Summer 2003

Cased Hole Formation Evaluation

Environmentally Sound Surveys

Mechanical Earth Modeling

NMR in Real Time

Oilfield Review

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No accidents, no harm to people and no damage to theenvironment. These are the aspirations that drive the wayBP conducts its operations. Specific targets and goals areestablished in support of these aspirations. For example, all exploration and production (E&P) activities in BP noware governed to a large degree by the ISO 14001 standards for environmental management set by the International Organization of Standardization.

BP is not alone in recognizing that top performance inthe areas of health, safety and environmental (HSE) man-agement is essential for any responsible and successfulcompany in the E&P sector. Throughout the 1990s, oil com-panies and their contracting partners made great strides inimproving HSE performance. The initial focus was on safety.By 2001, BP had reduced its lost-time injury frequency to almost one tenth of the figure of one decade earlier. In recent years, increasing attention has been paid to environmental matters.

The field of seismic acquisition has featured strongly inthe drive for demonstrable excellence in environmentalmanagement. Many countries now have a legislative policythat requires the completion of an environmental impactassessment (EIA), including clear mitigation processes as well as consultation with potentially impacted parties,before seismic work can proceed. Even where there is nolegislative requirement, most responsible operators willhave an internal requirement for an EIA.

In the offshore setting, interest is currently focused onthe question of possible physical and behavioral impacts ofseismic energy on marine mammals. In the Gulf of Mexico,the Sperm Whale Seismic Study (SWSS), of which BP is acosponsor, is seeking to provide rigorous data that willenable the seismic industry, environmental organizationsand government agencies to better understand the behav-ioral responses of large cetaceans to seismic signals.

Onshore seismic operations have an even greater poten-tial for leaving a footprint on the environment, so it isencouraging that several seismic vendors are now offeringproduct lines that focus on minimizing environmentalimpact. BP recently operated a major 3D survey on theNorth Slope of Alaska, USA, with WesternGeco as the con-tractor. The environmental standards required to operateseismic surveys on the North Slope are justifiably some ofthe most stringent in the world, so the project presented an excellent opportunity for BP to test the WesternGecoEcoSeis† system (see “Promoting Environmental Responsi-bility in Seismic Operations,” page 10). This system is a

Toward Greener Seismic Surveys

tool for monitoring and tracking performance against therequirements of clients, governmental agencies and localcommunities. Inspections are conducted regularly using aformat specific to the prospect. These inspections are thenscored to measure the level of compliance. Completedinspections are accumulated and scores plotted to showhow the crew is performing against its plan. Remedialactions are set in place in response to low inspection scores.

For the BP North Slope project, inspections were con-ducted daily on the crew’s staging area, with a separateinspection made each time the staging area was moved to a new location. Inspections focused on drip pads beingin place, minimizing residual trash, and monitoring drips and beverages that had spilled onto the snow. The processhad the desired outcome of ensuring negligible environ-mental impact.

In a world where the BP HSE goals are becoming less ofan aspiration and more of an expectation, it is good to seethat the seismic industry is providing products that willhelp meet that expectation. Only by judicious partneringwith suppliers that share common goals can E&P compa-nies hope to meet their HSE goals.

James W. FarnsworthTechnology Vice PresidentBPHouston, Texas, USA

Jim Farnsworth is BP technology vice president responsible for worldwideexploration and is also the senior manager for the BP Global Initiative for Seis-mic Services. Prior to this he was vice president of North America Exploration.His other positions with BP have included vice president of deepwater explo-ration in Houston, Texas; Alaska exploration manager; and Central North Seasubsurface manager. Jim obtained BS and MS degrees in geophysics and geol-ogy from University of Western Michigan and Indiana University, respectively.

† EcoSeis is a mark of WesternGeco.

Advisory Panel

Abdulla I. Al-DaaloujSaudi AramcoUdhailiyah, Saudi Arabia

Syed A. AliChevronTexaco E&P Technology Co.Houston, Texas, USA

Andreina IseaPetróleos de Venezuela S.A. (PDVSA)Los Teques, Venezuela

George KingBPHouston, Texas

David Patrick MurphyShell Technology E&P CompanyHouston, Texas

Eteng A. SalamPERTAMINAJakarta, Indonesia

Richard WoodhouseIndependent consultantSurrey, England

Executive Editor/Production EditorMark A. AndersenAdvisory EditorLisa StewartSenior EditorsGretchen M. GillisMark E. Teel EditorsMatt GarberDon WilliamsonContributing EditorsRana RottenbergStephen Prensky

Design/ProductionHerring DesignMike MessingerSteve FreemanIllustrationTom 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.

© 2003 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) 281-285-7847Fax: (1) 281-285-8519E-mail: andersen@sugar-land.oilfield.slb.com

Address distribution inquiries to:

Matt Garber(44) 1223 325 377Fax: (44) 1223 361 473E-mail: mgarber@cambridge.scr.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.ukwww.oilfieldreview.comAnnual subscriptions, including postage, are 160.00 US dollars, subject to exchange rate fluctuations.

On the cover:

A rig crew prepares a nuclear magnetic resonance logging tool forrunning into a borehole. This proVISION* tool provides identificationof pay and estimates of producibility in real time. The tan portion ofthe tool is one of two antennas.

*Mark of Schlumberger

Summer 2003Volume 15Number 2

Schlumberger

2 Evaluating and Monitoring Reservoirs Behind CasingAdvanced formation-evaluation services accurately determine porosity,lithology, shale content, fluid saturations and pressure, and recover forma-tion-fluid samples in cased holes. Innovative tool designs and processingsoftware make formation evaluation behind casing a viable option to evalu-ate bypassed zones, intervals that must be cased before openhole logs arerun, and the effects of time on producing zones. This article examines howexploration and production companies cost-effectively deploy novel casedhole services in difficult operating environments.

52 Contributors

55 New Books and Coming in Oilfield Review

Oilfield Review

1

40 Nuclear Magnetic Resonance Logging While Drilling

Nuclear magnetic resonance logs can now be obtained while drilling. Real-time identification of pay and predictions of producibility can be used toplace the borehole for optimal productivity. This article introduces develop-ments in nuclear magnetic resonance logging while drilling and discusseshow operators are using this technology to place wellbores and evaluate formations in real time.

10 Promoting Environmental Responsibility in Seismic Operations

Land seismic operations can promote stewardship of the environment andrespect for local culture. An environmentally responsible process institutedby WesternGeco starts in the planning stage, runs through survey acquisi-tion, and includes postproject analysis to help plan future work. This articledescribes the new approach to acquiring seismic data with examples fromNorth and South America, Australia and Southeast Asia.

22 Watching Rocks Change—Mechanical Earth Modeling

The state of stress in the Earth affects many aspects of hydrocarbonexploitation. Information about rock stresses around a borehole or in a fieldis usually incomplete and must be obtained by inference from a wide varietyof sources. A consistent mechanical earth model that can be updated withreal-time information is becoming essential in many difficult drilling anddevelopment projects around the world.

2 Oilfield Review

Evaluating and Monitoring ReservoirsBehind Casing

Kevin BellmanEnCana CorporationCalgary, Alberta, Canada

Scott BittnerAnkur GuptaSugar Land, Texas, USA

David CameronBruce MillerStavanger, Norway

Edwin CervantesAnthony FondygaDiego JaramilloVenkat PachaQuito, Ecuador

Trent HunterAl SalsmanCalgary, Alberta

Oscar KelderStatoilStavanger, Norway

Ruperto OrozcoEnCanEcuador CorporationQuito, Ecuador

Trevor SpagrudEnterra Energy CorporationCalgary, Alberta

For help in preparation of this article, thanks to Darwin Ellis,Ridgefield, Connecticut, USA; Enrique González, Quito,Ecuador; Martin Hyden, Dwight Peters and MiguelVillalobos, Clamart, France; Martin Isaacs, Sugar Land,Texas, USA; and Marvin Markley, New Orleans, Louisiana, USA.ABC (Analysis Behind Casing), AIT (Array Induction ImagerTool), CBT (Cement Bond Tool), CHDT (Cased HoleDynamics Tester), CHFD (Cased Hole Formation Density),CHFP (Cased Hole Formation Porosity), CHFR (Cased Hole

Formation Resistivity), CHFR-Plus (Cased Hole FormationResistivity), CNL (Compensated Neutron Log), DSI (DipoleShear Sonic Imager), GPIT (General Purpose InclinometryTool), InterACT, MDT (Modular Formation Dynamics Tester),Platform Express, PowerSTIM, PS Platform, RST (ReservoirSaturation Tool), RSTPro (Reservoir Saturation Tool for PSPlatform string), SpectroLith, TLC (Tough Logging Conditions),USI (UltraSonic Imager) and Variable Density are marks ofSchlumberger.

Advanced formation-evaluation services help accurately determine porosity,

resistivity, lithology, shale content, fluid saturations and pressure, and recover

formation-fluid samples in cased wells. Innovative tool designs and processing

software make formation evaluation behind casing a viable option to evaluate

bypassed zones and intervals that must be cased before openhole logs are run.

Cased hole data reveal the effects of time on producing zones. Exploration and

production companies now are able to obtain cost-effective, useful data in

difficult operating environments.

Imagine trying to read a newspaper in a darkroom, or to sense with your hands the tempera-ture of a baked potato or the texture of a rockwhile wearing insulated gloves. Measuring rockproperties using logging tools is equally difficultwhen the formation is on the other side of steelcasing and cement. Significant software and tooldevelopments now make possible rigorous evalu-ation of formations behind casing.

Advanced formation-evaluation services helpexploration and production (E&P) companiessearch for additional or initially unrecognizedzones and identify bypassed hydrocarbons aftercasing is set. These innovative, cased hole wire-line services facilitate determining porosity,lithology, shale content, fluid saturations andpressure. A state-of-the-art testing tool recoversformation-fluid samples from cased holes. TheABC Analysis Behind Casing suite of servicesoffers a robust, cost-effective method for E&Pcompanies to analyze or monitor formations inwells that are already cased.

Whether dealing with aging fields or new dis-coveries, cased hole services bolster effectivedecision-making. For example, ABC services pro-vide backup logs when openhole logging is toorisky. The tools also offer valuable data whenlooking for bypassed pay in older wells or whenmonitoring saturation, depletion and pressure tooptimally manage oil and gas fields.

In this article, we review cased hole formation-evaluation tools and examine their effectivenessin operations in Canada, Ecuador and theNorwegian North Sea.

Evaluation Between a Rock and a Hard PlaceGiven the choice, many operators prefer evaluat-ing formations that are not yet cased. There aremany instances, however, when the risk of open-hole logging is too great, or when it makes economic sense to conduct logging operationsafter drilling operations have ceased and thedrilling rig has been released. For example, in amultiwell drilling campaign, some operators prefer

Summer 2003 3

to case all the wells and evaluate them after-wards. There also are existing wells and fields inwhich the potential rewards behind casing aretoo rich to bypass.

In mature fields, commonly known as brown-fields, operators reevaluate zones that might havebeen logged decades ago using only gamma ray,spontaneous potential and resistivity devices. In other situations, wellbores might penetrate for-mations that were not logged at all. New measure-ments facilitate formation evaluation no matterhow old the well is. Typically, the cost of acquiringdata from these cased holes is far less than that ofdrilling a new well solely to gather data. The riskof cased hole logging operations is also substan-tially less than that of drilling operations.

