SCHLUMBERGER OILFIELD REVIEW

SUMM

ER 2001VOLUM

E 13 NUM

BER 2

Summer 2001

Ultralight Cements

Exceptional Seismic Quality

Innovative Drilling Solution

Horizontal Gravel Packing

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For many years, the exploration and production industry hassought to reduce drilling costs through improvements intechnology. Some developments aim at making drilling oper-ations more efficient, while other initiatives focus on reduc-ing nonproductive time (NPT). The result of many differentkinds of drilling problems, NPT accounts for approximately20% of all rig time and can be much higher in difficult fields.Although equipment failures are a significant element, themajor causes of lost time in BP drilling operations areformation-related, such as stuck pipe and lost circulation.

In 1988, a BP task force looked at reducing the costimpact of stuck pipe and found that many incidents hadtwo attributes. First, downhole conditions such as formationpressure, fracture gradient and presence of faults oftenwere different from what had been predicted. Second, littleinformation was available to allow drillers to react correctlyto these unexpected incidents. It was clear that stuck-pipeevents could be avoided by improved detection of developingproblems, if suitable warnings were provided to the rightpeople at the right time. This, combined with better predic-tion of downhole conditions, would make well plans moreaccurate and allow for improved contingency planning.These principles are just as relevant for avoiding otherproblems, such as well-control or lost-circulation events.

Despite major technological advances over the last decade,BP still has many of the same problems and about the samepercentage of NPT. To achieve a major breakthrough, BPand Schlumberger jointly created the No Drilling Surprisesprogram, a holistic approach taking advantage of currentdrilling, measurement and communications technologies.The BP target for this effort was a reduction of NPT due todownhole events to less than 5%. Mungo field in the NorthSea provided an early challenge for the No Drilling Surprisesinitiative, because NPT exceeded 40% in 1988.

Sophisticated formation measurements now can betransmitted from several miles below the surface of theearth as a drilling operation is carried out. Predicted con-ditions can be compared with actual formation resistiv-ities, acoustic measurements—both sonic and seismic—and downhole pressures in the borehole. More traditionalmeasures of drilling progress, such as weight on bit, rate ofpenetration, vibration, mud flow rates and mud volumetrics,are also monitored. This ongoing diagnosis of the downholeenvironment enhances the ability to identify the approachof impending hazards.

The No Drilling Surprises process relies heavily on real-time data, but it includes much more than just measure-ments. Information must be provided to people on the teamwho need it, in a format that helps them make better andfaster decisions. Use of three-dimensional graphics has beena key step, enabling teams to interpret the contents of someextremely large and complex databases. Visualization

Intelligent Planning Reduces Nonproductive Drilling Time

screens were used in a Mungo well-planning meeting toconsider seven possible trajectories to reach three reservoirtargets. In a one-day session, hazards were mitigated withfull input from all members of the multidisciplinary team:drillers, geologists, geomechanics experts and reservoir engi-neers. Weeks of iterations were saved, and mutual under-standing increased dramatically. Collaborative meetings likethis create a tremendous benefit—the best possible planfrom the data available in the shortest possible time.

These plans, however, include some uncertainty becausethe data available before drilling are an imperfect guide todownhole conditions. The No Drilling Surprises initiativeprovides a framework and methodology to compare pre-dictions with critical real-time measurements. Updatingthe plan continually makes it a living well plan, whichallows the No Drilling Surprises team to plan for contin-gencies. Hazards from offset wells help predict possibleevents in the current well so they can be effectively dealtwith while drilling, even anticipated and discussed at thedaily meeting. Experience gained from NPT incidents andnear misses—NPT events that were avoided—is capturedin a database for planning the next well.

The future promises even more ways to drill successfully.New telemetry methods will yield more bandwidth to sendmeasurements made while drilling to the surface. Improvedmeans of obtaining seismic sections by looking ahead of thebit while drilling will provide more and better informationto a drilling team. Efficient sorting of an increasing volumeof information will be an absolute necessity, as will indepen-dent displays designed specifically for each member of thedrilling team.

BP and Schlumberger have taken a major step forward.In Mungo field, NPT was cut in half between 1998 and 2000.The No Drilling Surprises program is more than a slogan;it is an important step toward intelligent drilling.

Chris RhodesTechnology Vice PresidentBPSunbury on Thames, England

Chris Rhodes is the Technology Vice President responsible for worldwidedrilling for BP Exploration. Chris began his career with BP in 1971 in refining,then drilling. He was Business Unit Leader for the Eastern Trough Area Project(ETAP) of seven oil and gas fields including Mungo. Chris attended GlamorganPolytechnic, Pontypridd, Wales on a BP scholarship, receiving a BS degree(Hons) in chemical engineering, and later obtained an MS degree in petroleumengineering from Imperial College, London, England.

Advisory PanelTerry AdamsAzerbaijan International Operating Co., Baku

Syed A. AliChevron Petroleum Technology Co.Houston, Texas, USA

Antongiulio AlborghettiAgip S.p.AMilan, Italy

Svend Aage AndersenMaersk Oil Kazakhstan GmBHAlmaty, Republic of Kazakhstan

George KingBPHouston, Texas

David Patrick MurphyShell E&P CompanyHouston, Texas

Richard WoodhouseIndependent consultantSurrey, England

Executive EditorDenny O’BrienAdvisory EditorLisa StewartSenior EditorMark E. Teel EditorsGretchen M. GillisMark A. AndersenMatt GarberContributing EditorsRana Rottenberg

DistributionDavid E. BergtDesign/ProductionHerring DesignSteve FreemanKaren MalnarIllustrationTom McNeffMike MessingerGeorge StewartPrintingWetmore Printing CompanyCurtis Weeks

Oilfield Review is published quarterly by Schlumberger to communicatetechnical advances in finding and producing hydrocarbons to oilfieldprofessionals. Oilfield Review is distributed by Schlumberger to itsemployees and clients. Oilfield Review is printed in the USA.

Contributors listed with only geographic location are employees ofSchlumberger or its affiliates.

© 2001 Schlumberger. All rights reserved. No part of this publicationmay be reproduced, stored in a retrieval system or transmitted in anyform or by any means, electronic, mechanical, photocopying, recordingor otherwise without the prior written permission of the publisher.

Address editorial correspondence to:

Oilfield Review225 Schlumberger Drive Sugar Land, Texas 77478 USA(1) 281-285-8424Fax: (1) 281-285-8519E-mail: obrien@sugar-land.oilfield.slb.com

Address distribution inquiries to:

David E. Bergt(1) 281-285-8330Fax: (1) 281-285-8519E-mail: dbergt@sugar-land.oilfield.slb.com

Oilfield Review subscriptions are available from:

Oilfield Review ServicesBarbour Square, High StreetTattenhall, Chester CH3 9RF England(44) 1829-770569Fax: (44) 1829-771354E-mail: orservices@t-e-s.co.ukAnnual subscriptions, including postage, are 160.00 US dollars, subject to exchange rate fluctuations.

Summer 2001Volume 13Number 2

Schlumberger

2 Light as a Feather, Hard as a Rock

Weak or low-pressure formations must be cemented carefully to ensure zonalisolation and environmental protection. Enhanced cement slurries achievethe ultralight densities necessary to avoid formation fracturing and circulationlosses during well construction and completion operations. Once set, ultralightcement attains the low permeability and high compressive strength necessaryfor wellbore integrity and zonal isolation.

74 Contributors

78 New Books and Coming in Oilfield Review

Oilfield Review

1

52 High-Productivity Horizontal Gravel Packs

Until recently, stand-alone screens were the predominant sand-control measure for horizontal openholes. However, operators now gravel pack moreof these wells because many screen-only completions have failed prematurely.This article reviews stand-alone screens, water packing, Alternate Path tech-nology and damage removal, including wellbore displacements and simulta-neous cleanup with water-base fluids. New tools, developments in oil-basefluids and emerging techniques like expandable screens are discussed.

16 Raising the Standards of Seismic Data Quality

An innovative way of acquiring marine seismic data produces dramaticallyimproved images for detailed interpretation. With the new system, every stepof marine acquisition has changed: receiver streamers are steered and posi-tioned reliably and repeatably; air-gun source controllers regulate sourcequality; signals are recorded at individual point receivers instead of in groups,for better noise reduction and signal enhancement. The resulting images areremarkably clear and are setting new standards for marine seismic data quality.

32 Avoiding Drilling Problems

Drilling wells without incident is expensive enough, but encountering hazardscan rapidly destroy a budget. A new process can mitigate drilling problems bygathering the right data in the right time frame and communicating this infor-mation to the right people. Case studies from the Gulf of Mexico and theCaspian and North Seas illustrate the effectiveness of this new drillingprocess in difficult drilling environments.

2 Oilfield Review

Light as a Feather, Hard as a Rock

Abdullah Al-SuwaidiChristian HunAbu Dhabi Company for Onshore Oil OperationsAbu Dhabi, United Arab Emirates

José Luis BustillosCiudad del Carmen, Mexico

Dominique GuillotJoel RondeauPierre VigneauxClamart, France

Husam HelouAbu Dhabi, UAE

José Antonio Martínez RamírezJosé Luis Reséndiz RoblesPetróleos Mexicanos (PEMEX)Ciudad del Carmen, Mexico

For help in preparation of this article, thanks to WassimAssaad and Mohamed Jemmali, Ahmadi, Kuwait; JeanMarc Boisnault, Philippe Drecq, Bruno Drochon, MartinHyden, Bernard Piot and Benoit Vidick, Clamart, France;Leo Burdylo, Andre Garnier, Roger Keese, Erik Nelson andDwight Peters, Sugar Land, Texas, USA; Sherif Foda andPhilippe Revil, Abu Dhabi, UAE; Greg Garrison, Houston,Texas; Stephan Harris, New Orleans, Louisiana, USA; andRobert Roemer, Aberdeen, Scotland.CBL Adviser, CBT (Cement Bond Tool), CemCADE,CemCRETE, CET (Cement Evaluation Tool), LiteCRETE, PAL (Pipe Analysis Log), SFM (Solids Fraction Monitor), USI (UltraSonic Imager) and Variable Density are marks of Schlumberger. Windows is a mark of MicrosoftCorporation.

Until recently, it has been impossible to design and prepare isolation-quality cement

slurries that are close to the density of water. New lightweight cements attain the

low permeabilities and high compressive strengths necessary for wellbore integrity

and zonal isolation, yet they have slurry densities low enough to prevent fracturing

and lost circulation.

Wellbore cement that provides complete zonalisolation protects the environment, enhancesdrilling safety and optimizes production. Withouthigh-quality cement filling the annulus betweenthe casing and the formation, freshwateraquifers above or below the reservoir might becontaminated by fluid from other formations.Casing that is not protected by cement might beprone to corrosion by formation fluids. Drillingfluids that exceed the formation fracture pressurecan induce fracturing. Circulation, and thereforewell control, might be lost during drilling andcementing operations, meaning that no fluidreturns to surface, particularly if weak formationsare not protected from mud or slurry weights thatexceed the formation fracture pressure. Drillingfluids then are lost into the fractures and do notreturn to the fluid-circulation system. Productionmight be impaired if hydrocarbons flow anywhereother than into the wellbore.

CemCRETE cements, introduced in 1995,maintain high performance standards in extremeoilfield conditions, with engineered particle-sizedistribution that ensures high compressivestrengths and complete zonal isolation across awide range of densities.1 Recently, thelightweight version of CemCRETE technology,known as LiteCRETE technology, has beenupgraded to provide comparable physical proper-ties at a slurry density similar to that of water.

The enhanced LiteCRETE technology is effec-tive in difficult operational situations. Perhaps

the biggest challenge in lightweight cementingenvironments is controlling circulation losses.Even the lightest drilling muds and cement slur-ries may be lost to weak or fractured formations.Cementing lost-circulation zones usually entailsextra expenditures for stage tools, top jobs andother remediation to guarantee isolation of weakformations and aquifers.2

High-performance lightweight cementingtechnology improves zonal isolation. Ultralight-weight cements protect freshwater supplies andshield the casing from corrosion because theycan be placed higher in wellbore annuli than con-ventional slurries, even in areas prone to extremecirculation losses. Weak formations can becemented completely using LiteCRETE blendsthat do not exceed low formation-fracture gradi-ents. LiteCRETE plugs are strong enough to serveas kickoff or whipstock plugs, and productioncasing cemented with LiteCRETE systems can beperforated cleanly without fracturing. Set-cementpermeability is lower than that of conventionalClass G Portland cement, and compressivestrength rivals that of Portland cement. LiteCRETEapplications are successful in a range of environ-ments from 80 to 450°F [27 to 232°C], downholepressure to 8000 psi [55.15 MPa] and 8.2 to 12.5 lbm/gal [0.98 to 1.50 g/cm3] slurry densities.

In this article, we review high-performancecementing technology, discuss how slurries lighterthan water have been blended and placed successfully, and demonstrate the role that new

Summer 2001 3

SFM Solids Fraction Monitor technology hasplayed in making ultralightweight cementing oper-ations possible without using a foamed-cementsystem. We also discuss recent operational mile-stones in Abu Dhabi and other areas of the MiddleEast, and Mexico.

Lightening the LoadCemCRETE technology is concrete-based slurrytechnology that optimizes performance duringplacement while ensuring high set-cement quality.

To create these high-performance slurries, parti-cles of several sizes are blended to maximize theamount of solid particles in a given volume ofslurry (right). The bulk properties of the cement,such as density, depend on the properties of thecoarsest particles. The intermediate particles areselected to offer a specific chemical response,such as chemical resistance or thermal stability.The smallest particles ensure specific matrixproperties, including stability, fluid-loss controland permeability. Various particle types and

> Optimized particle-size distribution.Small particles occupy the void spacebetween the largest particles, resultingin a higher solid fraction in the slurryand lower set-cement permeability.

1. For an introduction to CemCRETE technology: Boisnault JM,Guillot D, Bourahla A, Tirlia T, Dahl T, Holmes C,Raiturkar AM, Maroy P, Moffett C, Pérez Mejía G,Ramírez Martínez I, Revil P and Roemer R: “ConcreteDevelopments in Cementing Technology,” Oilfield Review 11, no. 1 (Spring 1999): 16-29.

2. Stage tools are used in stage-cementing operations,which commonly are performed when cementing weakformations that cannot support a long fluid column. Thetools enable the first-stage cement slurry to be placed

through the float shoe or guide shoe and up the annulus,but not past the stage tool. Next, an opening bomb isdropped, which opens ports in the stage tool and preventsaccess below the bomb. The second-stage slurry ispumped down the casing, passes through the ports andgoes up the annulus, completing the cementing operation.A top job may be necessary to fill the annulus betweenthe formation and the casing. Top-job operations involvepumping cement down the annulus from surface, ratherthan down the drillpipe and up the annulus.

particle-size distributions can be blended toachieve a specific slurry density while maintain-ing desirable rheology—the slurry must behomogeneous, stable and easy to pump.3

CemCRETE slurries with as much as 65% dryblend or as heavy as 24 lbm/gal [2.88 g/cm3]have been blended and pumped successfully.

At the other end of the spectrum, increasinglylower slurry densities are being developed toaccommodate difficult cementing situations(left). Previously, slurry density could be reducedonly by adding water or using a foamed-cementsystem. However, increasing the water contentof an ordinary Portland cement slurry producesset cement with high permeability, low compres-sive strength and poor corrosion protection forthe casing.

Foamed cement was developed more than 20 years ago for lightweight cementing applica-tions, and is still useful in certain situations.4

Foamed-cement systems require special equip-ment to incorporate nitrogen gas or air in theslurry to reduce density (bottom left). A surfac-tant is added to the slurry to generate and stabi-lize the foam until the cement sets. Foamedcements have been pumped at densities rangingfrom 3.5 to 15.0 lbm/gal [0.42 to 1.80 g/cm3].5

However, foamed cement with more than 30% foam quality, or density of approximately9.0 lbm/gal [1.08 g/cm3], does not achieve thelow permeability and high strength of LiteCRETEcements (next page).6 Foamed cements per-form suitably in a limited number of specific

4 Oilfield Review

5

10Water density,

8.3

15

20

25

Slur

ry d

ensi

ty, l

bm/g

al

Cement systems

DensifiedWeighted HeavyweightNeatConventional

lightweightUltralightweight

> Cement classification by slurry density.

Conventional Cementing Equipment

Foamed Cementing Equipment

Mixingpackage

Cementing unit

Foamed cement bleedoffMix waterDry blend Wellhead

Foam generator

N2 pump Process-control

computer

2000-gal N2 tank,180,000 scf

N2 isolation valve

Cementing truckCementing skid

Nonradioactivedensitometer

N2 bleedoff

2000-gal N2 tank,180,000 scf

Foamerpump

> Cementing equipment. Conventional slurries can be mixed and pumped using a pump skid or truck-mounted unit (top), with dry blend stored in silos on site.Foamed-cementing operations (bottom) require a nitrogen pump, nitrogen tanksand a container for electronics, flowmeters and other tools, in addition to equip-ment required for ordinary cementing operations. Because of the variety of rigs,foamed-cementing equipment is set up differently for each job according to thespace available on the rig.

3. Maroy P and Baret JF: “Oil Well Cement Systems, TheirPreparation and Their Use in Well Cementing Operations,”European Patent 621,247 (July 7, 1999).

4. For more on foamed cement: de Rozières J and Griffin TJ:“Foamed Cement,” in Nelson EB: Well Cementing.Sugar Land, Texas, USA: Schlumberger Dowell (1990):14-1–14-19.

5. Reference 4: 14-1.6. Foam quality is the ratio of gas to total volume of the

system, expressed as a percent.For more on foamed-cement characterization: de Rozières J and Ferrière R: “Foamed-CementCharacterization Under Downhole Conditions and ItsImpact on Job Design,” SPE Production Engineering 6,no. 3 (August 1991): 297-304.

7. Rondeau J and Vigneaux P: “Fluid Mixing System,” USPatent Application 09/726,784, filed November 11, 2000.

Summer 2001 5

applications, such as controlling water flowsfrom near-surface layers when drilling in deep-water locations, but fast-setting LiteCRETEsystems also perform well in these settings.

Optimized particle-size distributions and spe-cial low-density particles in LiteCRETE slurriesallow adjustment of slurry properties independentof water content. The lightest LiteCRETE slurrieshave densities below 8.34 lbm/gal [1.00 g/cm3],light enough for a cube of set cement to float inwater. Despite their low densities, these new ultra-light slurries contain 60% solids and 40% waterwhen pumped. Once set, ultralight LiteCRETEcements achieve the low permeability and highcompressive strength of the first-generationLiteCRETE cements.

Innovation for Quality ControlAn important element of successful low-densityslurry placement and ideal set-cement propertiesis quality control. A key measure of quality incement slurries is the solid fraction, which is thepercent of dry blend in the slurry. The solid frac-tion can be calculated by dividing the volume ofdry blend by the volume of slurry, and multiplyingby one hundred. The solid fraction plus the poros-ity, or mix-water content, equals 100%. In a con-ventional cementing operation, densitometersmeasure slurry density, and the solid fraction iscalculated from density measurements. In ultra-lightweight slurries, however, the densities ofthe dry blend and the mix water are nearly thesame, so densitometer measurements cannot

discriminate between water and solid. The densitywould be the same even if the slurry consistedentirely of water. Although small jobs can bebatch-mixed and quality-controlled in a laboratoryenvironment, this is impractical for jobs thatrequire large volumes of slurry. The engineeringteam that developed low-density LiteCRETE sys-tems recognized the importance of inventing acomplementary quality-control technology.

The SFM Solids Fraction Monitor system,invented and patented by engineers at theSchlumberger Riboud Product Center in Clamart,France, is a new method for real-time slurry quality control that accurately determines liquid-solid ratios independent of slurry density.7

The system was created in a tightly scheduled

> Comparison of compressive strength and permeability of set foamed and LiteCRETE cements.

Com

pres

sive

stre

ngth

, psi

Density, lbm/gal

3500

3000

2500

2000

1500

1000

500

08 9 10 11 12 13

Foamed cement LiteCRETE cement

Perm

eabi

lity,

log

mD

Density, lbm/gal

3

2

1

0

-1

-2

-3

-48 9 10 11 12 13

Foamed cement LiteCRETE cement

> Comparison of set-cement permeability. Cubes of 8.0 lbm/gal [0.96 g/cm3] LiteCRETE and foamed cement float in water initially, as shown in thephotograph at the left. After a period of seconds to minutes, the higher permeability of the foamed cement allows it to become waterlogged andsink, as shown in time-lapse photographs.

product-development process that lasted only 90 days, and was first used in Abu Dhabi. Thesystem measures the rate of mix water and slurryflow and calculates the solid fraction from thosemeasurements (above). Although SFM technol-ogy was developed specifically for lightweightcementing operations, it is effective for slurriesof any density.

SFM technology allows cementing crews tomaintain desired slurry properties while continu-ously mixing and pumping large slurry volumes.The system requires a slurry flowmeter, which canbe the existing nonradioactive densitometeralready available on cementing units, and addi-tional sensors—a sensor showing the level ofslurry in the tub and a water flowmeter. Theseretrofits can be added easily to onshore or off-shore mixing equipment (right). Windows-basedsoftware helps cementing crews monitor andadjust the blend whenever necessary usingexactly the same procedures as in conventionalslurry mixing (next page). In a field application of the SFM system, 98% of the slurry volume has been maintained within 2% of the solid-fraction target.

SFM technology has been used in 55 jobs, 39 involving LiteCRETE systems, in the MiddleEast, Mexico, Indonesia and France. The SFMsystem is available worldwide for use in conven-tional and LiteCRETE slurries.

Evaluation of Lightweight CementsQuality control while mixing and pumping slurriesis critically important, but evaluation of setcement is also a key to successful long-termzonal isolation. Once slurry has been pumped andbecomes set cement, it is important to evaluatethe cement to confirm its successful placementand its ability to fulfill its objectives. In mostcases, cement is placed to support casingstrings, isolate water and hydrocarbon zones,and protect the casing from corrosion or erosion.Simple hydraulic tests—pressure testing thecasing shoe, “dry” drillstem testing to determinewhether cement will prevent fluid from enteringthe wellbore or tests through perforations to

check for annular communication—cannotensure that all of those objectives have beenmet, so logging tools that measure acoustic prop-erties of set cement have been developed toevaluate cement.8

Acoustic logs are used to assess the qualityof cement jobs by measuring the propagation of sound waves near the wellbore. Ultrasonictools measure the acoustic impedance—densityof the material times velocity of the compres-sional wave—of the material behind the casing.In most cases, solid material—set cement—exhibits a higher acoustic impedance thanliquids—mud, spacer or liquid cement. Therefore,ultrasonic tools can be used to differentiatesolids from liquids through a contrast in acousticimpedance. If a solid material is uniformly dis-tributed around the casing over some minimalrequired length, hydraulic isolation is ensured.

Sonic tools are based on a differentprinciple—the wave propagates along the cas-ing. Sonic tools respond to the acousticimpedance of the solid material behind the cas-ing. The higher the acoustic impedance of thematerial bonded to the casing, the higher theattenuation of the wave. However, attenuation isaffected by other parameters, such as the distri-bution of solid and liquid materials around thecasing. Thus, interpreting attenuation measure-ments obtained with sonic tools is usually farmore difficult than interpreting an acoustic mapfrom an ultrasonic tool. The combination of sonicand ultrasonic tools is most effective when log-ging lightweight cement because the VariableDensity log from the sonic tool is the only mea-surement that provides information on thecement-to-formation bond.

6 Oilfield Review

(1) Porosity (%) = VolumeMix water /VolumeSlurry x 100

(2) Solid fraction (%) = VolumeBlend /VolumeSlurry x 100

(3) Solid fraction + Porosity = 100 %

(4) Solid fraction from densities = (ρSlurry – ρMix water) / (ρBlend – ρMix water)

(5) Solid fraction from flow rates = (QSlurry – QMix water) / QSlurry.

Examples of solid fraction from densities

Solid-fraction calculations

(8.38 – 8.34) / (8.45 – 8.34) = 36%

(8.42 – 8.34) / (8.45 – 8.34) = 72%

> Solid-fraction calculations from densities and flow rates. Slurryporosity and solid fraction are defined as the ratio of the volumeof mix water and dry blend to the volume of the slurry. Slurryporosity and solid fraction add up to 100%, as shown in the firstthree equations. The solid fraction can be calculated from densi-ties (fourth equation) or flow rates (fifth equation). Examples ofcalculations of solid fraction from slurry densities approximatelythe density of water demonstrate that a difference of +/- 0.02, orthe resolution of a densitometer, can produce solid-fraction valuesranging from 36 to 72%.

Junctionacquisition box

MixerDensitometer

Water flowmeter

6-bbl tub

Tub-level sensor

Mix waterrate (Qw)

Slurry rate (Qs)

SFM Slur

ry d

ensi

ty, l

bm/g

al

Slur

ry ra

te, b

bl/m

in

Slur

ry v

olum

e, b

bl

Pum

pim

g pr

essu

re, p

si

Solid

frac

tion,

%

8:01 8:06 8:11 8:16 8:21 8:26 8:31 8:36 8:41 8:46 8:51 8:56 9:01 9:06 9:11 9:17Days

0

70

60

50

40

30

20

10

1200

1000

800

600

400

200

0

> SFM equipment. Cementing units can be retrofitted with the SFM equipmentin a matter of hours.

Summer 2001 7

Sonic measurements include cement bondlogs, such as the CBT Cement Bond Tool output,which are used to evaluate the bond betweencasing and cement using waves that propagateparallel to the casing. A transmitter sends acous-tic energy, and a receiver measures returningsignals from waves that travel through casing,cement, formation, drilling mud or some combi-nation of those. Hallmarks of a good sonic logresponse include an amplitude or attenuationthat corresponds to the expected acousticimpedance for the cement placed behind the cas-ing, nonexistent or weak casing arrivals on theVariable Density log, and good to strong forma-tion arrivals on the Variable Density log.

Ultrasonic tools include the USI UltraSonicImager and CET Cement Evaluation Tool devices,which emit high-frequency waves that propagatenormal to the casing. The energy that returns to the receivers depends on the acoustic

impedances of the casing, the fluid inside thepipe and the material in the annulus. Since theacoustic impedances of the casing and fluidwithin it are known, it is possible to determine theacoustic impedance of the material in the annu-lus. From this, the bonds between casing andcement are evaluated. The measurements ofacoustic impedance are usually expressed inMegarayleighs (Mrayl), or 106 kg/m2s. A goodultrasonic response is simply an acousticimpedance higher than the liquid-to-solid thres-hold all around the casing. When these goodresponses are obtained across some minimumlength, the formations below are considered to behydraulically isolated from overlying formations.

A key aspect of successful cement evalua-tions is understanding the set-cement propertiesexpected from a given blend. LiteCRETE cements

do not comprise 100% cement particles. Theyhave lower acoustic impedance than conven-tional Portland cement systems at 1.90 g/cm3

[15.8 lbm/gal], the density often used to cementproduction strings. LiteCRETE systems are moredifficult to log than conventional Portland cementsystems at 1.9 g/cm3 because the contrast inacoustic impedance between solids and liquids isreduced. Because density influences acousticimpedance more than velocity does, the lowerthe density, the worse the problem. However,LiteCRETE systems also have higher acousticimpedance—because of the higher solidfraction—than conventional cement systemswith the same density, so they are easier to logthan any other cement system designed at thesame density.

There are two major reasons why theresponse of acoustic logs run across LiteCRETEsystems may be misinterpreted. First, theresponse is expected to be as good as for a con-ventional Portland cement system at 1.9 g/cm3.This expectation is incorrectly based on the factthat these two systems have nearly the samecompressive strength, but, in fact, the responseof acoustic logs has nothing to do with compres-sive strength. Second, default settings for sometools are based on the response of a conven-tional Portland cement system at 1.9 g/cm3. Toavoid misinterpreting ultrasonic logs of anylightweight cement, the acoustic impedance maybe determined given the time, density and tem-perature before logging.

The traveltime of set cement can be mea-sured using an ultrasonic cement analyzer (UCA);the acoustic impedance of the cement can be cal-culated from the traveltime. Alternatively,cementing design and evaluation software, suchas the CBL Adviser module in the CemCADE pro-gram, can estimate acoustic impedance beforecementing operations begin. Then the log can berescaled or simply interpreted by consideringhow acoustic impedance will affect the measure-ments. For ultrasonic logs, this is a matter ofproperly setting the threshold acousticimpedance between liquids and solids as a func-tion of the acoustic impedance of the mud thatwas displaced and the set cement behind the

0.00 bbl/min

0.00 bbl/min

0.00 bbl/min

54%

59% 3.28

0.0049%0.0 lbm/gal

0.0 bbl/min 16:18:27

56.0%

> Real-time quality control. A laptop computer (bottom) with SFM softwareinstantly displays critical data in convenient, readable formats (top).

8. For more on cement evaluation: Jutten J and Morriss S:“Cement Job Evaluation,” in Nelson EB: Well Cementing.Sugar Land, Texas, USA: Schlumberger Dowell (1990):16-1–16-44.

casing. Also, the maximum scale of the acousticimpedance and cement maps should be adaptedto the acoustic impedance of the set cement. Forsonic logs, the CBL Adviser module is used topredict the 100% bond amplitude or attenuationwith which the measured values are compared.

Perhaps the most significant informationgained from cement-evaluation efforts iswhether a primary cement job is adequate. Thisis the basis for determining if remedial cement-ing operations are necessary. In regions ofextreme lost circulation, the definition of “ade-quate” may range from cement covering a criticalzone to 100% bonding from total depth to theprevious casing shoe.

Preventing Corrosion in Weak Abu Dhabi FormationsThe Simsima and Umm El Radhuma formations ofAbu Dhabi, UAE, comprise weak carbonate rocksprone to massive circulation losses during drillingand cementing operations (above left). The AbuDhabi Company for Onshore Oil Operations(ADCO) addresses these concerns, in addition tolocal regulations, with customized casingdesigns and fluid programs that minimize lost cir-culation and casing corrosion.9

Corrosive formation brines can attack casingunless the cement sheath completely isolatesand protects the casing (left). Conventional prac-tice is to cement the casing in two stages and toperform a top job if cement does not reach thesurface. However, stage operations and top jobsare less desirable for long-term isolation. Stage-cementing operations are complicated and havea relatively high failure rate. The stage tool,which is similar to a sliding sleeve, tends to be aweak point that is prone to corrosion. Casingleaks may develop at the stage tool later in thelife of the well.

Cementing to surface in a single-stageoperation is the optimal approach because iteliminates the potential for leakage from a stagetool and the possibility of inadequate linear andradial coverage by a top job. Selecting the high-est quality primary cement is a practical businessinvestment because this reduces the need forremedial cementing operations during the life ofthe well. It is equally important for set cement toprotect the environment after well abandonment

8 Oilfield Review

SAUDI ARABIA

IRAQ

IRAN

KUWAIT

UNITED ARABEMIRATES

OMAN

The Gulf

Gulf of Oman

N0 150 300 miles0 200 400 km

> The Middle East. Several carbonate formations in the Middle East are prolifichydrocarbon zones, but prone to lost circulation.

3600

3700

Dept

h, ft

0 0 555

Flux leakage,upper array

Eddy current,upper array

Eddy current,lower array

Flux leakage,lower array

V V V V

> Evidence of corrosion. Exterior corrosion occurs when aggressive fluidsflow through permeable cement. Corrosion can be seen in casing photographs(left) and PAL Pipe Analysis Log readings (right). Flux leakage is an indicatorof total corrosion; eddy current leakage is a sign of internal corrosion.Corrosion in the upper casing is low, except for a small hole around 3602 ft.In the lower casing, there is massive external corrosion, indicated by thehigh flux leakage from 3712 to 3744 ft, and minor internal corrosion in thesame interval.

Summer 2001 9

by isolating freshwater zones, preventing fluidmigration to surface and maintaining theintegrity of casing-cement and cement-formationbonds long after well abandonment.10 For thispurpose, ADCO considers the life span of a wellto be 50 years.

Placing cement is difficult because circulationlosses occur routinely in the Simsima and UmmEl Radhuma formations. Emulsion mud or aerateddrilling fluids with densities of 8.0 lbm/gal [0.96 g/cm3]—less than the density of water—minimize losses during drilling; lightweightcement slurries are necessary to avoid fluidlosses during cementing operations. Also, theset-cement must have low permeability to mini-mize the potential for casing corrosion.

ADCO uses three different casing andcementing schemes according to whether thewell is intended for light or heavy development,or gas well or appraisal purposes (below).Lightweight LiteCRETE systems are a key part ofeach design because they can be pumped to sur-face without fracturing the formation or inducingcirculation losses. Set-cement properties, partic-ularly low permeability and extremely low acidsolubility, protect the casing from corrosion.

Since the volume pumped in each cement job was expected to exceed 500 bbl [80 m3], the ability to mix slurry continuously was crucial.The SFM system was applied first in Abu Dhabi,and as of June 2001, 27 LiteCRETE jobs had been performed there. Of these, 25 had cementreturns to surface.

