Annular Pressure Measurements.pdf

8/10/2019 Annular Pressure Measurements.pdf

1/16

40 Oilfield Review

Using Downhole Annular Pressure Measurementsto Improve Drilling Performance

Walt Aldred

John Cook

Cambridge, England

Peter Bern

BP Exploration Operating Company Ltd.

Sunbury on Thames, England

Bill Carpenter

Mark Hutchinson

John Lovell

Iain Rezmer-Cooper

Sugar Land, Texas, USA

Pearl Chu Leder

Houston, Texas

For help in preparation of this article, thanks to Dave Bergt,Schlumberger Oilfield Services, Sugar Land, Texas, USA;Tony Brock, Kent Corser, Kenneth Sax and James Thomson,BP Exploration, Houston, Texas; Tony Collins, Liz Hutton,

John James, Dominic McCann, Rachel Strickland andDave White, Anadrill, Sugar Land, Texas; Tim French,Anadrill, New Orleans, Louisiana, USA; Vernon H. Goodwin,EEX Corporation, Houston, Texas; Aron Kramer, GeoQuest,Youngsville, Louisiana; and Technical editing Services (TeS),Chester, England.

APWD (Annular Pressure While Drilling), CDR(Compensated Dual Resistivity tool), LINC (LWD InductiveCoupling tool), SideKick, VISION475, VISION675 and VIPERare marks of Schlumberger. PWD (Pressure-While-Drilling)service is a mark of Sperry-Sun.

When monitored downhole in the context of other parameters, pressure in the borehole annulus can

be used to identify undesirable well conditions, help suggest and evaluate remedial procedures and

prevent serious operational drilling problems from developing.

To survive and prosper in todays low-price oil

and gas market, operating companies are con-

tinually challenged to lower their finding and

producing costs. To tap the full potential of exist-ing reservoirs and make marginal fields more

productive, many wellbores are becoming both

longer and more complex. However, keeping

costs low requires operating companies to

improve drilling efficiency. The rig floor is some-

times like a hospital surgical theater. Instead of

finding physicians and nurses, one finds drillers,

engineers and other crew members working

with one objective: to keep their patient, the

borehole, alive and healthy. Just as biological

vital signs, like blood pressure and heart rate,are monitored during an operation, so the life

signs of the borehole construction process

downhole pressure and mud flow ratesare

monitored during drilling.

The measurements described in this article

are the sight and touch of the driller, enabling

him to see and feel the dynamic motions of the


2/16

The pressure window. In some wells,especially deviated and extended reach, themargins (right)between pore pressure (redcurve) and fracture gradient (yellow curve)may be small500 psi [3447 kPa] or lessand very accurate annular pressure (whitecurve) information is essential to maintainoperations within safe limits. Well controlrequirements are such that circulation of aninflux through the long choke and kill linesthat run from the subsea blowout preventer(BOP) also imply a lower kick tolerance

(orange dashed curve). The influence ofwell deviation angle on the pressure window(below)shows that managing the mudweight in extended-reach wells is mademore difficult by annular pressure losseswhich are inherently high for wells with longhorizontal sections.

Winter 1998 4

drillstring, and the downhole behavior of the

drilling fluid, so that optimal decisions can be

made. Vibration and shock data along with

torque and weight on bit can be used to modify

drilling parameters for increased bit and bottom-

hole assembly (BHA) reliability and performance.

The lifeblood of the drilling process is the drilling

fluid, and downhole mud pressuremeasured in

the annulus between the drill collar and the bore-

hole wallis one of the most important pieces

of information that the driller has available to

sense what is happening as the drill bit enters

each new section of formation, or during running

the bit into or out of the hole.

Monitoring downhole annular pressure is being

used in many drilling applications, including

underbalanced, extended-reach, high-pressure,

high-temperature (HPHT) and deep-water wells.1

Such measurements are provided by a number of

service companies, and operators have been

using them for a wide variety of applications

including monitoring the effects of pipe rotation,

cuttings load, swab and surge, leak-off tests(LOT), formation integrity tests (FIT), and detect-

ing lost circulation (see How Downhole Annular

Pressure is Monitored, page 42).2

In underbalanced directional drilling, the use

of downhole annular pressure sensors keeps the

operation within safe pressure limits and moni-

tors the use of injected gas, which results in

more efficient, lower cost drilling. In extended-

reach drilling (ERD), annular pressure measure-

ments can be used to detect poor hole cleaning

and help the operator modify fluid properties

and drilling practices to optimize hole cleaning.

In conjunction with other drilling parameters,real-time annular pressure measurements

improve rig safety by helping avoid potentially

dangerous well-control problemsdetecting

gas and water influxes. These measurements

are often used for early detection of sticking,

hanging or balling stabilizers, bit problem detec-

tion, detection of cuttings buildup and improved

steering performance. While real-time pressure

data are of significant value, the information

from these measurements is also useful in plan-

ning the next well.

This article examines the physical processes

associated with downhole hydraulic systemsand the use of annular pressure in monitoring

the downhole drilling environment. We will look

at field examples that show the dynamics of

common drilling problems and demonstrate how

a basic understanding of hydrodynamic

processestogether with a knowledge of

drilling parameterscan help provide advance

warning of undesirable and preventable events.

The examples illustrate three important drilling

applications in which downhole pressure meas-

urements are valuable: Extended-reach wells, where efficient hole

cleaning and cuttings transport are essential in

preventing stuck tools and packoff events,

which may damage formations and lead to

expensive fluid loss.

Deep-water wells, where there is a narrow

pressure window between pore pressure

and formation fracture pressure, and both

fluid influx detection and wellbore stability

are critical.

Improved drilling efficiencies, with downhole

annular pressure measurements providing

accurate LOT and FIT pressures, and a morerealistic determination of formation stress.

Wellbore Stability

Successful drilling requires that the drilling fluid

pressure stay within a tight mud-weight windowdefined by the pressure limits for wellbore sta

bility. The lower pressure limit is either the pore

pressure in the formation or the limit for avoiding

wellbore collapse (above). Normal burial trends

lead to hydrostatically pressured formations

where the pore pressure is equal to that of a

water column of equal depth. If the drilling fluid

pressure is less than the pore pressure, then for

mation fluid or gas could flow into the borehole

with the subsequent risk of a blowout at surface

or underground.

The upper pressure limit for the drilling fluid

is the minimum that will fracture the formation. Ithe drilling fluid exceeds this pressure, there is a

risk of creating or opening fracturesresulting

in lost circulation and a damaged formation. In

the language of drilling engineers, pressures are

often expressed as pressure gradients or equiva

lent fluid densities. The upper limit of the pres-

sure window is usually called the formation

fracture gradient, and the lower limit is called the

pore pressure, or collapse, gradient.

Mudweight,

sg

Collapsegradient

0.00 20 40

Well deviation, degrees

60 80

0.4

0.8

1.2

1.6

2.0

2.4

Fracturegradient

Stable

Depth

Pressure

Annularpressure

Kicktolerance

FracturegradientPore

pressure

1. Isambourg P, Bertin D and Brangetto M: Field HydraulicTests Improve HPHT Drilling Safety and Performance,paper SPE 49115, accepted for presentation at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 27-30, 1998.

2. Rudolf R and Suryanarayana P: Field Validation of SwabEffects While Tripping-In the Hole on Deep, HighTemperature Wells, paper SPE 39395, presented at theIADC/SPE Drilling Conference, Dallas, Texas, USA, March3-6, 1998.


3/16

42 Oilfield Review

The history of annular pressure measurements

extends as far back as the mid 1980s when

Gearhart Industries, Inc. provided annular pres-sure sensors on their measurements-while-

drilling (MWD) tools. Since then, Anadrill and

other service companies have developed sensors

for downhole annular pressure measurements

while drilling.1 The first application of these

measurements has been primarily for drilling

and mud performance, kick detection and equiv-

alent circulating density (ECD) monitoring.

