional frictional pressure (resistance to flow) gained in the string due to circulating a heavier fluid.

In a vertical well, basic calculations are required to plot decreased pressure values and pump strokes when making a pressure schedule. Two assumptions are made. The first is that the length of the column of Kill Weight Mud increases the same amount for each incremental increase in pump strokes. This is correct if the string has no changes in internal diameter (ID) of tubulars, drillpipe, HWDP and collars. The second assumption is the true vertical height of the column of kill weight fluid increases the same amount for each incremental increase in pump strokes. This is true if the well is vertical and the first assumption is correct.

If standard Wait and Weight killsheets are used on highly deviated wells, the calculations could result in imposing higher backpressure than required to balance formation pressure. In some cases this may be as much as 500 psi (34.48 bar). On the standard Wait and Weight killsheet, calculations predict drillpipe pressure from ICP to FCP based on pump strokes (volume at measured depth), treating the gain in hydrostatic and friction as a simple linear relationship. That is to say, the pressure change stays constant for each increment of volume pumped from the surface to the bit.

Water

Sea Floor

Production Zone

MD for Friction Pressure Calculations

TVD for Hydrostatic Pressure Calculations

Vertical

Directional

Horizontal

ICP

FCP

HorizontalPoint

KickoffPoint

Straight versus high angle well pressures

Calculations on a standard wait and weight killsheet could result in higher backpressure than required to balance the formation.

CHAPTER 77-24

On highly deviated and horizontal wells the relationship of hydrostatic and friction must be treated separately, with friction based on measured depth, and hydrostatic on TVD. It is possible to gain full effects of hydrostatic pressure with several hundred strokes still left to pump kill fluid to the bit (and its resulting frictional increase). If this extra pressure is not acceptable, a pressure schedule compensating for the well’s directional aspect should be used.

A highly deviated or horizontal well’s pressure schedule will only have a linear pressure

schedule in the vertical portion from surface to the kick off point or KOP. Then from the KOP to the bit, calculations are based on directional (TVD and MD) data. The horizontal well’s pressure schedule has a linear pressure change for the vertical section, a schedule for the radius from the KOP to horizontal, and a linear pressure chart from the horizontal point to the bit. The calculations get complex, using several sets of directional data and measured lengths.The necessary calculations follow:

Repeat #3 for several equal lengths along curve of directional well to plot what circulat-ing pressure should be. (This also works for vertical, horizontal and coiled tubing depths or lengths).

You may notice when the horizontal length is significant (as long as/longer than well's

vertical portion), that the CPKOP may be below the FCP value, and then increase to the FCP due to friction gain. This is because of the increase in hydrostatic pressure over the TVD, without the addition of friction from the KOP to the bit over the horizontal section.

1. Calculate the Increase in Circulating Friction Gradient (psi/ft or bar/m)

Increase in Frictionpsi/ft = (FCPpsi – Original Kill Rate Pressurepsi) ÷ Length of stringft

Increase in Frictionbar/m = (FCPbar – Original Kill Rate Pressurebar) ÷ Length of stringm

2. Calculate the Gain in Hydrostatic Pressure Gradient (psi/ft or bar/m)

Gain in Hydrostaticpsi/ft = SIDPPpsi ÷ TVDft of well

Gain in Hydrostaticbar/m = SIDPPbar ÷ TVDm of well

Or,

Gain in Hydrostaticpsi/ft = (KWMppg – OWMppg) × 0.052

Gain in Hydrostaticbar/m = (KWMkg/m3 – OWMkg/m3) × 0.0000981

The above calculation assumes rounding up of the kill fluid or use of a heavier than actual calculated kill fluid.

3. Calculate the Circulating Pressure (CP) at a given depth (requires both MD and TVD depths) CP = ICP + (Increase in Friction × MD) – (Gain in Hydrostatic × TVD)

CPpsi = ICPpsi + (Increase in Frictionpsi/ft × MDft) – (Gain in Hydrostaticpsi/ft × TVDft)

CPbar = ICPbar + (Increase in Frictionbar/m × MDm) – (Gain in Hydrostaticbar/m × TVDm)

On highly deviated

horizontal wells the relationship

of hydrostatic and friction

must be treated separately.

WELL CONTROL METHODS7-25

From this discussion, questions arise. Are the extra steps necessary and is the Wait and Weight Method the optimal choice? If the pressure difference between strokes to the kick off point on a standard pressure schedule and the pressure calculated at CPKOP is more than 100 psi (6.89 bar), then it is probably justified. If it is less than 100 psi (6.89 bar), it may be better to just use the standard method of calculating the pressure schedule, unless you are close to MASP (Maximum Allowable Surface Pressure), or are having lost circulation complications. Factors such as kick size, MASP, and SICP may dictate that pressures be plotted accurately and adhered to closely.

The chart below shows the differences if a standard or straight well pressure plot (ICP to FCP) is followed versus pressure required by calculations. In this example, special deviated pressure change calculations are not needed when the average angle is less than 60° and/or the kick intensity is less than 1.0 ppg (120

kg/m³). Generally, the higher the angle and/or increase in kill weight fluid, the greater is the necessity for a detailed pressure chart to prevent overpressuring the well.

Following is a simple method to determine the pressure decrease necessary to balance or slightly exceed formation pressure while pumping the kill fluid from the surface to the bit in a deviated well. The graphical solution offered on page 143 simplifies what otherwise would require numerous detailed calculations.

First it is necessary to plot ICP and FCP vs. strokes (or volume) on graph paper. Next, determine the greatest discrepancy. This will occur in the vicinity of the end of the angle buildup. Calculation #3 on page 144 will predict the CP. From the MD, the volume and strokes can be determined and plotted. Then the difference in pressure can be determined.

A major advantage of the Wait and Weight Method is that it results in lower annular surface pressures in straight holes when kill

Kicks size, MASP and SICP may dictate that pressures be plotted accurately and adhered to closely.

COMPARISON OF MAXIMUM PRESSURE DISCREPANCYVS STRAIGHT AND HIGH ANGLE WELL PRESSURE PLOTS

CALCULATED CIRCULATING PRESSURE AT EOB TVD KICK AVERAGE STRAIGHT HOLE DEVIATED HOLE IF STRAIGHT HOLE MD AT EOB INTENSITY ANGLE METHOD PT. A METHOD PT. B METHOD, A – B FEET FEET PPG DEGREES PSI PSI PSI

12,000 7,654 1.0 60 878 825 53 5,786 1.0 75 804 721 83 3,910 1.0 90 738 622 116 7,654 2.0 60 1,156 1,051 105 5,786 2.0 75 1,008 841 167 3,910 2.0 90 876 643 233 7,654 3.0 60 1,435 1,276 159 5,786 3.0 75 1,212 961 251 3,910 3.0 90 1,014 659 35515,000 9,154 1.0 60 959 900 59 6,563 1.0 75 828 757 95 3,910 1.0 90 738 583 155 9,154 2.0 60 1,319 1,200 119 6,563 2.0 75 1,104 914 190 3,910 2.0 90 876 635 241 9,154 3.0 60 1,679 1,500 179 6,563 3.0 75 1,356 1,071 285 3,910 3.0 90 1,054 652 402

CALCULATIONS USE 11.5 PPG ORIGINAL FLUID, 3°/100 FT RATE OF ANGLE BUILD, 2,000 FT KOP

CHAPTER 77-26

weight fluid comes up the annulus and before a gas influx reaches the surface. This results in a gain of annular hydrostatic pressure and therefore requires less surface pressure (choke backpressure) in order to balance formation pressure. In horizontal, or very high angle wells, the effect of hydrostatic pressure gain is not realized until the kill fluid starts up the vertical portion of the hole, that is, above the Horizontal Point (HOP). If the drill string volume plus the annular volume from TD to the HOP is greater than the annular volume from the HOP up to the surface, then the influx will be circulated out before heavier fluid starts killing the annulus. Surface pressures will have already reached their highest value (as in the Driller’s Method).

In this case, the primary benefit from the Wait and Weight Method is the chance to kill a well in one circulation. Other benefits, such as lower surface pressure than in the Driller’s Method may not be fully realized or could be totally absent. The Driller’s Method should be given consideration as a viable option since kill weight fluid is not in the vertical portion of the well before the influx in circulated out.

The Driller’s Method is well suited for horizontal well control. It offers simplicity over other methods (especially, in light of the previous discussion on how to calculate the pressure change schedule in the Wait and Weight Method). It also minimizes shut-in time and removes the influx in a shorter time than the Wait and Weight Method, with no complex pressure charts to follow.

Regardless of which well control circulating method is used (W&W, Driller’s, Concurrent), or if the deviated well application is used, the ICP and FCP would be the same. The difference between vertical well control calculations and deviated/horizontal wells occurs between ICP and FCP, with the greatest discrepancy at the end of angle build-up. The deviated/horizontal well calculations will closely approximate circulating pressures that will occur during the second circulation of the Driller’s Method.

High angle and horizontal wells can exhibit unexpected behavior after the kick has been circulated out. A reason for this is hole washout

or enlargement in shale sections, while sand sections may be relatively in gauge (due to fluid cake build up on the face of permeable sands). These irregular washout sections can result in pockets of gas accumulation from circulating out the influx. At the slower circulating rates gas migrates into these sections. Once the well is thought killed, it is common to open the BOPs and circulate bottoms up to clean out the well. Typically, this is with higher circulating rates (e.g., turbulent flow). This may provide an efficient job of sweeping the gas out of the washed out pockets. The gas will freely expand and soon show at surface as:

w Increase in fluid return rate on flow sensor

w Pit gain indicated by PVT

w Severely gas cut fluid

Obviously, under these conditions, the well should be shut in again and circulated out through the choke and fluid-gas separator. It is possible that this gas will be enough to induce another kick from the formation if not shut in and controlled. Since the fluid is already at kill weight the Driller’s Method should be used to finish circulating out. Resist the temptation to increase fluid weight. Another circulation at higher pump rates may be required to finish cleaning out any gas pockets.

In horizontal well control, consideration must be given to the differences between TVD, MD, and how the horizontal section will affect kick detection and well control efforts and calculations as illustrated above. These include:

w With more producing formation exposed, the potential flow capabilities increase tremendously. This can result in larger influxes, increased risks of lost circulation and surface equipment complications.

w Kicks are harder to detect in the horizontal portion when they first occur. The only defense may be in the vertical portion of the well. Well conditions must be monitored every minute, when in possible high pressure zones. The driller needs to be alert for drilling breaks, pump pressure changes, etc. The amount of influx may be much greater than it seems at first.

The driller’s method is well

suited for horizontal well

control.

WELL CONTROL METHODS7-27

w The difference between SIDPP and SICP will be minimal, unless the influx size is greater than the horizontal volume, or if the influx extends to the vertical portion.

w There is the possibility of the kick going into weak spots or fractures along the horizontal wellbore, not giving reliable pressure readings on surface. When well is shut in, monitor it for fluctuations or a decrease in SIDPP or SICP. Lost circulation right after a kick is possible and it could lead to an underground blowout and sticking of pipe in the horizontal section.

w Gas may not migrate, or migrate slower in the horizontal section than the vertical or curved section. Also, when circulating the influx, as long as it remains in the lateral section, no expansion should occur (providing bottomhole pressure remains constant). Once in the vertical section, expansion and pressure adjustments to maintain constant bottomhole pressure will become more frequent.

w In horizontal section, gas can stay on upside or top of the hole, especially if the section has any pockets to trap gas in the upper portion. This gas may not be circulated out, and can be a problem while tripping and pulling this gas into the vertical portion.

w The order of the string in a horizontal well may be reversed from conventional drilling. This is to say, the collars are near the surface, HWDP (heavy weight drillpipe) below the collars, and drillpipe and tools beneath the HWDP. All of this affects annular volumes and velocities while circulating an influx, with higher velocities (and expansion potential).

w Gas may be more strung out due to the horizontal portion and hole washout. However, once in the vertical section, especially around the collars, the influx will elongate due to the smaller annular clearances. The velocity through the choke can increase rapidly, increasing pressure at the choke. The choke may have to be adjusted quickly to maintain proper bottomhole pressure, and to minimize pressure on the casing shoe and weaker formations.

w The proper depth is important when calculating kill weight fluid. Although the well may have a measured depth (MD) several thousand feet longer than the true vertical depth (TVD), TVD is still used to calculate kill weight fluid. Also, MD is used to calculate volumes for either well type. Though this seems simple, simple things have resulted in many blowouts.

w If conditions such as lost circulation or other well kill related problems occur, it may be necessary to stop the kill and reevaluate the best method to kill the well. Safety of personnel should always be the most important part of a well kill planning and execution process.

w Underbalanced Drilling/Producing While Drilling (UBD/PWD) wells are allowed to flow while drilling. Killing of these wells may damage future production. However, the well can be shut in and kill weight fluid calculated. If the well has vertical fractures the well could still flow, as the kill fluid might have gone into a fracture that was empty or depleted.

Gas Pockets

Cutting Buildup

The horizontal well can create complications.

Gas may not migrate or may migrate slower in the horizontal section.

CHAPTER 77-28

UNDERBALANCED DRILLING (UBD)/ PRODUCING WHILE DRILLING (PWD)

UBD or PWD deviates from standard well control methodology because it relies heavily on surface equipment to maintain control of the well rather than the hydrostatic pressure of the fluid column. The well is allowed to flow, and that flow is tolerated to a certain extent. It must be noted that this technique is not suitable for all areas. Wells with a high flow potential, or high pressures and temperatures should be drilled with conventional techniques and well control procedures. UBD/PWD has several advantages.

w It provides production and reservoir

information while drilling.

w It minimizes potential hydrostatic pressure

or drilling fluid damage to the formation.

w It reduces or eliminates complications in

potential lost circulation zones.

The basis for UBD/PWD or drilling while the well is flowing was founded on air drilling techniques. In UBD/PWD underbalanced conditions (i.e., a combined hydrostatic and circulating pressure less than the formation pressure) are used. In some areas, this requires low-density liquids such as water, brines, or oils. In subnormally pressured formations gas (usually nitrogen) can be injected into the circulating system to reduce the effective hydrostatic pressure.

Drilling continues when a producing formation is entered, unless pressures or production rates become too great. At this point the well is usually killed using conventional well control techniques.

With the introduction of UBD equipment, drilling while the well is flowing (hence, PWD) became a reality for many horizontal wells. Much of the UBD/PWD technology is the same as the air drilling techniques, with the exceptions of higher pressure rated equipment and production/storage facilities on location.

DRILLING WITH NO RETURNS

Drilling with no returns is common in many areas such as the Austin Chalk because of formation fractures. In some areas, the fractures are so large that drilling two or three days with no returns or limited returns may be routine. The use of field brine appears to be the fluid of preference as it can be dumped into the reserve pit or the fluid tanks. If the brine water gets low the drilling and pump rates are slowed until adequate water can be obtained and normal drilling resumed.

MUD-GAS SEPARATOR INADEQUATE

The gas busters (mud-gas separators) on UBD/PWD wells sometimes become overloaded and blow by into the separation tanks. Choke size should be slowly decreased until gas quits coming out of the separator flowline. If it appears to be getting out of hand, well may be shut in and the decision made to kill the well.

SPREAD THE KICK

Spread the kick is a technique that keeps the well under control by drilling while flowing in the Austin Chalk. It was discovered that most wells were ruined after a kick was encountered, because the accepted way was to pump 10 ppg (1198 kg/m³) brine water down the hole to control pressure. It was found that every other fracture in the Austin Chalk area seemed to be depleted or underpressured. By drilling ahead, not using any kill weight fluid and controlling the formation by using backpressure with the choke, the well could be drilled to the next fracture. Once in the next fracture, which is presumably underpressured, the present pressure invades the depleted zone, resulting in a pressure reduction on surface. This technique has become common in some areas that have this type of vertical fracturing. This is a technique that works in some, but not all areas. Well control plans need to be area and well specific.

UBD equipment has made

drilling while the well is flowing a reality for many horizontal wells.

WELL CONTROL METHODS7-29

PRODUCING TOO MUCH OIL

Producing too much oil or gas on a UBD/PWD well can lead to complications, but this seldom is a problem. The well can be shut in, until more storage can be brought to location, or tankers can haul out the oil to market.

LEAKING ROTATING HEAD

A leaking rotating head is serious and must be repaired. The well may or may not be shut in. If it is not shut in, drilling should be halted until the preventer is repaired. (Pumps may be left running at the operator’s discretion.) The annular preventer or pipe ram (or both) should be closed, and pressure relieved from the area between the rotating head and closed BOP. The rotating head element is then replaced. Remember the well is producing and pressure is present under the closed BOP. Flammable fluids, the possibility of the closed BOP leaking and the chance of an explosion exist.

DRILL THROUGH ANNULAR PREVENTER

If the pressure limitation of the rotating head is reached, drilling can continue, using the annular preventer in the same fashion as the rotating head. Keep pipe well lubricated, and the closing pressure at the minimum necessary to obtain a seal. However, remember that the useful life of the packer will decrease and if it fails, the remainder of the BOP stack must be adequate to provide necessary well control.

TRIPPING OUT

There are basically two options if the string must be tripped on a UBD/PWD well. The first is the use of a snubbing unit to strip the pipe out under pressure and/or while the well is still flowing. The second option requires that the well is static. This necessitates that the pipe be stripped into the curved or vertical section, and the well circulated with a fluid of sufficient density to keep the well from flowing.

The yellow area is the pay zone. Horizontal wells cut more pay, one good reason for horizontal drilling.

Producing too much oil or gas on a UBD/PWD well can lead to complications.

CHAPTER 77-30

If the well kicks while tripping out from this point, stripping back to bottom of casing and circulating a heavier fluid may be tried. Another technique is to bullhead heavy fluid to bottom of casing just above open hole, then check for flow. If hydrostatic column in casing is adequate to stabilize well, tripping may continue. If well cannot be stabilized, conventional well kill techniques may need to be applied.

PIPE CONNECTIONS

If well is allowed to flow, backflow protection devices must be used. Often a series of backpressure valves (BPVs) are used. If one fails, there is another to prevent venting of formation fluids through pipe to the rig floor.

Pressure build-up and surges may occur during a connection and they may exceed safe design limits. Keep connection time to a minimum. If only one BPV is used, the joint or stand to be made up should have a safety valve in place until pipe can be stabbed and made up.

INJECTION TECHNIQUES

In some regions it is common to inject gas, foam or lightweight fluid to reduce hydrostatic pressure for high penetration rates and/or to prevent formation damage. This may be done by injecting down the drillstring, into casing, or down parasitic tubing strings run with casing string. Injection rates may be varied to control pressure and flow rates at surface.

UBD/PWD EQUIPMENT

The basic equipment consists of a mud-gas separator, a gas flare line, flow lines, separation tanks and pumps to move oil to frac or storage tanks and circulate fluid back to tanks for reuse. A Compressed Natural Gas (CNG) unit may be used to collect gas instead of flaring.

Lighting is important at night on a land location. The derrickhand usually works the separation tanks, and needs good tank lighting.

UBD/PWD equipment can be assembled with elaborate features including shale shakers, sand controllers, gas separators, multiple flare lines, automatic floats and indicators on tanks and warning lights. State and federal regulations may dictate minimums, but safety dictates maximum equipment arrangement.

UBD/PWD equipment often makes a land location look like a miniature refinery. When an operator builds a location or specifies equipment layout, consideration must be given to prevailing winds when locating flare lines. Tanker truck access is important – a turnaround must be built on location for access to fluid and oil storage tanks. All weather roads must be in place when well goes horizontal. In some areas, this may not be a serious concern. The drawing below is a standard and a UBD/PWD location Layout.

In some regions it is common to

inject gas, foam or lightweight

fluid to reduce hydrostatic

pressure for high penetration.

WELL CONTROL METHODS7-31

ROTATING/CONTROL HEADS

The rotating head was originally designed for air drilling with operating limits in low pressure ranges (less than 500 psi [34.48 bar]). If pressure increased higher, the operator would have to operate through the annular. With the increase in UBD/PWD horizontal drilling, a need for rotating or control heads that could control pressure while drilling underbalanced was created. Several accidents have occurred with the rotating head by putting too much pressure on the rotating head rubber. This necessitated the improved rotating and control heads of today, several models of which hold up to 5,000 psi (344.75 bar) static pressure.

The following are special considerations for optimum rotating and control head performance. When ordering this equipment, the Kelly type should be specified. It is generally recommended to keep at least one extra set of sealing elements on location at all times in the event that one or more needs replacing. It is recommended that the closing unit for the rotating head be independent of primary closing unit.

KELLY TYPES

w Tri-Kelly – The Tri-Kelly is perhaps the optimum kelly type because it has three sides and a rounded smooth corner, which yields longer stripper life. w Hex-Kelly – The Hex-Kelly is more

common than the tri-kelly. However, the sharp corners do slightly cut the stripper rubber, and shorten the wear life. w Square-Kelly – The Square Kelly is perhaps

the least desirable. Field experience has shown that it is hard to get a good seal using this shape with a rotating head.

STRIPPER RUBBERS

w Natural stripper rubbers are used for air, gas, and water based fluid drilling. They are available in high or low-pressure design. w Polyurethane stripper rubbers are available

for oil based fluid drilling.w Other elastomeric compounds may

be custom designed based on operating conditions and requirements.

PRESSURE TESTING

Pressure tests should be performed following the testing procedure from the rotating head manufacturer.

DOUBLE ANNULAR

When horizontal drilling began, rotating heads were not adequate to handle the pressure, so operators started using the double annular. With the development of high pressure rotating heads, the use of this preventer is on the decline. The double annular also is restricted by the height of the substructure on many rigs.

SPECIAL CONSIDERATIONS – HIGH ANGLE/ HORIZONTAL AND UBD/PWD WELLS

The operator’s representative should have all the rig crews trained before drilling the curve. They need to understand that the well may be shut in at any time, and it often looks more serious than it really is. Surface equipment should be tested prior to drilling the curve (in addition to normal testing), and the crew must understand that the blowout prevention equipment will work. It is good to show them the test report to build their confidence. Make sure all know their stations and responsibilities.

Tourly safety meetings should be held. The crew assignments for horizontal wells are similar to vertical wells in most safety operations, and station bills during a kick will be the same. For example, on many UBD/PWD wells, the operator’s representative is usually on the choke, the driller is on the brake, and the toolpusher is on the accumulator controls. The derrickhand is on the separation tanks to pump oil and fluid when necessary, and to report any problems to the driller. The motorman position is typically at the pumps and the kill fluid valve in case of an emergency. Floorhands must assist the derrickhand or motorman, look for leaks around the blowout prevention equipment, and report to the driller. If there is a mud engineer on location, he can assist the derrickhand in switching oil and drilling fluid using the pumps.

Too much pressure on the rotating head rubber may cause accidents with the rotation head.

CHAPTER 77-32

Make sure emergency numbers are posted in several locations and that everybody on location knows where they are.

It can be a terrifying experience when the first kick occurs with oil and gas flowing to surface, the rig shaking, flowlines bouncing up and down, and a flare burning in the air. Proper training can be the best preparation for this kind of experience.

On UBD/PWD wells, it is recommended in the horizontal portion to have two operator’s representatives working twelve-hour shifts. This is because flowing wells require additional supervision on the floor most of the time.

PRESSURE CHART MODIFICATIONS

The pressure chart calculations and treatment from ICP to FCP are an oversimplification of what is really happening to circulating pressures. In most cases this results in holding slightly higher pressure against

formation as kill fluid is pumped to the bit. Factors not usually taken into account on well kill worksheets are:

w ID differences for circulating friction (BHA, tapered strings, etc.). A small difference in diameter may make a large difference in friction.

w Pressure change calculations assume that each stroke moves the fluid the same length. If the BHA has a smaller ID than the pipe above, each stroke of the pump will displace fluid a greater length than if it were in the larger diameter pipe.

w Friction through motors, tools and bit. The frictional pressure losses across downhole motors and logging tools usually are well documented at optimum pump rates, but not necessarily so at (slow) kill rate speeds. Calculations may be made to negate these pressure losses, resulting in less psi/ft (bar/m) decrease as kill fluid is pumped.

1300

1200

1100

1000

900

800

0 200 400 600 800 1000 1200

A

B

C D

D

A

B

CC

Kill mud @ top of drill collars

Kill mud @ top of Bit

After kill mud is going through bit

to kill mud filling annulus

PUMP STROKES

FCP 832psi

DP Pressure Schedule by standard method(ICP-FCP) / Total Strokes to bit = psi/100 stks

100

Min. CDPP to balance FBHPAdjusted by:

CDPP=ICP-Hydrostatic Gain + Friction Gain

ICP 1,290psi

PUM

P PR

ESSU

RE

Max Disparity @ B = 44psi (Excess back pressure)

ICP = 1290FCP = 832�A = 814B = 788C = 831�D = 833�

StandardICP to FCP plot

versus actual pressure

distribution

Make sure emergency

numbers are posted in

several locations.

WELL CONTROL METHODS7-33

w Hole inclination. As discussed in the section on Horizontal and Deviated wells, increase in friction and gains in hydrostatic pressure are not linear (psi/ft [bar/m]) in these conditions.

w Annular friction losses. Traditional thinking puts annular friction at slow circulating rates at minimal values. These are usually dismissed. However, in smaller diameters, this may be several hundred psi (bar) and should be taken into account. This may be treated similarly to choke line friction on subsea BOPs, that is to say, the choke pressure is adjusted lower by the amount of friction.

w MWD/LWD technologies. Several arrays of instruments transmit downhole pressure while circulating. The difference between hydrostatic and reported circulating annular pressures gives actual annular friction loss. This is treated as above.

w Fluid properties. Frictional properties vary depending on the type of fluid, circulating time and velocity.

It should be obvious that if all the above is taken into account, a sophisticated electronic spreadsheet may prove more beneficial than typical worksheet calculations. Well specific spreadsheets taking the above into account should be considered on critical applications or when losses may be anticipated.

COILED TUBING CONSIDERATIONSThe well control techniques and principles

discussed in this chapter are usually not limited by unit type. Depending on well geometry and unit type, modification to calculations may not be needed. However, this is not the case with coiled tubing units with pipe on the reel on surface. If the Wait and Weight technique is employed, the formula to determine circulating pressure at any point must be applied. It may take several barrels (m³) or several hundred strokes pumped before the gain in kill fluid hydrostatic begins to be pumped vertically. This results in an increase in circulating friction as it is pumped in the reel hub and throughout the rest of the coiled string. Hydrostatic pressure gain does not occur until the kill fluid is

pumped vertically down the coiled tubing in the well. The following calculation may be used (as previously discussed) to calculate circulating pressure at various points.

Circulating Pressure = ICP +(Increase in Frictionpsi/ft or bar/m × MD) –(Gain in Hydrostaticpsi/ft or bar/m × TVD)

VOLUMETRIC METHODOF WELL CONTROL

The Volumetric Method can be described as a means of providing for controlled expansion of gas during migration. It can be used from the time the well is shut in after a kick until a circulating method can be implemented and can be used to bring a gas kick to the surface without using a pump. As with other constant bottomhole pressure methods, the Volumetric Method is based on the principles of the Gas Law. It trades pressure for volume at the appropriate time to maintain a bottomhole pressure that is equal to, or slightly higher than, the kicking formation pressure without exceeding the formation fracture pressure.

The Volumetric Method is not intended to kill the kick, but rather it is a method of controlling the downhole and surface pressures until killing procedures can be started. In cases of a swabbed in kick, it can be used to bring the influx to surface. And, providing no additional influx allowed in, volumetric techniques can be used to replace the gas with fluid to bring the well back into hydrostatic pressure control.

The effects of gas migrating up the hole have been previously discussed in this manual in Kick Theory. The primary concern is that migrating gas can cause pressure increases at the surface, downhole and throughout the well that could in turn cause surface equipment or casing failure, or formation break-down with resulting lost returns and possibly an underground blowout. The Volumetric Method reduces these high pressures by a systematic bleeding of fluid to allow expansion of gas.

The volumetric method allows controlled expansion of gas during migration.

CHAPTER 77-34

There are several situations in which the Volumetric Method may be applicable.w String is out of the holew Pumps are inoperative due to mechanical

or electrical malfunctionsw String is pluggedw A shut-in period such as weighting up

drilling fluid prior to using Wait and Weight, or repairs to surface equipment (choke, piping, fluid mixers, etc.)w A washout in the drillstring that prevents

displacement of the kick by one of the circulating methodsw String is a considerable distance off bottom

and the kick is below stringw Casing pressure develops on a production

or injection well because of a tubing or packer leakw During stripping or snubbing operations.

The need for the Volumetric Method can usually be determined from casing pressure behavior as early as a few minutes after a kick is shut in. If casing pressure does not increase after about 30 minutes, there is probably no gas associated with the kick. (Except with oil-based fluid or highly deviated wells, where solubility or hole angle may prevent or slow migration.) If casing pressure continues to increase above original shut in pressure, gas is present. A possible need for the Volumetric Method exists with delays in starting a primary circulating method.

A few basic principles are required to perform the Volumetric Method correctly.

1. The Gas Law. Normally, Boyle’s Law is used for well control purposes (it ignores temperature effects and gas compressibility factors).

BOYLE’S LAW

P1 V1 = P2 V2Where: P1 = pressure at position 1; V1 = volume at position 1; P2 = pressure at position 2; and V2 = volume at position 2.

Boyle’s Law describes the pressure/volume relationship for gas. If gas expands (increasing volume) pressure within the gas will decrease. This is precisely the action taken with the Volumetric Method. The gas bubble is allowed to expand by bleeding off a calculated volume of fluid at the surface, thereby reducing wellbore pressures.

2. Single Bubble Theory. Used in well control discussion for simplicity. It is also assumed that a kick comes from total depth of well. Actually a kick may be strung out in the form of many bubbles over thousands of feet or meters, meaning considerable gas expansion has been allowed by the time the well is shut in. This means a lower SICP.

Note: Gas density is usually estimated from 1.25 to 2.75 ppg (150 to 330 kg/m³) with 2.2 ppg (264 kg/m³) being the norm for 10,000 ft (3048 m) wells. As gas expands, its density decreases. Some very shallow gas could be less than 0.25 ppg (30 kg/m³).

GAS

SITP

SICP

H

MW

MW

BHP

TVD

Leng

th o

f mud

abo

ve g

as

Hm

Nomenclature:BHP = bottomhole pressure, psi (bar)

HP = hydrostatic pressure, psi (bar)SITP = shut in tubing pressure, psi (bar)

SICP = shut in casing pressure, psi (bar)MW = mud weight, ppg (kg/m³)

l = length of mud column above gas, ft (m)H = height of gas bubble, ft (m)

Hm = height of mud below gas ft (m)Ptg = pressure at top of gas, psi (bar)

Pbg = pressure at bottom of gas, psi (bar)TVD = true vertical depth, ft (m)

The single bubble theory is used in well

control discussion for

simplicity.

WELL CONTROL METHODS7-35

The rising gas bubble can be treated as a surface pressure with respect to the fluid below it. This concept can also be used in calculations to determine pressures in the gas bubble or

bottomhole pressures. Bottomhole pressure is the sum of the pressure at the bottom of the gas bubble, Pbg, added to the hydrostatic pressure of the fluid column below the gas.

520

820

Ann. = 0.05618 bbl/ft

12.5 ppg

5000'

Ann. = 0.0503 bbl/ft

7,450'

10,000'

Gas Kick

FBHP = 7,020 psi

Initial Conditions

2000

1500

1000

50020 40 60 80 100

Typical casing pressure profile when able to use SIDP to moniter FBHP & Hole Geometry is uniform

Bleed mud from annulus at a rate to keep SIDP between 620 to 670 psi

50 psi Working Margin

100 psi overbalance

Choke pressure increase is equal to hydrostatic pressure decrease

Minimum choke pressure to balance FBHP

Gas Bubble Size, bbls. (Kick + Expansion)

Choke

Pre

ssure

, psi

820 SICP

(2) Annulus pressure profile: The annular pressures experienced during a properly execut-ed volumetric control procedure will closely approximate the pressures seen on the first circulation in the Driller's Method.

(3) Fluid to bleed: The Volumetric Method allows controlled expansion of gas so no addi-tional influx is taken and pressures stay below formation breakdown. This is done by bleeding off calculated amounts of fluid from annulus.

BHP = Pbg + HP of fluid below gas or BHP = Pbg + (Hm × MW × Conversion Factor)

BHPpsi= Pbgpsi + HPpsi of fluid below gas or BHPpsi = Pbgpsi + (Hmft × MWppg × 0.052)

BHPbar= Pbgbar + HPbar of fluid below gas or BHPbar = Pbgbar + (Hmm × MWKg/m³ × 0.0000981)

3. Bottomhole Pressure Determination

(1) BHP = HPmud + HPkick influx + SICPor when kick is in position as shown in sketch on page 7-34,

BHPpsi = ([TVD – H] × MWppg × 0.052) + (Hft × gas densityppg × 0.052)+ SICPpsi

BHPbar = ([TVD – H] × MWkg/m³ x.0000981) + (Hm × gas densitykg/m³ × 0.0000981) + SICPbar

The rising gas bubble can be treated as surface pressure with respect to fluid below it.

CHAPTER 77-36

Each barrel (m³) of fluid that is bled from the annulus causes:A. Gas to expand by one barrel (m³);B. Hydrostatic of fluid in annulus to decrease;C. Wellbore pressures to decrease; D. Surface casing pressure should stay the

same (intentionally held constant while bleeding off with choke).