When drilling new wells, operators occasionallyencounter formations in which openhole-logging conditions are difficult. Rather than risklosing tools due to sticking in these formations,operators may opt for cased hole formation eval-uation, or they may acquire cased hole logs tocomplement logs acquired while drilling. Inareas where openhole logging is difficult, opera-tors save time and money and optimize their formation-evaluation programs by planningcased hole logging operations ahead of time.

Cased hole logging also helps operators evaluate the effects of production, such as themovement of fluid contacts, changes in satura-tion and pressure, and depletion and injectionprofiles. An integrated suite of new and not-so-new

tools makes these types of evaluations possibleand cost-effective.

Formation Evaluation Behind CasingSeveral key elements contribute to effective for-mation evaluation behind casing. A thoroughunderstanding of the condition of the casing andcement is a prerequisite for successful evaluation.A cement-evaluation log, ideally a combination ofUSI UltraSonic Imager and CBT Cement BondTool data, reveals any anomalies in the cementsheath that might affect results from through-casing formation-evaluation tools. Of course, the diameter of the wellbore and completion configuration influence logging-tool selection.

Skilled log interpreters incorporate comple-tion details—wellbore geometry, tubulars, incli-nation angle and any downhole restrictions—and the well-log data into production estimatesand recommendations for perforating or otherprocedures, such as stimulation treatments.These recommendations stem from a detaileddescription of the formation—porosity, lithologyand fluid saturation—derived from density,gamma ray, neutron, resistivity, sonic and spec-troscopy data. Fluid-mobility data from casedhole testers complement the petrophysical anal-ysis. Time-lapse evaluations require two sets ofthese data.

Many ABC services are available to meetdiverse customer requirements (below). To eval-uate saturation, the CHFR Cased Hole FormationResistivity tool applies groundbreaking technolo-gies for deep-reading resistivity measurementsbeyond steel casing.1 The new CHFR-Plus CasedHole Formation Resistivity tool offers enhancedhardware and measurement techniques thatimprove the operational efficiency of cased holeresistivity measurements. Both tools operate in a

similar way, by introducing current into the cas-ing. A voltage drop occurs as a small amount ofthe current escapes into the formation. The volt-age drop is proportional to formation conductiv-ity, allowing calculation of formation resistivity.

Commercially available since 2000, the origi-nal CHFR device has proved its value worldwidefor applications such as evaluation of bypassedpay, reevaluation of old fields, reservoir and saturation monitoring and primary evaluation of wellbores cased before complete formation eval-uation. The CHFR-Plus tool, introduced in 2002,offers similar measurement capabilities, but attwice the speed of the CHFR device, because of anew measurement technique.2 To date, the CHFRand CHFR-Plus tools have performed more than800 logging jobs.

The RSTPro Reservoir Saturation Tool for thePS Platform string also helps determine satura-tion. Formation sigma measurements are mosteffective in high-salinity formation fluids forwater-saturation answers.3 As part of the RSTProservice, SpectroLith lithology processing of spectra from neutron-induced gamma ray

spectroscopy tools quantifies lithology interpre-tations.4 Carbon/oxygen logging, commonlyknown as C/O logging, can give saturation resultsin fresh water and in waters of unknown salinity,for example in zones where there is ongoingwater injection and the salinity of the injectedwater differs from that of the original water inplace. When made more than once on a givenreservoir, saturation measurements from theCHFR and RSTPro devices are key elements oftime-lapse monitoring for reservoir management.

To complement saturation analyses, theCHFP Cased Hole Formation Porosity tool mea-sures formation porosity and sigma. This tool hasan electronic neutron source, also known as aminitron, eliminating the need for a chemicalsource. Borehole shielding and focusing allowpetrophysicists to perform environmental correc-tions. The CNL Compensated Neutron Log devicealso may be run in cased holes, but requires moreextensive environmental corrections because itlacks the borehole shielding and focusing of theCHFP device.

The CHFD Cased Hole Formation Density tooluses a new characterization of the three-detectordensity device incorporated in the PlatformExpress tool specifically for cased hole operations.

The DSI Dipole Shear Sonic Imager tool provides accurate measurements of formationcompressional transit times—used to establishporosity and as a gas indicator. The tool also measures shear slowness—key for evaluatingmechanical properties such as wellbore or perforation stability, hydraulic fracture-heightprediction or sanding analysis.5 DSI results canalso be used to determine stress anisotropy, a keycomponent for oriented fracturing. The data alsocontribute to geophysical interpretations usingsynthetic seismograms, vertical seismic profilesand amplitude variation with offset analysis.Fully combinable with other cased hole loggingtools, the DSI device operates at logging speedsup to 3600 ft/hr [1100 m/hr]. Prior to running theDSI tool, it is crucial to evaluate cement integritybecause a high-quality cement sheath improvesthe quality of DSI results.

The CHDT Cased Hole Dynamics Tester tool isa unique tool that measures multiple pressuresand collects fluid samples behind casing.6 Thetool drills a small hole through casing and cementand into the formation. After measuring pressureand collecting fluid samples, the tool plugs thehole drilled through the casing. The device hasbeen used to drill more than 300 holes and has asuccess rate of more than 91% when the operatorhas chosen to plug the test hole. CHDT operations

4 Oilfield Review

Property

Casing condition

Cement condition

Lithology

Pressure

Lithology

Porosity

Oil content

Gas content

Fluid identification

Logging Tools

USI tool and caliper devices

USI and CBT tools

RST and RSTPro tools andSpectroLith lithologyprocessing of spectra

CHDT tool

Gamma ray, density and neutron tools

CHFD, CHFP, CNL and DSI tools

RST and CHFR tools

Neutron and sonic tools

CHDT tool

> Components of ABC Analysis Behind Casingservices. ABC tool combinations may be selectedto complement openhole data or to achievespecific formation-evaluation objectives.

Summer 2003 5

offer a cost-effective method to optimize recom-pletion plans, enhance old or incomplete log data,assess pay zones and evaluate wells for their eco-nomic potential. The tool also can be used tomonitor flood fronts and measure their effective-ness in secondary-recovery operations.

Customized software, known as the ABCComposer, helps log interpreters prepare mean-ingful composite log presentations. The softwarecan incorporate PDS and ASCII files.7

Thorough prejob planning is essential for suc-cessful ABC services. Job preparation includes abit and scraper run to clear debris from the well-bore. Wellbore conditions affect certain toolsmore than others. For example, in the presenceof corrosion, the CHFR tool is susceptible to poorelectrical contact with the casing. USI and CBTlogs identify potential casing corrosion, so run-ning these tools before deploying the CHFRdevice is recommended practice.

Contingency Logging in NorwayTo develop the Snorre field, located in theTampen area offshore Norway in the North Sea,Statoil and its partners are drilling developmentwells from two platforms (right).8 In theNorwegian sector, this field is second in size onlyto the Ekofisk field. Thanks in part to continualapplication of new technology, the Snorre fieldhas been producing oil and gas for more than adecade. Horizontal production wells drain sev-eral complex reservoirs by water-alternating-gas(WAG) injection. WAG injection creates distinctpressure regimes in separate reservoir compart-ments. Understanding these pressure regimes iscritical to effective reservoir management.

In a Snorre injection well with deviation of63° from vertical, logging-while-drilling (LWD)measurements were acquired from 4070 to

1. For more on the CHFR tool: Aulia K, Poernomo B,Richmond WC, Wicaksono AH, Béguin P, Benimeli D,Dubourg I, Rouault G, VanderWal P, Boyd A, Farag S,Ferraris P, McDougall A, Rosa M and Sharbak D:“Resistivity Behind Casing,” Oilfield Review 13, no. 1(Spring 2001): 2–25.

2. The CHFR-Plus device introduces current on the side ofthe casing opposite where current is flowing to reducethe sensitivity of the measurement to the resistance ofthe casing. Also, the calibration step for this deviceoccurs at the same time as the formation-resistivity measurement, saving additional time.

3. Sigma is the macroscopic cross section for the absorp-tion of thermal neutrons, or capture cross section, of avolume of matter, measured in capture units (c.u.). Sigmaalso refers to a log of this quantity. Sigma is the principaloutput of the pulsed neutron capture log, which is mainlyused to determine water saturation behind casing. Sigmatypically increases as water saturation increases, or asoil saturation decreases. For more on pulsed neutroncased hole logging: Albertin I, Darling H, Mahdavi M,

Cratonic, mainly low relief

Paleogeographic map of the Late Triassic in the northern North Sea

Continental, lacustrine sediments

Deltaic, coastal and shallowmarine clastic sedimentsShallow-marine, mainly shaleswith minor carbonate sediments

Normal fault

Carbonate rocks

Direction of clastic influx

Direction of intrabasinalclastic transport

DENMARK

NORWAY

Tampen Spur and Snorre field

Bergen

Shetland Platform

Grampian High

Stavanger

Edinburgh

Oslo

NORWAY

DENMARK

SWEDEN

FINLAND

OsloBergenSnorre

Stavanger

N o r t h

Se

a

0

0 200 400 600 km

100 200 400 miles300

100 km

< Location of the Snorre field, Norwegian NorthSea. The paleogeographic map (lower right)shows that the Tampen area sits in normallyfaulted, continental or lacustrine sediments ofthe Statfjord formation. These complex reser-voirs are now undergoing water-alternating-gas(WAG) injection. Successful WAG operationsdepend on a thorough understanding of reser-voir compartments and their pressures.

Plasek R, Cedeño I, Hemingway J, Richter P, Markley M,Olesen J-R, Roscoe B and Zeng W: “The Many Facets ofPulsed Neutron Cased Hole Logging,” Oilfield Review 8,no. 2 (Summer 1996): 28–41.

4. The term spectroscopy refers to the study of the compo-sition and structure of matter using various analyticalinstruments to measure the emission and dispersion ofparticles or energy. For more on the use of the RSTProdevice in carbonate rocks: Akbar M, Vissapragada B,Alghamdi AH, Allen D, Herron M, Carnegie A, Dutta D,Olesen J-R, Chourasiya RD, Logan D, Stief D,Netherwood R, Russell SD and Saxena K: “A Snapshot ofCarbonate Reservoir Evaluation,” Oilfield Review 12, no. 4(Winter 2000/2001): 20–41.

5. For more on DSI technology: Brie A, Endo T, Hoyle D,Codazzi D, Esmersoy C, Hsu K, Denoo S, Mueller MC,Plona T, Shenoy R and Sinha B: “New Directions in SonicLogging,” Oilfield Review 10, no. 1 (Spring 1998): 40–55.

6. For more on the CHDT tool: Burgess K, Fields T, Harrigan E,Golich GM, MacDougall T, Reeves R, Smith S,Thornsberry K, Ritchie B, Rivero R and Siegfried R:

“Formation Testing and Sampling Through Casing,”Oilfield Review 14, no. 1 (Spring 2002): 46–57.Fields T, Gillis G, Ritchie B and Siegfried R: “FormationTesting and Sampling Through Casing,” GasTIPS 8, no. 3(Summer 2002): 32–36.

