40 Oilfield Review

Using Downhole Annular Pressure Measurementsto Improve Drilling Performance

Walt AldredJohn CookCambridge, England

Peter BernBP Exploration Operating Company Ltd.Sunbury on Thames, England

Bill CarpenterMark HutchinsonJohn Lovell Iain Rezmer-Cooper Sugar Land, Texas, USA

Pearl Chu LederHouston, 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 and Dave 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 today’s low-price oiland gas market, operating companies are con-tinually challenged to lower their finding andproducing costs. To tap the full potential of exist-ing reservoirs and make marginal fields moreproductive, many wellbores are becoming bothlonger and more complex. However, keepingcosts low requires operating companies toimprove drilling efficiency. The rig floor is some-times like a hospital surgical theater. Instead offinding physicians and nurses, one finds drillers,

engineers and other crew members workingwith one objective: to keep their patient, theborehole, alive and healthy. Just as biologicalvital signs, like blood pressure and heart rate,are monitored during an operation, so the lifesigns of the borehole construction process—downhole pressure and mud flow rates—aremonitored during drilling.

The measurements described in this articleare the “sight and touch” of the driller, enablinghim to “see and feel” the dynamic motions of the

The pressure window. In some wells, especially deviated and extended reach, themargins (right) between pore pressure (redcurve) and fracture gradient (yellow curve) may be small—500 psi [3447 kPa] or less—and 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 of well deviation angle on the pressure window(below) shows that managing the mud weight in extended-reach wells is made more difficult by annular pressure losseswhich are inherently high for wells with longhorizontal sections.

Winter 1998 41

drillstring, and the downhole behavior of thedrilling fluid, so that optimal decisions can bemade. Vibration and shock data along withtorque and weight on bit can be used to modifydrilling parameters for increased bit and bottom-hole assembly (BHA) reliability and performance.The lifeblood of the drilling process is the drillingfluid, and downhole mud pressure—measured inthe annulus between the drill collar and the bore-hole wall—is one of the most important piecesof information that the driller has available tosense what is happening as the drill bit enterseach new section of formation, or during runningthe bit into or out of the hole.

Monitoring downhole annular pressure is beingused in many drilling applications, includingunderbalanced, extended-reach, high-pressure,high-temperature (HPHT) and deep-water wells.1

Such measurements are provided by a number ofservice companies, and operators have beenusing them for a wide variety of applicationsincluding 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 AnnularPressure is Monitored,” page 42).2

In underbalanced directional drilling, the useof downhole annular pressure sensors keeps theoperation within safe pressure limits and moni-tors the use of injected gas, which results inmore efficient, lower cost drilling. In extended-reach drilling (ERD), annular pressure measure-ments can be used to detect poor hole cleaningand help the operator modify fluid propertiesand drilling practices to optimize hole cleaning.In conjunction with other drilling parameters,real-time annular pressure measurementsimprove rig safety by helping avoid potentiallydangerous well-control problems—detectinggas and water influxes. These measurementsare often used for early detection of sticking,hanging or balling stabilizers, bit problem detec-tion, detection of cuttings buildup and improvedsteering performance. While real-time pressuredata are of significant value, the informationfrom these measurements is also useful in plan-ning the next well.

This article examines the physical processesassociated with downhole hydraulic systemsand the use of annular pressure in monitoringthe downhole drilling environment. We will lookat field examples that show the dynamics ofcommon drilling problems and demonstrate howa basic understanding of hydrodynamicprocesses—together with a knowledge ofdrilling parameters—can help provide advancewarning of undesirable and preventable events.

The examples illustrate three important drillingapplications in which downhole pressure meas-urements are valuable: • Extended-reach wells, where efficient hole

cleaning and cuttings transport are essential inpreventing stuck tools and packoff events,which may damage formations and lead toexpensive fluid loss.

• Deep-water wells, where there is a narrowpressure window between pore pressure and formation fracture pressure, and both fluid influx detection and wellbore stability are critical.

• Improved drilling efficiencies, with downholeannular pressure measurements providingaccurate LOT and FIT pressures, and a morerealistic determination of formation stress.

Wellbore Stability Successful drilling requires that the drilling fluidpressure stay within a tight mud-weight windowdefined by the pressure limits for wellbore sta-bility. The lower pressure limit is either the porepressure in the formation or the limit for avoidingwellbore collapse (above). Normal burial trendslead to hydrostatically pressured formations,where the pore pressure is equal to that of awater column of equal depth. If the drilling fluidpressure 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 surfaceor underground.

The upper pressure limit for the drilling fluidis the minimum that will fracture the formation. Ifthe drilling fluid exceeds this pressure, there is arisk of creating or opening fractures—resultingin lost circulation and a damaged formation. Inthe language of drilling engineers, pressures areoften expressed as pressure gradients or equiva-lent fluid densities. The upper limit of the pres-sure window is usually called the formationfracture gradient, and the lower limit is called thepore pressure, or collapse, gradient.

Mud

wei

ght,

sg

Collapsegradient

0.00 20 40

Well deviation, degrees60 80

0.4

0.8

1.2

1.6

2.0

2.4Fracturegradient

Stable

Dept

h

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.

42 Oilfield Review

The history of annular pressure measurementsextends as far back as the mid 1980s whenGearhart Industries, Inc. provided annular pres-sure sensors on their measurements-while-drilling (MWD) tools. Since then, Anadrill andother service companies have developed sensorsfor downhole annular pressure measurementswhile drilling.1 The first application of thesemeasurements has been primarily for drillingand mud performance, kick detection and equiv-alent circulating density (ECD) monitoring.Adding internal pressure sensors, combinedwith annular pressure measurements, enablesdifferential pressure to be determined, whichcan be used to monitor motor torque and powerperformance.

