MINISTRY OF HIGHER EDUCATION AND SCINTIFIC

RESEARCH

BRIGHT STAR UNIVERSITY, EL -BREGA

FACULTY OF TECHNICAL ENGINEERING.

DEPARTMENT OF PETROLEUM ENGINEERING.

(WELL CONTROL _BLOW OUT PREVENTERS)

Submitted in partial fulfillment of the requirement for (B.Sc.) degree

in Petroleum Engineering :

By:

1. Hussain Jaberl Mohamed ( 13131 )

2. Fares Ahmed Mohamed ( 13260 )

3. Hamed Agila Abdalkarim ( 13125 )

4. Mustafa Ali Almabrook ( 21161106 )

Supervised by: Dr / Fakeri Abu Zeid

Project NO: PE. 2016. 4. A

FALL - 2017

MINISTRY OF HIGHER EDUCATION AND SCINTIFIC

RESEARCH

BRIGHT STAR UNIVERSITY, EL –BREGA

FACULTY OF TECHNICAL ENGINEERING.

DEPARTMENT OF PETROLEUM ENGINEERING.

(WELL CONTROL _BLOW OUT PREVENTERS)

Submitted in partial fulfillment of the requirement for (B.Sc.) degree

in Petroleum Engineering :

By:

1. Hussain Jaberl Mohamed ( 13131 )

2. Fares Ahmed Mohamed ( 13260 )

3. Hamed Agila Abdalkarim ( 13125 )

4. Mustafa Ali Almabrook ( 21161106 )

Supervised by: Dr / Fakeri Abu Zeid

1…………………….. 3………………………….

2…………………….. 4…………………………..

FALL - 2017

حيم حمن الره الره بسم الله

قال تـعالي:

نذين ووونوا} " م واله ذين آمنوا منن اله بمن يرفع الله ن و والله ر العلنم

{وعملون خبير

من صنع إليم معروف ":(وقل رسول الله )صلي الله عليه وسلم

ففئوه, فإن لم ووا م وفئونه به فعوا له حوى وروا ونم

..... "فأوموه

وبو اوو رواه

إهداء

من وحمل اسمك بل فخر إلي

من افوقك منذ الصغر إلي

وبي .............من ووعوني لله وهيك هذا البحث إلي

الصعب لأصل إلي م ون فيهمن علموني وعن إلي

وعنم وسوني الهموم وسبح في بحر حننه ليخفف من آلامي.........ومي

من ن سني وقووي في الحيةإلي ..........إلي من علمني النح والصبر

إلي من افوقه في مواهة الصعب ........ولم ومهله الني ليشرني فرح نحي

اخي ....)المرحوم رابح بريل الزواوي(

إلي سني وقووي وملاذي بع الله

إلي من آثروني علي انفسهم ...... إخووي

إلي من وذوق معهم ومل اللحظ

سأفوقهم.................ووومني ون يفوقونيإلي من

إلي ن علهم الله وخووي بلله..........ومن وحببوهم في الله.....طلاب قسم

.........النفط

كلمة شكر

لاب لن ونحن نخطو خطواون الأخيرة في الحية المعية من وقفة

الفضنعو إلى وعوام قضينه في رحب المعة مع وسوذون

)فري بوزي(

وذلك نشر ل من سع على إومم هذا البحث وقم لن العون

هذا البحثوم لن ي المسعة وزون بلمعلوم اللازمة لإومم

الشر الذي من النوع الخص فنحن نووه بلشر ويض إلى ل

من لم يقف إلى نبن ، ومن وقف في طرقن وعرقل مسيرة بحثن،

وزرع الشوك في طريق بحثن فلولا ووهم لم وحسسن بموعة

البحث ، ولا حلاوة المنفسة

…………………ولولاهم لم وصلن إلى م وصلن إليه الان

I

(ABSTRACT)

This section of the project, following the Introduction, helps Engineers to

understand the key basics of well control. How events happen; why they

happen and what we can do when they do happen. We begin with basic

calculations and go on through to details relating to well control

downhole.

By the end of the course, delegates will understand well control at

introductory level which will enable them to know the causes of well

control events, what can be done to prevent them and what to do should

one occur. Well control equipment will also be reviewed.

Delegates will also benefit from reviewing previous well control events to

assist their learning.

The theoretical and practical nature of the course will assist delegates

with their job and with their advancement to the next level of well

control.

Who Should Attend:

Anew to the drilling industry, pump-men, derrick-men, young trainee

Drilling Engineers, Service Company.

II

TABLE OF CONTENT

CONTENTS PAGE

ABSTRACT……………………………………………………… I

CHAPTER 1

1.Introduction…………………………………………………. 1

1.2 Basic calculation and Terminology...................................... 3

1.2.1 UNDERSTANDING PRESSURES............................... 3

1.2.2 Hydrostatic Pressure..................................................... 3

1.2.3 Pressure Gradient............................................................ 5

1.2.4 Pressure Gradient............................................................ 6

1.2.5 Formation Pressure......................................................... 7

1.2.6 Surface Pressure.............................................................. 8

1.2.7 Bottom hole Pressure....................................................... 8

1.2.8 Choke Pressure................................................................ 9

1.2.9 Swab pressure.................................................................. 10

1.2.10 Fracture Pressure......................................................... 11

CHAPTER2

2.CAUSES AND DETECTION OF KICKS........................ 12

2.1. Causes of kick............................................................................ 12

2.2 Detection of kick........................................................................ 15

2.3 Indication of kick....................................................................... 15

CHAPTER3

3.1 SHUT-IN PROCEDURE WHILE DRILLING...................... 18

3.2 POST SHUT-IN PROCEDURES WHILE DRILLING......... 19

3.3 SHUT-IN PROCEDURE WHILE TRIPPING...................... 20

3.4 POST SHUT-IN PROCEDURES WHILE TRIPPING......... 21

III

TABLE OF CONTENT

CONTENTS PAGE

3.5 WHEN AND HOW TO CLOSE THE WELL……………… 23

3.6 KICK CONTROL PROCEDURES...................................... 25

3.6.1 Driller’s method................................................................ 25

3.6.2 Engineer’s method............................................................ 25

3.6.3 Volumetric method........................................................... 25

3.7 Kill sheet............................................................................... 27

3.8 Relief Well............................................................................ 30

CHAPTER4

4.1 Well control equipment......................................................... 31

4.1.1 Classification of BOPs........................................................ 31

4.1.2 Basic types of blowout preventers on drilling rig... 31

4.1.3 Inside preventers................................................................ 37

4.1.4 Pressure test........................................................................... 44

4.1.5 Drilling chock system............................................................ 47

4.1.6 Crew Positions During Well Kick Control Operations 50

CHAPTER5

Case Study about (Deep water horizon rig)……………… 52

5.1 Deep water horizon rig……………………………… 53

5.1.1 Overview……………………………………………… 54

5.1.2 Conclusion of this case study............................................. 59

5.1.3 Conclusion……………………………………………… 60

References…………………………………………………… 61

IV

LIST OF SYMBOLS:

Symbols: Full form:

HP Hydrostatic Pressure

MW Mud Weight

PG Pressure Gradient

TVD True vertical Deapth

ECD Equivalent Circulating Density

SICP shut-in casing pressure

SIDP shut-in drill pipe pressure

BOP Blowout preventer

V

LIST OF FIGURS:

FIG:NO PAGE

Fig .1 Installed blowout preventer

2

Fig .2 Hydrostatic Pressure

4

Fig.3 The relationship between Pressure

Gradient Density Conversion Factor

6

Fig .4 Formation pressure

8

Fig .5 Swab and Surge Pressures 10

Fig.6 Fracture Pressure 11

Fig.7 Kill sheet preparation

29

Fig. 8 show the Relief well 30

Fig 9 Annular Blowout Preventer 32

Fig 10 Cross section of Annular preventer 33

Fig .11 Rotational preventers and diverters 34

Fig .12 assembly of "Bop" Installed 35

Fig . 13 Ram-type preventer 36

Fig .14 Kelly valves (Kelly cocks) 38

Fig . 15 Drill string float valve

39

Fig .16 Flapper-type float valve 40

Fig .17 Well head

42

Fig. 18 Hydro-Nitrogen Accumulators 46

VI

Fig .19 Choke and kill manifold 47

Fig.20 Deep water horizon

53

Fig.21 Show the pressure records in kill line

and Drill pipe

Fig.22 Cement job

54

55

Fig.23 " BOP " Failed to shear the pipe

56

Fig .24 Explosion of Deep water horizon 57

Fig.25 Show oil spill

58

Fig.26 Show oil spill in the The Gulf Of

Mexico

58

1

1-Introduction:

Oil well control is the management of the dangerous effects caused by

the unexpected release of formation fluid, such as natural

gas and/or crude oil, upon surface equipment of oil or gas drilling

rigs and escaping into the atmosphere. Technically, oil well control

involves preventing the formation fluid, usually referred to as kick, from

entering into the wellbore during drilling.

Formation fluid can enter the wellbore if the pressure exerted by the

column of drilling fluid is not great enough to overcome the pressure

exerted by the fluids in the formationbeing drilled. Oil well control also

includes monitoring a well for signs of impending influx of formation

fluid into the wellbore during drilling and procedures, to stop the well

from flowing when it happens by taking proper remedial actions.

Failure to manage and control these pressure effects can cause serious

equipment damage and injury, or loss of life. Improperly managed well

control situations can causeblowouts, which are uncontrolled and

explosive expulsions of formation fluid from the well, potentially

resulting in a fire.

The single most important step in well control is closing the blowout

preventers when the well kicks. The decision to do so ranks as high as

keeping the hole full of fluid as a matter of extreme importance in drilling

operations.

The successful detection and handling of threatened blowouts (“kicks”) is

a matter of maximum importance . Considerable studies and previous

experience have enabled the industry to develop simple and easily

understood procedures for detecting and controlling kicks.

2

There are many reasons for promoting proper well control and blowout

prevention. An uncontrolled flowing well can cause any, or all, of the

following:

✓ personal injury.

✓ loss of life.

✓ damage and/ or loss of contractor equipment.

✓ loss of operator investment.

✓ loss of future production due to formation damage.

✓ loss of reservoir pressures.

✓ damage to the environment through pollution.

Fig .1 Installed blowout preventer

3

1.2 BASIC CALCULATIONS AND TERMINOLOGY

1.2.11 UNDERSTANDING PRESSURES:

1.2.2 Hydrostatic Pressure:

All vertical columns of fluid exert hydrostatic pressure. The

magnitude of the hydrostatic pressure is determined by the height

of the column of fluid and its density. It should be remembered

that both liquids and gases can exert hydrostatic pressure.

Hydrostatic pressure exerted by a column of fluid can be

calculated

• Hydrostatic Pressure

using Equation .1, below:

Eqn HP = MW x 0.052 x TVD

where: HP = Hydrostatic Pressure (psi)

MW = Mud Weight (ppg)

0.052=Conversion Factor (ppg)

TVD = True Vertical Depth (ft)

While drilling ahead, hydrostatic pressure exerted by the drilling mud is

the major deterrent against kicks.

4

Fig .2 Hydrostatic Pressure

5

1.2.3 Pressure Gradient:

When comparing fluid densities and hydrostatic pressures, it is often

useful to think in terms of a pressure gradient. The pressure gradient

associated with a given fluid is simply the hydrostatic pressure per

vertical foot of that fluid. Heavier (more dense) fluids have higher

pressure gradients than lighter fluids. The pressure gradient of a given

fluid can be calculated by using the formula in Equation .2.

• Pressure Gradient

Eqn .2 PG = MW x 0.052

where:

PG = Pressure Gradient (psi/ft)

MW = Mud Weight (ppg)

As you can see from the above equation, the pressure gradient can be

thought of as an alternate way of describing a fluid’s density.

6

1.2.4 Pressure Gradient:

Calculate the pressure gradient one of the most important calculation used

in well control:

Pressure Gradient = Fluid Density × Conversion Factor ( ppg) ( 0.052)

The conversion factor used to convert density to pressure gradient in the

English system is 0.052.

Why0.052??

Imagine a cube with 1ft sides its volume would be 1 cubic foot or 7.48

gallons, if we fill this cube with a fluid of density 1pound per gallon ,the

total weight of fluid would be 7.48 pounds

The area of the base is 12x12=144squar inches

7.48/144=0.0519psi=0.052

Fig.3 The relationship between Pressure Gradient Density

Conversion Factor

7

1.2.5 Formation Pressure:

Formation pressure is the pressure contained inside the rock pore spaces.

Knowledge of formation pressure is important because it will dictate the

mud hydrostatic pressure and also the mud weight required in the well. If

the formation pressure is greater than the hydrostatic pressure of the mud

column, fluids such as gas, oil, or saltwater can flow into the well from

permeable formations. Normal pressure gradients for formations will

depend on the environment in which they were laid down and will vary

from area to area..

Consider a formation located at a vertical depth of 5,000 ft and with a

reservoir pressure of 2,325 psi. The pressure gradient of this formation

can be easily figured with the following formula: Reservoir Pressure =

2,325 psi

PG = 0.465 psi/ft

Vertical Depth 5,000 ft

In order to keep this formation from flowing into the well, the mud in the

hole must also have a pressure gradient of at least 0.465 psi/ft. This

condition is achieved by filling the hole with 9.0 ppg saltwater.

8

Fig .4 Formation pressure

1.2.6 Surface Pressure:

We use the term surface pressure to describe any pressure that is exerted

at the top of a column of fluid. Most often we refer to surface pressure as

that which is observed at the top of a well. Surface pressure may be

generated from a variety of sources, including downhole formation

pressures, surface pumping equipment, or surface chokes.

1.2.7 Bottomhole Pressure:

Bottom hole pressure is equal to the sum of all pressures in a well.

Generally speaking, bottom hole pressure is the sum of the hydrostatic

pressure of the fluid column above the point of interest, plus any surface

pressure which may be exerted on top of the fluid column, and the effect

of friction pressure must be added or subtracted depending on the

direction of flow.