The amount of fluid to bleed is the gas expansion needed to return BHP to formation pressure plus a desired overbalance. The use of manual choke is recommended. Also, measurement of volume is critical to this method. Where possible, the fluid returning from a gas separator into a small stripping tank is suggested. Note that it is important to bleed off fluid from the annulus at a rate

that permits the casing pressure to be held constant. Casing pressure is held constant only while bleeding fluid. At other times, the casing pressure is allowed to increase, reflecting the effects of migration. Thus, volumetric control is accomplished in a series of steps that causes the bottomhole pressure to rise and fall in succession.

Step 1. Let the gas migrate and wellbore pressures increase.

Step 2. Bleed fluid (holding casing pressure constant) and the wellbore pressures decrease.

The steps are repeated until gas reaches the surface or other kill operations are initiated. In this way bottomhole pressure is held within a range of values that is high enough to prevent another influx but low enough to prevent formation breakdown.

VOLUMETRIC METHOD WHILE STRIPPING

No ExpansionUse Trip Tank Volume Control

Casing pressure allowed to increase due to migration by bleeding only the amount of mud equal to total tubing displacement

(No gas expansion allowed)

ExpansionUse Casing Pressure Control

Hold choke pressure constant while bleeding6.1 bbls mud from annulus allowing gas expansion

to neutralize the effects of migration

100 psi ¸ 6.1 bbl = 16.39 psi/bbl1.0 bbl ¸ 0.03962 = 25.241/bbl

25.241 X 12.5 ppg X 0.65 = 16.41 psi/bbl

100 p

si

100 p

si

100 p

si

100 p

si

100 p

si

1600

1400

1200

1000

800

600

7800

7700

7600

7500

7400

7300

1010 20 30 40 50

Gas Expansion Allowed (Bbls bled-off over total tubing displacement)

Expansion

No Expansion

Botto

m -

Hole

Pres

sure

Casin

g Pr

essu

re

Upper limit of workin

g margin

Lower limit of workin

g margin

csg. pressu

re read to balance FBHP

Calculate @ 16.41 psi/bbl

6.1 bbls.

6.1 bbls.

7675 psi100 psi Working Margin7575 psi

FBHP

100 psi over-balance

100 psi over-balance

100 psi working margin

723 psi to balance FBHP

7.53 bbls

(continuous stripping - no shut down)

Volumetric control uses a series of steps to cause

bottomhole pressure to rise

and fall in succession.

WELL CONTROL METHODS7-37

The following examples illustrate common situations where the Volumetric Method is applicable. Assume it has been determined that gas is associated with the kick; surface pressures are increasing as the gas migrates up the well.

STRING ON BOTTOM, NO BACKPRESSURE VALVE IN THE STRING

This is the simplest application of the Volumetric Method because the shut in drillpipe/tubing pressure can be used to directly monitor bottomhole pressure. No calculations are necessary. The standpipe or drillpipe pressure gauge will be the controlling guide.

Theoretically, liquid fluid can be bled off

from the annulus so SIDPP remains the same. Surface annulus pressure will increase by the amount of hydrostatic pressure bled off. This process is continued until gas reaches surface. Once gas is at surface, do not bleed gas unless SIDPP increases. If SIDPP does not increase, and gas is bled, this may allow more formation influx. With gas at surface and SIDPP stabilized, that is all that can be done until other well control techniques can be initiated (i.e., a circulating constant bottomhole pressure method or the Lubricate and Bleed Method, as discussed later).

Since it is practically impossible to operate a choke so the bleed-off rate holds the SIDPP exactly, a safety factor is imposed, by allowing SIDPP/SICP to increase from gas migration. The overbalance insures sufficient bottomhole pressure is imposed against kicking formation to prevent more formation fluid influx and to compensate for slight errors operating choke.

The amount of overbalance usually ranges from 50 to 200 psi (3.45 to 13.79 bar). The choice is influenced by tolerance allowed by the difference in SICP and calculated estimated integrity pressure (MASP). For example, if estimated integrity pressure is 1,050 psi (72.4 bar) and SICP is 800 psi (55.16 bar), then probably no more than 100 psi (6.89 bar) of overbalance would be allowed unless it was certain that portions of the influx were above the weak zone.

520

820

5000' 4070 psi

9450' 6963 psi

10000'

12.5 ppg

Annulus = .02915 b/ft

Annulus = .05618 b/ft

LOT = 4290

MASP =1040

Annulus = .05053 b/ft

16 bbls Gas= 57 psi= 549'

FBHP = 7020 psi

Initial Conditions

620

885

5000' 4135 psi

9362'

9846'

6,970 psi

7,020 psi

BHP = 7120 psi

484'

50 p

si

154' Migration

670

916

4166 psi

6973 psi @ 9317'

7020 psi @ 9769'

BHP = 7170 psi

451'

47 p

si

231' Migration

670

849

4099 psi

6779 psi @ 9124'

6812 psi @ 9450'

BHP = 7170 psi

326'

33 p

si

550' 358 psi

16.5 bbls

670

979

4229 psi @ 5000'

4262 psi @5526'

BHP = 7170 psi

52

6'

26.56 bbls

670

972

3890 psi

3920 psi

BHP = 7170 psi

510'28.65 bbls

670

1504

1534 psi1441 psi

3920 psi 3770 psi

BHP = 7170 psi BHP = 7020 psi

1303'

73.22 bbls

520

1411

1420'

79.80 bbls

Gas migrates to establishover-balance = 100 psi

Gas migrates to establishworking margin = 50 psi Gas above DCs If FBHP balancedTop gas @ surface

Top gas @ shoe Bottom of gas @ shoe

(start bleeding)

Pressure @ bottum of gas bubble

7000

6000

5000

4000

3000

2000

1000820

16 20 30 40 50 60 70 80 90

casing pressure required to hold 150 psi overbalance

casing pressure required to balance FBHP

Gas

@ s

urfa

ce w

ith B

HP

bal

ance

d =

1400

psi

SIC

P &

79.

5 bb

ls

Gas

@ s

urfa

ce 1

505

psi

75

.0 b

bls

h

oldi

ng 1

50 p

si o

ver F

BH

P

Kick size, bbls (including expansion)

Cas

ing

pres

sure

, psi

@ 11.57 psi/bbl

Above: pressure size profiles can be generated to estimate maximum gas expansion and pressure.Below: volumetric technique – controlled expansion to maintain constant BHP.

A safety factor is imposed since the choke cannot hold the bleed-off rate to SIDPP.

CHAPTER 77-38

This represents the distance from bottom of well to bottom of influx. Bottomhole pressure can then be estimated by adding the pressure within the gas plus the hydrostatic of the fluid below the gas. Also, the hydrostatic pressure of the influx contributes to bottomhole pressure and can be considered. Boyles Law can be used to demonstrate that the 100 psi (6.89 bar) increase is equivalent to about 0.71 bbls (0.113 m³) of fluid in the annulus as shown by:

P1V1 = P2V2

7,475 psi × 52.25 bbl = (7,475 psi – 100) × V2

V2 = 52.96 bbls gas

The amount of expansion is:

52.96 bbls – 52.25 bbls = 0.71 bbls

P1V1 = P2V2

515.4 bar × 8.3 m³ = (515.4 bar – 6.89 bar) × V2

V2 = 8.413 m³ gasThe amount of expansion should have been:8.3 m³ – 8.413 m³ = 0.113 m³

Casing pressure must compensate for fluid bled from the well in this technique. If bottomhole pressure is allowed to return to its original 7,475 psi (515.4 bar), a bleed off of 0.71 barrels (0.113 m³) of fluid should have occurred while compensating for hydrostatic pressure of the fluid bled. The hydrostatic pressure of the 0.71 barrels (0.113 m³) while in the well would have exerted approximately 15 psi (1 bar). So, casing pressure would now have to be the original 600 psi (41.37 bar) plus 15 psi (1 bar) and should now be 615 psi (42.4 bar). It should be noted that if casing pressure had been allowed to fall to 600 psi (41.37 bar) without compensating for the hydrostatic pressure lost due to expansion that the bottomhole pressure would have been reduced below formation pressure thereby allowing additional influx into the well.

When choke is opened to bleed off fluid two things are happening simultaneously: 1) the gas bubble is expanding and; 2) the influx is migrating. Both of these affect hydrostatic pressure in the well and must be considered when applying the Volumetric Method in the field.

STRING OUT OF WELL OR PLUGGED

Where it is not possible/reliable to use shut in tubing/drillpipe pressure to monitor downhole conditions, the use of casing or annulus pressure is required. Following is an example.WELL DATA

Depth: 11,500 ft (3505.2 m)Casing: 7-5/8” (193.67 mm) at 10,000 ft (3048 m),24 lbs/ft (0.017 kg/m), 0.04794 bbls/ft (0.025 m³/m) capacityTubing: 2-7/8 (73.03 mm), 10.4 lbs/ft (15.48 kg/m), 0.00353 bbls/ft (0.00184 m³/m) displacement, 0.00449 bbls/ft (0.00234 m³/m) capacity. Off bottom, influx swabbed in below tubing.Fluid density: 12.5 ppg (1498 kg/m³)SCIP: 600 psi (41.37 bar)Final pit gain after shut in: 52.25 bbls (8.3 m³)Formation BHP: 7,475 psi (515.4 bar)

Suppose while shut in, waiting for orders, casing pressure increases from 600 to 700 psi (41.37 to 48.27 bar). Since the well has remained shut in and tubing has not been moved, it can be assumed the influx has begun to migrate upward. Total BHP is now 7,475 + 100 = 7,575 psi (515.4 + 6.89 = 522.3 bar). An estimate may be made of the distance of migration.

Fluid gradientpsi/ft = Fluid Densityppg × 0.052

= 12.5 × 0.052

= 0.65 psi/ft

Fluid gradientbar/m = Fluid Densitykg/m³ × 0.0000981 = 1498 kg/m³ × 0.0000981 = 0.14695 bar/m

Gas Migration Distanceft = Pressure Increasepsi ÷ Fluid Gradientpsi/ft

= 100 ÷ 0.65

= 154 ft

Gas Migration Distancem = Pressure Increasebar ÷ Fluid Gradientbar/m = 6.89 bar ÷ 0.14695 bar/m = 46.9 m

Boyle’s Law: P1V1 = P1V1

WELL CONTROL METHODS7-39

Carefully measure fluid bled from well and estimate its equivalent hydrostatic density.

STRIPPING/MOVING PIPE ANDVOLUMETRIC CONSIDERATIONS

Suppose in the example given, the crew has received orders to strip back to bottom before a circulating method is implemented. During the stripping operation pipe will be moving, gas may be migrating, and fluid will be bled off at choke. To carry out operation safely, a plan or stripping pressure schedule must be designed.

Assume that well is shut in with 600 psi casing pressure. In designing a bleed-off schedule, a safety margin and a working margin are chosen. In this example we use 100 psi (6.89 bar) for each. In other words, the choke will not be opened for any bleed-off until casing pressure has been allowed to rise to 800 psi (55.16 bar). During first bleed-off, casing pressure will be maintained between 700 and 800 psi (48.27 and 55.16 bar).

It is necessary to carefully measure any fluid bled from the well and to estimate its equivalent hydrostatic pressure. Tubing will be fitted with at least one backpressure valve so total displacement will be that of the full outside diameter.

0.00802bbls/ft × 90’ = 0.72 bbls/stand

0.00413m³/m × 27.43m = 0.113 m³/stand

Pressure equivalent to well fluid in open casing:

0.65psi/ft ÷ 0.04794bbls/ft = 13.6 psi/bbl

0.14695bar/m ÷ 0.025m³/m = 5.88 bar/m³

Pressure equivalent in casing/tubing annulus:

0.65psi/ft ÷ 0.04441bbls/ft = 14.6 psi/bbl

0.14695bar/m ÷ 0.02316m³/m = 6.34 bar/m³

With this information, a stripping/bleed-off schedule is created (see above). Using chart, the following steps describe a procedure when tubing is continuously stripped into the well.1. Strip in well without bleeding fluid until

casing pressure increases 200 psi or 13.79 bar (100 psi [6.89 bar] for safety margin and 100 psi [6.89 bar] for working margin) from 600 psi (41.37 bar) to 800 psi (55.16 bar).

2. Once casing pressure has reached 800 psi (55.16 bar), it is used as a guide for bleed-off rate. As long as tubing is moving into well, continue bleeding at a rate to hold choke pressure between 700 and 800 psi (48.27 and 55.16 bar). After bleeding equivalent of 100 psi (6.89 bar) of fluid hydrostatic pressure above pipe’s cross section displacement, (13.6 psi/bbl, so 100 psi ÷ 13.6 = 7.4 bbls [assuming gas is below tubing]) allow casing pressure to increase by another 100 psi.

3. At this point discontinue using casing pressure as control. As pipe is lowered into well, carefully bleed off only amount of tubing displacement (0.72 bbls [0.15 m³] per 90’ [27.4 m] stand) as it is lowered into well. Casing pressure is allowed to increase. If casing pressure has not increased by 100 psi (6.89 bar) after stand is lowered and set on slips, close choke, and make up next stand. Continue bleeding only pipe displacement when the connected stand is lowered.

VOLUMETRIC METHOD WHILE STRIPPING

No Expansion

Use Trip Tank Volume Control

Casing pressure allowed to increase due to

migration by bleeding only the amount of

mud equal to total tubing displacement

(No gas expansion allowed)

Expansion

Use Casing Pressure Control

Hold choke pressure constant while bleeding

6.1 bbls mud from annulus allowing gas expansion

to neutralize the effects of migration

100

psi

100

psi

100

psi

100

psi

100

psi

1600

1400

1200

1000

800

600

7800

7700

7600

7500

7400

7300

1010 20 30 40 50

Gas Expansion Allowed (Bbls bled-off over total tubing displacement)

Bleed

Migrate

Bot

tom

- H

ole

Pres

sure

Cas

ing

Pres

sure

Upper limit of workin

g margin

Lower limit of workin

g margin

csg. pressu

re read to balance FBHP

Calculate @ 16.41 psi/b

bl

7.4 bbls.

7.4 bbls.

7675 psi

100 psi Working Margin

7575 psi

FBHP

100 psi over-balance

100 psi over-balance

100 psi working margin

723 psi to balance FBHP

7.53 bbls

(continuous stripping)

CHAPTER 77-40

4. When casing pressure has increased to 900 psi (62.06 bar) control changes once again back to casing gauge. While continuing to strip, maintain casing pressure between 800 and 900 psi (55.16 and 62.06 bar) until a gain of 7.4 bbls (1.13 m³) is noted. At this point, change control once again to measurement of tubing displacement.

Steps are repeated until tubing has been run to bottom or gas reaches surface.

POSITION OF THE INFLUX

It is not practical to take every geometric change into consideration for most volumetric techniques. Simplicity and a prudent safety and working margin will enhance the chance for a successful operation.

When stripping into the well, consideration should be given to what will happen when the BHA stings into the main body of the gas. As gas is displaced or migrates around the BHA, its vertical length increases and may result in a decrease in effective hydrostatic pressure.

Many operators simplify matters by using the annulus between the tubing and casing for psi/bbl (bar/m³) calculation. Although this may result in slightly higher pressures if there is a long open hole section, remember the majority of expansion will occur nearer the surface.

PRESSURE EQUIVALENT TO WELL FLUID

In the example, the open casing volume was used to illustrate equating fluid removed from the well to hydrostatic pressure loss. A more conservative approach would have been to use the tubing/casing annulus. Like safety margins, this must be a well-specific decision. Some of the considerations required are estimates of the bubble position, maximum allowable pressures, amount of open hole in relation to the casing seat, well geometry and size of pipe to be stripped in.

SELECTING SAFETY & WORKING MARGINS

Choosing appropriate safety and working margins must be well-specific. For example, formation integrity pressure may be a concern.

If, in the example above, the estimated formation integrity pressure were 1,200 psi (82.74 bar), the selections of 200 psi (13.79 bar) total margins would likely be safe since 1,200 – 800 = 400 psi (82.74 – 55.16 = 27.58 bar), which should be ample tolerance.

If casing pressure does not increase after a few stands (about three stands in example) it could mean that the well is already taking fluid and that fracture pressure has been exceeded.

Once it is established that the well is taking fluid, stripping may continue by bleeding just enough fluid to equal the total displacement of the tubing. In this situation, less fluid would be forced into the formation and the losses might stop once the gas rises above the fracture point.

STRIPPING WITH SMALL TUBING The stripping procedure in the example is

well suited for conditions with larger pipe sizes and gas influxes of 50 bbls (7.95 m³) or less. When tubing smaller than 2-3/8” (60.33 mm) OD is used on kicks larger than 50 bbls (7.95 m³), a slightly different (and simpler) procedure has been successful. Using the same example:

1. Establish safety/working margins as before.

2. Bleed off volume of fluid (in this case we use the more conservative 6.1 bbls or 0.97m³) from the well that equals the hydrostatic pressure of the working margin (100 psi or 6.89 bar) while holding casing pressure constant at 800 psi (55.16 bar).

3. Close the choke and continue stripping without bleeding until the casing pressure increases by the 100 psi (6.89 bar) working margin (to 900 psi or 62.06 bar). The increase in casing pressure is caused by the effects of migration and the compression of the gas by the tubing volume stripped into well. (This eliminates the need for coordinating the bleed-off with pipe movement and measurement of barrels bled off in order to compensate for the total tubing displacement.

4. After desired Shut In Casing Pressure has been reached (900 psi), resume bleeding

Choosing appropriate

safety and working margins

must be done on a case by

case basis.

WELL CONTROL METHODS7-41

fluid out of well at a rate that allows casing pressure to be held steady within the limits of the working margin (800-900 psi) until 6.1 bbls above the cross section displacement of pipe has been bled off.

Repeat steps 3 and 4 until the tubing is on bottom or gas is at surface.

LUBRICATE & BLEED (LUBRICATION)

The Lubricate and Bleed Method is often a continuation of the Volumetric Method, and is used once kick fluid reaches the wellhead. It is also used if perforations or circulating ports in the tubing are plugged, tubing is sanded up or plugged, circulation is not feasible or high well pressures start to reach rated wellhead pressure ratings.

In the Lubricate and Bleed Method, fluid is pumped into the well and allowed to fall down into the annulus. Sufficient time must be allowed for the fluid to begin to affect (increase) the annular hydrostatic pressure. Since hydrostatic pressure was added to well, backpressure may be taken or bled off equal to the gain of hydrostatic.

To begin lubricate and bleed, fluid must be pumped into well. This fluid must be carefully measured. From the number of pump strokes

or from a measure of volume pumped, length of fluid when in the wellbore can be calculated. Once length is known, the gain in hydrostatic pressure created by it can be determined. This value will be bled off on surface.

EXAMPLE

Surface pressure (SICP) is 4,650 psi (320.62 bar)

Casing ID =6.004” (152.5 mm)

Tubing OD = 2-7/8” (73.03 mm)

Fluid weight = 9.0 ppg 1078 kg/m³

Pump is a Gardner Denver PZ9 with 0.044 bbl/stk (0.007 m³/stk) output

In this example we would bring the pump online enough to slightly overcome wellbore pressures. This requires a high pressure pump. The pump forces fluid into the well, which will raise pressures. Therefore, pressure and injected fluid should be limited, typically to a 200 psi (137.9 bar) increase above the shut-in pressure.

When fluid was injected, it took 195 strokes to increase casing pressure by 200 psi (13.79 bar) to 4,850 psi (334.41 bar). The volume pumped into the well can be calculated:

195 stks × 0.044 bbl/stk = 8.58 bbls

195 stks × 0.007 m³/stk = 1.365 m³

Pump (lubricate) fluid in well

Allow fluid to fall Bleed off pressure from pump

Bleed off gain in hydrostatic pressure

HP Gained

Lubricate and bleed process

The lubricate and bleed method is often a continuation of the volumetric method.

CHAPTER 77-42

We want to avoid excessive pressures at all times. However, we must wait until the fluid drops down the annulus before we can bleed off the 200 psi (13.79 bar) of injection pressure and take casing pressure back to 4,650 psi (320.62 bar). If we do not wait for the fluid to fall, we can lose fluid (and its hydrostatic) out of the well when we start to bleed off. Only after sufficient time has been given, can the injection pressure increase be bled off. Waiting for the fluid to fall depends on well geometry, type of fluid and section it has to fall through. This can take 15 to 30 minutes or longer depending on fluid type and well geometry.

Next, we can calculate how much hydrostatic pressure was gained when we pumped liquid into the well, and then bleed off an equivalent amount of backpressure. First, calculate the length from the volume pumped in:

8.58 bbls ÷ 0.027 bbl/ft = 318’

1.365 m³ ÷ 0.01408 m³/m = 97.9 m

Now calculate gained hydrostatic pressure.

9.0 ppg × 0.052 × 318’ = 149 psi(approx. 150 psi)

1078kg/m³ × 0.0000981 × 97.9 m = 10.3 bar

The 150 psi (10.3 bar) gain in hydrostatic pressure is subtracted from the present casing pressure of 4,650 psi (320.62 bar) and then casing pressure bled down to that value.

4,650 psi – 150 psi = 4,500 psi

320.62 bar – 10.3 bar = 310.32 bar

The procedure, injecting fluid, waiting for it to hold hydrostatic pressure, then bleeding off casing pressure, is repeated until annulus is full of fluid and casing value is 0 psi. If the well was underbalanced, the space that gas occupies in wellbore must be replaced with a fluid heavy enough to compensate for pressure underbalance (this may not be predictable or possible).

WELL KICKS WHEN THEPIPE IS OFF BOTTOM

Some of the worst blowouts have occurred during a trip. If fluid weight was heavy enough to operate without kicking, the swabbed kick on the trip would be signaled by the hole not taking the proper amount of fluid. Kicks on a trip usually result from a failure to detect swabbing.

Once it has been determined an influx has entered the wellbore (by improper fill or flow detection) and well is shut in, pressures should be low. Once shut in, stripping or staging may be used to control the well, while incorporating volumetric corrections to pressures held during circulation or the trip back to bottom.

Volumetric corrections compensate for kick length changes as wellbore geometry changes, and due to displacement of fluid out of the well from gas expansion. If these considerations are ignored, hydrostatic pressure may be lowered enough to allow further influx into the well.

If possible, stripping back to bottom is considered the best option. The trip back to bottom and what pressures to hold, versus volume gained, can be complex with multiple pipe sizes and well geometry. Once on bottom, circulating bottoms up using a Driller’s Method should regain hydrostatic control of the well.

While not recommended, the concept of staging to bottom is the use of a much heavier fluid at that depth needed to overcompensate for the kick in the hole. This should take into account the depth where you will be circulating, and the effect that a heavier fluid and ECD will have on casing shoe, or weak zones in the wellbore. After heavy fluid has been circulated, the well is held static by the additional hydrostatic. At this point, the preventer is usually opened and a predetermined amount of pipe is run into the well. The process of circulating a heavy fluid (cutback) and then tripping back in to a predetermined depth is then repeated, until pipe is back to bottom. Each circulation uses a less dense heavy fluid until on bottom where the proper mud weight is circulated.

Some of the worst blowouts have occurred

during trips.

WELL CONTROL METHODS7-43

Several complications may arise from staging back to bottom. First, the well cannot be killed until kick is out of the hole and entire column of fluid is conditioned. Second, if influx is gas, it will migrate, expand and displace fluid from well, resulting in a hydrostatic loss, which may lead to additional influx entering wellbore. Also, if too much pipe is run, the heavy fluid displaced by tripping pipe reduces hydrostatic pressure and may allow well to flow. If pipe is tripped in until it is noticed the well is flowing, additional influx and higher shut-in pressures may cause additional complications. If influx is gas and is below the end of the string, maintaining planned circulating pressures without using volumetric corrections for gas expansion may lead to further influx and disaster. It must be stressed that increases in fluid levels in pits (not due to pipe displacement, weight material or chemicals to treat fluid system during circulation) is probably due to gas migration and expansion.

STRIPPING

Stripping is moving pipe into or out of the well against well pressure when the force of that pressure is less than the weight of pipe being stripped. Remember additional influx and/or excessive pressures can occur if pressure is not monitored and corrected for the displacement of the pipe being stripped and gas expansion.

Exercise care when stripping. If necessary pipe weight (tripping in or out under pressure) is not maintained, pipe can be blown from well. Stripping complications can occur due to some preventers being wellbore pressure assisted to various degrees. Also, the wear factor on sealing elements may lead to element failure and pressure venting to rig floor. If preventer develops a leak, this may lead to rapid failure of a sealing element and/or preventer and may jeopardize the operation. There is also the possibility of the wrong preventer being opened if speed exceeds caution. All stripping operations should be performed carefully, with all personnel briefed and familiar with their responsibilities.

Stripping policies and procedures vary. The procedures given here cover essential elements of stripping with equipment that is normally available on a rig, although it is usually better to get a regular stripping or snubbing crew.

Depending on pressure, pipe, collars and tool joints may not strip down of their own weight, but require a pull-down (snub) force. The force required to push pipe down through preventers against well pressures and preventer friction may be estimated as follows.

Swt = (0.7854 × D² × P) + F

Where:

Swt = Estimated weight to strip into hole

0.7854 = π ÷ 4

D = diameter of largest collar or tool joint in preventer rubber inches (mm).

P = annular pressure psi (bar)

F = approximate pipe weight to slide through packer rubber

BPV

Force

Pressure

Area

BOP Force Against Pipe

Force equals area × pressure

Stripping should be performed carefully, with all personnel briefed and familiar with their responsibilities.

CHAPTER 77-44

Note: Preventer type, element type, total element area sealing pipe, closing pressure, wellbore pressure, fluid type, lubrication, condition of pipe and preventer elements, all affect force necessary to strip pipe through a preventer. For example, with minimum closing pressure and no well pressure it takes about 2,000 lbs. (907.2 kg) to move 5” drillpipe through a closed Hydril 13-5/8” annular preventer.

String weight must be greater than computed force or pull down force (snubbing) will be required. The equation shows why it might be necessary to start pipe with a few stands of ram to ram stripping rather than with the annular preventer. When using ram to ram stripping, tool joint is never in the preventer so the term D is smaller. Based on this equation, it is obviously difficult to get the first few collars in the hole if there is any annulus pressure.

Travelling blocks have been used to push pipe down. This is dangerous because pipe might slip back up and start to unload out of the hole. Be careful about the beginning of stripping operations. If pipe is not heavy enough to go into the hole against the well pressure, it needs to be kept under restraint at all times while stripping, until it is heavy enough to overcome upward forces.

When stripping in or out of the hole it is necessary to have a float or inside BOP in the string. Also, a safety valve should be on the open box as a joint or stand is pulled/lowered. Two safety valves may be used. One is on the string and another is either taken off the last joint pulled or made up on the next to be run. These valves must be in place in the event the float or inside BOP fails, so the string can be shut in. Safety valves should be left open so pipe will not pressurize without warning.

Displacement principles are the same in stripping/snubbing as in normal tripping procedures with the exception of pressure. When stripping into the hole, fluid will be displaced out of the hole and when stripping out of the hole, fluid must be pumped into the hole. The arrangements for doing this should be tested before committing to stripping operations. The displacement is important because failure of the displacement system will cause either lost circulation or the kick size to increase and could possibly result in both situations.

Stripping operations require excellent communications between the choke operator and driller. As tool joint nears the floor, driller must inform choke operator that he will be slowing and stopping pipe. Choke operator must dictate the overall rate of pipe movement, as it will be his responsibility to maintain pressures as close as possible according to calculations.

Some operators close off the accumulator bank and strip using accumulator pumps for pressure. This is a bad technique as pumps are used too erratically. A better procedure would be to close off one-half of the bank and keep it for reserve or to turn off either electric or air pumps and keep one type of pump for reserve.

STRIPPING WITH THEANNULAR PREVENTER

The annular preventer is the most satisfactory stripping head normally on the rig. It is easier and quicker to use the annular preventer than rams or a combination of the two. There are limits and some special points that need to be checked before using the annular preventer.

BEFORE USING ANNULAR PREVENTER

1. Check accumulator reservoir for fluid.

2. If gas is not present, annular preventer closing pressure must be relaxed until preventer slightly leaks when moving pipe to provide lubrication. Remember any fluid vented from well to lubricate packer should be captured in trip tank. Annular preventer characteristics vary; closing pressure recommended by preventer manufacturer should be used to adjust pressure if top of annular preventer cannot be seen. If gas is present underneath BOPs, a leak-tight seal must be effected.

3. Make sure pressure regulator valve for annular preventer will relieve pressure back through valve. This valve is key to move-ment of preventer packer around tool joints. It must work to avoid tearing packer.

When stripping in or out it is

necessary to have a float or inside BOP in

the string.

WELL CONTROL METHODS7-45

4. Annular closing lines must be short in length and large enough in diameter to allow closing fluid to move. The use of a small accumulator bottle on the closing line near the annular preventer is a real asset in preventing wear during stripping.

5. Annular preventers may allow protector rubbers to pass through them. They must be removed when stripping in. When stripping out, annular to ram stripping techniques should be used to prevent the possibility of leaks (as fluted designs are stripped through annular) or protector rubbers from breaking off (if they will not pass through packer).

6. Limit speed of pipe. Pass tool joints slowly through preventer. One second a foot is a good rate to remember, and go even slower at tool joints. Ultimately it is the choke operator who should set the speed.

7. Sharp, rough tool joints or pipe necks create excessive wear on the annular elements.

8. Use a lubricant in bowl on top of annular preventer when stripping in. Soluble oil and water, oil bentonite suspension and water are all good pipe lubricants.

STRIPPING IN THE HOLE WITH THE ANNULAR PREVENTER

When stripping into hole, fluid will have to be released from hole equal to total cross section area (displacement/capacity) of pipe. The easiest way is to hold annular pressure constant when going back into hole, so the pipe displaces correct amount of fluid, except for any upward displacement of kick or gas migration. Check the amount of fluid displaced in a trip tank. If volumes displaced do not correspond to calculations, pressure adjustments should be made.

If choke pressure is maintained constant prior to bleed off, when pipe enters the kick, kick length will increase due to reduced clearance between the pipe and wellbore. Therefore, choke pressure must be corrected. This correction, with an example is described under the Volumetric Method of Well Control. As a practical consideration, unless the stripping operation is going to take several days or annular pressures are high, it may be better to ignore volumetric corrections. The potential for error or problems is perhaps greater when trying to overcorrect annular pressure than it is to ignore the volumetric corrections.

Back Pressure Valve

LandingNipple

SafetyValve

Step 1: make up landing nipple and backpressure valve. Install open safety valve on top of pipe.

TRIP TANK

PUMP CHOKE LINEKILL LINE

ANNULAR

RAM

RAM

RAM

Step 2: slowly lower pipe into hole. Ease each tool joint through preventer. Check annular regulator valve on accumulator to be sure it is working and regulated pressure to preventer is remaining constant. As casing (or annular) pressure starts to increase, bleed off excess (above starting) pressure (volumetric method).

TRIP TANK

PUMP CHOKE LINEKILL LINE

ANNULAR

RAM

RAM

RAM

Step 3: Land pipe, fill pipe, install safety valve on new stand, remove safety valve from stand in slips, make up pipe. Repeat sequence again beginning with Step 2.

TYPICAL STRIPPING IN WITH THE ANNULAR PROCEDURE

When stripping in, fluid will have to be released from the hole equal to total cross section area of pipe.

CHAPTER 77-46

STRIPPING OUT OF THE HOLE WITH THE ANNULAR

If a pump down type of float is used, be sure that it is seated before committing to pulling the pipe. Remember to keep the safety valves open when pulling the pipe so that if the float leaks, it will not pressure up the pipe.

When stripping out of the hole, the fluid will have to be pumped into the annulus to keep the hole full. There are a number of ways to do this, but the best way is to arrange to circulate across the BOP stack from the kill to the choke line. A cementing pump generally works better than the rig pump. Backpressure, which is initially about 100 psi (6.89 bar) greater than casing pressure, is maintained from the choke. As the pipe is pulled, fill up from circulating across the top should be automatic. The fluid should be taken from a single tank with an accurate volume measuring system. After each stand, the total pipe displacement should be compared to fluid actually taken by the well. Casing pressure should stay constant and corrections to volume

pumped in the hole can be made by adjusting the choke. The pump should be kept running throughout the activity.

When stripping out of the hole, casing pressure should drop as the collars are pulled out of the kick fluid. However, the upward migration of gas and some upward drag will tend to raise the casing pressure. Again, the correction to the casing pressure is made according to the Volumetric Method.

Every three or four stands, it might be necessary to use the pipe rams to strip the pipe rubbers through an open annular preventer. If possible, release the pressure between the pipe ram and the annular preventer before opening the annular preventer.

Again, good communications should be exercised between choke operator and driller.

While stripping out, at some point there will not be enough pipe weight for the pipe to stay in the well against the wellbore pressure. Make provisions and issue warnings in order to protect the crew.

TRIP TANK

PUMP CHOKE LINEKILL LINE

ANNULAR

RAM

RAM

RAM

Step 1: start circulating across the hole with 100 psi greater pressure than shut in pressure. Install safety valve and begin slowly pulling pipe.

TRIP TANK

PUMP CHOKE LINEKILL LINE

ANNULAR

RAM

RAM

RAM

Step 2: check to ensure the annular preventer is leaking and the hole is taking mud. Ease tool joints through the rubber. Check annular regulator.

TRIP TANK

PUMP CHOKE LINEKILL LINE

ANNULAR

RAM

RAM

RAM

Step 3: Land pipe on slips. Check mud displacement and annular pressure. Break off stand and install safety valve. Repeat sequence again beginning with Step 1.