Sperry-Sun was an early proponent of record-ing ECD measurements during connections, andwhile pulling out and running in hole to monitorswab-and-surge effects.2 Their PWD (Pressure-While-Drilling) service uses a quartz pressuregauge capable of measuring up to 20,000 psi[138 MPa], and is available in collar sizes from31⁄4 to 91⁄2-in.

Today, Anadrill provides APWD AnnularPressure While Drilling measurements both inreal time and recorded mode using an electro-mechanical or bellows resistor device installedon the side of the 150°C-[300°F]-rated CDRCompensated Dual Resistivity tool and the175°C-rated VISION475 tool (right). The CDRtool is available in 63⁄4-, 81⁄4- and 91⁄2-in. collarsizes. These tools can measure several pressureranges, up to 20,000 psi, with an accuracy of0.1% of the maximum rating and a resolution of1 psi. They are also capable of continuous moni-toring during no-flow conditions, which enablesreal-time dynamic testing while mud pumpmotors are shut down—such as during leakofftesting. Other parameters measured whiledrilling, such as downhole torque and weight on bit, can be combined with APWD measure-ments to evaluate hole-cleaning efficiency andearly detection of sticking, hanging or ballingstabilizers, to detect bit problems and cuttingsbuildup, as well as to improve drilling and steer-ing performance.

For operators trying to reduce drilling andcompletion costs by downsizing from conven-tional hole sizes, the Anadrill 43⁄4-in. VISION475tool enables simultaneous real-time APWDmeasurements as well as drilling, directionalsurveying and formation evaluation of boreholesas slim as 53⁄4 in. (see “Pushingthe Limits of FormationEvaluation WhileDrilling,” page 29).HPHT upgrades for25,000 psi [172MPa] and 350 °F[175 °C] are avail-able, and a newsystem with APWDcapability for largerboreholes, calledVISION675, will be available soon.

For underbalanced operations, a coiled tubingdrilling system, the VIPER system, offers real-time internal, annular and differential pressuremeasurements. The use of a wired BHA such asin the VIPER system can be used in standpipegas injection applications such as nitrified fluidsand foams. APWD measurements in such under-balanced operations enable the driller to opti-mize production by maintaining planneddownhole pressures selected to minimize oreliminate invasion and formation damage.Under these conditions, the rate of penetrationwill also be improved.

How Downhole Annular Pressure is Monitored

> Annular pressure sensor. Resistor-based bellowsgauges (insert) are used for APWD measurementsin the CDR Compensated Dual Resistivity tool, andare available in three pressure ranges to meet theexpected wellsite conditions. These tools are mudpulse-operated, so no information is sent in realtime when the mud pumps are off. However, theycan record pressures when the pumps are off, andonce pumping is re-established, this information can be sent to the surface. Master calibrations are performed over a range of temperatures using a 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 Drilling

Data Improves Reservoir Drilling Performance,” paperSPE/IADC 37588, presented at the SPE/IADC DrillingConference, Amsterdam, The Netherlands, March 4-6, 1997.

Winter 1998 43

Pore pressure—One ongoing oilfield chal-lenge is determining the pore pressure in shales,and almost all pore pressure prediction is basedon correlation to other measured properties ofshales. Shales start their life at the surface asclay-rich muds, and water is expelled from themas they are buried and subjected to increasingloading from the overburden above them. If theburial is sufficiently slow, and there is an escaperoute for the water, the pressure in the pore fluidremains close to hydrostatic, and the overburdenis supported by increased stresses in the solidparts of the rock. The water content, or porosity,decreases, and this variation of porosity or otherwater-dependent properties with depth is knownas the normal compaction trend.

However, if burial is very rapid, or the fluidcannot escape—because of the low permeabilityof shales—the increasing overburden load is sup-ported by the increasing pore pressure of the fluiditself. The stress in the solid parts of the rockremains constant, and the water content, orporosity, does not decrease. After rapid burial, theshale is not normally compacted; its pore pres-sure is above hydrostatic, and its water content ishigher than it would be for normally-compacted shale at that depth. The shalebecomes overpressured as a result of undercom-paction. Detecting overpressured zones is a majorconcern while drilling, because water or gasinflux can lead to a blowout.

Fracture gradients—Fracture gradients aredetermined from the overburden weight and lat-eral stresses of the formation at depth and fromlocal rock properties. Density and sonic loggingdata help provide estimates of rock strengths.3

Calculating offshore fracture gradients in deepwater presents a special problem. The uppermostformations are replaced by a layer of water,which is obviously less dense than rock. In thesewells, the overburden stress is less than in acomparable onshore well of similar depth. Thisresults in lower fracture gradients and, in gen-eral, fracture gradients decrease with increasedwater depth. Thus, increasing water depthreduces the size of the margin between the mud weight required to balance formation pore pressures and that which will result information breakdown.

Downhole PressureAfter the wellbore stability pressure window hasbeen determined, the driller has more to do thankeep the drilling fluid within these limits. To cor-rectly interpret the response of a downhole annu-lar pressure measurement, it is important toappreciate the physical principles upon which itdepends. The downhole annular pressure hastwo components. The first is a static pressuredue to the density gradients of the fluids in theborehole annulus—the weight of the fluid verti-cally above the pressure sensor. The density ofthe mud column including solids (such as cut-tings) is called the equivalent static density(ESD), and the fluid densities are pressure- andtemperature-dependent.

Second is dynamic pressure related to pipevelocity (swab, surge and drillpipe rotation),inertial pressures from string acceleration ordeceleration when tripping, excess pressure tobreak mud gels, and the cumulative pressurelosses required to move drilling fluids up theannulus. Flow past constrictions, such as cuttingsbeds or swelling formations, changes in holegeometry, and influxes or effluxes of liquids andsolids to or from the annulus all contribute to thedynamic pressure. The equivalent circulatingdensity (ECD) is defined as the effective mud

weight at a given depth created by the totalhydrostatic (including the cuttings pressure) anddynamic pressures.