7. Picture Description Script (PDS) is a proprietarySchlumberger graphics format for displaying log data.American Standard Code for Information Interchange(ASCII) is another industry standard for computer data formats.

8. On January 1, 2003, Norsk Hydro turned over operator-ship of the Snorre field to Statoil. For more information:“Snorre Turns 10 With Second-Highest RemainingReserves” (March 6, 2003):http://www.hydro.com/en/press_room/news/archive/2002_08/SnorreBirthday_en.htmlFor more on the Snorre field: “Snorre” (March 13, 2003):http://www.statoil.com/STATOILCOM/SVG00990.NSF?opendatabase&lang=en&artid=7840C91E88FEBE93C1256B3D003B8F41

4820 m [13,353 to 15,814 ft]. Additional mea-surements from the DSI, MDT ModularFormation Dynamics Tester and PlatformExpress tools using the TLC Tough LoggingConditions system were originally planned forthe entire openhole section.

The Platform Express integrated wireline log-ging tool, the DSI device and the MDT tool wererun in combination to acquire openhole data andthree formation pressures. The MDT pressuremeasurements were sufficient to characterizethe pressure regime in the upper reservoir sec-tion. This Snorre well was not considered highrisk, but the logging tools reached a depth of just4440 m [14,568 ft] because of hole problems,measuring only 50 m [164 ft] of the reservoirinterval and leaving a critical 380-m [1247-ft]interval through the remaining reservoir sectionwithout porosity logs of any type.

The operator decided to set casing and deployan ABC tool suite to obtain the required data.This ABC logging program, which was the first useof the ABC suite, included the USI, CBT and GPITGeneral Purpose Inclinometry Tool devices to

evaluate cement quality across the interval (left).The CHFD, CHFP, DSI and GPIT devices were runfor formation evaluation. The operation wasplanned and executed without problems, and the data were transmitted using the InterACTreal-time monitoring and data delivery system forprocessing by Schlumberger Data & ConsultingServices in Stavanger, Norway, and New Orleans,Louisiana, USA, and the Schlumberger-DollResearch Center in Ridgefield, Connecticut, USA.The cased hole logs closely match the openholelogs in overlapping intervals.

The operator characterizes certain wells ashigh-risk because the time between drilling andachieving zonal isolation of the reservoir units iscritical.9 Time spent running openhole logs—primarily the MDT device for pressure data—allows borehole conditions to deteriorate, some-times to the degree that the casing cannot be runsuccessfully or cement quality is suboptimal andzonal isolation cannot be achieved. To eliminatethis problem, the operator selected the CHDTservice to obtain formation pressures throughcasing and cement.

6 Oilfield Review

-1000.0-500.0

0.32.63.03.54.04.55.05.56.06.57.07.58.0

X050

Casing ConditionCement Map

Cement MapBonded

Shale Solids

Bound Water

Effective Porosityvol/vol

vol/vol

0.0

1.0

1.0Hydrostatic Pressure

bar 400.0250.0

0.0Clay Volume

Sand

Hydrocarbon

Formation CHDT Pressures WellSketch

Depth,m

InternalRadius

Average

4 5in.

X100

X200

X300

X250

X350

X450

X550

X400

X500

X150

Formation Pressurebar 400.0250.0

ExternalRadius

Average

4 5in.

> ABC services in the North Sea. Logging-while-drilling (LWD) results from this Snorre well,shown in Track 2, demonstrate alternating sandand shale layers. This composite log is one ofmany possible ways to display data acquiredusing ABC services.

CANADA

ALBERTA

Calgary

11-26-34-7well

0

0 200 400 km

100 200 miles

> Location of the 11-26-34-7 well, Caroline field, central Alberta, Canada.

Summer 2003 7

To date, three CHDT jobs have been com-pleted in the Snorre field; additional jobs areplanned. These have been some of the most chal-lenging tractor-conveyed CHDT wells in theworld.10 The first Snorre well in which the toolwas run was highly deviated—approximately83°—and, therefore, the first ever tractor-conveyed CHDT operation. It also was the firstcommercial use of the CHDT tool in the Snorrefield. The second well was the first CHDT job in ahorizontal well—in this case, a well with a 95°deviation. At 1460 kg [3219 lbm], the tool stringfor that job, which included both pressure andsampling modules, remains the heaviest conveyed by tractor to date. Recently, the firstdual-probe CHDT tool string was run in a Snorrewell to maximize the number of test points in asingle trip. Valuable formation-pressure datahave been obtained from these three CHDT oper-ations. The main lesson learned is that goodcement quality is crucial for a proper and reli-able CHDT formation-pressure interpretation.

For high-risk Snorre production wells, forma-tion-pressure data help establish uniform pressure zones in the completion design andoptimize the completion-fluid weight. Without

pressure data, completion-fluid weight is basedon the maximum pore-pressure prognosis forwell control. If the reservoir pressure is consid-erably lower than this prognosis, the well will notflow, which delays production. In addition, thewell will require an intervention for stimulation operations, which cost more than USD 1 millionin rig time alone.

Pressure data in the high-risk injection wellsare vital for confirming communication betweeninjection wells and production wells located inthe same fault block. If the reservoir pressure ina newly drilled injector is at initial pore pressure,then the injector is not in communication withproducing wells and will not increase oil recov-ery. A new injector is required—at a cost ofapproximately USD 10 million—to sweep hydro-carbons from the producing reservoir.

Formation Evaluation Behind Casing in CanadaIn the Caroline field of Alberta, Canada, Big HornResources, Ltd. (now part of Enterra EnergyCorp.), drilled the 11-26-34-7 well to test twopotential hydrocarbon zones (previous page,top). A downhole bridge prevented openhole

logging tools from accessing the bottom 50 m ofthe well, which was the location of the primaryobjective. The secondary objective was evaluatedusing openhole resistivity and porosity logs.

Big Horn Resources wanted to evaluate gas-detection indications from mud logging, but hadto run casing because of poor wellbore conditionsfor openhole logging. The company planned togather additional reservoir information by log-ging behind casing, deploying the USI and CBTtool combination to assess cement quality, theDSI and CNL tools to determine porosity, theCHFR tool to evaluate fluid saturations and theCHDT device to acquire formation-fluid samplesand pressure measurements.

The primary and deeper objective—theElkton carbonate formation in the bottom zoneat XX00 m—proved to be nonproductive on thebasis of ABC results (above). The CHFR resistiv-ities, combined with porosity measurements

Casing SegmentResistance–Repeat Pass

Gamma Ray CementBond

DSI SonicCoherence

ohm-m0 0.0001

0 API

XX00 m

150

Casing SegmentResistance–

First Pass

ohm-m0 0.0001

CHFR Resistivity–Repeat Pass

ohm-m2 2000

CHFR Resistivity–First Pass

ohm-m vol/vol2 2000

Cased Hole DSI Delta T

µs/m µs/m300 100100 700

Cased Hole Neutron Porosity

0.45 -0.15

> Cased hole evaluation of primary objective, Caroline field, Canada. The CHFR resistivities (Track 3),combined with porosity measurements from the sonic and neutron tools (Track 4), indicated high watersaturation in the primary, deeper objective near XX00 m. Since there was no gas indication from theneutron and sonic combination, this zone was abandoned.

9. For more on zonal isolation in the Tampen area: Abbas R,Cunningham E, Munk T, Bjelland B, Chukwueke V, Ferri A,Garrison G, Hollies D, Labat C and Moussa O: “Solutionsfor Long-Term Zonal Isolation,” Oilfield Review 14, no. 3(Autumn 2002): 16–29.

10. A tractor is a device used to convey equipment in wellsbeyond the point where gravity alone would help theequipment reach the bottom of the hole.

from the sonic and neutron tools, indicated highwater saturation, and since there was no gas indi-cation from the neutron and sonic combination,this zone was abandoned.

The secondary, upper zone at XX75 m, aCretaceous sandstone of the Mannville Group,the Rock Creek formation, was expected to begas-bearing; its productivity was evaluated with aCHDT sample (above). The CHDT fluid samplingconfirmed the presence of hydrocarbon in this

zone. On the basis of fluid-mobility estimates(the ratio of permeability to viscosity in units ofmD/cp), however, the potential mobility of thefluid was uncertain, but considered likely to below. Big Horn Resources elected to perforate thiszone using tubing-conveyed perforating technol-ogy. Pressure-transient measurements from aflow test confirmed the low mobility estimatefrom the CHDT device, so the company aban-doned the upper zone. (next page, top). Without

the data from the CHDT tool, the company mighthave invested over CAD 250,000 for hydraulicfracturing and flow testing of this well.

The experience of Big Horn Resourcesdemonstrates that formation evaluation behindcasing can be a viable alternative to openholelogging when wellbore conditions make openholelogging difficult and increase the risk of stickinglogging tools in the hole while performing theseoperations. For operators deciding whether toperform expensive operations, such as well com-pletions, stimulation or testing operations, onthe basis of incomplete formation evaluations,ABC services are a cost-effective alternative.

Formation Evaluation in EcuadorOpenhole logging operations in the Dorine field,Oriente basin, Ecuador, are risky and often expen-sive because of borehole-stability issues. The fieldis in development, so the operator, AEC EcuadorLtd. (now EnCana Corporation), is emphasizingrig efficiency and minimizing capital and operat-ing expenses. AEC decided to acquire cased holelogs for a well in which openhole logs had beenacquired several months earlier. By comparingopenhole and cased hole logs, the operator soughtto gain confidence in an evaluation techniquethat would help reduce field-development costs.Rather than spending time and money acquiringsuboptimal openhole data from difficult wells, theoperator was considering acquiring only casedhole logs in future wells. Cased hole density,porosity and sonic data closely matched openholedata (next page, bottom).

Several conditions led to the high quality ofthe cased hole data. The operator andSchlumberger performed extensive prejob planning to ensure that the well was a suitablecandidate for ABC services. Specifically, engi-neers checked the condition of the cementsheath to ensure that the well was an appropri-ate candidate for using the CHFP, DSI and CHFDdevices. The USI and CBT tool used in combina-tion indicated the cement quality was generallygood. Corrosion can be a particular concernwhen using the CHFR device in older wells, butthe casing in this well was new.

As operations began, the wellsite crew ranscrapers in the wellbore to remove cementstringers or scale that might interfere with casedhole data acquisition. Data were transmitted to

8 Oilfield Review

Cased Hole Gamma Ray

API0 150

Caliper

in.6 16

Bit Size

Resistivity Decision Track Cement Map Depth, m

in.6 16

90-in. AIT-H Investigation

ohm-m0.2 2000

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ohm-m0.2 2000

CHFR Resistivity

ohm-m0.2 2000

Casing

in.0 20

Openhole Bulk Density

g/cm31.95 2.95

Cased Hole Thermal Neutron Porosity

vol/vol0.45 -0.15

Openhole Thermal Neutron Porosity

vol/vol0.45 -0.15

Formation Pressure

psi4050 4550

Hydrostatic Pressure

psi4050 4550

XX75

XX50

> Cased hole evaluation of another Caroline field zone, Canada. The upper sandstone reservoir isclearly visible in the green gamma ray curve (Track 1) above XX75 m. CHFR data (blue circles) overlaydeep-reading resistivity data (red curves) in Track 2. The operator decided to acquire CHDT pressuredata from the lower part of the sandstone (blue and red circles in Track 3). The cement map (Track 4)guided CHDT test points. This cased hole evaluation prompted the operator to complete the well in thelower part of the sandstone interval.