One of the many successful LiteCRETE opera-tions in Abu Dhabi involved a well that required95⁄8-in. casing in a 121⁄4-in. openhole sectionextending from 1670 to 8355 ft [509 to 2547 m].ADCO wanted to cement the casing in a single-stage operation. Lightweight LiteCRETE slurrywas proposed for the lead slurry and mixed at

Light developmentwell

Heavy developmentwell

Appraisal orgas well

133⁄8-in.casing shoeat or aboveRus

Dammam limestone

Nahr Umr shale

Pay zones

Rus anhydrite/dolomite/limestone

Umm El Radhumaand Simsima limestonelost-circulation zones

Fiqa marl and shale/limestoneShilaif limestone

95⁄8-in. casingacross pay zone

133⁄8-in.casing shoeat Fiqa

95⁄8-in.casing shoeabove pay zone

> Customized casing and cementing designs in Abu Dhabi. For development wells, 133⁄8-in. casing maybe set below either the Dammam formation (left) or Simsima and Umm El Radhuma formations (center).The 95⁄8-in. production casing is set below the Nahr Umr shale, which is sensitive to water-base fluidsand requires high hydrostatic pressure to control. In both designs, the challenge is to get the highestpossible cement quality. For gas or appraisal wells, 133⁄8-in. casing is set below the Simsima and UmmEl Radhuma formations before penetrating the pay zone (right). In all cases, lightweight LiteCRETE slurriescan be pumped to surface, solving lost-circulation problems while providing complete zonal isolation.

9. Mukhalalaty T, Al-Suwaidi A and Shaheen M: “IncreasingWell Life Cycle by Eliminating the Multistage Cementerand Utilizing a Light Weight High Performance Slurry,”paper SPE 53283, presented at the SPE Middle East OilShow, Bahrain, February 20-23, 1999.

10. For more on cementing for permanent well abandon-ment: Slater HJ, Stiles DA and Chmilowski W:“Successful Sealing of Vent Flows with Ultra-Low-RateCement Squeeze Technique,” paper SPE/IADC 67775,presented at the SPE/IADC Drilling Conference andExhibition, Amsterdam, The Netherlands, February 27–March 1, 2001.

50434schD02R1 10/15/01 12:41 PM Page 9

8.3 to 9.5 lbm/gal [0.99 to 1.14 g/cm3].11 SFMtechnology enabled the crew to maintain a solidfraction of approximately 55% (left). The tailslurry was 15.8-lbm/gal Class G Portland cement.Both slurries were displaced at 12 bbl/min [1.9 m3/min] by the rig pumps without losses, and30 bbl [4.7 m3] of slurry returned to surface.12 Ashoe-bond test performed to 1650 psi [11.4 MPa]was successful.

To ensure zonal isolation and casing cover-age, USI, CBT and Variable Density log toolswere run in combination to demonstrate cementquality. However, cement-map readings forLiteCRETE cements had to be estimated beforelogging so that reasonable cutoff values for goodcement could be incorporated in the evaluation.The UCA tool was used to measure the acousticimpedance of LiteCRETE cement. CBT amplitudefor 100% and 80% bond with a LiteCRETE systemwas estimated using CemCADE cementing-simu-lation software before logging. The logs clearlyindicate that high-quality cement filled the annu-lus and covered the entire zone (next page). Theresults also matched predictions made during theplanning stage. Within 22 hours, the compressivestrength of the LiteCRETE cement exceeded 2100 psi [14.5 MPa] (bottom left).

10 Oilfield Review

Slur

ry d

ensi

ty, l

bm/g

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8:01 8:06 8:11 8:16 8:21 8:26 8:31 8:36 8:41 8:46 8:51 8:56 9:01 9:06 9:11 9:16Time, hours and minutes

0

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> SFM technology to ensure consistent solids content. Cementing operations in Abu Dhabi requiredlightweight slurry to avoid circulation losses. In this example, lead slurry density (green curve) washeld to values substantially below 10 lbm/gal [1.20 g/cm3] while the solid fraction (red curve) remainedrelatively constant.

11. “Lead” refers to the first slurry pumped during primarycementing operations. “Tail” refers to the last slurrypumped during primary cementing operations. Typically,the tail slurry covers the pay zone and is denser thanthe lead slurry.

12. Returns are an indication of the quality of a cementingoperation, and the only indication of losses. If returnsare observed and pumping pressures remain within the expected range during the operation, then no prob-lems are expected. If returns are not observed, or onlypartial returns are observed, then losses occurred during the operation. In this case, the top of cement will not be as high as planned and remedial cementingmay be necessary.For more on evaluation of cementing operations: PiotBM and Loizzo M: “Reviving the Job Signature Conceptfor Better Quality Cement Jobs,” paper IADC/SPE 39350,presented at the IADC/SPE Drilling Conference, Dallas,Texas, USA, March 3-6, 1998.

200

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> Compressive-strength development in ultralightweight cement. The 8.3- to 9.5-lbm/gal LiteCRETEslurry began to set within 16 hours. It ultimately developed a compressive strength of more than2100 psi [14.5 MPa].

Summer 2001 11

Maximumamplitude

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impedance

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Averageinternalradius

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in.5 4

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classification

4900

5000

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5400

5200

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< Cement evaluation in Abu Dhabi. The cementmap, Track 9 in the USI log (top), shows thatcement is evenly distributed around the casing.Track 1 shows the tool eccentricity (red) andcasing-collar locator (blue). USI processingflags appear in Track 2 and amplitude inTrack 3. Track 4 displays casing diameters.The casing-diameter map is shown in Track 5.In Track 6, the blue curve indicates maximumcasing thickness, minimum is shown in redand average thickness is black. Gamma rayappears in green. Track 7 shows acousticimpedance, approximately 4 Mrayl. The bondindex is shown in Track 8.

CBT Cement Bond Tool data (bottom)include gamma ray (green) and transit times(blue and red) in Track 1. The casing-collarlocator (green) and cable tension (black)appear in Track 2. Amplitude is shown inTrack 3 and the Variable Density display isshown in Track 4.

The amplitude, 35 millivolts (mV), is higher than the 10 mV expected for this combination of cement and casing. This response typicallyoccurs in instances of channeling, cementcontamination or the presence of a microan-nulus, which is a small gap between the cas-ing and the cement. The continuous cementconfirmed by the USI log eliminates the possi-bility of a channel. The acoustic impedance isslightly higher than the 3 Mrayl measured inthe laboratory, making contamination unlikelybecause contamination typically lowers theacoustic impedance. Thus, the CBT responsereflects the presence of a microannulusbetween the cement and the casing.

The microannulus was created duringpressure testing after the cement set. Thisexample clearly demonstrates the importanceof combining CBT and USI tools because theUSI tool is less sensitive to a liquid-filledmicroannulus than is the CBT tool. Formationarrivals, present throughout the VariableDensity log but most obvious at 5232 ft and5274 ft, indicate that cement is at least partiallybonded to the formation.

Ultralightweight Cementing in MexicoThe supergiant Cantarell field, located offshoreMexico in Campeche Bay, is Mexico’s largest oilfield (above). Discovered in 1979, it producesapproximately 1.6 million barrels [407,000 m3] ofoil per day, 42% of Mexico’s daily oil output, fromfractured or vugular Paleocene and UpperCretaceous carbonate formations. The field alsocontributes 30% of the gas production offshoreMexico. Lost circulation during drilling andcementing operations in this field is a major chal-lenge for the operator, PEMEX Exploration &Production, because of the potential for inducingfractures. The possibility of inadequate zonal iso-lation exists because placing a column of cementslurry high enough in the annulus is difficult.

Many cementing techniques have beenattempted with conventional cements, but theresults have not proven entirely satisfactory.Inadequate placement of lead and tail cementslurries in conventional operations led to highremedial cementing costs, and even then it wasnot possible to cover the entire cased section.The addition of a liner-top packer helped elimi-nate remedial cementing at the top of the liner,but slurry placement over the rest of the sectionremained challenging, even when using two

slurries. Operations using a single 1.35-g/cm3

[11.3-lbm/gal] conventional slurry resulted ininadequate isolation of the exposed formationand only modest improvement in the height ofthe cement column in the annulus.

The fracture gradient of the producing LaBrecha formation is 5.88 kPa/m [0.26 psi/ft].Formation permeability can be as high as 5 dar-cies. The formation is drilled using 65% diesel-emulsion drilling fluid with a density of 0.89 g/cm3

[7.4 lbm/gal]. Circulation losses are so great thatthere are no fluid returns to surface during drilling.The low-density drilling fluid may help movedrilling debris into natural fractures and vugs,limiting fluid losses during cementing operations.Since there is no other means to maintain wellcontrol during drilling and cementing, seawateris pumped down the annulus during drilling tocontrol gas migration.

Cement slurry with a density similar to that ofthe drilling fluid is essential to minimize furtherlosses into the formation. It is impractical to usefoamed cement because of inadequate set-cement properties at such low density. LiteCRETEslurries thicken in only 3 hours, reach a highcompressive strength of 2000 psi [13.8 MPa] in 16 hours, have relatively low fluid loss (26 cm3/30 minutes) and have extremely low den-sities, properties the operator values.

Ultralightweight slurries have been used suc-cessfully in three wells in Cantarell field. Forexample, 1.1-g/cm3 [9.2-lbm/gal] LiteCRETEslurry was used in Well 2091, which was deep-ened to 2905 m [9531 ft] and deviated as much as56° to search for additional oil reserves. Severallost-circulation zones were penetrated, with15,300 bbl [2430 m3] of drilling fluid lost.Nevertheless, a 5-in. liner was cemented suc-cessfully using 1.1-g/cm3 LiteCRETE slurry (nextpage). SFM technology was used to continuouslymix slurry and control its quality. For the first timein this field, the slurry completely covered theannulus, a key accomplishment in this challeng-ing environment. The shoe was tested success-fully to 500 psi [3447 kPa].

In Cantarell Well 53D, fluid losses duringdrilling totaled 7100 bbl [1130 m3]. A 95⁄8-in. linerwas cemented successfully across several zonesof lost circulation using 1.1-g/cm3 continuouslymixed LiteCRETE slurry. The SFM system ensuredthat the slurry had a 53% solid fraction and washomogeneous, stable and easy to pump. In theCantarell field, it is typical to have no returns, butpartial returns were observed during this job.

The 5-in. liner in a third well, Cantarell Well 61,was cemented using 1.1-g/cm3 LiteCRETE slurry

12 Oilfield Review

MEXICO

MEXICO

Cantarell

Gulf of Mexico

N 0

0 25 50 miles

25 50 75 km

> Cantarell field, Mexico.

Summer 2001 13

VariableDensity log

Top of 5-in.liner at 2361 m

Bottom of5-in. liner at2901 m

75⁄8-in.liner at 2565 m

Bondingline

2485 to 2510 mopen interval,total lostcirculation Top of cement

at 2490 m(70 m above75⁄8-in. casingshoe)

µsec

Collars AmplitudeMin200 1200

MaxDiscriminatedsynthetic CBL

mV 1000

Tension,lbf

0 100Gamma ray

API 1000

, Isolating the pay zone in Cantarell Well2091. Cement evaluation with the CBT deviceconfirmed that, for the first time in Cantarellfield, cement covered the entire sectionbehind the 5-in. liner, as shown in the well-bore schematic diagram (left) and log (right).Track 1 shows the gamma ray log (green),transit times (blue and red) and casing-collarlocator (black). Cable tension appears inTrack 2. Amplitude, displayed in Track 3, isrelatively low below 2490 m, which confirmsthe presence of cement behind the casing.Variable Density data appear in Track 4, withweak or nonexistent casing and formationarrivals below 2490 m indicating cementbehind the casing. The higher amplitude andstrong casing arrivals above 2490 m demon-strate that there is no cement above 2490 m.The cement bond log did not reach totaldepth because the well deviated 56°.

after drilling fluid losses of 14,800 bbl [2350 m3].The top of cement was logged at the top of theliner, and the CBT log showed more than 90%bonding across the cemented section (above).Again, SFM technology was applied, recordingstable solid fraction and density during continu-ous mixing operations.

PEMEX plans to drill 90 more wells in theCantarell field. Another future project, develop-ment of deeper oil reserves in the Sihil trapbelow Cantarell field, also is expected to benefitfrom ultralightweight cementing technology.

Eliminating Multistage Cementing Optimal cementing practices can solve problemsby eliminating multistage cementing operations,limiting the need for remedial cementing andproviding excellent zonal isolation withlightweight slurries. In many fields in the MiddleEast, well cementing is challenging, especiallygetting cement returns to surface. Circulationlosses and the low fracture gradient in carbonateformations necessitate use of lightweightcement. The fracture gradients can be as low as

8.2 lbm/gal, meaning that a fluid column consist-ing only of water can fracture these formations.

To further complicate matters, the potentialexists for casing corrosion by formation waters inseveral formations if the isolation performance ofthe cement is inadequate.

As in any other region, balancing cost andquality is important to operators in the MiddleEast; remedial cementing adds expense andcomplicates field operations. Given the need forhigh-quality set cement and low-density slurry,operators have used CemCRETE technology forseveral years.

The lighter LiteCRETE slurries allow operatorsto combat casing corrosion, achieve good zonalisolation and avoid crossflow across lost circula-tion zones and weak formations. Lightweightslurries allow single-stage cementing with aslurry that, when set, exhibits good compressivestrength and low permeability to invading forma-tion fluids.

In many cases, two-stage operations arenecessary because of the vast length—oftenexceeding 3500 ft [1067 m]—of uncementedannulus and the weakness of the formations. Inone well, the first stage consisted of 71 bbl [11 m3] of 8.2-lbm/gal LiteCRETE slurry pumpedahead of the 15.8-lbm/gal [1.9-g/cm3] tail slurry.In the second stage, 240 bbl [38 m3] of 8.2-lbm/gal LiteCRETE slurry preceded 131 bbl[21 m3] of 12.5- to 15.8-lbm/gal [1.50- to 1.90-g/cm3] conventional cement slurry. Theoperation proceeded smoothly, with partialreturns at surface. A top job of 20 bbl [3 m3]brought the cement level to surface, indicatingthat the top of cement achieved with the LiteCRETEjob was relatively high. Previously, three or four top

14 Oilfield Review

Top of 5-in.liner at 2460 m

2520 to 2545 mopen interval,total lost circulation

Partial to total lostcirculation while drilling

7-in. linerat 2596 m

Bottom of5-in. linerat 3004 m

VariableDensity log

Bondingline

µsec

Collars AmplitudeMin200 1200

MaxNear

synthetic CBLmV 1000

Tension,lbf

0 100Gamma ray

API 1000

> Continued success. Cantarell Well 61 also has LiteCRETE cement placedhigh in the 5-in. liner despite massive lost-circulation challenges. Track 1shows the gamma ray log (green), transit times (blue and red) and casing-collar locator (black). Cable tension appears in Track 2. Amplitude is displayedin Track 3 and Variable Density data appear in Track 4. The top of cementappears above 2550 m, evidenced by the dramatic increase in amplitude abovethat depth and the abrupt character change in the Variable Density log.

13. Pozzolan cement is made from siliceous material pro-duced by volcanic activity or burning coal.

14. For more on advances in cement systems: Le Roy-Delage S, Baumgarte C, Thiercelin M and Vidick B:“New Cement Systems for Durable Zonal Isolation,”paper IADC/SPE 59132, presented at the IADC/SPEDrilling Conference, New Orleans, Louisiana, USA,February 23-25, 2000.Baumgarte C, Thiercelin M and Klaus D: “Case Studiesof Expanding Cement to Prevent MicroannularFormation,” paper SPE 56535, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3-6, 1999.Thiercelin MJ, Dargaud B, Baret JF and Rodriguez WJ:“Cement Design Based on Cement MechanicalResponse,” paper SPE 38598, presented at the SPEAnnual Technical Conference and Exhibition, SanAntonio, Texas, USA, October 5-8, 1997.

15. Mohammedi N, Ferri A and Piot B: “Deepwater WellsBenefit from Cold-Temperature Cements,” World Oil 222,no. 4 (April 2001): 86, 88 and 91.Piot B, Ferri A, Mananga S-P, Kalabare C and Viela D:“West Africa Deepwater Wells Benefit from Low-Temperature Cements,” paper SPE/IADC 67774, pre-sented at the SPE/IADC Drilling Conference andExhibition, Amsterdam, The Netherlands, February 27–March 1, 2001.

Summer 2001 15

jobs were required to bring cement to surface. The24-hour compressive strength of the LiteCRETEslurry was 1175 psi [8101 kPa].

In another well, 133⁄8-in. casing was cementedfrom 3368 ft [1027 m] to surface in two stages.Previously, similar wells were cemented in three-stage operations. A key objective was to isolatea shallow zone prone to lost circulation.

The hole was drilled with 8.6-lbm/gal [1.03-g/cm3] drilling fluid, so 315 bbl [50 m3] of8.4-lbm/gal [1.00-g/cm3] LiteCRETE slurry waspumped first, followed by 30 bbl [4.7 m3] of ordi-nary 15.8-lbm/gal Class G Portland cement.Cementing operations proceeded flawlesslyaccording to design, with 98% returns of the leadslurry and 100% returns of the tail slurry in thefirst stage of the operation. The solid-fraction

target of 54% was maintained using SFM tech-nology (above). At 24 hours, the compressivestrength of the LiteCRETE slurry was 1300 psi[8963 kPa] at 119°F [48°C]. The second stage,which consisted of 152 bbl [24 m3] of 13.5-lbm/gal [1.62-g/cm3] pozzolan slurry,resulted in 100% returns.13

Future DevelopmentsLiteCRETE technology is succeeding in environ-ments where other lightweight and ultra-lightweight cements have proven suboptimal,making it possible to isolate low-pressure zonesthat cannot tolerate fluids heavier than water. As of June 2001, more than 35 LiteCRETE jobs at densities lower than 10 lbm/gal [1.20 g/cm3]had been performed in Europe, the Middle East,and Central and South America. Most of these

operations involved continuous mixing with new SFM technology. The total volume pumped usingSFM technology exceeds 25,000 bbl [3970 m3]with no failures.

The success of engineered particle-size distri-butions is spurring development of technology formore demanding cementing applications. Newapplications of the technology offer tougher andmore flexible cements.14 Deepwater cementing atlow temperatures is also improving as newcementing technology is modified to suit the mostextreme cementing conditions.15 High-temperaturecementing remains a challenge, but work is alsounder way to meet the specific demands of diffi-cult cementing environments. —GMG

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> Operating according to design. SFM technology (top) helped field engineers maintain the solidfraction target of 54% (bottom) throughout cementing operations.

16 Oilfield Review

Raising the Standards of Seismic Data Quality

Phil ChristieDavid NicholsAli ÖzbekCambridge, England

Tony CurtisLeif LarsenAlan StrudleyGatwick, England

Randall DavisHouston, Texas, USA

Morten SvendsenAsker, Norway

For help in preparation of this article, thanks to Mark Egan,Olav Lindtjorn and Steve Morice, Gatwick, England; andPeter Canter, Leendert Combee, James Martin and Nils Lunde, Asker, Norway. Special recognition to all themembers of the Receiver, Positioning and Central

Seismic data just got better, thanks to a group of engineers and geophysicists who

developed the world’s most advanced marine seismic acquisition system. The clarity

of the new images has to be seen to be believed.

In the last 20 years, the oil and gas industry hasbenefited from remarkable advances in seismictechniques. Where once surveys covered a two-dimensional sliver of the subsurface, they nowilluminate three-dimensional volumes. Marineacquisition that began with a single cable of sen-sors in tow now involves deployment of an arrayof streamers covering an area the size of a golfcourse. Marine and land surveys are prepro-cessed onboard or in the field, reducing dataturnaround from years to weeks. Multi-component seabottom cables record compres-sional and shear waves for analysis of reservoir

lithology and fluid content. Sophisticated dataprocessing and improved computing capabilitiesallow geophysicists to extract images from noto-riously difficult settings such as complex faultzones, below salt and beneath shallow gas.Time-lapse recordings help scientists understandand track changes in reservoir fluids, pressuresand stresses as hydrocarbons are produced, facil-itating optimal exploitation of reserves.

These innovations are helping make seismicdata a vital tool for every stage of the E&P effortat a time when many oil companies are empha-sizing enhanced production from existing assets.

Acquisition Domains at the Oslo Technology Center,Norway, for contributing to the world-class engineeringeffort described in this article.Monowing, Q, Q-Fin, Q-Marine and TRINAV are marks ofWesternGeco.

Summer 2001 17

Optimization and fast-track delivery of newassets from ever fewer wells increase relianceon reservoir geophysics to build subsurface mod-els with real predictive power.

Because so many of the newly inventeduses—imaging for well placement, predictingpore pressure and monitoring fluid fronts—require extremely accurate data, there is a height-ened demand for data of the highest possiblequality. For seismic data, high quality is defined ashigh signal-to-noise ratio and wide bandwidth, orrange of frequencies contained in the signal. Overthe years, tremendous care has gone into devel-oping survey-design programs and efficient data-processing schemes to increase signal quality byenhancing acquired signal bandwidth and ampli-tudes and suppressing noise to get the most outof every bit of data acquired. But the questionmust be asked: can seismic data get any better?

The answer is yes, but to understand how, wemust first examine the problem of noise.

What Causes Noise?About 10 years ago, scientists and engineers atwhat is now WesternGeco began to look at theheart of the noise problem. They proposed a con-ceptually simple, two-part campaign to improvemarine data quality. First, identify every signifi-cant source of noise in seismic data, then sup-press or minimize it.

Through a holistic analysis of data from exist-ing acquisition systems and additional modeling,they were able to quantify the level of noise rel-ative to signal for each noise type (above).Dozens of potential causes were considered,including source and receiver positioning, distor-tions due to source variations, receiver sensitivity,recording electronics, and water and vessel

motion. The dominant noise sources were foundto be swell and wave action at the surface, vari-ation in source characteristics and positioningerrors associated with receiver groups. In somecases, noise levels were high enough to makeinterpretation of the resulting images difficult.Only by reducing noise to its lowest possiblelevel would seismic data be usable for reliablestratigraphic and time-lapse interpretation.

This article chronicles efforts by geophysi-cists, engineers and signal-processing experts tominimize these sources of noise, enhance signalquality and produce images suitable for detailedinterpretation. We describe how traditionalmethods of acquisition and noise suppression fall short and how advances in acquisition systems—especially a new point-receiverapproach—are helping to produce a quantumleap in seismic data quality.

> Significant sources of noise detected in marine seismic data. Horizontalbars show levels of noise present in standard processed data. Effects ofswell noise and source-signature variation can be ameliorated by processingthat reduces noise to levels indicated by arrows. Vertical color bands showthe level of noise that can be tolerated in different applications of interpretedseismic data. For structural interpretation, higher noise levels can be toleratedthan for stratigraphic interpretation, and interpretation of seismic data fortime-lapse reservoir monitoring requires the lowest possible noise levels.

Sensor-sensitivity variation,hydrophone drop-outs

Swell noise

Source-signature variation

Source directivity

Positioning accuracy

Positioning repeatability

Time-lapse reservoir monitoring

Stratigraphic interpretation

Structural interpretation

Decreasing Noise Level Beneath the Signal

Traditional Marine AcquisitionMarine seismic surveys are acquired by shipstowing streamers, or instrumented cables, torecord signals from shots fired as the vesselmaneuvers across the target (right). A typicalstreamer is 3000 to 8000 m [9800 to 26,200 ft]long and, in conventional acquisition, carrieshundreds of receiver groups of 12 to 24 hydro-phones feeding to a single recording channel(below). In principle, summing the detected signals before recording—a step called arrayforming—enhances signal-to-noise ratio. How-ever, array forming can irreparably damage signalfidelity and reduce the effectiveness of subse-quent processing steps aimed at attenuatingnoise traveling down the streamer. To minimizesea-surface wave noise, streamers are towed ata depth specified in the survey-planning stage,usually 6 to 10 m [20 to 33 ft]. Towing at shal-lower depths can increase the high-frequencycontent of the recorded signal, but usually alsoincreases noise level.

High-performance acquisition vessels cantow 12 to 16 streamers spaced 50 to 100 m [160to 330 ft] apart. Deflectors based on Monowingmultistreamer towing technology are deployed atthe front of the streamer to help maintainstreamer spacing.1 While the Monowing devicescontrol streamer separation at the front, whathappens behind that point is subject to nature.Currents, tides and other forces can causestreamers to feather, or drift laterally from programmed positions, and in extreme cases,tangling can occur. Tangled streamers have to be reeled back to the vessels and untangled manually, resulting in nonproductive time.

Any application of seismic data requires accu-rate position information, and some uses, such astime-lapse seismic monitoring, demand repeat-able positioning. To ensure that the acquisition

arrangement is accurately documented, position-ing sensors are used to determine the position ofevery source and receiver at every shot point asthe vessel moves. Global Positioning System(GPS) measurements use satellites to pinpointthe vessel position to within three meters. Withtraditional systems, positions of seismic sourcesand receivers relative to the vessel are calcu-lated using information from acoustic andstreamer-mounted heading sensors in networks

at the front and tail of the streamer (next page, far right). The front and tail positions of thestreamers are known accurately. However, thepositions of individual sensors are estimated froma streamer shape that is calculated by use ofstreamer-mounted heading sensors placed at afew locations along the streamer, which canintroduce significant errors.

18 Oilfield Review

> Streamers, or instrumented cables, for recording signals as the seismic vessel moves across the target.

> Interleaved groups of hydrophones feeding to a single recording channel. Signals from each hydrophone in a group are summed to produce a singlerecorded trace per group.

Conventional Analog Groups

Single conventional group, 24 individual hydrophones

12.5-mgroup interval

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16.12-mgroup length

Summer 2001 19

The typical seismic source is an array com-posed of subarrays each containing up to six airguns separated by about 3 m [10 ft] (below). Like streamers, air-gun arrays also are towed ata depth of 6 to 10 m. Arrays that are towed tooshallow produce insufficient output; instead ofthe air-gun burst traveling downward, it producesonly bubbles at the sea surface because there isnot enough hydrostatic pressure to form themproperly. Sources produce signals that arealtered by destructive interference between thedirect sound waves that travel downward andthose that travel up first and reflect off the seasurface—ghosts—just a few milliseconds later.Receivers similarly suffer from interferencebetween the upcoming reflections and downgo-ing ghosts reflected off the sea surface. The shal-lower the source or streamer, the more thehigh-frequency content in the recorded signal,but the greater the loss of deeply penetrating lowfrequencies and the higher the noise. The deeperthe source or streamer, the greater the low-fre-quency content and the lower the noise, but atthe cost of losing high-frequency signal. The sig-nature of a source array can vary from shot toshot depending on variations in individual gun fir-ing times, gun-chamber pressure, array geometryand drop-out—failure of a gun to fire. Theseshot-to-shot variations can reduce the accuracyand repeatability of seismic surveys.

Improved Marine AcquisitionWesternGeco geophysicists and engineers devisedways to suppress the streamer-, positioning- andsource-related noise that plagues traditionalacquisition. Several teams at the Oslo TechnologyCenter in Norway cooperated to overcome thetremendous technical challenges involved in per-fecting the Q point-receiver technology. The prod-uct of their labor, the Q-Marine system, deliversmarine seismic data of unsurpassed quality. Thenew system includes improvements in receiversensitivity and positioning accuracy, steerablestreamers, enhanced source control and point-receiver acquisition to consistently provide repeat-able high-quality data.

To solve the problem of receiver sensitivityvariation, manufacturing engineers stipulatednew high-fidelity tubular hydrophones with tightand stable sensitivity specifications. Hydro-phones typically experience hydrostatic pres-sures that may affect sensitivity over time, oreven destroy the sensors. The new hydrophoneshave much higher survival-depth tolerances andmore stable sensitivities because they are pre-aged in the manufacturing process and performconsistently thereafter. Each hydrophone has itsown calibration certificate, and all sensitivity values are stored in the streamer front-end electronics for automatic data calibration.2

3000-m distance

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Source> Positioning networks at the front (top)and tail (bottom) of the streamers. GlobalPositioning System (GPS) sensors, head-ing sensors (compasses) and acousticsensors provide measurements to helpcalculate the position of the sources andreceivers in the streamer array.

> Air-gun subarrays each containing six air guns. The quality of every seismic shot depends on thesize, location and firing timing of each gun in the array.

6- to 10-mtowingdepth

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Typical Configuration

15- to 20-msubarrayseparation

1. Beckett C, Brooks T, Parker G, Bjoroy R, Pajot D, Taylor P,Deitz D, Flatten T, Jaarvik LJ, Jack I, Nunn K, Strudley Aand Walker R: “Reducing 3D Seismic Turnaround,”Oilfield Review 7, no. 1 (January 1995): 23-37.

2. Svendsen M and Larsen L: “True 4D-Ready-SeismicUtilizing Q-Marine,” paper OTC 13163, presented at theOffshore Technology Conference, Houston, Texas, USA,April 30-May 3, 2001.

With recent advances in electronics and fiber-optic networks, the system can record more than4000 hydrophones per 12-km [8-mile] streameron up to 20 streamers, for a maximum of 80,000channels. The resulting 4-fold increase in band-width capacity compared with conventionalacquisition systems opens the possibility ofbringing raw point-receiver data up to the vesselfor advanced processing with digital group-forming algorithms, discussed later in this article.

The new acquisition system carries an acous-tic ranging system along the full length of thestreamer. Distinctive acoustic sources spacedevery 800 m [2600 ft] along the streamers emitsignals that can be recorded at any seismichydrophone. The relative timing of each arrivalallows a set of ranges, or distances betweensource and hydrophone, to be computed acrossthe entire network (below left). The acousticranges are used as input to a ranging-network

adjustment that extends between GPS readings.The result is an absolute positioning accuracy towithin 4 m [13 ft] anywhere along the streamers.The computational power required for solving thein-sea network adjustment is many times greaterthan that required for the conventional solution.

While all traditional acquisition systemsallow control of streamer depth, only the Q-Marine approach enables active horizontalsteering in addition to depth control. Streamer

20 Oilfield Review

> The new Q-Marine positioning system deploying a full acoustic network along the entirestreamer length. Receiver positioning can now be calculated to within 4 m [13 ft] anywherealong the streamer. In addition to range information (orange) from the tail (left) and frontnetworks (right), the full-streamer network for this 10-streamer configuration calculatesranges at hundreds of intermediate points (blue).

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> The Q-Fin steering device for controlling streamer separation and position by steering thestreamer horizontally and vertically.

Summer 2001 21

orientation can be modified laterally for optimalcoverage, allowing streamers to be towed at separations as close as 25 m [82 ft] with greatlyreduced risk of tangling. Narrow streamer sepa-ration allows higher resolution sampling forimproved imaging, and in-sea equipment can besteered safely near potential hazards such assurface installations. Steerable streamers areideal for reservoir surveys because they allowsignificantly faster vessel turns, a major time-saving in relatively small-acreage surveys.

Steering control improves logistics involved instreamer deployment and retrieval, making theback deck safer. Acquisition operations are saferbecause less time is spent on the back deck.3

Steering devices are located every 400 to800 m [1300 to 2600 ft] along the streamer. TheWesternGeco Q-Fin steering system has indepen-dently controllable wings to steer streamers up,down, and side to side (previous page, bottom).Unlike traditional devices that are clamped on tohang below the streamer, the Q-Fin assemblage is

an integral part of the streamer. This innovativeconfiguration maximizes hydrodynamic lift andhelps minimize acoustic noise associated withstreamer steering.

The Q-Fin mechanism is controlled by a steer-ing controller, which compares calculatedstreamer positions in the navigation system withthe desired positions, and adjusts streamer ori-entation as required (above). The controller

Range data

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TRINAV navigation systemStreamers

> Flow of streamer steering data. Positioning data from the streamer are fed to the positioning controller, whichcalculates streamer positions in terms of ranges, or distances, between hydrophones. The TRINAV navigationsystem uses the ranges to calculate actual positions, which are recorded as navigation data, and also passesthe positions to the steering controller to feed back changes if required.

3. Swinsted N: “A Better Way to Work,” Oilfield Review 11,no. 3 (Autumn 1999): 46-60.

computes the forces required by each steering finto bring all streamers to their appropriate loca-tions (above).

The steering capability of Q-Marine stream-ers reduces the need for infill lines—lines thatare shot to fill gaps after the bulk of acquisitionis completed. This translates into shorterturnaround time for surveys and less nonproduc-tive time. Better steering also produces higherquality data, because consistent seismic linespacing delivers more uniform areal coverage.

To reduce noise further, seismic-sourceexperts engineered improvements to the marineair-gun arrays, which generate both seismicenergy and unwanted noise. Variations from oneshot to the next in the output from an air-gunarray lead to unwanted noise in the recorded sig-nals. Gun-array control systems are designed toprevent this from happening, but events outsidethe tolerances of the control systems can lead tounacceptable levels of variation in the output ofthe array. Minor changes in air pressure at differ-ent guns and wave action at the surface can

result in an unpredictable source signature. Tocompensate for these situations, variations in thepressure field surrounding individual air guns—due to the presence of other air guns and otherhydrostatic pressure variations—must be mea-sured and calibrated.

Since the source signature must be removed,or deconvolved, from the recorded data beforefurther processing, the lack of a fully predictablesignature has forced geophysicists to rely on sta-tistically based deconvolution techniques.However, these provide only approximateanswers and may fail to account for source-gen-erated variations.

An advanced source-controller system and asignature-estimation technique solve this prob-lem. Source-control electronics on the air-gunsubarrays synchronize and fire each gun based onits acoustic output. Fiber-optic lines communi-cate with the vessel, replacing conventional two-way systems that can mistime gun firing as theysend signals to and from the vessel. GlobalPositioning System antennae deployed on eachsubarray provide accurate positioning of air guns.

The pressure signature near each gun is mea-sured for input to a signature-estimation tech-nique.4 A patented hydrophone arrangementadjacent to each air-gun element records acous-tic pressures and defines, for each air-gun ele-ment, a notional signature that does not containthe effects of pressure fields from other guns. Bysumming notional signatures from all the airguns together with the free-surface ghost reflections, a far-field signature, or the effectivesource output seen by the streamer hydrophones,can be computed.