Adding internal pressure sensors, combined

with annular pressure measurements, enables

differential pressure to be determined, which

can be used to monitor motor torque and power

performance.

Sperry-Sun was an early proponent of record-

ing ECD measurements during connections, and

while pulling out and running in hole to monitor

swab-and-surge effects.2 Their PWD (Pressure-

While-Drilling) service uses a quartz pressure

gauge capable of measuring up to 20,000 psi

[138 MPa], and is available in collar sizes from

314 to 912-in.

Today, Anadrill provides APWD Annular

Pressure While Drilling measurements both in

real time and recorded mode using an electro-

mechanical or bellows resistor device installed

on the side of the 150C-[300F]-rated CDR

Compensated Dual Resistivity tool and the

175C-rated VISION475 tool(right). The CDR

tool is available in 634-, 814- and 912-in. collar

sizes. These tools can measure several pressure

ranges, up to 20,000 psi, with an accuracy of

0.1% of the maximum rating and a resolution of

1 psi. They are also capable of continuous moni-

toring during no-flow conditions, which enables

real-time dynamic testing while mud pump

motors are shut downsuch as during leakoff

testing. Other parameters measured while

drilling, such as downhole torque and weighton bit, can be combined with APWD measure-

ments to evaluate hole-cleaning efficiency and

early detection of sticking, hanging or balling

stabilizers, to detect bit problems and cuttings

buildup, as well as to improve drilling and steer-

ing performance.

For operators trying to reduce drilling and

completion costs by downsizing from conven-

tional hole sizes, the Anadrill 434-in. VISION475tool enables simultaneous real-time APWD

measurements as well as drilling, directional

surveying and formation evaluation of boreholes

as slim as 534 in. (see Pushing

the Limits of Formation

Evaluation While

Drilling,page 29).

HPHT upgrades for

25,000 psi [172

MPa] and 350 F

[175 C] are avail-

able, and a new

system with APWD

capability for larger

boreholes, called

VISION675, will be

available soon.

For underbalanced operations, a coiled tubing

drilling system, the VIPER system, offers real-

time internal, annular and differential pressure

measurements. The use of a wired BHA such as

in the VIPER system can be used in standpipe

gas injection applications such as nitrified fluids

and foams. APWD measurements in such under-

balanced operations enable the driller to opti-

mize production by maintaining planned

downhole pressures selected to minimize or

eliminate invasion and formation damage.

Under these conditions, the rate of penetration

will also be improved.

How Downhole Annular Pressure is Monitored

>Annular pressure sensor. Resistor-based bellows

gauges (insert) are used for APWD measurements

in the CDR Compensated Dual Resistivity tool, and

are available in three pressure ranges to meet the

expected wellsite conditions. These tools are mud

pulse-operated, so no information is sent in real

time when the mud pumps are off. However, they

can record pressures when the pumps are off, and

once pumping is re-established, this information

can be sent to the surface. Master calibrations

are performed over a range of temperatures usinga dead-weight tester. At the location or wellsite,

hydraulic tests using a hand pump are performed

on these gauges before and after use in each well

to verify calibrations.

6.5 ft

Pressure port

Resistivity

Gamma ray

Annular pressure sensor

CDR tool

1. Hutchinson and Rezmer-Cooper, reference 5, main text.

2. Ward CD and Andreassen E: Pressure While DrillingData Improves Reservoir Drilling Performance, paperSPE/IADC 37588, presented at the SPE/IADC DrillingConference, Amsterdam, The Netherlands, March4-6, 1997.


4/16

Winter 1998 43

Pore pressureOne ongoing oilfield chal-

lenge is determining the pore pressure in shales,

and almost all pore pressure prediction is based

on correlation to other measured properties of

shales. Shales start their life at the surface as

clay-rich muds, and water is expelled from them

as they are buried and subjected to increasing

loading from the overburden above them. If the

burial is sufficiently slow, and there is an escape

route for the water, the pressure in the pore fluid

remains close to hydrostatic, and the overburden

is supported by increased stresses in the solid

parts of the rock. The water content, or porosity,

decreases, and this variation of porosity or other

water-dependent properties with depth is known

as the normal compaction trend.

However, if burial is very rapid, or the fluid

cannot escapebecause of the low permeability

of shalesthe increasing overburden load is sup-

ported by the increasing pore pressure of the fluid

itself. The stress in the solid parts of the rock

remains constant, and the water content, or

porosity, does not decrease. After rapid burial, theshale is not normally compacted; its pore pres-

sure is above hydrostatic, and its water content is

higher than it would be for normally-

compacted shale at that depth. The shale

becomes overpressured as a result of undercom-

paction. Detecting overpressured zones is a major

concern while drilling, because water or gas

influx can lead to a blowout.

Fracture gradientsFracture gradients are

determined from the overburden weight and lat-

eral stresses of the formation at depth and from

local rock properties. Density and sonic logging

data help provide estimates of rock strengths.3Calculating offshore fracture gradients in deep

water presents a special problem. The uppermost

formations are replaced by a layer of water,

which is obviously less dense than rock. In these

wells, the overburden stress is less than in a

comparable onshore well of similar depth. This

results in lower fracture gradients and, in gen-

eral, fracture gradients decrease with increased

water depth. Thus, increasing water depth

reduces the size of the margin between the

mud weight required to balance formation

pore pressures and that which will result in

formation breakdown.

Downhole Pressure

After the wellbore stability pressure window has

been determined, the driller has more to do than

keep the drilling fluid within these limits. To cor-

rectly interpret the response of a downhole annu-

lar pressure measurement, it is important to

appreciate the physical principles upon which it

depends. The downhole annular pressure has

two components. The first is a static pressure

due to the density gradients of the fluids in the

borehole annulusthe weight of the fluid verti-

cally above the pressure sensor. The density of

the mud column including solids (such as cut-

tings) is called the equivalent static density

(ESD), and the fluid densities are pressure- and

temperature-dependent.

Second is dynamic pressure related to pipe

velocity (swab, surge and drillpipe rotation),

inertial pressures from string acceleration or

deceleration when tripping, excess pressure to

break mud gels, and the cumulative pressure

losses required to move drilling fluids up the

annulus. Flow past constrictions, such as cuttingsbeds or swelling formations, changes in hole

geometry, and influxes or effluxes of liquids and

solids to or from the annulus all contribute to the

dynamic pressure. The equivalent circulating

density (ECD) is defined as the effective mud

weight at a given depth created by the tota

hydrostatic (including the cuttings pressure) and

dynamic pressures.

Understanding the different pressure

responses under varying drilling conditions also

requires an appreciation of the drilling fluids rhe

ological properties, including viscosity, yield and

gel strength, and dynamic flow behavior. Is the

flow laminar, transitional or turbulent? The varia

tion of the rheological properties with flow

regime, temperature and pressure singly, and in

combination, affects the total pressure measured

downhole.4 Some of these downhole parameters

such as flow rate, can be controlled by the driller

Others, such as downhole temperature, cannot.

Pressure Losses

Until recently, the industry had been divided on

the effects of drillpipe rotation on pressure

losses. Some researchers have explicitly stated

that rotation acts to increase axial pressure drop

while others have taken the opposing view, tha

an increase in rotation rate decreases annulapressure drop. In fact, both of these seemingly

conflicting views can be correct, and both effects

have been observed. Annular pressure losses o

axial pressure drop depend upon which part o

the flow regime predominates when the rotation

rate is changed (below).

Rotation rate

Flow

rate

Pressure increasing

Turbulent

Turbulent with vortices

Laminar

Laminar with vortices

> Flow regimes. In laminar flow the annular pressure losses decrease with increasing pipe rotation,because azimuthal stresses reduce the effective viscosity of the drilling fluid. Once the Taylor number(a condition for rotational flow instability) is exceeded, vortices will be formed, which extract energyfrom the mean axial flow, and yield a turbulent-like pressure drop. As the axial flow rate increases,full turbulence will occur and the axial pressure drop will then increase with increasing rotationalrate. Similarly, increases in the rotation rate can also assist in the transition from laminar to turbulentflow and can lead to an increase in the axial pressure drop.