11. For more on PowerSTIM well optimization services: Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S,Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC,Norville MA, Seim MR and Ramsey L: “From ReservoirSpecifics to Stimulation Solutions,” Oilfield Review 12,no. 4 (Winter 2000/2001): 42–60.

Summer 2003 9

Schlumberger Data & Consulting Services inQuito in real time using the InterACT service.This example from the Dorine field demonstratesthat logging after setting casing is a cost-effective method of formation evaluation whenborehole stability presents unacceptable risks.

ABC services have been used elsewhere inEcuador. For example, an operator selected theCHFR device to reevaluate saturation in a zone ofinterest in which openhole logs indicated a rela-tively high water saturation; the CHFR resultsindicated a lower water saturation. The ABC services also have proved to be a critical part ofthe candidate-recognition process to evaluatewells for PowerSTIM well optimization services.11

ABC results helped determine Young’s modulus,Poisson’s ratio and the formation-fracture gradi-ent, which are crucial inputs for optimizing thedesign of the hydraulic fracturing operations.ABC services also have been used in wells that had to be cased before openhole logs were acquired.

Staying Ahead Behind CasingAs more E&P companies emphasize brownfieldactivity, formation evaluation behind casing willbecome more essential as a cost-effectivemethod to optimize production. ABC services,including interpretation support, allow compa-nies to acquire and interpret data and then makeinformed decisions, such as sidetrack drilling,offset drilling, well interventions, wellbore orfield monitoring, and other operations.

ABC services make it possible for E&P com-panies to obtain well logs in situations that previously would have impeded or preventeddata acquisition. In adverse wellbore conditions,such as wells experiencing borehole-stabilityproblems, operators now can decide to run casing and conduct logging operations after-wards using the ABC services. For older fields,operators may use these services to evaluatepotential pay behind pipe rather than drill a newwell simply to acquire data. Producing wells andfields are easily monitored using ABC tools. Inmany situations, planning these operationsahead of time minimizes rig-time costs. Perhapsthe only obstacles to successful data acquisitionwith these tools are well accessibility and thecondition of the casing, cement and well-comple-tion hardware. As service companies and E&Pcompanies gain familiarity with comprehensiveformation evaluation through casing, they willcontinue to seek first-class answers to questionsabout ever-changing reservoirs. —GMG

120

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Bit penetration positionPretest volume

Casing-seal test Drill casing Formation pretests Plug casing

> CHDT results from Caroline field, Canada. This plot of CHDT pressure versus time shows a completetest cycle, beginning with the casing-seal test, drilling into the casing, performing multiple formationpretests and plugging the casing. The pressure changed as soon as the tool drilled through the casing,which is typical for this region. The USI log in this well revealed the existence of cement channels inthe zone, which might have influenced the pressure response. The test required more than four hoursto complete because of the low permeability of the zone. An openhole formation test of similar durationwould present a higher risk of sticking the tool. In this case, the logging tools were run from a servicerig, which cost much less than a drilling rig.

MD, ft

X060

X070

X080

X090

X100

Openhole Compressional Slownessµs/ft

Cased Hole Compressional Slownessµs/ft

Caliperin.6 16 140 40 140 40

Openhole Thermal Neutron Porosityvol/vol

Cased Hole Thermal Neutron Porosityvol/vol

Cased Hole Gamma RayAPI0 150 0.6 0 0.6 0

Openhole Bulk Densityg/cm3

Cased Hole Bulk Densityg/cm3

Openhole Gamma RayAPI0 150 1.65 2.65 1.65 2.65

> Comparison of openhole and cased hole density, porosity and sonic data. Openhole and cased holedata (Tracks 2 and 3) match closely.

10 Oilfield Review

Promoting Environmental Responsibility in Seismic Operations

As it moves into the 21st Century, the oil and gas industry is placing a high priority on

developing and implementing new technology. The most successful advances not only

enhance efficiency in all aspects of evaluating and managing the reservoir, but also

promote stewardship of the environment and respect for local cultures. A new system

for planning and monitoring land seismic operations is one such technology that is

showing remarkable results.

David GibsonHouston, Texas, USA

Shawn RiceGatwick, England

For help in preparation of this article, thanks to RhondaBoone, Tony Bright and Robin Walker, Gatwick, England;and Bruce Clulow and Ryan Szescila, Anchorage, Alaska,USA. For the oil painting depicted on page 10, thanks to George Stewart, Stewart Graphics, Ridgefield,Connecticut, USA.Desert Explorer, EcoSeis and Navpac are marks ofWesternGeco.

Summer 2003 11

Finding and developing the resources to meetthe world’s demand for oil and gas has alwayspresented challenges to oil companies.

In the early days of exploration, decidingwhere to drill for oil or gas was based largely onsurface geology and hunches. Drilling additionalwells to define reservoir extent was expensiveand intrusive; the results were unpredictable,and in some cases, the impact on the local envi-ronment was devastating (right).

The practice has evolved considerably. Overthe years, this system of exploration drilling by“best guess” has been replaced with science inthe form of systematic geological mapping, geo-chemical analysis of seeps and potential sourcerocks, and seismic-surveying technology.

Seismic surveying uses acoustic waves toobtain an image of structures beneath the sur-face. On land, a seismic source—usually eithervibroseis vehicles or an explosive charge—isused to generate acoustic waves, which propa-gate deep into the earth. Each time a wavefrontencounters a change in rock-mechanical proper-ties, part of the wave is reflected back to the sur-face, where an array of sensors records thereturning signal. The recorded information isprocessed to develop an image of the subsurface.Exploration and production (E&P) companiesuse these images and attributes derived fromthem to decide where to drill by identifying subsurface rock formations that are most likelyto contain trapped oil or gas.

As an exploration technology, seismic survey-ing has been remarkably successful. E&P expertsrank three-dimensional (3D) surface seismic surveys as the technology with the greatestimpact on the E&P industry. In the last decade,since application of 3D seismic surveys becamewidespread, exploration success has risen from40% in 1992 to 70% in 2001 (right). At the sametime, the average number of barrels of oil foundper successful well has increased fourfold.Seismic surveys have saved oil companies millions of dollars and have helped keep fuelprices low, but at what cost to the environment?

Acquisition of seismic data involves transi-tory use of the land surrounding a prospect.Traditionally, surveys have been conducted predominantly in the exploration cycle; however,the data are used throughout the life of the field.During survey acquisition, temporary—and inrare cases, permanent—changes can occur if theproject is not managed well. Actual land use dur-ing acquisition affects only between 2.5% and5.0% of the land surface area covered by the seis-mic survey.1 Depending on survey design, thisimpact typically equates to between 750 and

1000 linear km [470 and 625 linear miles] of seis-mic line or between 2.5 and 5.0 km2 [0.9 and1.8 sq miles] of the surface area per 100 km2

[39 sq miles] of area surveyed.Although the impact is considered temporary

and mainly aesthetic, poorly performed seismicsurveys have the potential for significant ecolog-ical impact. In the last decade, heightened envi-ronmental awareness and focus by government,industry and interest groups have increasedpressure to leave no “footprint,” or trace of activity, following such surveys. At the same time,

1. Sweeney DF, Hughes JR and Cockshell D: “IntegratingEnvironmental Impact Evaluation into a Quality, Health,Safety and Environmental Management System,” paperSPE 74009, presented at the SPE International Conferenceon Health, Safety and Environment in Oil and GasExploration and Production, Kuala Lumpur, Malaysia,March 20–22, 2002.

> Production derricks in the Kern River field, Bakersfield, California, USA, in 1932. Development of this field, which was discovered before the advent of seismic surveys, had a sizable impact on the environment.

> Increasing drilling success since the introduction of 3D seismic surveys,for a sampling of 70 exploration and production (E&P) companies fromaround the world. Success ratio is the total number of exploration wellsclassed as commercial success divided by the total number of wells drilled.Another measure of exploration success is the increasing number of bar-rels of oil reserves added per well (green curve) since the introduction of3D surveys. Data are taken from financial disclosures made to the UnitedStates Securities and Exchange Commission, supplied to the OilfieldReview by Robin Walker, WesternGeco, Gatwick, England.

0

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the industry is increasingly conducting time-lapse, or four-dimensional (4D), surveys.Onshore application of 4D surveys could haveeven greater environmental impact becauserepeat surveys may have to be acquired beforethe baseline survey area has had time to recover.2

These repeat surveys are conducted over thesame area to monitor changes in reservoir fluidswith time.

Against this backdrop of heightened environ-mental awareness, the industry continues todemonstrate its commitment to protecting theenvironment by insisting on safer and more environmentally sound drilling, logging, testing and production practices. Because most E&P companies hire seismic contractors to acquiregeophysical data on their behalf, rather than col-lecting the data themselves, geophysical serviceproviders must also manage their operations toprevent health, safety and environmental (HSE)incidents. The client and the contractor mustwork together to prepare HSE management plansfor each geophysical project.

To lower the risk of a potential environmentalincident during seismic data acquisition,WesternGeco developed and introduced theEcoSeis environmental performance monitoringsystem for seismic operations. The EcoSeis systemfocuses the WesternGeco quality, health, safetyand environment (QHSE) management system on

the environmental concerns in an area. This structured and systematic approach is customizedfor each seismic project to achieve a desired low-impact environmental outcome. QHSEexperts develop project-specific environmentalprocesses and procedures in accordance withclient and regulatory requirements, project haz-ard assessments, reference guidelines, and localcultural considerations and concerns. These pro-cesses and procedures are then monitored in realtime and compared with the desired outcome toensure that the project footprint is minimized.

This article describes current practices inonshore seismic data acquisition, along with newmethods for avoiding environmental damage andfor monitoring compliance with regulatory guide-lines. Case studies from around the world showhow the EcoSeis system works to minimize survey impact and helps E&P companies acquiredata safely and cost-effectively.

Planning to Minimize Seismic ImpactThe best way to begin planning a seismic surveyis to understand the needs of all interested parties, including local inhabitants, clients, gov-ernmental regulatory bodies, nongovernmentalorganizations and single-interest groups. Theseparties contribute to the creation of an environ-mental-impact assessment (EIA), sometimescalled an environmental-impact statement

(EIS), which describes the existing conditions inthe area under consideration and any risks that a survey may pose to flora, fauna, cultural heirlooms or other aspects of the environment.Many governments require compliance with EIA documents, which typically are assembled byspecialized consulting companies and can number hundreds of pages in length. In theabsence of governmental or client-imposed regu-lations, contractors usually follow their own com-pany guidelines, and also those set by the International Association of GeophysicalContractors (IAGC).3

Ideally, the EIA should be seen and under-stood by all potential contractors before they bidon a seismic project. Service companies thatagree to acquire a seismic survey without priorknowledge of restrictions and environmentalrequirements can encounter unexpected costsand delays during survey acquisition. Most con-tractors routinely conduct preliminary scoutinginvestigations into potential survey areas beforebidding, to identify obstacles and difficulties.