Understanding the different pressureresponses under varying drilling conditions alsorequires an appreciation of the drilling fluid’s rhe-ological properties, including viscosity, yield andgel strength, and dynamic flow behavior. Is theflow laminar, transitional or turbulent? The varia-tion of the rheological properties with flowregime, temperature and pressure singly, and incombination, affects the total pressure measureddownhole.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 onthe effects of drillpipe rotation on pressurelosses. Some researchers have explicitly statedthat rotation acts to increase axial pressure drop,while others have taken the opposing view, thatan increase in rotation rate decreases annularpressure drop. In fact, both of these seeminglyconflicting views can be correct, and both effectshave been observed. Annular pressure losses oraxial pressure drop depend upon which part of the flow regime predominates when the rotationrate 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 rotational rate. 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-Temperature Well Construction,” Oilfield Review 10, no. 2 (Summer1998): 36-49.

44 Oilfield Review

Experiments performed with the 50-ft [15-m]flow loop at Schlumberger Cambridge Research(SCR), in England confirmed the complex effectsof rotation on annular pressure losses (left). Atlow flow rates, the pressure drop decreases withincreasing rotation rate. At higher flow rates, theopposite effect is observed. However, in nearlyall field examples, with typical drilling muds inconventional borehole sizes, only the increase inannular pressure loss with increased rotationrates has been observed (middle left). This is anarea of ongoing research.

Hole CleaningEfficient hole cleaning is vitally important in thedrilling of directional and extended-reach wells,and optimized hole cleaning remains one of themajor challenges. Although many factors affecthole-cleaning ability, two important ones that thedriller can control are flow rate and drillpipe rota-tion (bottom left).

Flow rate—Mud flow rate is the most impor-tant parameter in determining effective holecleaning. For fluids in laminar flow, fluid velocityalone cannot efficiently remove cuttings from adeviated wellbore. Fluid velocity can disturb cut-tings lying in the cuttings bed and push them upinto the main flow stream. However, if the fluidhas inadequate carrying capacity—yield point,viscosity and density—then many of the cuttingswill fall back into the cuttings bed. Mechanicalagitation due to pipe rotation or back-reamingcan aid cleaning in such situations, but some-times are inefficient or worsen the situation.Agitation that is too vigorous, such as rotatingtoo 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 cuttingsconcentrations in the annulus (next page, top). Acuttings accumulation may lead to a decrease inannular cross-sectional area, and hence anincrease in the ECD—ultimately leading to aplugged annulus, called a packoff. The use ofreal-time downhole annular pressure measure-ments allows early identification of an increasingECD trend, caused by an increasing annularrestriction, and helps the driller avoid formationbreakdown resulting from high pressure surgesor a costly stuck-pipe event.

An example shows how APWD AnnularPressure While Drilling measurements helpdetect packoff.5 The log shows that the annulusstarted to pack off at approximately 1:20 (nextpage, middle). Drilling parameters, such asincreasing surface torque and variations in rota-tion rates, were becoming erratic. Standpipepressure increased slightly. These warnings

2500

2000

1500

1000

500

00 50 100 150 200 250

Rotation, rpm

Pres

sure

gra

dien

t, Pa

/m

300 350 400 450 500

Low flowMedium flowHigh flow

Experimental conditionsHole 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 rotation on 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.

Equi

vale

nt c

ircul

atin

g de

nsity

, sg

0 10 50 100 120 130 Rotation, rpm

600 gal/min

400 gal/min

200 gal/min

1.13

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 were in 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

Largeinfluence

on cuttingstransport

Littleinfluence

on cuttingstransport

Hole cleaning.Some factors areunder the controlof the driller, suchas surface mudrheology, rate ofpenetration (ROP),flow rate and holeangle. Others,including drillpipeeccentricity, andcuttings densityand size, cannot becontrolled as easily.

>

Winter 1998 45

could have been interpreted as due to increasedmotor torque associated with an increase in sur-face torque. However, the large ECD increaseconfirmed that the mud flow was restrictedaround the BHA just above the annular pressuresensor. Based on the confirmation from APWDmeasurements, the driller reduced the mud flowrate and worked the pipe to prevent the ECD fromexceeding the fracture gradient.

Drillpipe rotation—Another example demon-strates the effect of pipe rotation on hole clean-ing (above). At 15:00, pipe rotation was stoppedto enable drill-bit steering. The ECD decreasedfor 20 minutes as the cuttings fell out of suspen-sion. A few swab-and-surge spikes wereobserved. These pressure spikes were introducedas the pipe was moved up and down to adjustmud motor orientation. After steering for a total

of 11⁄4-hours (at 16:15), rotary drilling wasresumed, and the ECD abruptly increased as thecuttings—accumulated during the sliding inter-val—were resuspended in the drilling fluid.Here, real-time APWD data helped determine theminimum rate of rotation required to effectivelystir up cuttings and clean the wellbore.

Stat

iona

ry

Rolli

ng

Asymmetricsuspension

Symmetricsuspension

Low flow rate High flow rate

Low

ECD

High

ECD

Cuttings 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 borehole—building 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 increases further, 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 fromGrover GW and Aziz A: The Flow of Complex Mixtures in Pipes. Malabar, Florida,USA: Robert E. Krieger Publishing Company, Inc., 1987.]

ECD/ESD1410

Temperature°C 200

lbm/gal

0Standpipe pressure

40000

Total pump flow1000gal/min

psi

0Surface torque

300

Surface rotation150rpm

kft-lbf

0

TimeMeasured depth

110000

Surface weight on bit60klbf

ft

0

01:00

02:00

Packing off. The driller responds in real time to an increase in the ECD (red curve), shown in 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 annulusbecomes clear again.