TYPICAL STRIPPING OUT WITH THE ANNULAR PROCEDURE

When stripping out, fluid will have to be

pumped into annulus to keep

hole full.

WELL CONTROL METHODS7-47

STRIPPING IN THE HOLE WITH PIPE RAMSHigher pressure operations and specialized

stripping BOP stacks use ram to ram stripping techniques. The pipe rams can be used to strip pipe in much the same manner as with the annular preventer, except two pipe rams have to be used to pass tool joints. Packing in pipe ram blocks is adequate and will continue to extrude and seal for a long period of stripping. Pressure on the closing side of the rams should be reduced for stripping operations to avoid burning packing around pipe as the pipe is sliding past. There are no strict rules about pressure on closing side of rams, but 400 psi (27.58 bar) is often used. Other recommendations vary from 100 to 500 psi (6.89 to 34.48 bar).

When using rams for stripping, upper ram should be used to better manage packer wear. If

rams on bottom are kept as a master valve, or safety ram, ram to ram stripping would require a four ram stack, or an annular preventer in place of one set of rams would be required.

Stripping rams must be spaced far enough apart so tool joints will not interfere with either ram when both are closed. This requires a single ram with a spacer in the stack. Adjacent rams in double or triple sets should not be used for stripping. Always use safety valves and keep them open. The constant annulus pressure can be checked by the volumetric calculations every several stands if necessary, or if that is the operating policy.

Calculations must be used. Even 100 psi (6.89 bar) of well pressure will not allow 93 feet (28.3 m) of 4-1/2 inch (114.3 mm) 16.6 ppf (24.6 kg/m) pipe to strip down of its own weight.

PUMP

LNBPV

TRIP TANK

PUMP

TRIP TANK

LNBPV

PUMP

TRIP TANK

LNBPV

PUMP

TRIP TANK

LNBPV

TRIP TANK

PUMP

LNBPV

LNBPV

TRIP TANK

PUMP

PUMP

LNBPV

TRIP TANK

Step 1: with well shut in on blind ram, lower pipe until BPV/LN assembly is just above blind ram. Use open safety valve on each stand, keep annulus pressure constant by releasing mud through choke.

TYPICAL PROCEDURE FOR STRIPPING IN WITH PIPE RAMS

Step 2: Close the upper stripping ram. Pressure up between rams to well pressure using pumps.

Step 3: open blind ram. Lower the next tool joint into the stack until it is just above the upper stripping ram.

Step 4: close the lower stripping ram. Bleed off pressure between the two rams. Open upper rams.

Step 5: lower the pipe until the tool joint is just below the upper stripping ram.

Step 6: close upper rams and choke, pressure between rams to well pressure using pumps.

Step 7: open lower ram and lower pipe until tool joint is just above upper stripping ram and repeat sequence starting with Step 4.

When using rams for stripping, upper ram should be used to take maximum wear.

CHAPTER 77-48

STRIPPING OUT OF THE HOLE WITH PIPE RAMS

The upper stripping ram should be used to take most of the wear. Begin by ensuring that the float is holding properly. Also, keep an open safety valve on the tool joint box.

Each stand or every several stands, check the displacement according to the table and compare with the fluid volume being displaced. If there is a significant refusal of the well to take fluid, then the Volumetric calculations can be used within limits to correct the displacement.

PUMP

TRIP TANK

LNBPV

PUMP

LNBPV

TRIP TANK PUMP

TRIP TANK

LNBPV

PUMP

TRIP TANK

LNBPV

PUMP

TRIP TANK

LNBPV

Step 1: circulate across stack keeping well pressure on choke. Using upper stripping ram, slowly raise pipe until

next lower tool joint is just below upper stripping ram. As pipe is raised,

mud pumped across hole should automatically displace into hole.

TYPICAL PROCEDURE FOR STRIPPING OUT WITH PIPE RAMS

Step 2: stop pipe and close lower stripping ram. Shut down

pump and bleed off the pressure between stripping rams.

Step 3: open upper ram, pull tool joint above the upper ram.

Step 4: close upper stripping ram. Pressure up, circulate area between

rams to well pressure using pumps.

Step 5: open the lower stripping ram. Repeat sequence beginning

with Step 1.

Before beginning, be sure the work string float is

holding properly.

WELL CONTROL METHODS7-49

CONCENTRIC TECHNIQUES

Snubbing and coiled tubing units are specialized and take advantage of stripping principles. Both units can strip and snub. Stripping is moving pipe in or out of a well against pressure when pipe weight is greater than the force to be overcome. Snubbing is forcing pipe in or out of a well against well pressure sufficient to eject the pipe. This is accomplished by special slip assemblies and hydraulic jacks on snubbing units and by the tubing injector head on coiled tubing units. Pressure control is maintained by specialized stripper assemblies.

A snubbing unit can work up to the BOP pressure rating. The only limitation is snub force to overcome the cross section area of pipe and well pressure. Larger units are sometimes required to snub large pipe against high well pressures. Once sufficient pipe weight is in the well, snubbing ceases and stripping begins. Snubbing units are used for remedial activities because of their size, portability and ability to handle unexpected pressure. They help drilling rigs during complications like stuck pipe, or being caught out of the hole when the well kicks, and to clear blocked drillpipe during a kill operation. They are compact enough to fit inside most derricks and provide additional safety by providing extra BOPs.

The typical coiled tubing unit can strip in up to 5,000 psi (344.75 bar) of pressure under normal conditions. Coiled tubing is usually run with one or more backpressure valves in the string. In any event, since the tubing is shut in at pump valves, the entire cross sectional area is exposed to well pressure when considering required snub force. The injector head of the coiled tubing unit provides the necessary force to move pipe into or out of well under pressure.

Snubbing and coil tubing units can strip tubing inside tubing or drillpipe. This has many applications. In remedial operations, it is possible to strip pipe inside the producing tubing string and then kill the well. In wells where circulation is not possible in the tubing

or drill pipe (sanded up, plugged string or bit, etc.) these units can strip inside these strings, clear the obstruction and then kill the tubing/ drillpipe, and the well.

Discuss procedures and operations performed by snubbing and coil tubing units with all personnel involved. Unauthorized personnel should stay clear of the area where one of these units is working. As with any specialized operation, proper supervision is required. The service company provides personnel trained and experienced to handle the job, however if complications arise, or if unsafe or improper techniques are used, the operation should be shut down until the complications are solved.

Small tubing units can also strip pipe into a well. The string of pipe, often called a macaroni or spaghetti pipe, is used as a work string inside an existing production tubing string. For practical purposes, the small tubing rig cannot snub this pipe into the well.

Depending on the type of the well, stripping/volumetric techniques may be warranted. There are four basic scenarios:

w Producing gas or oil wells, flowing while tripping in. Seldom in this case are volumetric techniques required. As the displacement of steel enters, the production choke allows pressure compensation. If excess pressure builds, the tripping speed may be slowed or stopped until acceptable levels are obtained.

w Shut in gas well. The shut in gas well seldom poses a problem with stripping in. As the pipe displacement compresses the gas, excess pressure in the well will begin to inject the gas back into the formation. If this is acceptable, no surface volumetric control will be necessary. If this is not acceptable, as pressure increases, excess pressure (gas) is bled from the choke to maintain a predetermined level. An unacceptable condition may arise when gas separation occurs and may actually damage the formation if pumped back in. Again, predetermined pressure is held as pipe is tripped, with excess pressure bled off.

Snubbing units can work with as much pressure as the BOPS are rated to.

CHAPTER 77-50

In some areas, bullheading is

a common way to kill wells

before working them over.

w Shut in oil well. If the native formation oil carries asphaltines, fines, etc., and may cause formation damage (e.g., plugging or bridging) if injected back into formation, volumetric/stripping techniques may be used to keep pressure fairly constant. w Fluid filled well. If a well kill attempt is

not successful, a kill string can be stripped to bottom and the fluid conditioned or replaced with another (i.e., kill or completion fluid). Stripping pipe back to bottom should use volumetric/stripping

techniques if minimizing potential damage to the formation is a concern.

The previous scenarios require detailed information about the formation and produced fluid characteristics. If the volumetric/stripping techniques will be used, then the predetermined pressures should be maintained and the liquid level of the tanks should be closely monitored. Pressure corrections should be made corresponding to the tank level changes as calculated (i.e., gain or loss).

BULLHEADING

Bullheading, also called deadheading, is a common way to kill a well in workover in some areas. This technique works when there are no obstructions in the tubing and injection into the formation can be achieved without exceeding any pressure limitations. In bullheading, the well fluids are pumped back into the reservoir, displacing the tubing or casing with a sufficient quantity of kill fluid. Bullheading is applicable in some drilling circumstances, mainly if an H2S kick is taken. Here it may be preferable to pump it away, back into the formation, instead of bringing it to the surface.

In remedial operations, bullheading has limited applications and it is subject to many problems, such as the following:

w High viscosity formation fluids may be difficult and time consuming to bullhead.

w Tubing and casing burst pressures should be known and not exceeded. When bullheading down the tubing, some pressure may have to be applied to the casing so the tubing will not burst.

w Gas may present a serious migration problem. Should the gas migration problem occur, it is usually recommended that viscosifiers be added to the kill fluid.

w Low reservoir permeability may require that the fracture pressure be exceeded.

C

M

M

W

PUMP

PIT

Pressure

Adequate fluid?Adequate weight?

Pump pressure /Rate

Produced fluid type(s)

Tubing condition

Fluid level

Formation Fracture?

Perforation/Formation~vs~

Injector rate

Packer status

Annulus Status

Gas Migration

Rate

Kill point?

Overdisplace?

Considerations for bullheading

WELL CONTROL METHODS7-51

A well cannot be considered dead until the kill fluid has displaced the old fluid in the casing.

BULLHEADING PROCEDURE

1. With the well shut in, determine the tubing pressure (if bullheading down casing, determine the casing pressure).

2. Prepare a rough pressure chart using strokes versus pump pressure. Start out with 0 strokes and SITP at head of chart.

As you bring pump up with just enough pump pressure to overcome well pressure, fluid will start to compress the well gases or fluids until the formation begins accepting them. This pressure may be several hundred psi (bar) over the SITP. Be careful not to exceed any maximum pressure. Pump at planned rates. Normally the pump is slowly brought online, then once the injection is established, it is brought to the desired kill rate, and then slowed back down as the kill fluid is thought to be near the formation.

When injecting the produced fluids into the formation, the added hydrostatic of pumped kill fluid will lower the tubing pressure. Record the actual pressure values on the chart at their proper volume or stroke intervals until at tubing end/bit.

3. Once the kill fluid starts to enter the formation, since it is usually not the same type of fluid, a pressure increase will be seen on the pump. Stop the pump, unless an over-displacement has been approved, shut the well in and monitor.

If pressure is still seen, then gas may have migrated up faster than it was being pumped down, or the kill fluid is not of sufficient density. The lubricate and bleed technique, or a reverse or normal circulation method may be used. It must be remembered that a well cannot be considered dead until the kill fluid has completely displaced the old fluid.

Another bullheading technique, used mainly in drilling requires pumping into the annulus and not allowing returns through the drillpipe. As mentioned, this does have applications such as sour gas, and kick sizes

too large to bring to surface or where surface equipment cannot withstand the anticipated maximum pressure which could be placed on it.

It should be remembered that the decision to bullhead in drilling must be made before hand, as part of the shut in procedure. If there is delay before the decision is made to use this technique, gas may migrate up, and decrease the chances of forcing the kick back into the formation that produced it. Pumping this way, that is, pressuring up the wellbore, can result in formation fracture at the shoe or other weak points in the system.

Working pressure range during Bullhead

Static pressure that would fracture formation

Maximum pump pressure with 150 psi safety factor

Static tubing pressure to balance pore pressure

SU

RFA

CE

PR

ES

SU

RE

(psi

)

TUBING VOLUME DISPLACED (bbls)706050403020100

3500335032003000

2500

2000

1500

1000

0

500

CHAPTER 77-52

Mudcap drilling allows drilling

while managing severe lost

circulation in an overpressured environment.

MUDCAP DRILLING

Mudcap Drilling allows drilling to continue while managing severe lost circulation in an overpressured environment and maintaining control of well. It is used where returns cannot be circulated back to surface. It is also used if annulus pressures at surface approach operational limits, with excessive loss of drilling fluid or if surface fluid handling capacity is exceeded.

In mudcap techniques, the upper portion of the annulus is loaded with heavy, viscous fluid called mudcap. The hydrostatic pressure exerted by the mudcap forces drilling fluids, formation fluids and drill cuttings into weakest exposed open hole zone, and drilling continues as a lighter-than-kill-weight, formation compatible fluid is pumped down drillstring. Mudcap drilling does not require surface fluid handling and processing equipment. It does require high drillpipe/pump pressures to generate enough force to balance formation pressure and induce and maintain fluid injection into weakest zone.

Mudcap drilling offers advantages where formations cannot be drilled by conventional or underbalanced (PWD or flow) methods.

ADVANTAGES OF MUDCAP DRILLING

w Eliminates lost time and money spent combating lost circulation w Reduces surface pressure on annulus w Less complex than flow drillingw Eliminates hydrocarbons, H2S at surfacew Minimizes surface fluid processing equipment

requirementsw Requires less environmental planning than

PWD drilling

DISADVANTAGES OF MUDCAP DRILLING

w More planning than conventional drilling

w Increases logistical requirements over conventional drilling

w More complex drilling and tripping operations than conventional drilling

w Higher pressure rotary drilling equipment than conventional or PWD drilling

w Requires higher pump pressures which may require existing rig pump modifications or alternate pump selection

w Increases requirement for highly trained and competent personnel

w Increases drillstring sticking potential at point of injection by either differential pressure or cuttings/packoff

w Increased formation damage potential

w Drill cuttings and fluid samples can’t be obtained due to well shut in at surface.

There are several mudcap drilling techniques, including pressured and non-pressured. In pressured, a pressure of from 150 to 200 psi (10.34 to 13.79 bar) is maintained on the annulus. The pressured mudcap allows monitoring of annulus pressure to indicate downhole changes. The pressure is maintained against a rotating or control head BOP, often referred to as a Rotating Control Device (RCD).

In the non-pressured technique, annulus pressure is maintained at zero. This does not allow monitoring of annulus pressure. Annulus fluid level can be expected to rise and fall as drilling progresses. The hydrostatic pressure of the mudcap is maintained by varying the density and height of the mudcap in the annulus and may require pumping additional heavy, viscous fluid into the annulus.

In the floating mudcap drilling technique, lost circulation has occurred but drilling proceeds with fluid in the annulus seeking an equilibrium level. The floating mudcap is the equilibrium level to drilling depth.

In the previous techniques mudcap fluid is usually drilling mud with thixotropic properties and a sufficient density to yield a hydrostatic pressure greater than formation pore pressures. Viscosity should be high to minimize gas migration and have the capability to stay in place in the annulus. Typically, mudcap fluid is located within the cased section of the annulus. Some mudcap losses to formation can be expected, and mudcap fluid design should attempt to minimize formation damage.

WELL CONTROL METHODS7-53

Since drilling fluid is pumped into formation, cost is a major factor in selecting fluids.

The drilling fluid injected down the string is usually a clear fluid that produces less hydrostatic pressure than formation pressure. Since drilling fluid is pumped into the formation, cost is a major factor in selecting the optimum drilling fluid. Another factor is compatibility with formation fluids. Clear fluids with minimal density and viscosity are often used. However, with excess torque or cuttings buildup, increasing the drilling fluid’s viscosity may be necessary. Polymers and viscosifying agents (e.g., bentonite) must be carefully selected as both can do irreversible damage to matrix and fractured formations.

Higher pressure rated equipment is typically used in mudcap drilling. Casing and wellhead should be rated to maximum predicted surface pressure plus enough applied pressure on surface to bullhead formation fluids into the formation with fresh water. Other pressure considerations include provisions or placement of a bleed off line between RCD and BOP stack to relieve trapped pressure. Non-ported backpressure valves are incorporated into the string to prevent flow inside the drillpipe. A minimum of two ball or dart type valves are usually run below the MWD/LWD tools, Monels or the downhole motors. Consideration

should be given to the abrasion resistant properties of these valves.

While tripping, a trapped pres-sure phenomenon called squirt com-monly occurs while using some RCDs, though not as severe as in flow drilling. Squirt is a result of the inability of rubber sealing elements to completely seal around grooves in tool joints or the bottom of a tool joint while tripping out of the hole. The trapped wellbore fluids are released when the tool joint is extracted above the sealing element. The amount of volume expelled is directly proportional to the pres-sures below the RCD. A Top Hat or secondary venting device can be installed above these types of RCDs to vent liquids, gas or H2S away from the rig floor. If an RCD has more than one sealing element, squirt is not normally experienced, as that occurs between the elements. Additional equipment and consid-erations include the following:

w Tool joints should not haverough/hard banding, sharp edges or deep multiple grooves. Spiral design collars and BHA components wear on the RCD sealing equipment, and their use is not recommended.

PUMP

PUMPChoke Line

Kill Line

RCD

Convergence Point

PUMP

BOP Stack

Mudcap

CHAPTER 77-54

Well control during mudcap drilling is limited

to maintaining a predetermined pressure on the

annulus.

w Use a short BHA to limit out-of-hole time (pick-up) while changing BHA during trips.

w Tripping is a concern and long life drilling bits should be used to minimize trips

w Positive pulse MWD/LWD and PWD tools usually provide better performance in mudcap drilling than negative pulse tools.

w Chemical pumps may be used to inject oxygen scavengers and corrosion inhibitors if fresh water is used as the drilling fluid. A bactericide can be used to prevent H2S forming from fluid and downhole bacteria.

w Pressure bleed off from high drillpipe pressures during connections is a concern. Pressure venting must be reliable and easy.

w Annulus must be continuously monitored– whether by pressure or liquid level.

w Additional volumes of kill fluid should be kept on location due to the amount of injection and Bullheading involved.

Well Control during mudcap drilling is typically limited to maintaining a predetermined pressure on the annulus, similar to underbalanced drilling. If pressure increases, do not overreact. Pick up off bottom and review drilling parameter trend lines. If annulus pressures increase or approach preset operating limits or pressure limits of the RCD, shut the annular preventer and bleed off pressure between the RCD and annular preventer. Pump additional mud down the annulus to increase size and hydrostatic pressure of mudcap. To evaluate BHP pressure differential, check SIDPP by using procedures to obtain SIDPP value with a float in the string (see Complications chapter). If SIDPP is the same as the initial SIDPP, too much formation fluid may have entered the annulus and/or the mudcap length was reduced. Corrective actions are limited to Bullheading additional mudcap fluid down the annulus until pressures reach previous trend lines and/or increasing drilling fluid density.

If well will be killed, Bullhead kill methods are commonly used. Standard well control procedures are usually not applicable due to

the formation’s lost circulation potential and inability to support a full column of kill weight fluid.

Tripping calls for heightened alertness. Tripping under pressure may be necessary and stripping calculations for buoyant balance point must be determined. Tripping practices follow.

w Remove the annular pressure by bullheading mudcap fluids down the annulus as necessary.

w Bleed off pressure from the drillpipe. Ensure that floats are holding.

w Monitor the annulus while tripping.

w Once drillpipe is pulled to the casing shoe, fill the string with kill weight mud to remove differential pressure from the backpressure valves.

w Evaluate well status and ensure pressure is static or mudcap level is constant. Proceed to POOH and if possible, pump the displacement of each stand (including the BHA if applicable) while pulling. If not possible, circulate across the BOP stack and closely monitor fill.

w Once the top of the BHA is below the RCD, close the annular preventer, check for pressure and remove or open the RCD packing element.

w Pull the BHA out of the hole.

w When the bit clears the blind rams, close the blind rams. If possible bleed trapped pressure, then open the annular.

w Monitor pressure below the blind rams while changing the BHA. Check that no pressure has built up below the BOP. If pressure exists, pump kill fluids into the well until the pressure is zero. Open the blind rams.

w Run the BHA in the hole. Depending on policy, the RCD packing element may or may not be installed at this time.

w Fill the drillpipe at least every 10 stands while tripping in the hole.

w If the RCD packing element has not been installed, install it when the BHA is at the casing shoe.

WELL CONTROL METHODS7-55

When reversing, the majority of pump pressure to circulate is exerted on the annulus.

w As more pipe is lowered, mudcap fluid is displaced and the annulus may show signs of pressure or flow.

w Whenever underbalanced logging is required in an open hole section, a lubricator capable of covering the entire length of the logging tools should be used.

As a subset of tripping, running liners is another area of concern. Underbalanced wells are sometimes completed with an uncemented liner to reduce formation damage from cement. External Casing Packers (ECPs) can be used for zonal isolation. Depending on the completion objective, solid or slotted liners can be used.

A solid liner is run in the same manner as in conventional wells. Monitor the annulus during its run. Surge pressure created by running liner may cause the annular mudcap fluid to be forced downward and perhaps into the loss zone. If this occurs, well may begin to flow at surface. Also, when liner is below mudcap level, upward displacement of lighter fluids may allow well to flow. Annular preventer or casing rams should be closed and the mudcap fluid pumped until desired annulus pressures are obtained.

It is more difficult to run a slotted liner because there is communication between the liner ID (through slots) and annulus. With slotted liner across BOPs, well cannot be shut in. The potential for this complication can be minimized by having a liner to safety valve crossover and a safety valve made up on a drillpipe joint. If necessary, this assembly can be installed and run across BOP, and BOPs closed. Surge pressures will be less than those for a conventional liner because of communication between liner ID and annulus. However, annulus still must be monitored and kept full at all times.

REVERSE CIRCULATION

Reverse circulation, as the name implies, is a reversal of normal circulation or standard well kill pump direction. The pump is lined up to pump down the casing annulus, and returns are taken through the string to a choke manifold.

ADVANTAGES OF REVERSE CIRCULATION

w It is the shortest or quickest route to circulate something to the surface.w It gets the problem inside the strongest

pipe from the start.w Many times the annular fluid (packer

fluid) is sufficiently dense to control the formation, which minimizes fluid mixing and weighting requirements.

DISADVANTAGES OF REVERSE CIRCULATION

w The largest percentages of frictional pressure losses are inside the smallest diameter. Usually, this will be in the tubing. When reversing, the majority of pump pressure to circulate is now exerted on the annulus. In drilling, weak formations may not withstand the extra pressure. In remedial operations, weak or bad casing may fail, or if high rates (resulting in high pressures) are attempted, gas filled and/or weak tubing may collapse from the pressure differential.

w Reverse circulation is generally not recommended where there is danger of plugging circulating ports, perforations, or bit nozzles in the string with cuttings or debris in the well and where there chances of loss circulation or stuck pipe.

w If the tubing is gas-filled, there may be difficulties establishing and maintaining circulating rates and pressures due to its expansive and compressive nature. The choke operator should expect that a slight adjustment might create large changes in circulating pressure.

w If there are different density fluids throughout the circulating system, calculating pressures to maintain can become complex.

w If there is gas in the annulus, it may migrate upward faster than the pumping rate. The addition of viscosifiers may reduce this problem, but will increase the pump pressure.

w If there is a possibility of H2S gas being present, ensure that the gas is routed through the proper piping, separation and flare equipment.

CHAPTER 77-56

In areas where air drilling is accepted

practice, water is scarce and not

usually found on location.

The basics for reverse circulating are essentially the same as for any constant bottomhole method. It differs in that no circulating rate or pressures are predetermined. The pump must be brought up to speed, bottomhole pressure stabilized and circulating pressure established.

It also differs that instead of using tubing pressure to monitor bottomhole pressure, the casing gauge is used. Instead of using back or choke pressure from the casing, backpressure is exerted from, and the choke is run off the drill string or tubing. It should be noted that if gas is not already at surface, it will reach the surface much sooner than regular circulation.

Often, when a circulating port is opened in the tubing, fluids in the annulus will U-tube. This may require pumping at a very fast rate to fill the annulus, just trying to catch up with the dropping fluid level. This problem can be minimized by keeping the tubing’s choke closed until the pump start up procedure can begin.

When bringing the pump on line, tubing pressure should be held constant. This may not be easy when the tubing string is full of gas. Once the pump is running at the desired speed (also accounting for the time lag it takes to stabilize throughout the system), casing (now pump) pressure is held constant until the tubing has been displaced. This is very similar to the Driller’s Method.

Complications can occur when the annular fluid is not the proper density to control the formation. Consideration should be given whether to circulate and displace the tubing and annulus, then weight up, or to increase the weight and circulate using a Weight and Wait technique. If the packer fluid is too heavy, fluid loss and formation damage may occur.

If tubing is full of formation gas, friction pressure change as kill fluid circulates upwards cannot be accurately calculated. Standard circulating techniques are inadequate. Under these circumstances, the estimated hydrostatic gain in tubing can be calculated, and choke pressure decreased by that amount. Prepare a chart of pressure to hold, versus strokes, and use it as a guideline. A standard kill sheet pressure chart will help to plot the pressure.

AIR DRILLING WELL CONTROL

Generally, a kick is defined as an unwanted intrusion of liquid or gas into the wellbore. The principles of air drilling allow kicks until the formation is producing at a large enough rate that air drilling must be discontinued or the conditions are no longer safe. When the influx rates are too high, the decision may be made to fluid up, or water the hole and kill the well. In many areas, it is very rare to shut the well in, unless there is equipment failure, or if higher than expected pressures and production are encountered. (This prevents the hole, and casing shoe from pressuring up.)

Depending on the region and accepted practices for the area, well killing techniques can differ. In some areas, changing from injecting air to pumping water (still taking returns through the blooie line) is common practice. In other areas, water may be used, but returns are taken at the choke line. In other areas, wells are completely shut in and the hole filled by pumping into a kill line (using a method similar to Lubricate and Bleed).

In areas where air drilling is accepted practice, a common consideration when it is necessary to kill the well is saving water. Water often is scarce and not usually found on location. Fresh water is used in some areas, but often it is brine water, produced from wells in the area. It must be hauled in, and stored in tanks or storage pits. Supplies are limited and efforts are made to reduce downhole losses.

Whether taking returns through a blooie or choke line, most kill techniques pump water down the drill string to the bit. A high pump rate is used due to vacuuming of the drill string. Vacuuming is simply the producing formation pulling a suction on the drillpipe. There is also a tremendous differential between the weight of water being pumped, and the formation gases in the annulus. For these reasons, the water is pumped at a high rate down the drill string. In many areas it is common practice to slow the pump rate down just prior to when water is calculated to reach the bit, to prevent a sudden increase (or surge) in pressure on the pump.

WELL CONTROL METHODS7-57

It defeats the economics of air drilling to water the hole and perform a leak-off test.

From this point, different techniques can be used. These techniques depend largely on the geology, the estimated or known formation fracture gradients, what equipment is on hand or can be rigged up and what works best for the area. The simplest technique is to continue pumping at a high rate. Once sufficient water hydrostatic has built up in the annulus, the formation ceases to flow and the well is killed.

Another technique that gives more precise control of pressure is circulating through a choke. Since the choke system has a smaller diameter than the blooie line, circulating through the choke will impose more backpressure on the well. The extra backpressure may be enough to keep the well from flowing, or it may require using a choke technique.

Choke techniques use different variations to maintain the equivalent hydrostatic pressure of water to regain control of the well. In one technique, as soon as the water rounds the bit, the choke is closed enough to exert the water’s hydrostatic as backpressure. As water is circulated up the hole, the backpressure is gradually decreased by the calculated gain in water hydrostatic. It should be pointed out that the formation gases also exert hydrostatic pressure. For this reason, a safety factor is usually used to prevent the well from pressuring up higher than the equivalent weight of the water used. (Remember, the water may be brine and weigh more than fresh water.)

The safety factor is the weight of the water being used less the estimated weight of the formation gasses. Suppose a well was to be mudded up using a 9.3 ppg (1114 kg/m³) brine, and the estimated formation gasses (including misting of formation liquids) was estimated to be 2 ppg (240 kg/m³). To calculate the equivalent pressure to start holding: 9.3 ppg – 2.0 ppg = 7.3 ppg (1114 – 240 = 874 kg/m³), and is multiplied by the depth (TVD) and by 0.052 (0.0000981) to give the equivalent hydrostatic or backpressure to use initially on the choke as the brine starts its way up from the bit.

From volume, strokes pumped, or according to time, the estimated gain in hydrostatic pressure can be calculated, and choke pressure decreased by that amount. This can be simply done by

constructing a chart of pressure to hold, versus strokes pumped. A standard kill sheet pressure chart will suffice, but remember it is choke pressure, not tubing or drillpipe pressure, being plotted. Many air drilling operations do not use fluid pumps so a drillpipe pressure gauge is not required equipment. If it becomes necessary to kill the well using a conventional method (Driller’s, Weight and Wait, etc.) then these gauges become necessary.

Another technique uses the same principle of removing backpressure as hydrostatic is gained, except that the pressure is not applied on the choke until water is estimated to be at the casing shoe. And then, it is only the equivalent hydrostatic from the shoe to surface that is held. As hydrostatic is gained above the shoe, the equivalent is bled from the choke. This last choke technique is based on many unknowns.

Often the formation fracture or formation strength at the casing shoe is not known, or known by personnel on location. It defeats the economics of air drilling to water the hole to perform a leak-off test. Therefore, in many areas this is not performed. Little is known about the structural integrity of the formation, or the quality of the bond between the cement and casing. Because of this, many people used to (and in many areas still do) use a rule of thumb of choke pressure to hold. This rule of thumb is to take half the casing depth and use that figure as psi of pressure to hold. In other words, if casing were set at 500’ (152.4 m) then the backpressure to hold would be 250 psi (17.2 bar).

Whichever method is used, an advantage is gained by using backpressure. If the influx is gas and at a high enough rate, it may produce a mist from the kill fluid. Water is precious in many regions and this mist may not be recoverable. Holding backpressure through the choke slows the rate of expansion, allowing water droplets to fall back down hole and reduce misting and the amount of water lost.

Once the fluid has reached surface, the well usually has been killed due to hydrostatic pressure of water. If well continues to flow, conventional circulating techniques must be used.

CHAPTER 77-58

In slim hole wells more than 90

percent of the hole length is

drilled with bit diameters that

are smaller than 7”.

MULTI-COMPLETION ANDMULTILATERAL CONSIDERATIONS

When producing from multiple zones or wellbores, well control is generally limited to one or more of the following procedures, selected on a case by case basis.

w Mechanical barriers. If zonal isolation is possible, conventional techniques may be used. Each producing zone may be separately controlled/killed. Mechanical plugs may be set to achieve isolation.

w Fluid barriers. Plugs, pills or cement may be spotted across a producing zone to achieve isolation or pressure control. Depending on the well type (i.e., gas), this alone may not be sufficient to maintain a degree of safety.

w Live well intervention. Coiled tubing and snubbing units are used to work on wells with multiple zones. They are also used to set mechanical barriers or perform circulating kill on producing zones.

w Bullhead kill. Depending on zonal integrity and characteristics, bullheading may be used. It is difficult to determine the zone taking fluid and if downward momentum of fluid is displacing produced fluids back into the formation.

SLIM HOLE CONSIDERATIONS

This discussion on Slim Hole is based on drilling applications, but the principles and suggestions apply to all small annular applications.

Slim Hole refers to wells where more than 90 percent of the hole length is drilled with bit diameters less than 7” (177.8 mm), or drilled with bits smaller than those in a conventional hole at the same depth. Ultra Slim Holes are wellbores in the 4” (101.6 mm) range.

Well control concerns for slim annular versus conventional annular configurations focus on high annular friction while pumping, on heightened chances to swab in a kick, effects of extensive vertical height of even small kicks and the resultant rapid evacuation of the annulus.

Multilateral well control

WELL CONTROL METHODS7-59

One well control concern for slim annular versus conventional configurations is the high annular friction while pumping.

High annular friction may lead to fluid losses while circulating. If formation breakdown results, the liquid column may decrease, allowing a kick to occur. It is possible to drill in underbalanced conditions with high ECDs (annular friction pressure loss) preventing the well from flowing. However, if the pumps are shut down, the potential for the well to flow may exist. If you are using jointed pipe, then connection time should be minimal.

As previously discussed, the selection of pump rates may be critical. Kill rate speed and pressures must keep the annular friction manageable. The use of downhole pressure sensor tools (if and when available in smaller sizes) to determine annular friction is recommended. If they are unavailable, then friction calculations (preferably with the use of computer programs) may be performed.

Due to the smaller clearance, swabbing potential increases dramatically. Calculations for trip speed at a given depth should be made and followed. In some instances, tripping without pumping out of the hole may not be possible without a high potential for swabbing.

Each barrel (m³) of influx will extend upwards many more times in length than it will in non-slim hole wells. This may result in a higher initial SICP and in higher pressures at weak points along the wellbore (considering the influx is below those points). Every effort to minimize kick size should be taken. The influx comes to surface much quicker and has the potential for very high expansion as it travels upwards. If undetected at first, this potential may quickly evacuate the fluid above the influx as expansion occurs. When circulating through the choke, high gas flow rates at the choke may be experienced, requiring a rapid response as the influx expands.

KICK DETECTION

While drilling, kick detection is basically the same between Slimhole and Standard techniques (i.e., ROP, the increase in flow, pit gain, pump pressure decrease, pump speed increase, gas/oil shows, string weight changes). However, a kick must be detected on a much

smaller increase in flow, a smaller gain in pit or during the earlier stages whenever possible.

While tripping, the same warning signs are applicable as in conventional wells (i.e., the hole takes less than the calculated fill, the hole does not take any fluid to fill, the well starts to flow, a gain in the pits).