3. Brie A, Endo T, Hoyle D, Codazzi D, Esmersoy C, Hsu K,Denoo S, Mueller MC, Plona T, Shenoy R and Sinha B:New Directions in Sonic Logging, Oilfield Review 10,no. 1 (Spring 1998): 40-55.

4. For a detailed discussion of static, dynamic and cuttingspressure contributions to the total downhole pressure:Adamson K, Birch G, Gao E, Hand S, Macdonald C, MackD and Quadri A: High-Pressure, High-TemperatureWell Construction, Oilfield Review10, no. 2 (Summer1998): 36-49.


5/16

44 Oilfield Review

Experiments performed with the 50-ft [15-m]

flow loop at Schlumberger Cambridge Research

(SCR), in England confirmed the complex effects

of rotation on annular pressure losses (left). At

low flow rates, the pressure drop decreases with

increasing rotation rate. At higher flow rates, the

opposite effect is observed. However, in nearly

all field examples, with typical drilling muds in

conventional borehole sizes, only the increase in

annular pressure loss with increased rotation

rates has been observed (middle left). This is an

area of ongoing research.

Hole Cleaning

Efficient hole cleaning is vitally important in the

drilling of directional and extended-reach wells,

and optimized hole cleaning remains one of the

major challenges. Although many factors affect

hole-cleaning ability, two important ones that the

driller can control are flow rate and drillpipe rota-

tion (bottom left).

Flow rateMud flow rate is the most impor-

tant parameter in determining effective holecleaning. For fluids in laminar flow, fluid velocity

alone cannot efficiently remove cuttings from a

deviated wellbore. Fluid velocity can disturb cut-

tings lying in the cuttings bed and push them up

into the main flow stream. However, if the fluid

has inadequate carrying capacityyield point,

viscosity and densitythen many of the cuttings

will fall back into the cuttings bed. Mechanical

agitation due to pipe rotation or back-reaming

can aid cleaning in such situations, but some-

times are inefficient or worsen the situation.

Agitation that is too vigorous, such as rotating

too fast with a bent housing in the motor,can have a detrimental effect on the life of down-

hole equipment.

Inadequate flow results in increased cuttings

concentrations in the annulus (next page, top). A

cuttings accumulation may lead to a decrease in

annular cross-sectional area, and hence an

increase in the ECDultimately leading to a

plugged annulus, called a packoff. The use of

real-time downhole annular pressure measure-

ments allows early identification of an increasing

ECD trend, caused by an increasing annular

restriction, and helps the driller avoid formation

breakdown resulting from high pressure surgesor a costly stuck-pipe event.

An example shows how APWD Annular

Pressure While Drilling measurements help

detect packoff.5 The log shows that the annulus

started to pack off at approximately 1:20 (next

page, middle). Drilling parameters, such as

increasing surface torque and variations in rota-

tion rates, were becoming erratic. Standpipe

pressure increased slightly. These warnings

2500

2000

1500

1000

500

0

0 50 100 150 200 250

Rotation, rpm

P

ressuregradient,Pa/m

300 350 400 450 500

Low flow

Medium flow

High flow

Experimental conditions

Hole size = 4.9 in.

Pipe outer diameter = 3.5 in.

Plastic viscosity = 3.4 cpYield point = 3.8 lbf/100 ft2

> Laboratory-measured annular pressure losses. Experimental comparisons of the effect of rotationon annular pressure losses with a clean drilling fluid (no solids) at low, medium and high flow rateshighlight the flow behavior in different flow regimes. These measurements confirm that under someconditions rotation acts to increase axial pressure losses, whereas under other conditions itdecreases the losses.

Equivalentcirculatingdensity,

sg

0 10 50 100 120 130

Rotation, rpm

600 gal/min

400 gal/min

200 gal/min

.

1.11

1.09

1.07

1.05

1.03

1.01

0.99

0.97

0.95

> Effect of rotation on equivalent circulating density (ECD). In addition to distinct effects on hole-cleaning efficiency, rotation also affects fluid behavior in an unloaded annulus. In this field experimentof drillpipe rotation (at different flow rates), the ECD increases from 1.092 sg to 1.114 sg as the rotationrate increases to 130 rpm with a 1.0 sg mud weight circulating at 600 gal/min [2300 L/min] in an 8-in.[20-cm] casing section. The increment of 0.022 sg is equivalent to 50 psi [350 kPa]. No cuttings werein suspension as this test was performed just prior to drilling.

Drillpipeeccentricity

Mudweight

Cuttingsdensity

Cuttingssize

Hole sizeand angle

Drillpiperotation

FlowrateMud

rheology

Rate ofpenetration

Hard to control Easy to control

Large

influence

on cuttings

transport

Little

influence

on cuttings

transport

Hole cleaning.Some factors areunder the controlof the driller, suchas surface mudrheology, rate of

penetration (ROP),flow rate and holeangle. Others,including drillpipeeccentricity, andcuttings densityand size, cannot becontrolled as easily.

>


6/16

Winter 1998 45

could have been interpreted as due to increasedmotor torque associated with an increase in sur-

face torque. However, the large ECD increase

confirmed that the mud flow was restricted

around the BHA just above the annular pressure

sensor. Based on the confirmation from APWD

measurements, the driller reduced the mud flow

rate and worked the pipe to prevent the ECD from

exceeding the fracture gradient.

Drillpipe rotationAnother example demon-strates the effect of pipe rotation on hole clean-

ing (above). At 15:00, pipe rotation was stopped

to enable drill-bit steering. The ECD decreased

for 20 minutes as the cuttings fell out of suspen-

sion. A few swab-and-surge spikes were

observed. These pressure spikes were introduced

as the pipe was moved up and down to adjust

mud motor orientation. After steering for a total

of 114-hours (at 16:15), rotary drilling wasresumed, and the ECD abruptly increased as the

cuttingsaccumulated during the sliding inter

valwere resuspended in the drilling fluid

Here, real-time APWD data helped determine the

minimum rate of rotation required to effectively

stir up cuttings and clean the wellbore.

Stat

ionary

Rol

ling

Asymmetricsuspension

Symmetricsuspension

Low flow rate High flow rate

LowE

CD

HighECDCuttings transport. The cuttings transport mode affects hole-cleaning

ability, especially in deviated wells. At low flow rates, the cuttings can fallout of suspension to the low side of the boreholebuilding a cuttings bedand increasing the ECD due to cuttings restriction in the annulus. As theflow rate is increased, the cuttings will start to roll along the wellbore erod-ing the cuttings bed. As the cuttings bed is partially eroded, the annular gapincreases and the ECD will start to decrease. As the flow rate increasesfurther, the majority of the cuttings are transported along the low side of thewellbore, with some suspended in the fluid flow above the bed (asymmetricsuspension) leading to an increase in ECD. At higher flow rates frictionalpressure losses are significant, and the cuttings are transported completelysuspended in the fast-moving fluid (symmetric suspension). [Adapted from

Grover GW and Aziz A: The Flow of Complex Mixtures in Pipes. Malabar, Florida,USA: Robert E. Krieger Publishing Company, Inc., 1987.]

ECD/ESD

1410

Temperature

C 200

lbm/gal

0Standpipe pressure

40000

Total pump flow

1000gal/min

psi

0Surface torque

300

Surface rotation

150rpm

kft-lbf

0

TimeMeasured depth

110000

Surface weight on bit

60klbf

ft

0

01:00

02:00

Packing off. The driller responds in real timeto an increase in the ECD (red curve), shownin track 4, as the annulus packs off above themeasurements-while-drilling (MWD) tool.Surface torque and rotation rates, shown intrack 2, start to become erratic as the drillpipebegins to pack off. Standpipe pressure, shownin track 3, increases slightly. By temporarilyreducing the mud flow (green curve), shown intrack 3, and working the pipe, the annulus

becomes clear again.