HookloadTime

Surface torquekft-lbf

Surfacerotation

Blockspeed

ftDepth

Rotationstops

Slidinginterval

Rotationstarts

2000 rpm500010-10 14.213.2 lbm/gal10000

gal/minft/s klbf

Totalpump flow

ECD / ESD

Standpipe pressure

Temperature

15:00

16:00

5000psi0

100°C0Effect of drillpipe

rotation on hole cleaning. The ECD (redcurve), shown in track6, increases—indicat-ing cuttings are resus-pended in the drillingfluid—at 16:15 as rotation 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.

>>

>

46 Oilfield Review

Improving Efficiency in Extended-Reach DrillingBP encountered severe wellbore instability prob-lems when drilling development wells in Mungofield in the Eastern Trough Area Project (ETAP) ofthe North Sea. These instability problems weredue in part to large cavings formed while drillingthe flanks of salt diapirs. Long S-shaped 121⁄4-in.[31-cm] sections are generally the most problem-atic. The volume of cavings—coupled with highlyinclined wellbore trajectories—results in poorhole-cleaning conditions. The main cause of thepoor hole cleaning is believed to be the formationof cuttings and cavings beds on the highlyinclined 60° section. These beds are manageablewhile drilling, but present a major hazard when

tripping and running in casing. Most of the earlywells experienced extreme overpulls, packing offand stuck-pipe incidents when pulling out of thehole. In addition, severe mud losses had beenencountered when drilling inadvertently into thechalk at total depth.

Based on this experience with borehole insta-bility, BP revised its drilling program with a com-bination of better fluid management andhydraulics monitoring aimed at improving bothhole cleaning and drilling practices. The resultswere impressive. In the first well in the secondphase of the Mungo development, nonproductivetime was reduced from 34%—the average expe-rienced on earlier wells—to 4%, with estimatedcost savings of over $500,000. Drilling rate per-formance increased 10%, while the incidence ofstuck pipe decreased.

The logs from this well exemplify how newhole-cleaning practices, supported by APWDmonitoring, led to a successful drilling program(above). The pumps were switched on at 19:05,and the flow rate increased to 1000 gal/min [3785L/min]. The standpipe and the downhole annularpressure responded almost instantaneously andafter a few minutes, the driller started rotatingthe pipe. The increased downhole weight on bitindicates that drilling commenced just before19:10. The first part of the stand was rotary drilledat approximately 100 rpm until 19:27. At this time,the drillstring was raised to set the necessarytoolface for the next sliding period. Slidingbegan—shown by zero surface rotation rate—at19:30 and continued until 19:45.

Blockposition

Drilling cycle 1

Drilling cycle 2

Pumps on

Pipereciprocating

m0 50

Hookloadklbf0 400

ROPm/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

Turbinerotationrpm0 5000

Standpipe pressurepsi0 4000

Annulus pressure

psi0 4000

Annulus temperature°C0 200

ECDsg1.65 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.

Winter 1998 47

As the stand was being drilled, the ECD logshowed the effects of rotating and sliding.During rotary drilling, ECD values were approxi-mately 1.70 sg. When the drillstring was pickedup to set the toolface for sliding, the hole wasswabbed and the ECD dropped slightly to 1.69 sg.As the drillstring was lowered, the hole wassurged about the same amount, raising the ECDto 1.71 sg. Once rotation stopped, the ECD againfell to 1.68 sg and continued to fall, as the cut-tings started to settle in the hole, due to the lackof mechanical agitation—reducing the cuttingscontribution to the ECD.

Even though drilling continued during sliding,and cuttings were being produced at a steadyrate, the ECD did not increase. This demon-strates that the hole was not being cleaned asefficiently as it had been with rotary drilling.This was confirmed by the lack of cuttings overthe shale shakers.

The last part of the stand was also rotarydrilled. Rotation resumed at 19:46, and the ECDincreased immediately and continued to show anincreasing trend. Increasing ECD was caused byturbulence and axial flow in the mud column inthe annulus as it stirred cuttings that settled onthe bottom of borehole. The cuttings added to thehydrostatic pressure and increased the ECD. At19:54 the driller picked up the string and startedthe hole-cleaning procedure.

The bell-shaped profile of the ECD curve dur-ing rotary drilling was formed by the increasingECD due to the rotation and stirring of pre-exist-ing cuttings beds as well as increased cuttingsload resulting from drilling ahead. The ECDreached its peak value when the stand wasdrilled down. As the hole was cleaned by recip-rocating the pipe (maintaining a constant mudflow and rotary speed), the ECD decreased.When the value returned to nearly 1.71 sg, thehole was deemed to be sufficiently cleaned.After pipe reciprocation and flow were stopped,a survey was taken at 20:19. After completion ofthis operation, a connection was made anddrilling resumed successfully at 20:30 with goodhole cleaning.

Another example—using APWD monitoringto avoid stuck pipe—shows how an indication ofcuttings accumulation during a drilling break cantake several hours to appear in the ECD logbecause of the horizontal wellbore traveltime inextremely long ERD wells. In BP’s most recent

record-breaking horizontal well at Wytch Farm,England, a cuttings cluster traveled along thehorizontal leg of the wellbore for almost fivehours after the drilling break at 12:00 beforereaching the vertical section of the well (above).6

Finally, at 4:40 the ECD readings started increas-ing—approaching the fracture gradient of theformation. The driller, anticipating potentiallysevere well problems, decided to stop drillingearly, and clean out the cuttings accumulated inthe borehole by reciprocating the pipe. This isanother success story. Without advance noticefrom the APWD measurement, the drillstringmight 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

Drillingbreak

1:00

4:00

5:00 ECDincrease

Standpipepressureincrease

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

6. Allen F, Tooms P, Conran G and Lesso B: “Extended-Reach Drilling: Breaking the 10-km Barrier,” OilfieldReview 9, no. 4 (Winter 1997): 32-47.