Remember that the volumes and reaction times are smaller in slim hole than during standard drilling, and it is easier to swab a kick in.

Pointers for slim hole kick detection follow:

w Always use a trip log sheet.

w Calculate the pipe displacement accurately.

w Calculate the theoretical fill.

w Measure the trip tank accurately.

w Record the actual values.

w Compare against theoretical values.

w Consider U-tubing of the slug affecting several fillups.

w Consider a pumpout to non-swab potential depth.

KICK DETECTION EQUIPMENT

Besides existing kick detection equipment (flowline sensors, pit-volume totalizer, trip tanks, stroke counters, pressure gauges, torque/drag indicators), consider the following:

SENSOR PACKAGE/DATA ANALYSIS UNIT

w Stroke Counters

w Flows in per pump

w Standpipe Pressure

w Casing Pressure

w Bell Nipple Pressure

w Flows out per each line

w Mud Density in

w Mud Density Out

w Mud Gas Level

w Mud Level in each tank

w Depth indicators

w MWD/LWD tools

CHAPTER 77-60

COMMUNICATIONS

After each team member has received his or her instructions and job responsibilities, then the work can begin. The information gathered during that phase can be checked for changes from the norm. These changes can be subtle enough that reporting this insignificant change may be considered trivial. All changes, no matter how slight, should be reported to a supervisor. If you are in doubt, communicate. Remember that well control is a team effort.

OTHER CONTROL TECHNIQUES

This chapter discussed the main well control options. Each well is unique, so well control and contingency plans need to be developed on a case by case basis. Techniques such as Low Choke Method, Dynamic and Momentum Kills, etc., are specific and more

advanced techniques. They have not been included in this section. The potential for misuse, misunderstanding, and loss of life, equipment and resources is high and extreme caution should be exercised. These techniques should only be used by personnel who have been specially trained for this particular kind of work.

SUMMARY

Proven methods of well control exist. These methods have advantages and limitations. Pressure, kick type, well control problems, location, rig and well type affect the choice for the proper method to control a well. Often several (Bullheading, Reverse Circulation and Driller’s) are incorporated into a well killing operation. Experience and common sense are the two most important factors for method selection. t

Think of the six methods of well control as tools.

ü Driller’s Method

ü Wait and Weight

ü Concurrent

ü Volumetric

ü Lubricate and Bleed

ü Bullheading

Choose your tools according to wellsite specifics.

Each well is unique, so well

control and contingency

plans need to be developed

on a case by case basis.

WELL CONTROL METHODS7-61

A BRIEF REVIEW OF THE THREE PRIMARY CIRCULATING WELL KILLING METHODSWELL HAS BEEN SHUT IN ON A KICK. KICK SIZE, STABILIZED SIDPP AND SICP ARE RECORDED.

DRILLER’S METHOD

1. Begin circulating original mud by slowly bringing the pump up to the kill rate while using the choke to maintain the casing pressure at the shut-in value.

2. Compare the pump pressure to the calculated initial circulating pressure (ICP). If not equal, investigate.

3. Circulate the influx out of the well at the kill rate, maintaining constant pump pressure with the choke.

4. Either continue circulating from isolated pit or simultaneously shut down the pump and close the choke to prevent trapping pressure or additional influx. (SIDPP should equal SICP).

5. Weight up the active system to the calculated kill fluid density.

6. Circulate the drillpipe full of kill fluid at the kill rate, while using the choke to hold the casing pressure constant at its last shut-in value.

7. When kill fluid is at bit, change from casing pressure control to pump pressure control (should be equal to calculated Final Circulating Pressure). Keep pump pressure constant with choke until well is full of kill fluid.

8. Shut down pump and check for flow; close the choke, and check for pressure build-up.

WAIT AND WEIGHT METHOD

1. Weight up the active system to the calculated kill fluid density.

2. Calculate a drillpipe pressure schedule/graph.

3. If shut-in pressures increase significantly due to gas migration, use the Volumetric Method by bleeding off mud from the annulus maintaining constant drillpipe pressure.

4. Begin circulating kill weight fluid by slowly bringing the pump up to the kill rate while using the choke to maintain the casing pressure at the shut-in value.

5. Compare the pump pressure to the calculated initial circulating pressure (ICP). If not equal, investigate and recalculate if necessary.

6. Displace drillstring with kill weight fluid, adjust drillpipe pressure according to calculated schedule using choke.

7. When the kill mud reaches the bit the circulating pressure should be at the calculated FCP.

8. Maintain the FCP using the choke while pumping at the kill rate until the kick is out of the well and the annulus is full of kill weight fluid.

9. Shut down pump and check for flow; close the choke, and check for pressure build-up.

CONCURRENT METHOD

1. Begin circulating original mud by slowly bringing the pump up to the kill rate while using the choke to maintain the casing pressure at the shut-in value.

2. Compare the pump pressure to the calculated initial circulating pressure (ICP). If not equal, investigate.

3. Begin weighting up active pits while pumping. Each point of fluid weight increase should be recorded with the pumps stroke count at that time.

4. The total strokes to get each unit of increase in mud weight to the bit is calculated.

5. As each point of heavier mud reaches the bit the choke is adjusted to reduce circulating pressure by: (ICP – FCP) ÷ [(KMW – OMW) × 10]

6. When the kill mud reaches the bit the circulating pressure should be at the calculated FCP.

7. Maintain the FCP using the choke while pumping at the kill rate until the kick is out of the well and the annulus is full of kill weight fluid.

8. Shut down pump and check for flow; close the choke, and check for pressure build-up.

CHAPTER

8

Few well control

operations are textbook

perfect. It is vital to

familiarize yourself

with complications to

prepare for them.

COMPLICATIONS

8-1

W hen complications arise during any activity, experience and common sense will usually solve the problem.

Once the problem is identified, various solutions may be tried until it is solved. It is imperative to keep good records. Without records of what trend is developing or the sequence of events, many complications cannot be easily solved.

SHUT-IN PRESSURES

Shut-in pressures are not normally consid-ered a complication. However, complications can result if the shut-in pressures are too high or low. Stabilized pressure values are essential to minimize potential problems during well kill activities.

CHAPTER 88-2

Shut-in DP/Tubing pressure has tobe determinedwith BPV in string.If BPV holds,DP/Tubing pressureis zero.

0

HP

FormationPressure

Once a well is shut in, write down the time of kicks and record pressures every minute until they begin to stabilize. Factors such as formation characteristics, pressure, depth, fluid type and influx type all affect the time it takes for the wellbore to reach equilibrium and pressures to stabilize. This is why a set timeframe for pressures to stabilize is impossible to predict.

From the recorded pressures, kill weight fluid is calculated. Also, the annular pressure is held constant while bringing the pump up to speed to kill the well. If the recorded pressures are too high, an excessively weighted kill fluid may be mixed, and while bringing the pump online, excessive pressure could be held. These complications could result in lost circulation problems. If recorded pressures are too low, the kill fluid may not be adequately weighted and insufficient circulating pressures may be maintained, thus allowing additional influx.

As mentioned earlier, the assumption is that shut-in pressures are correct. If proper shut-in procedures are used and recording begins immediately, determination of correct pressures

is usually an easy task. However, if shut-in pressure is thought to be too high, a small amount of pressure should be bled from the choke, and the corresponding changes monitored closely. Several small bleed-offs may be required to confirm correct pressures. It should be remembered that if the original pressures were correct, additional influx could enter the well, resulting in a slightly higher casing pressure.

Shut-in drillpipe pressure is generally lower than shut-in casing pressure because the kick density is usually much lighter than the fluid in use. If the influx is liquid and has a higher density than the fluid in use, SIDPP will be higher than SICP. This is common in some remedial operations. Other causes include trapped pump pressure, blockages, quick setting gels and gas entering the string. If the fluid in the string is not uniform, such as when gas migrates into it, SIDPP will not be correct. By circulating slowly with the Driller’s Method and pumping several barrels (m³) to ensure the string is displaced with good fluid, the well may be shut in again and the SIDPP established.

Trapped Pressures?

Float (BPV)?

Fluid Type?

Gel Strength?

Solubility?

Formation Permeability?

Well Depth?

Well Geometry?

Kick Type?

Kick Migration?

A BPV in the string will cause the initial shut-in pressure to be zero or unreliable. Many variables affect shut-in pressures.

It is not possible to predict a

timeframe for shut-in pressures

to stabilize.

COMPLICATIONS8-3

FLOAT, CHECK OR BACKPRESSUREVALVE (BPV) IN STRING

Floats, check valves or BPVs are commonly used in the string. They are used for pressure work, directional drilling, MWD/LWD tools and preventing the annulus from U-tubing. Company policy and field experience will dictate the use of floats in different intervals of the hole. A float has the effect of either making the shut-in drillpipe pressure read zero or reading some unreliable intermediate value.

To obtain a correct shut-in drillpipe pressure, the string must be pressured until the float opens. There are several ways to do this, depending on the pump drive system.

w Pressure the pipe up in small increments, kicking or rocking pump in and out. Pressure in the string will increase with each increment. The pressure increases as pump is kicked in, then breaks back when pump is kicked out. Pressure to which it drops is SIDPP value.

w Slowly pressure up the string. It is best to use a high pressure/low volume type of pump, similar to a cementing pump. Closely monitor the pressure gauge indicator needle. A small dip or break back may be noticed when the BPV opens. This point will be the SIDPP value. Pressure inside the string equalizes with well pressure outside.

w Another method, if kill rate pressures were taken recently and are accurate, is to open the choke, bring the pump up to the desired speed, then adjust casing pressure back to the value it had before you started the pump. When standpipe or tubing pressure stabilizes, subtract the kill rate pressure value from it. This is the SIDPP. When using this technique, use the slowest rate to avoid adding extra circulating friction, which results in a SIDPP higher than what it should be.

SIDPP =Circulating Pressure – Kill Rate Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

When pressures stabilize, line up pump on the string.

Slowly rock pump or pressure string in set increments. Stop after each increment.

If pressure holds, pressure up another increment.

Again, if pressure holds, pressure up another increment.

When pressure drops back, the reading it drops to is the Shut-in Pressure value on drillpipe or tubing.

There are several methods for determining the current Shut-in Drillpipe/Tubing Pressure with a BPV in the string.

8-4CHAPTER 8

w If the pump can be rolled over or high pressure/low volume pumps can be used, pump the equivalent of one-half barrel (0.8 m³) and stop; check the casing pressure. Repeat until the float opens and an increase in casing pressure is noticed. Subtract the increase in casing pressure from the pressure reading on the string. These steps should be repeated after bleeding casing pressure back to its original value. The pressures should agree within 100 psi (6.89 bar).

EXCESSIVE CASING PRESSURE

If casing pressure reaches a point where it could exceed burst pressure, shutting down or slowing down the pumps may be required. If shut-in pressure continues to rise, take action immediately. Bleeding off pressure may not be enough and may be courting disaster. Analyze the situation by using all information available. Reach a conclusion based on facts, not guesswork, and take proper action. If

circulation is being lost, the situation may call for lost circulation material. Has a new zone been penetrated or perforated which might have an abnormally high pressure? Could shallow sands up the hole have been charged up earlier in the life of the well and now be coming in through corroded or damaged casing? Analyze and eliminate false assumptions. Don’t rule out or overlook the unusual. Don’t hesitate to call for help. Slowly pumping heavier fluid, shutting down and bleeding off, and then pumping again may be the answer

Maximum casing pressure can be based on the pressure required to break down the formation, casing burst or BOP stack pressure limitations. If a maximum allowable pressure is posted on the rig, the reason for the limitation should be posted also. In general:

w Maximum allowable surface pressure may depend on casing burst.

w Maximum allowable surface pressure may depend on BOP stack rating.

w Lost circulation is usually the safety valve for high pressure and will occur before the mechanical limitations are reached.

30 SPM

Drill PipePSI

CasingPSI

30 S P M

Plugged

Drill P ipeP S I

C as ingP S I

Left and right: before and after

a partial blockage in the string.If pump rateand casing

pressure don’t change,

BHP remains constant.

Lost circulation is often the

safety valve for high pressures

in a well.

8-5COMPLICATIONS

KILL RATE PRESSURE IS NOT AVAILABLE OR RELIABLE

A correct circulating or kill rate pressure is essential in most well control methods. In many non-drilling activities, the kill rate pressure is not taken. In drilling, mud properties, string components, or depth may change enough to make the last kill rate pressure unreliable.

To find or develop a new kill rate pressure:

1. Open the choke slightly before starting the pump.

2. As the pump is being brought up to the desired kill rate, hold the casing pressure constant at the shut-in value.

3. When the pump is up to the desired kill rate and the casing pressure is adjusted to the same pressure as when shut in, record the circulating pressure.

4. Under these particular conditions, this circulating pressure will be the initial circulating pressure (ICP).

5. To find the kill rate pressure (KRP):

KRP = ICP – SIDPP (Or more simply, any-thing above SITP value must be pump pressure.)

To demonstrate: A well was shut in and the pressure determined (SIDPP = 300 psi [20.68 bar], SICP = 800 psi [55.16 bar]). The pump is brought online, and casing pressure is adjusted back to 800 psi (55.16 bar). The drillpipe pressure stabilized at 900 psi (62.05 bar), so:

KRP = ICP – SIDPP = 900 – 300 = 600 psi

KRP = ICP – SIDPP = 62.05 – 20.68 = 41.37 bar

When using this technique, be sure to circulate long enough to break the initial gel strength of the fluid. The new circulating pressure will be closer to the true value after the fluid has been circulated to break some of the original gel strength.

PUMP FAILURE/CHANGING PUMPS

Pump rate and volume are important. If the pump fails or is not operating correctly during well control operations, change to another pump using the following steps.

1. Slow down and stop the pump, while holding the casing pressure constant.

2. Shut the well in.

3. Switch to the alternate pump and bring it up to the desired kill rate.

4. When second pump is up to desired kill rate, and casing pressure is the same as when shut in the second time, record the circulating pressure.

5. This value will be the new circulating pressure. Pressure may be higher or lower than first pump’s pressure because of efficiency or output differences. Depending on stage of well control operation, circulating pressure may be initial, final or some intermediate pressure.

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Hold casing pressure bringing pump online.

Pump at kill rate, casing pressure ok.

Accurate kill rate pressures are necessary if a kick is to be circulated out safely.

CHAPTER 88-6

In the event of sudden pump failure the well should be shut back in and volumetric techniques implemented until it can be repaired or another brought on line.

BLOCKAGES IN THE STRING

A blockage such as a plugged nozzle is indicated by an abrupt increase in circulating pressure. The choke operator should not overreact by opening the choke to bring circulating pressure to its prior value. This may allow additional influx into the well. Instead, and providing that a partial plugging problem does not exceed maximum pump pressure, observe casing pressure and immediately ascertain that the pump rate has not changed. If casing pressure does not increase, or remains approximately the same, it is an indication that a partial blockage exists and the new pump pressure value should be taken as the new circulating pressure.

If the pump pressure value is too high, or if uncertainty exists as to what the new circulating pressure should be, stop pumping and shut in the well, then re-establish the correct shut in pressures. To determine the new circulating pressure, bring the pump online while holding casing pressure constant. With pump at the desired speed, the circulating tubing pressure will represent a correct circulating pressure at the present stage of the kill operation. If this occurs while circulating kill fluid down the string, a new final circulating pressure and strokes vs. pressure chart must be calculated.

A total blockage problem will cause a sudden and increasing pump pressure and casing pressure will begin to decrease. The casing pressure value should be immediately adjusted to the proper value.

Can BHP > FP BEProperlly Maintained?

Kic

k

Kic

k

Severity ofWashout?

Kick Position?

New shut-in pressures can indicatethe position of the influx.

Casing PressureTubing Pressure

Casing PressureTubing Pressure

Casing PressureTubing Pressure

If pump becomes too erratic. . .

Shut it down and shut well in maintaining casing pressure.

Swap pumps and bring up to speed holding casing pressure constant. Pressure on tubing is the new circulating pressure.

An abrupt increase in circulating

pressure may indicate a

blockage in the drillstring.

COMPLICATIONS8-7

Suggestions to clear a complete blockage or reestablish circulation in the past have included:w Surging the blockage by rapidly increasing

and decreasing the pump rate.w Perforate the string above the blockage.w Use of a string shot or shaped charges

near the blockage.

HOLE IN THE STRING

A hole or washout developing during well control activities is rare. It may also be difficult to detect a small hole that develops in the string while circulating other than increases in fluid density out of the well earlier than planned or perhaps a quicker response time for the transit of pressure changes on the choke. If the string remains static (no pipe movement) it is unlikely that a hole would develop at a lower pressure than typical circulating pressures. However, the hole may enlarge or the string fail from stresses created by movement of pipe and/or rotation.

Generally, a hole in the string will cause a decrease in circulating pressure. During well control conditions the choke operator will typically respond by adjusting the choke to compensate for the decrease in pressure and create higher than required pressure in the annulus. This may lead to more complications. Chances of detecting a hole in the string increase if the hole is large and occurs suddenly.

Likewise, under normal circumstances, if a washout is suspected, a marker (paint, dye, etc.) is pumped and returns monitored. From strokes or volume pumped when the marker surfaces, estimations can be made as to its location. Caution should be used if additives such as nut plug or soft line are used to detect the washout. Under slower circulation rates they may plug the jet nozzles.

The position of the washout may dictate what actions will follow. Actions should be taken to prevent the washout from enlarging. In a well control activity, maintaining bottomhole pressure is paramount. Maintaining circulating pressure according to plans may increase or decrease pressures in the annulus, depending on where the washout is located and its severity. Perhaps the best course of immediate action is to shut the well back in and monitor pressure. If the shut in pressures (on string and choke) are essentially the same, the washout is above the influx. When the shut in pressure on the string is lower than pressure on the choke, the washout is below the influx.

Circulating to kill the well is a judgement call. If washout is below influx, an attempt may be made to circulate and kill the well. Since the circulating pressure with washout is not known, procedures in “Kill Rate Pressure Not Available or Reliable” in this section should be followed to establish a reliable pump pressure. Even so, periodically the well should be shut in and new pump pressures established if washout worsens, or existing pump pressure validated if it does not. Trying to establish

Small washouts can enlarge and become big problems if circulation continues.

A hole in the string will usually cause a decrease in circulating pressure.

8-8CHAPTER 8

and maintain a new pump pressure when the washout is above the influx will not take gas expansion into account and may allow bottomhole pressure to drop.

Use volumetric techniques if it is suspected that pumping might create complications. Other possible actions are stripping out of the well and replacing the bad joint, pumping a dart down the string to isolate washout, or using a coiled tubing, snubbing or small tubing unit to run a kill string inside damaged tubing.

PIPE TOO BADLY CORRODEDTO PULL FROM THE WELL

When fluid cuts, or erodes seal areas or corroded sections of tubulars, a washout may occur. A washout in the pipe may be indicated by a gradual decrease in pump pressure. Washouts are progressive and may cause string failure. During a well kill operation, a washout might be indicated if the kill fluid is detected at the choke (return) line before calculated.

Sometimes in corrosive wells where inadequate or no chemical treatment was used, the tubulars deteriorate to the point of total failure. The pipe must then be washed over and fished out of the hole. This can be a long and frustrating job if only small sections can be recovered with each trip in the hole. Where there is communication between tubing and the annulus, it may be difficult to kill a well without putting excessive pressure on the casing. Care must be taken not to assume that kill fluid has been displaced to the total depth of the string and circulated throughout the well.

PRESSURE GAUGE FAILURE

Although rarely a problem, it is possible for a gauge to malfunction or fail during any well control operation. Most units contain several pressure gauges that can be used to read shut in and circulating pressures. In addition to the set of primary gauges that will be used, it is advisable to identify and record pressure values from all the gauges that may be used during a well control operation.

Little / No Flow

Blockage

Full Flow

Circulation is Restricted

Full Flow

Full Flow

Circulation is Unrestricted

If choke plugs, flow diminishes

and pressure increases.

It is good practice to

record pressures from all gauges

that may be used during a

well control operation.

8-9COMPLICATIONS

Remember that there may be variations in pressure readings from one gauge to another. Also, keep in mind that if a primary gauge fails, the alternate gauge may be remotely located. This will also require a communication network to relay pressure readings and what adjustments must be made on the choke and pump to successfully continue the control operation. If electronic communications are not available or malfunctions, then hand signals or runners may be required.

CHOKE/KILL MANIFOLDAND DOWNSTREAM PROBLEMS

Alternate flow routes are usually provided on the choke/kill manifold in the event of plugging or washouts. This may require that flow be redirected through a different choke. Common sense and observing the sequence is vital to troubleshoot these problems. The pressure gauge on the kill manifold gives a good indication whether the problem is

upstream or downstream of this gauge. For example, if choke pressure rapidly bleeds off, even with the choke operator trying to maintain correct pressure, the plugging problem is upstream of the pressure sensor. Or, if pressure begins increasing and not responding to choke adjustment, the blockage may be downstream of the choke. Once the problem is identified an alternate flow path may be chosen.

If the mud gas separator becomes plugged, flow may have to be redirected to the flowline and bypass the line to the mud gas separator until it can be unplugged. Caution should be used, as the flow may be flammable. Consideration should be given to shutting the well back in until the necessary repairs are completed.

ANNULUSBLOCKAGE/COLLAPSE

If the annulus should become totally blocked or collapses during well control operations, circulating pump pressure will begin to increase while choke pressure decreases. If pumping continues, pressures below the blockage will pressure the wellbore, thereby increasing the risk of formation failure/fracture. The pump should be shut down and the choke closed.

There are many possible solutions to this problem. But well control should be the primary concern. It may be possible to cut the pipe above the pack off, controlling the well to that point with heavier fluid. Although not killed, the well may be static, allowing other fishing or wash over activities until full circulation may be possible.

PUMP

Well caving in and blocking circulation up from the bottom of the well

Well-designed choke manifolds include alternate flow routes, thus anticipating complications.

CHAPTER 88-10

Losses can be attributed to causes other than lost circulation. Large amounts of fluid can be expelled from improperly working solids control equipment. If a shale shaker screen is blinded for example, cuttings and fluid will be lost. Other solids control equipment such as mud cleaners, centrifuges and desanders can expel significant volumes. High rates of penetration and deepening, especially in large bore hole can result in a pit volume decrease that may be interpreted as a loss. In addition, dumping a sand trap or adding fluid to the active circulating system without notifying the driller can be interpreted as pit gains or losses.

CASING DAMAGE OR FAILURE

Casing is the main defense against undesired fluid migration from one zone to another. Casing protects the formation from well pressures and the wellbore from formation pressure. This allows us to drill deeper with higher mud weights. It supports the walls of the well and prevents contamination from other zones. Casing also serves as a barrier to protect fresh water zones from the wellbore.

PIT CHANGES

While not always considered a complication, a word or two about changes in fluid level in the pits is appropriate. A change in the level of the pit is often one of the first indicators noticed in kick detection or lost circulation. It may be true in some operations that gains and losses are normal. However, pit changes should be reported and treated as possible warning signs until it is proven that a complication does not exist. The Driller should be notified prior to additions, dumping or fluid transfers and the change noted on PVT charts and recorders.

Kick size may be the most inaccurate estimate used in well control problems, but it is important that it be reported as accurately as possible. Many calculations - such as estimates of kick density, projections of maximum volume displaced and maximum anticipated surface pressure - depend on accurate readings. Drain back from flow lines and solids control (if shut down) should not be included in the reported size of the kick. If the drain back volumes are determined and posted, accurate pit gains and losses will be easier to report.

Bell Nipple or

Diverter Housing

Gumbo Box

(Optional) Primary ShakersHigh Performance Shakers (Optional) Degasser Desander Centrifuges Desilter /

Mud Cleaner

MUD PITS

Drain Back When Pump Is Shut Down

Kick size may be the most inaccurate

estimate used in well control

situations.

COMPLICATIONS8-11

Pressure between casing strings is an indication of failure and its cause should be determined.

The deterioration of casing is a serious matter. Temperature in excess of 250° F (121° C) will start to affect the properties of the casing, while a temperature of 300° F (149° C) will reduce the casing’s performance by 10%. A steel derating factor vs. temperature should be used in casing design. Sometimes holes in the casing appear opposite formations bearing corrosive fluids. Damage and wear in the casing can occur from extended pipe rotation and from running tools. Leaks can start where joints were improperly stabbed, doped or made up. Casing may collapse, or formation movement may shear it.

Under well control conditions, a hole in the casing may be difficult to identify because the symptoms are similar to that of lost circulation. The solutions listed under lost circulation should be investigated while attempting to identify the complication.

PARTIAL LOST CIRCULATION

Often the first sign of lost returns during a kill is fluctuation of gauge pressure and/or a fluid level drop in the pits. If well will circulate, but pit level is dropping because of partial lost returns, several techniques may be tried.

w No pressure safety margin should be held if lost returns are suspected. If the fluid volume can be maintained by mixing, continue. Pressure on the thief zone is reduced after the kick is circulated above it, so the problem may solve itself.

w Choose a slower circulating rate and establish a new circulating pressure. The slower pumping rate will reduce frictional pressure losses occurring in the annulus. With the well shut in, the procedure to establish a new circulating pressure is essentially the same as bringing the pump on line, covered in “Kill Rate Not Available or Reliable” in this chapter, with the exception of the new slower pump speed:

1. Open the choke.

2. Bring pump up to the new slower rate.

3. Adjust the choke until casing pressure is the same as when shut in. Pressure on the drillpipe or the tubing gauge is the new circulating pressure.

If the well is still being circulated:

1. Slow pump down to reduced rate.2. While pump rate is being reduced,

maintain casing pressure at present value.

3. When at desired rate while maintaining casing pressure, the pressure on the drillpipe or tubing gauge is the new circulating pressure.

Partial Loss of Return

A slower circulatingrate may help.

High temperatures may have a significant effect on casing strength limits.

8-12CHAPTER 8

Several signs serve as possible indicators for an underground blowout. w A sudden break back in surface pressure.

This may indicate the formation failing.w Fluctuations in casing pressure.

Depending on the severity of the underground blowout, this may be very rapid. Casing pressure may increase to high levels.w Loss of communication between drillpipe

(tubing) and the annulus.w Drillpipe (tubing) decreasing or on

vacuum.w Stripping pipe up or down with no change

in annulus pressure.w Sudden drillpipe or tubing vibration

or drag when moving the pipe against blowout zones. w BOP or tree vibration.w Lower than expected shut-in pressure.

Annulus pressure may increase due to migration, if mud is lost and replaced

Full Loss of Return

w When circulating with partial lost returns, reduce bottomhole pressure (by choke adjustment) by 100 psi (6.89 bar), or preferably by the calculated annular friction value, and wait to see if it reduces the rate of lost returns. Remember that dropping pressure may drop bottomhole pressure enough to let more formation fluid feed in and make the situation worse. It is not a good idea to reduce bottomhole pump pressure this way more than about 200 psi (13.79 bar) or the annular friction value, if known. If this does not solve the lost circulation problem, then shut the well in and try another technique.

w Pick up and shut in the well. Give the hole time to cure itself. Keep the shut in string pressure constant by relieving choke pressure and using volumetric techniques.

w Mix a slug of heavy fluid to spot on bottom to try to kill the well. This may work with a small kick if the loss zone is above the kick zone. Then solve the lost circulation problem.

If lost circulation material (LCM) is to be used, there is a possibility that the LCM may plug the bit, jet nozzle or string at reduced rates. Careful consideration in selecting the LCM material (size and type) should be used during a kill operation. Fine sized LCM should be tried first and, if necessary, then gradually build up to larger LCM sizes.

SEVERE LOST CIRCULATION/UNDERGROUND BLOWOUTS

Standard blowout control procedures do not work unless the well can be circulated. If total lost returns occur, there may be gas all the way to the surface; this problem is an underground blowout.

Pick up, shut in, waitwhile observing pressures.

Decreasing choke pressure

can drop BHP enough to let

more formation fluid feed in, making the

situation worse.

8-13COMPLICATIONS

Several techniques may provide a solution to the problem.

w A plastic plug can be set by one of the cementing companies that may solve the lost circulation.

w A barite plug, a mixture of barite and water, will plug the hole above the kick zone. Barite plugs must settle out after being displaced into the hole. The time barite takes to settle makes it difficult to get a good plug with high volume water flows, but the barite plug works well with gas flows. When making up a barite plug, use enough material to give plug a chance to work even if part of it is washed away. The mixture list in the chart below is for a 300’ (91.4 m) plug of barite in the hole. Many operators will use a 22 ppg (2636 kg/m³) mixture; however, the lighter the mixture, the faster the barite will settle. The chart suggests a plug that is about two pounds heavier than the fluid weight in use. When pumping this mixture, care should be taken not to plug the nozzles.

with formation fluids. Fluids may have to be pumped down annulus to keep pressure below surface and/or casing limitations.

w Lower than normal flowing pressures while producing. In addition, signs of non-native formation fluids in production stream (changing gas/oil ratio).

If any of these indicators are present, a positive test may be performed. Slowly pump into the drill (tubing) string. Stop pumping and see if the pressure increase has been transferred to the annulus. If pressure is not transmitted throughout, do not proceed with a standard kill method. Note: If the pipe is stuck and the hole packed off around it, pressure will not be transmitted and may not be a sign of an underground blowout.

The depth of the lost circulation (thief) zone must first be identified. Once identified, the objective is to stop or reduce the lost circulation so the well can be killed with standard procedures. Running wireline logs (temperature, sound and pressure) may do this.

200

180

160

140

120

100

80

60

40

2015 16 17 18 19

1,000 SX BARITE 150 LB PHOSPHATE700 SX BARITE 100 LB PHOSPHATE

425 SX BARITE 50 LB PHOSPHATE335 SX BARITE 50 LB PHOSPHATE270 SX BARITE 35 LB PHOSPHATE185 SX BARITE 25 LB PHOSPHATE

1. Add water, then phosphate, then Barite then adjust pH to 9.0 with caustic soda.

2. Use fresh, clean water.1 sack 100 LB (45 kg) of Barite.

FOR A 17 1/2" HOLE USE TWICE THE MIX FOR A 12 1/4" HOLE

BARITE PLUG MIXTURE – 300' PLUG

MUD WEIGHT – LB/GAL

WAT

ER –

BB

L

Barite plugs are most effective when the plug density is about 2.0 ppg greater than the fluid in use.

CHAPTER 88-14

It should be noted that the bottomhole assembly and some pipe might be lost in this procedure as the barite rapidly settles in the annulus and sticks the string.

w One of the better methods of plugging the wellbore with a water flow is with a gunk plug. Gunk is a mixture of bentonite and diesel oil. The oil acts as a bentonite carrier. When oil is washed away from bentonite by water or fluid, bentonite sets up as a thick clay cement. The gunk plug does not work well on dry gas flows. Gunk plugs can weaken over time. If the plug is to be in place for several days, it is a good idea to set a cement plug on top of the gunk. (See chart below.)

w Perform a sandwich kill. Pump fluids with high concentration of LCM down annulus while simultaneously pumping a heavy fluid down string. In the rare case of a loss zone below blowing zone, these would be reversed. In addition, low friction fluids should be used to avoid pressure that may exceed critical pressure limitations - surface or downhole. Note: the string must be below the zones for this to be effective.

w Dynamic kill using fluid that will generate high enough ECD to overcome the blowing zone, but light enough that loss will not occur.

w Relief well drilled to kicking zone and dynamic techniques used.

CEMENT PLUGS

Cement makes an ideal plug. However, it is often difficult to get cement to set in moving gas, oil or water. Specialized cement mixtures, designed for this purpose, are available from cementing companies.

BOP FAILURE

Both contingency plans and emergency response plans (ERPs) should include action plans for BOP failure. BOP failure can result in additional formation influx and escape of formation fluids at surface resulting in the loss of the well and rig. Hence the reason the BOPs should be monitored throughout any well control activity. If there is a leakage

BENTONITE-DIESEL OIL GUNK MIXFOR A 300-FOOT COLUMN

HOLE SIZE DIESEL OIL BENTONITE TOTAL VOLUME

INCHES MM BBLS M³ 100 LB SX 50 KG SX BBLS M³

6 1/2 165.1 9 1.43 27 24.5 12 1.91

7 7/8 200.03 13 2.07 40 36.3 18 2.86

8 3/4 222.25 14 2.23 49 44.5 22 3.5

9 7/8 280.83 20 3.18 62 56.3 28 4.45

12 3/4 323.85 33 5.25 98 88.9 44 7

15 381 50 7.95 150 136.1 66 10.49

17 1/2 444.5 66 10.49 200 181.4 89 141.5

Conventional cement slurries

will usually not set up in

moving gas, oil or water flows.

COMPLICATIONS8-15

Crews should be familiar with alternate closing devices in the event of hydraulic failure of the closing system. This may be as simple as selecting another BOP, or manually closing a pipe ram. It may be necessary to manifold a high pressure test or cement pump to the stack’s closing line if the closing unit fails and the rams cannot be closed manually. If a hydraulic line fails, the function should be blocked to avoid loosing closing pressure. Subsea BOP stacks are equipped with alternate control pods, which may be selected if the primary closing pod fails to function correctly.

The point of failure is critical. If the failure is a flange seal between two BOPs, closing a lower ram may allow pressures to be controlled and depending on arrangement, well control activities to continue. Dropping the pipe and closing a blind ram is yet another possibility depending on the severity and location of the failure. Another solution to a flange seal failure is to pump a graded sealant into the wellhead. Pumping cement to plug the well is usually the last resort.

PRESSURE BETWEENCASING STRINGS

There are many causes why pressure can exist between two casing strings. Some of these reasons are the result of poor cement bonds, corrosion, wear, liner hanger packer failure and thermal effects on tubulars and packer fluids.