HookloadTime

Surface torque

kft-lbf

Surfacerotation

Blockspeed

ftDepth

Rotationstops

Slidinginterval

Rotationstarts

2000 rpm500010-10 14.213.2 lbm/gal

10000

gal/minft/s klbf

Totalpump flow

ECD / ESD

Standpipe pressure

Temperature

15:00

16:00

5000psi0

100C0Effect of drillpipe

rotation on holecleaning. The ECD (redcurve), shown in track6, increasesindicat-

ing cuttings are resus-pended in the drillingfluidat 16:15 asrotation recommencesafter a slide-drillinginterval is completed.

5. Hutchinson M and Rezmer-Cooper I: Using DownholePressure Measurements to Anticipate Drilling Problems,paper SPE 49114, accepted for presentation at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 27-30, 1998.

>

>

>


7/16

46 Oilfield Review

Improving Efficiency in

Extended-Reach Drilling

BP encountered severe wellbore instability prob-lems when drilling development wells in Mungo

field in the Eastern Trough Area Project (ETAP) of

the North Sea. These instability problems were

due in part to large cavings formed while drilling

the flanks of salt diapirs. Long S-shaped 1214-in.

[31-cm] sections are generally the most problem-

atic. The volume of cavingscoupled with highly

inclined wellbore trajectoriesresults in poor

hole-cleaning conditions. The main cause of the

poor hole cleaning is believed to be the formation

of cuttings and cavings beds on the highly

inclined 60 section. These beds are manageable

while drilling, but present a major hazard when

tripping and running in casing. Most of the early

wells experienced extreme overpulls, packing off

and stuck-pipe incidents when pulling out of thehole. In addition, severe mud losses had been

encountered when drilling inadvertently into the

chalk at total depth.

Based on this experience with borehole insta-

bility, BP revised its drilling program with a com-

bination of better fluid management and

hydraulics monitoring aimed at improving both

hole cleaning and drilling practices. The results

were impressive. In the first well in the second

phase of the Mungo development, nonproductive

time was reduced from 34%the average expe-

rienced on earlier wellsto 4%, with estimated

cost savings of over $500,000. Drilling rate per-formance increased 10%, while the incidence of

stuck pipe decreased.

The logs from this well exemplify how new

hole-cleaning practices, supported by APWD

monitoring, led to a successful drilling program(above). The pumps were switched on at 19:05,

and the flow rate increased to 1000 gal/min [3785

L/min]. The standpipe and the downhole annular

pressure responded almost instantaneously and

after a few minutes, the driller started rotating

the pipe. The increased downhole weight on bit

indicates that drilling commenced just before

19:10. The first part of the stand was rotary drilled

at approximately 100 rpm until 19:27. At this time,

the drillstring was raised to set the necessary

toolface for the next sliding period. Sliding

beganshown by zero surface rotation rateat

19:30 and continued until 19:45.

Blockposition

Drilling cycle 1

Drilling cycle 2

Pumps on

Pipereciprocating

m0 50

Hookload

klbf0 400

ROP

m/hr200 0

Bit depthvalue, m

Downholeweight on bit

klbf0 80

Surfaceweight on bit

klbf0 80

19:00Time

20:00

21:00

Downholetorque

kft-lbf0 20

Surface torque

kft-lbf20 60

Surfacerotation

rpm0 200

Total pumpflow

gal/min0 1500

Turbinerotation

rpm0 5000

Standpipe pressure

psi0 4000

Annulus pressure

psi0 4000

Annulus temperature

C0 200

ECD

sg1.65 1.75

Bit on bottom flag

Cuttingssettling out

Hole surged

Hole swabbed

Surge andswab

Pumps off

Rotary drilling

Slide drilling

Kelly down

> Downhole pressure monitoring to improve hole cleaning. Drilling fluid pumps start at 19:05, shown by pump flow rate in track 5. Pipe rotation starts a fewminutes later, seen by the increase in surface rotation rate shown in track 4. The instantaneous increase in standpipe pressure (green curve) and thedelayed downhole ECD (black curve) measurement can be seen in track 6. Rotary drilling stops and slide drilling starts at 19:27, shown by surface rotationrate (track 4) and weight on bit (track 2). The immediate effect of slide drilling on the downhole ECD (black curve) can be seen in track 6. After Kelly down,shown by the block position in track 1, the driller starts hole cleaning by reciprocating the pipe in and out. After the hole cleaning is completed, the drillermakes a new connection and starts the next drilling cycle at 20:30.


8/16

Winter 1998 47

As the stand was being drilled, the ECD log

showed the effects of rotating and sliding.

During rotary drilling, ECD values were approxi-

mately 1.70 sg. When the drillstring was picked

up to set the toolface for sliding, the hole was

swabbed and the ECD dropped slightly to 1.69 sg.

As the drillstring was lowered, the hole was

surged about the same amount, raising the ECD

to 1.71 sg. Once rotation stopped, the ECD again

fell to 1.68 sg and continued to fall, as the cut-

tings started to settle in the hole, due to the lack

of mechanical agitationreducing the cuttings

contribution to the ECD.

Even though drilling continued during sliding,

and cuttings were being produced at a steady

rate, the ECD did not increase. This demon-

strates that the hole was not being cleaned as

efficiently as it had been with rotary drilling.

This was confirmed by the lack of cuttings over

the shale shakers.

The last part of the stand was also rotary

drilled. Rotation resumed at 19:46, and the ECD

increased immediately and continued to show anincreasing trend. Increasing ECD was caused by

turbulence and axial flow in the mud column in

the annulus as it stirred cuttings that settled on

the bottom of borehole. The cuttings added to the

hydrostatic pressure and increased the ECD. At

19:54 the driller picked up the string and started

the hole-cleaning procedure.

The bell-shaped profile of the ECD curve dur-

ing rotary drilling was formed by the increasing

ECD due to the rotation and stirring of pre-exist-

ing cuttings beds as well as increased cuttings

load resulting from drilling ahead. The ECD

reached its peak value when the stand wasdrilled down. As the hole was cleaned by recip-

rocating the pipe (maintaining a constant mud

flow and rotary speed), the ECD decreased.

When the value returned to nearly 1.71 sg, the

hole was deemed to be sufficiently cleaned.

After pipe reciprocation and flow were stopped,

a survey was taken at 20:19. After completion of

this operation, a connection was made and

drilling resumed successfully at 20:30 with good

hole cleaning.

Another exampleusing APWD monitoring

to avoid stuck pipeshows how an indication of

cuttings accumulation during a drilling break cantake several hours to appear in the ECD log

because of the horizontal wellbore traveltime in

extremely long ERD wells. In BPs most recent

record-breaking horizontal well at Wytch Farm,

England, a cuttings cluster traveled along the

horizontal leg of the wellbore for almost five

hours after the drilling break at 12:00 before

reaching the vertical section of the well (above).6

Finally, at 4:40 the ECD readings started increas-

ingapproaching the fracture gradient of the

formation. The driller, anticipating potentially

severe well problems, decided to stop drilling

early, and clean out the cuttings accumulated in

the borehole by reciprocating the pipe. This is

another success story. Without advance noticefrom the APWD measurement, the drillstring

might have become stuck.

5:00

ECD

2000

3000

0

Block position0 50m

ROP100m/hr

Hookload0 500klbf

0 50Surface torque

kft-lbf

Standpipe pressure4000

Annulus pressure3000psi

1.2 1.3sgTotal pump flow

20000 gal/min

psi

12:00

Drilling

break

1:00

4:00

5:00 ECDincrease

Standpipepressureincrease

> Preventing packoff events. The ECD, shown in track 4, risesdue to cuttings accumulation enteringthe vertical section of an extended-reach wellabout five hours after a drilling break.

6. Allen F, Tooms P, Conran G and Lesso B: Extended-Reach Drilling: Breaking the 10-km Barrier, OilfieldReview9, no. 4 (Winter 1997): 32-47.