48 Oilfield Review

Kick Detection The influx of another fluid into the wellbore dueto unexpected high formation pressure is one ofthe most serious risks during drilling. The char-acter of the fluid influx will depend primarilyupon influx fluid density, rate and volume,drilling fluid properties and both borehole anddrillstring geometry (right). Simulations per-formed by The Anadrill SideKick software modelare frequently used to understand the pressureresponses expected downhole and at the sur-face due to gas influxes. (see “Simulating GasKicks,” page 50).7 During gas kicks, ECDresponses for typical boreholes and slim well-bore geometries are dominated by two phenom-ena—reduced density of the mud column asheavier drilling fluid is replaced by less densegas, and increased annular pressure loss due tofriction and inertia when accelerating the mudcolumn above the gas influx.

The reduced annular gap in slimhole wellscan cause unique drilling problems.8 For example,in slim holes the acceleration of the kick fluidinto the wellbore can lead to a sudden increasein frictional pressure loss in the annulus due toacceleration of the mud ahead of the kick fluid. Inaddition, evidence of the influx may not be seenuntil the pumps are shut down. In typical holesizes, the hydrostatic imbalance between thedrillpipe and the annulus outweighs any frictionallosses, and a decrease in the bottomhole annularpressure is evident.

Constant monitoring of all available drillingdata is critical in detecting a downhole kickevent. In an example of a gas kick, an operatorwas drilling a 121⁄4-in. hole section in a well inthe Eugene Island field in the Gulf of Mexico(next page). The formations were sequences ofshales and target sands, and several of thesands were likely to be depleted by previousproduction. In offset wells, the low-pressuresands led to problems including stuck pipe,twist-offs and stuck logging tools.

Maintaining a minimum mud weight wasrequired to avoid differential sticking in thedepleted sands. Due to faulting in the area, zonalcommunication was uncertain and the pore pres-sure limits were difficult to anticipate. Anadrillwas using the CDR Compensated Dual Resistivitytool for formation resistivity and the MultiaxisVibrational Cartridge (MVC), Integrated Weight-on-Bit (IWOB) tool and APWD sensors for moni-toring drilling performance. The plan was to set aliner below a normally pressured zone beforedrilling 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

Annu

lar p

ress

ure,

psi

Pit g

ain,

bbl

Stan

dpip

e pr

essu

re, p

si

Fric

tion

pres

sure

loss

, 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 pressureresponse. 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 300Block height

Annulustemperature

ft °F 13 18ECD

lbm/gal 3000 5000

Standpipepressure

psi 08:00Time

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.

Winter 1998 49

During drilling through a shale zone justbefore 14:00, a few indications of increasingformation pressure were seen in the APWD dataand several connection and background mud gasindications were detected in the mud flow. Oil-base mud weights during this run wereincreased from 11.5 to 12.0 lbm/gal [1.38 to 1.44g/cm3]. Just before the sand was entered at17:10, the real-time ECD measured downholewas 12.5 lbm/gal [1.50 g/cm3]. At this point, theROP abruptly increased and drilling wasstopped—10 ft [3 m] into the sand zone—tocheck for mud flow. Although the potential for akick was a concern, the fact that there was noevidence of a kick or mud flow suggested that itwas safe to proceed.

As drilling progressed after 18:10, the ECDmeasurement 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] ofthe well. The drilling foreman noticed the largedrop in ECD readings—signaling an influx.Increased pit volumes were noticed at this timeand the well was immediately shut in at 19:50.The kill took 24 hours with an additional 30 hoursto repair blowout preventer (BOP) damage.

At what point did the kick first becomeapparent on the downhole ECD log? The firstECD drop from 12.5 to 12.35 lbm/gal probablycould be attributed to the decrease in ROP. Suchchanges were seen earlier in this well.Statistical variations in ECD, due to drillingnoise, can be as high as 0.2 lbm/gal. On theother hand, the systematic change from 12.35 to12.0 lbm/gal is a clear signal that an influx isalready in the mud column. Monitoring the ECDconstantly, using alarms set to detect the firstsign of ECD changes, and checking corroboratingdrilling indications, such as ROP, can provide ear-lier warning of such occurrences.

In another example, use of APWD data helpedsave a well. In this well, drilling was proceedingwithout any indication of an influx either from pitgain or in mud flow rates in or out of the well (pre-vious page, bottom). However, the ECD started todecrease 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 ECDresponse, the driller stopped drilling and safelycirculated 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/hrBit depth

500 0

ft0 100

Surface weight on bit

klbf0 60Downhole weight on bit

klbf0 60

Surface torque

kft-lbf0 25

Bit on bottom flagDownhole torque

kft-lbf0 8

Totalpumpflow

gal/min0 1500

CDR annulus pressure

psi0 10000

ECD

lbm/gal9 11

Annulus temperature

°F100 300Standpipe 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 influx was 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 decrease suddenly increased. After drilling ahead for 30 minutes with rapidly decreasing ECD and increasing pit 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,” OilfieldReview 5, 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.

50 Oilfield Review

The growth in deep-water drilling activities inmany regions of the world is attractingincreased attention to the specific problems ofgas influx and well control. Deep water posesspecial problems related to both the depth andtemperature of the water. Reduced marginsbetween pore pressure and fracture gradientrequire accurate understanding of downholefluid behavior.