The reasons why pressure exists between strings must be identified before proceeding with the planned activity. Regulations may require that the problem be rectified before continuing operations if the cause of pressure is communication between zones.

Pressure

Casing Parted

13 3/8" Casing

9 5/8" Casing

Pressure Between Two

Strings

when the BOP is closed the packer element may be damaged. Often increasing the closing pressure may stop the leak, however if the leak is severe an alternate preventer should immediately be used.

On surface BOP stacks most rams have a weephole that indicates failure of the main seals of the ram shaft. This can result in failure of a positive closure of the ram around the pipe or wellbore. Several BOP manufacturers provide a temporary means to remedy this problem. A hex screw, located upstream from the weephole, when tightened will force packing or sealant material into the seal area to reduce or stop the shaft seal from leaking. When the well is back under control this problem must be repaired.

Barite should not be dumped directly into the pits to increase fluid density.

8-16CHAPTER 8

If pressure is trapped between strings, it may not be as much of a problem as communication between zones. However, it should be treated seriously if casing to casing annulus valve is opened prior to nippling down BOPs or when setting a new string of casing. Always open this valve carefully. Always assume that pressure is trapped, even if a gauge is installed and is not registering pressure.

PLUGGED HOPPER

If the mud-mixing hopper becomes plugged while maintaining weight and circulating a kick, mud weight will start decreasing. The mud hopper must be in working order so weight material can be mixed when needed. Dumping weight material directly into a pit is not as efficient as using the hopper.

BRIDGES IN STRING

Always anticipate pressure below a bridge or plug. It may be cleared up in several ways:w Apply pump pressure.w Run a wireline tool.w Run a small ID string and wash out.

w Pull the string.

STUCK PIPE

In many areas, the primary reason for stuck pipe is differential sticking. However, pipe can become stuck in the well for other reasons. The point where it is stuck and where it is free must be determined. Various specialty stuck pipe spotting materials are available from mud suppliers. If the pipe cannot be freed, the decision may be made to cut or back off the pipe just above the free point. After the string is parted, fishing tools, jars and other equipment may be run to attempt to free the pipe.

Parting the string can be accomplished by:w Mechanical internal cutters: Mechanical

internal cutters have a set of knives fed out of a mandrel on tapered blocks. When the tool is rotated, they engage and cut pipe. There are also external mechanical cutters.w Chemical cutters: Chemical cutters

produce a series of holes to weaken the pipe so that the pipe will part at the desired point when pulled.w Jet cutters: Jet cutters cut the pipe with a

shaped charge.w Explosion: String shot charges produce

momentary expansion of a connection. Torque is applied opposite the thread direction (usually left-hand torque) and primer cord explosive is fired either inside or outside the pipe to be backed off. A partial unscrewing of the threads is accomplished. The pipe may then be rotated to break out or release connection.

FREE POINT DETECTION

A free point detector is a wireline device run inside pipe to determine at what depth the pipe is stuck. The free point may also be calculated from stretch measurements.

Once the free point (the point above which the pipe is not stuck) is determined, a string-shot back off may be used to unscrew the pipe above the stuck-point. Jet, chemical, or mechanical cutters may be used to cut the string.

FISHING

The term fishing applies to attempting to recover equipment dropped, left, lost or stuck in the well. The fish may be in open hole, casing or in the tubing or drillstring. Most fishing jobs inside the casing are done with tubing or drillpipe, while most fishing jobs inside tubing or drillpipe are done with wireline.

Fishing:method used

to recover equipment or

junk lost in a well.

8-17COMPLICATIONS

There are various causes of fishing jobs, including the following.

w Drillstring or pipe twist-offs

w Foreign objects lost or dropped in the hole

w Parting of wireline and cables

w Tool or bit failures

w Backing off above a stuck point

w Human error

The first thing that should be done is to make a detailed sketch of the fish. This is why it is critical to measure and know the diameters of anything that is run into the hole. The sketch should include a complete wellbore configuration. The fishing tools are selected (or made) from the sketch and the location of the fish. All fishing tools run into the hole should be calipered and measured.

A simple job, such as running an overshot to catch a pipe joint connection, is often done by the rig crew. However, the operator must analyze the situation before taking hasty action. If the operator is lacking in either tools or skill, a specialist should be called.

Tools run to the fish include the following.

w Catch internally – spears or tapered taps

w Catch externally – overshots (spiral and basket grapples)

w Pick up or catch – magnets, junk baskets or spears

w Drill, mill and cut – rotary shoes, mills, cutters and bits

w Roll and scrape – rollers and scrapers

Accessories are also used to enhance the fishing job. They include such items as impression blocks, jars, bumper subs, safety joints, accelerators, knuckle joints and washover pipe. Fishing tools may be run on pipe or wireline, depending on the application.

FISHING TOOLS

Many tools are used to complete a fishing job. If the shape or size of the top of the fish is in doubt, it may be necessary to run an impression block to obtain this information.

T op S ub

T ype A P acker

B owlS piral G rapple

G rapple C ontrol

G uide

Top Sub

Bowl

BasketGrapple

Mill ControlPacker

Guide

Top Sub

Bowl

Grapple Control

Guide

Fishing overshots

Jars: impact devices used to deliver upward or downward blows to free stuck equipment.

CHAPTER 88-18

Down hole cameras and video recorders have been used to identify fish in wells using clear fluids. When information about the top of the fish is known, the proper catching tool is selected.

An overshot is the most common and versatile fishing tool. It can grasp collars, pipe or fishing necks and pull retrievable tools. Many overshots are equipped with safety joints so they can be released if necessary. Overshots may also have a packoff to seal around the fish when circulation is necessary. They may be run on pipe, coil tubing or wireline.

Wash pipe is normally heavy-walled casing, flush-jointed inside and out. It is used to wash down the hole over a fish. Usually only 3 or 4 joints of a fish are retrieved at a time. The shoe run on the bottom of the wash pipe is designed for the job. A tooth shoe is used when drilling, milling or cutting is necessary.

Magnets are used to retrieve smaller fish such as bit cones. They can be electromagnets run on wireline. Permanent magnets are often run on the tubing or drillpipe and have circulating ports to wash the fish clean.

Other accessory tools are often used with primary fishing tools. Jars are impact devices. They deliver a downward or upward blow to free the fish once caught. Junk baskets may be run on the string or wireline to pick up small metal cuttings. Junk subs are placed in the work or drillstring immediately above the bit or mill. As the hole is circulated, metal cuttings are washed off bottom, quickly falling back into the basket skirt. Hydrostatic bailers can also be used to clean out junk in the wellbore, and can be run on pipe or on slick line.

MILLING

Mills are used for a variety of reasons. Occasionally it is necessary to mill away complete sections of tubing, drillpipe, casing or fish that cannot be caught in their present state. Milling is also necessary if the well is

being sidetracked. If metal being milled is steel, milling tools are usually dressed with tungsten carbide cutting surfaces. Mills come in many different sizes and shapes designed to do a particular job.

During milling work, it is advisable to place magnets at the surface to catch and aid in the removal of metal cuttings from the fluid. Metal cuttings will damage the pump if they are left in the circulating fluid.

FREEZING

Freezing is a technique used to seal tubing, drillpipe, casing or surface equipment if other equipment fails or if other methods are unsafe. Once frozen, equipment can be removed or replaced as necessary. This process has been successful in pressures in excess of 10,000 psi (689.5 bar). Some uses of freezing follow.

w After a kick is taken, the kelly cannot be removed because of no float, or the lower kelly valve develops a leak.

w Either a master valve on a tree or a blowout preventer fails requiring that it be removed for replacement.

w So a faulty valve can be removed or a check valve installed.

To perform a freeze operation a static fluid condition must exist at the desired freeze point. A specially formulated gel-like fluid must be spotted at the desired freeze point either by pumping through the kelly or by use of a hot tap. The formulation has a high concentration of particle matter. Bentonite (gel) and water (the maximum amount of gel that can be mixed and still remain pumpable) together work well in this application. The gel provides the necessary solids as well as viscosity to keep the solution in place. For spotting in gas or empty pipe, more viscosity will be needed to keep the pill in place. To be successful the pill has to remain static. If the fluid is not stationary, the chance for success is low. Water, when freezing will expand. This can damage the

Consider service companies for

fishing, freezing and hot tapping

operations which require

specialized tools and personnel.

COMPLICATIONS8-19

vessel it is freezing in. The solids will compress and provide a cushion for the expanding water.

A bolt-on a split bucket or drum (55-gallons [208.2 l] will usually suffice) is wrapped around the section to be frozen. The interior is lined with plastic (similar to trash bags) and packed with dry ice layers, no more than 6” (152 mm) per layer. The object is to provide a very dense arrangement of dry ice, with as little void or air space as possible. Dry ice has a temperature of -109°F (-78°C). Colder temperatures may damage the composition of steel and may make

it too brittle at the time of freezing.Wait approximately one hour for every

inch (25.4 mm) of diameter that is being frozen, repacking with dry ice every 30 minutes. Once sufficient time has passed, an ice plug should have formed. Normally the plug will extend from 1 to 2-1/2 feet (0.3 to 0.76 m) above and below the bucket area.

The frozen section may now be worked on. It should be pointed out that frozen metal is extremely brittle. If it should break, an uncontrolled situation may develop rapidly.

Bit Drive Shaft

Ratchet Assembly

Rod ClampStuffing BoxBleed Off Valve

Quick UnionValve

Pack Off

ClampsBull PlugTie BoltsWellhead

Bit Drive Shaft forHand Or Power Tools

Stuffing Box

Bleed OffValve

Quick Union

Valve

BitSaddle Clamp

Ratchet Assembly

Rod Clamp

Hot Tapping Equipment

The first step in safely handling complications during a well control situation is to accurately identify the problem.

8-20CHAPTER 8

MECHANICAL AND HOLE PROBLEMSDRILLPIPE CASING ACTIONSPRESSURE PRESSURE TO TAKE RESULT PROBLEM SOLUTION

Up Up about same Check Pump rate too fast Circulating pressure is too high because Slow pump rate down to planned rate. If pressures comeamount as drillpipe pump rate pump is running faster than planned down, everything is okay. If not, continue down chart.

Increase Drillpipe/casing pressures Choke size was too small If pressures come down when choke size was increased,choke size came down everything is okay. If not, continue down chart.Open choke Drillpipe/casing pressures Either choke size was too small or If pressures come down, everything is okay.all the way came down choke was trying to plug If not, continue down chartStop the Drillpipe/casing pressures Choke manifold has started to plug up Switch to alternate choke line and clear manifold. Ifpump came down pressures do not come down, continue down chart.Shut in Pressures stay up Manifold is plugged Switch to alternate choke line. If pressures come down,the well go back to well killing. If not continue down chart.

Manifold is plugged at or above the T Close master valve on kill line. Release pressurefrom manifold and clean it out.

Up Up but not Check Pump rate too fast Circulating pressure is too high because Slow pump to planned rate. If pressures come down,very much pump rate pump rate is faster than planned everything is okay. If not, continue down chart.

Increase Drillpipe/casing pressures Choke size was too small If pressures come down, everything is okay.choke size came down If not, continue down chart

Casing pressure comes Wait at least 2 minutes to see if Allow for a long time lag with big gas kicks. If pressuredown but not drillpipe there is a long lag between choke does not come down, continue down chart.

movement and drillpipe pressureDrillpipe pressure A mud ring or pack off near bit Raise or reciprocate drillpipe. If drillpipe pressure comesdoes not come down down, everything is okay. If not, continue down chart.

Plugged casing pressure to where it was before troublestarted. Take changed drillpipe pressure as new constantcirculating pressure. OR:Stop pump, shut well in, bleed pressure off drillpipe.Start up holding casing pressure constant until youreach a new pump rate. Use new circulating pressureas new constant circulating pressure.

Up No change Check Pump rate too fast Circulating pressure too high Slow pump to planned rate. If pressure comes down,abrupt pump rate because rate is faster than planned okay. If not, continue down chart.change Increase Casing pressure gets A mud ring or pack off near bit Raise or reciprocate drillpipe. If drillpipe pressure

choke size very low before drillpipe comes down, okay. If not, continue down chart.pressure comes down

Up No change Increase Casing pressure gets Plugged bit Take new drillpipe as constant circulating pressure. OR:size very low before drillpipe Stop pump and shut well in. Bleed off drillpipe pressure

change pressure comes down Start up holding casing pressure constant, until youreach a new pump rate. Use new circulating pressureas constant circulating pressure.

Open choke Drillpipe pressure Plugged bit Stop pump and shut in well. Try rocking pump to cleardoes not come down bit. You may have to shoot off or back off the bit.

On marine rig with subsea wellhead/riser,possible plugged wellhead/riser kill line

No change Down or Increase or Pressures do not seem Lost circulation, bad cement job, or hole • Pick a new slower circulating rate.no change decrease in to respond to choke in casing. Check pit volume • Add lost circulation material

choke size movement • Drop a barite plugCheck pit Volume okay Check choke for failure Switch to alternate chokevolume

Down Down Check Pump rate too slow Circulating pressure too low because Increase pump rate to planned rate. If pressure comespump rate pump is running slower than planned up, okay. If not, continue down chart.Decrease Drillpipe and casing Choke size was too large If pressure go up when choke size decreased, okay. Ifchoke size pressure came up not, continue down chart.

No change in drillpipe/ Lost circulating, bad cement job, or hole See drillpipe pressure – no change.casing pressures in casing. Check pit volume

Down No change Check Pump rate too slow Circulating pressure is too low because Increase pump rate to planned rate. If pressure comespump rate pump is running slower than planned up, okay. If not, continue down chart.Decrease Pressures increase Choke size was too large If pressures go up when choke size decreased, okay. Ifchoke size not, continue down chart.

Pressures increase but kelly Pump trouble Change pumps or repair pumphose jumps and drillpipepressure surges

Continually Drillpipe pressure stays Hole in drillpipe Stop pump and shut in well. You may have to stripdecreasing same, casing pressure out to replace a joint of pipechoke size goes up

Abrupt No change Decrease Drillpipe and casing Washout on bit or drillpipechange choke size pressure go updown

Restore jet

choke abrupt

8-21COMPLICATIONS

HOT TAPPING

Hot tapping is the process of tapping or drilling an entry point into a pipe or a vessel under pressure. The technique provides a means of bleeding off or pumping into otherwise sealed vessels. Hot tapping uses include the following.

w In snubbing, if there is pressure trapped between two plugs in the tubing, when the first plug is out of the well, the hot tap can be used to drill a hole in the pipe to relieve the pressure.

w After setting a frozen plug in the string, a hot tap may be used to tap into string to bleed off trapped pressure. This allows the kelly to be removed, a valve to be set, additional equipment to be installed and the well to be killed.

w It may be used to drill into plugged or bridged tubing to relieve pressure.

w Hot taps may be used to tap into bull plugs in surface pipe, casing wellheads and manifolds.

When performing a hot tap, a special saddle clamp is attached to the equipment to be drilled. The saddle makes the primary seal to the medium or pipe to be tapped. The seal is normally mechanical (wrap around or donut seal), and is energized by the saddle mechanism.

A special drill bit with a lubricator assembly is assembled onto the clamp. From that point, the bit is rotated hydraulically or by hand. The drill is guided and held by a threaded yoke that provides the needed force against the pipe in order for bit to drill through it. Pilot drill bits, stepping up to the desired hole size, are drilled into the pipe. The hot tapping process should be performed rapidly, but safely. If the saddle seal mechanism fails, control may be lost.

MECHANICAL & HOLE PROBLEMS

Both the pump pressure gauge and casing pressure gauge should be monitored at all times during a kill. Problems that develop can usually be diagnosed by interpreting the gauge reactions. It is imperative to monitor these gauges and notice if one change affects the other.

SUMMARY

Complications often arise during well control activities. Few well kill attempts actually proceed without glitches. It stands to reason that problems should be anticipated, and caution and attention should be exercised throughout the operation. Not paying attention to all of the details and trends is a contributing factor to beginning or existing problems.

Problems can be solved, but first they must be properly identified. After the problem is discovered, the solution can be determined with a combination of experience and common sense. Always remember that if the solution – or the problem – does not seem clear, then the best idea is to get some help. If immediate help is not available, go ahead and shut the well in and then get help. Failure to do so can result in the tragic loss of life and resources. t

Most well kill attempts have complications: anticipate problems and exercise caution during the entire operation.

CHAPTER

3CHAPTER

9

The fundamentals

of fluid control

are key to

well control.

FLUIDS

9-1

The general functions of drilling fluids are fairly standardized. Since most drilling operations rely on liquid drilling fluids,

we will make them our main concern in this chapter. The eight basic functions of drilling fluids are listed below.

w Transportation of cuttings to surface

w Suspension of cuttings when circulation is stopped

w Control of annular pressure

w Lubrication and cooling of the drilling assembly.

w Provision of wall support

w Suspension of drilling assembly and casing

w Delivery of hydraulic energy

w Provision of a suitable medium for wireline logging

9-2CHAPTER 9

Most drilling operations use

liquid drilling fluids.

TRANSPORT CUTTINGS TO SURFACE

The hole must be properly cleaned to prevent cuttings from accumulating in the annulus, which could cause increased torque, drag, fill or hydrostatic pressure. This may result in stuck pipe, loss circulation, pipe failure or a decrease in penetration.

Since cuttings are heavier than the drilling fluid, they are lifted out of the hole by the fluid flowing in the annulus. Gravity will try to cause the cuttings to fall toward the bottom of the hole. The speed at which the cuttings fall depends on particle size, shape, density and fluid viscosity.

SUSPENSION OF CUTTINGS

Cuttings will try to fall to bottom when circulation is stopped unless the drilling fluid forms a gel-like structure. This gel-like structure should suspend or hold the cuttings in place until circulation is started again. Excessive surge and swab pressures may be caused if the mud remains in a gel-like structure once circulation has started.

ANNULAR PRESSURE CONTROL

Since formation fluids (oil, water or gas) are under great pressure, they must be balanced or overbalanced to prevent uncontrolled flow. The hydrostatic pressure of the mud in the annulus accomplishes this.

LUBRICATION AND COOLING

As the bit drills on bottom and the drillstring turns in the hole extreme heat is developed. This heat must be absorbed by the drilling fluid and carried away from the bottom of the hole.

The drilling fluid must also lubricate the casing, drillstring and bit. Lubricating properties can be improved by the addition of special materials (dispersants, friction reducers). This may also increase bit life, decrease torque and drag, reduce pump pressure and reduce frictional wear on the drillstring and casing.

WALL SUPPORT

The formation could fall into the wellbore before casing is set unless support is replaced by the drilling fluid. The amount of support required to prevent this from occurring depends on the formation. Little support is needed in a very firm formation, whereas consolidated or fairly firm formations may be supported just by the mud density. In weak or unconsolidated formations the drilling fluid must have the ability to form a thin, tough wall cake in the hole.

DRILLING ASSEMBLY/CASING SUSPENSION

The drillstring and casing weight can exceed many thousands of pounds and develop extreme stress on the rig’s structure. These extreme weights can be partly supported by the buoyant force of the drilling fluid. This force is dependent on the weight of the fluid and the displacement of the pipe.

DELIVER HYDRAULIC ENERGY(BIT HYDRAULICS)

A high velocity is developed as drilling fluid passes through bit nozzles during circulation. This velocity, or hydraulic force, will keep the area under the bit clean, so the bit will not have to regrind the old cuttings, causing a reduction in penetration rate. The physical properties and velocity of the drilling fluid help keep the area under the bit clean.

SUITABLE WIRELINE MEDIUM

The drilling fluid is necessary for many MWD/LWD (measurement and/or logging while drilling) tools and wireline logs that are used in formation evaluation. Many logs require that the drilling fluid be an electrically conductive liquid exhibiting different electrical properties from the fluids in the formation.

9-3FLUIDS

Unnecessarily high mud weights can reduce the penetration rate.

SIDE EFFECTS

The following side effects should be minimized while drilling.

w Open hole formation damage

w Casing and drillstring corrosion

w Penetration rate reduction

w Circulation, surge and swab problems

w Lost circulation

w Drill string sticking

w Wellbore erosion

w Settling in the pits

w Mud pump wear

w Cement and environmental contamination

OPEN HOLE FORMATION DAMAGE

Formation damage can appear in two different forms: a reduction in hydrocarbon production or wellbore stability. Many types of drilling fluids will alter formation characteristics, but some formations are more sensitive than others and some fluids more damaging. Particularly sensitive formations (e.g., hydro-pressured or bentonitic shales) may require special drilling fluids, treating chemicals or other considerations.

CASING AND DRILLSTRING CORROSION

The steel tubulars in the hole may be subject to a corrosive environment from the drilling fluid and formation. Chemical treatment of the drilling fluid or adding a protective coating to the surface of the steel can minimize the corrosive effect.

PENETRATION RATE REDUCTION

Many factors affect the penetration rate, but the difference between formation pressure and hydrostatic pressure is the most significant. If the hydrostatic pressure of the drilling fluid is much higher than the formation pressure, a reduction in penetration rate will occur.

CIRCULATION, SURGE AND SWAB PROBLEMS

High viscosity drilling fluids can increase circulating, surge and swab pressures. A thick filter cake can also contribute to surge and swab pressures that might result in a kick. Excessive viscosity limits the flow rate, puts extra stress on the pump and may also reduce penetration rates if sufficient pressure at the bit cannot be achieved.

LOST CIRCULATION Lost circulation can be caused when

hydrostatic pressure exceeds the strength of the formation. High pressures can also be the result of bad tripping or drilling practices, high mud weight and/or fluid viscosity. High drilling fluid and well cost, along with the chance of taking a kick are the results of lost circulation.

DRILLSTRING STICKING

An excessive amount of cuttings in the hole is one cause of pipe sticking, but the most significant type of sticking is when the pipe is embedded in a thick filter cake. Pipe sticking can lead to expensive fishing jobs and increase the well cost.

WELLBORE EROSION

Problems with wireline logging, cementing and stuck pipe are just a few of the difficulties of wellbore erosion. There are two types of wellbore erosion, physical and chemical. Pumping the drilling fluid up the annulus at a lower velocity will help reduce physical erosion. Chemical erosion depends on the chemical reaction between the drilling fluid and the formation.

SETTLING IN THE PITS

The same gel strength that prevents the cutting from falling in the well when circulation is stopped can also prevent unwanted solids from falling in the pits. Gravity does cause some of the solids to fall to the pit bottom.

CHAPTER 99-4

Environmental effects are

a major consideration

when designing fluid systems.

However, most must be removed by proper use of solids control equipment such as de-sanders, de-silters, centrifuges and mud cleaners.

MUD PUMP WEAR

Those same solids can cause excessive pump wear if solids are not removed. The most abrasive solid is probably sand incorporated into the fluid while drilling. This sand should be removed by solids control equipment.

CEMENT/ENVIRONMENT CONTAMINATION

Some drilling fluids that are good for drilling operations are incompatible with slurries of cement. A flush, wash or spacer fluid should be used to separate the cement and the drilling fluid.

Environmental problems are caused by certain liquid, solid and chemical additives. Sometimes a particular additive must be replaced by a less effective and more expensive product that will not harm marine life.

FIELD TESTS ON FLUIDS

Physical or chemical fluid properties must be properly controlled for the fluid to perform during drilling and remedial operations. These properties are routinely checked and recorded at the well site.

In the following pages we will cover the following tests: mud weight, rheological properties (funnel viscosity), filtration characteristics (API low pressure test), filtrate analysis (salt concentration) and temperature.

Portable field test lab for

drilling fluids

FLUIDS9-5

A pressurized mud balance should be used if the fluid contains a significant amount ofgas or air.

MUD WEIGHT TEST

The conventional mud balance and the pressurized mud balance both use a graduated arm and beam balance principle to measure density. For most applications the conventional balance is adequate, however if the mud or cement slurries contain a significant amount of entrained or trapped air, the pressurized balance should be used. The pressurized mud balance compresses the quantity of entrained air to a negligible volume so the value given is comparable to what is realized down hole. Mud weight test procedures follow.

1. Set up the instrument base so it is level.

2. Fill the clean, dry cup with the mud to be weighed.

3. Place the lid on the cup, and seat it firmly but slowly with a twisting motion. Be sure that some mud escapes through the hole in the cap.

When using a pressurized mud balance, use the pump to add mud into the cup under pressure. Fill the pump with mud, place the pump on the cup fittings and push on the piston until no additional mud can be added.

4. Wash or wipe all mud from the outside of the cup and arm.

5. Set the knife on the fulcrum, and move the sliding weight along the graduated arm until the cup and arm are balanced.

6. Read the density of the mud at the left-hand edge of the sliding weight.

7. Report the result to the nearest scale division in lb/gal, lb/cu ft, specific gravity or psi/1,000 ft of depth.

8. Wash mud from the cup immediately after each use. It is essential that all parts of the mud balance be kept clean if accurate results are to be obtained.

A mud balance is used for fluid density control, the first line of defense against blowouts.

9-6CHAPTER 9

To calibrate the mud balance, the same procedure should be performed filling the cup with fresh or distilled water. Adjust the sliding weight to the line at 8.33 ppg and set the knife edge of the balance on the fulcrum. If the weight and cup do not balance in level position, add or remove shot as required or adjust the calibration screw at the end of the arm. Shot may be added or removed by removing the screw in the chamber at the end of the graduated arm.

RHEOLOGICAL PROPERTIES

Rheology is the study of the flow of liquids and gases. Viscosity, which can be thought of as the resistance to flow (or relative thickness) of a fluid, is the common rheological term used in the oilfield industry. The measurement of the rheological properties of a fluid is important for calculating frictional pressure losses; determining the mud’s ability to lift cuttings and cavings to surface; analyzing mud contamination by solids, chemicals or temperature; and determining pressure changes in the well during a trip. The underlying properties are viscosity and gel strength.

Simple viscosity measurements are taken using a Marsh funnel, which measures a timed rate flow. The funnel viscosity is the number of seconds required for a quart (0.946 l) of mud to pass through a 3/16-inch (4.8 mm) tube fastened to the bottom of a 12-inch (305 mm) long funnel. The resulting value is a qualitative indicator of the mud viscosity.

To calibrate the Marsh funnel for the standard API test, fill the funnel with 1,500 cc of clear water at a temperature between 70° and 80° F (22° and 27° C), and note the time that is required for one quart (0.946 l) to drain from the funnel. The time for fresh water should be 26 seconds, with a tolerance of a half second, more or less.

To insure that you get dependable results use a funnel that is clean and dent-free. Take the sample at the flow line, straining it through the screen, and run the test immediately, timing the flow rate. The procedure for the funnel viscosity test follows.

1. Cover the tip of the tube with a finger and pour mud through the screen until the level reaches the screen bottom.

The marsh funnel gives the apparent

viscosity of a fluid, an indicator

of flow properties.

Rheology:the study of the

flow of liquids and gases.

9-7FLUIDS

Gel strength:an estimate of a fluid’s ability to suspend particles when at rest.

2. Remove finger from the outlet and carefully observe the time required, in seconds, for one quart (0.946 l) of mud to flow out of the funnel. The number of seconds is the funnel viscosity.

3. Report the temperature of the sample in degrees F (degrees C).

A better measurement of the mud’s rheological properties is obtained using a RP or Fann viscometer, also called a VG meter. This instrument uses a rotating sleeve around an inner tension adjusted cylinder to give either direct or digital readings of the fluid’s resistance to flow. Readings are typically taken at 300 and 600 rpm to determine the plastic

viscosity (PV) and yield point (YP) of the fluid.

To determine PV the 300 rpm reading is subtracted from the 600 rpm reading. Plastic viscosity measures the flow resistance caused by friction between suspended solid particles and the liquid phase of the fluid. Since this is solid particle dependent, the size, shape and number of particles all affect the plastic viscosity. The unit of measurement is expressed in centipoise.

Yield point is the measurement of resistance to flow caused by the attractive forces between particles in the fluid. This is due to charges on the particle surfaces. Yield point is measured in pounds per 100 square feet and is determined by subtracting the PV measurement from the 300 rpm reading.

The viscometer is also used to determine gel strength, or the

ability of fluid to develop a rigid or semi-rigid gel structure when the fluid is not moving. The fluid’s thickening, or thixotropic, properties are measured 10 seconds and 10 minutes after it stops moving.

API WATER LOSS

An important property of a fluid is filtration rate, or water loss. It is a measure of the relative amount of water in the mud lost to permeable formations, and of the relative amount of mud or filter cake on the permeable walls of the hole. The low pressure filter press meets API specifications for measurement of filtration. The pressure is supplied from carbon

One typeof viscometer

CHAPTER 99-8

API filter cake is measured

in 32nds of an inch.

dioxide (CO2) cartridges, but modification of the connections allows the use of compressed air from the rig supply or cylinders. The procedure for making the filtration test follows.

1. Assemble the parts of the clean, dry filter press, using a dry filter paper.

2. Fill the mud reservoir to within about 1⁄2 inch of the top with mud. Filling the cell to the top is necessary only to conserve gas. If compressed air is plentiful, the cell need be only partially filled with mud.

Nitrogen may be used instead of air or carbon dioxide. (Do not use oxygen; it may cause an explosion.)

3. With the graduated cylinder in place to receive the filtrate, allow gas pressure to be applied through regulators to obtain 100 psi (6.89 bar), with a tolerance of +/– 5 psi (0.3 bar). Never open the gas valve to a regulator that is not adjusted to minimum pressure. Turn the pressure to the filter press on or off with the regulator screw.

Filter press, used for API

water loss test.

FLUIDS9-9

A high concentration of salt will contaminate some drilling fluids.

4. At 30 minutes, release the pressure and read the amount of water loss or filtrate in the cylinder in milliliters (ml). Carefully remove the filter paper with the filter cake and rinse off the excess mud. The thickness of the filter cake is read to the nearest 1/32 inch.

5. In general, the 30-minute test should be used. If the API water loss test is greater than 8 ml, the volume of filtrate obtained in 7 1/2 minutes may be doubled to give a fair approximation of the API value. The actual time of the test, if different from the standard 30-minute test, should be recorded on the driller’s report. In addition to a report of the thickness of the cake, a descriptive note should be included when the cake has poor texture, or settling has increased its thickness. Cake thickness should not be reported for tests shorter than 30 minutes.

CHLORIDE TEST

The salt or chloride test is important for checking salt contamination and determining concentrations in saltwater or salt-treated muds. The test is performed on mud filtrate taken from the standard API filtration test. The chloride content test procedure follows.

1. Measure a sample of any convenient volume, 1 to 10 cc, into titration dish and dilute to about 50 cc with distilled water.

2. Add a few drops of phenolphthalein indicator. If a pink color develops, add sulfuric acid until it completely disappears. If phosphates have been added in large quantities, add 10 to 15 drops of calcium acetate solution.

3. Add 4–5 drops of potassium chromate indicator to obtain a bright yellow color.

4. Add standard silver nitrate solution one drop at a time continuously. The end-

Filtrate fromthe water loss test is analyzed for chemical content usinga filtratetitration kit.

9-10CHAPTER 9

The temperature at which tests are run should

be recorded with test results.

point of the titration is reached when the sample first changes to orange or brick red.

Calculate the chloride (Cl) content using

the following formula.

Cl contentmg/l =cc of silver nitrate ÷ cc of sample

× 1,000

The preceding method of calculation assumes no change density of the filtrate with

increasing salt concentration. Therefore, the results are correctly expressed in milligrams (mg) per liter but not in parts per million. To express the concentration in parts per million or percent by weight, use the following formula.

Parts per million =mg/l ÷ density of solution (g/cc)

Percent by Weight = mg/l÷ (10,000 × density of solution [g/cc])

High temperature, high pressure

filter press

9-11FLUIDS

Completion fluids are used opposite the production zone and are designed to prevent unnecessary formation damage.

In addition to common salt, or sodium chloride, salt beds and brines often contain the chlorides of calcium and magnesium. The testing method described determines the amount of chloride ion present but can be expressed as if it were in combination with sodium, as in NaCl, or salt.

This is calculated by multiplying by 1.65, which is the ratio of the molecule to the weight of the associated chloride ion.

TEMPERATURE TESTS

Drilling mud rheological properties and the effectiveness of the various additives are affected by temperature. Downhole temperatures are of great concern, but they cannot be determined readily. Measurement of flowline temperature using a common thermometer provides a reasonable indication of downhole conditions. Rheological properties are taken at this flowline temperature.

WORKOVER AND COMPLETION

There are many applications of fluids in remedial activities. They can be used for perforating, cementing, fracturing, acidizing, stimulating, well killing, recompletion, drilling, deepening, plugging back, cleaning out, packer fluid, completion fluid, circulating and more. These fluids may be gases, oils, brine waters, muds or other chemical solutions used during normal remedial activities.

Specialized fluids consist of packer fluids and completion fluids. Packer fluids are left in the well between the tubing and casing above the packer and must be stable, non-corrosive, maintain pressure control and remain able to be circulated. Completion fluids are used opposite productive formations to prevent permanent zone damage.

The mud retort –for solids analysls.

CHAPTER 99-12

High temperature

fluid stability is an important

feature of remedial fluids.