9/16

48 Oilfield Review

Kick Detection

The influx of another fluid into the wellbore due

to unexpected high formation pressure is one of

the most serious risks during drilling. The char-

acter of the fluid influx will depend primarily

upon influx fluid density, rate and volume,

drilling fluid properties and both borehole and

drillstring geometry (right). Simulations per-

formed by The Anadrill SideKick software model

are frequently used to understand the pressure

responses expected downhole and at the sur-

face due to gas influxes. (see Simulating Gas

Kicks, page 50).7 During gas kicks, ECD

responses for typical boreholes and slim well-

bore geometries are dominated by two phenom-

enareduced density of the mud column as

heavier drilling fluid is replaced by less dense

gas, and increased annular pressure loss due to

friction and inertia when accelerating the mud

column above the gas influx.

The reduced annular gap in slimhole wells

can cause unique drilling problems.8 For example,

in slim holes the acceleration of the kick fluidinto the wellbore can lead to a sudden increase

in frictional pressure loss in the annulus due to

acceleration of the mud ahead of the kick fluid. In

addition, evidence of the influx may not be seen

until the pumps are shut down. In typical hole

sizes, the hydrostatic imbalance between the

drillpipe and the annulus outweighs any frictional

losses, and a decrease in the bottomhole annular

pressure is evident.

Constant monitoring of all available drilling

data is critical in detecting a downhole kick

event. In an example of a gas kick, an operator

was drilling a 1214-in. hole section in a well inthe Eugene Island field in the Gulf of Mexico

(next page). The formations were sequences of

shales and target sands, and several of the

sands were likely to be depleted by previous

production. In offset wells, the low-pressure

sands led to problems including stuck pipe,

twist-offs and stuck logging tools.

Maintaining a minimum mud weight was

required to avoid differential sticking in the

depleted sands. Due to faulting in the area, zonal

communication was uncertain and the pore pres-

sure limits were difficult to anticipate. Anadrill

was using the CDR Compensated Dual Resistivitytool for formation resistivity and the Multiaxis

Vibrational Cartridge (MVC), Integrated Weight-

on-Bit (IWOB) tool and APWD sensors for moni-

toring drilling performance. The plan was to set a

liner below a normally pressured zone before

drilling into the underpressured sand beds.

Typical hole

4600

4800

5000

Slim hole

0

4

8

12

16

20

0

1000

2000

Shut-in Kill Shut-in Kill

Time, min

0

200

400

600

800

Time, min0 10 20 30 40 0 10 20 30 40

Friction pressure loss Pit gain Standpipe pressure Annulus pressure

Annularpressure,

psi

Pitgain,

bbl

Standpipepressure,

psi

Frictionpressureloss,

psi

> Kick detection. In a typical wellbore geometry (top left), the annular pressure (orange curve) can beseen to decrease as the displacement of heavier drilling fluids by a gas influx dominates the pressure

response. For slimhole geometry (top right)the annular pressure (orange curve) can increase initiallyduring a gas influx as the inertia of the mud column dominates the response. One major benefit ofdownhole annular pressure monitoring is early kick detection. Mud-pit gain (red curves in upper plots),standpipe pressure (green curves in lower plots), and frictional pressure loss (yellow curves in lowerplots) help the driller identify gas kicks.

1200 200 300

Block heightAnnulus

temperature

ft F 13 18

ECD

lbm/gal 3000 5000

Standpipepressure

psi

08:00

Time

Rack backstand of pipe

Temperature rises,ECD drops

Flow checkand close in

12:00

11:00

10:00

09:00

> Gas influx. When gas mixes with drilling fluid, the density of the drilling fluid decreases. Fifty minutesafter the ECD (blue curve), shown in track 3, started to decrease, a flow check confirmed that a smallgas influx had occurred. Note the increase in annular temperature, shown in track 2, as the formationfluid warmed the borehole.


10/16

Winter 1998 49

During drilling through a shale zone just

before 14:00, a few indications of increasing

formation pressure were seen in the APWD data

and several connection and background mud gas

indications were detected in the mud flow. Oil-

base mud weights during this run were

increased from 11.5 to 12.0 lbm/gal [1.38 to 1.44

g/cm3]. Just before the sand was entered at

17:10, the real-time ECD measured downhole

was 12.5 lbm/gal [1.50 g/cm3]. At this point, the

ROP abruptly increased and drilling was

stopped10 ft [3 m] into the sand zoneto

check for mud flow. Although the potential for a

kick was a concern, the fact that there was no

evidence of a kick or mud flow suggested that it

was safe to proceed.

As drilling progressed after 18:10, the ECD

measurement decreased slowly to 12.35 lbm/gal

[1.48 g/cm3] over a period of 90 minutes. Sud-

denly at 19:20, the ECD dropped to 12.0 lbm/gal

[1.44 g/cm3] while drilling the next 9 ft [2.7 m] of

the well. The drilling foreman noticed the large

drop in ECD readingssignaling an influx.Increased pit volumes were noticed at this time

and the well was immediately shut in at 19:50.

The kill took 24 hours with an additional 30 hours

to repair blowout preventer (BOP) damage.

At what point did the kick first become

apparent on the downhole ECD log? The first

ECD drop from 12.5 to 12.35 lbm/gal probably

could be attributed to the decrease in ROP. Such

changes were seen earlier in this well.

Statistical variations in ECD, due to drilling

noise, can be as high as 0.2 lbm/gal. On the

other hand, the systematic change from 12.35 to

12.0 lbm/gal is a clear signal that an influx isalready in the mud column. Monitoring the ECD

constantly, using alarms set to detect the first

sign of ECD changes, and checking corroborating

drilling indications, such as ROP, can provide ear-

lier warning of such occurrences.

In another example, use of APWD data helped

save a well. In this well, drilling was proceeding

without any indication of an influx either from pit

gain or in mud flow rates in or out of the well (pre-

vious page, bottom). However, the ECD started to

decrease at 11:00 and continued for 50 minutes.

At the same time, an increase in the annulus tem-

perature was observed, due to the formation fluidwarming the borehole fluid. Guided by the ECD

response, the driller stopped drilling and safely

circulated out a small gas influx.

14:00

15:00

16:00

17:00

18:00

19:00

20:00

21:00

Block speed

ft/s-2 2

ROP

ft/hr

Bit depth

500 0

ft0 100


klbf0 60

Downhole weight on bit

klbf0 60

Surface torque

kft-lbf0 25

Bit on bottom flag

Downhole torque

kft-lbf0 8

Totalpumpflow

gal/min0 1500

CDR annulus pressure

psi0 10000

ECD

lbm/gal9 11

Annulus temperature

F100 300

Standpipe pressure

psi0 5000

Time

Axial vibration

G4 0

Torsional vibration

ft-lbf4000 0

> Kick alert in the Gulf of Mexico. A sudden increase in the rate of penetration (ROP) (blue curve),shown in track 1, at 17:10 alerted the driller that the bit had entered a sand zone and that an influxwas possible. Drilling restarted after having seen no evidence of flow in the mud-flow measurementsor pit volume. However, as drilling progressed into the sand zone, the ECD (pink curve), shown intrack 5, started to decrease slowly at 18:10 and continued until 19:20. At this time, the rate of decreasesuddenly increased. After drilling ahead for 30 minutes with rapidly decreasing ECD and increasingpit volume, the driller recognized that an influx had occurred and the well was shut in.

7. MacAndrew R, Parry N, Prieur J-M, Wiggelman J,Diggins E, Guicheney P, Cameron D and Stewart A:Drilling and Testing Hot, High-Pressure Wells, OilfieldReview5, no. 2/3 (April/July 1993): 15-32.