9

• Equivalent Circulating Density:

When circulating fluid in a wellbore, frictional pressures occur in the

surface system, drillpipe, bit, and annulus which in turn are reflected in

the standpipe pressure. As mentioned previously, these frictional

pressures always act opposite to the direction of the flow. When

circulating conventionally (the "long way"), all the frictional pressures,

including annular friction, act against the pump. The annular friction, or

annular pressure loss, acts against the bottom of the wellbore, resulting in

an increase in bottomhole pressure. This is known as Equivalent

Circulating Density, or ECD. ECD is normally expressed as a pound per

gallon equivalent mud weight, and is shown mathematically in Equation:

Equivalent Circulating Density

Annular Pressure Loss + Present Mud Weight

ECD = ---------------------------------------------------------

0.052 x TVD hole

ECD is the result of annular friction and is affected by such items as:

1.2.8 Choke Pressure:

Choke pressure is the pressure loss created by directing the return flow

from a closed-in well through a small opening or orifice for the purpose

of creating a back pressure on the well while circulating out a kick. The

choke, or back pressure, can be thought of as a frictional pressure loss

that will be imposed on all points in the circulating system, including the

bottom of the hole.

10

Fig .5 Swab and Surge Pressures:

1.2.9 Swab pressure:

is the temporary reduction in the bottomhole pressure that results from

the upward movement of pipe in the hole. Surge pressure has the opposite

effect, whereby wellbore pressure is temporarily increased as pipe is run

into the well. The movement of the drill string or casing through the

wellbore is similar to the movement of a loosely fit piston through a

vertical cylinder. A pressure reduction or suction pressure occurs below

11

as the piston or the pipe is moved upward in the cylinder or wellbore and

a pressure increase occurs below as they move downward.

Swab and surge pressures are mostly affected by the velocity of upward

or downward movement in the hole. Other factors affecting these

pressures include:

1.2.10 Fracture Pressure:

The formations penetrated by the bit are under considerable stress due to

the weight of the overlying sediments. If additional stress is applied while

drilling, the combined stresses may be enough to cause the rock to fail or

split, allowing the loss of whole mud to the formation. Fracture pressure

is the amount of borehole pressure a formation can withstand before it

fails or splits

Fig.6 Fracture Pressure:

12

Chapter2

2- CAUSES AND DETECTION OF KICKS:

2.1. CAUSES OF KICKS

A kick is defined as any undesirable flow of formation fluids from the

reservoir to the wellbore that occurs as a result of a negative pressure

differential across the formation face. Wells kick because the reservoir

pressure of an exposed permeable formation is higher than the wellbore

pressure at that depth. There are many situations which can produce this

unfavourable downhole condition. Among the most likely and recurring

are:

• Causes of Kicks

A. Low density drilling fluid.

B. Abnormal reservoir pressure.

C. Swabbing.

D. Not keeping the hole full on trips.

E. Lost circulation.

A. Low Density Drilling Fluid

Density of the drilling fluid is normally monitored and adjusted to

provide the hydrostatic pressure necessary to balance or slightly exceed

the formation pressure. Accidental dilution of the drilling fluid with

makeup water in the surface pits or the addition of drilled-up, low density

formation fluids into the mud column are possible sources of a density

reduction that could initiate a kick. Diligence on the mud pits is the best

way to ensure that the required fluid density is maintained in the fluids

pumped downhole.

13

Most wells are drilled with sufficient overbalance so that a slight

reduction in the density of the mud returns will not be sufficient to cause

a kick. However, any reduction in mud weight during circulation must be

investigated and corrective action taken. A major distinction should be

drawn between density reductions caused by gas cutting and those caused

by oil or salt water cutting.

B. Gas Cutting:

The presence of large volumes of gas in the returns can cause a drop in

the average density and hydrostatic pressure of the drilling fluid.

However, the appearance of gas cut mud at the surface usually causes

unnecessary concern, and often results in over-weighting of the mud.

C. Oil or Salt Water Cutting:

Oil and/or saltwater can also invade the wellbore from cuttings or

swabbing, reduce the average mud column density, and cause a drop in

mud hydrostatic pressure large enough to initiate a kick.

D. Abnormal Reservoir Pressure:

Formation pressure is due to the action of gravity on the liquids and

solids contained in the earth's crust. If the pressure is due to a full column

of saltwater with average salinity for the area, the pressure is defined as

normal. If the pressure is partly due to the weight of the overburden and

is therefore greater, the pressure is known as abnormal. Pressures below

normal due to depleted zones or less than a full fluid column to the

surface are called sub normally pressured.

14

C. Swabbing

Swabbing is a condition that arises when pipe is pulled from the well and

produces a temporary bottom hole pressure reduction. In many cases, the

bottom hole pressure reduction may be large enough to cause the well to

go underbalanced and allow formation fluids to enter the wellbore. By

strict definition, every time the well is swabbed-in, it means that a kick

has been taken. While the swab may not necessarily cause the well to

flow or cause a pit gain increase, the well has produced formation fluids

into the annulus that have almost certainly lowered the hydrostatic

pressure of the mud column. Usually, the volume of fluid swabbed-in to

the well is an insignificant amount and creates no well control problems

(e.g., a small amount of connection gas). Many times, however,

immediate action will need to be taken to prevent a further reduction in

hydrostatic pressure which could cause the well to flow on its own.

D. Not Keeping Hole Full

Blowouts that occur on trips are usually the result of either swabbing or

not keeping the hole full of mud. Substantial progress has been made in

blowout prevention, but constant اvigilance must be maintained. As drill

pipe and drill collars are pulled from the hole during tripping operations,

the fluid level in the hole drops. In order to maintain fluid level and mud

hydrostatic pressure, a volume of mud equal to the volume of steel

removed must be pumped into the annulus. An accurate means of

measuring the amount of fluid required to fill the hole must be provided.

E. Lost Circulation

An important cause of well kicks is the loss of whole mud to natural

and/or induced fractures and to depleted reservoirs. A drop in fluid

15

level in the wellbore can lower the mud hydrostatic pressure across

permeable zones sufficiently to cause flow from the formation.

2.2 DETECTION OF KICKS

It is highly unlikely that a blowout or a well kick can occur without some

warning signals. If the crew can learn to identify these warning signals

and to react quickly, the well can be shut-in with only a small amount of

formation fluids in the wellbore. Smaller kick volumes decrease the

likelihood of damage to the well bore and minimize the casing pressures.

Kick indicators are classified into two groups: positive and secondary.

Anytime the well experiences a positive indicator of a kick, immediate

action must be taken to shut-in the well. When a secondary indicator of a

kick is identified, steps should be taken to verify if the well is indeed

kicking.

2.3 INDICATION OF KICK:

A. Increase in Pit Volume .

The influx of a barrel of gas will also push out a barrel of mud at the

surface, but as the gas approaches the surface, an additional increase in

pit level will occur due to gas expansion. This is a positive indicator of a

kick, and the well should be shut-in immediately any time an increase in

pit volume is detected.