Survey planners can then use this initialinformation to design a survey that meets geophysical as well as environmental objectives.Often, E&P company geophysicists providedetailed specifications regarding shot spacingand depth, receiver line spacing and orientation,and source type, frequency content and size.

12 Oilfield Review

> A paleosol, or ancient soil layer (darker surface), exposed by wind-blown shifting sands in AbuDhabi, UAE. These ancient surfaces host many kinds of easily disturbed wildlife, so seismic lines andaccess roads deviate to avoid them.

Paleosol

Summer 2003 13

Major seismic contractors also have the capabil-ity to design surveys and to modify survey plans ifnecessary.4 For example, the orientation ofclient-specified receiver lines may need to bechanged to fit local conditions. A survey in adesert sand-dune environment may need a different orientation relative to prevailing winddirections, to allow acquisition between dunesrather than across them. In some desert environ-ments, such as in the southern deserts of AbuDhabi, UAE, paleosols, or ancient soils, havebeen exposed by shifting sands and made vulner-able to the elements (previous page). These pale-osols, which contain fossilized coral formed in aprevious warm-water environment, are home tomany forms of modern wildlife, and need to beavoided when deploying seismic lines.

Once a seismic contractor secures an acquisi-tion contract and understands the survey specifi-cations, guidelines need to be set for the crewthat will survey seismic source and receiver posi-tions. Surveying the positions of source andreceiver lines requires access by land-surveyingexperts and their equipment. In open areas, seis-mic crews typically survey lines by drivinglightweight trucks mounted with global position-ing systems (GPS) along the predetermined grid,then setting stakes at specified source andreceiver locations.

Environmental concerns at this stage includenot only damage that may occur during the sur-vey, but also the potential damage that the newlycreated access might cause. The paths createdduring a seismic survey can become unofficialroads that subsequent visitors may use to takevehicles into remote locations. To mitigate thiseffect, and also to minimize impact on soil andvegetation, surveying crews may drive in a weav-ing, or crooked-line, pattern instead of straightlines. This practice helps reduce erosion, elimi-nates visual impact and discourages people fromlater driving the routes taken by the vibroseisvehicles. Vehicles also access survey lines by exit-ing a main road at an angle, so that survey linesare not as visible.

In the past, surveys in areas that have signifi-cant vegetation have used bulldozers to cleartracks for survey access. Bulldozers uproot treesand shrubs, and are a fast and cost-effective wayto clear lines for GPS-equipped survey vehicles.In some environments, and with landowner consent, bulldozing remains the method ofchoice for line preparation. However, new equipment and techniques allow for lowerimpact surveys to be acquired, minimizing theamount of vegetation disturbance.

When the survey is in difficult terrain, remotelocations or environmentally sensitive areas,conventional line preparation is often impossible

or undesirable. An alternative is the Navpaclightweight, portable inertial navigation unit(above). Contained in a backpack, this unitallows surveyors to set a route without cuttingoverhead foliage—otherwise needed to achieveclearance for GPS surveys. This alternative alsoallows survey lines to safely follow the path ofleast resistance. The unit contains a hand-heldcontroller to navigate and record data, and canbe augmented by an embedded GPS-receiver cir-cuitry board that automatically uses differentialGPS when available.

Differential GPS works by taking startingcoordinates at a known, stationary referencepoint, then tracking the GPS signal as the Navpacunit moves and sending a correction value to themoving unit. If the GPS cannot function, such asunder dense foliage that hides the Navpacantenna from orbiting satellites, the unit oper-ates in inertial mode. Inertial mode uses arugged, precise gyroscope to keep track of allhorizontal and vertical changes in position. The

2. For more on time-lapse seismic monitoring: Pedersen L,Ryan S, Sayers C, Sonneland L and Veire HH: “SeismicSnapshots for Reservoir Monitoring,” Oilfield Review 8,no. 4 (Winter 1996): 32–43.

3. http://www.iagc.org4. Ashton CP, Bacon B, Mann A, Moldoveanu N, Déplanté C,

Ireson D, Sinclair T and Redekop G: “3D Seismic SurveyDesign,” Oilfield Review 6, no. 2 (April 1994): 19–32.

> The Navpac portable inertial navigation unit. This navigation system, which can be carried in a backpack, allows survey coordinates to be mapped without cutting overhead foliage to achieve clearance for global positioning system (GPS) surveys. The unit contains a hand-held controller tocheck coordinates and record data, and can be supplemented with a GPS receiver board for use inareas where GPS can be accessed.

Navpac unit compares these position changeswith the starting coordinates to give the coordi-nates at any new point.

The Navpac system is an excellent example ofa technology that was developed and imple-mented to provide efficiency gains in productiv-ity while also minimizing the impact on theenvironment. Used routinely in Canada, it hasproved to output superior surveying data in diffi-cult terrain with a single survey pass, minimal cutting of vegetation and improved crewsafety. It is useful in heavily forested areas,among tall crops, under vegetation, and in urbanareas—places where surveying is difficult andminimal impact is desired.

Once the source and receiver positions aresurveyed and marked, the recording crewdeploys receivers. These are geophones that areplanted into the ground, typically with one geophone group plugged into the acquisition lineevery 25 to 30 meters [82 to 98 ft] (left). The geo-phones record an analog signal; the analog signals from each station—usually comprising 6to 72 geophones—are grouped into one channel,sent to a digitizer and recorded on tape. Aftereach day’s acquisition, quality-control specialistsperform preliminary data processing on the digitized data to verify the suitability of theacquisition geometry. Typically, 8 to 12 receiverlines are active at any given time, with up to500 channels each. In a standard survey with12 geophones per channel, 400 channels per lineand 8 active lines, there are 38,400 geophonesdeployed over a few square miles. After recordinga source position, the crew rolls the acquisitiongeometry along by gathering the receivers in theback of the survey and placing them at the front.

For explosive seismic sources, the seismiccrew drills a shot hole, typically 30 to 100 ft [9 to30 m] deep, to contain the charge. The shot holehas a diameter from 2.5 to 4 in. [6 to 10 cm].Usually, the hole is drilled with a rotary drill thatis mounted on any one of a variety of carriers,including trucks, trailers, articulating buggies,low-impact track vehicles and all-terrain vehi-cles. The drill is driven or otherwise transportedfrom shotpoint to shotpoint. When a circulatingfluid is required, 50 to 150 gallons [190 to 570 L]of water or mud may be needed for each hole.Mud is recirculated and collected in a portablemud pit. The cuttings, which may amount to8 cubic feet [0.2 m3] per hole, are deposited backinto the borehole or spread evenly on the ground.Since the subsurface is made up of different

14 Oilfield Review

5. Sweeney et al, reference 1.

> Laying out receiver lines (top) and planting geophones (bottom) in adesert environment. Geophones need to be planted, rather than simply laidon the ground, to ensure good coupling with the earth and to reduce windnoise. The geophones are so sensitive that a gentle wind will cause noiseon the recorded traces. This survey featured a 72-geophone per group lay-out in a trapezoid pattern. A more typical layout is 6 or 12 geophones in astraight line.

> Five vibroseis units at a shotpoint in a Middle East survey. These source vehicles are examples of the Desert Explorer family of land seismic vibrators developed by WesternGeco. The proprietarydesign includes safer walkways, a desert-light kit and a zero-leak refueling system. These and otherimprovements provide safety and reliability and minimize environmental impact. The inset (top) showsa source vehicle with articulated chassis, allowing stable operation in rough terrain.

Summer 2003 15

types of rock layers, the cuttings can create apatch of discolored earth that may remain forseveral years. In some areas, access by truck-mounted drills and associated water trucks canrequire clearing heavy vegetation from a path 12to 16 ft [4 to 5 m] wide.

In inaccessible areas, the drilling crew movesa portable drilling system from point to point byhelicopter operations (right). Helicopter opera-tions impose minimal additional environmentalimpact on shot-hole drilling.

Finally, to detonate a charge, a member of theacquisition crew connects a radio-controlled unitto the charge, which is then fired remotely froma recording truck.

The other typical seismic energy source is avibroseis source. Each vibroseis truck weighsapproximately 65,000 lbm [29,500 kg], but in thedesert, crews usually deploy articulated vibroseisbuggies, which are heavier (85,000 lbm)[38,600 kg]. In all cases, the vehicles lower aheavy plate to the ground that vibrates andimparts energy to the earth. Two to ten such vehicles shaking the earth in synchrony—timedby a simultaneous radio signal to all vehicles, andnominally at one source position—constitute asingle source point (previous page, bottom). Aftergenerating energy at one source point, the vibro-seis sources move to the next point along thesource line, which will be at some angle to thereceiver lines.

In snow-covered terrain and fragile sandyenvironments, vibroseis sources can be mountedon articulated rubber-tracked vehicles.WesternGeco has used these in several differentenvironments, most recently for BP in theAlaskan arctic. The rubber tracks help preventdamage to delicate tundra when the vehicleturns, and also are more effective than tires atdistributing the weight of the vibroseis unit. Thisminimizes ground pressure and provides furtherprotection for the vegetation under the snow.Their enhanced maneuverability provides anadditional benefit; they do not require a track tobe plowed ahead of them, further reducing theamount of travel required when surveying a specific location.

Planning ahead and applying the proper tech-nology to minimize environmental impact are vitalsteps in survey acquisition. The next step, mea-suring the success with which a seismic surveycomplies with environmental requirements, canbe a difficult task. To effect this measurement,WesternGeco has developed the EcoSeis system tohelp seismic crews perform surveys while mini-mizing harm to the earth and to living things.

The EcoSeis SystemThe EcoSeis management tool helps crews monitor and assess the environmental perfor-mance of their land seismic activities. It uses aprocess called goal-attainment scaling that wasdeveloped in the 1960s and 1970s in the USA as atool for monitoring and evaluation in the field ofhealth services.5 This tool was adapted by thepetroleum industry through collaborationbetween government—Primary Industries andResources, South Australia (PIRSA)—industry(Santos) and environmental interest groups.WesternGeco used the system in Australia on several Santos projects.

The EcoSeis method provides a crediblemeans for establishing environmental objectivesthat are relevant and appropriate to the activities being undertaken, and establishes a

practical means for evaluating the level of attainment of those objectives. To allowwidespread access, the program is integratedwith the global Schlumberger QHSE reportingsystem known as QUEST. Through the QUESTdatabase, Schlumberger personnel report allwork-related HSE observations, accidents, haz-ardous situations and service-quality events. Thesite also documents each employee’s safety-training record and schedule, records audits andmeetings, organizes remedial work plans andcompiles company-wide statistics.

The EcoSeis system uses an objectiveapproach toward environmental managementthat involves establishing a set of meaningful andmeasurable environmental objectives acceptableto the geophysical service contractors and their

> A portable drill for drilling shot holes in Bolivia. Portable drills use airpressure for hole cleaning and often are light enough to be disassembledand carried to the next shotpoint. In difficult terrain, this portable equipmentis transported by helicopter.

clients, regulators and the community. The aimsof the approach include assessing environmentalactivities more effectively and efficiently; achiev-ing better environmental outcomes; providinggreater flexibility in terms of the application of new and improved technology to achieve environmental objectives; and assuring clients,regulators and the community that environmen-tal objectives are being achieved. The EcoSeisapproach is different from prescriptive environ-mental management systems, which outline spe-cific practices to be followed. Instead, theEcoSeis method focuses on the outcome.