REQUIRED WORKOVER AND COMPLETION FLUID CHARACTERISTICS

A good fluid should:

w Be sufficiently dense to control well pressures without being too heavy. This reduces a large fluid loss to the formation. By staying close to formation balance, overbalance losses are reduced.

w Be cost effective. Sometimes expensive fluids are necessary to prevent damage in sensitive formations. There are occasions where less expensive fluids will cause little or no harm. Past experience is valuable here.

w Be as free of solid particles as possible. Solids can plug perforations and reduce production after a fracture or gravel pack job.

w Be non-corrosive, to prevent future expensive tubular goods failure and fishing costs.

w Be stable. Stability is important if fluid is to be left in the hole for an extended period of time. Fishing for stuck packers and tubing can be expensive and might even lead to abandonment of the well before production is completed. High temperature fluid stability is also desirable, especially in deep hot wells.

w Be clean and filtered. Some fluids have high amounts of suspended solid particles which can be harmful to the producing formation (fines or silts), and abrasive to equipment (sand or metals). Others have low amounts of solids but can also cause plugging. The better fluids are filtered or cleaned, and have few solids. Generally, fluids that are filtered to 2-4 microns, or 10-20 NTUs are thought to minimize formation damage, allowing higher production rates. (NTU = Nephelometric Turbidity Unit, a measure of fluid clarity.)

CONTAMINATION PROBLEMS

Some fluids that are excellent for normal operations can be incompatible with cement slurries or acid. It may be necessary to use a fluid spacer to separate them.

There can be environmental problems caused by certain liquid, solid and chemical additives, as well as by fluid itself. Sometimes it may require replacement by a less effective and/or more expensive product that will not harm marine life.

FUNCTION AND PURPOSE

The functions of fluids used in remedial activities such as workover or completions are standard. Fluids are important to the success of most remedial jobs. They must be non-damaging to the producing formation and non-hazardous to the equipment, personnel and to the environment. It is essential that fluids be properly applied, controlled and monitored.

Workover and completion fluids range in weight from low density (gas) to high density (liquids). Their basic functions follow.

w Transportation of materials

w Suspension of materials when circulation is stopped

w Pressure control

w Lubrication and removal of heat

w Delivery of hydraulic energy

w Suitable medium for wireline tools, logging and perforating

w Allow safe downhole equipment run

w Non-damaging – producing formation

w Non-damaging – downhole equipment

w Non-damaging – surface equipment

w Non-damaging – people/environment

FLUIDS9-13

In remedial operations, the preferred method of circulation is often reverse circulation.

TRANSPORTATION OF MATERIALS In order to perform many operations it

is important to be able to circulate materials both into and out of the wellbore. Certain materials are added to perform an objective. Other materials, which may cause damage, must be removed to keep the wellbore clean.

Potentially damaging undesirable materials that may be circulated from the wellbore include: cement, corrosive fluids, cuttings, debris, gravel, gas, metals, old contaminated mud, plastics, sand, unused wet cement. Equally necessary is the ability to circulate desirable material such as acid, cement, gelled pills, plastic, gravel, fracture sand, sealers and other fluids into the well.

Accumulation of material in the wellbore may cause many problems, including, sticking or failure of the pipestring, pipe plugging or bridging, increased torque or drag, lost circulation, fill, perforation or formation plugging and excessive equipment wear.

SUSPENSION OF MATERIALS WHEN CIRCULATION IS STOPPED

If the fluid in use has a high gel strength, it has good suspension capabilities when circulation is stopped. This gel-like structure resists the sinking of solids and cuttings until circulation can be resumed. This helps reduce the amount of fill and minimizes sticking of tools, tubulars and wireline due to the solids pulled down by gravity. However, during remedial operations most of the trash removal can be done by reverse circulation at higher velocity and in less time. Because this high suspension ability may not be required, and because generally the higher the gel strength, the higher the chances are to develop swab and surge pressures, in some instances this can be a detriment to good workover practices. If the trash is too heavy (e.g., metal cuttings) to be circulated up the string, a boot basket may be used with normal circulation.

PRESSURE CONTROL

We must assume that we could be exposed to formation pressure at any time during a remedial activity. There are instances where work is performed on a live well under pressure. However, many workover activities require that the well be killed. It is therefore required that we balance or overbalance the formation pressure to prevent well flow. This is accomplished by the hydrostatic pressure of the fluid in the well. Fluids may be adjusted or weighted as necessary to obtain a balanced condition. If the fluid is too heavy losses to and formation damage may occur.

LUBRICATION AND REMOVAL OF HEAT As the bit or mill and string turn in the

hole, extreme heat is developed. This heat must be absorbed by the fluid, cooling the assembly to prolong bit or mill life, and preventing heat from weakening or damaging the assembly. The fluid also acts as a medium to lubricate the metal-to-hole contact to prevent excessive heat, wear or failure in these areas.

DELIVERY OF HYDRAULIC ENERGY

Many of the routine and special activities during remedial operations require that pressure be applied at the wellhead and transmitted through the fluid to some downhole location. Other circumstances require a circulating fluid and fluid velocity. These must be obtained through proper application of fluids, and by use of the rig’s pumps.

SUITABLE MEDIUM FOR WIRELINE TOOLS, LOGGING AND PERFORATING

A relatively large percentage of activity associated with workovers can be performed by wireline. Here, the fluid used becomes of prime importance to allow timely access to the wireline run equipment, such as perforating guns, electric cased hole logs, plugs and packers, and also to run other nipple seated devices.

9-14CHAPTER 9

Special safety precautions may

be necessary when working with remedial

fluids.

ALLOW SAFE DOWNHOLE EQUIPMENT RUN

A fluid that is not properly conditioned (e.g., thick and viscous) can contribute to problems in circulating, and surge and swab problems when tripping. Improper fluid types may lead to formation damage.

NON-DAMAGING – PRODUCING FORMATION

It is important that the fluid used does not cause permanent damage to the productive zone by leaving silts, fines, sludge, gum or resins in the formation. Formation erosion can occur if high pump rates are used. Fresh water can cause a flow-blocking emulsion in some gas/oil producing formations. Fluids with a high water loss may swell sensitive formations (skin damage), leading to a decrease in productivity. The fluid should not change the wetability of the reservoir sand or rock.

NON-DAMAGING – DOWNHOLE EQUIPMENT

Much consideration is given to fluids, such as packer fluids, that are left in the hole. They must be non-settling and non-corrosive. The expected life of the well usually dictates what type of fluid and additives are to be mixed and left in the well. During remedial activities the packer fluid is often altered, diluted or replaced. If the fluid is not properly treated, it can become corrosive. This can jeopardize the expected life of seals and equipment.

NON-DAMAGING – SURFACE EQUIPMENT

Corrosive fluids can lead to failure of sealing elements on many types of surface equipment. Sand-laden fluids can be abrasive, eroding and cutting valves, swabs and other equipment in a short period if recirculated.

NON-HAZARDOUS – PEOPLE/ENVIRONMENT

Often fluids used in remedial activities can be hazardous to personnel. Acids, caustics, bromides, some chlorides and other chemicals

can cause serious burns. They can also be toxic and can cause visual and respiratory problems. Care and proper safety clothing should be used when handling and mixing these chemicals.

Our environment is one of our most precious resources. It can be damaged by fluids used in and produced from the well. Regulatory bodies mandate and public concerns demand actions to prevent and report spills. Safely haul and properly dispose of fluids used on rigs.

TEMPERATURE

Density, remedial fluid rheological properties, and the effectiveness of various additives are affected by temperature. Downhole temperatures are of the greatest concern. The effective density of many remedial fluids decreases as temperature increases. Remedial fluids should be designed with this in mind, and efforts should be made to determine downhole temperature. Also, temperatures at the flowline and pits should be known to give information that may avert a potential problem. (See crystallization later in this chapter.)

COMMON FLUID TYPES

OIL

In most producing areas, oil is plentiful and economical to use. It is usually non-corrosive, and oil will not cause clay swelling in the producing zone. And oil is light (approx. 7 ppg [839 kg/m³]), which is excellent for low pressure oil wells. Some precautions when using oil are:

w Oil can contain wax, fine particles of sand, solids or asphalt.

w Oil may be corrosive if H2S or CO2 are present.

w It may be too light to maintain proper hydrostatic pressure in some areas and too heavy in others.

9-15FLUIDS

w Oil is a fire hazard, and very slippery, especially if pulling a wet string of pipe.

w Oil pollutes if spilled.

w Oil may not be compatible with the reservoir oil if it is from elsewhere in the field.

w Oil should never be used in a gas well.

Diesel oil and kerosene are sometimes used. Both are more expensive and can be hazardous. They are, however, clean and non-corrosive. Proper fire-extinguishing equipment should be in accessible locations and crews should be trained in their use.

OIL-BASED FLUIDS (OIL-IN-WATER, WATER-IN-OIL EMULSIONS)

The most common emulsion fluid is oil-in-water. With oil-in-water, oil is the dispersed phase and exists as small droplets. The continuous phase may be fresh or salt water fluid. Stability depends on the presence of one or more emulsifying agents (starch, soap or organic colloids). Diesel oil is satisfactory to use for the dispersed phase. The advantage of using diesel to work over a well is that it is less damaging to the productive formation. The inverse of oil-in-water is the water-in-oil emulsion. In a water-in-oil emulsion, water is the dispersed phase, and the oil is the continuous phase. Filtrates (fluid loss rates) are low and usually any filtrate obtained should be oil. This mixture is very unstable above 200° F (93° C). If these combinations are solids laden, they can cause formation plugging.

GAS

Gas can be used in low formation pressure reservoirs. During operations with this medium, the well is controlled only by surface backpressure. Natural gas, while readily available and cheap in some fields, is extremely flammable. Nitrogen gas is inert and has a number of favorable qualities. Chemically it will not harm the formation, metal goods or rubber seals.

Cleaning trash from the well can be a problem with gas. Foam mixed by the Service Company supplying the nitrogen is available. It has good to excellent hole cleaning and carrying capacity.

WATER

Water base fluids include fresh water, brine water and muds.

w Fresh water used in remedial activities has been losing favor over the past few years in many areas. It can hydrate clays and severely damage formations. Low salinity water is usually plentiful and inexpensive. Normally water requires little treatment. However, beware of the high solids associated with some waters. If in doubt as to solids in the water, filtration should be considered.

w Brine waters are salt solutions that are commonly used. Brines are readily available and can be easily mixed. The cost is usually low. There is no explosion or fire danger, but brines can be an environmental hazard in some areas.

w Muds combine water, clays and chemicals to give various properties. Muds have high solids contents and may be damaging to certain formations by water loss and blocking of pore spaces. Their cost is relatively low and they are easy to work with most of the time. They make controlling a high-pressure, high-permeability gas well simpler. Sometimes it is necessary to use this fluid if there is a high loss of a very expensive clear fluid. In a dual completion, one zone may take fluid at a lower pressure than is necessary to hold the other formation. Economics may also be a factor when determining which fluid to use. Mud makes a very poor packer fluid.

If oil is to be used as a completion fluid, crews should be trained to use onsite fire extinguishing equipment.

CHAPTER 99-16

When very high density brines are required, a mixture of several salts

is used.

DENSITY OF BRINES

When salt is added to solutions, it increases density and hydrostatic pressure. This should not increase the solid content of the solution, as extra salts dissolve into the solution. The increase in salt concentrations does inhibit clay hydration. In some areas, however, salt waters will swell shales and clays. Calcium or potassium can be used to prevent this. If lease saltwater is used, be sure no oil wetting emulsion breakers were added during production. If any solids are present, be sure to filter the water.

Single-salt brines, such as sodium chloride (NaCl), potassium chloride (KCl), calcium chloride (CaCl2) and calcium bromide (CaBr2) all fall in the lower density range. The most commonly used single-salt brine is sodium chloride. We can increase the density of simple salts by adding more salt until we reach a saturation point at a given temperature.

Multi-salt brines (where two or more salts are added) can be used when higher densities are needed. The ratio of one salt to the other(s) must be carefully controlled. Listed in the chart below are the density ranges of some fluids.

Some acidic compounds can become a serious corrosion problem at higher densities. They can corrode well equipment in a short time. Always circulate them out from bottom as soon as possible. There are many fluid charts and graphs available from brine/additive suppliers. Check with the manufacturer for the correct density at specific temperature and for pressure requirements. Sack or weight materials should be kept on hand. Many brines are hygroscopic, meaning they absorb water from the atmosphere. In humid regions, density can reduce several tenths of a pound per gallon over several hours. The reduction is more pronounced in heavier fluids, but can occur at lighter densities. Keep a close watch on fluid density.

CRYSTALLIZATION

Commercial crystal development has been a great benefit to mankind. But crystal formation in fluids can be a real hazard. When mixing a fluid, different salt and mineral combinations may be used to get the desired fluid weight at the most economical and safest condition.

FLUID DENSITIES

APPROXIMATE APPROXIMATE PRACTICAL

FLUID TYPE MINIMUM DENSITY MAXIMUM DENSITY MAXIMUM DENSITY (PPG) (KG/M³) (PPG) (KG/M³) (PPG) (KG/M³)

Oil 6.0 719 8.5 1018 8.0* 958 Diesel Oil 7.0 839 7.0 839 Fresh Water 8.3 998 Sea Water 8.4 1006 8.6 1030 8.5 1018 Brine-Sodium Chloride (NaCl) 8.4 1006 10.0 1198 9.8 1174 Brine- Potassium Chloride (KCl) 8.3 995 9.8 1174 9.7 1162 Brine-Calcium Chloride (CaCl2) 11.0 1318 11.6 1390 11.5 1378 Brine-Calcium Bromide (CaBr2) 11.7 1402 15.1 1809 14.6 1750 Brine-Zinc Bromide (ZnBr2) 15.2 1821 21.0 2516 19.2 2301

* Some oils will sink in water.

FLUIDS9-17

A good packer fluid is non-corrosive and temperature stable.

Often, the mixture contains all the material that water can hold at given temperatures. This is called the saturation point. No further weight will be gained by adding more material. Should material be added, with the temperature held constant, one of two things will happen: the material will fall to the bottom of the tank or crystallization will occur. Crystallization looks like ice is forming and is called freezing by field personnel. Should the temperature of fluid in the tanks be reduced by a change in weather or other conditions, crystallization can occur. Crystallization reduces not only the fluid density, but also its ability to be pumped.

Charts on the particular fluid being used should be consulted for the fluid’s exact data. Temperature affects different solutions in different ways and winter blending is available to reduce the freezing point. For some examples, see the chart at right.

Variations in the ratio of brines and brines to water in solutions may affect the crystallization point drastically. Therefore, do not use training manual information. Get actual charts and graphs from the fluid supplier for your particular situation.

When remedial fluids like those described in this section are used in cold climates, steam coils or some other heat should be available for the tanks. Long line sections should be insulated. Winter blends reduce the freezing point, but they increase the cost per barrel.

PACKER FLUID

One of the most important procedures in a workover is often the last step before putting the well back on production. This is displacing the space between the casing and tubing with a fluid which will remain in this area until the well is reworked again or abandoned. Primary functions of a packer fluid include providing formation pressure control and preventing the collapse of casing and burst of the production string. A good packer fluid should be non-corrosive, stable with time and temperature,

should not allow solids to fall out on top of the packer and should be economical. In addition, the fluid must be pumpable and remain pumpable and must not harm packer seals.

CRYSTALLIZATION OR FREEZE POINTS

SODIUM CHLORIDE (NACL) BRINE

CRYSTALLIZATION

WEIGHT OR FREEZE POINT (PPG) (KG/M³) (°F) (°C)

8.5 1018 29 - 1.6 9.0 1078 19 - 7.2 9.5 1138 6 -14.4 10.0 1198 25 - 3.8

CALCIUM CHLORIDE BRINE

CRYSTALLIZATION

WEIGHT OR FREEZE POINT (PPG) (KG/M³) (°F) (°C)

8.5 1018 30 - 1.1

9.0 1078 21 - 6.1

9.5 1138 9 -12.7

10.0 1198 - 8 -22.2

10.5 1258 -36 -37.7

11.0 1318 -22 -30

11.5 1378 1.6 35

CALCIUM CHLORIDE/CALCIUM BROMIDE

CRYSTALLIZATION

WEIGHT OR FREEZE POINT (PPG) (KG/M³) (°F) (°C)

12.0 1438 54 12.0

12.5 1498 57 13.8

13.0 1558 59 15

13.5 1618 61 16.1

14.0 1678 64 17.7

14.5 1737 65 18.3

15.0 1797 67 19.4

9-18CHAPTER 9

Soft (pumpable) plugs may be used to solve

many downhole problems.

In older wells, drilling mud was left in the hole as the packer fluid. This often caused expensive fishing jobs on workover of the well from separation of the solid phase from the fluid phase over time. The precipitation (fallout) of solids produced a cement-like accumulation of solid settlement on top of the packer. Lime-based muds used as a packer fluid – when exposed to temperature – react with the clays in the mud and can set up, much like cement. These problems led to development of the many good packer fluids now available.

PLUGS AND PILLS

Plugs or pills are used, like mechanical plugs, to solve or control many downhole problems and for downhole treatment. Plugs and pills have many uses, including the following.

w Seal casing leaks

w Correct the injection profile in water injection or disposal wells

w Stop lost circulation in permeable sands

w Divert acid during well clean-up or stimulation

w Shut off salt water flows

w Be spotted inside tubing or workstring of 1,000’ or more. They can be readily removed and can be worked through with concentric tubing or coil tubing

w Stabilize unconsolidated gravel zones

w Seal fractures

w Improve cement jobs by running them ahead of the cement to prevent loss of low viscosity cement to theft zones

w Kill underground blowouts

To accomplish these tasks, there are many different soft, or pumpable, plugs. They may consist of neat cement, thickened oil base mud, diesel oil/cement, diesel oil/bentonite, bentonite/cement, silica/clay, polymers, plastics, acids or other miscellaneous lost circulation materials, plugging and treatment chemicals.

These compounds are often weighted and their viscosity is relatively high. Setting retarder

or accelerator may be used, depending on temperature and pumping time. Viscosifiers are also quite commonly used.

On some occasions, a time-delayed self-complexing plug may be called for. If necessary, a breaker can be added to provide a predictable plug breakdown time, usually from one to ten days. (This is easily accomplished in polymer pills with an enzyme that reduces the large polysaccharide [sugar] molecules to low molecular weight polymers and simple sugar.) Any time a polymer plug is in contact with a producing zone it should contain some breaker.

A typical case would be a dual well where one zone requires a certain density to kill it, and that density would cause lost circulation in the other zone. Depending on mechanical facilities and arrangement of packers, tubing, etc., spot a small pill or plug in the weak zone. Add sufficient breaker to dissolve this plug at some future time if the weak zone is to be returned to production. For typical operations, pills or plugs of 5 barrels (0.8 m³) are usually sufficient. Frequently, one or two barrels is adequate.

Polymers can be used to create an elastomeric type pack off in the tubing string. This is done by using a polymer that will flash set. The tubing or the workstring can be filled from the surface with a tough, rubbery plastic polymer, weighted as much as desired. Concentric pipe can be pushed through this pack off and withdrawn, rotated or reciprocated as much as desired. Once the string is withdrawn, then the resulting hole will close back up.

Caution should be used to avoid mixing plugs that, on breaking, form water or acid insoluble precipitates, which could invade the productive formation. Pilot testing should be used if breakers are used. These systems should be mixed through a hopper and well agitated to assure thorough mixing. In order to be effective, soft plugs must be pumped to the correct predetermined location in the well. Doing this correctly often requires some calculation.

9-19FLUIDS

Often, careful monitoring of the work fluid can help in identifying downhole problems.

GENERAL FLUID SAFETY

During the mixing of any fluid system, all personnel should be informed of the hazards involved in handling and mixing the chemical solutions. Remember these chemicals can cause serious burns, be toxic to man and the environment, and cause visual and respiratory problems. Often, chemicals thought to be minimally harmful can cause harm in concentrated form. Industrial chemicals used in the oilfield are usually concentrated. Protective clothing, goggles, vinyl or rubber gloves, aprons, boots, etc., should be used when handling and mixing chemicals. Have MSDS sheets on location for hazardous materials. When chemicals are to be mixed with water or with other fluids, mix the chemicals into the water or fluid in order to reduce the possibility of a violent reaction. Always have a method of washing eyes and skin near the mixing point. On contact with eyes and skin, immediately begin to flush the area with water and report incident to supervisor for further instructions.

Pit jetting or mixing guns should be secured in one position while unattended. Material should be stacked to a reasonable height to minimize handling and danger.

SUMMARY

Fluids play an important role in any process. For workover, completions and drilling, the condition of the fluid can increase overall rig performance and minimize potential formation damage. Fluid should be monitored closely to ensure it meets all specifications. Monitoring of fluid in the pits or tanks can indicate the presence of downhole problems. Time is money: nowhere is this more evident than when looking at the invoices for activities gone wrong. Often an excessive number of rig hours is due to poor fluid application. Rig costs are driven up and other services are affected.

Toolpushers and drillers are not expected to be mud engineers, but changes on the drilling console gauges can reflect changes in the flow properties or hole conditions. The fluid used is like blood in the human body. It circulates around the system, and if problems occur, then simple tests can help evaluate these problems. Tests on fluid should be performed regularly, both by the mud engineer and the crew, and any fluid changes reported.

Finally, as many oilfield fluids are dangerous, safety cannot be stressed often enough.t

CHAPTER

10

The well cannot

be controlled without

properly maintained,

functioning equipment.

SURFACEEQUIPMENT

10-1

T he Blowout Preventer Stack is such a vital part of the rig equipment that it should never be overlooked. The BOP system

is actually a unique set of very large hydraulic valves. BOPs have large bores, high-pressure rat-ings, and operate quickly. These characteristics build some limitations into the system that the operating crew needs to be aware of and watch carefully.

BOP STACK ORGANIZATION

The BOP stack may be built in a variety of configurations. American Petroleum Institute (API) Code to describe stack configurations is contained in API Bulletin RP53. The recommended component designation codes for blowout preventer arrangements are as

10-2CHAPTER 10

The purpose of the BOP stack is

to close in the well and allow

the greatest flexibility for subsequent operations.

follows.A = annular type blowout preventerG = rotating headR = single ram type preventer with one set of

rams, blind or pipe, as operator prefersRd = double ram type preventer with two sets of

rams, positioned as operator prefersRt = triple ram type preventer with three sets of

rams, positioned as operator prefersCH = remotely operated connector attaching

wellhead or preventers to each otherCL = low pressure remotely operated connector

attaching the marine riser to BOP stackS = spool with side outlet connections for

choke and kill lines

M = 1,000 psi (68.95 bar) rated working pressure

Components are listed reading upward from the bottom of the preventer stack. Blowout preventer stacks may be fully identified by simple designations, such as:

15M–7-1/16” (179.39 mm)–RSRRA10M–13-5/8” (346.08 mm)–RSRRA 5M–18-3/4” (476.25 mm)–RRRRAA.

The first of the previous preventer stacks would be rated 15,000 psi (1034.2 bar) working pressure, would have a bore of 7-1/16 inches (179.39 mm), and would be arranged as in the first example in the figure below.

This illustration, from API RP53 “Blowout Prevention Equipment Systems,” shows three configurations, but several more are possible in an annular and three ram arrangement.

The most important consideration of how the stack is organized is what appears to be the greatest hazard that may be encountered. In this regard, several points could be made.

w Stack requirements should be based on a per job basis.

w None of the three figures shown is suitable for ram to ram stripping according to the general rules of stripping. For ram to ram stripping, the minimum configuration is RRSRA or RRRA if the BOP side outlet will be used to circulate.

w Desirable configurations are endless, but more rams make the stack heavier, larger, and more expensive. Fewer rams have less flexibility and reduce safety.

w The best stack arrangement is one that is adequate for the job and area, and has a degree of safety built as well.

From the viewpoint of well control, the purpose of the BOP stack is to close in the well when a kick occurs and still allow the greatest flexibility for subsequent operations. If this is kept in mind, many possible stack configurations are satisfactory. Critical concerns of well control operations are some inherent limits such as pressure, heat, space, economics, etc., in the design or operation of the stack.

Typical BOP stack arrangements

10-3SURFACE EQUIPMENT

Annular preventers are the most versatile wellhead pressure control devices.

ANNULAR PREVENTERS

Annular preventers, sometimes called bag preventers, spherical preventers, or simply Hydrils, are probably the most versatile well-head pressure control devices. Some models are highly wellbore energized, that is, well pressure pushes upwards and provides additional sealing force. The annular preventer is used for a closing seal around whatever may be in the hole and as a lubricating head for moving or stripping pipe under pressure. Most modern annular preventers will close around the kelly, collars, drill pipe, work string, tubing, wireline, or in an emergency, the open hole.

The preventer consists of a circular rubber packer element, a piston, a body and a head (cap). When hydraulic fluid is pumped into the closing chamber, a sequence takes place in which the sealing element is forced inwards. Depending on the manufacturer and model, the inner workings of equipment may vary in how that seal is obtained, but typically it is by vertical or horizontal packer movement. It is the packer within the annular that provides the seal. Spare parts for annulars should include the appropriate packer and sealing elements.

There are many manufacturers with various models in use today, such as the Hydril GL, GX and the GK, Cameron D and DL, and the Shaffer bolted cover and wedge cover. All three companies offer dual housing models for Subsea applications or when two annular preventers in tandem are needed and space may be a problem. Operating pressures, characteristics

as well as limitations will vary with the different makes and models. It is for this reason that hydraulic regulators should be available for all annular preventers to allow adjustment of the operating pressure when needed.

The regulator valve that supplies closing pressure will allow flow in both directions. This is an important feature for moving or stripping pipe and tool joints through it to keep a constant closing pressure and seal against the pipe. However, if well pressure exceeds the manifold pressure and a seal fails, well pressure can unload through the closing line regulator back to the accumulator reservoir.

The biggest problem in field use of various makes and models appear to be the user’s lack of knowledge of that specific model. It is good practice to check the manufacturer’s manual to find correct operating pressure characteristics of various preventers, and what recommended closing pressure should be, given the well’s pressure and size pipe in use. The essential thing is that the packer must exert enough pressure against the pipe to ensure a good seal, but pressure should not be so tight that the packer element will deteriorate. Not using correct pressures could lead to early failure and subsequent replacement, which are costly and time consuming. In some cases, these failures can have disastrous effects.

Most annular preventers are designed for a maximum recommended closing pressure of 1,500 psi (103.42 bar), though some annular BOPs have a maximum operating chamber working pressure of 3,000 psi (206.24 bar). The minimum pressure to obtain a seal is

Two examples of annular preventers

CHAPTER 1010-4

dependent on several factors such as bore size, outer diameter (OD) of the pipe and the wellbore pressure. In general, the larger the bore size and the smaller the pipe, the more the closing pressure that is required to ensure a seal, although certain models have very specific closing pressure requirements.

Generally, the regulated pressure for an annular preventer should be about 500 to 800 psi (34.47 to 55.16 bar) when moving the pipe. The rubber packer in the annular preventer that allows this flexibility is the critical part of the preventer and can be destroyed through misuse or abuse. The use of improper operating (accumulator) pressure on the annular preventer is one of the major sources of abuse that causes failure of the annular preventer packer. Although the annular will close on a multitude of pipes and shapes, it should be tested using the tube body of the string in use. There are occasions where a seal is necessary, such as when closing around a wireline or the kelly, or when H2S gas is present. It should be remembered that these operations might result in reduced life of the packer element. In using the annular preventer, every effort should be made to use as little operating pressure as possible. Minimal closing pressure will help to preserve the packer.

It takes more hydraulic fluid to close an annular preventer than a pipe ram. So it will take longer to close an annular than a ram type preventer. Higher closing pressures will not improve closing time as much as larger diameter operating lines, larger fittings and regulators.

Annular preventer operation on the rig can be improved by observing the following.

w Never use more pressure on closing unit than necessary, especially if moving pipe.

w Test packer when it is put in preventer, as required by operations, according to state or federal regulations or industry practices.

w Check manufacturer’s manual for operating data of various models. There can be considerable differences in operating data for various annular preventers.

w Moving pipe through the preventer at high closing pressures could cause wear and early failure of packer element.

w Store packers in cool, dry, dark areas away from electric motors.

w As always, consult the manufacturer’s manual or talk to a service representative for the proper control pressures, rubber compounds, additional stripping procedures, equipment limitations, testing or any questions you may have about your particular model.

It should be pointed out that packers for certain annular preventer models can be split to allow removal when the kelly or string cannot be removed from the well bore. Annular packer elements are available from the factory already split. Pre-split packers are a great convenience if the annular preventer will be used to strip pipe.

Remember you must always consult a manufacturers operator’s manual or talk to a service representative for the proper control pressures, rubber compounds, additional stripping procedures, equipment limitations, testing or any questions you may have about your particular annular preventer model.

Stripping through an annular preventer

Moving pipe through the

preventer at high closing pressures

causes wear and packer

failure.

SURFACE EQUIPMENT10-5

SPECIAL PURPOSEANNULAR PREVENTERS

Most manufacturers of BOP equipment offer a variety of special purpose annular type preventers. The specific function of each is indicated by its name, including rotating heads, tubing strippers, wireline strippers, rod strippers, stuffing boxes and circulating heads.

This group of equipment allows for the stripping or rotation of pipe, wireline, or pumping rods, while the well is under pressure. The packing element is flexible enough to expand and contract to conform to the size and shape of the string that is in the hole. While flexible, care should be used to insure that tool joints, collars, and other connections are stripped slowly to prevent the premature failure of the packing element.

These preventers often replace the standard annular preventer. They function manually or hydraulically, or they may have a permanently

seated packing element that is always closed, depending on the type and model. In addition, many of the models are equipped with slip bowls.

DIVERTER SYSTEMS

The diverter system is an annular preventer coupled with a large diameter piping system underneath. It is used when only conductor pipe is set and to divert flow and gas from the rig on vessels with a riser. The large diameter pipe, or blooie line, usually has routing in two directions. This system pipes, or diverts, the stream of wellbore fluids away from the rig and personnel. Diverter systems should be used if a well cannot be shut in for fear of lost circulation or formation breakdown. Some government regulations and operator policies require the use of diverters. Depending on the type of operations, for instance on floating rigs, diverters may be used throughout the entire drilling operation.

Typically, the diverter system is installed on conductor casing or as part of the marine riser, with diverter lines running to a safe, downwind area. For this reason, on offshore locations two diverter lines are utilized with selective valving, so that the driller may select the downwind line tourly, or as the wind conditions change.

The diverter controls on the floor are best arranged as a single separate control to avoid confusion, since diverter operations are usually undertaken quickly. The control lever on the accumulator should be coupled with the control for the diverter line so the annular preventer can’t be closed before the diverter line(s) open.

Diverter systems are used to protect personnel and

equipment from shallow gas flows.

On floating rigs, diverters may be used throughout the entire drilling operation.

10-6CHAPTER 10

The rotating head, or

rotating BOP, allows rotation

of the string with pressure

below it.

Diverter systems are designed for brief periods of high flow rates, not high pressure. Erosion at high flow rates is a concern. The larger the diverter lines, the better. Some operations utilize both an annular and ram preventer above the diverter line(s) due to high flow rates. To minimize erosion effects, the lines should be as large and simple as possible, and targeted to the vent location with a minimum of bends or turns. Testing should include a function test, pumping water at a maximum rate to assure that the system is not blocked, and a low pressure test in accordance with state or government regulations.

ROTATING HEADS/BOPS

The rotating head or rotating BOP is becoming commonplace in many areas. It allows rotation of the string with pressure below it. Underbalanced drilling operations can continue with circulation through the choke manifold. Several manufacturers (Williams Tools, Shaffer, Grant, etc.) have models that allow rotation of the string, or maintaining static pressures to 5,000 psi (344.75 bar). Given the nature of rotating pipe while under pressure, several replacement packer elements should be maintained on location. In case of a packer leak, consideration should be given to replacing element before operations continue. Sudden failure of the sealing packer may occur at higher pressures.

Depending on the manufacturer, additional equipment may be required. This may include a dedicated hydraulic unit, rig floor control panel, and cooling systems. Proper documentation on these units should be kept on location and all personnel instructed in the specifics of how to operate this equipment.

RAMS

The pipe ram is the basic blowout preventer. The reliability of the ram is in part due to basic simplicity and in part due to the effort put into the design of the ram. Most ram preventers are normally closed with 1,500 psi (103.42 bar) operating pressure and should not be varied unless specific conditions or type of ram require a different pressure or procedure.

Three components for a rotating head system.

Left to right: a chiller,

a control panel and a

rotating head

A BOP accumulator control panel

10-7SURFACE EQUIPMENT

Most rams are designed to seal pressure from the lower side only.

Rams come in many sizes and pressure ratings. There are many types of custom built or specialty rams designed for particular applications. Rams range from simple manual one-ram sets to multiple-ram set bodies. Simple rams may consist of a polished rod that closes by turning handles on either side to screw the ram inward and around the pipe. Complex multiple sets of rams may be housed in a single body remotely operated by hydraulic pressure.

The rams of most BOP systems are closed by means of hydraulic pistons. The piston rod is sealed against the well by a primary lip seal, installed in the bonnet, through which the operating rod passes. It is very important that wellbore pressure is sealed from the operating cylinder. If well pressure bypasses the primary seal and enters the operating cylinder, it may force the ram open. To prevent this, a series of secondary seals and a detection method are

provided, including back up O rings, plastic packing injection seal and a vent to the atmosphere. If fluid is noticed venting out of the BOP, the secondary or auxiliary plastic seal should be energized to seal against the piston shaft.

Some ram BOP closing systems use a screw jack to close the preventer, but regulations often dictate that BOPs be hydraulically operated. In case of hydraulic system failure, most rams can be manually closed, unless they’re equipped with a hydraulic ram lock system. When closed, rams can be locked with hydraulic or manual (hand wheel) locking systems.