B. Increase in Flow Rate

An increase in the rate of mud returning from the well above the normal

pumping rate indicates a possible influx of fluid into the wellbore or gas

expanding in the annulus..

16

C. Decrease in Circulating Pressure

Invading formation fluid will usually reduce the average density of the

mud in the annulus. If the density of mud in the drillpipe remains greater

than in the annulus, this causes a decrease in the pump pressure and an

increase in the pump speed.

D. Gradual Increase in Drilling Rate

Therefore, the drilling rate will almost always increase as the bit enters an

abnormally pressured shale. This increase will not be rapid but gradual. A

penetration rate recorder simplifies detecting such changes. In

development drilling, this recorder can be used with offset well electric

logs to pinpoint the top of an abnormal pressure zone before any other

indicators appears.

E. Drilling Breaks

Abrupt changes in the drilling rate without changes in weight on bit and

RPM (rotation per min) are usually caused by a change in the type of

formation being drilled. A universal definition of a drilling break is

difficult because of the wide variation in penetration rates, types of

formations, etc. and experience in the specific area is required. In some

sand-shale sequences, a break may be from 10 ft/hr to 50 ft/hr, or perhaps

from 5 ft/hr to 10 ft/hr. In any case, while drilling in expected high

pressure areas, if a relatively long interval of slow (shale) drilling is

suddenly interrupted by faster drilling ( indicating a sand) the kelly

should be picked up immediately, the pump shut off, and the hole

observed for flow.

F. Increase in Gas Cutting

A gas detector provides a valuable warning signal of an impending kick.

17

G. Increase in Chlorides

Invasion of the drilling mud by formation water can sometimes be

detected by changes in the average density or the salinity of the mud

returning from the annulus. Depending on the density of the mud, dilution

with formation water will normally reduce average density. If the density

of the invading fluid is close to that of the mud, the density will be

unaffected, but perhaps a change in salinity will be apparent. This would

depend on the salinity contrast between the formation.

H. Decrease in Shale Density

The shale density will generally decrease when an abnormal pressure

zone is penetrated. This would be a good indicator if bulk densities of

representative samples could be accurately measured. A decrease in

density is a result of an increase in the water content within the shale.

I. Change in Cutting Size and Shape

The amount of shale cuttings will usually increase and change in shape

will take place when an abnormal pressure zone is penetrated. Cuttings

from normally pressured shales are small with rounded edges and are

generally flat, while cuttings from an abnormally pressured often become

long and splintery with angular edges. As the differential between the

pore pressure and the drilling fluid hydrostatic pressure is reduced, the

pressured shales will explode into the wellbore rather than being drilled

up. This change in shape, along with an increase in the amount of cuttings

recovered at the surface, could be an indication that the mud hydrostatic

pressure is too low and that a kick could occur while drilling the next

permeable formation.

18

Chapter 3

3.1 SHUT-IN PROCEDURE WHILE DRILLING

Drilling crews must be alert while drilling ahead and be on the lookout

for indicators that the well is kicking or that the bit is penetrating

abnormal pressure. The well must be shut-in immediately when there is

an indicator of a kick in the form of an increase in pit volume or flow

rate.

(1) SPACE OUT: Pull the kelly out of the hole. Position the kelly so that

there are no tool joints in the preventer stack.

(2) SHUT DOWN: Stop the mud pumps.

(3) SHUT-IN: Close the annular preventer or uppermost pipe ram

preventer. Confirm that the well is shut-in and flow has stopped.

The person most likely to shut-in the well is the Driller. The Driller

should be trained and will be able to take the initiative اto perform this

important function on his own without prompting or assistance. After the

well is securely shut-in, the Driller should notify the Drilling Supervisor

and the Contract Toolpusher. At this time, all members of the drilling

crew should be at their predetermined stations awaiting further

instructions.

a “hard shut-in” procedure:

means that the choke line valves on the drilling spool are in the closed

position while drilling and remain closed until after the preventer is

sealed and the well is shut-in.

a soft shut-in:

19

In the “soft shut-in” procedure, the choke line valves are opened to allow

the well to flow through the surface choke. After the preventers are

sealed, the choke is then closed to stop the flow. The soft shut-in

procedure gives the well additional time to flow before shut- in.

Therefore, it is not recommended because it doesn't minimize the size of

the influx.

3.2 POST SHUT-IN PROCEDURES WHILE DRILLING

After the well has been shut-in, the Drilling Representative has several

items to read and record. These include:

(1) SICP Read and record the shut-in casing pressure. Valves on the

drilling spool and choke manifold will need to be lined-up so that

wellbore pressure is transmitted to the closed drilling choke. The shut-in

casing pressure should be read from a gauge installed upstream of the

closed choke.

(2) SIDP Read and record the shut-in drillpipe pressure. If no float is in

the drillstring, this pressure can be read directly from a pressure tap on

the standpipe manifold. However, since it is recommended practice, most

drillstrings should have floats installed which will require “bumping” in

order to determine the SIDP.

(3) PIT GAIN Read and record the pit gain. The amount of influx is

important for accurate calculation of the maximum casing pressure. Pit

level charts or other volume totalizers can be examined to determine the

pit gain.

(4) TIME Make a note of the time the kick occurred. Also, keep an

accurate log of the entire kill operation as it progresses.

(5) CLOSING PRESSURES If the Drilling Representative

20

decides to work the pipe during the kill circulation, then the closing

pressure on the annular preventer should probably be reduced to prolong

the life of the element. The proper amount of closing pressure will

depend on the size and make of the preventer and the wellbore pressure

underneath. It should be high enough to prevent wellbore fluid from

leaking around the element.

After this information has been gathered, the Drilling Representative

should notify his Supervisor to discuss the appropriate method for killing

the well.

3.3 SHUT-IN PROCEDURE WHILE TRIPPING

Statistics indicate that the majority of kicks occur while tripping. Pulling

out of the hole is a critical operation that demands diligence by the

drilling crews and is not the time to be realix about well control! Hole

filling and hole monitoring equipment should be in top condition so that

the kicking well can be detected as early as possible. Preparation for a trip

should be the same as the one to penetrate a known abnormal pressure

zone. Be prepared for the well to kick on every trip.

Every time a well is swabbed-in, it takes a mini-kick; formation fluids

enter the wellbore from the negative pressure differential generated by the

swabbing effect. The well may not continue to flow after the pipe is

stopped, but formation fluids that have entered the annulus reduce the

hydrostatic pressure. If the well continues to swab-in on successive:

stands, then the hydrostatic pressure in the annulus may be sufficiently

reduced to allow the well to flow when the pipe is stationary. For this

reason, any time swabbing is indicated during a trip, the drillpipe should

be run back to bottom and the well circulated at least to bottoms-up.

Furthermore, any time the well is detected to be flowing during a trip, it

21

must be shut-in immediately using the following "Three S" Shut-in

Procedure

Shut-In Procedure While Tripping

(1) STAB VALVE: Install the fully opened safety valve in the drillstring.

Close the safety valve.

(2) SPACE OUT Position the drillstring so that there are no tool joints in

the preventer stack.

(3) SHUT-IN Close the annular preventer or uppermost pipe ram

preventer. Confirm that the well is shut-in and flow has stopped.