Goal-Attainment ScalingGoal-attainment scaling makes the EcoSeis technique easy to apply to a variety of situations.An important feature of goal-attainment scalingis that all stakeholders—those individuals orgroups with an interest in the outcome—can be

involved in evaluating and seeking consensus onthe most important aspects of any goal, and thelikely range of desirable and undesirable out-comes of activities undertaken, environmental or otherwise.

For each aspect assessed, outcomes aregraded on a scale of –2 to +2. It is expected thatmost outcomes will meet the criteria allocated toa score of 0. This is the level that stakeholdersagree is a satisfactory level of achievement. Inmost surveys, outcomes sometimes are better ormuch better than the acceptable standard. Thesecases are allocated a score of +1 and +2.Similarly, outcomes that are less than the accept-able standard are given scores of –2 and –1.Generally, scores of +1 and –1 occur much lessfrequently than scores of 0, while +2 and –2 situations occur rarely.

The occasional occurrence of a score of –1should serve as a warning that more attention isneeded in that particular aspect of operations

and that some sort of remedial action is required.If scores of –1 happen regularly, a systematicproblem in operations needs to be addressed.The occurrence of a –2 situation normally indi-cates the need for immediate remedial action.This may take the form of physical rehabilitation,system review or other reporting and revisionmechanisms. The appearance of several scores of+1 indicates that the operator and contractor aredoing a better-than-expected job. Cases of +2indicate an ideal outcome; some degree of commendation is warranted to reward excellentoutcomes, unless it is found that the standardswere not high enough.

An example from Indonesia shows theEcoSeis system goal-attainment scaling inaction. In arranging a survey in a remote location, the first step is to set up a base camp,which will occupy the site for several months.However, some members of the crew, including

16 Oilfield Review

>5 open rubbish andkitchen-waste pits

<5 open rubbish andkitchen-waste pits

<3 open rubbish andkitchen-waste pits

<2 open rubbish andkitchen-waste pits

No open rubbish andkitchen-waste pits

>2 toilet facilities open <2 toilet facilities open All toilet facilities closed All toilet facilities closed All toilet facilities closed

>20 items of campconstruction material lefton site

<20 items of campconstruction material lefton site

<10 items of campconstruction material lefton site

<5 items of campconstruction material lefton site

No camp constructionmaterial left on site

>25 items of rubbish on site <25 items of rubbish on site <15 items of rubbish on site <10 items of rubbish on site No rubbish on site

Small patches or signs ofpollution or spills

Moderate signs ofpollution or spills

No signs of pollutionor spills

No signs of pollutionor spills

No signs of pollutionor spills

Excessive signs ofimpact on surrounding area

Moderate signs ofimpact on surrounding area

Minimal signs of impact onsurrounding area

Minimal signs of impact onsurrounding area

No sign of impacton surrounding area

>5 steps cut into soilsurface

<5 steps cut into soilsurface

No steps cut into soilsurface

No steps cut into soilsurface

No steps cut into soilsurface

Prospect Area Site Location Department Survey Date

All rubbish, burn and food-wastepits backfilled

All camp construction materialremoved

All toilet units backfilled Bathing areas free ofrubbish and construction material

No signs of excessive cuttingRe-greening implemented (statenumber of seedlings planted)

Site free of signs ofpollution and spills (includingnearby water bodies)

Site free of rubbish

Camp drainage system backfilled Access routes to bathing andtoilet areas have no steps cutinto soil surface and left in place

No sign of burning in area apartfrom rubbish pits

Minimal impact on surrounding area

Conducted by Client representative (if required) Site exit scoreDate of inspection

Fly Camp Exit Inspection

–2

Poor Inadequate

–1

Satisfactory

0

Good

+1

Very Good

+2

>10 metersdrainage system open

<10 metersdrainage system open

<5 metersdrainage system open

<2 metersdrainage system open

No drainage system open

> Scorecard for measuring goal-attainment scores using the EcoSeis environmental performance-monitoring system at a flycamp in Indonesia. Points ranging from –2 to +2 are awarded for proper cleanup in categories including rubbish pits, toilet facili-ties, construction material, spills and pollution, soil disruption and visual impact on the environment.

Summer 2003 17

surveyors, shot-hole drillers and the recordingcrew, need to live closer to the work. Up to1000 crewmembers may spend 10 days to severalweeks housed at a distant fly camp—named forthe fly, or tent, under which the crew lived in theearly years of seismic surveying.

For the Indonesia survey, there were no governmental regulations, environmental impactassessments or local restrictions to guide fly-camp activities. The WesternGeco crew resolvedto treat the area containing the fly camp as theywould a campground area near home, and cleanup after themselves. They set up objective guide-lines for cleanup, site inspections and compliancedefinitions (previous page). Criteria for satisfac-tory performance—a goal-attainment score of0—are fewer than three open rubbish or kitchen-waste pits; fewer than 5 meters [16 ft] of rain-drainage system left unfilled; all toilet facilitiesclosed; fewer than 10 items of camp construction material left on site; fewer than 15 items of rubbish left on site; no signs of pollution or spills;minimal sign of impact on the surrounding area;and no steps cut into the soil surface.

Crew management advised crew membersand subcontractors in advance that the groundswould be inspected as part of the cleanup pro-cess, and acquainted all staff with the guidelinesthat would be used to monitor compliance.Inspections conducted after dismantling the flycamp showed a satisfactory level of compliancewith specified guidelines (above right). Mostinspections assigned scores of 0 to cleaned-upconditions, and recorded few scores of –1 and+1, with even fewer scores of –2 and +2.

In addition to helping crews assess how sur-veys affect land and vegetation, the EcoSeis sys-tem has been used to monitor the impact ofsurveys on native inhabitants and archeologicalsites. The first EcoSeis project, conducted inAustralia, ensured that the survey would not disturb the archeological sites of native peoples.The native inhabitants traveled on foot through-out the country, and the tracks they created areconsidered archeological sites. The challengewas to lay out a survey that avoids these sites. Tominimize impact on these sites, WesternGecotrained bulldozer operators to recognize them.Environmental monitoring experts revisited thesurvey site one year later, and confirmed that disrupted vegetation had grown back to coverlines and access roads (right).

In Mexico, survey crews have discovered mon-ticulos, or small mounds, that are manifestationsof ancient communities. Now that they are awarethat mounds may be present in many parts of thecountry, WesternGeco crews scout potential

0

5

10

15

20

25

Num

ber o

f ins

pect

ions

Poor Inadequate Satisfactory Good Very good

Line preparation

Camp site

Waste pit

Oil-change sites

Waste storage

> Compilation of inspection results after dismantling the Indonesia flycamp, showing a satisfactory level of compliance with specified guide-lines. Most inspections assigned scores of satisfactory (0) and good (+1)conditions and recorded few scores of -2, -1 and +2.

> Photographs taken during Australia survey acquisition (top) and one year after (bottom), showingthat vegetation had grown back.

survey areas, paying special attention to thesearcheological features.

For a survey in an area containing thesemounds, an unsatisfactory score of –2 on theEcoSeis scorecard would be obtained if the linetraverses and damages a monticulo. A score of –1would result if a site is encountered and narrowlyavoided during line deployment, but not seen,flagged or reported during line preparation. Asatisfactory score of 0 would require that everymound be identified, flagged and reported beforethe survey commences, and that survey linesweave to avoid the site. A score of +1 could beobtained if all sites are scouted, flagged, reportedand the coordinates logged, and the line deviatesto avoid the site by 25 m [82 ft]. A score of +2requires that all sites be scouted, flagged,reported and the coordinates logged, and thatthe line deviate to avoid a site by 50 m [164 ft].

Since WesternGeco crews often venturewhere no one has gone for hundreds of years,they often encounter archeological sites that areunknown even to government organizations.Care is always taken to hand over maps and loca-tions of culturally significant sites to the properauthorities so the sites can be protected.

Minimizing Survey Footprint in ChadThe goal-attainment scaling scorecard and pre-and postproject photographic evidence are justtwo of the QHSE management tools available forpromoting environmentally responsible actionsin land seismic acquisition. WesternGeco crewsalso develop unconventional technology toachieve their goals.

One example comes from the Doba field insouthern Chad, where WesternGeco began surveyoperations in 1996. With proven reserves of more

than 1 billion bbl [159 million m3] stretchedacross a heavily forested area of some 600 km2

[232 sq miles], Doba was a prime candidate forinnovative line preparation. For years, the leastexpensive and most effective means for clearingsurveying lines has been the bulldozer, whichremoves topsoil and roots, creates large piles ofvegetation to be cleared after surveying, andleaves landscapes more susceptible to erosion.Conventional swaths bulldozed every 200 m[656 ft] over an area the size of the Doba fieldwould have left a gigantic grid etched in theEarth surface.

The initiative behind developing a more envi-ronmentally friendly line-clearing method camefrom the World Bank and the oil company client,who agreed on the need to preserve the fragileecosystem in southern Chad. This meant minimizing damage and discouraging futureaccess to the forested area. To meet that need,WesternGeco introduced environmental brushcutters (above left). These large industrial mow-ing machines reduce scrub trees and weeds tomulch without damaging their root structure orthe underlying soils. The roots left in place andmulch remaining on the surface reduce erosionand allow vegetation to grow back rapidly. Brushcutters are slower and more expensive than bulldozers, but inflict less damage.

Photographs taken during line preparationand at intervals after survey completion showhow quickly vegetation returns when lines havebeen cleared by brush cutters (next page). Afterone month, the lines are still visible, but vegeta-tion is growing. After two months, larger plantsare beginning to flourish. Postproject assessmenthas shown that survey lines are impossible to seeafter 6 to 12 months. Today, even the most recentlines are no longer visible. The same linescleared by a bulldozer might still be visible after30 years.

WesternGeco crews are expanding use ofenvironmental brush cutters, and have deployedthem in Chad, Bolivia and the United States formultinational operators who desire to apply thesame environmentally sound technology in foreign locations that they would want used intheir home countries.

Beyond the Call of Duty in BoliviaRecent seismic operations in a sensitive ecosys-tem in southern Bolivia followed strict standardsto minimize impact of the base camp, fly campsand line preparation on the environment and onthe indigenous community.6 The survey, covering1090 km2 [421 sq miles] of the Bolivian Chacoregion, adhered to the crew’s project-specificenvironmental-management plan, which included

18 Oilfield Review

> An environmental brush cutter in Chad. These large mowing machines areused to remove underbrush without damaging roots or soil. Brush cutters areslower and more expensive than bulldozers, but have less environmentalimpact. Leaving the roots in place helps reduce erosion and allows vegetation to grow back rapidly.

> A drill buggy for drilling a small percentage of shot holes in the Bolivia survey.

Summer 2003 19

WesternGeco environmental standards, Bolivianenvironmental law, the client’s policies, andInternational Organization for Standardization(ISO) Standard 14001.7

The prospect area contains a mix of desert veg-etation from scrub to 20-m [66-ft] trees. In thisarid climate, with extreme temperatures rangingfrom 48°C [119°F] in November to –10°C [14°F]in June, the sparse human population existsmainly by cattle farming. Of the 11 communities inthe region, only one has an electric generator.Water supplies, roads and other services are inpoor condition. Every aspect of the seismic project’s potential impact on the environment hadto be considered and monitored.