An example of the power of the calibratedmarine source (CMS) technique comes from theOrca basin in the deep water of the Gulf ofMexico. In this basin, a salt body outcrops on theseafloor, increasing the salinity of the deepestwaters. The contrast in seawater salinity gener-ates a strong, isolated, horizontal reflection at3.0-sec two-way time, some 200 msec before

22 Oilfield Review

Survey 1 Survey 2

> Two surveys (left and right) with repeated streamer positions in a four-streamer test. For each survey, positions are calculatedfor the four streamers (top), showing a constant streamer separation. The forces required to achieve the desired positions areshown by white arrows (bottom).

Summer 2001 23

the reflection from the seabed (below). Withoutmarine-source calibration, variations in bubblesgenerated by the raw source are evident around3.15 sec. These variations, although they appearminor, affect later signals and can lead to erro-neous interpretations. After CMS deconvolution,bubble amplitudes and their variations are minimized so signals from deeper reflections are cleaner.

This combination of calibrated receiver sensi-tivity, enhanced recording capability, improvedstreamer positioning, better source control andsignature estimation sets the stage for the ultimate breakthrough that distinguishes the Q-Marine system from other marine seismic sur-vey techniques, and that is point-receiver acqui-sition. Point-receiver acquisition records tracesfrom individual receivers, whereas conventionalacquisition sums traces from a group of receivers

in a step called analog group forming, thenrecords that sum (see “Problems with SeismicRecording Using Arrays,” page 24 ).

The idea of acquiring data from each sensorindividually rather than as a group is not new. Inthe late 1980s, Shell geophysicists proposed asimilar method and discussed the potential bene-fits.5 They realized that the traditional techniqueusing an acquisition system composed of hard-wired groups did not produce optimal data. Theyalso showed how signal processing, or digitalgroup forming, could reproduce the desired filter-ing effects of analog group forming. However, theyacknowledged that the ultimate solution—a onechannel per hydrophone system—would requirestep changes in hardware and processing capabil-ities, and would not be adopted immediately bythe industry. The WesternGeco Q-Marine systemis the first to realize this point-receiver vision.

Seeing the DifferenceThe combination of advances introduced withthe Q-Marine system brings unsurpassed clarityto the resulting seismic images. An examplefrom the Garden Banks area in the Gulf ofMexico shows the improvements in signal qual-ity and resolution that can be achieved when all the noise-reduction and signal-boosting

Raw-source bubble variation

Bubble variation after source-signatureestimation deconvolution

Bubble Elimination, Deepwater Gulf of Mexico

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> Calibrated marine source in the Gulf of Mexico. The major reflection feature in this seismicsection is the salinity contrast imaged at 3.0 sec (top). Zooming in shows bubble signals thatarrive from 3.1 to 3.15 sec with varying arrival times and amplitudes (middle). Marine-sourcecalibration helps remove the variations in the bubble (bottom) so that interpretation of deeperreflections can be made with greater confidence.

4. Ziolkowski A, Parkes G, Hatton L and Haughland T: “The Signature of an Airgun Array: Computation fromNear-Field Measurements Including Interactions—Part 1,” Geophysics 47 (1982): 1413-1421.

5. Ongkiehong L and Huizer W: “Dynamic Range of theSeismic System,” First Break 5, no. 12 (December 1987):435-439.Ongkiehong L: “A Changing Philosophy in Seismic DataAcquisition,” First Break 6, no. 9 (1988): 281-284.

(continued on page 26)

24 Oilfield Review

Ever since the 1930s, when reflected seismicwaves were first used for petroleum explorationon land, signals have been acquired with groups,or arrays, of sensors. This technique, designedto facilitate land acquisition, was adopted laterfor marine acquisition. A brief review of acquisi-tion basics shows the advantages and disadvan-tages of the method.

Energy from an exploration seismic sourceradiates outward in several modes. On land,compressional and shear waves, called bodywaves, travel through the body of the earth,reflect off subsurface layers and return to sur-face sensors; these are the most useful wavesfor seismic imaging. Offshore, only compres-sional waves are generated. Not all the energyrecorded by surface sensors is usable for imag-ing. Waves that travel directly to the sensorwithout reflecting are considered noise, becausethey do not contribute energy to a reflectionimage. In addition to these direct arrivals, otherenergy modes can arrive as noise. On land, sur-face waves, called ground roll, travel along theground surface and add high-amplitude noise.In marine acquisition, waves originating in andtraveling along the streamers constitute noise.

When the reflecting surface at depth is hori-zontal, compressional and shear waves arriveback at the sensors along nearly vertical ray-paths, while much of the noise arrives nearlyhorizontally. Early on, geophysicists discoveredthat the different arrival directions could beused to dampen the amplitude of incomingnoise. Instead of recording arrivals on a receiver

Problems with Seismic Recording Using Arrays

1. Özbek A: "Adaptive Beamforming with Generalized LinearConstraints," Expanded Abstracts, SEG InternationalExposition and 70th Annual Meeting, Calgary, Alberta,Canada, August 6-11, 2000: 2081-2084.

Conventional Grouped Hydrophones, 12.5-m Group Spacing

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> A shot record acquired in relatively rough weather with conventionallygrouped hydrophones. High-amplitude wave noise that appears incoherentcan be seen on many traces at nearly all arrival times.

By recording signals at every receiver position digitally, the properly

sampled incoming wavefield, containing both signal and noise, can

be processed using sophisticated algorithms. This signal-processing

step, which improves upon the noise-suppression capability of a

hard-wired array, is called digital group forming. Digital group

forming can make use of processing techniques more powerful

than simple linear summation.

Summer 2001 25

at one point, they set up a group—called ahard-wired array—of receivers separated by nomore than one-half the dominant wavelength ofthe expected noise. This simple analog summa-tion of signals arriving at each receiver in thegroup attenuates much of the horizontally arriving coherent noise, but unfortunately mayalso attenuate the higher frequencies of signalsthat arrive nonvertically, such as from a dipping reflector.

By recording signals at every receiver positiondigitally, the properly sampled incoming wave-field, containing both signal and noise, can beprocessed using sophisticated algorithms. Thissignal-processing step, which improves upon thenoise-suppression capability of a hard-wiredarray, is called digital group forming. Digitalgroup forming can make use of processing techniques more powerful than simple linearsummation.1

Comparison of digitally formed array resultswith those from hard-wired arrays shows howwell the new technique works. A shot recordacquired with conventionally grouped hydro-phones at a standard 12.5-m [41-ft] group spacing displays high residual levels of weather-related noise that appears incoherent, and thusdifficult to filter out (previous page). At thesame time, a Q-Marine streamer, with closelyspaced digital traces, recorded the same shotsunder the same weather conditions (top left).The noise, properly sampled, is coherent andcan be filtered out through processing withoutaffecting the signal. The digitally array-formeddata, output with one channel every 12.5 m,have significantly reduced levels of the residual noise that dominated the conventional shotrecord (left).

> A shot record acquired simultaneously with the data acquired in theprevious-page figure, but with closely spaced Q-Marine point-receiverhydrophones. High-amplitude wave noise is present, but appears coherentand can be filtered out with processing.

> Q-Marine data. A shot record of digitally array-formed point-receiverdata output at larger trace spacing for comparison with the shot recordfrom the hard-wired array shows almost none of the high-amplitude noisethat contaminated the conventional shot record.

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techniques come into play (above). A conven-tional three-dimensional (3D) survey shot in mid-1997 for multiple clients produced an apparentlysatisfactory image. With Q seismic acquisitionand processing technology, a remarkablyenhanced image was delivered in 2000, eventhough the new section is only from a 2D line.The Q-Marine seismic section illuminates morelayers and small-scale features than the conven-tionally acquired section. Reflections that were

imperceptible in the older survey are clear andstrong in the newer image.

Another comparison, this time over the Dianafield, again shows the superior resolution andimaging power achievable with the Q system (next page, top). The image produced from a con-ventional 1999 survey shows the prospect as ahigh-amplitude feature on the flank of a saltdome. A Q-Marine survey shot over the same line images the field and overburden with greater resolution.

With Q-Marine technology, more high-frequency signal is preserved at all depths (next page, bottom). Whereas conventional sur-veys may contain usable 60-Hz signals at the tar-get depth, the Q system delivers frequencies upto 85 Hz at the same depth. This improvement inresolution allows more detailed interpretation ofsubtle features such as lateral stratigraphicchanges and time-lapse reservoir variations.

26 Oilfield Review

Garden Banks Conventional Line 3 Garden Banks Q-Marine Line 3

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> Comparing a conventional seismic section with one acquired using Q-Marine technology. A two-dimensional (2D) panel from a three-dimensionalsurvey (3D) acquired in 1997 with conventional streamers (left) in the Garden Banks area, Gulf of Mexico, shows several subsurface reflections.Results from a 3D survey should be superior to those from a 2D line, but in this case, the 2D line acquired in 2000 with Q-Marine technology (right)reveals more about the subsurface.

Summer 2001 27

Diana Field Conventional Data Diana Field Q-Marine Data

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> Conventional (left) and Q-Marine seismic data (right) from the Diana field, Gulf of Mexico. The Diana field appears as a dipping high-amplitudereflector in the lower right of each panel. The Q-Marine survey images the field and surrounding layers with higher resolution than can be obtainedwith conventional acquisition.

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> Average amplitude spectra for Diana field data acquired conventionally and with Q technology. Conventional data (left) contain useful(at least –30 dB) signal up to 60 Hz at the target depth. Q-Marine acquisition and processing (right) preserve high-frequency signals up to85 Hz at the same depth. Frequency spectra pertain to signals recorded in the interval 3.3 to 3.7 sec.

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Zooming in on part of the Diana prospect, theQ-Marine survey adds resolution at target depthto help delineate features that can affect layercontinuity (above). The conventionally acquiredsection shows a fairly continuous-looking reflector, while the Q image reveals possible discontinuities in the reservoir. The improvementin image quality achieved in Q surveys is making many operators question what they mayhave missed in earlier conventional surveys inother areas.

Repeatability for Reservoir MonitoringIn addition to enhancing imaging for structuraland stratigraphic interpretation, the Q-Marinesystem delivers surveys that can be used in time-lapse reservoir monitoring. Use of seismic datafor monitoring reservoir changes is based on eval-uation of differences between two seismic sur-veys acquired at different times separated by aperiod during which some aspect of the reservoir,such as fluid saturation, pressure or rock stress,has changed. Time-lapse monitoring attributes allobserved changes to the reservoir, not the seismic

recording system or background noise. The tech-nique is based on the premise that two surveysacquired at intervals during which no reservoirchange has occurred should be alike.

Repeatable positioning of streamers is key toreliable time-lapse surveys. When streamers areeven slightly off position, seismic lines acquiredonly days apart can show differences unrelatedto subsurface changes (next page, top). Properlyrepeating streamer positions minimize differ-ences between immediately succeeding surveys(next page, bottom).

28 Oilfield Review

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> A seismic close-up of the Diana prospect. The conventionally acquired survey (top) shows a relativelycontinuous high-amplitude reflection at the reservoir level, while the image derived from the Q survey(bottom) reveals a less continuous reflection.

Summer 2001 29

Survey 1 Survey 2 Difference

.When streamer position isnot repeated. Streamers thatare slightly off position duringrepeat surveys fail to delivertruly repeatable data. Theinsert (above) shows thestreamer positions in two shotsacquired within two days ofeach other (left and center).Subtracting one shot gatherfrom the other (right) showsdifferences related only tovariations in acquisition, sincethe subsurface did not changeduring the two-day period.

Survey 1 Survey 2 Difference

. Repeatable data with repeat-able positioning. When posi-tioning is properly repeated,time-lapse surveys show realsubsurface changes. Shotsfrom Survey 1 (left) and Survey2 (center) were acquired withrepeatable streamer positioning.Their difference (right) correctlyshows no difference in thesubsurface.

Streamer position

Streamer position

In another example from the Gulf of Mexico,a 2D line was acquired to serve as the baselinesurvey (above). Two days later, a second line wasacquired, under the same calm-sea conditions asthe first. The data were acquired from pointreceivers and processed identically using source-signature deconvolution and digital groupforming. Subtracting one line from the othergives an image of the difference between thetwo surveys (next page).

Measures of repeatability can be defined toquantify the likeness of two traces.6 One possiblemetric is the normalized root-mean square(NRMS) difference between two traces within a

given time window. The lower the NRMS, themore alike the traces. Another metric, pre-dictability, is a function of the correlated powerbetween two traces. The higher the predictabil-ity, the more alike the traces. The difference plotshows high repeatability values on the left half ofthe image and lower repeatability on the right.7

For this test, streamer position was not con-trolled. Strong currents caused the streamers to

feather, or deviate from their optimal positions,making it difficult to reproduce the streamer posi-tion on the repeat pass. When streamer locationsare not reproduced from one survey to the next,repeatability suffers. Strong trace similarities correspond to data for which acquired commonmidpoint (CMP) traces are in the same location.Lower trace similarities occur when CMP loca-tions differ across the two surveys.

30 Oilfield Review

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> Initial stacked section (top) acquired in calm seas for repeatability test. The repeat survey(bottom) was acquired under the same weather conditions two days later for quantifyingrepeatability.

6. Morice S, Ronen S, Canter P, Welker K and Clark D: “The Impact of Positioning Differences on 4DRepeatability,” Expanded Abstracts, SEG InternationalExposition and 70th Annual Meeting, Calgary, Alberta,Canada, August 6-11, 2000: 1161-1164.

7. Kragh E and Christie P: “Seismic Repeatability,Normalized RMS and Predictability,” submitted for presentation at the SEG International Exposition and 71st Annual Meeting, San Antonio, Texas, USA, September 9-14, 2001.

Summer 2001 31

Getting the Most from Seismic DataInterest in the new Q-Marine system is growingrapidly. The Geco Topaz, the first vessel to berigged for commercial services, began 3D Q-Marine data acquisition in the Gulf of Mexicoin January 2001. She has a full summer seasonscheduled in the North Sea acquiring severaltime-lapse Q-Marine surveys and high-resolution3D data sets. A second vessel, the WesternPride, is being rigged for the Q-Marine system

and will be available by August 2001. A third ves-sel will be equipped with Q-Marine technologybefore the end of 2001.

The early results are meeting and even sur-passing expectations in terms of data quality andrepeatability. The imaging power and resolutionseen in Q-Marine survey data have become thenew benchmarks for data quality. As more Q sur-veys are acquired, geophysical interpreters willcome to rely on the clarity delivered by the new

steered-streamer, point-receiver, calibrated-source technique. Systems are under develop-ment or in deployment for land, borehole andseabed acquisition using the same principles asin Q-Marine technology. Eventually, every reservoir, even those in notoriously difficult envi-ronments, may benefit from the enhanced illumi-nation that comes with properly sampled signalsfrom the subsurface. —LS

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>Measures of repeatability (top), common midpoint locations (middle) and difference plot (bottom).Subtracting the repeat line from the initial line gives the difference between the two surveys. Onthe left side of the difference plot, amplitudes are small because the locations of the common mid-points that contribute to the stacked data are similar. SP1 is the location of the first shot point. Onthe right side of the line, differences are large because common midpoints differed greatly in thetwo surveys. The predictability and NRMS curves are indicators of similarities and differences,respectively, between the lines compared.

32 Oilfield Review

Tom BrattonStephen EdwardsHouston, Texas, USA

John FullerLaura MurphyGatwick, England

Shuja GorayaSugar Land, Texas

Toby HarroldBPSunbury on Thames, England

Jonathan HoltBPAberdeen, Scotland

John LechnerStavanger, Norway

Hugh NicholsonBPStavanger, Norway

William StandifirdLafayette, Louisiana, USA

Bill WrightParis, France

Summer 2001 33

A tropical storm was lumbering across the east-ern Gulf of Mexico, not quite reaching hurricanestatus. Evacuation of a semisubmersible rig wasimminent, but first the crew had to secure thewell they were drilling. Two days earlier, the bithad penetrated a permeable formation, causing akick—unwanted fluid flow into the wellbore.

Immediately after the kick, drillers began awell-control procedure known as wait andweight. To determine the pore pressure, thedrillers shut in the well, waited for wellbore annu-lar pressure to stabilize and then circulated mudof greater density to balance that pressure. Thisprocedure required returning mud to flow througha surface choke line that was smaller than thenormal return line. Unfortunately, the drilling mudthickened during the waiting period, and higherresistance in the small-diameter choke lineincreased backpressure in the wellbore enough tofracture an interval somewhere in the openholesection below casing. There were no fluid returnsto surface. As fast as it could be pumped, drillingmud was going into the induced fracture.

The storm was moving closer to the drillsite,and now the well had two problems, a fractureand an exposed high-pressure formation.Downhole pressure had to be high enough tobalance pore pressure of the permeable zone butlow enough to avoid expanding the fracture. Thefracture was believed to be near the casing shoe,but its exact location and extent were unknown.The operator injected a slug of viscous fluid fol-lowed by a cement plug to isolate the sectionbelow casing, pulled the drillstring, shut in thewell and evacuated the rig. Now, the well couldride out the storm safely.

A tropical storm is not the only demandingcircumstance encountered during drilling.Nowhere are conditions more challenging than indeep water, where drilling a well can cost $30 to$50 million. At these prices, simply making aconduit from a reservoir to the surface is inade-quate. The completed well must be able todeliver hydrocarbons at a rate sufficient to meetor exceed the operator’s expected return oninvestment. Every opportunity to improve the

Avoiding Drilling Problems

Gather relevant information in the required time frame to drill a well. Communicate

data for all parties to analyze and interpret. Anticipate contingencies and continu-

ally update the plan. This approach may seem simple and logical, but in the past,

consistent application has been difficult. Now, a new process can greatly improve

drilling performance.

For help in preparation of this article, thanks to Walt Aldred,Iain Cooper, Cengiz Esmersoy and Andy Hawthorn, SugarLand, Texas, USA; Dan Bordelon, New Orleans, Louisiana,USA; Ian Bradford, John Cook and Christoph Ramshorn,Cambridge, England; Steve Brooks, MI Drilling Fluids,Houston, Texas; Pat Hooyman and Dick Plumb, Houston,Texas; Evangeline Manalac, Gatwick, England; and Tim Schofield, BP, Aberdeen, Scotland.

AIT (Array Induction Imager Tool), APWD (Annular PressureWhile Drilling), ARC (Array Resistivity Compensated tool),BOS (Bit On Seismic), Drill-Bit Seismic, Drilling Office,DrillMAP, DrillViz, DSI (Dipole Shear Sonic Imager), ECS(Elemental Capture Spectroscopy), GPIT, iCenter, InterACTWeb Witness, MDT (Modular Formation Dynamics Tester),NGS (Natural Gamma Ray Spectrometry), PERFORM,RiskTRAK, SeismicMWD and WellTRAK are marks ofSchlumberger. Form-A-Set AK is a mark of M-I, LLC. Drilling the Limit is a mark of Shell Oil Company.

probability of success must be considered, andproblems must be anticipated with contingencyplans. This includes documenting both problemsand successes, so that future drilling and well-construction projects proceed smoothly.1

To this end, BP and Schlumberger joinedforces and created the No Drilling Surprises, orNDS, initiative incorporating techniques devel-oped by both companies. By combining a majoroperator’s experience with the broad base ofSchlumberger tools and expertise, fit-for-purposeapplications were developed and tested rapidly.

The NDS initiative provides a completeframework to improve drilling performance any-where, especially in deep water and in high-cost,high-risk wells. Multidisciplinary teams fromoperators and service companies apply advancedtechnologies within a structured process thatemphasizes communication and collaboration.The No Drilling Surprises program incorporates abroad base of Schlumberger experts, advancedprediction and drilling database software and thelatest hardware. Schlumberger has developed orimproved software tools for planning, monitoringand storing drilling information to support theNDS process. Drilling hazard information islinked among these applications.

This article describes the NDS process and itsuse in a visualization room to plan a North Seawell. A case study from the Caspian Sea showshow new seismic measurements made at eachpipe connection while drilling helped determineand update bit location relative to a seismic sec-tion. And finally, we return to the Gulf of Mexicodeepwater well after the tropical storm passedand learn how the team sealed the fracture.Then, we follow the well’s progress in a very dif-ficult drilling environment.

Expect the UnexpectedCommunication—getting relevant information tothe right people in time to plan and make informeddecisions—is the essence of the No DrillingSurprises approach to constructing wells. This pro-cess brings together people, software tools anddata synchronization and visualization techniquesto transform all available data into usable infor-mation to optimize drilling. It begins with gather-ing data to prepare a predrill well plan andindicating information needed to make drillingdecisions, then planning how to acquire essentialmeasurements in time to influence those deci-sions. Real-time measurements obtained whiledrilling are interpreted using tailored software

tools, which output the analysis in a meaningfulway to help people do their jobs efficiently andeffectively. The well plan is continually updatedwith the latest information (below).

Underlying this process is the concept thathazards can be identified in advance, so opera-tors can develop contingencies for dealing withthem. A 1991 BP stuck-pipe study indicated that,with the benefit of hindsight, the reasons forsticking drillpipe were clear. Since the causescould be determined, the study recommendedthat improved detection and warning would helpprevent many stuck-pipe problems.2

Today’s well planners—including those in allrelevant disciplines—seek to use all availabledata in the well-construction process to signifi-cantly and continually improve drilling perfor-mance. Geologists and geophysicists find thetarget reservoir and provide an understanding offaults and fracture zones, bedding orientationand lithologies. Seismic interpretation locatestargets and hazard zones and through geo-mechanical modeling provides a prediction ofpore pressure and formation strength. Offsetwells offer drilling records that indicate possiblehazard zones and a history of downhole incidentsand their causes. These nearby wells also provide

34 Oilfield Review

Acquire data needed for decisionsImplement at wellsite

Revise models in real time

Capture lessons learned

Discuss in appropriate environment

Create or update earth model

No DrillingSurprises

> The No Drilling Surprises process. Relevant information is gathered before and while drilling to create a living well plan.Communication among all parties involved results in better-informed decisions. Experience and lessons learned are capturedto update the earth model and provide guidance for the process to begin again on the next well.

Summer 2001 35

drilling-mechanics information to optimizedrilling efficiency through combinations of bits,bottomhole assemblies (BHA) and surfaceparameters. Downhole measurements from off-set wells provide formation pressures and awealth of petrophysical information, includingrock properties, such as permeability and poros-ity, detailed lithology, stress magnitude, stressorientation and rock-strength information. Thesemeasurements can be supplemented by coreanalysis, which provides more information onrock strength and petrophysics. Wellsite bio-stratigraphy uses known markers to correlate for-mation age to depth, and assists in correlation ofmechanically weaker intervals.

Yet a problem remains—along the specifictrajectory, the best available information comesfrom estimates, correlations and predictions. Theactual conditions begin to emerge only as thewell is drilled. Regardless of how detailed andhow expertly engineered it is, a predrill plan isobsolete almost as soon as the well is spudded.

The No Drilling Surprises approach uses apredrill plan as the starting point to create adynamic, living well plan updated continually withreal-time information that accounts for, andeven anticipates, differences from predictions.Schlumberger PERFORM Performance ThroughRisk Management engineers have the tools andtraining to play a key role in keeping the well plancurrent.3 From the drillsite, these specialists moni-tor a wide variety of drilling parameters, includingsurface measurements such as rate of penetration(ROP) and weight on bit, mud-flow conditions and

downhole measurements of pressure and forma-tion resistivity. However, data gathering is just thebeginning—the information must be delivered ina useful form. A well plan must be able to incor-porate new information so engineers can adjustdrilling operations accordingly. Managing thisintegration of drilling information puts PERFORMengineers in an ideal position to identify and com-municate potential problems to the right people socontingency plans can be executed.

Different types of information remain rele-vant over different periods of time. An inter-preted seismic section in the time domain,showing general features of the subsurface, usu-ally remains valid throughout a drilling project,although conversion of traveltime to depth maychange. At the other extreme, downhole annularpressures and predictions of pore pressure andfracture gradient ahead of a bit need to bestreamed to surface and incorporated into thewell plan immediately (above).

The NDS process focuses on obtaining infor-mation in relevant real time, a time frame thatmay vary as drilling progresses. For example,there may be a large degree of uncertainty indepth to targets when a predrill plan is devel-oped. A few hundred meters of uncertainty in for-mation depth may have little importance whenthe BHA is thousands of meters above the target.However, the degree of uncertainty becomes crit-ical as the borehole gets within that last fewhundred meters to a target and the drilling teamwants to determine the bit location more pre-cisely. The relevant time frame for updating maybe daily until just before reaching the target,when updates become almost continuous.

Gather Together—Information and People Occasionally, an engineer with extensive experi-ence in a given basin can recall every drillingevent in detail. Ask about stuck-pipe incidentsand the recitation may last an hour. Unfor-tunately, such human databases are rare, and inmost exploration areas, they are nonexistent. TheNDS system provides a continuous, structuredmeans for capturing and learning from failuresand successes to reduce drilling costs.

The No Drilling Surprises process is designedto manage one or a combination of sources ofpotential hazards, such as pore pressure, well-bore instability and hole cleaning. The NDS teambegins by gathering and organizing data andassessing how much new information will beneeded to drill a well successfully. Planning is acomplex task, often detailing actions in fifteen-minute increments.

Field development Well development Daily meeting MWD update

> Relevant real time. Relevant lifetime varies by data type, as indicated by the examples here, decreasing induration from left to right. Seismic interpretation has a long life during field development. Well trajectoriesand drilling status are updated at least daily. At the shortest time scale, measurements-while-drilling (MWD)updates may be needed on a minute-by-minute basis for decision-making.

1. Amin A, Bargach S, Donegan J, Martin C, Smith R,Burgoyne M, Censi P, Day P and Kornberg R: “Building aKnowledge-Sharing Culture,” Oilfield Review 13, no. 1(Spring 2001): 48-65.Dewhirst NW, Evans DC, Chalfont S and Jobson N:“Development of an Active Global Lessons LearnedDatabase—LINK,” paper SPE 64529, presented at theSPE Asia Pacific Oil and Gas Conference and Exhibition,Brisbane, Queensland, Australia, October 16-18, 2000.Evans DC: “The Application of World Wide WebTechnology in a Learning Organization,” paper SPE36011, presented at the SPE Petroleum ComputerConference, Dallas, Texas, USA, June 2-5, 1996.

2. Bradley WB, Jarman D, Auflick RA, Plott RS, Wood RD,Schofield TR and Cocking D: “Task Force Reduces Stuck-Pipe Costs,” Oil & Gas Journal 89, no. 21 (May 27,1991): 84-89.

3. Aldred W, Plumb D, Bradford I, Cook J, Gholkar V,Cousins L, Minton R, Fuller J, Goraya S and Tucker D:“Managing Drilling Risk,” Oilfield Review 11, no. 2(Summer 1999): 2-19.Cuvillier G, Edwards S, Johnson G, Plumb D, Sayers C,Denyer G, Mendonça J, Theuveny B and Vise C: “Solving Deepwater Well-Construction Problems,”Oilfield Review 12, no. 1 (Spring 2000): 2-17.

The WellTRAK knowledge system provides aframework for recording these activities. Forexample, drilling an 8-in. hole section may bebudgeted to take 32 days. This could be brokendown into drilling the section followed by casingand cementing operations. These actions aredetailed further, eventually to the point of bud-geting five minutes to connect a new joint whiledrilling (above). The WellTRAK software is inte-grated into the NDS data-gathering process.

A data audit determines required elements todevelop a mechanical earth model (MEM) appro-priate for the situation and indicates whethersufficient data exist to recommend solutions forexpected problems. This step delineates areas ofrisk. The audit catalogs data for an MEM of aproposed drilling location, using regional and off-set-well information to determine the following:• mechanical stratigraphy through the well

trajectory• vertical stress profile from densities in the strati-

graphic section• pore-pressure calibration based on log and seis-

mic data• profile of elastic parameters and rock strength• minimum horizontal-stress profile and direction• estimates of maximum horizontal-stress

magnitude.

Gaps in the data are identified and a plan isdeveloped to fill them, either before or duringdrilling. The well trajectory is analyzed to identifypotential hazards and to predict necessary mudweights that limit or prevent mechanical well-bore instability.

Shell’s Drilling the Limit process is a similarprogram that also relies heavily on data captureand analysis. Its goal is to define a perfect well-bore, then plan contingencies to achieve it.4 Anintegrated borehole-stability study during thewell-planning phase aims to eliminate problemsduring execution.

The NDS process uses the RiskTRAK drilling-risk database to collect historical hazard informa-tion systematically (below). A drilling event,defined within the RiskTRAK system as a drillingproblem resulting in nonproductive time, providesa wealth of information for future drilling opera-tions. Sometimes wells are drilled “without inci-dent” because small problems are correctedbefore they become lost-time events. It is equallyimportant to capture such near misses—incidentsthat were avoided—because they give importantclues about precursors to problems. This conceptcomes from safety processes, which systemati-cally capture near misses to update risk profiles.

36 Oilfield Review

> Budgeting drilling time and expense. WellTRAK software (top) organizesbudget information for drilling. Clicking on line items brings up a greater levelof detail. Drilling hazards, such as one in the WellTRAK screen Commentsfield, are linked to the RiskTRAK database (bottom).

> Tracking drilling hazards. The RiskTRAK database provides screens forentering and retrieving hazard information. Offset-well information can beselected through the data structure on the left side of each screen. Tabs navigate to screens for general information (top), hazard causes, precursors(bottom), consequences, and preventive and remedial actions.

Summer 2001 37

While drilling in Mungo field, SchlumbergerPERFORM engineers maintained a database ofdrilling events that became the model for theRiskTRAK system.5 Mungo field, operated by BP, isat the edge of the Eastern Central Graben in theUK sector of the North Sea about 143 miles[230 km] east of Aberdeen (above). The productiveForties, Lista and Maureen formations, which arePaleocene sandstones, ring a salt diapir. Drillinghazards include zones with a potential for mudlosses, wellbore enlargement, cuttings buildupand avalanches at certain well inclinations.6

It is easier to understand how the RiskTRAKdata are used in a well-planning meeting if wefirst look at how the database is populated.When a drilling problem occurs or is foreseenand averted, the PERFORM engineer categorizesit within the database by type—for example,stuck pipe, wellbore stability, lost circulation,hole cleaning or pore pressure. A problem may beassociated with a specific depth, geologic age,BHA and drilling activity, so that information alsois captured to compare with offset wells. Afteran incident or near miss, the drilling crew dis-cusses its causes, any precursors noted, and howthe event was, or could have been, avoided.These proposed prevention measures are inputinto the RiskTRAK system. For future reference,severity of the problem and its probability ofrecurrence are estimated. Remedial actions

taken after the event are cataloged, along withconsequences in lost time and the equipmentused to remediate.

Information in the database is useful forpreparing end-of-well reports, by selecting fromone of the RiskTRAK menus. However, acting asthe foundation for a final report is not the end ofthe data’s usefulness. In some cases, a solutionto an event or the handling of a near miss couldbe written up as a lesson learned. Schlumbergerexperts review each lesson learned and mayupgrade it to a best practice, a designation indi-cating experts recommend it. Both best practicesand lessons learned are available to otherSchlumberger employees—both through theRiskTRAK software and the company’s internalknowledge-sharing tool called InTouch—improv-ing client operations throughout the world.

During planning, offset-well data in theRiskTRAK database can be searched by type, forexample geologic age or hole inclination, to pop-ulate other software applications used by a NoDrilling Surprises team. The WellTRAK planningsoftware links to hazards in the RiskTRAKdatabase, and a mouse click summons informa-tion on the type of hazard and what it will cost toavoid or remediate it. Then, while drilling isunder way, the WellTRAK program comparesactual drilling activities with the original plan, soa project team can readily identify suboptimalconditions, unplanned events and their costs and

impacts on operations. After information ondrilling the new well is entered into theRiskTRAK database, the data cycle is complete.

Planners accessed a database containing pre-vious Mungo field wells to plan Well 22/20-A11in the northeast part of the field. In addition, BPand Schlumberger did extensive work to constructa three-dimensional (3D) MEM of Mungo thataccounted for rock strength, complex rotation ofstress around the salt diapir and known geologi-cal stability hazards such as faults and fractures.

Nine members of the operator’s well-planningteam met with an NDS team at the SchlumbergerCambridge Research facility in Cambridge,England, to discuss proposed trajectories forMungo development drilling. Ongoing operationsprevented the drilling manager from attending,but he monitored progress in real time on asecure, live Web site. Videoconference facilitiesalso were available.

North AtlanticOcean

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>Mungo field in the North Sea, offshore Aberdeen, Scotland (left). Cross section shows a salt diapir that pierces the reservoir sandstones (right).Because of the platform location, some wells must go through the salt diapir to reach reservoir targets.

4. Van Oort E, Nicholson J and D’Agostino J: “IntegratedBorehole Stability Studies: Key to Drilling at theTechnical Limit and Trouble Cost Reduction,” paperSPE/IADC 67763, presented at the SPE/IADC DrillingConference, Amsterdam, The Netherlands, February 27-March 1, 2001.

5. Examples given in this article are from the current version of the RiskTRAK software.

6. Cuttings beds tend to form in inclined-well sections, as gravity pulls cuttings to the lower side of a hole. In Mungo field, inclinations between about 50º and 65ºcan lead to unstable beds that can slide downward, oravalanche, creating an instantaneous buildup of cuttingsaround the drillpipe or BHA. If not treated properly,avalanching can result in stuck pipe.