8. In this article, slimhole wells are defined as those with anaverage pipe-to-annular radius ratio greater than 0.8.


11/16

50 Oilfield Review

The growth in deep-water drilling activities in

many regions of the world is attracting

increased attention to the specific problems ofgas influx and well control. Deep water poses

special problems related to both the depth and

temperature of the water. Reduced margins

between pore pressure and fracture gradient

require accurate understanding of downhole

fluid behavior.

Various definitions of kick tolerance exist and

may be given in terms of pit gain, mud weight

increase or even underbalance pressure. What-

ever way it is expressed, kick tolerance is a

measure of the size and pressure of kick the well

can take and still be controlled without fractur-

ing the formation. Kick tolerance decreases as

drilling proceeds deeper, and once the limit is

reached, additional casing must be set to protect

the formation. Kick tolerance is a complex con-

cept as it varies as a function of the formation

pressure driving the kick, the amount of influx

entering the well and the distribution of the

influx in the annulus. Balancing this complexity

makes a simulator an ideal choice for computing

kick tolerance.

Scientists at BP and Schlumberger Cambridge

Research, England have spent years studying the

behavior of gas kicks.1

Their work, along withengineering development at the Schlumberger

Sugar Land Product Center in Texas, has pro-

duced the Anadrill SideKick-PC software model,

which simulates gas kicks and helps plan meth-

ods of detecting and controlling them. SideKick-

PC models include the effects of gas distribution

in the annulus. This produces a more realistic

and less conservative kick tolerance, which

leads to the use of fewer casing strings and sub-

stantial cost savings. Kick tolerance is illus-

trated in user-friendly, automatically generated

plots of safe pit gain versus safe formation pres-

sure(below). The simulator helps engineersanticipate and meet the challenges of a wide

variety of drilling environments.

The simulator can be used in planning under-

balanced drilling programs, which require esti-

mates of wellbore pressures and fluid produc-

tion rates. In addition, the cost-effectiveness of

using the underbalanced methods must also be

evaluated. Other simulators have helped address

Simulating Gas Kicks

1000

900

800

700

600

500

400

Shut-

in

drillpipe

pressure,

psi

0 10 20 30 40

Pit gain, bbl

StaticCirculating

Safe

Unsafe

> SideKick-PC kick tolerance. The SideKick-PC program computes separate kick tolerances for the shut-in

and kill periods of a simulation. The kick tolerance plot is used to differentiate kicks that can be safely

shut in (static) from those that can be safely killed (circulating). The determination depends on many

factors such as pressures in the well, gas migration, circulating friction and kill-mud hydrostatic pressure.

Kicks in the region to the left and below each curve are considered safe, and those severe enough to be in

the region above and to the right of each curve may cause lost circulation.

these issues, but have looked only at stabilized

steady-state conditions. This simulator is a fully

transient numerical simulator that can deter-mine the optimum amount of nitrogen necessary

to reach a desired underbalance.2

The SideKick-PC program also introduces

the concept of the Maximum Allowable Blowout

Preventer Pressure (MABOPP).3 This gives an

improved indication of the potential for shoe

fracture during a kill using a BOP pressure

measurement to remove uncertainties involved

in fluid properties in long choke and kill lines.

Simulations have shown that a simple tech-

nique can minimize the risk at the end of a

deep-water kill by slowing the pumps when the

choke is wide open to minimize pressure in theannulus. This technique has been shown to be

preferable to other methods, such as using a

reduced slow-circulation rate over the whole kill

or arbitrarily reducing the flow rate, and is now

an integral feature of the simulator.

The SideKick-PC program has proved effective

in allowing engineers to run many complex sim-

ulations easily and quickly. Coupled with defin-

ing safe operating envelopes in minutes rather

than hours or days of well planning, gas-kick

simulation is helping to enhance overall per-

formance by improving efficiency and reducing

well construction costs.

1. Rezmer-Cooper IM, James J, Davies DH, Fitzgerald P,Johnson AB, Frigaard IA, Cooper S, Luo Y and Bern P:"Complex Well Control Events Accurately Represented byan Advanced Kick Simulator," paper SPE 36829, pre-sented at the SPE European Petroleum Conference, Milan,Italy, October 22-24, 1996.

2. A fully transient simulator is one that allows for thetemporal development of fluid behavior in the borehole asthe fluids are circulated, or while the well is shut in. Thishas the advantage over steady-state models, where theimposed state does not change fluid propertiesover time, and cannot allow for effects such as gassolubility as the gas cloud migrates after circulation hasstopped. Furthermore, such a transient simulator canindicate whether steady state can even be reached.

3. James JP, Rezmer-Cooper IM, and Srskr SK: MABOPP

New Diagnostics and Procedures for Deep Water WellControl, paper SPE 52765, submitted for presentation atthe 1999 SPE/IADC Drilling Conference, Amsterdam, TheNetherlands, March 9-11, 1999


12/16

Winter 1998 5

Deep-Water Wells

Unconsolidated sediments typically encoun-

tered in deep-water formations tighten the

wellbore stability window between pore pres-

sure and formation fracture pressure. At a given

depth, fracture gradient decreases with increas-

ing water depth, and can result in a very narrow

pressure margin.9

Additionally, cooling of the mud in the deep-

water riser can cause higher mud viscosity,

increased gel strength, and high frictional

pressure losses in choke and kill lines during

well-control procedures. Combined, these fac-

tors increase the likelihood of lost-circulation

problems, and drilling engineers must take

appropriate steps to avoid exceeding formation

fracture gradients.

Staying within the pressure window

Keeping the ECD within the pressure window is

a constant struggle, especially in deep water and

HPHT applications. In a well in the Gulf of

Mexico, EEX Corporation experienced a kick

while drilling at near-balance conditions in ZoneA (right). After the kick was taken and the well

was under control, increased mud weight was

needed to continue safely. A 13 38-in. [34-cm] cas-

ing string was set because the heavier mud

weight exceeded the previous leakoff test.

The next two hole sections were drilled

without incident. However, as drilling pro-

ceeded deeper into the third section, the

increasing pore pressure eventually approached

the pressure exerted by the heavier mud and

another kick was experienced in Zone B. A

958-in. [24-cm] casing was needed to permit

another increase in mud weight. As drilling con-tinued, increases in the cuttings load caused the

mud pressure to exceed the overburden pres-

sure in Zone C, resulting in some lost circulation

over a period of several days. Lost-circulation

material helped minimize mud losses, and

drilling continued successfully thereafter. At the

narrowest point shown in this example, the

pressure window was only 700 psi [4827 kPa].

Dynamic kill procedureReal-time analysis

of downhole annular pressure helped BP

Exploration monitor a dynamic kill procedure

used to stop an underground flow in a deep-

water well in the Gulf of Mexico. Drilling unex-pectedly entered a high-pressure zone, where a

water influx fractured the formation at the casing

shoe. Real-time APWD measurements were

combined with standpipe pressure to monitor the

process of the dynamic kill.

The procedure circulated kill-weight mud fast

enough to outrun the influx and obtain a suffi-

cient hydrostatic gradient to kill the well. Drilling

fluid used in this well weighed 11.8 lbm/gal

[1.41 g/cm3], and the kill-weight mud was

17.0 lbm/gal [2.04 g/cm3]. During the kill

procedure, BPs Ocean America operating crew

monitored the standpipe pressure to determine if

Zone A

Zone B

Zone C

20

Casing, in.

16

133/8

113/4

95/8

Overburden gradient, lbm/gal

Resistivity pore pressure estimate, lbm/gal

ECD, lbm/gal

Seismic pore pressure estimate, lbm/gal

10.00 17.00

17.00

17.00

17.00

10.00

10.00

10.00

Kick

Kick

75/8

> Staying within the pressure window. A gas kick was observed in Zone A, where the ECD (blue curve)dropped significantly below the pore pressure gradientestimated from resistivity logs (red curve) orseismic time-to-depth conversions (black curve). The well was brought under control with an increasein mud weightshown by the increased ECD. However, a second kick was experienced in Zone Bas pore pressure again increased above the ECD in this deeper section of the well. After anotherincrease in mud weight, some mud losses were experienced in Zone C, where the ECD increasedslightly above the overburden gradient (purple curve).