After the well is securely shut-in, the Driller should notify the Drilling

Representative and the contract Toolpusher while all members of the

drilling crew are at their assigned stations awaiting further instructions.

3.4 POST SHUT-IN PROCEDURES WHILE TRIPPING:

Taking a kick while tripping is a severe well control complication.

Because there is no steady-state while tripping, the data that was

previously relied upon to kill the well may not be valid. Nevertheless,

after the well is securely shut-in, the Drilling Representative will need to

gather as much information about the wellbore condition as possible.

These will include:

(1 ) SICP Read and record the shut-in casing pressure. Valves on the

drilling spool and choke manifold will need to be lined-up so that

wellbore pressure is transmitted up to the closed drilling choke. The shut-

in casing pressure should be read from a gauge installed upstream of the

closed choke.

22

(2 ) PIT GAIN Read and record the pit gain. The amount of influx is

important for accurate calculation of the maximum casing pressure. If a

trip tank is in use and an accurate trip log was being maintained, then the

pit gain is simply the difference between the present trip tank volume and

the volume after the last fill-up, plus the volume of metal pulled from the

well since the last fill-up. If the hole was being filled out of the active

pits, which is not recommended, then determination of the kick volume is

much more difficult. Pit level charts or other volume totalizers can be

examined in an attempt to determine the pit gain in these instances.

(3 ) TIME Make a note of the time the kick occurred. Also, keep an

accurate log of the entire kill and/or stripping operation as it progresses.

(4 ) BIT DEPTH Determine the bit depth from the Driller’s pipe figures.

This number is important for a variety of calculations and determinations

discussed later in this section.

NOTE: It will usually not be necessary to record a value for the shut-in

drillpipe pressure. This is because the mud weight does not usually have

to be increased when a kick is taken during a trip unless the well is going

to be killed off-bottom. However, if a shut-in drillpipe pressure is taken,

then allowances must be made for the volume of drillpipe slug(What is

slug? Slug: It is heavy mud which is used to push lighter mud weight

down before pulling drill pipe out of hole) remaining in the pipe. If this

volume cannot be determined, then an accurate value for shut-in drillpipe

cannot be calculated.

After this information has been gathered, the Drilling Representative

should consult with a Drilling Supervisor to determine the proper

remedial ) اaction to take in controlling the well. This will usually involve

stripping back to bottom, which is covered in Section

23

3.5 WHEN AND HOW TO CLOSE THE WELL

While drilling, there are certain warning signals that, if properly analyzed,

can lead to early detection of gas or formation fluid entry into the wellbore.

1. Drilling break. A relatively sudden increase in the drilling rate is called a

drilling break. The drilling break may occur due to a decrease in the

difference between borehole pressure and formation pressure. When a

drilling break is observed, the pumps should be stopped and the well

watched for flow at the mud line. If the well does not flow, it probably

means that the overbalance is not lost or simply that a softer formation has

be encountered.

2. Decrease in pump pressure. When less dense formation fluid enters the

borehole, the hydrostatic head in the annulus is decreased. Although

reduction in pump pressure may be caused by several other factors, drilling

personnel should consider a formation fluid influx into the wellbore as one

possible cause. The pumps should be stopped and the return flow mud line

watched carefully.

3. Increase in pit level. This is a definite signal of formation fluid invasion

into the wellbore. The well must be shut in as soon as possible.

4. Gas-cut mud.Whendrilling through gas-bearing formations, small

quantities

of gas occur in the cuttings. As these cuttings are circulated up, the

annulus, the gas expands. The resulting reduction in mud weight is

observed at surface. Stopping the pumps and observing the mud return line

help determine whether the overbalance is lost.

24

If the kick is gained while tripping, the only warning signal we have is an

increase in fluid volume at the surface (pit gain). Once it is determined that

the pressure overbalance is lost, the well must be closed as quickly as

possible. The sequence of operations in closing a well is as follows:

1. Shut off the mud pumps.

2. Raise the Kelly above the BOP stack.

3. Open the choke line

4. Close the spherical preventer.

5. Close the choke slowly.

6. Record the pit level increase.

7. Record the stabilized pressure on the drill pipe (Stand Pipe) and annulus

pressure gauges.

8. Notify the company personnel.

9. Prepare the kill procedure.

If the well kicks while tripping, the sequence of necessary steps can be

given below:

1. Close the safety valve (Kelly cock) on the drill pipe.

2. Pick up and install the Kelly or top drive.

3. Open the safety valve (Kelly cock).

4. Open the choke line.

5. Close the annular (spherical) preventer.

6. Record the pit gain along with the shut in drill pipe pressure (SIDPP) and

shut in casing pressure (SICP).

7. Notify the company personnel.

8. Prepare the kill procedure.

25

Depending on the type of drilling rig and company policy, this sequence

of operations may be changed.

Read also Drilling Rotating Equipment

3.6 KICK CONTROL PROCEDURES

There are several techniques available for kick control (kick-killing

procedures).

In this section only three methods will be addressed.

3.6.1 Driller’s method. First the kick fluid is circulated out of the hole

and hen the drilling fluid density is raised up to the proper density

(kill mud density) to replace the original mud. An alternate name

for this procedure is the two circulation method.

3.6.2 Engineer’s method. The drilling fluid is weighted up to kill

density while the formation fluid is being circulated out of the hole.

Sometimes this technique is known as the one circulation method.

3.6.3 Volumetric method. This method is applied if the drillstring is off

the bottom.

The guiding principle of all these techniques is that bottomhole pressure is

held constant and slightly above the formation pressure at any stage of the

process. To choose the most suitable technique one ought to consider

(a) complexity of the method.

(b) drilling crew experience and training,

(c) maximum expected surface and borehole pressure.

26

(d) Time needed to reestablish pressure overbalance and resume normal

drilling operations.

27

3.7 Kill sheet:

A kill sheet is normally used during conventional operations. It contains

prerecorded data, formulas for the various calculations, and a graph—or

other means—for determining the required pressures on the drillpipe as

the kill mud is pumped. Although many operators have complex kill

sheets, only the basic required kick-killing data is necessary. A kill sheet

is shown in the example problem in the following section.

A summary of the steps involved in proper kick killing follows. The

sections not directly applicable to deepwater situations are noted. When a

kick occurs, shut in the well using the appropriate shut-in procedures.

Once the pressures have stabilized, follow these steps to kill the kick:

1. Read and record the shut-in drillpipe pressure, the shut-in casing

pressure, and the pit gain. If a float valve is in the drillpipe, use the

established procedures to obtain the shut-in drillpipe pressure.

2. Check the drillpipe for trapped pressure.

3. Calculate the exact mud weight necessary to kill the well and prepare a

kill sheet.

4. Mix the kill mud in the suction pit. It is not necessary to weight up the

complete surface-mud volume, initially. First pump some mud into the

reserve pits.

28

5. Initiate circulation after the kill mud has been mixed, by adjusting the

choke to hold the casing pressure at the shut-in value, while the driller

starts the mud pumps. (Not applicable in deep water.)