By using the precursor of the RiskTRAK soft-ware and a 3D model of the Mungo structurewith real-time well planning tools, the team dis-cussed multiple trajectories for a proposed Well22/20-A11 reservoir target, updated the wellpath twice and agreed on a final recommenda-tion in one day. During this same six-hour meet-ing, provisional plans were developed for twoadditional wells.7

This rapid evaluation of proposals was possi-ble because the team met in an iCenter collabora-tive meeting facility. This electronic conference

room integrates modern visualization tools withinteractive computing packages. The Mungo plan-ning meeting brought together individuals fromdifferent disciplines, including drilling engineers,geoscientists, geomechanics experts and reservoirengineers. Although each discipline has its ownconventions and terminology for describing drillingand well objectives, the iCenter environmentenables information display in a visual format thatpromotes mutual understanding. Participants atthe Mungo planning meeting used the prototype

of the DrillViz 3D visualization application to viewa geologic model of the field, including existingand proposed well trajectories. The display couldbe rotated in three dimensions so participantscould examine every sector of the field.

The DrillViz display highlighted potential haz-ards for the proposed wells, obtained from off-set-well information in the RiskTRAK database(above). Additional hazard details could beaccessed in a window by clicking hazard areas onthe display.

38 Oilfield Review

>Well trajectories for Mungo Well 22/20-A11. The first proposed trajectory (dark blue)passed too close to an area of brine flow that caused problems in an earlier well. The secondwell path (orange), which was closer to Well 22/20-A02 (black) that had no brine flow, wasmoved upward to avoid fractured Eocene mudstones as the wellbore exited the diapir. Thistrajectory was too flat, which could have led to hole-cleaning problems. The final trajectorymitigated hazards as much as possible, but drillers had to remain aware of potential prob-lems. The planned well path is shown as a thick, multicolored tube—yellow for breakouthazard, red for mud-loss hazard, blue for hole-cleaning hazard and pink for hazard drillingparallel to bedding planes.

Summer 2001 39

Salt tectonism at the center of Mungo fieldgenerated extensive faulting and fracturing informations above the reservoir (below right).Earlier wells experienced problems duringdrilling through faults, but not all faults causedproblems. Wells that intersected faults at smallangles had instability problems, but those thatintersected at angles greater than 45° did not.Fracturing, another cause of wellbore instability,was confined mainly to the Eocene shales overly-ing the reservoir. Instability problems alsooccurred when well trajectories were almost parallel to bedding planes.8

The first well scheduled to be drilled, Well22/20-A11 in the northeast part of Mungo field,targeted a high-quality reservoir sand discoveredby an appraisal well. Discussion on the proposedtrajectory focused on several potential drillingproblems. Brine had flowed into the wellbore ofthe most recent development well, 22/20-A09Z,while drilling through the diapir. The problemswere severe, resulting in a plug-back operationand a redrilling of the bottom section. The sim-plest path to reach the Well 22/20-A11 reservoirtarget would have passed close to the brine-flowarea just to the north. The trajectory was shiftedfarther south, paralleling another developmentwell in the area, Well 22/20-A02, which had nobrine-flow problems.

Eocene shales are fractured and particularlyunstable adjacent to the salt diapir, where themud-loss gradient—indicating the mud weightthat will open existing fractures—is lowest. Theless fractured Miocene mudstones in the forma-tion above were more stable, so Well 22/20-A11avoided the fractured Eocene shales by exitinginto the Miocene mudstones.

These requirements imposed constraints on anew trajectory, which was designed using theDrilling Office directional well-planning system toautomatically account for drilling-related concernssuch as build angles and collision avoidance. TheNDS team put the new well path into the MungoMEM and computed mud-weight limits for the tra-jectory. Planning, analysis and importing into a

DrillViz presentation took about one hour. The newtrajectory, including potential hazards, was exam-ined and discussed by the group. A long tangentsection was at an inclination angle that had previ-ously caused hole-cleaning problems, which coulddestabilize drilling. This had not been recognizedin the previous discussion, but was now immedi-ately obvious to the team. A second Drilling Officerevision minimized this hazard, increasing holeangle by dropping the exit point from the diapir,but staying within the Miocene formation.

By collaborating in an iCenter environment,the team eliminated weeks of iterationsbetween drilling and reservoir staff, and every-one gained a better understanding of the com-plex well problems in this field. Hazards werenot completely eliminated, but the worst oneswere mitigated and engineers developed plans

for handling others. The drilling team used aDrillMAP poster as a reminder of where toexpect four types of hazards in the wellbore:• Breakout—low mud weight can cause hole

enlargement, increasing cavings that must becleaned out of the wellbore.

• Mud losses and gains—losses indicate mudflow into a fracture, possibly increasing its size,and gains indicate gas or brine flow into thewellbore, creating potential for a blowout thatmust be controlled.

• Bedding planes—formation failure is morelikely when drilling a well parallel to bedding,which could cause the drillstring to pack off.

• Hole cleaning—well inclinations between 50°and 65° lead to cuttings avalanches that cancause sticking, so proper hole cleaning isimportant.

7. Holt J, Wright WJ, Nicholson H, Kuhn-de-Chizelle A andRamshorn C: “Mungo Field: Improved CommunicationThrough 3D Visualization of Drilling Problems,” paper62523, presented at the SPE/AAPG Western RegionalMeeting, Long Beach, California, USA, June 19-23, 2000.

8. Beacom LE, Nicholson H and Corfield RI: “Integration ofDrilling and Geological Data to Understand WellboreInstability,” paper SPE/IADC 67755, presented at theSPE/IADC Drilling Conference, Amsterdam, The Nether-lands, February 27-March 1, 2001.

> Fractures in Mungo field. BP geologists mappedmany fractures overlying the diapir. These frac-tures intersect horizons in a radial pattern. A viewfrom above shows interpreted fractures intercept-ing the Late Miocene mudstones (top). Knowingthe location of the fractures in three dimensionshelps well planners avoid fracture-related hazards (bottom).

The DrillMAP presentation listed parametersthat should be monitored and recommendedactions to avoid these hazards (above and nextpage). The PERFORM engineer on site recordedobservations and interpretations during drilling,and suggested changes to improve the MEM forfuture wells. As a result of careful planning andexecution, the well was drilled successfully to thereservoir target with no nonproductive timerelated to wellbore stability.

Where’s the Bit? Drilling-target location often is determined froma surface seismic section, which is an interpreta-tion of traveltime to subsurface reflectors pre-sented in milliseconds (msec). Unfortunately, thedepth of reflectors may not be established, par-ticularly for exploration wells. Conversion fromtraveltime in msec to depth in feet or meters is

not straightforward—it requires knowledge ofthe velocity of sound in all the rocks from surfaceto the target, information that is often unknownand assumed by analogy to other basins.Nonetheless, drilling decisions must be madebased on such data. In many instances, casingpoints are selected to avoid drilling into a hazard

40 Oilfield Review

Summer 2001 41

with a long openhole section above. By casingthe well, mud weight can be changed to accom-modate the hazard ahead without endangeringthe overlying formations.

Before drilling begins, uncertainty in the loca-tion of casing points may be hundreds of meters,

which introduces unacceptable risk. Duringdrilling in development areas, uncertainty can bedecreased by examining cuttings or logging-while-drilling (LWD) responses to compare withdistinct, or marker, beds encountered in nearbywells. In a new basin, recognized markers may

not be established, so other means must be usedto locate the drill bit on a seismic section.

Until now, drillers had two options for convert-ing seismic traveltime to depth. The first, whichinterrupted drilling, was a checkshot using a wire-line borehole seismic receiver and a source on the

,Drilling hazards for Mungo Well 22/20-A11. TheDrillMAP presentation can be made into a postershowing locations of potential hazards, groupedby type of hazard. Recommendations to avoid orremediate problems are listed in the middle sec-tion. The safe mud-weight window graphicallyillustrates the potential for a kick or a breakout ifmud weight gets too low, or losses to fractures ifmud weight gets too high. Stress and rock-strengthparameters from the MEM are shown on the rightside. Other data, such as well trajectories or geo-logic information, can be added.

surface (above). While this provides a high-qualitymeasurement, the logging run requires substantialrig time, adding cost and additional risk. Evenworse, the measurement could be scheduled tooearly or too late to be useful—before or after acasing point or hazard is reached.

By the mid-1990s, a check shot could beobtained while drilling using surface receiversand noise from the drilling bit as the source, theDrill-Bit Seismic service.9 This technology workswell in many situations, but is unreliable in softformations, in high-angle holes and when poly-crystalline diamond compact (PDC) bits are used.

A new solution provides vertical seismic pro-file (VSP) surveys approaching wireline quality inrelevant real time without additional rig time.10

The SeismicMWD tool places a seismic receiverin a LWD assembly and uses a surface source toproduce a VSP while drilling. A measurements-while-drilling (MWD) mud-pulse telemetry sys-tem transmits real-time data to surface. TheSeismicMWD measurement can be used in situ-ations that the Drill-Bit Seismic service cannot,but it does require the tool on the BHA, andMWD telemetry must be in place if real-timemeasurements are required. On the other hand, a

wireline seismic survey provides better qualitydata for reservoir characterization studies thaneither the SeismicMWD tool or the Drill-BitSeismic measurement.

The SeismicMWD measurements are madebefore or after a new stand of pipe is connected,during the quiet time while the drillstring is stationary and no mud circulates. Normally, a connection takes several minutes, adequate forseveral readings taken at 10- to 15-second inter-vals. No time is taken away from the drilling oper-ation. The one-way traveltime, or check shot, istelemetered to surface as soon as the mud pumps

42 Oilfield Review

LWD receiver

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Drill-Bit Seismic system SeismicMWD system

> Options for wellbore seismic information. A wireline borehole seismic measurement must be done betweendrilling runs. The receivers are lowered into the wellbore and a surface source provides the signal (left). With theadvent of drill-bit seismic acquisition, noise from drilling acts as a source and the receivers are on the surface (middle). The new SeismicMWD receiver uses a surface source, but measurements can be obtained while drilling,as each stand of drillpipe is added or removed (right).

Summer 2001 43

start again, allowing a direct tie of bit location totransit time on a surface seismic section. The bitlocation can be converted to true vertical depth(TVD) through a record of measured depth andinclination along the well trajectory.

Full seismic waveforms are stored until theassembly is brought to surface. The capability totransmit MWD VSP waveforms to surface isexpected soon.

With check-shot data obtained at each connec-tion point, or more frequently if deemed necessaryby the client, the location of a bit on a seismic sec-tion can be determined while drilling. It is usuallynot practical to reprocess the complete surface

seismic section in real time, but it is quick, easyand usually accurate enough simply to stretch orcompress the depth-domain seismic sectionusing real-time check-shot data (below). Theupdated section can be used to predict the dis-tance to the next drilling objective or hazard. ThePERFORM engineer uses DrillMAP software as avisual aid, based on this updated informationabout the drilling environment, to notify the rigcrew of potential drilling hazards, decreasing therisk for drilling ahead. This provides a greatadvantage for drillers and also gets up-to-the-minute information more quickly to geoscientiststo update interpretations.

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> Stretching and compressing seismic sections. Normally, a seismic section in the time domain (left)is not reprocessed during drilling. The position of a bit is known from measured depth, inclination andazimuth along the well path (blue). Check-shot measurements transmitted to surface while drillinglocate the bit on the seismic section, allowing stretching or squeezing of the converted depth sectionto locate targets ahead (right). Each trace is converted, but no lateral variation is applied.

9. Borland W, Codazzi D, Hsu K, Rasmus J, Eichcomb C,Hashem M, Hewett V, Jackson M, Meehan R andTweedy M: “Real-Time Answers to Well Drilling and Design Questions,” Oilfield Review 9, no. 2 (Summer 1997): 2-15.

10. Esmersoy C, Underhill W and Hawthorn A: “SeismicMeasurement While Drilling: Conventional BoreholeSeismics on LWD,” Transactions of the SPWLA 42ndAnnual Logging Symposium, Houston, Texas, USA, June 17-20, 2001, paper RR.

As the wellbore approaches a casing point ortarget depth, updated information reduces uncer-tainty to an acceptable level (next page). TheBOS Bit On Seismic software captures this infor-mation from MWD telemetry and, in real time,updates the seismic section, the location ofmajor markers, the estimated target position anddepth uncertainties (above). In some areas, thereare no obvious markers to tie a seismic section tocuttings or other drilling parameters, and the onlycorrelation is through a seismic-while-drillingmethod. Improved knowledge of bit location mayresult in eliminating a casing point, or in somecases adding one to mitigate risk.

The SeismicMWD tool was used on a BP wellin the Caspian Sea in early 2001. The well wasdrilled directionally, which is unusual becausemost exploration wells are vertical. BP wanted toavoid an overpressured zone near the crest of thestructure and reach a reservoir target that wasunder a series of faults in an overthrust area withbeds dipping at 40°. Based on interpretation ofthe surface seismic section, the well trajectorywas 4500 m [14,800 ft] long. However, verticaluncertainty in depth of the top of the reservoirwas 700 m [2300 ft]. This is a critical problem,because missing the target by 100 m [330 ft]could put the well on the wrong side of a fault.Since sediments in this area are soft, using bitnoise as a seismic source while drilling was not

feasible. BP used the SeismicMWD tool to obtaincheck shots and update bit location while drilling.

The most accurate depth data from one-waytraveltime is obtained when the seismic wavetravels vertically. To achieve this in a deviatedundersea well, a boat pulling a surface seismicsource had to be moved for each check shot location and positioned based on the previousshot and a best estimate of subsurface bit location—a process called a walkabove survey.11

Results indicated that BP’s predrill surface seismic interpretation was accurate, but the

44 Oilfield Review

> BOS (Bit On Seismic) software display. A well trajectory (blue) is shown on a time-domainseismic section with specific markers highlighted (red). As drilling continues, the well trajec-tory extends on the display (upper left). The SeismicMWD check-shot data are used to locatethe bit in the depth-converted seismic section. The same markers are shown on this display,along with color-coded uncertainty bands (upper right). Depths ahead of the bit have increas-ingly wide uncertainty bands, as shown by the uncertainty distribution for a specific marker(lower left). Depth, inclination and azimuth information are entered to convert the traveltime to depth (lower right).

11. Hope R, Ireson D, Leaney S, Meyer J, Tittle W and Willis M: “Seismic Integration to Reduce Risk,” OilfieldReview 10, no. 3 (Autumn 1998): 2-15.

Summer 2001 45

> Decreasing uncertainty by increasing information.The well (thin blue line) begins in the upper left of thisdepth-converted seismic section. Three screens fromthe Bit On Seismic software show a wellbore advancingtoward the lower right. Marker locations are predictedat each step (red line), with uncertainty bands aroundthem (blue band). One marker bed was interceptedbefore the trajectory began deviating to the right (top).Since that marker depth is known, its blue uncertaintyband has disappeared. The software displays thepredrill prediction of depth (yellow line) and uncer-tainty (green band) for comparison to measured depth.Drilling through more markers provides additionalinformation (middle), improving time-to-depth conver-sion along the trajectory. Predictions of depths oflower markers are updated, and their uncertaintydecreases. No uncertainty remains after drilling intothe last marker bed (bottom).

SeismicMWD check shots provided additionalconfirmation as drilling progressed. After drilling,BP obtained a walkabove wireline seismic sur-vey. The results agreed closely with theSeismicMWD measurements (above).

The logging tool also captures full-waveformseismic signals, and the quality of the resultingwaveforms was good. However, when the wellwas drilled in early 2001, the tool could not trans-mit the waveforms to surface in real time, so thedata were downloaded once the tool returned tosurface (next page, bottom).

The operator felt the measurement had nonegative impact on drilling time and providedresults comparable to conventional wireline VSPsurveys. The costs of seismic-source boat andpersonnel deployment were more than offset by drilling time saved by not obtaining conven-tional surveys.

In some cases, SeismicMWD measurementsactually save rig time. In many cases involving adirectional well, a near-vertical pilot hole isdrilled to determine locations of markers or tar-get depth. This hole is then cemented back and sidetracked to land the well horizontallywithin the reservoir. Real-time BOS Bit OnSeismic interpretation may eliminate the need todrill a vertical hole, substantially reducing well-construction costs.

Relevant Real-Time Monitoring The Schlumberger PERFORM engineer sits at thecenter of an NDS communications web duringdrilling operations. This engineer is responsiblefor monitoring measurements made while drillingand alerting the drilling team—including thedrilling supervisor, onshore drilling engineers andexperts from other disciplines supporting thework—when parameters are outside tolerancelimits. In addition, the PERFORM engineer keepsthe drilling crew apprised of potential hazardsthat may be encountered in the next section orover the next 24 hours, along with contingenciesfor dealing with such occurrences.

A wide variety of problems—getting stuck,taking a kick by drilling into an overpressuredpermeable zone or creating or enlarging a frac-ture—may be encountered while drilling. ThePERFORM engineer tries to avoid these problemsby pulling together information from all availablesources. Historical data, such as experience inoffset wells, provide a forecast of possibilities,while measurements obtained while drill-ing reveal what is happening downhole. The PERFORM engineer makes recommendations onsurface mud weight and on controlling other con-ditions such as annular loading; swab, surge, andpackoff; mud flow rate; ROP; and rotational speedof the bit. NDS geomechanics and petrophysicsexperts onshore supply the scientific and techni-cal backing and sophisticated modeling the PERFORM engineer requires.

Hole condition can be inferred from cuttingsand cavings separated from mud returns at theshakers.12 The shape and size of cavings can dis-criminate between hole enlargement caused byshear failure when mud weight is too low andthat caused in naturally fractured zones whenmud weight is too high.13 Pictures of cuttings andcavings can be posted on a secure Web site toobtain rapid feedback from experts who are notat the well.

Monitoring mud volume gives an indication ofproblems. Mud loss suggests possible fracturing,and mud gain indicates a possible kick. However,it can take half a day for cuttings to reach the sur-face from 20,000 ft [6100 m] and hours to estab-lish mud losses, unless the mud loss is large.

An indication of gas influx, often caused bydrilling into a high-pressure, permeable zone,comes from the gas content of the mud. Smallamounts of gas can be controlled, but a rapidinflux may create significant problems. Gasexpands as it moves up the wellbore, pushingmud out of the hole ahead of it. This furtherdecreases hydrostatic pressure, allowing moregas expansion and potential loss of well control.The gas content is monitored at surface, but asmall influx might take several hours to bedetected. The longer a well-control incident goesundetected, the worse it becomes. In extremecases, a rig might have to be abandoned rapidly.

Remediation may create further damage. Forgreat depth and small hole diameters, the onlyway to control a kick is to bullhead—pump muddown both the drillpipe and annulus to force fluidback into a formation. While this may control gasinflux, it might also fracture a formation else-where in the openhole section.

The APWD Annular Pressure While Drillingmeasurement provides downhole annular pres-sure, obviating the need to estimate conditionsfrom surface pressures and modeling software.14

Because mud density is used to control pressuredownhole, drillers use the mud density unit ofpound-mass per gallon (lbm/gal, sometimes designated ppg) to describe pressures—down-hole annular pressure, pore pressure, and over-burden and lateral stresses. The APWDmeasurement, which measures the equivalentstatic density (ESD) of mud when pumps are offand the equivalent circulating density (ECD)when pumps are on, is used to monitor downholemud density to keep it within a specific range.The ESD must remain above pore pressure and, ifpossible, above the minimum pressure to controlborehole breakouts. The ECD must stay belowthe fracture gradient.

46 Oilfield Review

1600

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Cased-hole wireline VSP measurementsOpenhole SeismicMWD VSP measurements

> Comparison of VSP traveltimes. After a Caspian Sea well was drilled, a cased-holeVSP (red) was run to determine a time-to-depth conversion. The SeismicMWD mea-surement (black) compares closely with wireline VSP data. The gap in the data wascaused by problems with a crane supporting the seismic source on the boat.

Summer 2001 47

The APWD measurement also can give anindication of improper hole cleaning, which couldlead to stuck pipe or other problems, such as bal-looning, or opening and closing of a fracturewhen the ECD rises and falls.

Managing wellbore pressures is an importanttask for the PERFORM engineer. For deep wells indeep water, an overriding problem is the narrowwindow between pore pressure and fracture gra-dient. Both pore pressure and fracture gradientchange with depth, and the safe drilling windowbetween them often narrows (right). If mud den-sity is kept constant while pore pressureincreases, there is danger of a kick. If mudweight is increased too much, however, the opensection of the wellbore below the last casingpoint could fracture.

Normally, mud weight should be at least sev-eral tenths of a lbm/gal [several hundredths g/cm3]above the maximum pore pressure and at leastseveral tenths of a lbm/gal below the minimumfracture gradient in the openhole section. Whenthe pore pressure-fracture gradient window nar-rows to 1 lbm/gal [0.1 g/cm3] in deep wells, thisbecomes a drilling challenge. One response is toslow the pump rate, but since this affects the cut-tings-removal rate, ROP must be decreased, forc-ing a balance between loss of economy from slowdrilling and risk of damaging or losing the wellfrom taking a kick or fracturing a formation.Subsea-lift technology such as dual-gradientdrilling can decrease mud-weight gradients belowthe seabed, reducing the number of casing strings.This technology is not yet widely available.15

Interpretations from sonic and resistivity mea-surements made while drilling provide informationabout the formation just behind the bit. While itcan take hours for mud or cuttings to circulate tosurface, sonic and resistivity tools lag the bit byabout half an hour at typical drilling speeds. Bothtools predict pore pressure and fracture gradientbased on an MEM along this trajectory, helping aPERFORM engineer manage wellbore pressure.The engineer refines the model during drilling bycomparing predictions to leakoff tests—takenafter casing is set and drilled out—and to porepressures in permeable zones, obtained usingMDT Modular Formation Dynamics Tester mea-surements between drilling runs.

The well in the Gulf of Mexico that was threat-ened by a tropical storm was a challenge for thedrilling team: a directional exploration well indeep water with an ultradeep target. BP devel-oped a pore-pressure model prior to drilling butalso wanted to monitor conditions while drilling.The PERFORM engineer had several key tasks:• define safe ranges for wellbore pressure; in

this case, within a pore pressure-fracture gra-dient window

• make static and dynamic measurements offluid pressures in the annulus

• refine pore-pressure and fracture-gradient esti-mates continuously from real-time logging data

• identify and analyze drilling-induced hydraulicfractures

• identify and analyze wellbore-instability problems

> Seismic waveforms. Full-waveform seismic data were retrieved from the SeismicMWD tool aftertripping out. The operator felt that the raw (left) and processed waveforms (right) were of high quality.The gap in the data was caused by problems with a crane supporting the seismic source on the boat.

Dept

h fro

m d

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, m

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Raw Waveforms Processed Waveforms

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m20

00 ft

Real-time porepressureMDT pressureSurface mud weight

Equivalent circulatingdensityFracture gradientOverburden gradient

> Stress gradients and mud weights. The real-time pore-pressure prediction (yellow) was madewith resistivity and velocity data on this Gulf ofMexico well. Red diamonds represent MDT Modular Formation Dynamics Tester pressuredata. The fracture gradient (red) becomes coinci-dent with the overburden gradient (green) atgreat depth, and the safe mud-weight windownarrows. The ECD curve (purple) comes fromAPWD measurements.

12. Cuttings are pieces of rock removed by the bit. Cavingsare pieces of rock that fell off the borehole wall.

13. Aldred et al, reference 3.14. Aldred W, Cook J, Bern P, Carpenter B, Hutchinson M,

Lovell J, Rezmer-Cooper I and Leder PC: “Using DownholeAnnular Pressure Measurements to Improve DrillingPerformance,” Oilfield Review 10, no. 4 (Winter 1998): 30-55.

15. Cuvillier et al, reference 3.

• forecast risks associated with pore pressuresand fracture gradients

• communicate all observations and interpreta-tions to the drilling team.

The PERFORM engineer joined the drillingteam to begin real-time monitoring and managewellbore pressure when drilling reached the 21-in. casing shoe. The petrophysicist recom-mended that an ARC Array Resistivity Compen-sated tool be used while drilling. The sensorspacings in the ARC tool, along with a secondmeasurement frequency, provide information tohelp differentiate borehole breakouts fromhydraulic fractures—two distinct wellbore-stability problems.

Two ARC resistivity channels were monitoredin real time, while other channels were stored forretrieval after tripping to surface. One real-timesignal was a low-frequency phase-shift resistiv-ity that reads deep into the formation, used tomeasure true resistivity Rt. This signal is insensi-tive to tool eccentricity and large boreholes whenshale resistivity is low. The second signal sent tosurface continuously was the ARC tool’s shallow-est measurement, which is the most sensitive to

eccentricity, hole-size enlargement and fractur-ing. Separation of these two curves is an earlyindication of a hole problem.

After drilling ahead 1000 ft [300 m] from the21-in. casing set point, drillers noted mud flowingfrom the well during a drilling break, indicatinginflux into the wellbore. The pore-pressure modelgave no indications that ESD had been exceeded,nor were there changes in cuttings morphology,gas data or drilling parameters indicating that azone of high pore pressure had been encoun-tered. Later analysis showed that all pore-pressure models were in agreement, and theexcessive pressure was an anomaly.

The operator instituted a kill procedureknown as single-circulation wait and weight tostop the influx (above left). The subsea blowoutpreventer (BOP) was closed to avoid the possibil-ity of high pressure reaching the lower pressureriser. With the well shut in, the crew alloweddownhole pressure to stabilize with the porepressure. Then, they increased the mud weightwhile circulating mud down to bottom of the welland back to top. The return line was diverted to achoke, which is rated to high pressure all the wayto surface but has a smaller internal diameter

than the annular return above the subsea BOP.Unfortunately, during the wait period, mud in thehole gelled and became more viscous. When cir-culation began, increased friction resistance,coupled with the smaller diameter return linethrough the choke, forced downhole pressurehigh enough to fracture a formation somewherein the openhole. Drilling mud was lost as fast asit was pumped into the well.

By this time, the tropical storm was blowinginto the eastern Gulf of Mexico. The crewpumped gelled fluid and a cement plug to the bottom of the cased section to isolate the open-hole, shut in the well and evacuated the

48 Oilfield Review

0

Stan

dpip

e pr

essu

re, p

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SIDPP building

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Work pipe up and down

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SIDPP stabilizedat 10.89 lbm/gal

Surface APWD EMW

>Wait and weight procedure. The shut-in downhole pore pressure (SIDPP) stabilized at 10.89 lbm/gal[1.3 g/cm3] equivalent mud weight (EMW), measured using the APWD tool (green). After the pipe wasworked up and down to avoid sticking pipe while waiting, mud of higher weight was circulated into thehole. Increased annular pressure resulted from gelled mud in the hole. The team broke circulation—stopped the mud pumps—and began a well-control procedure. The surface standpipe pressure (blue)shows much less detail, but can be obtained throughout the procedure. The APWD measurements canbe transmitted to surface only when mud pumps are on.

X400

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Dept

h, ft

Resistivity, ohm-m1 10

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> Time-lapse resistivity. The high-frequency shortspacing of the ARC tool P16H phase-shift resis-tivity is most sensitive to near-well events, suchas fracturing. The measurement made whiledrilling (black) shows low resistivity below thecasing shoe at X407 ft. A few days later, the crewreentered the well and ran the tool again (red).The separation of the two logs indicated a frac-ture located from X410 to X650 ft.

Summer 2001 49

above 345 psi [2380 kPa] would exceed the mini-mum horizontal stress, extending this large frac-ture and making the problem worse. Polymer wasplaced from about 400 ft [120 m] below the indi-cated fracture up into the casing shoe, about1000 ft total. Slowly increasing wellbore pres-sure to just above the minimum horizontal stressopened the fracture in a controlled way, andsqueezed polymer into the fracture. After thepolymer set, the well was reamed carefully to thebottom of the fractured zone. Large, rubberychunks of the polymer circulated up to the shaleshakers, indicating that the material had set inthe expected firm, spongy structure (left).

As drilling continued, the PERFORM engineermonitored conditions at the bit and tracked thetype of cuttings coming to surface. The pore pres-sure-fracture gradient window narrowed, requir-ing a close watch on ECD and ESD. ROP had to be

balanced with mud-flow rates to ensure cuttingsremoval and avoid sticking the pipe. Pressuremanagement using all available information wascrucial in this difficult drilling environment.

One job of a PERFORM engineer is to monitorfluid returns when mud pumps are shut down.Profiles of flow duration and volume returnedindicate conditions of the exposed formation. Ifenough permeable zones are open to the well-bore and pore pressures are increasing, flowbacktimes and volumes may increase. Although not aquantitative measure of pore pressure, monitor-ing returns does indicate whether pore pressureexceeds static mud density. If there is an exposedhydraulic fracture, ballooning will dominateresults of flowback monitoring and obscure pore-pressure effects (above).

> Rubbery mass on shale shakers. Mud returnswhile drilling through the section injected withForm-A-Set AK polymer showed tough, rubberymasses of polymer like this one held by the mudlogger. Seeing these provided reassurance thatthis lost-circulation material had set properlydownhole.

A

A

Flow

rate

Time

B

BC

C

Flow

rate

Time

> Diagnosing mud returns. Mud volume increases in surface mud pits ortanks during drilling pauses provide information about the state of the well-bore. A ballooning fracture squeezes mud back into the wellbore rapidly atfirst, but the rate slows over time as the fracture closes, illustrated at timesA, B and C (top). A permeable formation also increases mud volume returningto surface, but the rate is constant with time (bottom).

semisubmersible rig. The storm moved north,making landfall and moving slowly across thesoutheastern USA, causing $16 million damageand killing one person in a tornado it spawned.

The crew returned to the rig after the stormpassed and found it undamaged. The NDS teamrecommended running a resistivity log to comparewith the log taken while drilling (previous page,right). The high resistivity of the second log fromthe 21-in. casing shoe at X410 ft to about X650 ftindicated an extensive fracture created during thepre-evacuation kill procedure. The strength of theshale and local stresses indicated that the fracturewould grow even larger if wellbore pressureswere not carefully controlled. The openhole sec-tion had almost another 1000 ft before the nextcasing set point, so a loss-control agent wouldhave to be durable to withstand continued drilling.

An M-I Drilling Fluids engineer recommendedForm-A-Set AK crosslinking polymer to penetrateand seal the fracture, because it set properly atthe downhole temperature and also could main-tain its integrity while the section below wasdrilled. The geomechanical fracture analysis,which would not have been possible without theupdated MEM, indicated that a surface pressure

In this well, both duration and volume of mudflow increased after a cement squeeze below the105⁄8-in. casing shoe (left). Although exposed permeable formations could cause such anincrease, the mud-flow rate would not decreasewith time.

The APWD measurement on the ARC toolprovided useful diagnostics throughout drilling.Confirmation that the mud flow was from a bal-looning fracture came from the shape of the ECDbuildup.16 Prior to fracturing, pressure builtrapidly when mud circulation began (below left).ARC runs after later joint connections showed anexponential pressure buildup once ECDexceeded the fracture opening pressure of16.95 lbm/gal [2.03 g/cm3]. The fracture wassealed with lost-circulation material, which wassuccessful for a time, but as the mud-flow mea-surements showed, drilling difficulties continued.

The ARC measurements also indicated thatoverburden gradient and fracture gradient wereboth 17.05 lbm/gal [2.04 g/cm3], so horizontalstresses equaled or exceeded vertical stress, acondition difficult to determine without APWDand density measurements.

The narrow pore pressure-fracture gradientwindow made drilling difficult, and the staff—both at the rig and onshore—monitored APWDpressures closely. The well was drilled another5000 ft [1525 m], at which point drilling and geo-logical objectives were achieved and drillingstopped. BP felt that participation of the NoDrilling Surprises team made drilling to totaldepth possible, overcoming narrow tolerances onECD and extreme drilling depth.

50 Oilfield Review

0 0.0

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Flowback timeFlowback volume

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> Mud returns to surface showing a ballooning fracture. The volume of returns (red) and the durationof mud flow (purple) are indicated over a long openhole section of a Gulf of Mexico well. A fractureopened after a cement squeeze at XX950 ft, indicated by increased mud returns that stopped after ashort period. Returns decreased after injection of lost-circulation material at XY400 ft. Mud weightwas increased at XY880 ft to control increased pore pressure, but the return volume flow and durationindicate that the fracture reopened. Casing was set at XZ400 ft. Confirmation that this behavior wasdue to a fracture and not a permeable zone came from the rapid decay in mud return during eachmeasurement period, mud losses during drilling and ARC resistivity measurements.

16. Bratton TR, Rezmer-Cooper IM, Desroches J, Gille Y-E, Li Q and McFayden M: “How to Diagnose DrillingInduced Fractures in Wells Drilled with Oil-Based Mudswith Real-Time Resistivity and Pressure Measurements,”paper SPE/IADC 67742, presented at the SPE/IADCDrilling Conference, Amsterdam, The Netherlands,February 27-March 1, 2001.

17. Bratton et al, reference 16.

ARC

ECD,

lbm

/gal

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17.0

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16.7

TM 155 to 170 TM 215 to 221 TM 350 to 362 TM 470 to 475

0 5 10Elapsed time, min

ECD buildup before fracture formation

Fracture opening pressure

> Exponential tails in ECD. The first time sequence, from time marker (TM) 155 to TM 170, shows ECD rise when mud begins circulating after the firstconnection at a casing shoe (light blue). The formation is not yet fractured so ECD increases rapidly. The slower, exponential rise of ECD after the next three connections is characteristic of a fractured formation (other curves).The change in behavior for TM 350 to 362 indicates fracture opening at 16.95-lbm/gal mud weight.