Various definitions of kick tolerance exist andmay be given in terms of pit gain, mud weightincrease or even underbalance pressure. What-ever way it is expressed, kick tolerance is ameasure of the size and pressure of kick the wellcan take and still be controlled without fractur-ing the formation. Kick tolerance decreases asdrilling proceeds deeper, and once the limit isreached, additional casing must be set to protectthe formation. Kick tolerance is a complex con-cept as it varies as a function of the formationpressure driving the kick, the amount of influxentering the well and the distribution of theinflux in the annulus. Balancing this complexitymakes a simulator an ideal choice for computingkick tolerance.

Scientists at BP and Schlumberger CambridgeResearch, England have spent years studying thebehavior of gas kicks.1 Their work, along withengineering development at the SchlumbergerSugar 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 distributionin the annulus. This produces a more realisticand less conservative kick tolerance, whichleads to the use of fewer casing strings and sub-stantial cost savings. Kick tolerance is illus-trated in user-friendly, automatically generatedplots of safe pit gain versus safe formation pres-sure (below). The simulator helps engineersanticipate and meet the challenges of a widevariety 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 ofusing the underbalanced methods must also beevaluated. Other simulators have helped address

Simulating Gas Kicks

1000

900

800

700

600

500

400

Shut

-in d

rillp

ipe

pres

sure

, psi

0 10 20 30 40Pit gain, bbl

StaticCirculating

Safe

Unsafe

> SideKick-PC kick tolerance. The SideKick-PC program computes separate kick tolerances for the shut-inand kill periods of a simulation. The kick tolerance plot is used to differentiate kicks that can be safelyshut 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 inthe region above and to the right of each curve may cause lost circulation.

these issues, but have looked only at stabilizedsteady-state conditions. This simulator is a fullytransient numerical simulator that can deter-mine the optimum amount of nitrogen necessaryto reach a desired underbalance.2

The SideKick-PC program also introduces the concept of the Maximum Allowable BlowoutPreventer Pressure (MABOPP).3 This gives animproved indication of the potential for shoefracture during a kill using a BOP pressuremeasurement to remove uncertainties involvedin fluid properties in long choke and kill lines.

Simulations have shown that a simple tech-nique can minimize the risk at the end of adeep-water kill by slowing the pumps when thechoke is wide open to minimize pressure in theannulus. This technique has been shown to bepreferable to other methods, such as using areduced slow-circulation rate over the whole killor arbitrarily reducing the flow rate, and is nowan integral feature of the simulator.

The SideKick-PC program has proved effectivein allowing engineers to run many complex sim-ulations easily and quickly. Coupled with defin-ing safe operating envelopes in minutes ratherthan hours or days of well planning, gas-kicksimulation is helping to enhance overall per-formance by improving efficiency and reducingwell 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 the temporal 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 properties over time, and cannot allow for effects such as gas solubility as the gas cloud migrates after circulation hasstopped. Furthermore, such a transient simulator can indicate whether steady state can even be reached.

3. James JP, Rezmer-Cooper IM, and Sørskår 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

Winter 1998 51

Deep-Water Wells Unconsolidated sediments typically encoun-tered in deep-water formations tighten thewellbore stability window between pore pres-sure and formation fracture pressure. At a givendepth, fracture gradient decreases with increas-ing water depth, and can result in a very narrowpressure margin.9

Additionally, cooling of the mud in the deep-water riser can cause higher mud viscosity,increased gel strength, and high frictionalpressure losses in choke and kill lines duringwell-control procedures. Combined, these fac-tors increase the likelihood of lost-circulationproblems, and drilling engineers must takeappropriate steps to avoid exceeding formationfracture gradients.

Staying within the pressure window—Keeping the ECD within the pressure window isa constant struggle, especially in deep water andHPHT applications. In a well in the Gulf ofMexico, EEX Corporation experienced a kickwhile drilling at near-balance conditions in ZoneA (right). After the kick was taken and the wellwas under control, increased mud weight wasneeded to continue safely. A 13 3⁄8-in. [34-cm] cas-ing string was set because the heavier mudweight exceeded the previous leakoff test.

The next two hole sections were drilledwithout incident. However, as drilling pro-ceeded deeper into the third section, theincreasing pore pressure eventually approachedthe pressure exerted by the heavier mud andanother kick was experienced in Zone B. A 95⁄8-in. [24-cm] casing was needed to permitanother increase in mud weight. As drilling con-tinued, increases in the cuttings load caused themud pressure to exceed the overburden pres-sure in Zone C, resulting in some lost circulationover a period of several days. Lost-circulationmaterial helped minimize mud losses, anddrilling continued successfully thereafter. At thenarrowest point shown in this example, thepressure window was only 700 psi [4827 kPa].

Dynamic kill procedure—Real-time analysisof downhole annular pressure helped BPExploration monitor a dynamic kill procedureused 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 casingshoe. Real-time APWD measurements werecombined with standpipe pressure to monitor theprocess of the dynamic kill.

The procedure circulated kill-weight mud fastenough to “outrun” the influx and obtain a suffi-cient hydrostatic gradient to kill the well. Drillingfluid 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 killprocedure, BP’s Ocean America operating crewmonitored 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 gradient—estimated from resistivity logs (red curve) or seismic time-to-depth conversions (black curve). The well was brought under control with an increase in mud weight—shown by the increased ECD. However, a second kick was experienced in Zone B as 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 S and Rushton S: “Deepening the Search for OffshoreHydrocarbons,” Oilfield Review 10, no. 1 (Spring 1998): 2-21.

52 Oilfield Review

kill weight mud was outrunning the influx fluid byfilling the annulus (below). However, under flow-ing conditions, the standpipe pressure could notbe used to accurately determine bottomholepressure. APWD measurements showed thatbottomhole pressure was increasing due to thekill mud, and confirmed that the new dynamic killprocedure was working. This process, monitoredwith downhole annular pressure measurements,has been incorporated into BP’s recommendeddrilling practices.