6. Use the choke to adjust the pumping pressure according to the kill

sheet while the driller displaces the drillpipe with the exact kill-mud

weight at a constant pump rate (kill rate).

7. Consider shutting down the pumps and closing the choke to record

pressures when the drillpipe has been displaced with kill mud. (Note: If

the kill mud is highly weighted up, settling and plugging may occur.) The

drillpipe pressure should be zero, and the casing should have pressure

remaining. If the pressure on the drillpipe is not zero, execute the

following steps:

▪ Check for trapped pressure using the established procedures. If the

drillpipe pressure is still not zero, pump an additional 10 to 20 bbl (1.5

to 3 m3) to ensure that kill mud has reached the bit. The pump

efficiency may be reduced at the low circulation rate.

▪ If pressure remains on the drillpipe, recalculate the kill mud weight,

prepare a new kill sheet, and return to the first steps of this procedure.

8. Maintain the drillpipe pumping pressure and pumping rate constant to

displace the annulus with the kill mud by using the choke to adjust the

pressures, as necessary.

9. Shut down the pumps and close the choke after the kill mud has

reached the flow line. The well should be dead. If pressure remains on the

casing, continue circulation until the annulus is dead.

10. Open the annular preventers, circulate and condition the mud, and add

a trip margin when the pressures on the drillpipe and casing are zero. In

29

subsea applications, the trapped gas under the annular is circulated out by

pumping down the kill line and up the choke line with the ram preventer

below the annular closed. The riser must then be circulated with kill mud

by reverse circulation, down the choke line and up the riser, before the

preventers can be opened.

The example below has been provided for this purpose.

Fig.7 Kill sheet preparation

30

3.8 Relief well:

Blowout happen and become uncontrollable one of the most method to

kill the well is relief well.

In the natural gas and petroleum industry, a relief well is drilled to

intersect an oil or gas well that has experienced a blowout. Specialized

liquid, such as heavy (dense) drilling mud followed by cement, can then

be pumped down the relief well in order to stop the flow from the

reservoir in the damaged well.

Drilling relive well to kill the well doesn't mean that such wells are easy

to engineer. It takes a rather sophisticated geophysical sensing system,

specialized simulation software, and some careful calculations.

Fig. 8 show the Relief well

31

Chapter 4

4.1 Well control equipment

4.1.1 Classification of BOPs.

Blowout preventers (BOPs), in conjunction with other equipment and

techniques, are used to close the well in and allow the crew to control a

kick before it becomes a blowout. Blowout preventer equipment should

be designed to :

✓ Close the top of the hole.

✓ Control the release of fluids.

✓ Permit pumping into the hole .

✓ Allow movement of the inner string of pipe.

These requirements mean that there; must be enough casing in the well to

provide an anchor for the wellhead equipment, there must be provision

for equipment to close the hole with or without pipe in well, theا

equipment must provide for the attachment of lines for bleeding off

pressure, and it must allow pumping into the working string or annulus.

4.1.2 Basic types of blowout preventers on drilling rig are :

A. annular preventers.

B. rotational preventers and diverters.

C. ram preventers.

32

A. Annular – type preventers

employ a ring of reinforced synthetic rubber as a packing unit that

surrounds the well bore to effect shutoff In the full-open position, the

inner diameter of the packing unit equals the diameter of the preventer

bore. A system for squeezing the ring of packing lets the operator reduce

the diameter until it engages the pipe, tool joint, kelly or the full inner

diameter of the preventer. The only way to close annular- type of

preventers is by use of hydraulic pressure.

Although initial closure of the packing unit is obtained by hydraulic

pressure from an external source, well pressure will increase sealing

effect and thus insure positive closure under high well pressure. The

preventer is normally operated by a fluid pressure of (1500 psi). A

pressure regulator should be employed to insure the lowest closing

pressure to permit slight leakage of well fluid around the drill pipe when

rotating or stripping in or out of the hole. A small amount of fluid leaking

past the pipe will lubricate and cool the packing unit.

Fig 9 Annular Blowout Preventer:

33

Fig 10 Cross section of Annular preventer:

34

.

Fig .11 Rotational preventers and diverters.

B. rotational preventers and diverters

In the BOP stack they are always positioned in such way, that annular

preventer is the working preventer positioned on the top of the stack, and

ram preventer is on the bottom as the backup. Working preventer is

always positioned far from the source of danger, to be in position to

change it if fails.

35

Fig .12 assembly of "Bop" Installed on well head:

36

Fig . 13 Ram-type preventer:

C. Ram-type preventer

They close the annular space outside the string of pipe in a well or open

hole, by moving rams from a retracted position clear of the bore into a

position where they close around the pipe. Rams operate in pairs and seal

space below them closed.

Pipe rams are provided with semi-circular openings which match the

diameter of the pipe sizes for which they are designed. It is absolutely

vital that the pipe rams in a preventer fit the drill pipe or tubing in the use,

and all concerned must be certain in this regard at all times. If more than

one size of drill pipe is in the hole, most operators require a second ram

preventer in the stack.

37

Pipe rams are provided with semi-circular openings which match the

diameter of the pipe sizes for which they are designed. It is absolutely

vital that the pipe rams in a preventer fit the drill pipe or tubing in the use,

and all concerned must be certain in this regard at all times. If more than

one size of drill pipe is in the hole, most operators require a second ram

preventer in the stack.

Blank units which will close on the open hole are commonly termed

“blind”rams. Blind rams will flatten drill pipe or tubing if they are

inadvertently closed in them, and the driller should always be certain not

to operate the blind rams when the pipe is in the hole. Ram-type

preventers were originally manually operated, but most preventers of this

type today are closed and opened by hydraulic means, using fluid that is

under (500 psi) to (1500 psi) of pressure. Most ram-type preventers are

provided with screws to lock the rams in the closed position. Manually

operated preventers are similar to hydraulic units, except for the hydraulic

cylinders.

Blind rams can also be used as drill pipe cutters. The use of blind rams

for such purposes is acceptable only when there is the treat of open

blowout, and nothing else can be done .

4.1.3 Inside preventers

✓ kelly cock

✓ inside blowout preventer, valve restrict flow up.

✓ drill pipe float valve ,

✓ or drop in check valve

should be available for use when stripping the drill string into or out of

the hole. The valve(s), sub(s), or profile nipple should be equipped to

screw into any drill string member in USA

38

Fig .14 Kelly valves (kelly cocks)

An upper kelly valve is installed between the swivel and the kelly. A

lower kelly valve is installed imediatelly below the kelly. Upper kelly has

on the top the left-hand screw to avoid uncontrolled screw of, and on the

bottom there will be a right-hand screw.

✓ Inside Blowout preventer:

The inside blowout preventer protects the rotary swivel, drilling hose,

standpipe and mud pumps when a kick occurs through the drill string. It

will effectively seal against the pressures up to 69 MPa.(20885.4 psi)

Permits downward flow of circulation fluid through the drill pipe while

preventing upward flow after circulation stops. Always on the working

floor near the rotary table.