Summer 2001 51

Drilling AheadIt is natural to expect ongoing change and evolu-tion from a program that advocates a dynamic,living well. The DrillMAP system was developed during and after drilling in Mungo field, andimprovements to the software continue. Newinterpretations for ARC resistivities help engi-neers diagnose drilling-induced fractures, even inoil-base muds.17 Software for making real-timepore-pressure predictions from LWD tools is indevelopment, and as LWD telemetry improves,more measurements will be available in realtime, including full-waveform seismic signalsfrom the SeismicMWD tool.

The No Drilling Surprises initiative is aboutmore than hardware and software. It providessolutions to drilling problems and anticipatesneeds, with an emphasis on communicating rele-vant information in a meaningful fashion in timeto make decisions. A recent improvement to theprocess uses a secure Web site to update

onshore teams of geologists, engineers, petro-physicists and drillers about drilling progress(above). The InterACT Web Witness data-delivery system connects directly with a rig toprovide involved parties with real-time drilling,logging, trajectory and survey information. Datacan be accessed through the Web using a per-sonal computer or Web-enabled PDA (personaldigital assistant), and alerts can be set to sendcritical messages to the pagers of appropriateteam members. When coordinated with amechanical earth model and DrillMAP software,differences between the original well plan andactual results can be evaluated quickly, so oper-ators can develop new contingency plans andnew approaches.

Schlumberger has teamed with BP, Statoil,Baker Hughes, Halliburton and software com-pany NPSi to establish a standard protocol fortransferring drilling information. The WITSMLprotocol, a wellsite information transfer standard

markup language, will provide a seamless flow ofwellsite data between operators and servicecompanies, covering drilling, completion andwell-service operations. The new protocol willexpand the capabilities of the InterACT WebWitness system by standardizing transfer ofdrilling information.

Extreme drilling conditions continue to chal-lenge the industry. Deeper water, deeper wells,higher temperatures and pressures, and narrowerallowable windows for mud weight are drivingimprovements in technology and interpretationtechniques. As programs like the No DrillingSurprises process solve today’s hurdles, operat-ing companies will “raise the bar” again. Only a dynamic, living process can continue to achieve success. —MAA

Hub

Pore pressure DrillMAP software

DrillViz software

Pager alarmsPDAWeb

Update model

Monitoring critical parameters

Real

-tim

e da

ta c

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ctio

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> A well-connected world. LWD data are transmitted in real time through a Web interface to teammembers anywhere in the world. Critical data can be monitored on a secure Web site, or data andalarms can be sent to a PDA (personal digital assistant) or pager. Drilling models can be updated inreal time to improve drilling performance.

52 Oilfield Review

High-Productivity Horizontal Gravel Packs

Syed Ali Rick Dickerson Chevron Houston, Texas, USA

Clive Bennett BP London, England

Pat Bixenman Mehmet Parlar Colin Price-Smith Rosharon, Texas

Steve Cooper BP Aberdeen, Scotland

Jean Desroches Sugar Land, Texas

Bill Foxenberg M-I Drilling Fluids Houston, Texas

Keith Godwin Stone Energy Corporation Lafayette, Louisiana, USA

Tim McPike Shell International E&P Rijswijk, The Netherlands

Enzo Pitoni Giuseppe Ripa Eni AgipMilan, Italy

Bill Steven Texaco Warri, Nigeria

Dave Tiffin BP Houston, Texas

Juan Troncoso Repsol-YPF Jakarta, Indonesia

ClearPAC, MudSOLV, NODAL, QUANTUM and SandCADEare marks of Schlumberger. AllPAC and Alternate Path aremarks of ExxonMobil; this technology is licensed exclu-sively to Schlumberger.

To increase productivity and reduce cost and complexity, horizontal wells often

are completed without casing across pay intervals. Stand-alone screens have

been used in openholes, but increasingly, operators are gravel packing long

intervals to stabilize boreholes, provide more reliable completions and mitigate

sand-related problems such as erosion, surface handling and disposal.

Loose formation grains and fine particles such asclays may be produced along with oil, gas andwater from unconsolidated reservoirs. Installingcompletions to control sand without sacrificingproductivity, flow control or recoverable reservesis challenging and expensive—as much as $3 million or more offshore. Costs of subsequenttreatments to mitigate damage and future reme-dial interventions also are extremely high—up to $1 million per job in deepwater and subseawells. Operators need reliable sand-controlmeasures, implemented correctly the first time,especially for horizontal, openhole wells in high-permeability formations.

Sand production, or sanding, is a function ofrock strength, in-situ stresses, produced fluidsand changes in flow rate related to pressuredrop, or drawdown. High production rates,increasing effective stress due to depletion, andwater breakthrough contribute to sanding.Problems associated with produced sand rangefrom surface handling and disposal to erosion ofsubsurface or surface equipment and loss of wellcontrol.1 If sand causes tubular or completion-equipment failures, production and reserverecovery can be delayed, or even lost, when coststo sidetrack or redrill a well are prohibitive.

Operators use various techniques to minimizesand in produced fluids (next page). Sand-controlmethods include limiting well flow to rates belowthe onset of sanding, in-situ consolidation, selec-tive or oriented perforating, gravel packing andfrac packing.2 Frac packing combines short, wide

hydraulic fractures, or tip-screenout designs,with gravel packing. To control sand in openholecompletions, operators use stand-alone screens,gravel packs, frac packs, and recently, expand-able screens (see “Emerging Sand-ControlTechniques,” page 72).

Restricting production, although successful inthe past, adversely impacts well profitability andis not practical in today’s economy, especially forhigh-cost, high-rate wells. In-situ consolidationlocks sand grains in place by injecting resins andcatalysts into formations, generally through per-forations in casing. Chemical placement anddiversion across large zones and all perforationsare difficult. Selective and oriented perforatingattempt to prevent sand production by avoidingweakly consolidated intervals or aligning perfo-rations with maximum in-situ stresses toincrease perforation stability.3

An effective and widely used sand-controlmethod, gravel packing places granular media, orgravel, around mechanical filters, or metalscreens, inside perforated casing or openhole.4

The “gravel” is clean, round natural sand or syn-thetic material that is small enough to excludeformation grains and some fine particles fromproduced fluids, but large enough to be held inplace by screens. A gravel and carrier-fluid slurryis pumped into perforations and the annulusbetween screens and perforated casing or open-hole. Gravel is deposited as carrier fluid leaksinto formations or circulates back to surfacethrough the screens.

For help in preparation of this article, thanks to Hal Riordan,Houston, Texas, USA; and Ray Tibbles, Rosharon, Texas.

Summer 2001 53

In some areas and under certain formationconditions, stand-alone screens may be an alter-native to gravel packing or frac packing. Initialproductivity from screen-only completions is usu-ally good, but solids can eventually plug screens.In contrast, gravel packs tend to maintain pro-ductivity and sand-control integrity for longerperiods because of increased wellbore stability.However, many screen-only completions fail toadequately exclude sand. Other wells completedwithout gravel packing have not failed com-pletely, but produce at reduced rates because ofplugged or eroded stand-alone screens.

Horizontal stand-alone screen in openhole

In-Situ Consolidation andSelective or Oriented Perforating Cased-Hole Gravel Pack Cased-Hole Frac Pack

Openhole Gravel PackOpenhole Stand-Alone Screen

Horizontal gravel-packed screen in openhole

Intermediatecasing

Resin

Cement

Perforations

Fracture

Gravel

Screens

Blank pipe

Filter cake

Openhole

Screens

Gravel

Productioncasing

Productioncasing

> Sand control. Selective or oriented perforating avoids weak zones and minimizes sand production; cemented casing provides positive zonal isolation.Cased-hole gravel packing provides sand control in laminated formations, lower quality sands or marginally economic vertical wells. Frac packingcombines stimulation and sand control in stacked pay or reservoirs with poorly sorted grains and low fluid transmissibility. In openhole, stand-alonescreens control sand in “clean” formations with large well-sorted grains and wells with short producing lives. Openhole gravel packs or frac packsmaintain productivity or injectivity longer than stand-alone screens in “dirty” formations with poorly sorted grains, high-rate wells with highertransmissibility and large reserves, and high-cost, high-risk deepwater or subsea completions.

1. Carlson J, Gurley D, King G, Price-Smith C and Walters F:“Sand Control: Why and How?” Oilfield Review 4, no. 4(October 1992): 41-53.

2. Hydraulic fracturing uses specialized fluids injected atpressures above the formation breakdown stress to cre-ate two fracture wings, or 180-degree opposed cracks,extending away from a wellbore. These fracture wingspropagate perpendicular to the least rock stress in apreferred fracture plane (PFP). Held open by a proppant,these conductive pathways increase effective wellradius, allowing linear flow into the fractures and to thewell. Common proppants are naturally occurring orresin-coated sand and high-strength bauxite or ceramicsynthetics, sized by screening according to standard USmesh sieves. In standard fracturing, the fracture tip is the final areathat is packed with proppant. A tip-screenout designcauses proppant to pack, or bridge, near the end of thefractures in early stages of a treatment. As additional

proppant-laden fluid is pumped, the fractures can nolonger propagate deeper into a formation and begin towiden or balloon. This technique creates a wider, moreconductive pathway as proppant is packed back towardthe wellbore.

3. Behrmann L, Brook JE, Farrant S, Fayard A,Venkitaraman A, Brown, A, Michel C, Noordermeer A,Smith P and Underdown D: “Perforating Practices ThatOptimize Productivity,” Oilfield Review 12, no. 1 (Spring2000): 52-74.

4. Sherlock-Willis TM, Morales RH and Price P: “A GlobalPerspective on Sand Control Treatments,” paper SPE50652, presented at the SPE European Petroleum Confer-ence, The Hague, The Netherlands, October 20-22, 1998.Parlar M and Albino EH: “Challenges, Accomplishments,and Recent Developments in Gravel Packing,” Journal ofPetroleum Technology 52, no. 1 (January 2000): 50-58.

As a result, there is a trend among operatorstoward gravel packing to protect screens andprovide better sandface completions. Sizinggravel correctly and completely packing theannulus stabilize formations and protect screensfrom erosion and gradual plugging. However,standard drilling and gravel-packing operationsmay trap mud and carrier-fluid residue betweengravel and formations or within the gravel pack,damaging both reservoir and pack permeabilities.Completion-induced damage results in high flow-initiation or drawdown pressures and reducedproductivity after gravel packing. This is espe-cially true when low-cost, conventional fluid sys-tems are used without regard for performance.

This article focuses on gravel packing of hori-zontal, openhole wells. We review sand-controlmeasures, including stand-alone screens, waterpacking and Alternate Path, or shunt-screen,technology. We discuss challenges and recentdevelopments in carrier fluids and filter-cakeremoval. Case histories demonstrate state-of-the-art wellbore cleanup, including chemicals,procedures and tools. Gravel-placement sim-ulation, techniques for gravel packing above frac-turing pressure or with oil-base fluids andexpandable screens also are included.

Casing or Openhole? Horizontal and high-angle drilling are common fornew and reentry wells even in reservoirs requiringsand-control completions. Cased-hole comple-tions are uncommon in horizontal wells becausecementing casing is difficult, perforating costs arehigher, and perforation cleanup to achieve effi-cient gravel packing often is problematic.Horizontal openholes also are less sensitive todrilling and completion damage because of sig-nificantly larger inflow areas. However, horizontalsections are drilled with specialized reservoirdrilling fluid (RDF) that contains primary polymersfor viscosity, bridging agents like sized calciumcarbonate [CaCO3] or sodium chloride [NaCl] saltand additives (usually starch or another polymer)tailored to control fluid loss (right).5

54 Oilfield Review

Loose filter cake, or "fluff"

Filter cake

300-ft/min [91-m/min] displacement rate

Borehole wall

Formation0.04 in.1 mm

> Filter cake. A properly formulated and conditioned reservoir drilling fluid (RDF) deposits a thin, low-permeability filter cake on borehole walls that does not deeply invade formations. Componentsinclude polymers for viscosity, bridging and weighting agents, and fluid-loss additives that seal withina few formation-grain diameters to minimize fluid and particulate invasion of productive intervals.Base brines, salts, CaCO3 and barite are common weighting agents. Bridging agents and fluid-lossadditives pack against a borehole wall. Proper RDF conditioning and wellbore displacements removeloose RDF material, or “fluff,” and minimize filter-cake thickness.

1000100

Mobility (Kh/µ), 1000 mD-ft/cp

Flow

effi

cien

cy, %

1011

10

100

Reduced flow efficiency

High flow efficiency

Best-fit curve for 12 high-rate wells Best-fit curve for 8 high-rate wells

Cased-Hole Frac-Pack Productivity

> Casing or openhole? Production data demonstrate the impact of perforated casing on wellinflow performance. In reservoirs with lower transmissibility—permeability times height (kh)divided by fluid viscosity (µ)—below about 40,000 mD-ft/cp, flow efficiency is high for perforated,cased-hole completions with frac-packs for sand control and stimulation. In high-rate wells,however, stimulation benefits can be lost when reservoir kh is high or fluid viscosity is lowbecause flow is choked by perforations. In formations with kh/µ greater than 40,000 mD-ft/cp,operators should consider openhole completions and, if possible, horizontal sections in payintervals to avoid reduced flow efficiency from perforation restrictions and turbulence. Stand-alone screens, openhole gravel packs and screens that expand against borehole walls are sand-control options for high-transmissibility reservoirs.

Summer 2001 55

Exposing more of the reservoir to a wellboreincreases productivity and injectivity whilereducing pressure drop and decreasing flowvelocities in formations. Less drawdown andlower fluid velocities also minimize sand produc-tion in some formations. Because cased-holeperforations and flow turbulence limit productiv-ity, particularly in high-rate wells, operators oftencomplete horizontal wells openhole for optimalproductivity.6 Using reservoir transmissibility—permeability times height (kh) divided by fluid vis-cosity (µ)—as a basis, BP evaluated frac-packed,cased-hole well productivity in terms of flow effi-ciency (previous page, top).7

As reservoir-fluid viscosity increases or per-meability and net-to-gross pay decrease—lessproductive pay, more silts and shales—operatorsmay need to frac-pack wells for stimulation and sand control in laminated or layered reser-voirs. As reservoir-fluid viscosity decreases orformation permeability and net-to-gross payincrease—more productive pay, fewer silts andshales—perforated casing reduces productionefficiency and stimulation benefits may benegated because flow is choked by perforations.

In high-permeability, high-productivity forma-tions, operators should consider openhole comple-tions with high-angle or horizontal sections inreservoirs, and stand-alone screens, gravel packsor expandable screens for sand control. Openholecompletions requiring sand control almost doubledfrom 1997 to 2000. Of these wells, about 20% were gravel packed in 1997 and 1998 com-pared with 40% in 2000. This trend is projected tocontinue, reaching about 60% in 2003.8 Controllingsand production in long, horizontal openholesrequires new technologies, detailed engineering,advanced planning and care execution.

Stand-Alone Screens or Gravel Packing? In the 1980s and early 1990s, stand-alone screenswere the primary sand-control option for horizon-tal openholes. Gravel packing long sections wasnot considered feasible. Operators installed con-ventional wire-wrap screens in openholes with-out gravel packing, but eventually turned toprepacked and premium-mesh designs for betterperformance and reliability (above right).

Because of larger inflow areas, initial produc-tivity from horizontal screen-only completions isusually higher and flow rates per unit length ofwellbore are lower than in vertical wells.However, many screen-only completions loseproductivity as formation solids plug screens,eventually failing because of increased sand pro-duction from high-velocity erosion of remaining

open screen areas. At first, stand-alone screenswere run in unconditioned drilling mud instead ofclean, filtered completion fluid. Poor mud filteringand conditioning, inadequate wellbore displace-ments after drilling and before installing screens

and lack of filter-cake cleanup led to screen plugging and low productivity.

Installing screens in openhole without gravel packing is successful in many wells, but effectiveness and reliability vary.9

5. Houwen O, Ladva H, Meeten G, Reid P and Williamson D:“A New Slogan for Drilling Fluids Engineers,” OilfieldReview 9, no. 1 (Spring 1997): 2-16.

6. Tiffin D, Stevens B, Park E, Elliott F and Gilchrist J:“Evaluation of Filter Cake Flowback in Sand ControlCompletions,” paper SPE 68933, presented at the SPEEuropean Formation Damage Conference, The Hague,The Netherlands, May 21-22, 2001.

7. Bennett CL: “Sand Control Design for Open Hole Comple-tions,” SPE Distinguished Lecturer Program presenta-tions, September 1999 to May 2000.

Wire-Wrap Screen Prepacked Screen

Premium-Mesh Screen

Perforated basepipe

Wire wrap

Protectivecover

High- permeability

gravel

Porous-membrane,fiber or metal-sintered

laminate

> Sand-control screens (Courtesy of U.S. Filter/Johnson Screens). Wire-wrapscreens, the most common design, generally consist of a drilled or slottedbasepipe with wire filters spaced to retain specific gravel sizes. In early versions, fluids flowed only through openings in the basepipe, so ribs, or rods,were added to form a small annulus for increased flow capacity and to reduceplugging. Prepacked screens are manufactured with high-permeability resin-coated gravel between two layers of wire-wrap filter media. Premium-meshscreen designs use a specialized wire-cloth media around a wire-wrap-screen.These screens usually include a shroud with drilled holes for additional pro-tection during installation or have openings designed to reduce erosion causedby sand grains and fine particles impacting directly on the internal filter mediaat high velocity.

8. Parlar M, Bennett, Gilchrist J, Elliott F, Troncoso J, Price-Smith C, Brady M, Tibbles RJ, Kelkar S, Hoxha Band Foxenberg WE: “Emerging Techniques in GravelPacking Open-Hole Horizontal Completions in High-Performance Wells,” paper SPE 64412, presented at theSPE Asia Pacific Oil and Gas Conference and Exhibition,Brisbane, Queensland, Australia, October 16-18, 2000.

9. Richard BM, Montagna JM and Penberthy WL Jr :“Horizontal Completions—2 Stand-Alone Screens Vary inEffectiveness,” Oil & Gas Journal 95, no. 32 (August 11,1997): 63-69.

Initially, failure rates averaged 50 to 65% for screen-only completions, but decreased toabout 20% as drilling fluids and cleanup techniques improved.10 Wells with reactive siltsand shales still have high failure rates caused bysand production and reduced productivity due toplugging of stand-alone screens. In the NorthSea, recovery factors for screen-only wells gener-ally meet expectations; sand-control failures havebeen low, but have increased over time. Some

stand-alone screen completions, however, pro-duce at restricted rates because of sand produc-tion, screen plugging and erosion, and are not yetclassified as failures.

Operating companies and service providerscontinue to develop guidelines and define criteriafor selecting sand-control techniques in horizontalopenhole wells (above). The choice betweenstand-alone screens and gravel packing dependson formation permeability, clay and fines content,

grain sizes and particle sorting in addition to bore-hole stability and the number of silt and shaleintervals exposed to openhole sections.

Most screen-only completions in Gulf ofMexico horizontal wells fail during the first threeyears of production, and average time for screen-only failures in the North Sea is about three tofour years.11 If flow rates are not high andexpected productive life is two to three years,stand-alone screens may be a good solution forwells with limited reserves because of lowerinstallation costs. In addition to rock strength andpermeability, determining factors for screen andgravel selection are formation grain-size sortingand uniformity and fines content (next page,top).12 Uniformity is an indication of variation information grains from larger to smaller sizes.Sorting is a measure of the range from coarse tofine formation particles.

If the risk of producing sand is limited, stand-alone screens can be used in “clean” (low finescontent), homogeneous sands with high net-to-gross pay and uniformly sorted, large grains—median sizes (D50) greater than 200 µm—such asthose in the North Sea.13 For weak sandstoneswith medium-size grains—median size (D50) ofabout 125 µm—primary factors to consider aregrain size uniformity and fines content. If forma-tions have poorly sorted grains or a fines contentgreater than 5%, operators should considergravel packing to combat sand erosion andscreen plugging from fines migration.

Weakly consolidated sandstones with smallgrains, as in many Gulf of Mexico formations,typically contain high percentages of dispersedfines and clays—particles less than 44 µm—thatmake stand-alone screens impractical. Wells in“dirty” (high fines content) or nonhomogeneousunconsolidated formations with low permeabilityand poorly sorted, small grains—median sizes(D50) of about 80 µm—should be gravel packedbecause stand-alone screens may not maintainproductivity and provide reliable long-term sandcontrol. Frac packing also is an option.

In high-cost, high-rate wells, expensive reme-dial interventions may affect field profitability oroverall project economics. In fact, most gas-delivery contracts have major monetary penaltiesfor defaulting on production quotas. For thesecost- and risk-sensitive completions, uncertaintyand historically high failure rates for stand-alonescreens justify gravel packing.

56 Oilfield Review

10. Bennett C, Gilchrist JM, Pitoni E, Burton RC, Hodge RM,Troncoso J, Ali SA, Dickerson R, Price-Smith C andParlar M: “Design Methodology for Selection ofHorizontal Open-Hole Sand Control CompletionsSupported by Field Case Histories,” paper SPE 65140,presented at the SPE European Petroleum Conference,Paris, France, October 24-25, 2000.

11. Perdue JM: “Completion Experts Study Gulf of MexicoHorizontal Screen Failures, Petroleum EngineerInternational 69, no. 6 (June 1996): 31-32.McLarty J: “How to Complete a Horizontal Well in theGulf of Mexico: Operators Share Experiences,”Petroleum Engineer International 70, no. 11 (November1997): 63-70. Schlumberger internal horizontal-well database.

Medium

Sand quality (net pay, particle sorting and uniformity, formation homogeneity and permeability)

Med

ium

Like

lihoo

d of

sol

ids

prod

uctio

n (ro

ck s

treng

th a

nd in

-situ

stre

sses

)

Low

High

Low High

Field I Field HField F

Major depletion expected (poor aquifer support, depletion, compaction drive, or gas blowdown)

Gulf of Mexico North Sea OtherPressure support (good aquifer support,gas or water injection)

Openhole gravel pack

No sand control

Openhole gravel pack or expandable screens

Field AField B

Premium-mesh stand-alone screens

Conventional stand-alone screens

Field G

Field F1 Field E

Field D

Field C

> Stand-alone screen or openhole gravel pack? A crossplot of likely solids production withrespect to formation sand quality helps operators develop guidelines for evaluating andselecting completion methods. Wells in low- to medium-quality reservoirs with a high probabilityof producing sand may need openhole gravel packs, but wells in high-quality sandstones withsimilar likelihood of sanding can be completed with stand-alone conventional wire-wrap,prepacked or premium-mesh screens. In reservoirs with gas and water injection or strongaquifers for pressure support and medium- to high-quality sands, screen-only completionsmay be adequate, while reservoirs of similar quality with depletion, or compaction, drive mayhave to be gravel packed.

12. Tiffin DL, King GE, Larese RE and Britt LK: “New Criteriafor Gravel and Screen Selection for Sand Control,”paper SPE 39437, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 18-19, 1998. Bennett et al, reference 10.

13. The designation “D” in analysis of grain-size distribu-tions is the mesh opening that retains a specific cumula-tive percent of particles. For example, D50 is the meshopening, in inches millimeters or microns (µm) abovewhich 50% of the formation or gravel—sand or syntheticproppant—particles are retained.

14. Parlar and Albino, reference 4. Penberthy Jr WL, Bickham KL and Nguyen HT:“Horizontal Completions—Conclusion: Gravel PackingPrevents Productivity Decline,” Oil & Gas Journal 95,no. 35 (September 1, 1997): 56-60.

Summer 2001 57

Unless formations have extremely clean,well-sorted grains, subsea production and injec-tion wells that may produce sand and mostdeepwater—greater than 1000 to 2000 ft [305 to 610 m]—completions should be gravel packed to avoid costly remedial interventions, espe-cially when large reserve volumes are involved.High-rate gas wells also need to be gravelpacked when sanding and screen erosion causesafety concerns.

Stand-alone screens may be justifiable incertain applications: • nonsubsea wells with a short productive life

and uniform hole collapse, regardless of rate • low-rate nonsubsea wells with few shale or

silt intervals and partial or no hole collapse • nonsubsea injection wells with a small wellbore-

screen annulus that limits flow around screens.Marginal economics, capital investment limi-

tations, potential completion damage or produc-tivity reduction and loss of zonal isolation arereasons not to gravel pack openhole horizontalwells. However, most operators agree that gravelpacking is preferred in horizontal openhole wellsto reduce sand-related failures and minimizeassociated productivity decline. High-pressure,high-temperature (HPHT) wells may be excep-tions because of fluid performance and compati-bility limitations. These HPHT sand-controlapplications present challenges for completionengineers and are currently under evaluation.

Water Packing or Alternate Path Screens? Openhole gravel packing has evolved as operatorsand service companies gain experience and a bet-ter understanding of completion damage andgravel placement in horizontal wells. If gravelpacking is required, operators must choosebetween two field-proven techniques currentlyavailable for completing long openhole sections—water packing and Alternate Path screens.

Water packing uses low gravel concentra-tions—0.5 to 2 pounds of proppant added (ppa) pergallon [0.06 to 0.2 g/cm3]—transported in low-vis-cosity carrier fluids, usually brine (left).14

Stand-Alone Screen and Gravel-Pack Criteria for Completion Design

Formation characteristicsCompletion

type

Wire-wrap or prepacked screens

Premium-mesh screens

Openhole gravel pack

Content of fines less than 44 µm

Less than 2%

Less than 5%

Greater than 5%

Uniformity coefficient D40/D90

Less than 3

Less than 5

Greater than 5

Sorting coefficientD10/D95

Less than 10

Less than 10

Greater than 10

> Screen and gravel-pack criteria. As formations become less uniform, completionselection needs to incorporate parameters other than median (D50) grain sizesfrom sieve analysis. Sorting coefficient D10/D95, uniformity coefficient D40/D90 andpercentage of 44-µm and finer particles address formation quality and influencescreen and gravel-pack designs. For example, in wells with sorting coefficientgreater than 10, uniformity coefficient greater than 5 and 44-micron fines contentgreater than 5%, an openhole gravel pack may be the most appropriate choice.

Blank pipe

1 2 3 4 5

678910

SlurryHeel Toe

CasingScreens

Filter cakeOpenhole

Screen Washpipe

Gravel duneWash pipe

Beta wave

Alpha wave

Typical Surface Treating-Pressure Response for Water Packing

Preflush stage

Slurry stage

Displacement stage

Alpha wave: slurry transport along the screens

Slurry at toe of well Beta wave: gravelpacking from toe to heel

Annularpackoff

Surfa

ce tr

eatin

g pr

essu

re, p

si

Treatment duration, min

>Water packing. Gravel packing with low-viscosity fluids, usually brine, relies on deposition ofgravel around screens on the low side of an annulus, while slurry with low gravel concentrationsmoves in turbulent flow along the top (top and bottom right). The borehole must be sealed with anRDF filter cake to minimize fluid leakoff. If circulation—fluid returns to surface—is maintained, gravel moves toward the far end, or toe, of horizontal sections in an “alpha” wave (1 to 5). If a slurrydehydrates and forward packing ceases in intervals with high fluid losses, gravel fills the annulusand forms a bridge. The result is an incomplete pack beyond that point. After bridging occurs orgravel reaches the toe, packing proceeds back toward the beginning, or heel, of a horizontal sectionin a “beta” wave (6 to 10). Surface treating pressures provide an indication of how water-packingtreatments are progressing (bottom left).

The low side of an annulus is packed first untilgravel reaches the far end, also called the toe, oruntil gravel packs off and forms a bridge becauseof high fluid leakoff. Gravitational forces domi-nate this “alpha” wave, so gravel settles likewind-blown sand dunes on a beach until reach-ing an equilibrium height. If fluid flow remainsabove critical velocity for particle transport,gravel will move down a horizontal sectiontoward the toe.

After the alpha wave stops, a second, or“beta,” wave packs the annulus topside backtoward the beginning of a horizontal section, alsocalled the heel, from the toe or a bridge. The betawave requires enough fluid velocity to maintainturbulent flow and move gravel along the top of awellbore annulus. This wave continues until spacebetween pack and formation becomes small rela-tive to gravel particle size. Low-permeability filtercake is required to prevent fluid loss into forma-tions, maintain equilibrium gravel height, avoidgravel bridging, which leads to incomplete pack-ing, and allow screens to be installed without dif-ferential sticking. Reduced annular flow as a resultof fluid loss from filter-cake erosion or exceeding

fracturing pressure increases downstream gravelheight and the possibility of premature bridgingand voids in packs.

Water packing relies heavily on filter-cakeintegrity and may not completely pack the annu-lus, which may introduce uncertainty about com-pletion success and consistency. For this reason,specialized and carefully designed RDF is used todrill openhole reservoir sections. An RDF shouldform thin, low-permeability filter cake that is brit-tle, but able to withstand erosion while gravel isbeing pumped. These characteristics make filtercake easier to remove or, at least, less damagingto formation permeability.15

If required, cleanup treatments must followwater packing to maintain filter-cake integritywhile placing gravel. In reservoirs with low net-to-gross pay, silt and shale intervals exposed tocompletion fluids can be eroded and transportedby high-velocity flow for long periods, potentiallyreducing final gravel-pack permeability. Usingprepacked or premium-mesh screens to controlsand in case of an incomplete pack compensatessomewhat for water-packing limitations, but amore reliable method was needed.

Alternate Path gravel packing uses shunts onthe outside of screens and high gravel concen-trations—4 to 8 ppa [0.48 to 0.96 g/cm3]—inviscous carrier fluids to ensure complete gravelpacks below bridges that form between screensand casing or openhole (above).16 Unlike waterpacking, this technique does not rely on filter-cake integrity. If an annular gravel bridge forms,pressure in the annulus increases and slurrydiverts into shunt tubes, the only open flow path.Shunt tubes provide conduits for slurry to bypasscollapsed hole, external inflatable packers orannular gravel bridges at the top of intervals oradjacent to zones with high fluid leakoff.17

58 Oilfield Review

15. Pitoni E, Ballard DA and Kelly RM: “Changes in SolidsComposition of Reservoir Drill in Fluids During Drillingand the Impact on Filter Cake Properties,” paper SPE54753, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, May 31-June 1, 1999.

16. Jones LG, Yeh CS, Yates TJ, Bryant DW, Doolittle MWand Healy JC: “Alternate Path Gravel Packing,” paper SPE 22796, presented at the 66th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas, USA,October 6-9, 1991.

17. Shunt-screen technology was developed by Mobil (now ExxonMobil), in the late 1980s and early 1990s andlicensed to Schlumberger.

CasingHeel Toe

Shunt tube

Shunttube

Nozzles

Nozzle

Slurry

1

2

3

4 5

Washpipe Blankpipe Gravel Screen Openhole Filter cake

Surfa

ce tr

eatin

g pr

essu

re, p

si

Treatment duration, min

Gravel formsDisplacement stage

Pressure increaseas flow divertsinto shunt tube

Slurry stage

Alpha wave: slurry transport along the screens

Typical Surface Treating-Pressure Response for Shunt-Tube Screens

Preflush stageAnnular packoffSlurry at toe of well

WashpipeScreen

> Alternate Path gravel packing. This technology ensures a complete gravel pack around screensacross an entire horizontal section. Shunt tubes attached on the outside of screens provide conduitsfor slurry to bypass gravel bridges and fill annular voids (top and bottom right). Shunt packing does notdepend on filter cake to prevent fluid loss. If the annulus between screens and openhole packs offprematurely (3), slurry diverts into the shunts and gravel packing proceeds toward the toe even withno fluid returns, or circulation, to surface (4 and 5). Pump rate usually is reduced after shunt flowbegins and pressure increases because of small shunt-tube diameters (bottom left).

Summer 2001 59

Large-scale tests simulating extremely highleakoff proved that single shunt tubes could pack2000-ft horizontal intervals even with no fluidreturns to surface.18 Engineers adapted AlternatePath screens for longer horizontal openholes bydesigning nozzles and shunts that reduce gravelbuildup inside shunts, by using nondamaging flu-ids with good gravel-carrying capacity and byinstalling pipe shrouds with drilled holes aroundthe entire assembly to help centralize screensand protect shunt tubes.

Gravel does not make turns into small exitports easily, so large angled nozzles extendinginto the flow stream reduce the tendency forgravel to settle and concentrate inside shunts.Shunts with ports, or nozzles, serve as packingtubes. For extremely long intervals, transportshunts without exit ports are attached along theentire length of screen assemblies to limit slurrydehydration by reducing carrier-fluid leakoff intothe annulus and deliver slurry to packing tubes at4 to 6 bbl/min [0.6 to 0.9 m3/min].

Transport tubes are connected to packingtubes by a manifold at each screen joint. Slurryflows down packing tubes or from transport topacking tubes and exits through wear-resistant,carbide nozzles to pack voids behind screens at0.5 to 2 bbl/min [0.08 to 0.3 m3/min]. Blank pipeabove a screen assembly also can be fitted withtransport tubes to provide a path for slurry incase of hole collapse or a gravel bridge at the topof an interval.

Gravel-Placement Simulation Computer tools are an integral part of designingsand-control treatments that reduce remedialworkovers and completion failures. Simulatinggravel-packing processes allows sensitivity anal-ysis to be performed using various gravel-packingparameters (above). These simulator tools helpoperators evaluate completion intervals, carrierfluids, gravel sizes and concentrations, pumprates, downhole fluid leakoff and returns at sur-face. Simulations also are used to optimizewashpipe, screen and service tool configura-tions.19 For example, SandCADE softwareincludes six modules—gravel-placement simula-tion for water and shunt packing, pump schedulegenerator, frac-pack simulator, tubing movementand packer hydraulics calculations, and torqueand drag analysis—that provide necessary infor-mation to design, execute and evaluate water-packing and shunt-packing treatments.