9. Brandt W, Dang AS, Mange E, Crowley D, Houston K,Rennie A, Hodder M, Stringer R, Juiniti R, Ohara Sand Rushton S: Deepening the Search for OffshoreHydrocarbons, Oilfield Review10, no. 1 (Spring1998): 2-21.


13/16


14/16

Winter 1998 53

In many deep-water wells, the first casing

or conductor pipe is usually 30 or 36 in. [76 or

91 cm] in diameter. The next hole section, typi-

cally 24 or 26 in. [61 or 66 cm], is often drilled

without a riser. In these wells, spent drilling fluid

and cuttings are returned to the ocean floor

around the wellhead (previous page, top). Since

the drilling fluid is not recovered under these

conditions, expensive synthetic- or oil-base muds

typically are not used. Instead, either seawater

or inexpensive water-base mud is used.

Standard operating practices in deep-water

wells use a remote operating vehicle with a cam-

era at the mud line to monitor flow coming out of

the wellhead. At a connection, the driller will

hold the drillpipe stationary and turn off the

pumps for a few minutes, to allow fluid u-tubing

oscillations to stabilize, and to observe whether

there is flow at the wellhead.

Downhole pressure measurements detect

shallow-water flowMonitoring ECD helps the

operator assess both the depth and severity of

the water flow, and decide whether the flow isserious enough to stop drilling. Most conven-

tional hydraulics models do not consider the

effects of mud returns to the seafloor, and thus

cannot accurately predict the expected ECD in

these wells. A direct measurement of downhole

mud pressure solves this problem.

Operators are starting to use downhole pres-

sure measurements as a way to detect the onset

of and prevent serious damage from shallow-

water flows.12 In a deep-water well in the Gulf of

Mexico, a water sand in Zone A was encountered

at X090 ft (right). The ECD suddenly increased in

this zone as the sand was penetratedindicat-ing water and possible solids entry. The rise in

annular pressure and an ensuing visual confirma-

tion of the mudline flow confirmed water entry.

The flow was controlled by increasing mud

weight and drilling proceeded. The same

trendsincreased ECD with a corresponding

annular temperature increasewere seen in the

lower section of the next sand, Zone B, and in the

sand in Zone D below. The influxes were not

severe and were safely contained by the increas-

ing ECD of the drilling fluid. Knowledge of the

location and severity of the contained water

influxes and quick response to early warningfrom annular pressure measurements made it

possible to continue drilling successfully to the

planned depth for this hole section.

Improving Drilling Efficiency

With higher rig costs on many drilling projects,

such as extended-reach and deep-water wells,

time savings and precise measurements are

critical. Accurate leakoff tests (LOT) are essential

to enable efficient management of the ECD

within the pressure window, and the correspon-

ding mud program.

Leakoff TestingA LOT is usually performed

at the beginning of each well section, after the

casing has been cemented, to test both the

integrity of the cement seal, and to determine

the fracture gradient below the casing shoe. Ingeneral, these tests are conducted by closing in

the well at the surface or subsurface with the

BOP after drilling out the casing shoe, and

slowly pumping drilling fluid into the wellbore at

a constant rate (typically 0.3 to 0.5 bbl/min [0.8

to 1.3 L/sec]), causing the pressure in the entire

hydraulic system to increase. Downhole pres-

sure buildup is traditionally estimated from

standpipe pressure, but can be monitored

directly with APWD sensors. If pressure meas

urements are made in the standpipe, then com-

plex corrections must be made for the effects o

temperature on mud density, and other factors

on downhole fluid pressure.13

Pressures are recorded against the mud vol

umes pumped until a deviation from a linea

trend is observedindicating that the well is

taking mud. This could be due either to failure o

the cement seal or initiation of a fracture. The

point at which the nonlinear response first occurs

Depthm

Attenuation resistivityGamma ray

0

A

150 0 10 8 9

500 0 0 10 2000 3000

0 2 50 100Phase-shift resistivity

ohm-m

Phase-shift resistivityohm-m

ECD

Annulus pressurepsi

Annulus temperature

FRate of penetration

ft/hr

lbm/galohm-mAPI

C

D

B-upper

B-lower

Water influx

Water influx

Water influ

X000

X100

X200

X300

X400

X500

X600

X700

X800

X900

> Shallow water flow in a deep-water well. Sand zones at A, B, C and D are indicated by decreasinggamma ray (pink curve), shown in track 1, and resistivity responses shown in track 2. Increasingannular pressure (green curve) and ECD (blue curve), shown in track 3, indicate that a water influxoccurred in three of these sands.

11. Smith M: Shallow Waterflow Physical Analysis, pre-sented at the IADC Shallow Water Flow Conference,Houston, Texas, USA, June 24-25, 1998.

12. APWD measurements are just one of the aids to mini-mize the hazards of shallow water flow. For additionalinformation: Alberty MW, Hafle ME, Minge JC and ByrdTM: Mechanisms of Shallow Waterflows and DrillingPractices for Intervention, paper 8301, presented at the1997 Offshore Technology Conference, Houston, Texas,USA, May 5-8, 1997.

13. Adamson et al, 1998, reference 4.

10. The Department of Interior Minerals ManagementServices manages the mineral resources of the OuterContinental Shelf and collects, verifies and distributesmineral revenues from Federal and Native Americanlands. They can be located at URL:http://www.mmm.gov/.


15/16

54 Oilfield Review

is the leakoff test pressure used to compute the

formation fracture gradient. Sometimes, the pro-

cedure is to stop increasing the pressure before

the actual leakoff pressure is reached. In such

cases, the planned hole section requires a lower

maximum mud weight than the expected fracture

pressure, and the test pressures only up to this

lower value with no evidence of fracture initia-

tion. This is called a formation integrity test (FIT).

If pumping continues beyond the fracture initia-

tion point, the formation may rupture, pressure

will fall, and the fracture will propagate.

APWD measurements helped monitor down-

hole pressure in a leakoff test performed by BP

Exploration in a deep-water well in the Gulf of

Mexico (below). As the pumped volume

increased to 3.5 barrels, the standpipe pressure

increased to 520 psi [3585 kPa]. Downhole ECD

increased from 9.8 lbm/gal (hydrostatic) to

10.9 lbm/gal [1.17 g/cm3 to 1.31 g/cm3]. At

this point, the pumping stopped, and the

ECD dropped exponentially to 10.7 lbm/gal

[1.28 g/cm3], indicating that the formation was

taking fluid. The pressure margin determined

from this test was sufficiently high to allow

drilling to proceed without incident.

Before a well is pressure tested, in order to

estimate downhole pressures from surface

measurements, the drilling fluid is often circu-

lated to ensure that a homogeneous column of

known density mud is between the surface and

casing shoe. However, the downhole annular

pressure measured at the casing shoe provides a

direct measurement, and therefore the mud con-

ditioning process is not requiredsaving the

cost of additional circulations. Downhole pres-

sure measurements remove uncertainties caused

by anomalies in mud gel strength or inhomo-

geneities in the mud column density due to pres-

sure and temperature effects.

Technologies from Schlumberger Wireline &

Testing, Anadrill and Dowell were combined to

perform a real-time downhole formation integrity

test in a deep-water well in the Gulf of Mexico.

During this test, an Anadrill CDR tool was

included in the BHA used to drill the casing shoe.

The CDR tool contained an APWD sensor to mon-

itor downhole pressure. In typical logging-while-

drilling (LWD) applications, sufficient mud is

pumped to enable the BHA to communicate to

the surface through mud-pulse telemetry. This is

not the case with slow pumping rates used dur-

ing a typical LOT or FIT. However, downhole pres-

sure can be monitored in real time through the

use of a wireline-operated LINC LWD Inductive

Coupling tool that sits inside the CDR tool and

transmits pressure data to the surface.