Most rams are designed to seal against pressure from the lower side only. This means the ram will not hold pressure if placed in an upside down position. Additionally it will not pressure test from the top side. Therefore, care must be used when installing the stack to ensure that it is right side up. The manufacturer’s name should be right side up, and circulating ports or outlets should be located below the ram.

When changing packers on rams, remember most problems come from improperly closing and sealing the bonnet or door seal. It is good practice to inspect and replace these seals as necessary, each time the rams are changed or the doors opened. A set of pipe rams and ram sealing elements for each size pipe used should be kept on location as well as complete sets of bonnet or door seals for each size and type of ram preventer used. Plastic packing for the secondary seals should also be kept on hand.

Three ram preventer models

CHAPTER 1010-8

PIPE RAMS

Pipe rams are designed to close around pipe. The basic strength and main limitation of a pipe ram is the ram block cutout. The ram preventer is a steel block cut to fit the pipe size around which it is to be closed. The cutout is meant to close and provide a good seal around one particular diameter or size pipe. There is a self-feeding packer rubber in the cutout that seals the ram around the pipe. Another self-feeding rubber packer (top seal) in the top of the ram seals upward against the top of the ram opening in the preventer body to seal the annulus against pressure.

Most rams have guides to center the pipe. The ram block cutout fits the pipe size closely. While the ram will close around pipe that has a small taper, it will not close around the tool joint without crushing the joint or damaging the ram face. Special care must be taken when closing the ram near a tool joint, especially when working with aluminum pipe, which has a larger taper than steel pipe.

Pipe rams should not be function tested without the appropriate size pipe in the preventers to prevent damage. They should not be closed on an open hole, as damage and packer extrusion may occur.

Pipe and tubing can be moved in the pipe rams. To minimize wear on the packer surfaces, the closing pressure should be reduced to approximately 200 to 300 psi (13.79 to 20.62

bar). Pressure from the well forces the rubber on the top of the ram block against the preventer body, which helps to seal off the well. Accumulator operating pressure for the rams should be regulated according to the manufacturer’s operating instructions. Pipe movement in the rams should be minimized, particularly abrupt reversals of pipe direction.

BLIND RAMS

Blind rams are a special type of ram with no pipe cutout on the ram block. Blind rams have large packer elements, and are made to close with no pipe in the hole. When tested, they should be pressured to full rating.

SHEAR RAMS

Shear rams are another type of ram, but with special shear blades to cut tubular goods (tubing, drillpipe, collars, etc.). Higher than normal regulated pressures and/or the use of hydraulic boosters may have to be used depending on the type of shear ram and the tubular to be cut. Shear rams have small closing tolerances. When they are closed for function testing they should not be slammed shut with high-pressure, but closed with a reduced operating pressure of about 200 psi (13.79 bar). When shear rams are pressure

Left: pipe ram blocksRight: blind ram blocks

Pipe rams should not be closed

on an open hole, as damage and packer

extrusion may occur.

SURFACE EQUIPMENT10-9

tested, the packer is extruded. Since the packer element in shear rams is small, very few pressure tests can be performed while retaining a useable packer element. Do not pressure test shear rams any more than necessary.

BLIND/SHEAR RAMS

Blind/shear rams combine both blind or open hole closing capability with shearing or cutting ability. These offer the advantage of cutting the pipe and sealing on the open well bore after the pipe is cut. Another plus of the blind/shear rams is the space saving advantage of using one set to do the jobs of both blind and shear rams.

VARIABLE BORE RAMS

Variable bore rams (VBRs) seal on several sizes of pipe, and depending on the type of VBR, on a hexagonal kelly. They may also

serve as the primary ram for one size pipe and a backup ram for another size. On wells with tapered strings where space is a concern, variable bore rams may also be used. In addition, a set of variable bore rams in a preventer may save a round trip of the subsea blowout preventer stack. This is because the rams do not have to be changed when different diameter pipe strings are used.

On one type of VBR, the packer contains steel reinforcing inserts similar to those in the annular BOP packer. These inserts rotate inward when the rams are closed, so that the steel provides support for the rubber which seals against the pipe. In standard fatigue tests, variable bore ram packers performed comparably to pipe ram packers. Variable bore rams are suited for H2S service.

Another type of VBR consists of several small pipe cutout plates which slide back out of the way of larger sized pipe until the correct cutout closes around the pipe. Sealing elements are placed between each plate to effect a seal.

Below: blind/shear ram blocks Right, top to bottom: shear ram blocks and two

examples of variable bore ram blocks

Variable bore ram packers performed comparably to pipe ram packers in standard fatigue tests.

10-10CHAPTER 10

There are many types of

hydraulic ram locking systems.

HYDRAULIC RAMLOCKING SYSTEMS

There are many types of hydraulic ram locking systems. The following are descriptions of several manufacturers’ types.

The Hydril multiple position lock (MPL) is a hydraulically operated mechanical lock which automatically maintains the ram closed and locked with the optimum rubber pressure required for seal off of the front packer and upper seal.

Hydraulic closing pressure closes the ram and leaves the ram closed and locked. The engaged clutch assembly allows unrestrained closing motion but prevents opening motion. Hydraulic opening pressure unlocks and opens the ram. Unlocking and opening motion are achieved by the application of opening pressure in the opening cylinder, which disengages the clutch assembly.

Three types of ram locks

PREVENTER BORE PIPE SIZE RANGE INCHES MILLIMETERS INCHES MILLIMETERS

7-1/16 179.39 2-7/8–2 3/8 73.03–60.33

7-1/16 179.39 3-1/2–2-3/8 88.9–60.33

7-1/16 179.39 4–2-7/8 101.6–73.03

11 279.40 2-3/8–3-1/2 60.33–88.9

11 279.40 5–2-3/8 127–60.3

11 279.40 5–2-7/8 127–73.03

13-5/8 346.08 5–2-7/8 127–73.03

13-5/8 346.08 5-1/2–3-1/2 127–88.9

13-5/8 346.08 6–3-1/2 152.4–88.9

13-5/8 346.08 6-5/8–5 168.28–127

16-3/4 425.45 5–2-7/8 127–73.03

16-3/4 425.45 7–3-1/2 177.8–88.9

18-3/4 476.25 5–2-7/8 127–73.03

18-3/4 476.25 5–3-1/2 127–88.9

18-3/4 476.25 7-5/8–3-1/2 193.68–88.9

10-11SURFACE EQUIPMENT

Common compounds used for packer elements are natural rubbers, nitrile and neoprene.

Incorporated in the MPL is provision for testing the locking mechanism. Manually operated lockout devices prevent opening pressure from disengaging the clutch assembly. Application of opening pressure then simulates opening forces applied to the ram thus testing proper functioning of the lock. The lockout device position is visually indicated.

Cameron wedgelocks lock the ram hydraulically and hold the rams mechanically closed even when actuating pressure is released. The operating system can be interlocked using sequence caps to ensure that the wedgelock is retracted before pressure is applied to the open BOP. For subsea applications, a pressure balance chamber is used with the wedgelocks to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic pressure.

The Shaffer UltraLock system incorporates a mechanical locking mechanism within the piston assembly. This locking system is not dependent on closing pressure to maintain a positive lock. It uses flat tapered locking

segments carried by the operating piston which engages another stationary tapered shaft located within the operating cylinder. Only one hydraulic function is required to operate the cylinder’s open/close function and the locking system. The system automatically locks in the closed position each time the piston assembly is closed. Once the operating piston is closed on the pipe, the locks are engaged until opening pressure is applied. Only hydraulic pressure can unlock and reopen the preventer.

SEALING ELASTOMERICCOMPONENTS

The packer or sealing elements of annular and ram preventers come in many sizes and pressure ratings. They are constructed of a high tensile rubber or rubber like material that is molded or shaped. Annular preventer packers are molded around a series of steel fingers. The steel fingers add strength and control the extrusion of packer material. The packer element may be made from a multitude of different compounds for a variety of uses. The most common compounds used for packer elements are natural rubbers, nitrile and neoprene. Specific compounds have been formulated for oil tolerance, extreme cold and heat, sour gas and corrosive environments. Elastomeric components should be changed out as soon as possible after exposure to hydrogen sulfide under pressure.

Examples of BOP sealing elements

CHAPTER 1010-12

Packer elements are identified by a codification system that includes information on the hardness, generic compound, date of manufacture, lot/serial number, manufacturer’s part number and operating temperature range of the component. Spare BOP seals and packing should be kept on location and stored according to the manufacturer’s recommendations. As you can see in the following table, there are many elastomeric compounds. Always refer to the manufacturv er for correct elastomeric or packer element selection.

Remember that maximum packing life will be realized by using the lowest closing pressure that will maintain a seal. When pipe is moved or rotated in a packer, the longest packing unit life is obtained by adjusting the closing chamber pressure low enough to maintain a seal on the pipe with a slight amount of fluid leakage. This leakage indicates the lowest usable closing pressure for minimum packing unit wear and provides lubrication for pipe motion. If pipe movement is not desirable or possible, a pressure tight seal with no leakage is required.

DRILLING/SPACER SPOOLS

If abrasive fluids are circulated, it is not usually desirable to circulate through the circulating ports of ram preventers, risking BOP body damage. The drilling or circulating spool provides outlets and is less expensive to replace. This will add additional height to the stack and increases the number of connection

points whereby a leak may develop. However, the drilling/spacing spool does provide more flexibility for choke or kill line connection options. It also allows additional space between rams to facilitate stripping operations and is often incorporated for this reason.

The spool should have a working pressure at least equal to the BOPs in use. The bore of the spool is typically at least equal to the bore of the BOP or uppermost casinghead. It should be equipped with side outlets no less than 2” (50.8 mm) for rated working pressures of 5,000 psi (344.75 bar) or less, and at least one 2” (50.8 mm) and one 3” (76.2 mm) for pressures above 5,000 psi (344.75 bar).

ELASTOMER COMPOUND MARKING CODE

COMMON ASTM NAME CHEMICAL NAME D-1418 CODE

Acrylic Polyacrylic ACM

Butyl Isobutylene-Isoprene IIR

Butyl Epichlorohydrin CO

Butyl Epichlorohydrin-Ethylene Oxide ECO

Diene Polybutadiene BR

EPR Ethylene-propylene Copolymer EPM

EPT Ethylene-propylene Terpolymer EPDM

Hypalon Chlorosulfonated Polyethylene CSM

Isoprene: Nat./syn. Polyisoprene IR

Kel-F Chloro Fluoro Elastomer CFM

Natural Polyisoprene NR

Neoprene Polychloroprene CR

Nitrile Butadiene-acrylonitrile NBR

Silicone Polysiloxanes Si

SBR (GR-S) Styrene-butadiene SBR

Thiokol Polysiloxanes

Urethane Diisocyanates

Vistanex Polyisobutlyene IM

Viton Fluorocarbon FKM

Maximum packing life will be realized by

using the lowest closing pressure

that maintains a seal.

SURFACE EQUIPMENT10-13

STACK INSTALLATION

The casing head provides the foundation for the BOP stack, tubing head and Christmas tree. It provides the housing for slips and packing assemblies to suspend and isolate other casing strings such as intermediate and production casing. If the casinghead is not perfectly vertical, BOP and casing problems may result.

There are general installation guidelines to improve operation and testing of the stack. Always use new ring gaskets between BOPs. When assembling the system, look at each preventer to be sure the writing on the forging is right side up. Circulating ports on rams, if so equipped, should be on the bottom of the ram. Be careful how you pick up the unit. Improper swinging of the system can injure someone, damage equipment, or make it difficult to set it down gently or line it up properly.

A set of ring gaskets to fit flanged connections should be included in the spare parts inventory. Clean the ring grooves and/or mating surfaces with clean rags, soap and water. Wire brushes and scrapers can scratch mating surfaces and ring grooves, and the stack will not test. Make a special effort to identify the closing and opening hydraulic ports and keep them clean. Trash and dirt in the hydraulic operating system will eventually cause the failure of the system. When making up the stack, one component at a time, hand tighten all bolts until the entire stack is made up. Then hammer all.

FLANGES AND RINGS GASKETS

Connection points are a weak point in any piping or valve system and the BOP stack is no exception. Flanges and sealing ring gaskets are subject to abuse in rigging up that can lead to failure on pressure tests. Probably the biggest source of failure is scratching ring-gaskets, ring grooves, or mating surfaces when cleaning or during nipple up. Keep the crew from using wire brushes or scrapers on mating surfaces and ring grooves. Bad seals will not give a pressure test, forcing the disassembly of the stack and perhaps leading to cut out connections. Ring grooves should be cleaned and dry prior to ring installation. However, some manufacturers in cases of close ring-to-groove tolerance may allow an application of light oil (e.g., WD-40) to assist the ring in properly seating. Rings should be thoroughly inspected. Any damage to the ring may prevent it from seating properly.

The crew often does not appreciate how important it is to keep nuts on the connecting flanges tight. The X type rings that are pressure energized help to keep the flanges tight but nothing can replace re-tightening. Type RX and BX ring-joint gaskets are used in self-energized type gaskets or grooves. Type R ring gaskets are not self-energized and are not recommended for use on well control equipment. The RX ring gaskets are used with Type 6BX flanges and 16B hubs. Type BX ring gaskets are used with type 6BX flanges and type 16BX hubs. Installing a

ring gasket

Do not use wire brushes or scrapers on mating surfaces and ring grooves.

10-14CHAPTER 10

The type R ring gasket is not energized by

internal pressure.

Wellhead flange bolts are particularly critical on stacks on jackups and some platform rigs. This is because movement of the long conductor pipe to sea bottom is restrained at the upper end by tying off the stack to the rig. On any surface stack rig, if only the stack is tied off to the rig, tremendous forces can act against the wellhead flange where all the bending is concentrated. This effect can be minimized if it is possible to tie off the conductor against the rig.

The API hub and clamp connection consists of two hubs pulled together against a metal seal ring by a two- or three-piece clamp. This connection requires fewer bolts to make up and is lighter, but is not as strong as the equivalent bore API flange connection in tension, bending or combined loading. However, proprietary clamp or hub connections may be equal or superior to the API flanged connection for combined loading.

COMMON RING JOINT GASKETS

API TYPE R RING JOINT GASKET

The type R ring joint gasket is not energized by internal pressure. Sealing takes place along small bands of contact between the grooves and the gasket on both the OD and ID of the gasket. The gasket may be either octagonal or oval in cross section. The type R design

does not allow face to face contact between the hubs or flanges. External loads are transmitted through the sealing surfaces of the ring. Vibration and external loads may cause the small bands of contact between the ring and the ring grooves to deform plastically, so that the joint may develop a leak unless the flange bolting is tightened on a weekly basis.

API TYPE RX PRESSURE ENERGIZED RING JOINT GASKET

In the RX pressure energized ring joint gasket, sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The RX design does not allow face to face contact between the hubs or flanges as the gasket has large load bearing surfaces on its inside diameter to transmit external loads without plastic deformation of the sealing surfaces of the gasket. A new gasket should be used each time the joint is made up.

Ring joint gaskets – below: type R; top right: type RX, bottom right: type RX face to face

10-15SURFACE EQUIPMENT

The face to face RX pressure-energized ring joint gasket is the API standard joint for clamp hubs.

API FACE TO FACE TYPE RX PRESSURE ENERGIZED RING JOINT GASKET

The face to face RX pressure-energized ring joint gasket was adopted by API as the standard joint for clamp hubs. Sealing takes place along small bands of contact between the ring grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves. It is slightly compressed to achieve initial sealing as the joint is tightened. The increased groove width insures face to face contact between the hubs, but this leaves the gasket unsupported on its ID. Without support from the ID of the ring grooves, the gasket may not remain perfectly round as the joint is tightened. If the gasket buckles or develops flats, the joint may leak.

CAMERON FACE TO FACE TYPE RX PRESSURE ENERGIZED RING JOINT GROOVE

Cameron modified the API face to face type RX pressure-energized ring joint grooves to prevent any leaking caused by buckling of the gasket in the API groove. The same API face to face type RX pressure-energized ring joint gaskets are used with these modified grooves. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The gasket ID will also contact the grooves when it is made up. This constraint

of the gasket prevents any leaking caused by buckling of the gasket. Hub face to face contact tolerances of the gasket and the groove is maintained within tolerances of 0.022 inches (0.56 mm).

API TYPE BX PRESSURE-ENERGIZED RING JOINT GASKET

The BX pressure energized ring joint gasket was designed for face to face contact of the hubs or flanges. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the ring grooves. It is compressed slightly to achieve initial sealing as the joint is tightened. The intent of the BX design was face to face contact between the hubs or flanges. However, the groove and gasket tolerances, which are adopted, are such that if the ring dimension is on the high side of the tolerance range and the groove dimension is on the low side of the tolerance range, face to face contact may be very difficult to achieve. Without face to face contact, vibration and external loads can cause plastic deformation of the ring and may eventually result in leaks. Both flanged and clamp hub BX joints are equally prone to this difficulty. The BX gasket is frequently manufactured with axial holes to ensure pressure balance, since both ID and OD of the gasket may contact the grooves.

Ring joint gaskets – left: type BX; right: Cameron modified type RX

CHAPTER 1010-16

CX pressure-energized ring gaskets allow face to face

contact between hubs

with minimal clamping force.

CAMERON TYPE AX & VETCO TYPE VX PRESSURE-ENERGIZED RING JOINT GASKET

With AX and VX type pressure-energized ring gaskets, sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves and is compressed slightly to achieve initial sealing as the joint is tightened. The ID of the gasket is smooth and is almost flush with the hub bore. Sealing occurs at a diameter, which is only slightly greater than the diameter of the hub bore, so the axial pressure load on the collet connector is held to an absolute minimum. The belt at the center of the gasket keeps it from buckling or cocking as the joint is being made up. The OD of the gasket is grooved to allow the use of retractable pins or dogs to positively retain the gasket in the base of the collet connector when the hubs are separated.

The AX and VX gasket design allows face to face contact between the hubs to be achieved with minimal clamping force. It is used at the base of the collet connector, because the lower gasket must be positively retained in the connector when the hubs are separated. Its design ensures that axial pressure loading on the collet connector is held to an absolute minimum. External loads are transmitted entirely through the hub faces and cannot damage the gasket. The AX and VX gasket also is suitable for side outlets on the BOP stack since these outlets are not subject to keyseating.

CAMERON TYPE CX PRESSURE-ENERGIZED RING JOINT GASKET

The CX pressure-energized ring gaskets allow face to face contact between the hubs to be achieved with minimal clamping force. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. External loads are transmitted entirely through the hub faces and cannot damage the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The gasket is patterned after the AX gasket, but is recessed instead of being flush with the hub bore for protection against keyseating. The gasket seals approximately the same diameter as the RX and BX gaskets. The belt at the center of the gasket keeps it from buckling or cocking as the BOP or riser joint is made up.

MINIMIZING BOP WEAR

Pipe in contact with the BOP stack creates metal to metal friction and wear. It should drop through the BOP center and not contact it. However, centering the bore of the BOP stack is often difficult. Movement, settling, or tipping of the rig can cause off centering of the BOP stack bore. If the derrick is not perpendicular at the base, the top of it may be several feet off-center of the hole.

Ring joint gaskets – left: type AX or VX; right: Cameron type CX

SURFACE EQUIPMENT10-17

The purpose of a fill-up line is to fill the hole during trips and when the well is not circulated.

The wear effect is not immediate, because the rams and annular preventer will close and test. But long-term damage is severe. It can result in off-center wear in the stack and bit or tool gouges in the stack bore, ram or annular faces. Wear and damage also may occur to the casing and wellhead. Minor damage may seal on a test, but there is the chance that further damage will occur and the stack will not seal during a kick. Beyond that, repair to the bore of the stack is a manufacturing plant job that is long and costly. Generally, wear rings, or bushings, will minimize inside wear and damage.

In addition, the stack should be stable. Guy wires and turnbuckles should be horizontal or lead upward from the stack or to deadmen outside the substructure. Guying downward can cause buckling of casing if the rig settles.

CHOKE/KILL LINECONNECTIONS

The high pressure line connections to the stack are weak points that need to be checked and rechecked. Common problems include using nipples that are too light, dirty seal rings, damaged mating surfaces, loose nuts and long unsupported nipples or lengths of pipe. There is very little to say about these points that does not fall under the heading of common sense.

Another source of problems is the use of low pressure hoses where there is not much room for steel piping. This is a doubly-bad situation. Excessive bends in pipe, or bent lines coupled with high-pressure situations, is not a good practice. This becomes particularly hazardous if the line involved is the choke line.

FILL-UP LINE

A fill-up line above uppermost preventer should be included in the stack. The purpose of this line is to fill the hole during trips and when well is not circulated. Maintenance of this line is slight, although if fluid is left in line it may plug and corrosive fluids may damage the line.

BOP TEST TOOL

The design of the BOP test tool varies, but it is a device attached to the end of tubing and run to the bottom of the BOP stack or in the casing head, and is held in place initially by the pipe weight. It is typically fitted with elastomeric seal rings and may also have several sealing cups to effect a seal. Use care: if the seals fail, the wellbore may be energized. Above the seals is an opening to the ID of the pipe to allow water to be pumped to fill the bore and allow pressure testing of the BOPs. On the upper part of the joint(s) of pipe is another tool with connection fittings to manifold back to the test pump.

Make sure connections are properly made up.

BOP test tool

Hydraulic actuated valve

Manual operated valve

10-18CHAPTER 10

The accumulator provides a

rapid, reliable way to close

blowout preventers when

a kick occurs.

The maintenance of the test tool should include component inspection, proper cleaning and storage after each use and inspection and replacement of sealing elastomers as needed.

CLOSING/ACCUMULATOR SYSTEMS

Blowout preventers for rotary drilling date back to the early part of the 20th century. However, it was the 1950s before there were good methods of closing the preventers. Older BOP units used a manual screw-jack system. Some manual closing systems are still in use on small rigs. During the beginning of a well kick, it is essential to shut the well in quickly to keep the kick small. Manual operating systems are generally slower than hydraulic units and may lead to larger influx volumes.

Fluid pumps, rig air and hydraulic pump closing units have all been tried and were unsatisfactory. Hydraulic accumulators are the first systems that have proven satisfactory.

The accumulator provides a rapid, reliable and practical way to close blowout preventers when a kick occurs. Because of the importance of reliability, closing systems have extra pumps and excess fluid volume in addition to alternate or backup systems. Air/electric-powered pumps

are rigged to recharge the unit automatically as the pressure in the accumulator bottle drops.

The standard rig system uses a control fluid of hydraulic oil or a mix of chemicals and water stored in 3,000 psi (206.84 bar) accumulator bottles. Enough usable fluid is stored under pressure so all stack components can function with pressure along with a reserve for safety.

In extremely cold environments, care should be taken not to let the core temperature of the accumulator system drop below freezing. The rubber goods inside, such as the bladders, will become brittle and can burst.

The basic accumulator system should have maintenance at least every 30-days or every well (which ever comes first). The following 30-day schedule is a guide, but may not be sufficient for some operations. The following needs to be checked during operational maintenance of the master accumulator package:

Top right: accumulator systems are kept charged by air and electric pumps.Bottom right: an accumulator unit

10-19SURFACE EQUIPMENT

Check and record precharge pressure every 30 days, or every well, whichever comes first.

1. Clean and wash the air strainer.

2. Fill air lubricator with 10 weight oil (or specified weight).

3. Check air pump packing. Packing should be loose enough that the rod is lubricated, but not loose enough to drip.

4. Check the electric pump packing.

5. Remove and clean the suction strainers. They are located on the suctions of both air and electric pumps.

6. Check oil bath for the chain drive on electric pump (if it is chain driven). It should be kept full of chain oil. Check bottom of oil reservoir for water.

7. Fluid volume in hydraulic reservoir should be at operating level (generally two-thirds to three-quarters full).

8. Remove and clean the high-pressure hydraulic strainers.

9. Lubricate the four-way valves (the operating valves). There are grease fittings on the mounting bracket and generally a grease cup for the piston rod.

10. Clean the air filter on the regulator line.

11. Check precharge of individual accumulator bottles (should read 900 to 1,100 psi [62.05 to 75.84 bar]).

THE NITROGEN PRECHARGE

An important accumulator element is the 1,000 psi (68.95 bar) nitrogen precharge in the bottle. If bottles lose their charge completely, no additional fluid under pressure can be stored. Keep bottles near their 1,000 psi (68.95 bar) precharge operating pressure. Nitro-gen tends to leak away or be lost over time. Loss varies with each bottle, but each bottle in the bank should be checked and the precharge recorded every 30 days, or every well, whichever comes first, using the following procedure.1. Shut off air to the air pumps and power to

the electric pump.

2. Close the accumulator shut-off valve.

3. Open the bleeder valve and bleed the fluid back into the main reservoir.

4. The bleeder valve should remain open until the precharged is checked.

5. Remove guard from accumulator bottle precharge valve. Screw on gauge assembly. Open accumulator precharge valve by screwing down on the T handle. Check precharge pressure. Gauge should read 1,000 psi (68.95 bar) or in the range from 900 to 1,100 psi [62.05 to 75.84 bar].

Above: a typical accumulator unitRight: a cylindrical accumulator bottle

CHAPTER 1010-20

If high, bleed excess pressure off; if low, recharge to proper pressure with nitrogen. Close precharge valve by unscrewing T bar, remove gauge assembly. Reattach guard.

6. Open accumulator shut-off valve.

7. Turn on air and power. The unit should recharge automatically.

The procedure is for a typical closing unit. Variations occur with specialized equipment or operations. For example, subsea BOP stacks may have accumulator bottles on the stack. The precharge on these bottles in deep water is the calculated hydrostatic pressure of seawater plus 1000 psi (68.95 bar), plus a safety margin for seepage or temperature. High-pressure bottles prevent burst when precharging on the surface.

ACCUMULATOR CHARGING FLUIDS

Fluid used in the accumulator should be a non-corrosive, non-foaming lubricant which should neither soften nor make rubber sealing elements brittle. It should be fire and weather resistant. Hydraulic oil fits these requirements.

A mixture of fresh water and soluble oil (with ethylene glycol for cold weather and anti boil compounds for high temperatures) is also satisfactory. Soluble oil and water is cheaper and not considered a pollutant, so it is favored over hydraulic oil. In warm climates bacteria, algae and fungus may accumulate in the system. Additional chemicals should be added according to manufacturer’s recommendation to prevent this growth (bactericides, fungicides, etc.).

Improper oils/corrosive waters will harm accumulator and closing elements of BOP stack.

VOLUME REQUIREMENTS

The accumulator system should have enough capacity to supply the volume necessary to meet or exceed minimum requirements for closing systems. There are various standards for calculating required volume and safety factors. For instance, the API in RP 16E details

the mathematics involved to calculate the API minimum volume. MMS requires 1.5 times the volume (50% safety factor) necessary to close and hold closed all BOP units with minimum of 200 psi (13.79 bar) above precharge pressure. Other government agencies, organizations or company policies have different requirements. Since it is better to have more than a minimum volume, most operators and contractors prefer to use three times the volume required to close everything on the stack. The idea is to have reserve power for the accumulator system to operate the stack and still have more than the nitrogen precharge remaining.

A quick estimation on a typical 3,000 psi (206.84 bar) system with 1,000 psi (68.95 bar) precharge is to use half the volume of the accumulator bottle. Approximately one-half of the total bottle size may be used before pressure drops to 200 psi (13.79 bar) above precharge. (A 20-gallon [75.7 l] bottle has a usable volume of about 10 gallons [37.85 l]. Larger spheres normally have a volume of 80 gallons [302.83 l] and a usable volume of 40 gallons [151.42 l].)

EXAMPLE 1 – ESTIMATED ACCUMULATOR VOLUME REQUIRED, 1.5 CLOSING FACTOR

Hydril GK 13-5/8” (346.08 mm) Annular Preventer to Close = 17.98 gallons (68.06 l)

(3) Cameron Type U Rams 13-5/8” (346.08 mm) to Close 5.80 gallons (21.96 l) times 3 sets of rams = 17.40 gallons (65.86 l)

Total for 1 closure = 35.38 gallons (133.93 l)

Accumulator Safety Requirement (Closing factor of 1.5) = 35.38 gallons (133.93 l) times 1.5 = 53.07 useable gallons (200.89 l) needed

53.07 gallons is rounded up to the next increment of 10 for a total of 60 gallons (227.12 l) of useable fluid.

In this example, it would be necessary to have six 20-gallon (75.71 l) bottles or spheres or combination that would give a minimum total of 60 gallons (227.12 l) of usable fluid. If a system other than the 3,000 psi (206.84 bar) system – say 2,000 psi (137.89 bar) or 1,500 psi (103.42 bar) – is used, or exact requirements must be met, use the following calculation.

Subsea BOP stacks may have

accumulator bottles on the stack.

SURFACE EQUIPMENT10-21

V3 = VR ÷ ([P3 ÷ P2] – [P3 ÷ P1])

Where:P1 = Maximum pressure when fully chargedP2 = Minimum operating pressureP3 = Nitrogen precharge pressureV1 = Volume of nitrogen at maximum pressureV2 = Volume of nitrogen at minimum operating pressureV3 = Total accumulator volume

VR = Total useable fluid (including safety factor)

EXAMPLE 2Using required volume from Example 1 of 53.07 gallons (200.89 l) (includes 1.5 safety factor), what is the total accumulator volume required for a 2,000 psi (137.8 bar) system with a 1,000 psi (68.95 bar) precharge and 1,200 psi (82.7 bar) minimum operating pressure?

V3 = VR ÷ ([P3 ÷ P2] – [P3 ÷ P1]) = 53.07 ÷ ([1,000 ÷ 1,200] – [1,000 ÷ 2,000]) = 53.07 ÷ (0.8333 – 0.5) = 53.07 ÷ 0.3333 = 159.22 rounded to 160 gallons (605.6 l)

CHOKE MANIFOLD

The purpose of the manifold is to provide a method of circulating from the BOP stack under a controlled pressure. The manifold provides alternate routes so that chokes and valves can be changed out or repaired.

The API bulletin RP-53 3.A.3 provides a description of the choke manifold and recommended practices for planning and installation. The recommendations include:

w Manifold equipment subject to well and/or pump pressure (normally upstream of and including chokes) should have a working pressure at least equal to the rated working pressure of blowout preventers in use. This equipment should be tested when installed to pressures equal to the rated working pressure of the blowout preventer stack in use.

w Components should comply with applicable API specifications to accommodate anticipated pressure, temperature, abrasiveness and corrosivity of the formation fluids and drilling fluids.

Several examples of choke manifolds

When installed, test manifold equipment to pressures equal to the rated working pressure of the blowout preventer stack in use.

10-22CHAPTER 10

w For working pressures of 3M (206.84 bar) and above, only flanged, welded or clamped connections should be used with components subjected to well pressure.

w The choke manifold should be placed in an accessible location, preferably outside of the rig substructure.

w The choke line (which connects blowout preventer stack to the choke manifold) and lines downstream of the choke should:

A. Be as straight as practicable; turns, if required, should be targeted.

B. Be firmly anchored to prevent excessive whip or vibration.

C. Have a bore of sufficient size to prevent excessive erosion or fluid friction.

1. Minimum recommended size for choke lines are 3” (76.2 mm) nominal diameter (2” [50.8 mm] nominal diameters are acceptable for Class 2M [137.89 bar] installations.).

2. Minimum recommended size for vent lines downstream of the chokes are 2” (50.8 mm) nominal diameters.

3. For high volumes and air/gas drilling operations, 4” (101.6 mm) nominal diameter lines (or larger) recommended.

w Alternate flow and flare routes downstream of the choke line should be provided so that eroded, plugged or malfunctioning parts can be isolated for repair without interrupting flow control.

w Consideration should be given to the low temperature properties of the materials used in installations that will be exposed to unusually low temperatures.

w The bleed line (the vent line that bypasses the chokes) should be at least equal in diameter to the choke line. This line allows circulation of the well with preventers closed while maintaining a minimum of backpressure. It also permits high volume bleed off of well fluids to relieve casing pressure with the preventers closed.

w Although not shown in typical equipment illustrations, buffer tanks (watermelons) are sometimes installed downstream of the choke assemblies for manifolding the bleed lines together. When buffer tanks are employed, provision should be made to isolate a failure or malfunction without interrupting flow control.

Left: production chokeMiddle: manual adjustable choke

Right: rigging up the annular preventer

The choke line should be as

straight as practible.

10-23SURFACE EQUIPMENT

w Pressure gauges suitable for abrasive fluid service should be installed so that tubing or drillpipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted.

w All choke manifold valves subject to erosion from well control should be full-opening and designed to operate in high pressure gas and abrasive fluid service. Double, full-opening valves between the blowout preventer stack and the choke line are recommended for installations with rated working pressures of 3M (206.84 bar) and above.

w For installations with rated working pressures of 5M (344.74 bar) and above the following are recommended: A. One of the valves in the above paragraph

should be remotely actuated.

B. Double valves should be installed immediately upstream of each choke.

C. At least one remotely operated choke should be installed. If prolonged use of this choke is anticipated, a second remotely operated choke should be used.

w All chokes, valves and piping should be H2S service rated.

CHOKES

A choke controls the flow rate of fluids. By restricting flow through an orifice, friction or backpressure is placed on the system, allowing a control of flow rate and well bore pressure.

Well control chokes are of different design than gas and oil production chokes. In general, the production choke is not suitable for well control. Manual adjustable chokes are used for some well control applications but most pressure operations use remote adjustable chokes.

FIXED CHOKES

The fixed choke usually has a choke body in line to permit the installation or changing of a bean choke with a certain size orifice.