Gravel-placement calculations are based on a pseudothree-dimensional wellbore simulator

capable of modeling horizontal or vertical, cased-hole or openhole gravel packs. A model based onsimilar concepts has been developed to simulateAlternate Path gravel packing with shunt tubes.Treatments can be designed with service tools insqueeze or circulating mode. In circulating posi-tion, surface-valve, or choke, pressure and fluid-return rate also can be modeled. The pumpschedule module uses specific job requirementsand input such as pump rate, gravel concentrationand fracture parameters to generate gravel-pack-ing treatments, reducing the number of iterationsneeded to obtain satisfactory pump schedules.

18. Jones LG, Tibbles RJ, Myers L, Bryant D, Hardin J andHurst G: “Gravel Packing Horizontal Wellbores withLeak-Off Using Shunts,” paper SPE 38640, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, October 5-8, 1997.

19. Karlstad S, Sherlock-Willis T, Rajan S, Samsonsen B and Monstad PA: “An Evaluation and Design Approachto Gravel-Pack Treatments in the Gullfaks Field,” paperSPE 48978, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana,USA, September 27-30, 1998.

0% 0 to 20% 21 to 40% 41 to 60% 61 to 80% 81 to 99% 100%

Nor

mal

ized

radi

us

1.0 0.5 0

-0.5 -1.0

Measured depth, ft12,392.0 12,835.7 13,279.4 13,723.0 14,166.7

1.0 0.5 0

-0.5 -1.0

Effect of Formation Permeability

Measured depth, ft12,392.0 12,835.7 13,279.4 13,723.0 14,166.7

Nor

mal

ized

radi

us

1.0 0.5 0

-0.5 -1.01.0 0.5 0

-0.5 -1.0

Effect of Skin

Measured depth, ft12,392.0 12,835.7 13,279.4 13,723.0 14,166.7

Nor

mal

ized

radi

us

1.0 0.5 0

-0.5 -1.01.0 0.5 0

-0.5 -1.0

Effect of Wash-Pipe OD/Screen ID

Nor

mal

ized

radi

us

1.0 0.5 0

-0.5 -1.01.0 0.5 0

-0.5 -1.0

Measured depth, ft12,392.0 12,835.7 13,279.4 13,723.0 14,166.7

Effect of Fluid Viscosity

1.0 0.5 0

-0.5 -1.0

Nor

mal

ized

radi

us

1.0 0.5 0

-0.5 -1.0

Measured depth, ft12,392.0 12,835.7 13,279.4 13,723.0 14,166.7

Effect of Gravel Concentration1.0 0.5 0

-0.5 -1.0

Nor

mal

ized

radi

us

1.0 0.5 0

-0.5 -1.0

Measured depth, ft12,392.0 12,835.7 13,279.4 13,723.0 14,166.7

Effect of Pump Rate

Gravel-pack efficiency

500 mD

5000 mD

OD/ID=0.8

OD/ID=0.3

Skin=10

Skin=100

0.4 cp

4 cp

1 ppa

3 ppa

4 bbl/min

1 bbl/min

> Gravel-placement simulation. The risk of gravel bridging increases as formation permeability andinterval length increase or reservoir fluid viscosity decreases. Factors that affect gravel packing such as formation characteristics, fluid leakoff, screen configurations, completion hardware and treatmentparameters can be modeled using computer software. Pack efficiency decreases as formation permeabilityincreases (top left). Low-permeability filter cake or high skin—damage—result in less fluid leakoff toformations and higher pack efficiency (top right). Carrier fluid tends to divert into the inner annulus asspace between washpipe and screens increases—the ratio of washpipe OD to screen ID ratios—resultingin reduced pack efficiency (middle left). Although the difference can be great, it is not significant in thisexample. Increasing carrier-fluid viscosity to reduce leakoff can improve gravel-transport characteristicsand pack efficiency (middle right). Early annular bridging may occur as gravel concentrations increase(bottom left). Gravel-packing efficiency decreases as pump rates are reduced and fluid leakoffincreases (bottom right).

In the past, frac packs, which often failedbecause of premature gravel packoff, weredesigned solely using hydraulic-fracturing simu-lators that neglected completion hardware insidewellbores—crossover ports in gravel-packingpackers, blank pipe, screens and washpipe.Users now can specify tip-screenout designs andsimulate frac-packing treatments with a recentlydeveloped coupled wellbore and fracture sim-ulator.20 This modified simulator, based on apseudothree-dimensional hydraulic fracturingsimulator, calculates parameters like gravel dis-tribution in fractures, fracture height and two-dimensional fluid flow as boundary conditions fora pseudothree-dimensional wellbore simulator.

Slurry flow is simulated along with well incli-nation effects, gravel settling and bridgingaround screens, and fluid flow through screens.In addition, the enhanced fracture simulator sup-ports tip-screenout designs in high-permeabilityformations. Inducing gravel packoff in wellboresby deliberately reducing pump rate or shiftingservice tools to circulation at the end of treat-ments also can be modeled.

Once a final pumping schedule is obtained, atubing-movement module calculates friction,buckling, ballooning, piston and thermal effects,and allows users to design seal assemblies inpackers that compensate for potential tubularmovement. Packer hydraulics calculations helpgenerate procedures to run gravel-pack packerssafely and avoid premature release. Torque anddrag analysis provides estimates to safely runcompletion assemblies to total depth withoutgetting stuck or damaging components.

Water Packing in China During May 2001, Schlumberger completed anoffshore oil well in China’s Bo Hai Bay where theoperator had drilled an 81⁄2-in. borehole for a pro-posed gravel pack. No fluid losses were reportedwhile drilling a 634-m [2080-ft] horizontal section.A series of SandCADE design simulations was runto optimize openhole water-packing procedures(below). Gravel-placement simulations indicatedthat 31⁄2-in. tubing would minimize gravel settlingand improve pumping efficiency.

Pumping rates from 3 to 8 bbl/min [0.5 to 1.25 m3/min] were modeled to determine packingefficiency. At both 7 and 8 bbl/min [1.1 and 1.25 m3/min] higher pressures and fluid leakoffresulted in gravel bridging and pack efficienciesof 58 and 88%, respectively. With no leakoff andfull returns to surface, pump rates of 3 to 6 bbl/min [0.95 m3/min] resulted in a 100% packefficiency, but 3 bbl/min was considered too lowbecause of potential gravel settling in low spotsalong a horizontal well profile.

Water packing at 5 bbl/min [0.8 m3/min] wasselected as the highest rate with lowest risk ofbridging that resulted in a complete pack. Thenext step was to determine allowable fluid lossby varying skin or formation permeability alongthe openhole from 5 mD and no losses to 350 mDand about 2 bbl/min [0.3 m3/min] of fluid returns.The alpha wave stalled when return rates fellbelow 2 bbl/min, and returns of less than 3 bbl/min were considered unacceptable by theoperator because of possible increasing lossesfrom filter-cake erosion.

Torque and drag monitoring and simulationwhile running and pulling drillpipe to displaceRDF with solids-free fluids helped the operatorestablish friction factors in casing and open-hole. These data were used in the SandCADEtorque and drag module to establish horizontallimits for various workstrings. This analysis pre-dicted possible buckling of 31⁄2-in. tubulars dur-ing screen installation.

In spite of additional precautions, bucklingproblems occurred as predicted while attemptingto run screens on 31⁄2-in. drillstring, so the screenassembly was pulled and rerun on 5-in. drillpipe.A water-packing procedure was performed afterswitching back to a 31⁄2-in. workstring. To verifycirculation, fluids returns of 4.7 bbl/min [0.75 m3/min] were established by pumpingfiltered brine at 5 bbl/min before placing gravelwith 0.5-ppa slurry. Pumping for 11 hours at 5 bbl/min resulted in an estimated pack effi-ciency of 158% based on 81⁄2-in. gauge holevolume. A post-pack cleanup treatment was per-formed to dissolve remaining filter cake.

60 Oilfield Review

20. Sherlock-Willis T, Romero J and Rajan S: “A CoupledWellbore-Hydraulic Fracture Simulator for RigorousAnalysis of Frac-Pack Applications,” paper SPE 39477,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 18-19, 1998.

21. Tibbles R, Blessen E, Qian X, Steven B, Pardo C, Hurst G,Kubota R and Mysko P: “Design and Execution of a 3000-ft Horizontal Gravel-Packed Completion (AKazakhstan Case History),” paper SPE 64410, presentedat the SPE Asia Pacific Oil and Gas Conference andExhibition, Brisbane, Queensland, Australia, October 16-18, 2000.

Rate,bbl/min

8

7

6

5

4

3

0.5

0.5

0.5

0.5

0.5

0.5

205

280

369

450

570

759

68

88

100

100

100

100

1.5

2.0

2.8

4.9

5.8

6.8

28

83

158

254

390

536

2625

2000

1465

1020

650

340

2863

2016

1647

1151

733

391

Gravelconcentration, ppa

Total pumptime, min

Gravel-packefficiency, %

Duneheight, in.

Beta-waveinitiation, min

Circulatingpressure, psi

Surfacepressure, psi

>Water-packing design. Prior to water packing a 634-m [2080-ft] horizontal well section in Bo Hai Bay,China, a series of computer simulations was run to optimize the design. Pump rates were modeled in 1-bbl/min [0.16-m3/min] increments from 3 to 8 bbl/min [0.5 to 1.25 m3/min] with a constant gravelconcentration of 0.5 ppa. At 7 bbl/min [1.1 m3/min] and above, gravel nodes form during alpha wavesbecause of high differential pressures between the openhole-screen annulus and screen-washpipeannulus. The nodes develop further and gravel bridges form at the heel of the well as pressureincreases during the beta wave. Some bridging still occurs at 6 bbl/min. At 3 bbl/min, packing efficiencyis 100%, but alpha-wave height is about 80% of the annulus volume. Pumping at 5 bbl/min [0.8 m3/min]results in a complete pack with an annular alpha-wave height of 55%.

Summer 2001 61

Shunt Packing in Kazakhstan Fit-for-purpose modifications and careful engi-neering extend Alternate Path gravel packing toextremely long horizontal, openhole sections.Operated by Texaco, North Buzachi field in west-ern Kazakhstan near the Caspian Sea, is 300 km[190 miles] north of Aktau, the nearest city. In1999, Well NB4Z was one of the first horizontalwells drilled in this shallow unconsolidated sand-stone reservoir, which produces relativelyviscous oil. Gravel packing a proposed 3000-ft[914 m], 81⁄2-in. openhole section required an esti-mated 85,000 lbm [38,560 kg] of gravel, soTexaco evaluated both water-packing and shunt-packing completion operations (right).21

The NB4Z horizontal section was much longerthan previous 1100-ft [335-m] shunt-screen com-pletions, so screen designs and pumping sched-ules were optimized to improve efficiency, reduceinstallation time and allow higher pump rates.The AllPAC design consisted of two large trans-port tubes that branched off at each screen jointto feed two packing tubes (right). This configura-tion decreased the number of shunt connectionsby 50% and reduced potential fluid loss andslurry dehydration along the screens.

Gravel was pumped in circulating mode—annulus open—with no washpipe insidescreens. When gravel arrived at the top screen,the slurry dehydrated immediately as carrier fluidleaked through the screen and an annular bridgeformed at the top of the horizontal section. Slurrydiverted into the shunts and gravel packing con-tinued. The treatment was pumped at 4 bbl/minuntil wet gravel caused mixing problems, andrate had to be reduced so the blender could keepup. Surface treating pressure increased through-out the job and was high enough to exceed frac-turing stress downhole. However, formationbreakdown did not occur because of friction inthe shunts.

Shunt technology was the key to successfulexecution of this extremely long horizontal, open-hole gravel pack in a remote area. Gravel packingwithout washpipe saved rig time, and a specialthread connection ensured proper shunt-tubealignment. Of 100 screen joints, 97 lined upexactly the first time. Screen makeup and runningspeed were about six joints per hour. A completegravel pack was achieved, placing 33% moregravel than the theoretical annular volume.

Shunt packing

102,000

15

0

3

18

6

405

Water packing

102,000

7

8

15

29

0.5

4857

Gravel volume with 20% excess, lbm

Screen running time, hr

Washpipe runningand pulling time, hr

Gravel pumping time, hr

Total completion time, hr

Gravel concentration, ppa

Fluid volume, bbl

< Comparison of water packing and shunt pack-ing. Texaco chose Alternate Path technology forthe NB4Z well in North Buzachi field, Kazakhstan,because completion time and fluid volumerequirements were significantly less than thoseof water packing. It takes additional time toassemble and run shunt screens, but pumpingtime is reduced by 80% because gravel concen-tration is much higher. Total completion time forshunt packing is 30% less than water packing.Shunt-packing fluid volumes are 10 to 20% ofwater-packing requirements, in this case lessthan 10%, which is important in remote areaswith limited water supplies.

Transport tube Nozzles

Packing tube

9393

ShroudScreens

QUANTUMgravel-pack packer

Oil-bearing layerAllPAC screens

AZERBAIJANTURKMENISTAN

UZBEKISTAN

KAZAKHSTAN

Caspian Sea

Baku

Aktau

North Buzachifield

> Alternate Path design for North Buzachi field in Kazakhstan (top insert). AllPAC screens for the TexacoNB4Z well consisted of two large transport tubes that branched off at each joint of screen to feed twopacking tubes (bottom insert). This configuration decreased the number of shunt connections by 50%and significantly reduced fluid loss and potential slurry dehydration along the 3000-ft openhole section.

Initial production was just 34 B/D [5 m3/d] ofwater and 1257 B/D [200 m3/d] of oil, three timesthe production from a horizontal perforated-linercompletion in the field.

Choosing between water-packing and shunt-packing methods requires operators to assesslogistics, risks and costs for each application.Both techniques have been used successfully togravel pack long, horizontal openhole wells. Thesuccess rate for completely packing long open-holes by water packing is about 70%, while forshunt packing, it is greater than 95%.22 Successis related primarily to shale content and shalereactivity with drilling and completion fluids,length of reservoir section and formation perme-ability. When gravel packing with Alternate Pathscreens, filter cake can be removed duringgravel-packing operations because a sealedwellbore is not required.

Filter-Cake Removal Gravel-pack plugging during production is largelya function of RDF filter-cake cleanup. Decisionsabout filter-cake cleanup depend on screen type,gravel size and well design—screen-only or

gravel-pack completion, production or injectionwell. If cleanup is required, engineers mustdecide which filter-cake components to remove.Filter-cake cleanup techniques vary from flow-back and production without cleanup to aggres-sive displacement procedures and multiple-stagechemical treatments placed with coiled tubing.23

Filter cake formed by RDF contains polymer,bridging and weighting agents and fluid-lossadditives as well as drilled solids. Acids, alpha-amylase enzymes or oxidizers remove fluid-lossadditives, usually starch or other polymers.Bridging agents, typically sized calcium carbon-ate or sodium chloride salt, are dissolved byacids and unsaturated brines, respectively. Whendrilled solids are absent, laboratory tests indicatethat the impact of filter cake on gravel-pack pro-ductivity often is negligible.

Filter-cake removal, either by forming pin-holes or by peeling off, is achievable throughflowback during production if a borehole is rela-tively stable. Complete polymer break is notnecessary. Some reduction in gel strength usu-ally is sufficient to induce flow at low pressuredifferentials. However, flowback often can be

problematic, especially for small gravel sizes,prepacked or premium-mesh screens and lowdrawdown pressures.

Filter cake containing drilled solids mayrequire high drawdown pressures—greater than200 psi [1.38 MPa]—to initiate flow when filtercake is trapped between gravel and formation. Inaddition, retained permeability after flowbackcan be extremely low—less than 1% of originalreservoir permeability.24 Test results and fielddata suggest that most horizontal, openholegravel packs require some type of cleanup.25

Flowback without chemical cleanup is viablein certain long, horizontal openhole completions,but more production logging data are needed toquantify its long-term impact on reservoir man-agement. Premature water or gas breakthrough,or coning, in areas where pinholes form or filtercake peels off may make wells uneconomicbefore all recoverable reserves are produced.Nonuniform cleanup has similar risks.

Enzymes and oxidizers that attack only starchand polymers or acids that dissolve CaCO3 bridg-ing agents and break polymer gels clean up filter-cake components. Because starch fractions in

62 Oilfield Review

24. Hodge RM, Augustine BG, Burton RC, Sanders WW andAtkinson DJ: “Evaluation and Selection of Drill-In FluidCandidates to Minimize Formation Damage,” SPE Drillingand Completion 12, no. 3 (September 1997): 174-179. Burton RC and Hodge RM: “The Impact of FormationDamage and Completion Impairment on Horizontal WellProductivity,” paper SPE 49097, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 27-30, 1998. Price-Smith et al, reference 23.

25. Brady ME, Bradbury AJ, Sehgal G, Brand F, Ali SA,Bennett CL, Gilchrist JM, Troncoso J, Price-Smith C,Foxenberg WE and Parlar M: “Filtercake Cleanup inOpen-Hole Gravel-Packed Completions: A Necessity or a Myth?” paper SPE 63232, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 1-4, 2000.

2 cm0.8 in.

After chelating agent soakAfter HCI soakBefore cleanup

> Filter-cake cleanup. Small-scale laboratory tests evaluated filter cake that was formed on cores by a reservoir drilling fluid with CaCO3, starch and polymer before cleanup (left) and after soaking inhydrochloric acid [HCl] or a chelating agent solution (CAS) at 180°F [82°C]. There is a single dominantconductive path after soaking with HCl (middle) and uniform filter-cake removal with CAS (right).

22. Bennett et al, reference 10. 23. Smejkal KD and Penberthy WL Jr: “Horizontal

Completions—1 Proper Drilling, Displacing Critical forOpen Hole Completions,” Oil & Gas Journal 95, no. 29(July 21, 1997): 71-78. Foxenberg WE and Lockett CD: “DisplacementTechnology to Ensure a Clean Well Bore,” PetroleumEngineer International 71, no. 10 (October 1998): 23-28. Price-Smith C, Bennett C, Ali SA, Hodge RM, Burton RCand Parlar M: “Open Hole Horizontal Well Cleanup inSand Control Completions: State of the Art in FieldPractice and Laboratory Development,” paper SPE50673, presented at the SPE European PetroleumConference, The Hague, The Netherlands, October 20-22, 1998.

26. Parlar M, Tibbles RJ, Chang FF, Fu D, Morris L, Davison M,Vinod PS and Wierenga A: “Laboratory Development ofa Novel, Simultaneous Cake-Cleanup and Gravel-Packing System for Long, Highly-Deviated or HorizontalOpen-Hole Completions,” paper SPE 50651, presented atthe SPE European Petroleum Conference, The Hague,The Netherlands, October 20-22, 1998. Brady ME, Ali SA, Price-Smith C, Sehgal G, Hill D andParlar M: “Near Wellbore Cleanup in OpenholeHorizontal Sand Control Completions: LaboratoryExperiments,” paper SPE 58785, presented at the SPEInternational Symposium on Formation Damage,Lafayette, Louisiana, USA, February 23-24, 2000.Stanley FO, Rae P and Troncoso JC: “Single-StepEnzyme Treatment Enhances Production Capacity onHorizontal Wells,” paper SPE/IADC 52818, presented atthe SPE/IADC Drilling Conference, Amsterdam, TheNetherlands, March 9-11, 1999.

Summer 2001 63

RDF formulations are much larger than those ofthe polymers, just removing starch from filtercakes significantly reduces flow-initiation pres-sure and permeability impairment. Enzymes oroxidizers can be used late in the treatment duringslurry displacement to remove starch and poly-mers, but leave bridging agents. Conventionalfilter-cake-removal treatments in gravel-packedcompletions typically include single-step oxidizer,enzyme and acid treatments or two-step enzymeand oxidizer soaks followed by acid.

Until recently, these treatments were per-formed after gravel packing with coiled tubingafter running tubing, requiring a second roundtrip. The MudSOLV service includes new systemsfor filter-cake removal that combine a chelating-agent solution (CAS) with an enzyme to attackstarch and CaCO3 simultaneously, but slowly formore uniform wellbore cleanup during or aftergravel packing (previous page).26

Test results indicate that filter-cakeremoval—the time at which a sharp increase influid leakoff occurs during an overbalancedsoak—by a CAS is an order of magnitude slowerthan with hydrochloric acid [HCl], and thatremoval times can be controlled by adding more

enzyme or viscoelastic surfactant (VES) toincrease viscosity (above). This low reaction rateallows a CAS and enzyme system to be placed inlong horizontal wells without creating thief zonesat initial contact points, a common occurrencewhen HCl is used.

Solids invasion into formations during filter-cake removal, an inherent risk in conventionaltwo-step treatments with enzyme or oxidizers fol-lowed by acid, is minimized or eliminated bybalanced soaks with CAS solutions. This newapproach avoids many sludge and compatibility

problems that are encountered when strong acidscontact some crude oils as well as difficultieshandling acids offshore. Another important con-sideration is screen corrosion when chemical areallowed to soak over long time periods. Testing ofmetallic screen samples exposed to HCl and CASindicates that corrosion rates for chelating agentsare much lower than for HCl (below).

In the past, treatments to remove filter cakewere performed after screens and gravel packswere installed, regardless of gravel-placementmethod. This approach involved pulling workstring

Leak

off v

olum

e, c

m3

60

50

40

30

20

10

00 5 10 15 20 25 30

Time, hr

HCI CAS/enzyme CASCAS/enzyme/VES

> Reaction rate. Sudden increases in fluid leakoff during overbalanced laboratory soaks indicatethat filter-cake removal with chelating agent solutions (CAS) are an order of magnitudeslower than with HCl. Reaction rates for combined CAS and enzyme solutions are measuredin hours, allowing these systems to be placed across long horizontal, openhole sectionswithout creating thief zones and high fluid loss. Reaction rates are controlled by adding CAS,enzyme or viscoelastic surfactant (VES). Additional VES for higher viscosity or more CASslows reaction rates; additional enzyme increases reaction rates.

Screen openings, µm

7.5% HCI with 1% inhibitor

CAS with 0.2% inhibitor

Screen material

J-55 carbon steel 0.0110 0.0037

13-Chrome steel 0.0130 0.0001

316-L steel 0.0580 0.0007

Before exposure 150 150

After exposure 250 150

Corrosion rate, lbm/ft2

> Corrosion rates. Screen openings did not change when exposed to CAS inlaboratory tests, but HCl increased the openings from 150 to 250 µm. This isenough to adversely affect sand control and completion integrity when soaking for extended time periods at high temperatures after gravel packing.

tubing and washpipe—tripping out and trippingin—to displace carrier fluid from screens andspot chemicals that attack specific filter-cake components.

This process is time-consuming and expen-sive, especially when long soak periods arerequired for enzymes or oxidizers to react withstarch and polymers in the filter cake. Inability tocirculate after gravel packing with conventionaldownhole assemblies was the reason for thispractice. Also, if a low-permeability filter cakewas intact, pumping breaker solutions downworkstrings and directly into an openhole sec-tion, or bullheading, could be difficult and resultin inefficient, nonuniform filter-cake removal.

A simple, low-cost mechanical modificationprovides a circulation path down the workstringand washpipe, back across the annulus betweenwashpipe and screens and up to surface via theannulus between workstring and casing. The new MudSOLV service tool uses the wash-pipe inside screens to spot slow-reacting breakersolutions for filter-cake cleanup immediately aftergravel packing (above).27 Slow-reacting breakerslike oxidizers, enzymes or enzymes combined witha CAS can be placed across horizontal sectionswithout significant loss of circulation for moreuniform filter-cake removal in much less time thanconventional coiled tubing cleanup treatments.

This approach eliminates the need for coiledtubing and allows breaker solutions to soakwhile wells are prepared for production, typicallyone to two days to trip tubing in and out. Sand-control screens are exposed to chemicals over along time period, and depending on metallurgy,corrosion may result in loss of sand-controlintegrity if corrosive fluids like HCl are allowed tosoak during these applications.

In principle, filter-cake cleanup with slow-reacting breakers like enzymes is possible duringwater-packing operations, but this increasesuncertainty about filter-cake integrity. Addingslow-reacting breakers during predicted betawaves mitigates this risk to some extent, but

64 Oilfield Review

1

2

3

4

5

> Service tool for circulating or squeeze packs and post-pack cleanup. The MudSOLV tool is a recent development that allows circulationdown internal washpipes immediately after water-packing or shunt-packing operations—position 1: running in hole; position 2: drop smallball; position 3: increase pressure to open crossover for gravel packing; position 4: drop larger ball; position 5: increase pressure to disablecrossover for gravel packing and enable new crossover for circulation. This modification allows chemicals to be placed across stand-alonescreens or gravel packs for subsequent soak, injection or circulation, eliminating the need for coiled tubing cleanup treatments. Displacingscreens with brine after using acids in carrier fluids to remove filter cake is another application.

29. Becker TE and Gardiner HN: “Drill-In Fluid Filter CakeBehavior During the Gravel-Packing of HorizontalIntervals—A Laboratory Simulation,” paper SPE 50715,presented at the SPE International Symposium on OilfieldChemistry, Houston, Texas, USA, February 16-19, 1999. Johnson MH, Ashton JP and Nguyen H: “The Effects of Erosion Velocity on Filter-Cake Stability During GravelPlacement of Openhole Horizontal Gravel-PackCompletions,” paper SPE 23773, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 26-27, 1992.

27. Parlar et al, reference 26. Brady et al, reference 26.Parlar et al, reference 8.

28. Barrilleaux MF, Ratterman EE and Penberthy WL Jr:“Gravel Pack Procedures for Productivity andLongevity,” paper SPE 31089, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 14-15, 1996. Penberthy et al, reference 14.

30. Brady et al, reference 26.31. Parlar et al, reference 26.

Parlar et al, reference 8. 32. Saldungaray PM, Troncoso JC and Santoso BT: “Simul-

taneous Gravel Packing and Filter Cake Removal inHorizontal Wells Applying Shunt Tubes and Novel Carrierand Breaker Fluid,” paper SPE 68205, presented at theSPE Middle East Oil Show, Bahrain, March 17-20, 2001.

Summer 2001 65

does not completely eliminate the risk of induc-ing losses and premature bridging. It is possibleto remove filter cake while gravel packing, butcleanup treatments usually have been performedafterward for several reasons.

First, water packing relies on competent filtercake to maintain critical slurry velocity for graveltransport and prevent alpha waves from stallingdue to fluid loss to formations and slurry dehy-dration. Therefore, filter-cake cleanup prior towater packing is not a viable option.28 Second,scouring and abrasion from gravel slurry in turbu-lent flow above a critical rate could erode filtercake and increase fluid leakoff.29 Tests indicatethat filter-cake dissolution times decrease signif-icantly as filter-cake thickness is reduced, andare considerably shorter than times required togravel pack extremely long horizontal sections.30

Finally, VES fluids gelled in solutions of enzymes,a CAS, or both for shunt packing and removing

filter cake simultaneously were only recentlydeveloped and applied in the field.31

Shunt packing is independent of external filter-cake condition, which allows slow-reacting break-ers to be combined with carrier fluids to gravelpack and clean up filter cake in a single step.Breakers can be selected to target specific filter-cake components without affecting carrier-fluidproperties. Simultaneous cleanup and gravel pack-ing with shunts ensure breaker contact throughoutthe annulus and across an entire gravel pack.

Why drill long horizontal openhole sectionsand then accept limited or nonuniform inflow?Compared with conventional cleanup techniques,simultaneous gravel packing and filter-cakeremoval improves horizontal gravel-pack produc-tivity and minimizes risk of water and gas break-through, or coning (below). This approachreduces costs by decreasing required fluid vol-umes and eliminating separate cleanup treat-ments with coiled tubing.

Single-Step Gravel Packing and Cleanup In 1999, Repsol-YPF and Schlumberger analyzedwell construction practices and production datafor Widuri field in the Indonesian Java Sea nearsoutheast Sumatra.32 The objective was to opti-mize completions in Talang Akar formation, anunconsolidated fluvial deposit with medium-sizegrains, high permeability and a tendency to pro-duce sand. This field was developed with verticaland high-angle wells until 1996, when the firsthorizontal wells were drilled and completed withstand-alone premium-mesh screens.

In 1997, water packing was first used to gravelpack openhole sections using brine and low gravelconcentrations of 0.5 to 1 ppa [0.12 g/cm3].Gravel-pack efficiency—gravel placed versusestimated hole volume—in 15 water-packingcompletions through the beginning of 1998 was71%, but a number of jobs achieved 100% efficiency. Since then, more than 60 horizontal

Simultaneous gravel packing and filter-cake removal

Gas and oil coning afternonuniform filter-cake removal

Uniform inflow after simultaneous treatment

Conventional post-pack filter-cake cleanup treatment

First point of acid or breaker contact or high-permeability streak

Gas

Oil

Untreated filter cake

Water

Gas

Oil

Water

Gas

Oil

Untreated filter cake

Water

Gas

Oil

Water

> Simultaneous filter-cake cleanup. Pumping aggressive chemicals like HCl acid directly down tubing typically removes filter cake at the point of first contact, causing preferential fluid loss at that location (top left). Localized filter-cake removal leaves much of the wellbore untreated with filter cakeintact. The resulting smaller inflow area may promote water and gas breakthrough, or coning (bottom left). Spotting breaker solutions across screens withcoiled tubing is more effective, but also requires additional fluid volumes and cost compared with placing gravel and removing filter cake in a single step.A MudSOLV simultaneous gravel-packing and cleanup strategy using Alternate Path screens ensures that less aggressive, or slow-reacting, chemicalscontact filter cake around the annulus along the entire wellbore (top right). As a result, the cleanup process is more efficient, flow-initiation and productiondrawdown pressures are reduced, and inflow across horizontal, openhole sections is more uniform (bottom right).

wells have been drilled and completed by waterpacking. However, some of these wells subse-quently produced sand and had electrical sub-mersible pump failures. Production log data andimages from a downhole camera suggested thatsanding might be eroding screens and damagingdownhole pumps.

In 1998, Repsol-YPF engineers implemented aseries of water-packing improvements. An RDFwith low-permeability filter cake was used tominimize fluid leakoff. Filter-cake integrity wasconfirmed by establishing circulation prior togravel packing. After gravel was pumped, filtercake was removed by chemical treatments placedwith coiled tubing. By the end of 1999, these pro-cedures increased average gravel-pack efficiencyto 89%, with one instance of sand production.

To further improve completions, Schlumbergerrecommended simultaneous gravel packing and fil-ter-cake removal using a polymer- and solids-freeMudSOLV carrier fluid with a ClearPAC viscoelasticsurfactant (VES) and AllPAC shunt screens (below).This technique reduces rig, coiled tubing and fluidcosts by eliminating post-pack cleanup treat-ments. Because Alternate Path gravel packing

ensures complete packs, it also may eliminatethe need for premium-mesh screens as a backupsand-control measure.

The final formulation balanced CAS, enzymeand VES concentrations to provide enough vis-cosity for gravel transport, but not so high as tocause slow diffusion through the filter cake.Using this fluid to remove filter cake formed on 1- to 2-darcy synthetic cores with the proposedRDF resulted in 92% retained permeability.

Simultaneous gravel packing and filter cakecleanup was implemented on the Aida-10 well.This well, characteristic of other Widuri fieldwells, was drilled to drain a 45-ft [14-m] sandwith 2- to 5-darcy permeability, 29% porosity, 5% clay content and medium-size grains thatrequire 20/40 mesh gravel. The reservoir hashigh transmissibility and a strong waterdrive,which typically results in rapid water break-through and more than 90% produced water.Once the target interval was penetrated, 95⁄8-in.casing was set just above the productive zonebefore drilling resumed. However, casing wasinadvertently cemented 100 ft [30 m] above thetarget in the Aida-10 well, leaving 60 ft [18 m] of

exposed coal and shale. The 651-ft [198-m] hori-zontal section was drilled with CaCO3, starch andpolymer RDF.

Exposed shale and coal also were a reason touse shunt screens. Because shunt packing pro-ceeds from heel to toe, coal and shale intervalsare exposed to carrier fluid only until adjacentsands are packed. This contrasts with exposurethroughout a water-packing process as the alphawave progresses from heel to toe followed by abeta wave from toe to heel. In addition, shunttubes allow openhole annular bypass in casecoal and shale layers collapse.

Prior to pumping gravel in April 2000, circula-tion tests at 8 bbl/min [1.3 m3/min]indicated totallosses with zero fluid returns to surface. For oper-ational simplicity and to achieve homogeneousdensity, slurry was batch mixed and pumped at 6 bbl/min. Initially, there was almost no surfacepressure, but after displacement began, treatingpressure increased to 200 psi [0.14 MPa]—thefirst surface indication of gravel bridging andflow diverting to the shunts. Pump rate wasreduced gradually as pressure continued to build.Pumping pressure reached 2300 psi [15.9 MPa]and remained there for several minutes as slurryflowed through the shunts and filled voids aroundthe screens.

Repsol-YPF evaluated this treatment basedon packing efficiency and productivity index (PI)using benchmarks from 10 wells completed inthe same reservoir during 1999. These wells hada 93% packing efficiency and a PI of 97 bbl/psi-D[2.2 m3/kPa-d]. The 20,700 lbm [9390 kg] placedgravel exceeded theoretical annular volume by12%. Based on excess gravel and surface pres-sure response, the completion team concludedthat the openhole was packed completely. Thewell produced more than 13,000 B/D [2070 m3/d]total fluid with 40 to 60% water and no sandafter installing an electrical submersible pump.