With this arrangement, the operator can

simultaneously view the surface and downholepressure buildup as the test proceeds. In the

absence of compressibility and thermal effects,

the rate of pressure rise downhole would be the

same as that at the surface. The operator can use

downhole pressure measured with the APWD

sensor to calibrate formation integrity while using

the pressure buildup differences to monitor the

compressibility of the drilling fluid. Because of

shallow water flow concerns in deep-water wells

with narrow wellbore stability margins, differ-

ences of a few tenths of a lbm/gal can make the

difference between one or two extra strings of

casing being needed to protect shallow intervals.Real-time downhole annular pressure meas-

urements offer at least three advantages during

LOT and FIT testing. First, the operator does not

want to overpressure downhole too farleading

to formation fractures or a damaged casing shoe.

A change in the slope of the pressure buildup

curve with pumped volume is a signal to stop the

test. This is the pressure used to determine the

fracture gradient of the formation. The use of

real-time annular pressure measurements pro-

vides the operator with an instantaneous signal

to stop the test.

Bit depth

ft0 100

Block speed

ft/s2 2

Hookload

klbf0 500

Surface torque

kft-lbf10 30

Annulus pressurepsi0 10000

ECD

lbm/gal9 12


klbf0 80Total pump

flow

0 1500gal/min

14:00Time

Surfacerotation

rpm

16:00

15:00

600

500

400

300

200

100

011 2 3 2 3 4 5 6 7 8 9 10

Volume, bbl Time, min

Surface

pressure,

psi

Pumping-upphase

Leakoffphase

Formation takingdrilling fluid

Leakoff test

80

165

260

350

430

480

520

460445

435430

420415 410 408 405 400

A

B

> Leakoff testing. A leakoff test was conducted in a deep-water well in the Gulf of Mexico. Duringthe pumping-up phase, the standpipe pressure increases linearly as the pump volume increases(top). At point A, the formation fractures and starts to take on some of the drilling mud. After thepumping stops at point B, the standpipe pressure decreases rapidly at first, then more slowly as theformation fractures close. The ECD log (bottom) from the APWD measurements, shown in track 6,increases from the hydrostatic pressure to 10.9 lbm/gal [1.31 g/cm3] during the pump-up phase. Afterpumping stops, the pressure starts to fall, and the ECD drops back.

14. Hutchinson and Rezmer-Cooper, reference 5.

15. Rojas JC, Bern P and Chambers B: Pressure WhileDrilling, Application, Interpretation and Learning, BPInternal Report, December 1997.


16/16

Next, monitoring surface pressure alone can

lead to incorrect estimates of bottomhole pres-

sure because of uncertainty in correcting for

the compressibility of the drilling fluid, particu-

larly significant when synthetic- or oil-base

muds are involved.

Finally, the unsteady nature of surface pres-

sure data can lead to errors in LOT estimates of

fracture gradient. An accurate measurement of

fracture gradient is required to determine the

ability of the formation and casing cement to

support the drilling fluid pressure during the

next section of drilling. The use of stable and

accurate downhole annular pressure measure-

ments helps makes drilling ahead a more exact

and safer process.

The Big Picture

In wireline logging, the log represents a state of

the wellshowing the more-or-less static for-

mation properties, such as lithological beds and

fluid saturations. Getting the data is most impor-

tant, but decisions made at the time of acquisi-

tion are not necessarily critical. However, logs of

downhole annular pressure and other drilling

performance parameters show a process

a process that is evolving with time. The evolu-

tion of the log in real time must be monitored as

downhole conditions are dynamic, and timely

decisions are essential. Delay or indecision can

lead to serious risks and added costs.

The format of drilling performance logs is dif-

ferent from wireline logs. Drilling problems gen-

erally result in slower rates of penetration and

data are compressed on a depth scale

Therefore, a time-based presentation is often

better suited for detailed analysis during prob

lematic drilling intervals. Still, depth-based pre

sentations are important for assessment o

drilling events in the context of BHA position rel

ative to lithological boundaries.

Drilling parameters should be presented in

relation to one another on the log. Wireline logs

such as the triple-combo used for formation eval

uation, have a standard layout that helps ana

lysts learn how to quickly spot the importan

productive zones. A standard layout for drilling

performance logs has recently been proposed

(previous page).14

The proposed layout enters geometric param

eters such as bit depth, ROP, and block speed in

track 1, followed by weight parameters such as

hookload and downhole weight-on-bit in track 2

Time or true vertical depth (TVD) are shown in the

next column. Next, torque parameters in track 3

rotation rates along with lateral shock and motostall in track 4, and flow parameters such as mud

flow rates, differential flow, total gas, mud pi

level and turbine rotation rate in track 5. Finally

pressure measurements such as ECD, ESD, annu

lar pressure, annular temperature, swab-and

surge pressures, estimated pore and fracture

pressure limits and standpipe pressure are al

shown in track 6.

Downhole annular pressure interpretation is

an evolving technique. All possible downhole

events have not yet been observed. Sometimes

the data are enigmatic. Nonetheless, certain

clearly identifiable and repeatable signaturescan be used to help diagnose problems (left)

Combining the information gleaned from down

hole annular pressure logs with other drilling

parameters creates an overall assessment, or the

big picture. This global view helps decipher the

individual measurements used to detect drilling

problems downhole.

Downhole real-time annular pressure meas

urements have a significant impact on todays

drilling practices with applications in every

aspect of drilling. For example, many of the les

sons and efficiency improvements made in high

cost ERD and deep-water wells can be applied tosimpler wells. Monitoring downhole annula

pressure along with other drilling parameters

provides an integrated view of a healthy drilling

environmentone that puts emphasis on antici

pation and prevention rather than reaction and

cure.15 Such improved operational procedure

will lead to decreases in nonproductive time and

increases in drilling efficiency. RCH

Event or procedure ECD change Other indications Comments

Mud gelation /pump startup

Sudden increasepossible

Increase in pump pressure Avoid surge by slowpumps and break rotation(rotation first)

Cuttings pick-up Increase then levelingas steady-state

reached

Cuttings at surface Increase may be morenoticeable with rotation

Plugging below sensor Sudden increase aspackoff passes sensor none if packoff remainsbelow sensor

High overpulls Steady increase in standpipe pressure

Monitor both standpipepressure and ECD

Plugging annulus Intermittent surgeincreases

Standpipe pressure Surge increase? Torque/RPM fluctuations High overpulls

Packoff mayblow-throughbefore formationbreakdown

Cuttings bed formation Gradual increase Total cuttings expected not seen at surface Increased torque ROP decreases

If near plugging, may getpressure surge spikes

Gas migration Shut-in surface pressuresincrease linearly (approx.)

Take care if estimatinggas migration rate

Running in hole Increase magnitudedependent on gap,rheology, speed, etc.

Monitor trip tank Effect enhanced ifnozzles plugged

Barite sag Decrease in staticmud density orunexplained densityfluctuations

High torque andoverpulls

While sliding periodicallyor rotating wiper trip tostir up deposited beds,use correct mud rheology

Gas influx Decreases intypical size hole

Increases in pit leveland differential pressure

Initial increase inpit gain may be masked

Liquid influx Decreases if lighterthan drilling fluid

Increases if influxaccompanied by solids

Look for flow at mudlineif relevant

Plan response if shallowwater flow expected

Pulling out of hole Decrease magnitudedependent on gap,rheology, speed, etc.

Monitor trip tank Effect enhanced ifnozzles plugged

Making a connect ion Decrease to stat icmud density

Pumps on/offindicatorPump flow rate lag

Watch for significantchanges in static muddensity

Increase if well isshut-in

> Interpretation guide. Monitoring ECD with downhole annular pressure measurements along withother drilling parameters helps the operator know what is happening downhole in the wellbore. Someof the known, clearly identifiable, and repeatable signatures of ECD changes are shown along withsecondary or confirming indications, such as those seen in surface measurements.

Documents

Annular Pressure Measurements.pdf