In compliance with the requirements of the oilcompany client, the Bolivian government,WesternGeco and the ISO 14001 rules, every newemployee had to complete a course on environ-mental education before signing a contract. Topicscovered in the course included QHSE organizationand policies, base-camp procedures, line-cuttingguidelines, waste management, handling of envi-ronmental incidents, archeological informationand environmental-restoration measures.

The base camp was constructed near a villagein an area that had been cleared previously forseismic camps. The crew pumped water for thecamp from a well near a school, and built a water-treatment plant to produce water for cooking andwashing, along with a septic system to handlewastewater. All solid waste—biodegradable,petroleum-based and recyclable—was collected,separated, weighed and disposed of according toISO 14001 standards and Bolivian law.8

To minimize survey impact, the maximum sur-vey-line width was 1.5 m [5 ft]. Only trees smallerthan 20-cm [7.8-in.] diameter at a specified heightcould be cut. Certain trees and cacti were classi-fied as protected species, and could not be cut atall. The survey design accommodated crooked-linegeometry, so any line could be moved to steer clearof obstacles. To avoid unnecessary damage to vegetation, the crew cut survey lines by hand—using machetes—leaving topsoil intact.

Portable drills that use air pressure for holecleaning were brought in to drill almost 95% ofthe shot holes. The portable equipment was lightenough to be taken apart and carried to the nextshotpoint if the terrain permitted. In dangerousterrain, helicopters and cargo nets moved theequipment. Drill buggies were used where possi-ble for a small percentage of holes (previouspage, middle).

After the survey, a restoration group walkedall the lines and checked all fly camps and heli-ports to restore the areas to their natural states.

6. Fyda JW and Eales RM: “Using an EnvironmentalManagement System During Seismic Activities toMinimize Environmental Impact and Provide a CivicAction Plan for Local Population in Proximity to aSensitive Bolivian Ecosystem,” paper SPE 74007, presented at the SPE International Conference on Health,Safety and Environment in Oil and Gas Exploration andProduction, Kuala Lumpur, Malaysia, March 20–22, 2002.

> Environmental-monitoring photographs taken during line preparation(top), one month after (middle) and two months after survey completion(bottom). Vegetation returns quickly to lines that have been cleared bybrush cutters.

7. ISO 14001 is the first level in the ISO family of internationalenvironmental standards. For more information:http://www.iso.ch/iso/en/prods-services/otherpubs/iso14000/index.html

8. Fyda and Eales, reference 6.

This group was responsible for picking up trash,survey flags and cap wires from shotpoints; fillingin shot holes that had blown out during surveyrecording; and placing the cut vegetation on thesurvey lines to act as mulch.

Sometimes, the effort to avoid environmentaldamage goes beyond what is required, and entailsenhancements to the surrounding area. To helpimprove some of the basic services in the area ofthe Bolivia survey, the base-camp crew partici-pated in social-action programs. The aims of theprograms were to increase community awarenessof environmental issues and help residents learnhow to improve the quality of life in this difficultarea. Through workshops at the local schools, theinhabitants learned about measures they couldtake to make their world safer and healthier.Courses covered aspects of home and kitchensafety, water sanitation, waste disposal and medical-emergency preparedness. The crew doctor visited the communities and arranged forsome patients to be transported by crew vehiclesto a distant hospital. The crew donated construc-tion supplies to repair community buildings, deliv-ered educational supplies to schools, repairedroads in the area and refurbished the generatorand water pumps in the nearby community.

Social-action programs are vital to operationsin many areas. They promote good relationsbetween the seismic contractor, the communityand the oil company client, and ensure that theprojects conducted by the contractor helpachieve the long-term goals of the community.

Acquisition in Arctic Environments In arctic environments, daunting conditionsrequire dedication, planning and experience on

the part of seismic crews to ensure that dataacquisition is completed safely and on schedule.Seismic crews have been conducting surveys onAlaska’s North Slope since the 1950s, whenWesternGeco began setting the standards for per-formance and safety in arctic conditions.

The arctic ecosystem is a delicate one.Fragile tundra vegetation, if disturbed, can takedecades to grow back. Roads, rigs, pipelines andthe presence of humans can affect caribou, birdsand other migrating species (above). Humanactivity can affect not only numbers but also thegeographic distribution of plants and animals.9 Ifnot managed properly, greater numbers of peopletemporarily living on the North Slope couldpotentially create more refuse for scavengingbears, foxes, ravens and gulls. The E&P industryhas identified this concern, so refuse is well pro-tected from access by animal species in the area.

To minimize environmental impact, arcticland surveys are carried out during winter monthswhen the tundra is frozen and a blanket of snowprotects the vegetation. WesternGeco has devel-oped special equipment, operations and trainingfor these harsh conditions. Vehicles on tracks, as opposed to wheels, have been used for sev-eral years in arctic regions.10 These vehicles are used not only to carry vibroseis sources, but also to deploy and retrieve acquisition equip-ment (next page, top). Continued advances intrack technology have made it possible to use fourrubber tracks, one on each corner of an articu-lated vehicle, to minimize skid steering on thedelicate tundra. Wider tracks also mean lowerpressure on the ground and improved ride qualitythat reduces operator fatigue and other health-related concerns. The plastic and wire-pin flags

that once were positioned to indicate source andreceiver points have been replaced with woodenstakes that will biodegrade if inadvertently left inthe field.

A recent example encompassing multipleenvironmental-protection efforts is the surveyWesternGeco conducted in the Greater PrudhoeBay Unit, Alaska, USA, for BP Exploration Alaska(BPXA) in the winter of 2002 to 2003. The surveywas designed to augment data acquired in the1980s and to improve the image of oil-bearing formations, with a view to identifying new welllocations in an aging field. With improved infilldrilling, BPXA expects to enhance productionand better control natural field-productiondecline. The proposed survey area includednumerous lakes and creeks and two main riverdrainages, the Kuparuk and Sagavanirktok. Also,throughout the survey area, the infrastructure ofthe Prudhoe Bay oil field—flow stations, wellpads, roads and pipelines—presented potentialman-made obstacles. The survey area includedthe community of Deadhorse and its airport. Thesurvey covered 180 sq miles [470 km2] and mobilized a crew of approximately 80 personnel.The crew utilized two fleets of rubber-trackedequipment to minimize environmental impact(next page, middle).

20 Oilfield Review

9. “Effects of Oil and Gas Development Are Accumulatingon Northern Alaska’s Environment and Native Cultures,”a Report by the National Academies: March 5, 2003.http://www4.nationalacademies.org/news.nsf/isbn/0309087376

10. Read T, Thomas J, Meyer H, Wedge M and Wren M:“Environmental Management in the Arctic,” OilfieldReview 5, no. 4 (October 1993): 14–22.

11. A staging area is a piece of ground where the crew prepares equipment before field use. The area can varyin size from 50 by 50 m to 200 by 200 m [164 by 164 ft to656 by 656 ft].

> Caribou coexisting with seismic acquisition vehicles.

Summer 2003 21

With so many vehicles on hand, special caremust be taken to avoid contaminating the snowwith drops or spills of hydrocarbon-based prod-ucts during refueling, maintenance and ordinaryoperation. A vibroseis truck circulates hydraulicoil at pressures of hundreds of bars [thousands ofpsi] to power the vibrator. If a hose breaks, up to150 liters [40 gal] of oil may escape. Today, toavoid any drips from the vehicles, all vehiclescarry absorbent materials that are placed under-neath them when they stop. In the past, any contaminated snow would have been scooped up,contained, and sent along with the contaminatedabsorbent materials by tracked support vehicleor airplane to a disposal facility in the town ofDeadhorse, which is distant from many activeexploration areas.

Today, WesternGeco crews can accumulate all contaminated snow and absorbent materialsat remote field locations and dispose of themusing a specialized waste-disposal and incinera-tion technology. The collected liquids and contaminated snow are drained into a computer-controlled, high-temperature separator. Theextracted water is recycled to launder shop ragsand personnel coveralls. The oil is used to fire anincinerator burner that disposes of waste materials and rubbish from the crew. The onlyremaining waste is ash that is then packaged at the remote site and sent to a proper disposal location.

A tundra-monitoring program has beenimplemented to help understand the complexi-ties of this fragile ecosystem and to develop waysto avoid long-term damage. During recent surveys, specific metrics were put in place tomonitor staging areas, camp sites and camp-move trails.11 Items monitored included drips,spills, trash, drip pads, spilled beverages and tundra impact, all of which were tracked on ascorecard. Additionally, managers were requiredto provide environmental monitoring and feed-back through a remedial workplan for visits tocrew locations. The Alaska EcoSeis programincludes summer over-flying to monitor thelonger term impact of tundra contact. This is per-formed in conjunction with other stakeholders.Monitoring has been instrumental in helpingcrews minimize the footprint of seismic surveys,prevent any potential long-term environmentalimpact and educate stakeholders on theadvances in the way WesternGeco performs surveys in this special environment.

Successful seismic surveys like the Alaskasurvey for BP do not happen easily, but ratherwith planning, training and rigorous attention todetail. WesternGeco worked with BP for almost a

year to plan the acquisition process and environ-mental activities before implementing the plansin 2003. In 2002, the WesternGeco Alaska procedures were audited by Det Norske Veritas(DNV) against the International EnvironmentalRating System (IERS), for which an IERS Level 5is equivalent to the ISO 14001 standard. TheWesternGeco Alaska environmental-manage-ment process received DNV IERS certificationLevel 7, indicating an improvement over existingISO 14001 standards. In addition, the specializedwaste-separation and incineration system wonthe 2002 Commissioner’s Pollution PreventionAward for Outstanding Achievement in WasteReduction, conferred by the Alaska Department of Environmental Conservation. The waste-treatment system also received the Schlumbergerenvironmental excellence award for demonstrat-ing environmental leadership and commitment.

Environmental Awareness—An IndustryResponsibilityFor most communities, the arrival of the seismiccontractor is their first encounter with the E&Pindustry. As such, contractor performance interms of health, safety and environment issues isclosely watched, and becomes the standard forother services that follow as a prospect develops.The geophysical industry takes this responsibilityseriously, and continues to develop technologythat promotes sound management of environ-mental and cultural resources.

The examples in this article highlight methods that WesternGeco has developed in theeffort to leave no footprint. With continued focusfrom the entire E&P community, similar effortsand expectations will become the norm in theindustry. It is through cooperative effort that wewill achieve our multiple goals—preservation ofecosystems and cultural treasures, technicallysuperior solutions and efficient exploration andproduction of resources. —LS

> A rubber-tracked line-deployment vehicle. A crew member known as acable hand deploys seismic cable as the vehicle moves along.

> Two fleets of five vibroseis units each, deployed in the Greater PrudhoeBay Unit for BP Exploration Alaska.