Shallow-water flow—According to a recentMinerals Management Services survey coveringthe last 14 years, shallow-water flow occurrenceshave been reported in about 60 Gulf of Mexicolease blocks involving 45 oil and gas fields orprospects.10 Problem water flow sands are typi-cally found at depths from 950 to 2000 ft [290 to610 m], but some have been reported as deep as3500 ft [1067 m] below the seafloor. Frequently,these problems are due to overpressurized andunconsolidated sands at shallow depths belowthe seafloor.11 They can lead to formation cave-inwhen uncontrolled water production occurs. If aninflux is severe enough, wells can be lost due tocontinuous water flow. Extensive washouts canundermine the large casing that is the major sup-port structure for the entire well.

Bit depth

ft0 100

Block speed

ft/s2 2

Annulus pressure

psi7000 9000

ECD

lbm/gal12 13

Annulus temperature

°F50 150Hookload

klbf400 600

ROPft/hr500 0

Surface torque

kft-lbf0 25

Standpipe pressurepsi2000 4000

Surface rotation

rpm0 200

Total pump flow

0 gal/min 100018:00Time

19:00

Kill starts

Kill stops

>Monitoring dynamic kill procedure. A water influx was encountered in a Gulf of Mexico deep-water well that was strong enough to fracture thecasing shoe, resulting in an underground flow. In track 6, both the standpipe pressure (green curve) and downhole annulus pressure (purple curve)showed a steady increase at 18:30 while the kill mud was being circulated in the wellbore.

Sand

Sand

With riser

Without riser

ρwater

ρmud

ρmud

> Riserless operations. During typical offshore drilling (left), drilling mud is circulatedthrough a riser back to the surface and the APWD tool measures an average ECD for theentire interval. During riserless operations (right), the pumped drilling fluid does not returnto the surface, but rather carries its drilling solids only as far as the seafloor.

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 drilledwithout a riser. In these wells, spent drilling fluidand cuttings are returned to the ocean flooraround the wellhead (previous page, top). Sincethe drilling fluid is not recovered under theseconditions, expensive synthetic- or oil-base mudstypically are not used. Instead, either seawateror inexpensive water-base mud is used.

Standard operating practices in deep-waterwells use a remote operating vehicle with a cam-era at the mud line to monitor flow coming out ofthe wellhead. At a connection, the driller willhold the drillpipe stationary and turn off thepumps for a few minutes, to allow fluid u-tubingoscillations to stabilize, and to observe whetherthere is flow at the wellhead.

Downhole pressure measurements detectshallow-water flow—Monitoring ECD helps theoperator assess both the depth and severity ofthe water flow, and decide whether the flow isserious enough to stop drilling. Most conven-tional hydraulics models do not consider theeffects of mud returns to the seafloor, and thuscannot accurately predict the expected ECD inthese wells. A direct measurement of downholemud pressure solves this problem.

Operators are starting to use downhole pres-sure measurements as a way to detect the onsetof and prevent serious damage from shallow-water flows.12 In a deep-water well in the Gulf ofMexico, a water sand in Zone A was encounteredat X090 ft (right). The ECD suddenly increased inthis zone as the sand was penetrated—indicat-ing water and possible solids entry. The rise inannular pressure and an ensuing visual confirma-tion of the mudline flow confirmed water entry.The flow was controlled by increasing mudweight and drilling proceeded. The sametrends—increased ECD with a correspondingannular temperature increase—were seen in thelower section of the next sand, Zone B, and in thesand in Zone D below. The influxes were notsevere and were safely contained by the increas-ing ECD of the drilling fluid. Knowledge of thelocation and severity of the contained waterinfluxes and quick response to early warningfrom annular pressure measurements made itpossible to continue drilling successfully to theplanned 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 arecritical. Accurate leakoff tests (LOT) are essentialto enable efficient management of the ECDwithin the pressure window, and the correspon-ding mud program.

Leakoff Testing—A LOT is usually performedat the beginning of each well section, after thecasing has been cemented, to test both theintegrity of the cement seal, and to determinethe fracture gradient below the casing shoe. Ingeneral, these tests are conducted by closing inthe well at the surface or subsurface with theBOP after drilling out the casing shoe, andslowly pumping drilling fluid into the wellbore ata constant rate (typically 0.3 to 0.5 bbl/min [0.8to 1.3 L/sec]), causing the pressure in the entirehydraulic system to increase. Downhole pres-sure buildup is traditionally estimated from

standpipe pressure, but can be monitoreddirectly with APWD sensors. If pressure meas-urements are made in the standpipe, then com-plex corrections must be made for the effects oftemperature on mud density, and other factorson downhole fluid pressure.13

Pressures are recorded against the mud vol-umes pumped until a deviation from a lineartrend is observed—indicating that the well istaking mud. This could be due either to failure ofthe cement seal or initiation of a fracture. Thepoint at which the nonlinear response first occurs

Depthm

Attenuation resistivityGamma ray0

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°F

Rate of penetrationft/hr

lbm/galohm-mAPI

C

D

B-upper

B-lower

Water influx

Water influx

Water influx

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/.

54 Oilfield Review

is the leakoff test pressure used to compute theformation fracture gradient. Sometimes, the pro-cedure is to stop increasing the pressure beforethe actual leakoff pressure is reached. In suchcases, the planned hole section requires a lowermaximum mud weight than the expected fracturepressure, and the test pressures only up to thislower 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, pressurewill fall, and the fracture will propagate.