39

✓ Drill string safety valve:

A spare drill pipe safety valve should be readily available (i.e. stored in

open position with wrench accessible) on the rig floor at all times. This

valve or valves should be equipped to screw into any drill string member

in use. The outside diameter of the drill pipe safety valve should be

suitable for running in the hole.

Fig . 15 Drill string float valve

✓ float valve

is placed in the drill string to prevent upward flow of fluid or gas inside

the drill string. This is a special type of back pressure check valve. When

in good working order it will prohibit backflow and a potential blowout

through the drill string.

The drill string float valve is usually placed in the lower-most portion of

the drill string, between two drill collars or between the drill bit and drill

40

collar. Since the float valve prevents the drill string from being filled with

fluid through the bit as it is run into the hole, the drill string must be filled

from the top, at the drill floor, to prevent collapse of the drill pipe.

Fig .16 Flapper-type float valve:

41

✓ The flapper-type float valve

offers the advantage of having the opening through the valve that is

approximately the same inside diameter as that of the tool joint. This

valve will permit the passage of balls, or go-devils, which may be

required for operation of tools inside the drill string below the float valve.

✓ Spring-loaded float valves:

The spring-loaded ball, or dart and seat float valve offers the advantage

of an instantaneous and positive shut off of backflow through the drill

string. These valves are not full-bore and thus cannot sustain long

duration or high volume pumping of drilling or kill fluid. A wire line

retrievable valve that seals in a profiled body that has an opening

approximately the same inside diameter as that of tool joint may be used

to provide a full-open access, if needed.

42

Fig .17 Well head

The wellhead includes all equipment placed on top of the well to support

tubulars, provide seals, and control the paths and flow rates of fluids.

−All wellheads include at least; −one casing head and casing hanger, −a

tubing head and tubing hanger, and a Christmas tree. Casing heads are

attached to surface casing or to another casing head to provide a hanging

point for the next string of casing. −If there is one casing head, it is

welded or screwed (depending on diameter) to the surface casing, and the

production casing is hung from it .

If more than one casing string is used inside the surface casing, then more

than one casing head may be needed. −An intermediate casing head may

43

be added with each new casing string until the production casing has been

hung.

The top of a casing head has a cone-shaped bowl that holds the casing

hanger. A casing hanger is a set of slips that grips and supports a casing

string. Metal and rubber packing rings fit over the slips to complete the

casing hanger assembly and provide an annular seal. Threaded or flanged

outlets on the side of the casing head allow access to the sealed annulus

for pressure gauges that warn of casing leaks.

Testing and Maintenance of surface BOP stack and well control

equipment

The purpose for various test programs on drilling well control equipment

is to verify :

✓ That specific functions are operationally ready.

✓ The pressure integrity of the installed equipment.

✓ The control system and BOP compatibility

All operational components of the BOP equipment should be functioned

at least once a weak to verify the component’s intended operations,

Function tests may ormay not include pressure tests. They should be

alternated from the driller’s panel and from mini-remote panels, if on

location. Actuation times should be recorded as a data base for evaluating

trends.

When testing BOP stack the hole is separated by the use of so called “cup

tester.”

44

4.1.4 Pressure tests

All blowout prevention components that may be exposed to well pressure

should be tested first to a low pressure of (200 to 300 psi) and then to a

high pressure. When performing the low pressure test, do not apply a

higher pressure and bleed down to the low test pressure. A stable low test

pressure should be maintained for at least 5 minutes.

The initial high pressure test on components that could be exposed to well

pressure (BOP stack, choke manifold and choke lines) should be to the

rated working pressure of the ram BOP’s or to the rated working

pressure of the wellhead that the stack is installed on, whichever is lower.

Initial pressure tests are defined as those tests that should be performed

on location before the well is spaded or before the equipment is put into

operational service.

The lower kelly valves, kelly, kelly cock, drill pipe safety valves, inside

BOP's and top drive safety valves, should be tested with water pressure

applied from below to a low pressure of (200 to 300 psi) and then to the

rated working pressure.

Subsequent high pressure tests on the well control components should be

to a pressure greater than the maximum anticipated surface pressure, but

not to exceed the working pressure of the ram BOPs. The maximum

anticipated pressure should be determined by the operator based on

specific anticipated well conditions..

The pressure test performed on hydraulic chambers of annular BOPs,

connectors, hydraulic lines and manifolds, should not exceed (should be

at least 1500 psi). Initial pressure tests on hydraulic chambers of ram

BOPs and hydraulically operated valves should be to the maximum

operating pressure recommended by the manufacturer.

45

For annular preventers closing pressures differ because of the higher

closing area. Figure shows closing pressures for annular preventers

depending on working pressure and closing area (full closing or around

specific pipe diameter.

• Pressure testing of an annular preventer

Pressure testing of ram-type preventer, closing around the pipe body.

• Hydraulic control fluids

Preventers are activated by the use of special hydraulic control fluid. The

fluid must: not freeze on low temperatures (temperature range from 84 °C

to –46 °C) lubricate moving parts and avoid wearing out not cause

corrosion disperse in salt or fresh water and not pollute or contaminate.

For such purpose it is possible to use: original manufacturer product

Koomey hydraulic fluid C-50F is mixed with fresh water and ethylene

glycol must be added to the diluted fluid for freeze protection.

Recommended installation of Blowout Preventer Control Systems

Recommended installation of Blowout Preventer Control Systems Quick

and efficient closing and control of preventer stack units is possible from:

accumulator (pumping) unit, master control panel, and auxiliary control

panel.

Safety distance for accumulator unit is recommended to be minimum30

meters away from the wellhead. All commands have graphical and

textual explanation. Commands are used to transfer the initial pressure

that opens or closes the hydraulic fluid passage in accumulator unit to

enable preventer closing or opening.

46

Fig. 18 Hydro-Nitrogen Accumulators

Three different types of accumulators are on disposal:

(1) separator type,

(2) cylindrical guided float type,

(3) spherical guided float type.

The separator type is recommended for maximum safety, and are

available in sizes ranging from 0.0245 liter to 42 liters, and 20,7 to 41,4

MPa working pressure. The operating temperature range is -34 °C to 85C

The temperature of nitrogen in the process of compression or expansion

is not constant, since there is a heat exchange between nitrogen and oil

and surrounding air or sea water. Actual measurements confirm that

nitrogen behavior in the mentioned conditions correspond to the

polytrophic change of state, as defined by Zeuner’srelation.

47

Fig .19 Choke and kill manifold

• Choke and kill manifolds

can be made to meet any customer requirements. But for optimal work,

they should consist of: one, two or more drilling choke system (operated

hydraulically or manual) manual and/ hydraulically or air operated gate

valves, pressure transmitters, pressure gauges, crosses, tees,*shaped like

T* and a buffer tank (sense of hummer decrease the pressure).(A buffer

tank is a storage tank used on the cold user side of an air-conditioning

system.)as required .

4.1.5 Drilling choke system

Hydraulically actuated drilling chokes are available in working pressures

from (5000 to 20000 psi). Inlet and outlet flange sizes from 77,8 to 103,2

mm. The standard size of orifice is 44,5 mm (1 ¾”). Working

48

temperature is up to 121 °C. Hydraulic pressure of (300 psi) is applied to

the actuator which results in opening or closing the choke.

manually actuated drilling chokes are available in working pressures from

(5000 to 20000 psi). Inlet and outlet flange sizes from 77,8 to 103,2 mm.