The Aida-10 PI was more than 409 B/psi-D[9.4 m3/kPa-d], substantially higher than previouswater-pack completions in the field. A relativelyslow increase in water production compared withprevious well completions indicates a more uni-form, lower pressure drawdown along the open-hole section. To date, there has been no sandproduction, and the objective of enhancing pro-ductivity has been met. These results indicatethat one-step shunt packing and cleanup is pos-sible without compromising productivity anddoes not require a competent filter cake and cir-culation to ensure gravel placement.

66 Oilfield Review

Transport tube

Packing tubeProtective shroud

Nozzle

Screen Basepipe

>Widuri field AllPAC screens. The shunt-screen assembly consisted of 12-gauge wire-wrap screens on 41⁄2-in. basepipe with four shunt tubes and a7-in. shroud. Two shunts were used as transport tubes, and two with carbidenozzles every 6 ft were used as packing tubes. Shunts were placed eccentri-cally along the screens to minimize overall diameter. The shroud protectsand centralizes screens in openhole to ensure that at least 0.8 in. [2 cm] ofgravel is placed inside the shroud on the low side of the annulus.

Summer 2001 67

Design and Selection Methodology Oil companies and service providers have estab-lished applications and technical limitations forgravel-placement methods, downhole tools andfluid chemistry. However, because the number ofpotential solutions is large, selecting the bestoptions for gravel packing and filter-cake cleanuprequires expertise and worldwide field experiencefrom drilling, completion and stimulation fluids tocompletion engineering and rigsite operations.

Experience gained during the past four years isthe basis for a rigorous approach for selecting fil-ter-cake cleanup methods.33 Case-based reasoning

(CBR) software is now available to capture gravel-packing knowledge and experience, and identifyapplicable techniques for a given set of well con-ditions and parameters. The CBR software ratio-nalizes the number of filter-cake removal optionsby eliminating alternatives based on establishedtechnical limitations and by ranking remainingoptions based on expert input, and laboratory andfield case-history databases (below).

Engineers answer yes-or-no questions aboutindividual cases, well parameters and conditions,completion variables, downhole tools and filter-cake cleanup techniques. The system uses these

answers to “reason a fit” between a particularwell and cases in the CBR knowledge base, pos-ing additional questions as needed to furtherrefine the level of fit, or reduce the number ofapplicable cleanup methods. Each answerimpacts the applicability of a case, eliminatingsome from consideration, and promoting ordemoting others. In this way, well scenarios arequickly matched to the smallest number of poten-tial filter-cake removal options, and then thosecases can be ranked.

Because of the cost of filter-cake removal,laboratory analysis often may be needed todecide between flowback alone and variouschemical cleanup treatments. To avoid unneces-sary testing, a laboratory database is searchedfor existing data applicable to the top three solu-tions. If sufficient data are not available, moretests are conducted. Flow-initiation pressure andretained permeability data are input in NODALanalysis software or sophisticated reservoir sim-ulators to predict production rates, evaluatecosts versus benefits and identify the most tech-nically and economically sound solution for agiven pair of reservoir drilling fluids and comple-tion fluids.34

33. Mason SD, Houwen OH, Freeman MA, Brady ME,Foxenberg WE, Price-Smith CJ and Parlar M: “e-Methodology for Selection of Wellbore CleanupTechniques in Open-Hole Horizontal Completions,” paperSPE 68957, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, May21-22, 2001.

34. NODAL analysis couples the capability of a reservoir toproduce fluids into a wellbore with the capacity of tubu-lars to conduct flow to surface. The technique namereflects discrete locations—nodes—where independentequations describe inflow and outflow by relating pres-sure losses and fluid rates from outer reservoir bound-aries across the completion face, up production tubingand through surface facility piping to stock tanks. Thismethod allows calculation of rates that wells are capa-ble of delivering and helps determine the effects of dam-age, or skin, perforations, stimulations, wellhead orseparator pressure and tubular or choke sizes. Futureproduction also can be estimated based on anticipatedreservoir and well parameters.

Applicable tools, placement and procedural solutions

Applicable chemistry solutions

Compatibility ofsolutions

Combined solutions

Rank combinedsolutions

Laboratoryevaluation

MudSOLV engineering toolkit

Solutions evaluations

Materialrequirements

Economics

MudSOLVrecommendation

Project data CBR solution finder

Field case-historydatabase

> Identifying and selecting cleanup techniques. A systematic MudSOLVapproach to filter-cake removal for horizontal, openhole completions usescase-based reasoning (CBR) and productivity prediction software along with simple Web-based calculators for volumetric and cost estimates. This MudSOLV process is a query system with tables to compare scenarios withthe knowledge base, which has two separate case bases, one for applicable fluid chemistry options and one for tools, gravel placement and proceduraloptions. A compatibility check resolves inherent incompatibilities betweencombinations from these case bases and ranks them to provide the final outputrecommendations. The CBR software relies on databases of field experienceand laboratory test results to continually update the knowledge base.

Gravel Packing North Sea Wells Many wells operated by BP in the North SeaHarding field require sand-control measures.Parts of the reservoir consist of sand and shale sequences with about 40% shale. Payintervals are clean, well-sorted, 3- to 4-darcy unconsolidated sandstones with 250-µm D50, or

median grain size, and a D40/D90, or uniformitycoefficient, of 2. Shales are composed of highlyreactive clay, varying from a few meters to lessthan a millimeter thick. Sieve analysis of com-bined sands and shales indicates a high contentof poorly sorted fines.

Because of low net-to-gross pay and highfines content, BP selected Alternate Path gravelpacking to ensure a complete gravel pack. Tofacilitate gravel packing with shunt tubes, poly-mer-free VES carrier fluid was specified for low-damage and low-friction characteristics. The CBR

68 Oilfield Review

Is it practical to condition RDF through shakers to prevent plugging or damage?Are prepacked or premium-mesh screens to be installed in the well?Is there a significant risk of damaging or prematurely setting the packer while runningcompletion hardware in used RDF?Can completion brine be formulated with sufficient density for well control?Is it likely that fluid circulation will be required to run hardware to total depth (TD)?After drilling with the intended RDF, has this completion hardware been run in thisfield with brine in the openhole, and with acceptable losses?Is it likely that sufficient drag to impede running of completion hardware to TD willbe encountered?Will a clean, unused RDF pass through completion hardware without plugging?Can a viscous fluid be formulated that is compatible with the RDF filter cake?Can a viscous fluid be formulated that is compatible with formation fluids?Are there facilities to effectively shear and filter a viscous fluid?Can completion brine be formulated that is compatible with the RDF filter cake?Can completion brine be formulated that is compatible with formation fluids?Will there be a capability to spot fluids in the openhole interval after installingcompletion hardware?Are there tools available that allow spotting, or circulating, cleanup treatment fluidsafter installing completion hardware?Will the well be gravel packed?Will the gravel-packing carrier fluid be a nonaqueous oil or synthetic fluid?Will the well be gravel packed using a viscous fluid process?Will the openhole be underreamed?Will shunt-tube screens be used in the completion?Will the well be gravel-packed by water packing?Will this be an openhole, stand-alone screen or slotted-liner completion?Has the use of a clear, viscous displacement fluid been ruled out?Is the generic composition of the clear, viscous fluid, which might be used as thedisplacement fluid, known?Has the use of completion brine as a displacement fluid been ruled out?Is the generic compostion of the completion brine, which might be used as thedisplacement fluid, known?

CBR queries

Output: potential solutions

Prior to running screens: Displace to 1) conditioned RDF or 2) unused RDF or 3) solids-freeviscous fluid or 4) completion brine.Gravel placement and cleanup options: 1) simultaneous or 2) post-gravel-pack cleanup.

Answer

YesNoNo YesNoYes No YesYesYesYesYesYesYes Yes YesNoYesYesYesNoNoNoYes NoYes

>Wellbore-displacement and gravel-placement queries and potential solutions from CBR softwareoutput for well completions in the North Sea Harding field. Leaving conditioned RDF in the openholesection was the most cost-effective option that neither plugs screens nor compromises hole stability.Both gravel packing with simultaneous filter-cake removal and post-pack cleanup were identified asfilter-cake removal options for shunt packing with VES carrier fluid.

Summer 2001 69

methodology identified conditioned RDF, unusedRDF, solids-free viscous fluids and completionbrine as four potential displacement options priorto running screens (previous page).

BP prohibits HCl and organic acids because ofpotential low spots in horizontal wellbores where

stagnant fluid raises corrosion concerns.Therefore, single-stage enzymes, single-stageoxidizers and combination CAS and enzymes arethe only available chemical options (above). Allthree chemistry cases are applicable for post-pack treatments, but required coiled tubing

placement because a MudSOLV service tool was notavailable to circulate immediately after gravel pack-ing. Chemical costs were about the same for simul-taneous and post-pack cleanup, so coiled tubing andrig costs made simultaneous gravel packing and filter-cake cleanup the most economical option.

Is a divalent brine (Ca, Mg, Zn) needed, as a breaker fluid carrier to provide required equivalent fluid weight, or density?Are the bridging agents or drill solids in the RDF primarily CaCO3?Are the bridging agents or drill solids in the RDF primarily sized salt?Are there likely to be low spots in the completion where breaker may accumulate andremain for periods longer than the onset of injection or production?Is the formation mineralogy (zeolites, siderites, chlorites) sensitive to mineral acids?Is the formation fluid incompatible with HCI?Is there calcite (carbonates) in the formation that is incompatible with Formic acid at high concentration?Does the operator prohibit use of HCI?Does the operator prohibit use of organic acids?Will the RDF contain a significant partially hydrolized polyacrylamide (PHPA) polymer ?Is the openhole interval sandstone with a carbonate-cementing material?Can surface facilities—separators and heaters—handle acids?Is the well to be an injector without any prior production stage?Is the formation sensitive to acid corrosion inhibitor? (If unknown, call an expert.) Is the RDF oil or synthetic-based fluid?Is the pH of the carrier fluid between 3 and 10?Is there starch in the RDF?Is there xanthan in the RDF?Is there scleroglucan in the RDF?Is the production dry gas with little or no oil condensate?Is the desired or required carrier brine compatible with VES?Have reservoir fluids demonstrated a tendency to form emulsions with VES?Is a post-gravel-packing circulation tool applicable for gravel-packing operations?Is the bottomhole temperature above 250°F [121°C]?

No YesNoYes NoNoNo

YesYesNoNoNoNoNoNoYesYesYesNoNoYesNoNoNo

CBR queries

Output: potential solutions

Applicable filter-cake cleanup chemistries: 1) none (backflow) or 2) enzyme or 3) Oxidizer or 4) CAS and enzyme treatmentsProcedure and chemistry combination for: Simultaneous gravel-packing and filter-cake removal with 1) VES and enzyme or 2) VES, CAS and enzymeProcedure and chemistry combination for: Post-gravel-pack filter-cake removal with 1) oxidizer or 2) VES and enzyme or 3) VES, CAS and enzymePlacement requirement: Coiled tubing

Answer

> Fluid-chemistry and filter-cake cleanup queries and potential solutions from CBR software output forwell completions in the North Sea Harding field. The chemistry case-base analysis step indicated single-stage enzymes, single-stage oxidizers and combination CAS and enzymes as options. Incompatibilitywith VES eliminated oxidizers for simultaneous gravel packing and filter-cake removal, leaving flowbackwithout cleanup, enzyme alone or combination CAS and enzyme as potential solutions.

Three options remained after analysis:flowing the well and producing without filter-cake cleanup, and simultaneous gravel packingand cleanup with either enzyme alone or CAS and enzyme in the carrier fluid. Laboratory testing provided flow-initiation pres-sures and retained permeabilities for these threeoptions, which were used in simulators to predictproduction rates (above). Production estimateswere essentially the same regardless of chemicaltreatment or flowback without cleanup, but somefilter-cake removal was warranted becauseinflow along the horizontal section might not beuniform and could lead to water or gas coningand reduced well life.

After setting a 75⁄8-in. liner in the first well to employ this procedure, about 300 ft [91 m] of81⁄2-in. openhole was drilled at a 75° inclinationwith the same synthetic oil-base mud that wasused in upper hole sections. This drilling fluidwas displaced with potassium and sodium-formate RDF containing polymer, starch andCaCO3, and the openhole section was under-reamed from 81⁄2 to 10 in. [22 to 25 cm].

The RDF was filtered to 63 µm through a 230-gauge mesh shaker before running ashrouded 41⁄2-in., wire-wrap shunt screen with

16-gauge 400-µm openings to prevent screenplugging. Mud engineers tested conditioned RDFon a sample screen in a modified fluid-loss cell toensure that no plugging occurred.

After screens were run to total depth, theopenhole section was displaced with filteredNaCl brine, the top packer was set, and the ser-vice tool was shifted to circulating position.Gravel was injected at 5 bbl/min in a VES carrierfluid with enzyme to dissolve filter-cake polymersuntil gravel bridging occurred. When flowdiverted into the shunts, pump rate was reducedto 2 bbl/min.

A total of 180 bbl [28 m3] of slurry wasinjected in one hour, indicating a complete packbased on gauge-hole estimates. Water packingwith lower gravel concentrations would haverequired three and a half hours with questionablegravel-packing efficiency. BP conducted a seriesof pressure buildup tests after gravel packing.These indicated that mechanical skin improvedfrom 5.5 to 2.7 over the first eight weeks ofproduction. Skin for openhole gravel packs inshaly reservoirs is typically about 8, so this well’s7700 B/D [1224 m3/d] oil rate was 30% higherthan the industry average.35

Gravel Packing above Fracturing Pressure Fracturing is avoided during water packing tomaintain filter-cake integrity and minimize fluidloss. However, injecting slurry above formationfracturing pressure shows promise for applicationwith Alternate Path screens. In addition to break-ing through external and internal filter cake that isnot removed by chemical treatments, potentialbenefits include additional stimulation to improveproductivity or injectivity and reduced potentialfor plugging, especially for injection wells forwhich increased flow area extends well life.36

Unlike conventional fracturing and frac pack-ing, this process does not initiate and propagatefractures with a pad of solids-free fluid or rampgravel concentrations to extend fractures.Instead, it requires only that fracture-initiationpressure be exceeded while pumping and placinggravel. This technique is a simple and cost-effective method without the complexity of tradi-tional frac packing and methods of generatingmultiple fractures.

Gravel packing above fracturing pressureuses viscous fluids pumped in squeeze mode.Slurry dehydration occurs once fracturing pres-sure is reached, and a small crack penetratesfilter cake and formation. High leakoff intocreated fractures causes gravel to bridge offquickly and pack the annulus across that section.Slurry is diverted through a transport tube toanother section of openhole, thereby initiatingmultiple fractures along the wellbore (next page,bottom). If there is no isolation in washpipe andbasepipe annulus, slurry can dehydrate betweenscreens and openhole, allowing carrier fluid toleak off into previously fractured sections.

Some degree of annular isolation betweeninternal washpipe and screenbase pipe atselected intervals prevents gravel slurry dehydra-tion through the screens and fluid loss into sec-tions that were already fractured and packed off.This downhole tool arrangement allows selectivegravel packing of some intervals and fracturing ofothers. Using isolation devices, operators now cangravel pack near the heel in circulating mode andfrac pack near the toe in squeeze mode if desired.

A similar process, reinjection of cuttings fromdrilling operations, generates multiple fracturesaround injection points and demonstrates the fea-sibility of gravel packing above fracturing pres-sure. Pumping gravel above fracturing pressurehas been successful in cased-hole completions inthe North Sea, Gulf of Mexico and West Africa toachieve post-pack skins similar to larger conven-tional frac packs. In reservoirs with high bottom-hole pressure, this technique eliminates the needto weight up base fluids for well control. No fluid

70 Oilfield Review

Flow

ing

pres

sure

, psi

22700 1000 2000 3000 4000 5000

Oil rate, B/D6000 7000 8000 9000 10,000

2290

2310

2330

2350

Ideal Enzyme/CAS Enzyme only No cleanup

Filter-cake cleanuptreatment

Flow-initiationpressure, psi

Retainedpermeability, %

No cleanupEnzyme only

Enzyme and CAS

16042

407091

Flow-conduit performance

> Flow-initiation pressure (FIP) and retained permeability for well completions in the NorthSea Harding field (top). NODAL analysis production estimates (bottom) were about thesame for flowback alone (green) or with chemical filter-cake removal by an enzyme only(purple) or CAS with an enzyme (blue) compared with ideal inflow (orange), indicating thatCAS might not be needed to remove bridging agents. Flowback without filter-cake cleanupyields a 160-psi [1.1 MPa] FIP, much greater than the 40-psi [275 kPa] drawdown limit set byBP. Estimated drawdown was about 32 psi [220 kPa] without cleanup, so the incremental costof an enzyme treatment was justified to ensure that FIP was safely below the imposed limit.

Summer 2001 71

is circulated into the annulus when pumpinggravel in squeeze mode, and any weight fluid,even lightweight gelled oil or low-density brinecan be used.

Stone Energy Corporation drilled a new well-bore from Well B-1 to develop up-dip reserves inthe Gulf of Mexico off Louisiana, USA.37

Beginning in September 1993, the original B-1wellbore produced from a down-dip location inthe target sands until February 2000, when gasproduction ceased because of high water rates.The target zone consists of two sands separatedby a thin shale. The upper sand is fine-grainedwith an estimated permeability of 150 mD, 60% water saturation and 6 ft [1.8 m] of net pay.The lower sand is clean with large grains, 1000-mD permeability, 10% water saturation and16 ft of net gas pay on top of water. This side-track placed a 277-ft [84-m] horizontal openholesection in the lower sand body.

Because of potential sand production andstrong bottom waterdrive, Stone Energy wanteda gravel-pack completion that minimized waterinflux coning and maximized reserve recoverywithout coiled tubing filter-cake removal or reme-dial stimulation. Simultaneous gravel packingand filter-cake cleanup using a MudSOLV andClearPAC VES carrier fluid with a CAS andenzyme to dissolve starch and CaCO3 met theseobjectives. A screen-only completion was elimi-nated because of concerns about screen pluggingand erosion after water breakthrough. An AllPACscreen assembly with one shunt reduced the riskof incomplete packing, eliminated the need forlost-circulation materials prior to gravel packingand allowed wire-wrap screens to be usedinstead of premium-mesh screens (above).

XX800

GR (API)0 150

CAL (INCH)8 18

SP (MV)

MD (FT)

-120 30

RWAA (OHM-M)0 1

RFOC (OHM-M)0.2 20

RILM (OHM-M)0.2 20

RILD (OHM-M)0.2 20

AC (MICS/FT)160 60

CNC (%)60 0

PORZ (%)60 0

Packing tube Nozzle

Protective shroud Screen

Well B-1, 54° Inclination

Watercontact

> Placing gravel above fracturing pressure, Gulf of Mexico. Stone Energy Corporation selected simultaneous gravel packingand filter-cake cleanup over stand-alone screens for their Gulf of Mexico B-1 well sidetrack to avoid screen plugging anderosion when water breaks through. The operator did not want to frac pack near water (left), but decided to place gravelabove fracturing pressure in the 277-ft [84-m] horizontal, openhole section using AllPAC screens with one shunt to ensuresandface conductivity (right). A ClearPAC and MudSOLV fluid with CAS and enzyme to gravel pack and dissolve starch andCaCO3 simultaneously achieved an effective gravel pack and uniform inflow, minimizing water coning.

Intactfilter cake

Limited fractures (few inches)

Fractures (few inches) across entire section

Gravel pack

Screen

Wash-pipe seals Polished-bore receptacle

> Gravel packing above fracturing pressure. Two critical hardware elementsfacilitate gravel placement above formation fracturing pressure. Shunt screenswith transport and packing tubes ensure that multiple fractures are initiatedalong long horizontal, openhole sections (top). To prevent fluid leakoff intopreviously fractured sections and promote multiple fractures, seals placed onthe internal washpipe to match polished-bore receptacles in the screens iso-late the annulus between washpipe and screens over discrete intervals (bottom).

35. McKay G, Bennett CL and Gilchrist JM: “High AngleOHGP’s in Sand/Shale Sequences: A Case History Usinga Formate Drill-In Fluid,” paper SPE 58731, presented atthe SPE International Symposium on Formation DamageControl, Lafayette, Louisiana, USA, February 23-24, 2000.

36. Parlar et al, reference 8.

37. Godwin K, Gadiyar B and Riordan H: “SimultaneousGravel Packing and Filtercake Cleanup with Shunt Tubesin Open-Hole Completions: A Case History from the Gulf of Mexico,” paper SPE 71672, prepared for presen-tation at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September 30-October 3, 2001.

The completion team did not want to fracpack near water, but decided to gravel packabove fracture pressure to improve sandface con-ductivity. Shunt packing does not rely on filter-cake integrity, so gravel was placed with theservice tool in squeeze position to increase thelikelihood of fracturing at low rates.

The job was pumped at 5 bbl/min, below the6-bbl/min capacity of a single shunt. After 40% of the slurry was pumped, surface pressureincreased to 3400 psi [23 MPa] when a gravelbridge formed in the annulus. At this point in thetreatment, slurry diverted into the shunt, pumppressure fell to 2000 psi [14 MPa] and packingcontinued. After 75% of the gravel was placed,the job was completed with the service tool incirculating position to ensure a complete pack atthe top of the screens.

More than 150% of the gravel volumerequired to fill the calculated annular space wasplaced around screens and blank pipe. Initial gasproduction was 15 MMscf/D [430,000 m3/d] withno water. Post-completion filter-cake removalwas not needed. A formation permeability of1000-mD with zero skin matched rates forNODAL analysis with actual production, indicat-ing close to 100% flow efficiency.

Five months after completion, the first waterproduction occurred and gas rates began todecline as water production increased. After 14 months, the B-1 sidetrack was producingsand-free, flowing 2.5 MMscf/D [72,000 m3/d]gas with 2300 B/D [365 m3/d] water and recover-ing 4 Tcf [143 million m3] of gas, most of the esti-mated reserves. Uniform filter-cake cleanupcontributed to efficient drainage along the struc-tural crest of this reservoir.

Emerging Sand-Control Techniques Drillers often prefer synthetic oil-base reservoirdrilling fluid over water-base RDF for betterlubricity, higher penetration rates, improved holestability and superior shale stabilization, espe-cially for high-angle or horizontal wells.38 In addi-tion to extensive experience gravel packing withwater-base drilling and completion fluids, com-pletion engineers prefer water-base RDF becauseof concern about emulsions or sludge that formwith some oil-base systems and crude oils. Also,synthetic oil-base carrier fluids that can controlwell pressures while gravel packing were notavailable until recently.

Water-base carrier-fluids require that opera-tors switch from oil-base to water-base RDF inreservoir sections or before gravel packing. Inopenhole, this change is costly, involves displace-ment procedures that sometimes are inefficient

72 Oilfield Review

Water-Base Filter Cake After Flowback

Synthetic Oil-Base Filter Cake After Flowback

Gravel

Filter cake

Berea sandstone core

Gravel

Dispersed filter cake

Berea sandstone core

> Comparison of water-base and oil-base filter-cake removal. In laboratoryevaluations, thin-section photographs of filter cake against artificial gravelshow significant differences after oxidizer cleanup treatment and flowback.Water-base filter cake remains essentially intact (top). Retained permeabilityis established through pinholes or channels. Oil-base filter cake typically isthinner and easier to remove, and often does not require additional cleanuptreatments. The cleanup mechanism for oil-base filter cake is fundamentallydifferent than water-base filter cake; virtually all the filter cake is removedfrom the core face and dispersed in gravel pore spaces or produced throughthe gravel (bottom).

38. Gilchrist JM, Sutton LW Jr and Elliott FJ: “AdvancingHorizontal Well Sand Control Technology: An OHGPUsing Synthetic OBM,” paper SPE 48976, presented atthe SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 27-30, 1998. Chambers MR, Hebert DB and Shuchart CE: “SuccessfulApplication of Oil-Based Drilling Fluids in SubseaHorizontal, Gravel-Packed Wells in West Africa,” paper SPE 58743, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 23-24, 2000.

39. Tiffin et al, reference 6.40. Price-Smith C, Parlar M, Kelkar S, Brady M, Hoxha B,

Tibbles RJ, Green T and Foxenberg B: “LaboratoryDevelopment of a Novel, Synthetic Oil-Based ReservoirDrilling and Gravel-Pack Fluid System That AllowsSimultaneous Gravel Packing and Cake-Cleanup inOpen-Hole Completions,” paper SPE 64399, presented at the SPE Asia Pacific Oil and Gas Conference andExhibition, Brisbane, Queensland, Australia, October 16-18, 2000. Kelkar S, Parlar M, Price-Smith C, Hurst G, Brady M andMorris L: “Development of an Oil-Based Gravel-Pack

Carrier Fluid,” paper SPE 64978, presented at the SPEInternational Symposium on Oilfield Chemistry, Houston,Texas, USA, February 13-16, 2001. Ladva HKJ, Brady ME, Sehgal P, Kelkar S, Cerasi P,Daccord G, Foxenberg WE, Price-Smith C, Howard P andParlar M: “Use of Oil-Based Reservoir Drilling Fluids inOpen-Hole Horizontal Gravel-Packed Completions:Damage Mechanisms and How to Avoid Them,” paperSPE 68959, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, May21-22, 2001.

41. Oil-external, or water-in-oil, emulsions contain an inter-nal phase of water or brine droplets dispersed in an oilor synthetic hydrocarbon external phase. Water-external,or oil-in-water, emulsions contain an internal phase ofdispersed oil or synthetic-hydrocarbon droplets in awater or brine external phase.

42. Tiffin et al, reference 6.43. Tiffin et al, reference 6. 44. Sanford BD, Terry C, Bednarz MJ, Palmer C and

Mauldin DB: “Expandable Sand Screen Alternative toFracture-Packing Sand Control,” Offshore 61, no. 6 (June 2001): 78-81, 106.

Summer 2001 73

and requires complex fluid-management proce-dures on drilling rigs. In many cases, upper holesections are drilled with oil-base RDF, but reser-voir sections are drilled with water-base RDF,again requiring displacement.

Laboratory and field data indicate that pres-sure differentials for oil-base filter-cake peeloffand flowback are lower, cleanup is easier andretained permeabilities are higher than forwater-base filter cake (previous page).39 However,liftoff pressures vary when gravel is small andformation permeability changes along a well-bore. In heterogeneous reservoirs with signifi-cant permeability variation, flowback withoutcleanup can result in uneven production profilesand premature water or gas breakthrough. As inthe case of water-base filter cake, combiningcleanup chemicals with carrier fluids rather thanrelying on flowback alone further improves pro-ductivity, so it is desirable to have simultaneousgravel-packing and cake cleanup systems for oil-base RDF.40

However, bridging and weighting agents in oil-base RDF filter cake are coated with an oilphase containing oil-wetting surfactants to formoil-external emulsions.41 This makes CaCO3

particles virtually inert to acids and difficult toremove. A synthetic oil-base RDF that inverts to awater-external emulsion and makes CaCO3 parti-cles water-wet when exposed to a pH-modifyingsolution is now available to address this problem.

With specific surfactants, oil-base RDF is for-mulated as an oil-external emulsion above acertain pH and water-external emulsions below it.

Like simultaneous gravel packing and filter-cakeremoval for wells drilled with water-base RDF,this pH-sensitive chemistry eliminates a separatecleanup step.

Both water-base and oil-base carrier fluidsprovide excellent filter-cake cleanup in wellsdrilled with synthetic oil-base RDF as long as therheology is suitable for gravel packing with shuntscreens, and the aqueous phase contains a pH-modifier and bridging-agent dissolver. Oil-external emulsions, preferably with the samebase oil and brine type in the internal aqueousphase as the synthetic oil-base RDF, are anothercarrier-fluid alternative. In this case, the internalphase of the carrier fluid contains a pH-modifierand bridging-agent dissolver such as a CAS or acid.

Stand-alone screens, gravel packing and fracpacking are not the only options to stabilize open-holes. Expandable screens have a reduced diam-eter that is expanded against the borehole wallafter running in openhole and appear to offersome advantages (above).42 Rock-mechanics the-ory indicates that if screens exert force againstborehole walls, expandable screens can preventsanding because greater compaction forces arerequired to initiate rock failure and sand produc-tion at the formation-wellbore interface.

These screens eliminate gravel packing,reduce well-construction costs by allowingsmaller holes to be drilled and provide largerinside diameters for enhanced intervention capability, higher flow capacity and, possibly,better zonal isolation than conventional comple-tions with an open or gravel-packed annulus.

Expandable screens also provide a viable methodto control sanding in high-pressure, high-temper-ature reservoirs at the time of initial completion.

One concern is that a small annulus mayremain even after screen installation as a resultof washed-out and enlarged holes or inadequateexpansion. If this annulus is large enough andexists over a long continuous interval, it couldreduce expandable screen effectiveness to thatof stand-alone screens. A screen design thatexpands compliantly and conforms to the bore-hole is desirable.

Another concern is effectiveness of filter-cakecleanup after screens are expanded. Testing todate, however, indicates that screens pressedinto filter cake do not inhibit cleanup and flow-back as long as RDF solids are sized correctly andfluids are properly conditioned.43 This concernalso can be addressed by using slow-reacting filter-cake-cleanup fluids once screens are installed.

Long-term performance of expandable screensas an effective sand-control method is under eval-uation. Both laboratory testing and field trials aredefining formation parameters and reservoir con-ditions in which this technology is best applied.Field experience with expandable screens is limited, but the number of case histories isincreasing. Weatherford, currently the only sup-plier of this type of screen, reports installing about23,000 ft [7000 m] of expandable screens in about25 well applications through November 2000.44

By working together, operating companiesand service providers have made significantadvances in downhole tools, gravel-placementmethods and chemistry for drilling and comple-tion fluids during the past five years. As a result,sand-control technology for openhole comple-tions has improved considerably, from stand-alone screens and openhole gravel packing tosimultaneous filter-cake cleanup, expandablescreens and openhole frac packing.

An improved understanding of the applica-tions for various sand-control techniques basedon field performance is helping operators realizeoptimal productivity, high reserve recovery perwell and reliable completions with minimalremedial intervention. However, major chal-lenges like increasing exploration and develop-ment in deep water and more subseacompletions lie ahead. Integration of geology andpetrophysics with reservoir, drilling, completion,surface facility and production engineering disci-plines is a key to current and future sanding pre-diction and sand-control success. —MET

Compliant Expandable Screens in Openhole

Filter media Expanded screens

Protective shroud

Base pipe Running screens

> Top view of expandable screens in openhole. To reduce initial diameter,overlapping layers of filter media are sandwiched between a slotted basepipeand a protective pipe shroud with drilled holes. After these screens are run,a mandrel is pushed through the assembly, expanding the basepipe slots, filtermedia and holes in the outer shroud against the borehole wall to providesand-control integrity. Filter-media layers, or leaves, open up by sliding overeach other, and the outside diameter increases by almost 50%.

Syed Ali, Senior Staff Research Scientist at ChevronPetroleum Technology Company in Houston, Texas,USA, provides technical consultation, training andrecommendations to engineers on rock-fluid interac-tion, sandstone acidizing, formation-damage control,fluid chemistry, horizontal completion, frac-packing,high-rate water packing and formation mineralogy. In 1976 he joined Gulf Research & DevelopmentCompany in Houston as a project geologist and laterbecame a senior project geologist. After a short stint as a sedimentologist for Sohio Petroleum Company in San Francisco, California, USA, he moved to GulfScience & Technology Company in Pennsylvania, USA,as a senior research geologist. From 1981 to 1984, hewas a senior staff geologist with Gulf Oil Exploration& Production Company in New Orleans, Louisiana,USA. He moved to Chevron Production Company inNew Orleans, and spent the next 10 years as supervi-sor of the Engineering Technology Laboratory. Beforeassuming his current position in 1999, he was a tech-nical advisor for Chevron in New Orleans. A prolificauthor and industry expert in formation-damage con-trol and sandstone acidizing, Syed holds a BS degreefrom University of Karachi in Pakistan; MS degreesfrom University of Karachi and Ohio State Universityin Columbus, USA; and a PhD degree from RensselaerPolytechnic Institute in Troy, New York, USA.

Abdullah Al-Suwaidi, Drilling Manager of Abu DhabiCompany for Onshore Oil Operations (ADCO) since1999, is responsible for 13 drilling rigs. Since 1988 hehas held various positions within Abu Dhabi NationalOil Company (ADNOC), Abu Dhabi Marine OperatingCompany (ADMA) and ADCO. Abdullah received anMS degree in petroleum engineering from theUniversity of Tulsa, Oklahoma, USA, in 1987.

Clive Bennett is a senior petroleum engineer with BP Exploration, and is based near London, England.After earning a BS degree from the University ofBristol in England in 1984, he completed a PhD degreein 1987. The following year he joined BP, working as a physical chemist and chemical engineer in supportof BP Chemicals and Downstream Units, before join-ing the Upstream Unit in late 1993. For the last sevenyears, he has worked in the Sand Control & Comple-tions Team, supporting BP Business Units worldwideduring the design, implementation and evaluation of cased and openhole sand-control completions. Hiscurrent responsibilities include providing technicalsupport to the BP Angola and Azerbaijan BusinessUnits and serving as project manager for the BP SandControl & Well Completions Technology and NetworkProjects. Clive served as SPE Distinguished Lecturer(1999 to 2000) and has published many SPE papers on sand-control completions.