APWD measurements helped monitor down-hole pressure in a leakoff test performed by BPExploration in a deep-water well in the Gulf ofMexico (below). As the pumped volumeincreased to 3.5 barrels, the standpipe pressureincreased 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 wastaking fluid. The pressure margin determinedfrom this test was sufficiently high to allowdrilling to proceed without incident.

Before a well is pressure tested, in order toestimate downhole pressures from surfacemeasurements, the drilling fluid is often circu-lated to ensure that a homogeneous column ofknown density mud is between the surface andcasing shoe. However, the downhole annularpressure measured at the casing shoe provides adirect measurement, and therefore the mud con-ditioning process is not required—saving thecost of additional circulations. Downhole pres-

sure measurements remove uncertainties causedby 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 toperform a real-time downhole formation integritytest in a deep-water well in the Gulf of Mexico.During this test, an Anadrill CDR tool wasincluded 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 ispumped to enable the BHA to communicate tothe surface through mud-pulse telemetry. This isnot 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 theuse of a wireline-operated LINC LWD InductiveCoupling tool that sits inside the CDR tool andtransmits pressure data to the surface.

With this arrangement, the operator cansimultaneously view the surface and downholepressure buildup as the test proceeds. In theabsence of compressibility and thermal effects,the rate of pressure rise downhole would be thesame as that at the surface. The operator can usedownhole pressure measured with the APWDsensor to calibrate formation integrity while usingthe pressure buildup differences to monitor thecompressibility of the drilling fluid. Because ofshallow water flow concerns in deep-water wellswith narrow wellbore stability margins, differ-ences of a few tenths of a lbm/gal can make thedifference between one or two extra strings ofcasing being needed to protect shallow intervals.

Real-time downhole annular pressure meas-urements offer at least three advantages duringLOT and FIT testing. First, the operator does notwant to overpressure downhole too far—leadingto formation fractures or a damaged casing shoe.A change in the slope of the pressure buildupcurve with pumped volume is a signal to stop thetest. This is the pressure used to determine thefracture gradient of the formation. The use ofreal-time annular pressure measurements pro-vides the operator with an instantaneous signalto stop the test.

Bit depth ft0 100

Block speedft/s2 2

Hookload klbf0 500

Surface torquekft-lbf10 30

Annulus pressurepsi0 10000

ECDlbm/gal9 12

Surface weight on bitklbf0 80

Total pumpflow

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

Surfa

ce p

ress

ure,

psi

Pumping-upphase

Leakoffphase

Formation takingdrilling fluid

Leakoff test

80

165

260

350

430

480

520

460445

435 430 420 415 410 408 405 400

A

B

> Leakoff testing. A leakoff test was conducted in a deep-water well in the Gulf of Mexico. During the 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 While

Drilling, Application, Interpretation and Learning,” BPInternal Report, December 1997.

Winter 1998 55

Next, monitoring surface pressure alone canlead to incorrect estimates of bottomhole pres-sure because of uncertainty in correcting forthe compressibility of the drilling fluid, particu-larly significant when synthetic- or oil-basemuds are involved.

Finally, the unsteady nature of surface pres-sure data can lead to errors in LOT estimates offracture gradient. An accurate measurement offracture gradient is required to determine theability of the formation and casing cement tosupport the drilling fluid pressure during thenext section of drilling. The use of stable andaccurate downhole annular pressure measure-ments helps makes drilling ahead a more exactand safer process.

The Big PictureIn wireline logging, the log represents a state ofthe well—showing the more-or-less static for-mation properties, such as lithological beds andfluid saturations. Getting the data is most impor-tant, but decisions made at the time of acquisi-tion are not necessarily critical. However, logs ofdownhole annular pressure and other drillingperformance parameters show a process—a process that is evolving with time. The evolu-tion of the log in real time must be monitored asdownhole conditions are dynamic, and timelydecisions are essential. Delay or indecision canlead 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 anddata are compressed on a depth scale.Therefore, a time-based presentation is oftenbetter suited for detailed analysis during prob-lematic drilling intervals. Still, depth-based pre-sentations are important for assessment ofdrilling events in the context of BHA position rel-ative to lithological boundaries.

Drilling parameters should be presented inrelation 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 importantproductive zones. A standard layout for drillingperformance logs has recently been proposed(previous page).14

The proposed layout enters geometric param-eters such as bit depth, ROP, and block speed intrack 1, followed by weight parameters such ashookload and downhole weight-on-bit in track 2.Time or true vertical depth (TVD) are shown in thenext column. Next, torque parameters in track 3,rotation rates along with lateral shock and motorstall in track 4, and flow parameters such as mudflow rates, differential flow, total gas, mud pitlevel 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 fracturepressure limits and standpipe pressure are allshown in track 6.

Downhole annular pressure interpretation isan evolving technique. All possible downholeevents have not yet been observed. Sometimesthe data are enigmatic. Nonetheless, certainclearly identifiable and repeatable signaturescan be used to help diagnose problems (left).Combining the information gleaned from down-hole annular pressure logs with other drillingparameters creates an overall assessment, or thebig picture. This global view helps decipher theindividual measurements used to detect drillingproblems downhole.

Downhole real-time annular pressure meas-urements have a significant impact on today’sdrilling practices with applications in everyaspect 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 annularpressure along with other drilling parametersprovides an integrated view of a healthy drillingenvironment—one that puts emphasis on antici-pation and prevention rather than reaction andcure.15 Such improved operational procedureswill lead to decreases in nonproductive time andincreases 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 slow pumps and break rotation(rotation first)

Cuttings pick-up Increase then levelingas steady-statereached

Cuttings at surface Increase may be more noticeable 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 may“blow-through”before 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 fluidIncreases 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 connection Decrease to staticmud density

Pumps on/offindicatorPump flow rate lag

Watch for significant changes in static muddensity

Increase if well is shut-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.