The standard size of orifice is 44,5 mm (1 ¾”). Working temperature is

up to 121 °C.

Pressure transmitters, located on the standpipe and the choke manifold,

use actual mud pressure as a pilot to regulate low pressure pneumatic

signals which are transmitted through hoses to the control console where

pressure readings are registered on the panel gauges.

• .Gate valves.

The valves used on the choke manifold are of the gate valve type. Their

main parts are:

1.positive rotating seats

2.gate and seat assembly

3.solid gate

4.thrust bearings

5.threaded packing retainer

6.back-seating

7.stem pin

8.grease injection port

9.body and trim

49

The air or hydraulically operated models are identical in construction,

except for the size and pressure rating of the operating cylinder.

50

4.1.6 Crew Positions During Well Kick Control Operations

1- Driller

The Driller is the main line of defense when a kick occurs. It is his

responsibility to:

- Close the well in.

- Call man in charge.

- On floating rigs, call the Subsea Engineer to the drill floor.

- Regularly monitor and record time, pressures, volumes etc. during the

kill

operations using page 2 of the kick report form 384.

- Remain at the drilling console in order to run the rig pumps during the

kill

procedure.

2- Rig Superintendent

The Rig Superintendent is the SEDCO FOREX man in charge of the kill

operation.

It is his responsibility to ensure that the crew is organized and prepared to

kill the

well. He will consult with the Company Representative whenever

possible. The Rig

Superintendent or his designee will operate the choke during well kill

operations.

3- Derrickman/Assistant Driller

- The Derrickman/Asst. Driller is to go to the mud pit area, line up mud

gas

separator, degasser and mixing pumps to raise mud weight.

- Line up to add baryte and standby for specific instructions from Rig

Superintendent and Mud Engineer.

51

- When pumping starts, keep constant check on mud weight and keep

Driller informed.

4- Roughnecks

On drill floor to follow instructions of Driller.

5- Electrician/Mechanic

Standby for possible instructions

6- Company Representative

It is suggested that, during the actual kill operation, he remain at the

remote choke

control panel so he can discuss the operation with the Rig Superintendent.

7- Mud Engineer,

Go to pits, check Derrickman/Asst. Driller’s preparations, assist in

building proper mud weight and maintaining same

8- Additional Personnel on Offshore Units

Responsibilities are as per posted station bill; the following are shown

below as examples:

Barge Supervisor:

- Ensure standby boat is notified.

- Standby in control room for instructions.

Cementer:

- Go to cement unit, line up for cementing, and standby for orders.

Roustabouts:

- In mud pump room to follow instructions of Derrickman.

Subsea Engineer:

- Report to rig floor to inspect subsea panel and observe possible

problems.

- Wait for instructions from Rig Superintendent.

52

Case Study about (Deep water horizon rig)

53

Chapter5

5.1 Deep water horizon :

was one of the most modern icon rigs in USA It was the best drilling rig

in the world and has the deepest drilling record in the world for more than

10,500 km,

Which was owned by Transocean And managed by "BP" (British

Petroleum) which were capable companies they had a very experienced

crew.

However, blowout happened cause one of the most worst environmental

disasters in world .

Fig.20 Deep water horizon

54

5.1.1 Overview:

• 20thApril .2010:

Deep water horizon had been drilled an oil well in 5000ft in deep water

in area of gulf Mexico know as Macando.

After a delay of 43 days, the drilling rig was prepared for the

disintegration of the completed well. The crew decided to temporarily

abandon the well and close it, conduct the negative pressure test and

make sure the well is closed. There is no entry for hydrocarbons.

The negative pressure test was not carried out properly, and the monitors

showed unusual pressure that could not be explained

The pressure reached 1,400 psi. If the well was sealed, the pressure would

be stable, which means that there is a path that could pass through the

hydrocarbon to the well .

Fig.21 Show the pressure records in kill line and Drill pipe

Where 1400 psi was interpreted as a false reading and thought that the

height was due to "bladder effect"

55

If the negative pressure between the kill line and the drill pipe is

explained to detect the faults, at this point they would be able to close the

well and avoid blowout.

Dad Cement job: There is not enough centralizers to make the hole

straight and the type of cement used has been added to the nitrate

mechanism, creating channels that allow oil and gas to enter the well.

Fig.22 Cement job

56

Failure of the" BOP" blowout preventer to seal the well, Investigations

have shown that batteries that feed "Deadman" were not charged and

therefore BOP could not shear the pipe.

Fig.23 " BOP " Failed to shear the pipe

Bad management by BP There is no spirit of teamwork, selfishness and

urgency in digging the well ignoring the signs of the blowout

All these reasons caused the explosion of the drilling rig and a major

environmental disaster led to the largest oil spill in the world, where

leakage of about 5 million barrels of oil-coated mortar about 90 km

This disaster caused the damaging reputation of BP.

BP was charged with murder for 11 people All its contracts were

withdrawn and fined $ 14 billion

57

Fig .24 Explosion of Deep water horizon :

58

Fig.25 Show oil spill

Fig.26 Show oil spill in the The Gulf Of Mexico

59

❖ according to National Commission for Investigations and Chemical

Safety Board, The cause of the kick are :

1. primary causes was the cement job failed to seal the bottom

of the well.

▪ Centralizers not enough to keep the hole straight

▪ Nitrified the cement which makes channels and

allow the hydrocarbon get in to the well

2. Misinterpreted pressure test.

3. Failed "BOP" to seal the well.

4. Investigation concllged that "BP" and Transocean each make

critical decision unilaterally, and there is no teamwork.

5.1.2 Conclusion of this case study:

Deep water horizon was an example of managing the wells control by

following the global procedures for drilling and not to ignore any signs of

risk and not to choose shortcuts to end the work, which in turn may cause

disasters

60

5.1.3 Conclusion

✓ The aim of oil operations is to complete all tasks in a safe and

efficient manner without detrimental effects to the

environment. This aim can only be achieved if control of the

well is maintained at all times. The understanding of pressure

and pressure relationships is important in preventing blowouts.

Blowouts are prevented by experienced personnel that are able

to detect when the well is kicking and take proper and prompt

actions to shut-in the well

61

Reference :

(n.d.).

http://petrowiki.org/Well_control. (n.d.).

http://www.arena-international.com/hrps2012-cancelled/richard-

sears/1973.speaker. (n.d.).

https://en.m.wikipedia.org/wiki/Deepwater_Horizon. (n.d.).

https://en.wikipedia.org/wiki/Oil_well_control.

https://en.wikipedia.org/wiki/Well_control#Conclusion. (n.d.).

https://www.netwasgroup.us/well-control-2/fundamental-principles-of-

well-control.html. (n.d.).

https://www.youtube.com/watch?v=_4Vn3uMv60k. (n.d.).

ttp://wildwell.com/literature-on-demand/literature/well-control-

methods.pdf.