Pat Bixenman, Product Development Manager, Sand Control Hardware at Schlumberger ReservoirCompletions Center (SRC) in Rosharon, Texas,oversees development of sand-control service tools,completion systems, screens and expandable screens.He also provides field support for operations with arapid response group to design hardware for customcompletion designs. He joined Schlumberger in 1985as a design engineer with Vector Cable. His nextassignment (1989 to 1994) was as design engineer and project manager at Houston Downhole Systems,where he worked on the design and commercializa-tion of the MDT* Modular Formation Dynamics Testertool. He spent the next four years as department man-ager of coiled tubing products at SRC. He has been in his current position since 1998. Pat obtained a BS degree at Tennessee Technological University in Cookeville, USA, and an MS degree from RiceUniversity in Houston, both degrees in mechanicalengineering. He has served two terms as co-chair of the International Coiled Tubing Association.

Tom Bratton, Lead Petrophysicist, Geomechanicsand Logging-While-Drilling (LWD) Interpretation forSchlumberger Data and Consulting Services, is basedin Houston, Texas. His work involves No DrillingSurprises and PowerSTIM* services, and LWD, time-lapse and geomechanical interpretations. He joinedSchlumberger in 1977 as a wireline field engineer for the Rocky Mountain division, Grand Junction,Colorado, USA. Subsequent assignments includedwireline recruiter for USA Land operations in Denver,Colorado (1980 to 1982); computing center manager,Midcontinent division in Oklahoma City, Oklahoma(1982 to 1984); wireline district manager, PermianBasin division in Levelland, Texas (1984 to 1986); andsenior log analyst, Rocky Mountain Computing Centerin Denver (1986 to 1990). From 1990 to 1996, he wassenior project engineer for petrophysics interpreta-tion engineering in Houston, and then senior projectengineer for LWD engineering and software atAnadrill in Sugar Land. Before taking his currentposition in 2000, he was principal petrophysicist, LWD Interpretation Section, Formation Evaluationdepartment, in Sugar Land, Texas, where he devel-oped LWD resistivity interpretation products. Tomholds a BS degree in physics from Wesleyan Universityin Lincoln, Nebraska, USA; and an MS degree inphysics from Kansas State University in Manhattan,USA. Author of many publications and winner ofnumerous awards, he was named SPWLADistinguished Speaker (1999 to 2000).

José Luis Bustillos, who works as district technicalengineer in Ciudad del Carmen, Mexico, is responsi-ble for the technical department and marketing forSchlumberger Mexico Marine. He began his career in1980 as a field engineer with Dowell in Villahermosa,Mexico. He spent the next 14 years in South Americaas field engineer, cementing specialist, field servicemanager and base manager. His next assignmentswere in Mexico as cementing specialist and base manager before assuming his current position twoyears ago. José earned a degree in mechanical engi-neering from Instituto Tecnológico de Chihuahua(Chihuahua-Mexico).

Phil Christie received a BA degree in theoreticalphysics from University of Oxford, England, in 1972and then went to Africa as a Schlumberger loggingengineer. After three years in Angola, Nigeria, Gabonand Niger, he returned to England to complete a PhDdegree in seismology at the University of Cambridge.Following postdoctoral work in high-resolution seismicstudies, he returned to Schlumberger in 1981 as unitgeophysicist for borehole seismic study within theEuropean region. In 1985 he set up the Schlumbergerborehole seismic engineering department in Clamart,France, where the present generation of Schlumbergeropenhole vertical seismic profile tools was designed.In 1987 he transferred to Schlumberger-Doll Research,Ridgefield, Connecticut, USA, to develop new sonic,ultrasonic and borehole seismic measurements andapplications. Three years later, he established theseismic department at Schlumberger CambridgeResearch (SCR) in England, dedicated to new surfaceand borehole seismic applications. From 1996 to 1997, Phil was seconded to the BP Atlantic MarginExploration group in Aberdeen, Scotland, where hisprojects included the joint reservoir monitoringexperiment in Foinaven sponsored by BP, Shell andGeco-Prakla. After an assignment with Geco-Prakla(now WesternGeco) in Gatwick, England, as managerof the Reservoir Geophysics group supporting multi-component and time-lapse seismic studies, Philreturned to SCR in October 2000 as scientific advisor.

Steve Cooper is a senior petroleum engineer with BPin Aberdeen, Scotland. He is responsible for deliveryof technical service and NODAL* analysis support andR&D for sandface-completion design across the com-pany’s business units. In his 18 years with BP, he hasgained technical experience in many locations includ-ing England and onshore Europe, the North andCaspian Seas, the Gulf of Mexico, Alaska and WestAfrica. He also has served as a petroleum engineer inHouston, Texas, and as a stimulation engineer on wellcompletion projects for various operators throughoutEurope and West Africa.

Contributors

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Tony Curtis, Principal Geophysicist in the WesternGecoGatwick Technical Center, is in charge of geophysicalvalidation of the Q-Marine* system, analysis of marine-acquisition test data and processing of case studies. He began his career in seismic data processing in 1975with Digicon Geophysical Company in East Gristead,England. He joined Geco in 1979 to help build land pro-cessing expertise. In 1981 he moved to Houston to helppromote market penetration of Geco services, includ-ing the first marine 3D project. Two years later heheaded a new department that managed the integratedservices of Geco marine acquisition and processingtechnology in US exploration projects. In 1985 hereturned to the UK Orpington office as area geophysi-cist, providing technical services for survey planningand exploitation of new marine acquisition and pro-cessing techniques. He subsequently becameprocessing manager of the UK data center. His otherassignments have been in Delft, The Netherlands, as geophysical manager of the Seismos software taskforce; in Gatwick, England, as product manager for the introduction of the Seismos system worldwide, and as Geco-Prakla commercialization manager. Tonyhas a BS degree (Hons) in environmental sciencesfrom University of Lancaster in England. He recentlywon the Henri Doll Award for the best R&D paper at the Schlumberger Oilfield Symposium.

Randall Davis is WesternGeco Q-Marine champion,North and South America. Based in Houston, Texas, hehas been responsible for marketing Q-Marine servicesto clients in North and South America since 2000. Hebegan his career in 1988 with Geco Geophysical inHouston as a data-processing geophysicist. From 1991to 1994, he was geophysicist and group leader withGeco-Prakla in London, England, involved in process-ing 2D and 3D data from Africa and the Far East. Hereturned to Houston in 1994 and spent the next yearprocessing 3D marine data from the Gulf of Mexico.From 1995 to 1996, he was an account manager, sellingdata processing services and marine data. He also hasbeen data-processing sales manager, marine salesmanager, and account manager for seismic productsand services. Randall holds a BS degree in geologyfrom Texas A&M University in College Station, and an MS degree in geology from Stephen F. Austin StateUniversity, Nacogdoches, Texas.

Jean Desroches has been section head of modelingand mechanics in the Engineering Applicationsdepartment at the Sugar Land Product Center since1998. In 1990, after working as a research engineer forObservatoire Volcanologiques and then CNRS Institutede Physique du Globe in France, he joined SchlumbergerCambridge Research in England as associate researchscientist. There he worked on developing uniquemodels for hydraulic fracturing. From 1995 to 1998, he was senior engineer at Schlumberger Well Servicesin Sugar Land, Texas, where he was domain expert on stress measurements. Author of many scientificpapers, Jean earned an MS degree in geology andgeophysics from Ecole Nationale Supérieure de

Geologie de Nancy; an MS degree from InstitutNational Polytechnique de Lorraine; and a PhD degreein geophysics from University of Paris, all in France.

Rick Dickerson is a completions engineer and senioradvisor for Chevron Petroleum Technology Company in Houston, Texas. He began his career with Gulf OilCorp. in 1972 and worked 22 years in the Gulf of Mexicoin well completions, production operations, and reser-voir and production engineering. For the past sevenyears, he has been in Houston with the Chevron WellCompletion Group, responsible for sand control andhorizontal well technology development and deploy-ment for Chevron operations worldwide. Rick obtaineda BS degree in petroleum engineering from LouisianaTechnical University in Ruston, and holds a patent fora major service company’s gravel-pack packer.

Stephen Edwards, Schlumberger No DrillingSurprises Geomechanics Engineer, is based at the BP office in Houston, Texas. He joined Schlumbergerin 1997 as a geomechanics engineer for IntegratedProject Management (IPM) in Gatwick, England, andthen moved to Holditch-Reservoir Technologies inHouston. Stephen received a BA degree in earthsciences at University of Oxford, and a PhD degree in geomechanics from University of London, both in England. He won a Performed by SchlumbergerSilver Medal in 2000.

Bill Foxenberg, Manager of Technology, CompletionFluids for M-I Drilling Fluids, is based in Houston,Texas, where he oversees technical services, researchand development for the M-I Global Completion FluidsBusiness Unit. His main responsibilities include direct-ing activities of Houston Laboratories, serving as pri-mary customer contact for technical support andtransfer of technologies to the field. He began hiscareer as a field services group leader for GeochemResearch in Houston, performing single-well tracerstudies for tertiary-recovery projects in older oil fieldsthroughout the world (1980 to 1987). He joined OSCAInc. in 1987 as a chemist, and in 1990 became a com-pletion fluids technical manager in Lafayette,Louisiana. He remained at OSCA until 1997 when hejoined M-I as technical manager for completion fluids.Bill has a BS degree in chemistry from State Universityof New York College of Environmental Science andForestry in Syracuse.

John Fuller currently leads the Schlumberger Dataand Consulting Services geomechanics group forEurope, Africa and the CIS. He joined Schlumberger as a wireline field engineer in 1980 and spent 10 yearsin the Middle East on various field assignments in Abu Dhabi, Turkey, Jordan, Syria, Egypt and Dubai. In 1990 he moved to Europe to work in geomechanics.This work included the development of geomechanicaltechniques with the Geomechanics Department ofSchlumberger Cambridge Research in Cambridge,England. He has served as technical vice president forthe London chapter of the SPWLA and was a memberof the 1999 SPE Forum steering committee for sand-ing. John holds a BS degree in physics from Universityof Portsmouth in England.

Keith Godwin is a reservoir engineer for Stone EnergyCorporation in Lafayette, Louisiana. He is responsiblefor new project evaluations and recommendations,reserves estimation, well completion designs, andoptimization of producing wells in the Gulf of Mexico.He began his career with Chevron USA in 1983 andspent the next 15 years working as a production andreservoir engineer in New Orleans and Lafayette. He has been in his current position for the past threeyears. Keith earned a BS degree in petroleum engineer-ing from Louisiana State University in Baton Rouge.

Shuja Goraya, Product Champion for No DrillingSurprises applications in the Sugar Land ProductCenter in Texas, is currently responsible for buildingsoftware applications to support the PERFORM*Performance Through Risk Management process and No Drilling Surprises initiatives. He joinedSchlumberger Drilling & Measurements in 1994 as a drilling services engineer in Pakistan and since thenhas worked in different locations as MWD/LWD engi-neer, geosteering coordinator, directional driller,PERFORM engineer and drilling engineer. Prior to his current position, he was in charge of the Banzalashallow-gas extended-reach project in Cabinda,Angola. Shuja obtained a BS degree (Hons) in elec-tronics engineering from University of Engineeringand Technology, Lahore, Pakistan.

Dominique Guillot, Cementing Technology Specialistfor Schlumberger worldwide, is based in Clamart,France. He joined Dowell in 1981 in Saint-Etienne,France, as development engineer and section head(1981 to 1984); and then became section head andproduct team manager on projects related to wellcementing (1984 to 1989). In 1990 he became acementing specialist in Houston, Texas, working onintroduction of new technology. The following year hereturned to Saint-Etienne as cementing engineeringspecialist, to work on cement mixing and cement jobevaluation. From 1994 to 1996, he was section head of Process and Software and Field Support in theSchlumberger Riboud Product Center. Before takinghis current post, he was a cementing engineering spe-cialist in Clamart, and served as InTouch knowledgechampion for the cementing segment. Dominique is a civil engineer, who trained at the Ecole Nationaledes Ponts et Chaussées in Paris, France, and receiveda Thèse de Docteur Ingénieur from the Centre deGéologie de l’Ingénieur de l’Ecole des Mines de Pariset de l’Ecole Nationale des Ponts et Chaussées.

Toby Harrold is a BP operations geophysicist, incharge of planning, execution and application ofborehole geophysics surveys to support drillingoperations. Currently working on the Inam project in Azerbaijan for BP, he is based at offices in bothSunbury, England, and Baku, Azerbaijan. He joined BP in 1999 and worked in the Algeria Business Unituntil October 2000 when he joined the Azerbaijanteam. Toby holds a BS degree in geology from theUniversity of Birmingham, and a PhD degree for workon pore pressure estimation from wireline logs fromthe University of Durham, both in England.

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Husam Helou, GeoMarket* Technical Engineer forthe Gulf region covering United Arab Emirates (UAE),Iran, Yemen and Qatar, is based in Abu Dhabi, UAE.He joined Schlumberger Well Services in 1993 as afield engineer and has worked in Syria, Oman (fieldengineer), Turkey (engineer in charge) and Kuwait(district technical engineer). Before assuming hiscurrent position, he was a DESC* Design andEvaluation Services for Clients engineer for ADCO for18 months. Husam is a graduate of Damascus Universityin Syria, with a BS degree in electronics engineering.

Jonathan Holt has been project manager, No DrillingSurprises, for BP Upstream Technology in Aberdeen,Scotland, since 1999. He began his career with BPExploration as a drilling engineer on various semisub-mersible exploration and appraisal wells in the Gulf ofMexico and the UK central North Sea (1985 to 1990).He spent the next six years as senior project engineerand drilling engineer on several subsea developmentsin Houston, Texas, and Aberdeen. From 1997 to 1999,he was drilling superintendent for Bruce Phase 2 sub-sea development. Author of several papers, Jonathanearned a BS degree in chemical engineering fromHeriot-Watt University in Edinburgh, Scotland.

Christian Hun joined TOTAL in 1976 to work in thecement and mud laboratory. He subsequently moved to operations and was responsible for cement and mudfluids in various locations in the Middle East, LatinAmerica and the North Sea. Currently on secondmentfrom TOTAL, he is the senior mud and cement engi-neer for ADCO. Christian is a graduate of University of Nancy in France with BS degree in chemistry.

Leif Larsen has an MS degree in physics from theNorwegian Institute of Technology in Trondheim. Hejoined Schlumberger as a field geophysicist in 1982. In his 19 years with the company, he has held manytechnical and managerial positions in seismic dataacquisition and processing. Currently he is globalmarine marketing and new technology manager basedin Gatwick, England. Previously, he was the generalmanager for Schlumberger Oilfield Services (OFS) in Australasia and was based in Melbourne, Australia.

John Lechner, Schlumberger NDS No DrillingSurprises Business Development Manager for Europe,CIS and Africa, is based in Stavanger, Norway. He hasbeen responsible for identifying, developing, coordi-nating and supporting NDS opportunities and projectsfor his area since 2000. He joined the company in 1984 as a wireline field engineer in West Texas.Subsequent assignments were in Houston, Texas, andPort Harcourt, Nigeria. He transferred to Stavanger aswireline location manager (1990 to 1993). He spentthe next two years in Paris, France, as SchlumbergerLimited internal auditor. He joined IPM at its incep-tion in 1995, working as project manager in Nigeria;Muscat, Oman; Bangkok, Thailand; and Cairo, Egypt.In 1998 he became IPM operations manager for theNorth Africa Region, then moved to Perth, Australia,as GeoMarket IPM operations manager and OilfieldServices marketing manager. John holds a BS degreein electrical engineering from University of Notre Dame,

South Bend, Indiana, USA, and completed theadvanced degree program in petroleum engineeringat the University of Houston in Texas. He was a mem-ber of the Schlumberger Forum 2005 team.

José Antonio Martínez-Ramirez, New TechnologyProject Engineer for Petróleos Mexicanos (PEMEX)Exploracion y Produccion, Marine Region, Ciudad delCarmen, Mexico, implements new technology prac-tices in drilling, workover and completions. Beforejoining PEMEX in 1997, he worked as a field engineerfor Halliburton Cementing and Stimulation inCarmen, Mexico (1995 to 1997). He has a degree in petroleum engineering from Instituto PolitécnicoNacional in Mexico City.

Tim McPike, Senior Production Engineer in the AppliedWell Technology Group with Shell International E&P, is based in Rijswijk, The Netherlands. At Shell, he hasfocused on stimulation and completion design andexecution related to sand control, including hydraulicfracturing, Frac and Pack, openhole gravel packing,ExxonMobil’s Alternate Path technology, and expand-able screens. He has performed various installationsworldwide, from offshore deepwater Gulf of Mexicoand the North Sea, to desert operations in Oman. Healso has worked for Halliburton Energy Services inCanada and the Gulf of Mexico. Tim obtained a BSdegree in mechanical engineering from the Universityof Calgary, Alberta, Canada.

Laura Murphy, who is based in Gatwick, England, has been a GeoQuest borehole geophysicist working in rock mechanics since 1999. Previously she was withGeoQuest in both Aberdeen, Scotland, and Gatwick(1998 to 1999). Her work has involved modeling ofvertical seismic profiles and processing as well asplanning of borehole seismic surveys in conjunctionwith offshore operations. After working as lead engi-neer for Kerr McGee North Sea operations, shebecame a wireline field engineer for SchlumbergerOilfield Services in Aberdeen (1995 to 1997). Lauraobtained a BS degree (Hons) in geophysics fromUniversity of Liverpool and is taking a distance learn-ing program to earn an MS degree in marketing fromRobert Gordon’s University in Aberdeen.

David Nichols, Seismic Research Director atSchlumberger Cambridge Research (SCR) in England,manages long-term research into seismic acquisition,processing, modeling and inversion. He began hiscareer in 1983 with Western Geophysical in London,England, first as a data processing geophysicist andthen as a seismic programmer. From 1994 to 1998, he was a senior software engineer at Geco-Prakla in Gatwick, England. In 1998 he moved to SCR as program manager and, before assuming his currentposition in 2001, was associate research director of the seismic group. After earning a BA degree inphysics from University of Cambridge in England, he obtained an MS degree from Imperial College,London, England, and a PhD degree from StanfordUniversity in California, both in geophysics.

Hugh Nicholson, Ula and Tambar Geologist for BPNorge AS in Stavanger, Norway, oversees geologicalaspects of well planning, reservoir model building and reservoir management on the Ula and Tambarreservoirs. He joined BP in 1990 to do research on carbonate reservoirs. From 1993 to 1994, he waswith BP Exploration involved in well operations andthe Eastern Trough Area Project (ETAP) appraisalteam. After a stint with Western Atlas in Bahrain andLondon, he rejoined BP in 1996, as development geol-ogist on ETAP diapir fields. He moved to Norway in2000. Hugh holds BA and MA degrees in geologicalsciences from University of Cambridge in England,and a PhD degree in geochemistry from University of Edinburgh in Scotland.

Mehmet Parlar, Principal Engineer and FluidsSpecialist with the Schlumberger Sand ControlBusiness Development team in Rosharon, Texas, pro-vides technical marketing and input to sand-controlproduct development, case-based reasoning forwellbore cleanup method selection, new technologypromotion, and sand control and stimulation fluidssupport. After receiving MS and PhD degrees in petro-leum engineering from the University of SouthernCalifornia at Los Angeles, he joined Dowell in Tulsa,Oklahoma, as a development engineer. From 1996 to 1999, he was a reservoir engineer with the DowellSand Control Business Development team inLafayette, Louisiana. Before his current posting, he was well production specialist and technical coor-dinator in Sugar Land, Texas (1999 to 2001). Author of many publications, he also holds a BS degree inpetroleum engineering from Istanbul TechnicalUniversity in Turkey.

Enzo Pitoni, Senior Completion and ProductionEngineer for Eni Agip, is based in Milan, Italy. He isinvolved in innovative water shutoff, frac and pac and screenless completion projects throughout thecompany. He spent eight years in the ProductionLaboratory before joining the Sand Control, WaterShutoff and Reservoir Drill-In Fluids group severalyears ago in Milan. Last year he returned from anassignment in Tunisia. He has contributed signifi-cantly to Eni Agip’s sand-control completion resultsand reservoir drill-in strategies in such areas as theAdriatic Sea and Africa. He was instrumental in therecent successful implementation of ClearFRAC*fluids for frac and packing of Eni Agip’s Adriatic Seagas fields. Enzo received an MS degree in chemistryfrom Perugia University in Italy.

Colin Price-Smith, Horizontal Sandface Completionsand Screens Business Development Manager atSchlumberger in Rosharon, Texas, has been coordi-nating this business area for Schlumberger worldwidesince 1999. He joined the company in 1985 after work-ing briefly for Salvesen Drilling Services in Aberdeen,Scotland. He then spent four years in Port Harcourt,Nigeria, as a field engineer and sales and technicalengineer. In 1989, he moved to Miri, East Malaysia, as district technical engineer for sand control andcementation services. In 1991, he joined the DowellR&D facility in Tulsa, Oklahoma, as sand-control

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product champion, responsible for the development andworldwide marketing of Schlumberger sand-controlfluids and systems. From 1993 to 1997, he was sand-control completions manager for the North Sea divi-sion. His next assignment was well production services(WPS) manager for Europe, Russia and CIS (1997 to1998). He spent the next year as WPS manager inWest Africa, responsible for development and imple-mentation of the African WPS business plans. Authorof many papers and articles relating to wellborecleanup and horizontal sand-control completions,Colin obtained a BS degree (Hons) in productionengineering and management from University ofNottingham in England.

José Luis Reséndiz Robles, Wells Project, Design and Engineering Superintendent at Unidad OperativaNoreste (UONE), PEMEX Marine Division, is based at Ciudad del Carmen, Mexico. He began his career in 1980 in El Plan Veracruz as a drilling engineer, and in 1992 became sectional drilling engineeringcoordinator in PEMEX South Division Department of Petroleum Engineering. From 1992 to1993, he wasdrilling engineering coordinator in Agua Dulce,Veracruz, for PEMEX South Division. In 1993 hebecame workover and completion coordinator beforeassuming his current position. He earned a degree in petroleum engineering from Instituto PolitécnicoNacional in Mexico City in 1980.

Chris Rhodes is the Technology Vice President withresponsibility for world-wide drilling for BP Exploration.He began his career with BP in 1971 in refining anddrilling. He was Business Unit Leader for the EasternTrough Area Project (ETAP) of seven oil and gas fieldsincluding Mungo. Attending Glamorgan Polytechinic,Pontypridd, Wales, on a BP scholarship, Chris receiveda BS degree (Hons) in chemical engineering, and laterobtained an MS degree in petroleum engineering fromImperial College in London, England.

Giuseppe Ripa, a senior completion and productionengineer, has been with Eni Agip for 16 years. He spentthree years involved in completion and workover tech-nologies and then eight years specializing in sandcontrol, matrix stimulation and hydraulic-fracturingtreatment and design for the production optimizationgroup. Since completing an assignment as a technicaladvisor for reservoir, completion and productiontechnologies in the Congo, he now works on new pro-duction optimization technologies and innovativesand-control completions in Eni Agip Milan head-quarters, focusing on increasing well productivity.Giuseppe is a graduate of the Pavia University in Italywith a degree in hydraulic engineering.

Joel Rondeau, Senior Development Engineer,Schlumberger Riboud Product Center in Clamart,France, has been working on the SFM* Solid FractionMonitoring system. He joined Dowell in 1981 at Saint-Etienne, France. From 1993 to 1997, he worked at theSugar Land, Texas facility on the EXPRES* cementinghead and the EXPRES latch coupler. In 1997 he trans-ferred to Clamart to work on the Sedco Express* plat-forms before taking on his current project. Joel has a degree in mechanical engineering.

William Standifird, Schlumberger PERFORMCoordinator, manages all the PERFORM engineers andexperts and all of the NDS and PERFORM jobs on theUS Gulf Coast. Since 1997 he has been a senior LWDfield engineer, radiation supervisor and PERFORMexpert, deploying sensitive electronic tools and com-puters for offshore drilling operations. Before joiningSchlumberger, he served in the US Army and alsoworked as a biomedical electronics engineer withNashville Medical Electronics (1995 to 1997). Williamearned a degree in electronics engineering technologyfrom ITT Technical Institute in Nashville, Tennessee,USA. In 2000 he was a Performed by Schlumbergersilver medalist.

Bill Steven, Drilling Manager, Texaco (Nigeria)Overseas Petroleum Co., manages offshore drilling andworkover operations in Nigeria. Since joining Texaco in 1979 as trainee drilling supervisor, he has had manyassignments worldwide with the company. Theseinclude serving as offshore drilling supervisor for theUK and Germany, drilling superintendent in Aberdeen,Scotland, drilling superintendent in China, drillingmanager for Texaco Malaysia in Thailand and Myanmar,drilling manager for Texaco North Buzachi, and drillingmanager in China. Bill earned a BS degree (Hons) inmechanical engineering from Robert Gordon’s Instituteof Technology in Aberdeen, Scotland.

Alan Strudley, Chief Geophysicist, Marine, forWesternGeco, is based at the company headquarters in Gatwick, England. He joined the company in 1981and held various positions in data processing until1988 when he joined a multidisciplinary team chargedwith developing reservoir characterization serviceswithin Schlumberger. In 1991 Alan became area chiefgeophysicist in Stavanger, Norway, where he con-tributed to the development of depth imaging andinversion services. In 1996 he was appointed regionchief geophysicist for Southeast Asia and continuedworking in this position until January 2001 when heassumed his current position. Alan’s interests includeseismic inversion, borehole-calibrated processing andsurvey design. He holds a BS degree in physics fromthe University of Manchester in England.

Morten Svendsen, WesternGeco Q-Marine ProductChampion in Asker, Norway, is responsible for commer-cialization of the Q-Marine system. He has held variouspositions in research and engineering, and seismicacquisition and processing. Morten earned an MSdegree in geophysics from University of Oslo in Norway.

Dave Tiffin, who is based in Houston, Texas, is asenior petroleum engineer with BP and a member ofthe Sand Control & Completions Team, which providesworldwide support for all BP completions. Among hiscurrent responsibilities are support of expandable-screen completions in the Western Hemisphere. Afterreceiving his PhD degree in chemical engineeringfrom the University of Notre Dame, South Bend,Indiana, he joined Amoco Production Co. in 1978 at their Tulsa (Oklahoma) Research Center.

Juan Troncoso, Production Engineering Specialist, iswith Repsol-YPF in Jakarta, Indonesia. Since 1996 hehas been responsible for production and completionengineering for the North Business Unit offshoreSoutheast Sumatra. This includes openhole horizontalgravel-pack completions, completion design, generalsand control (gravel packing and fracture packingopenhole completions), stimulation, artificial lift andworkovers. He began as a senior operations analyticalengineer with Arco Oil and Gas in Lafayette, Louisiana(1981 to 1986). He transferred to Jakarta, Indonesiawith Arco International Oil and Gas Company, as asenior petroleum engineer in the offshore North WestJava Sea (1986 to 1989). From 1989 to 1996, he workedfor Arco Oil and Gas Co. and Vastar Resources Inc. in Lafayette, Louisiana, as senior production andcompletion engineer for offshore Gulf of Mexico. Hejoined Repsol-YPF as a production engineering spe-cialist in 1996. Juan obtained a degree in mechanicalengineering from University of Chile; and an MSdegree in mechanical engineering from University of Colorado in Boulder.

Pierre Vigneaux, who is based at the SchlumbergerRiboud Product Center in Clamart, France, is projectleader of the low-density mixer project including SFM monitoring and the development of its automatedversion. He joined Flopetrol in 1977 to work on a two-phase flow surface-metering project. From 1984 to1993, he was with Schlumberger Wireline in Clamart,involved in characterizing liquid flow in deviated pipesand developing the Local Impedance Flowmeter Tool.He then moved to Dowell in Clamart as project leaderfor the high-pressure flowmeter, mud stickance testerand Vane rheometer. Holder of more than 10 patentson multiphase flowmetering and sensor technology,Pierre has degrees in fluid mechanics engineeringfrom Ecole National Supérieure de Mécanique inNantes and from Ecole Nationale Supérieure desTechniques Avancées in Paris, both in France.

Bill Wright, who is based in Paris, France, managesall Schlumberger Oilfield Services Solutions Projects.Since joining the company in 1978, he has held man-agement positions in every continent except SouthAmerica, and has worked with most of the Schlumbergercompanies. He recently was seconded to Amoco, andsubsequently BP-Amoco Drilling Research depart-ments, and helped found and manage the NDS project.Author of various SPE papers in the drilling domain,Bill obtained a BS degree (Hons) in materials scienceand physics from University of Liverpool, England.

Summer 2001 77

An asterisk (*) is used to denote a mark of Schlumberger.

Coming in Oilfield Review

Monitoring Downhole FluidSample Contamination. Obtaininghydrocarbon samples from sub-surface formations is vital forassessing reservoir value, planningfield development and designingproduction facilities. Contaminationby drilling-mud filtrate in samplesobtained from wireline tools canalter fluid properties significantly.This article describes a new tech-nique for determining how long itwill take to collect an acceptablefluid sample at a given samplingstation. We also show how provencontamination-detection methodscan be extended to high gas-oil ratio fluids and condensates.

Global Warming and the E&PIndustry. The debate surroundingthe impact of greenhouse gasemissions on global warming hasbecome increasingly heated in recentmonths. In this article, we look at thescientific arguments surrounding theissue and proactive steps beingtaken by the E&P industry to control,or eliminate, emissions in variousoilfield operations.

Advances in Borehole Imaging.Until recently, geologists and engi-neers who depend on microresistivityborehole images for enhanced forma-tion evaluation have had limitedoptions in synthetic- and oil-basemuds. A new wireline tool thatcombines innovative technology withthe time-honored principle of resis-tivity logging is allowing improvedcharacterization of reservoirs bysuccessfully imaging formationsthrough nonconductive muds.

Selective Stimulation. Multiplezones can be stimulated in a single operation by using coiledtubing as the conduit for proppant-laden fluids. A new tool selectivelyisolates target intervals withoutrequiring a rig to pull productiontubing or wireline intervention to setmechanical plugs. Individual stagesare treated separately to achieveoptimal fracture length and conduc-tivity for each zone. Case historiesfrom around the world demonstratehow this technique taps reservesbypassed by conventional comple-tion and fracturing methods, reducescompletion time and costs, improvespost-treatment cleanup, and increaseswell productivity.

Surfactants: Fundamentals and Applications in the Petroleum IndustryLaurier L. SchrammCambridge University Press40 West 20th StreetNew York, New York 10011 USA2000. 621 pages. $74.95ISBN 0-521-64067-9

Aimed principally at scientists and engi-neers who are involved with surfactants,this book provides an introduction to thenature, occurrence, physical properties,propagation and uses of surfactants inthe petroleum industry.

Contents:

• Surfactants and Their Solutions:Basic Principles

• Characterization of Demulsifiers

• Emulsions and Foams in thePetroleum Industry

• Surfactant Adsorption in Porous Media

• Surfactant Induced Wettability Alter-ation in Porous Media

• Surfactant Flooding in Enhanced Oil Recovery

• Scale-Up Evaluations and Simulationsof Mobility Control Foams forImproved Oil Recovery

• The Use of Surfactants in LightweightDrilling Fluids

• Surfactant Use in Acid Stimulation

• Surfactants in Athabasca Oil SandsSlurry Conditioning, Flotation Recov-ery, and Tailings Processes

• Surfactant Enhanced AquiferRemediation

• Use of Surfactants for EnvironmentalApplications

• Toxicity and Persistence of SurfactantsUsed in the Petroleum Industry

• Glossary of Surfactant Terminology

• Indexes

In addition to scientists and engi-neers in the petroleum industry, thisbook will be of interest to senior under-graduates and graduate students inscience and engineering, and to gradu-ate students of surfactant chemistry.

Barfoot L: Journal of Canadian Petroleum Technol-

ogy 39, no. 7 (July 2000): 19.

Renewable Energy: Its Physics,Engineering, Use, EnvironmentalImpacts, Economics and Planning AspectsBent SørensenAcademic Press525 B StreetSuite 1900San Diego, California 92101 USA2000. 912 pages. $75.00ISBN 0-12-656152-4

The book discusses the advantages and disadvantages of the variousalternatives to conventional fuels.Included are solar, wind, ocean waves,tide and river flow, biological conver-sion and geothermal flow sources.

Contents:

• Perspective

• The Origin of Renewable Energy Flows

• The Individual Energy Sources

• The Energy Conversion Process

• Energy Transmission and Storage

• Energy Supply Systems

• Socio-Economic Assessment of Energy Supply Systems

• Winding Up

• References, Index

The author is an authority whowrites with clarity and precision in this new edition to a book first pub-lished in 1979..

Although primarily aimed at engi-neering students, any layperson with aneed to learn the basic vocabulary andtechnical limitations of the variousenergy proposals would benefit greatly.

Comer JC: Choice 38, no. 5 (January 2001): 937.

Computerized Modeling of Sedimentary SystemsJan Harff, Wolfram Lemke andKarl Stattegger (eds)Springer-Verlag175 Fifth AvenueNew York, New York 10020 USA1999. 452 pages. $129.00ISBN 3-540-64109-2

This compilation of state-of-the-artresearch examines the types of sedi-mentary systems that recently havereceived attention from modelers, andalso showcases work coupling sedimen-tologic models with ocean and climatecirculation models.

Contents:

• Climatic, Oceanographic and Biologi-cal Forcing of Sedimentary Systems

• Trends and Periodicity in the Sedi-mentary Record as a Response toEnvironmental Changes

• Space-Time Models of Basin Fill

Like the types of models, the scientific caliber of the articles thatdescribe them is also highly variable.Some...could become highly citedworks, while others will clearly not.

And for those seeking morefundamental information on how to model sediment transport andstratigraphy formation, I suggestbeginning elsewhere.

Pratson LF: Journal of Sedimentary Research 70,

no. 4 (July 2000): 970.

78 Oilfield Review

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