ADJUSTABLE CHOKES

Adjustable chokes may be manually or remotely operated to adjust the orifice size.

MANUAL ADJUSTABLE CHOKES

This is the basic type of choke. It has a tapered bar and seat. As the bar gets closer to the seating area, there is less clearance and more restriction for fluid going through it, producing more backpressure on the well.

Top left: remote hydraulic chokeBottom left, middle and right: several types of remote choke panels

Adjustable chokes may be manually or remotely operated to adjust the orifice size.

CHAPTER 1010-24

This type of choke is often the most neglected piece of well control equipment. It serves as a backup choke, and often as a primary choke in operations. Care should be used to properly lubricate, function and test this vital piece of equipment on a regular basis, according to state or federal or governing body guidelines.

REMOTE ADJUSTABLE CHOKES

Remote adjustable chokes are the choke of preference in drilling operations and for pressure related work. They provide the ability to monitor pressures, strokes and control the position of the choke all from one console. The two most common manufacturers are Cameron and Swaco.

The Cameron choke is generally available in 5,000 to 15,000 psi (344.74 to 1034.21 bar) operating ranges. All chokes are trimmed for H2S service. The choke uses a bar that moves in and out of a tapered choke gate. Full opening when the bar is all the way out of the gate provides a 2” (50.8 mm) opening in common usage. The operating mechanism is a double-acting cylinder operated by hydraulic pressure from the choke console. Several manufacturers provide chokes of essentially the same design as the Cameron choke.

The SWACO Super Choke is normally available in 10,000 psi (689.47 bar) and 15,000 psi (1034.21 bar) operating ranges. The 10,000 psi (689.47 bar) choke is available in normal and H2S trim. The choke uses two lapped tungsten carbide plates, each with a half-moon opening, that rotate in and out of line. Full opening when the two half-moons are in line produces an opening of slightly less than the area of a full 2” (50.8 mm) choke bean. The choke will close and seal tight to act as a valve. The operating mechanism is a set of double-acting cylinders operating a rack and pinion that turns the upper choke plate. Rig air powering the choke panel supplies hydraulic pressure.

Both chokes have operating panels that include choke position, stroke and/or volume counters, stand pipe and casing pressure gauges, a positioning valve, a pump for hydraulic operation and an on-off switch.

Both types of chokes are good in well-killing operations. The basic limitations common to both types are that they are seldom used and tend to freeze up, lose gauge pressure and have the pump counters disconnected. All these problems can be resolved by operating the choke tourly and running a weekly function and operation check of the choke panel.

Mud/gas separator

M u d Ta n k

De g a s s e d Mu d

Ga s Ve n t Lin eGa s Ve n t Lin e

Va c u u m D-Ga s s e r

Ba c k Flo w

Ga s Ve n t Lin e

Ga s Cu tM u d Fr o mFlo w lin eO r Sh a leSh a k e r

Swaco Tota l Gas Con ta in m en t System Safe ly Ven ts All Gases

Mud/gas separatorRemote adjustable

choke

Remote adjustable

chokes are the choke of

preference in drilling

operations.

SURFACE EQUIPMENT10-25

GAS HANDLING EQUIPMENT

Gas handling equipment is a vital part of blowout control equipment. Without it, well control operations are difficult and can be hazardous, due to gas around the location. Gas handling equipment removes the large volumes of gas that could cause an explosive mixture if allowed to mix with the air around the rig.

MUD GAS SEPARATORS(GAS BUSTERS)

Mud gas separators (gas busters, poor boy degassers), generally are the first line of defense from gas around the location. A gas separator is a simple, open vessel connected to the end of the manifold or choke line, just before fluid enters the possum belly or return line.

The greatest amount of gas coming up with a kick will separate from the fluid below the choke. The separator handles this gas. The gas separator allows the free gas that breaks out of the fluid to leave the system and gravitate or be pushed to the flare line or water table. Design varies from a simple open cylinder used with some manifolds to the more complex float-operated gas separator.

With clear fluids, the gas separator may be sufficient. The low viscosity of clear fluids allows gas to break out of the fluid under atmospheric pressure. With viscous (thicker) fluids, the gas separator alone may not be sufficient.

Gas blow-by is a term used to describe overloading this piece of equipment as pressure builds inside the gas separator, displacing fluid in the liquid leg and allowing gas to enter the pit area. Pressure within the gas separator should be monitored when gas is at surface and maintained at values that prevent this overload and reduce the chance for vessel rupture.

DEGASSERS

The degasser has a limited capacity to handle gas volume, but since gas volume entrained (trapped) in the fluid is low, the degasser is usually adequate. If the fluid’s viscosity is high or fluid is contaminated, gas may not freely break out. Degassers may separate entrained gas from fluid using a vacuum chamber, a pressurized chamber, a centrifugal spray or a combination of these designs. The most common degasser is a vacuum tank or a pump sprayer, but there are many degassers and some combine functions. The three most common degassers are the SWACO vacuum degasser, the Welco Vacuum Degasser and the Drilco Seeflo Pump Degasser.

Two common degassers

Mud gas separators are the first line of defense from gas around the location.

10-26CHAPTER 10

The maintenance on degassers is slight. The pumps must be lubricated and sized properly. Where a float arm is used, the joints must be kept lubricated. When a vacuum pump is used, the water knockout ahead of the compressor must be emptied daily.

In general, the vacuum degassers are more effective for working with heavy viscous muds where it is difficult to extract the gas. In any degassing operation, residence time and extraction energy requirements are increased as mud viscosity and gel strengths increase.

The degasser typically intakes fluid from a pit close to the shakers and discharges degassed fluid to a pit downstream and towards the suction pit. Flowline degassers are also utilized that minimizes the amount of gas to the shakers.

SAFETY VALVES AND FLOATS

A method of closing off the string is a basic part of well control equipment. Equipment for closing off tubing or drillpipe includes safety valves, floats and inside blowout preventers. This equipment is handled by the floor crew. It is essential that the driller and toolpusher make sure the crew understands the rules for operating and maintaining this essential equipment.

UPPER KELLY COCK

The upper kelly cock is a standard part of the upper kelly assembly. The figure below shows an OMSCO upper kelly cock that has an integral one-way valve. Other upper kelly cocks are simple ball, flapper or plug type valves. The basic purpose of the upper kelly cock is to protect the kelly hose, swivel and surface equipment from high well pressure. It is normally pressure tested when the stack is tested. There is limited maintenance for the upper kelly cock.

LOWER KELLY COCK

The lower kelly cock is a full-opening valve which backs up the upper kelly cock. It allows removal of kelly when pressure on the string is greater than surface equipment rating. It is common practice to use the lower kelly cock as a fluid or mud saver valve. Continual use of the lower kelly cock has mixed advantages. The valve is operated at every connection so it is kept free and in operating condition. The crew learns how to operate the valve and the wrench

Left: an upper kelly cockRight: a full opening safety valve

The upper kelly cock protects the kelly hose,

swivel and surface

equipment from high well

pressure.

SURFACE EQUIPMENT10-27

is kept available. On the other hand, repeatedly using this ball valve for this purpose can reduce operation life. Some rigs have reported galling of valve threads from continual makeup and breakout. Galling can be eliminated through use of a saver sub. Threads should be checked weekly with a thread gauge for signs of stretching. In addition, a visual inspection should be made to check for galling.

FULL OPENING SAFETY VALVES

In addition to valves on the kelly, another full-opening safety valve is required to be kept on the rig floor. If a kick occurs during a trip, this valve needs to be installed immediately. Keep it in in a handy place. It must be in the open position, and the wrench to close it placed in a conspicuous location readily accessible to the crew. If a tapered string is used, or a casing string being run, then a crossover on the existing stabbing valve or another stabbing valve with proper threads must be available.

The safety or stabbing valve, commonly called a floor, hero or TIW valve, is a full-opening ball valve. The stabbing valve should be light enough so it can be lifted by the crew, or provisions should be made to lift it with an air hoist or counter balance system. A removable handle at a good balance point should also be rigged on the valve so it can be easily handled.

Stabbing valves need very little maintenance, but like the chokes that are seldom used, they need to be operated at least weekly to keep them from freezing up. Using crossover subs (so that the basic stabbing valve can be used with different sizes of pipe) can make the stabbing valve heavy, clumsy and difficult to stab.

INSIDE BLOWOUT PREVENTER

The inside BOP (sometimes called Grey valve) is a backpressure or check valve. It is a spring-operated, one-way valve that can be locked in the open position with a removable rod lock screw. Its primary use is for going in the hole under pressure. The inside BOP allows the hole to be circulated, but prevents pressure or flow reversing back into the string. It is a simple and reliable tool, but since it is not full-opening, the inner diameter of the string is restricted. Due to its design, wireline tools cannot be run through it, so there is some reluctance to use the inside BOP unless necessary.

The inside BOP should not be used to stab flowing tubing or drill pipe despite the common term inside BOP. If needed, it can be attached after the flow is stopped with a safety valve. One should be maintained on the rig floor in the open position at all times.

Left: an inside BOPAbove: a Kelly FOSV

Above: two examples of backpressure valvesRight: a dart type valve

The inside BOP allows the hole to be circulated, but prevents pressure or flow reversing back into the string.

CHAPTER 1010-28

BACKPRESSURE VALVES (BVP)

Many devices may be classified as back-pressure valves. Floats, inside BOPs, backpressure and check valves all act similarly to prevent flow and pressure from coming up the string. These devices are used in activities such as stripping, snubbing and pressure work. In some cases they may be required for the entire drilling operation according to company or operator policy.

The standard float valve, carried just above the bit, protects the string from back flow or inside blowouts. The two most common types of floats are spring operated piston (plunger) and flapper types. Plunger types are reliable, but not full-opening. Both floats are available in latch-open models for running in the hole with the valve in the open position. Flow down the string will release the latch and return the valve to its one-way mode. If surveys are to be made during drilling operations, a tool to receive the survey instrument must be installed above the float to prevent the survey instrument from being jammed or stuck in the float.

Some floats are ported. This refers to one or more small holes drilled through the float so pressure below it may be determined. It should be noted that these ports can easily plug and sometimes wash out.

CIRCULATING SYSTEM

The circulating system is composed of many individual components. These include pumps, surface lines, standpipe, kelly hose, swivel, kelly top drive, work string, well annulus (usually casing), shale shaker, fluid tanks and associated circulating (e.g., pump, standpipe, choke and kill) manifolds.

Positive displacement pumps are used to move fluid through the circulating system. Duplex pumps have two cylinders and triplex pumps have three. Due to the smooth displacement of high volumes, triplex pumps are more commonly used. All pumps have liners that can be changed due to wear or cavitation to prevent damage to the pump body itself. The liners can be changed to different sizes to increase or decrease pump volume and pressure output.

Rig pumps are typically outfitted with one or more stroke counters that are essential for accurate volume displacement. If these are not available, constant pump rates and times are used to track volume pumped, although to a less accurate degree. There are several types of stroke counters available ranging from a simple mechanical whisker type to more complex electronic devices. If work is performed on the pump, these counters are often damaged,

Left a flapper type BPV

Right: a pop-off valve

The standard float valve, carried just

above the bit, protects the

string from back flow or inside

blowouts.

SURFACE EQUIPMENT10-29

removed or misaligned upon reinstallation. Care should be taken to correctly set the counters, which should be checked against the readout to ensure proper functioning.

Higher pressure/low volume service company pumps are available and necessary in some operations. Most pumps may have resettable pressure relief (pop off) valves. If pump operation exceeds the pressure limitation, the pressure relief valve on the pump will blow and allow the well to unload into the pits.

Pumps should be kept in good condition. In most circulating well control activities, a constant output and discharge pressure is required.

CIRCULATING MANIFOLD SYSTEM

Circulating manifolds provide the ability to select different flow paths. Pump selection and fluid routing, along with isolation of pumps not in use are all accomplished by the pump manifold system. The standpipe manifold conveys fluid from the pumps to the upper area of the derrick to connect with the rotary, or kelly, hose. This hose makes a flexible connection between the standpipe and swivel and allows for pipe travel while pumping. The swivel is a device that allows the kelly to turn while pumping. Returns from the well may be routed to the tanks from the bell nipple on

surface BOP stacks or through a kill manifold connected to the BOPs.

The entire manifold system may be complex. It should be checked tourly for correct lineup. It should not be altered while pumping unless another fluid flow path has been opened. Cementing pumps or chicksan lines may have specific lineups different from standard pump and return paths.

MUD RETURN INDICATOR(FLOW LINE SENSOR)

In terms of kick detection equipment, the return indicator is probably the most important piece of equipment used. The mud return indicator is usually a paddle in the flow line. The paddle in the flow line reports flow of fluid in the line. This signal is sent to the driller’s console where it is reported as percent of flow (% flow) or gallons per minute (liters per minute in the metric system).

In most operations, a relative change from an established trend is an indicator of potential hazard. So it is crucial to detect any change in flow. If a well kick occurs, something has entered the wellbore. This will push fluid out of the flowline, showing as an increase in flow.

Left: pump stroke counterRight: flow line sensor

The swivel is a device that allows the kelly to turn while pumping.

10-30CHAPTER 10

The basic operation and maintenance of a flow sensor is to observe if it operates when the pump is turned on and off. Pump rate should be changed to see if the flow sensor reports change. Flow sensors are easily jammed, therefore they should be checked often for their full range of motion. They do not work well in flat or flooded flow lines.

PITS OR TANKS

The function of a system of interconnected pits or tanks is to hold, treat or mix fluid for circulating or storage. The pit volume should be determined for the particular job and sufficient tanks should be on hand. Typically, several pits or tanks are used and fluid may be routed by ditches interconnecting the pit system, by equalizing lines from tank to tank, or using circulating/mixing manifolds. The first tank from the flow line is usually a sand trap or settlement tank to prevent sand or undesirable solid particles from entering the main mixing, circulating and suction tanks.

Pits should be arranged to maximize the degassing effect of this equipment.

The pits with the suction and discharge from the degasser should not allow fluid to flow across the ditch to the next tank. These ditches should be closed off and the equalizer on bottom opened. In this way lighter gas-cut mud floating on top will not flow to the circulating and mixing tanks. The same principle also holds for the mixing and suction tanks.

MIXING FACILITIES

Good mixing facilities are necessary for most operations. If chemicals are to be mixed on site, fluids are to be weighted or conditioned or if the fluid must be kept moving, a circulating pump and lines are used. Centrifugal or impeller pumps are usually used to mix the fluid and chemicals. These mud mixing pumps usually are lined up through a jet and hopper system to mix fluid. The pump will then discharge fluid at the top of the tank or through jet guns. Discharge lines and jet guns will aerate the fluid in the tank to some degree. Oxygen scavengers may be used to eliminate this problem.

Left and middle: flowline sensors

Right: a pit volume totalizer system

The first tank from the flow

line is usually a sand trap or

settlement tank.

10-31SURFACE EQUIPMENT

FLUID VOLUME MEASURING DEVICE

The hole fill device is called by various names. This combination flowline sensor/ pump stroke counter measures mud required to fill the hole on a trip. To operate fill-up system, the switch on the driller’s console on the flow sensor is turned to trip and one pump is lined up to the fill-up line. When the driller wants to fill the hole after pulling one or more stands, he turns on the pump. The counter counts pump strokes, then automatically turns off when the flow-line sensor shows flow at the flow line. The calculated pump strokes required to fill the hole per stand of pipe are compared to the pump strokes actually required to fill the hole. Pump strokes are usually kept on both total strokes to fill the hole, and strokes to fill the last fill-up.

Maintenance of fill-up system requires that a floorhand check the hole during first fill-up to be sure pump stroke counter shuts off when flow starts. A common problem is that the pump stroke counter doesn’t work because the switch mounted on the pump was removed during pump repairs and was not replaced.

TRIP TANK

The trip tank is small, allowing accurate measurement of fluid pumped into well. It is the best way to measure the amount of fluid it takes to fill the hole on a trip out or the amount of fluid displaced on the trip back in. As each stand of pipe is pulled from the hole, the wellbore fluid level lowers by displacement of the steel, or if wet, displacement and capacity. It is necessary to measure the amount of fluid for fill-up to be sure a kick has not entered the well.

There are several types of trip tanks. A simple gravity-fed trip tank includes a small tank on the rig floor or elsewhere at a point above the flow line, marked in portions of a barrel (m³). A valve is required to release fluid from the tank into piping directing fluid into the bell nipple above flow line. The valve is manually opened, then closed when the hole is full, and the amount of fluid used is reported, recorded and compared to theoretical fill calculations.

More automated versions of gravity-fed trip tanks have a pump, actuated by the driller,

A trip tank arrangement

Automated trip tanks have a pump, actuated by the driller, which uses the flow line sensor to indicate when the hole is full.

CHAPTER 1010-32

which uses the flow line sensor to indicate when the hole is full and shut off the pump. The strokes or volume to fill should be reported, recorded and compared to theoretical fill calculations. This type of setup will not allow volume to be measured while tripping in.

Continuous fill trip tanks automatically fill the hole as pipe is pulled by circulating from the tank across the hole. Fluid volume used is measured and sent to a floor recorder for comparison against stands of pipe pulled. If this tank is used to measure gain in fluid on trip in, it is usually positioned below flow line level. Fluid displaced is routed from the flow line to the trip tank, measured and compared to theoretical pipe displacement. If properly placed, it can be used while tripping into the well.

Trip tanks require careful maintenance. Valves should be checked for easy operation, trip tank markers and pit level floats kept clean and clear of fluid buildup or solids, correct volume displacements calculated and posted, and the driller’s recorder checked for accuracy.

PIT VOLUME TOTALIZERS

Pit volume totalizers (PVTs) monitor, record and total the volume in each pit as well as the working surface fluid volume. The pit volume indicator is a basic well control warning

instrument. A well kick pushes fluid out of the hole. The increase in pit level (or pit volume) is recorded by the PVT. So one of the warning signs of a well kick is an increase in pit volume. Most pit volume systems are simple in operation. Today’s systems use mechanical floats or electrical (sonic) sensors to measure the height of the fluid in each pit. This height is multiplied by the pit volume in barrels per inch or some like term. The volume of the individual pits is totaled and reported on the chart and indicator. These measurements and calculations may be done either electrically or by air (pneumatically). The driller’s indicator has an alarm system that calls attention to pit changes.

To operate and maintain these systems, the following should be checked every day:

w Check chart paper and ink.

w If there are floats, clean off mud accumu-lations and make sure they move easily.

w Raise and lower each float to see that it reports a change to the driller.

w If the system is pneumatic, bleed off water from the air dryer.

w Check the air lubricator bottle for oil.

For sonic sensors, check that the sensor is free of mud accumulations and that the fluid does not have foam floating on top. Clean the sensor according to the manufacturer’s recommendation.

Pit volume totalizer systemRemote pit volume totalizer indicator

Continuous fill trip tanks

automatically fill the hole as pipe is pulled by circulating from the tank

across the hole.

SURFACE EQUIPMENT10-33

GAS DETECTORS

The gas detectors on rigs are used to warn personnel of increasing gas flow out of the well and areas of gas concentration in places where an explosion or fire could occur. Other types of gas detectors are placed in areas where toxic gases, such as H2S, can accumulate and harm personnel. Gas detectors should be tested on a regular basis with an approved gas source. Sniffing lines should be blown out periodically to remove stale or trapped gases. Maintenance should be performed according to manu-facturer’s specifications. Obvious problems with gas detectors are broken and plugged lines or dirty detector heads. If the alarms are placed in the mud logging unit only, then this unit must be manned 24 hours a day.

PRESSURE GAUGES

Pressure measurement is crucial in most oil industry operations. Pump, choke and shut-in pressures may be measured at several locations.

Gauges used to measure pump or circulating pressure include the standpipe pressure gauge, normally mounted at the standpipe on the rig floor. It may be mounted in another position if it can easily be read by driller. Drillpipe or tubing gauges are typically mounted on the driller’s console and the remote choke panel. The driller uses the pressure gauge located on his panel under normal drilling or circulating

conditions. But when recording slow pump rates, during well control activities and pressure sensitive tests, the gauge at the remote choke panel is generally used because of its accuracy.

Values on gauges measuring the standpipe pressure should be close. If there are large discrepancies between the readings, the incorrect gauge should be recalibrated or repaired. Pump pressure is also measured with a gauge mounted on the pump. This gauge shows absolute pressure to circulate at a given speed and includes all friction pressure losses. Gauges on the rig floor and remote choke console should read slightly less than the one on the pump due to friction between the pump and standpipe.

Gauges measuring casing or annulus pressure are typically found on the choke manifold and remote choke panel. This gauge may be called the wellhead or casing pressure gauge. Most regulatory bodies require a pressure gauge to monitor pressure between strings of casing.

Gauge range is the subject of much discussion. Ideally, the range should be to the highest expected pressure or rated working pressure of equipment being used, with a high degree of accuracy over the entire range. The scale of the gauge should be small enough to register small changes of pressure. In most operations, however, a 5,000 or 10,000 psi (344.74 or 689.47 bar) gauge is used. There are debates over the low pressure accuracy of large range gauges. It is not uncommon to have inaccuracy of 0.5 to 1.5 percent or greater. On a 10,000 psi (689.47 bar) gauge, for example, the uncertainty of pressure accuracy would therefore be +/– 50 to 150 psi (3.45 to 10.34 bar). Multiple gauges are often manifolded or kept on location to compensate for these inaccuracies.

Vibrations, pulsation and shock absorption if objects hit the gauge may also cause inaccuracies and damage. Fluid-filled gauges help dampen vibrations and shocks and also lubricate and protect internal components. Another source of inaccuracy is from air in the hydraulic line. For this reason, a hydraulic fluid hand pump should be used to purge the lines on a regular basis.

Pump pressure gauges

Gas detectors should be tested on a regular basis with an approved gas source.

10-34CHAPTER 10

w Turn on audio and visual alarms. Have the pit hand raise and lower the floats to insure that the alarms are functioning properly.

FLOW LINE SENSOR (SURFACE STACKS)w Set high/low sensor to the amount of flow

variance desired.

w Turn on the audio and visual alarms.

w Have the pit hand pull up and push down on the flow line sensor to insure that the equipment is operating properly.

FLOW LINE SENSOR (SUBSEA STACKS)w Set high/low sensor to the amount of flow

variance desired. The rig pitch, roll and heave should be taken into account when setting the variance.

w After the alarms have been turned on, the pit hand should raise and lower the sensor to insure proper operation.

Modern rigs provide the driller with a wealth of information.

ALARM SETTINGS

Equipment on rigs varies, so specific recommendations cannot be made. However, common sense and good practice dictate that all alarms should be set to the lowest alarm limit with regard to the operation at hand and that both the audible and visual indicators should be switched on.

GAIN/LOSS GAUGE (RANGE -50 TO +50 BBLS OR -7.95 TO +7.95 M³)w Set high/low sensor to desired values

(usually -5 to +5 bbls [+/-0.8 m³])

w Turn on the audio and visual alarms.

PIT VOLUME TOTALIZER (SURFACE STACKS)w Set high/low sensor to the desired values

(usually 5 to 10 barrels [0.8 to 1.6 m³]) and turn on audio and visual alarms.

w Once the alarms have been set, have the pit hand push down and pull up the float sensor so that the driller can verify that the alarms are working.

PIT VOLUME TOTALIZER (SUBSEA STACKS)w Set high/low sensor to the desired value.

This depends on the amount of rig motion. The high and low settings can be as much as 30 barrels (4.8 m³).

Good practice dictates that

alarms be set to the lowest limit with regard to the operation

at hand.

10-35SURFACE EQUIPMENT

INFORMATION SYSTEMS

As technological advances are made, sophisticated information gathering and display systems – keying from a logging unit, on a stand-alone basis, or a combination – are becoming available. Whereas standard geolographs are still used to record depth, weight, torque, pressure and penetration at one foot (0.3 m) intervals, many rigs are also equipped with information monitors to accurately display the rate of penetration in feet-per-hour. Many important well control parameters, such as depth, pump pressure, flow rate, pit levels and torque are displayed and the more sophisticated systems include trends, settings and alarms.

Maintenance of many of the sensor systems is the rig crew’s responsibility. It should be performed as recommended by the manufacturer. Calibration or repair should be performed as directed or by an authorized technician.

ROTATING SYSTEM String rotation is required at one time

or another during most activities. It is often necessary to drill formation cement, packers or plugs and when milling, fishing or setting downhole tools. Pipe rotation can be transmitted by a rotary table. The rotary table must also

support the work string at those times when the load is not supported by the derrick. Rotating can also be achieved by a top drive, power swivel or power tongs. Downhole well control problems may be noticed by changes in the rotational torque and should be constantly monitored.

TOP DRIVE The top drive unit has been used primarily

for drilling rigs, but has also been designed for smaller workover operations. The traditional kelly and kelly drive bushing are not required, as the work string is rotated directly by electric or hydraulic power. The system is an improvement in rotating technology, as multiple joints of pipe may be used at one time. A conventional elevator hoists and lowers the string when tripping. With the top drive, rapid response to well kicks is always available while tripping or drilling. The drilling shaft is never more than a few seconds away so the driller can set the slips, stab into the string, rotate and torque the connection, so shut in of the well does not depend upon floor crew. With a top drive, circulation can be maintained (pump out of hole), as can the ability to back-ream during trips out of the hole. Hazards are reduced by eliminating two-thirds of the connections, and no bushings rotate at the floor.

Left: a Kelly saver subAbove: a power swivel

With a top drive, hazards are reduced by eliminating two-thirds of the connections, and no bushings rotate at the floor.

Above: a top drive systemRight: a diagram of a top

drive system

CHAPTER 1010-36

1. Customer air supply: normal supply is 125 psi. (Higher may require air regulator.) 2. Air lubricator: on air inlet line to air pumps. Use SAE 10 lubricating oil. 3. Bypass valve: to automatic hydro-pneumatic pressure switch. If pressures higher than

normal 3,000 psi are required, open. Close at all other times. 4. Automatic hydro-pneumatic pressure switch: 2,900 psi cut-out with air and electric pumps.

3,000 psi for air pumps alone. Adjustable spring tension control. 5. Air shut-off valves: manual – open/close supply to air hydraulic pumps. 6. Air operated hydraulic pumps: normal operating air pressure is 125 psi. 7. Suction shut-off valve: manual. Normally open. One for each suction line. 8. Suction strainer: one for each suction line. Removable screens. 9. Check valve: one for each air operated hydraulic pump delivery line.10. Electric motor driven triplex or duplex pump assembly.11. Automatic hydroelectric pressure switch: pressure switch is set at 3,000 psi cut-out and 250

psi cut-in differential. Adjustable.12. Electric motor starter (automatic): for motor driving triplex/duplex pump. Works with auto.

hydroelectric pressure switch. Manual override on-off switch.13. Suction shut-off valve: manual, normal open. In suction line of pump.14. Suction strainer: located in the suction line of the triplex or duplex pump.15. Check valve: located in the delivery line of the triplex or duplex pump.16. Accumulator shut-off valve: manual. Normally open when the unit is in operation. Close

when testing or skidding rig or applying pressure over 3,000 psi to open side of ram preventers. Open when test is completed.

17. Accumulators: check nitrogen precharge in accumulator system every 30 days. Precharge should be 1,000 psi +/–10%. Caution: use nitrogen when adding to precharge. Other gases and air may cause fire and/or explosion.

18. Accumulator relief valve: valve set to relieve at 3,500 psi.19. Fluid strainer: located on the inlet side of the pressure reducing and regulating valves. Clean

strainer every 30 days.20. Koomey pressure reducing ad regulating valve: manually operated. Adjust to the required

continuous operating pressure of ram type BOPs.21. Main valve header: 5,000 psi W.P., 2” all welded.22. 4-way valves: with air cylinder operators for remote operation from control panel. Keep in

standard operating mode (open/close), never in center position.23. Bypass valve: with air cylinder operator for remote operation from control panels. Close

position puts pressure on main valve header (21). Open position puts full pressure on header. Keep closed unless 3,000 psi+ required on ram type BOPs.

24. Manifold relief valve: valve set to relieve at 3,500 psi.25. Hydraulic bleeder valve: manually operated – normally closed. Note: this valve should be

kept open when precharging the accumulator bottles.

26. Panel-unit selector: manual 3-way valve. To apply pilot air pressure to air operated Koomey pressure reducing/regulating valve, either from air regulator on unit or from air regulator on remote control panel.

27. Koomey pressure reducing and regulating valve – air operated: reduces accumulator pressure to required annular BOP operating pressure. Pressure can be varied for stripping operations. Maximum recommended operating pressure of annular preventer should not be exceeded.

28. Accumulator pressure gauge.29. Manifold pressure gauge.30. Annular preventer pressure gauge.31. Pneumatic pressure transmitter for accumulator pressure.32. Pneumatic pressure transmitter for manifold pressure.33. Pneumatic pressure transmitter for annular preventer pressure.34. Air filter: located on the supply line to the air regulators.35. Air regulator, Koomey pressure reducing/regulating valve – air operated.36. Air regulator for pneumatic transmitter (33) for annular pressure.37. Air regulator for pneumatic pressure transmitter (31), accumulator pressure.38. Air regulator for pneumatic pressure transmitter (32), manifold pressure. Controls for

transmitters normally set at 15 psi. Increase or decrease air pressure to calibrate panel gauge to hydraulic pressure gauge on unit.

39. Air junction box: connect unit lines to panel lines through air cable.40. Rig test check valve.41. Hydraulic fluid fill port.42. Inspection plug port.43. Rig test outlet isolator valve: high pressure, manually operated. Close when rig testing

– open when test is complete.44. Rig test relief valve: valve set to relieve at 6,500 psi.45. Rig test pressure gauge.46. A. Rig skid outlet and 46.B. Valve header isolator valves: manually operated. Close

valve header isolator and open rig skid isolator when rig skidding. Open valve header isolator and close rig skid isolator during normal drilling.

47. Rig skid relief valve; valve set to relieve at 2,500 psi.48. Rig skid pressure gauge.49. Accumulator bank isolator valves: manually operated, normally open.50. Rig skid return: customer’s connection.51. Rig skid outlet: customer’s connection.52. Electric power: customer’s connection.53. Rig test outlet: customer’s connection.

TYPICAL KOOMEY BOP CONTROL SCHEMATIC

17

49

47

51

4846b

46a

18

16

12

15

5213

14

20

23

19

5042

11

2122

24

28 29

26

35

25

27 30

32

38

34

41

10

7

43

9

8

40

53

4544

6

5

3 2

4 1

31

3736

33

39

SURFACE EQUIPMENT10-37

POWER SWIVEL

Power swivels are rotating and pumping units designed for light drilling, workover and remedial operations. The power source to provide rotation is hydraulic fluid from hydraulic pumps. The workover rig hydraulic system pumps are typically used for this. Skid/trailer-mounted portable hydraulic power units are also available. A telescoping torque rein, or arm, must extend to a guide, or rigid part of the rig, due to the torque effect of rotation.

SUMMARY

The BOP stack and related equipment are simple in concept, but complicated in use and operation. Take time to investigate the equipment on the rig and to check the manufacturer’s operating limits and instructions.

When moving pipe through blowout preventers, testing, or in any other way operating blowout preventers, check the operating pressures against recommended values for the particular preventer. Too much operating pressure will tear the packer elements. Hoses, hydraulic valves, lines, fittings and connections on the BOPs and accumulator unit should be visually inspected daily for signs of wear or failure.

Pressure or function testing of the system causes wear, but not operating the equipment allows it to freeze up. Test intelligently within the limits of the equipment to be tested. Take a little extra time when function testing the stack to check accumulator operation.

Supervisors should make sure that the crews understand the purpose, location and operation of this vital and expensive equipment. This should all be covered when the driller, floormen, and derrickman go through their rig orientation training.

Proper maintenance of equipment by rig personnel is essential in kick detection. Fluid sensing and handling equipment must be in

good working order at all times. The gas detector must not be plugged. The mud return indicator unit in the flow line must have its full range of motion. Fluid tanks should be kept as free of settlement as possible. Pit volume totalizer floats must move freely, diverter valves must not have barite settling in the valve body or have lines plugged, gas handling equipment and chokes must be in good working condition at all times. Simple maintenance and cleaning of equipment should be performed as often as called for and warranted. This may be weekly, daily, tourly or even hourly depending on the equipment and mud conditions. Company representatives, toolpushers, drillers and mud engineers should all check these items and ensure that rig personnel are keeping them in good working order. Preventive maintenance, inspecting and testing equipment on a regular basis will ensure that the equipment will work when it is needed. This is vital, lifesaving equipment. It must work when needed.

Proper procedures go hand-in-hand with equipment maintenance. Circulating a kick from the well is hazardous and equipment must be properly aligned. Pressure is regulated and controlled from the BOP as fluids and gas enter the kill manifold system. Typically, as flow is directed from the choke to the gas buster, free gas breaks out and is separated to the flare or vent line. Fluids with entrained gas should enter the degasser pit and be degassed before returning to the circulating pit system. The vent/flare line for the degasser must be separate from the gas buster. Overloading the gas handling system is always a possibility and caution should be exercised. Always use downwind lines if more than one vent or flare line is available. If a derrick vent line is used, volatile fluids and heavy gases may pose a hazard to the rig floor area. It is necessary to monitor many aspects, such as the aforementioned. This important monitoring requires proper training, drills and teamwork. To put the importance of equipment into perspective, remember that procedures, well control techniques, drills and training are for naught if the equipment fails to operate correctly. t

Power swivels are rotating and pumping units designed for light drilling, workover and remedial operations.