22 Oilfield Review

Watching Rocks Change—MechanicalEarth Modeling

Anwar Husen Akbar AliCairo, Egypt

Tim BrownMarathonOklahoma City, Oklahoma, USA

Roger DelgadoPluspetrolLima, Peru

Don LeeDick PlumbNikolay SmirnovHouston, Texas, USA

Rob MarsdenAbu Dhabi, UAE

Erling Prado-VelardeAl-Khobar, Saudi Arabia

Lee RamseySugar Land, Texas

Dave SpoonerBPAberdeen, Scotland

Terry StoneAbingdon, England

Tim StoufferMarathonMoscow, Russia

For help in preparation of this article, thanks to UsmanAhmed, Karen Glaser and Eduard Siebrits, Sugar Land,Texas, USA; Tom Bratton, Pat Hooyman and Gemma Keaney,Houston, Texas; Jim Brown, BG Tunisia, Tunis, Tunisia; John Cook, Cambridge, England; Juan Pablo Cassenelli,Pluspetrol, Lima, Peru; Marcelo Frydman, Bogatá,Colombia; Alejandro Martin and Julio Palacio, Lima, Peru;Adrian Newton, Gatwick, England; Bill Rau, ChevronTexaco,New Orleans, Louisiana, USA; and Ken Russell and Kate Webb, Aberdeen, Scotland. Thanks also to Pluspetrol,Hunt Oil, SK Corporation and Tecpetrol for their contributionsand release of the Camisea case.APWD (Annular Pressure While Drilling), CMR (CombinableMagnetic Resonance), DrillMAP, DSI (Dipole Shear SonicImager), ECLIPSE, FMI (Fullbore Formation MicroImager),FracCADE, MDT (Modular Formation Dynamics Tester),PowerDrive, PowerSTIM, RFT (Repeat Formation Tester),

UBI (Ultrasonic Borehole Imager) and USI (UltraSonicImager) are marks of Schlumberger.

In many complex drilling, completion and exploitation operations today, failure to

understand a field’s geomechanics represents an expensive risk. Developing a

consistent mechanical earth model can mitigate that risk and provide benefit

throughout the life of the field.

The Earth is a stressful place. The science ofgeomechanics attempts to understand earthstresses, whether they are in a simple subsidingbasin or at the intersection of colliding tectonicplates. A basic model might suffice in the firstcase, but complex tectonic settings and other situations encountered in the exploration anddevelopment of hydrocarbons require increasinglysophisticated geomechanical tools and models.

Stresses on people often lead them to changetheir behavior or personality. Similarly, stressesin the Earth often change its features, sometimescreating conditions for hydrocarbon trapping.Salt diapirism creates traps where porous forma-tions abut impermeable salt; salt movement alsocreates complex stress fields. Tectonic plates col-lide, uplifting formations into mountain ranges,and also form conditions for hydrocarbon accu-mulation. The rapid deposition of sediment inplaces like the Gulf of Mexico generates pressuredifferentials that can result in shallow-water

flows and deeper overpressured zones, both ofwhich are hazards to drilling operations.1

Understanding hazards generated by stressesin the Earth is important for safe and effectivedrilling and drives the development of geome-chanical models. Earth stresses also influenceother aspects of reservoir evaluation and develop-ment. Stress magnitude and orientation affectfracture initiation and propagation. Weakly con-solidated formations may fail into the wellborebecause of compressional stresses at the boreholewall—borehole breakout. Formation compress-ibility can be an important drive mechanism inweak reservoirs; the resulting subsidence candamage surface facilities and pipelines ordecrease the gap between the bottom of an off-shore platform deck and the top of the highestwaves, a potentially hazardous condition.

These few examples illustrate the need for acoherent picture of earth stresses. Unfortunately,data obtained within a geographic area are often

1. Alsos T, Eide A, Astratti D, Pickering S, Benabentos M,Dutta N, Mallick S, Schultz G, den Boer L, Livingstone M,Nickel M, Sønneland L, Schlaf J, Schoepfer P, Sigismondi M,Soldo JC and Strønen LK: “Seismic ApplicationsThroughout the Life of the Reservoir,” Oilfield Review 14,no. 2 (Summer 2002): 48–65.Carré G, Pradié E, Christie A, Delabroy L, Greeson B,Watson G, Fett D, Piedras J, Jenkins R, Schmidt D,Kolstad E, Stimatz G and Taylor G: “High Expectationsfrom Deepwater Wells,” Oilfield Review 14, no. 4 (Winter 2002/2003): 36–51.

2. Andersen MA: Petroleum Research in North Sea Chalk.Stavanger, Norway: RF–Rogaland Research (1995): 142.

3. Andersen, reference 2: 1.

Summer 2003 23

sparse and sometimes may even seem conflict-ing. In addition, stress conditions at a given wellmay differ significantly from conditions at offsetwells. Experts must be able to adjust the stressmodel to fit a specific location.

As complex as the state of stress can be at anyparticular place, drilling a borehole and extract-ing hydrocarbons make this state even morecomplex. Drilling and production activities alterthe local stresses, sometimes to the detriment ofreservoir-exploitation activities. Drilling removesmaterial from a formation, changing the near-well stresses. Drilling over- or underbalanced,respectively, increases or decreases formationpore pressure. These changes can make drillingmore difficult or easier, depending on local con-ditions, and it is important to know in advancewhich outcome is most likely. Increasing pres-sure in a wellbore can alter the local stresses somuch that the rock breaks. This can be good if itis a planned hydraulic fracture or bad if it gener-ates fluid losses while drilling. Productiondecreases pore pressure, which may result inpermeability decrease or formation compaction.These effects of depletion might not bereversible, even if the pore pressure increases asa result of water or gas injection.

Positive or negative results can be predictedmore reliably if the stress state is understood.Monitoring the state of stress while drilling isparticularly important in providing a measure oflocal rather than offset conditions. In addition,there often are gaps in the predrill data that con-tinuous recording of stress conditions can fill.Real-time stress measurement supplies key infor-mation for mitigating drilling risks. These dataare input into a mechanical earth model (MEM).

As implemented by Schlumberger, the MEMis a logical compilation of relevant informationabout earth stresses and rock mechanical properties in an area, a means to update thatinformation rapidly and a plan for using theinformation for drilling operations and reservoirmanagement. An MEM can use input from geo-physical, geological and reservoir-engineeringmodels, but it is not simply a gridded model withattributes assigned to each cell. The criticaladditional aspect an MEM provides is a unifiedview of the rock mechanical properties for agiven area (above).

This article describes construction and use ofMEMs as illustrated by examples from Peru, theNorth Sea, the Gulf of Mexico, Russia, the MiddleEast and Tunisia.

Planning for the Life of a FieldGeomechanics involves predicting and managingrock deformation. Unplanned rock deformationevents cost the industry billions of dollars per year.Lost time due to wellbore instability and tools lostin a borehole leads to higher drilling expendituresand delayed production. When severe, these problems can force a company to sidetrack orabandon a well. Poorly understood geomechanicalconditions may result in suboptimal completionsand ineffectual reservoir stimulations.

Development of the science and practice ofgeomechanics has been driven by industry need.Reservoir compaction and surface subsidencehave been severe in some North Sea chalk reservoirs, notably the Ekofisk field, wherePhillips—now ConocoPhillips—raised platforms6 m [19.7 ft] in 1987. The central portion of thefield had subsided another 6 m by 1994 and several platforms were later replaced.2 Both theValhall—operated by Amoco, now BP—andEkofisk fields have had wellbore-stability prob-lems while drilling and later during production.Starting in 1982, some of the companies involvedin producing North Sea chalk reservoirs joinedwith the Norwegian and Danish petroleum ministries to study chalk geomechanics in aseries of Joint Chalk Research programs.3

> Concept of the mechanical earth model (MEM). The first step in constructing an MEM is to understand the local and regional geology (left). The detailedmechanical stratigraphy provides information about facies types and local deformation mechanisms (middle). From this detailed study come profiles ofelastic and rock-strength parameters including unconfined compressive strength (UCS) (right). These parameters are used to predict pore pressure, Pp,minimum and maximum horizontal stresses, σh and σH, and vertical stress, σV. Determining horizontal stress direction is also important for drilling and completion operations.

Mechanicalstratigraphy

Elastic strengthGeology Earth stress and pore pressure

10

0 1

100Young's modulus, E, MPa

Stress,MPaPoisson's ratio, ν

20 400 0 200 W NDirection of σH

EUCS, MPa

0 70Friction angle,Φ, degrees

Pp σVσHσh

In the early 1990s, BP encountered severewellbore-stability problems in the Cusiana fieldin Colombia.4 Conventional approaches to solvingwellbore-stability problems were ineffective inthis field. A multicompany team of geoscientistsand engineers spent almost a year compiling sufficient geomechanical information to enablethem to improve drilling performance.Experience gained during this project ledSchlumberger experts to develop the concept ofa mechanical earth model.5 An MEM comprisespetrophysical and geomechanical data relatingto the state of a reservoir, its overburden and the nearby bounding layers, and, in addition, aunified understanding of that data.

Several MEM principles originated with theCusiana field study. First, all available datashould be used to develop the geomechanicalmodel of a field. The complexity of any data analysis must be balanced against available timeconstraints and the potential value of informa-tion gained. Three specific types of informationare of key importance: failure mechanisms, stateof stress and rock mechanical properties. Finally,real-time information to update the model, datamanagement and good communications are necessary for successful execution of the drillingprogram using an MEM.

To a great extent, the development of geome-chanics has coincided with the development ofincreasingly sophisticated logging tools, such assonic and imaging logs. An MEM uses these data,correlations to convert from log responses tomechanical properties, core and cuttings data,and information from daily drilling reports andother sources (above). The challenge is to takethe data from all these sources, organize themwithin a computer system, and process and inter-pret them in a timely fashion to effect a positiveeconomic outcome.

A complete MEM is more than the sum of thedata it comprises; it is a unified understanding ofall relevant data. When information is segmentedand kept in separate sets—such as problemsencountered while drilling offset wells in onecategory and seismic results in another, withpressures measured while drilling in yet anotherdata set—models can be incoherent or eveninconsistent. With a unified MEM, rigorous relationships can be applied uniformly, providingeasier access, visualization, real-time updatingand a single point for discussion as new informa-tion flows in from the rig or the production plat-form (see “Components of a Mechanical EarthModel,” page 26).

The degree of detail in an MEM varies fromfield to field, based on operational needs and risks.It may be a simple, one-dimensional set of depthprofiles indicating elastic or elasto-plastic para-meters, rock strength and earth stresses within thecontext of the local stratigraphic section. In a morefully developed model, lateral variations are incorporated to generate a three-dimensional (3D) geophysical framework incorporating a 3Ddescription of mechanical properties.

Of course, any MEM created before drillingwill be based on historical and offset data, so itwill inevitably contain uncertainties and besomewhat out of date as soon as the bit hitsearth. Updating the model while drilling is vitalto reduce uncertainties, achieve proper control

24 Oilfield Review

4. Last N, Plumb RA, Harkness R, Charlez P, Alsen J andMcLean M: “An Integrated Approach to ManagingWellbore Instability in the Cusiana Field, Colombia, South America,” paper SPE 30464, presented at the SPE Annual Technical Conference and Exhibition, Dallas,Texas, USA, October 22-25, 1995. Addis T, Last N, Boulter D, Roca-Ramisa L and Plumb D:“The Quest for Borehole Stability in the Cusiana Field,Colombia,” Oilfield Review 5, no. 2/3 (April/July 1993):33–43.

5. Plumb R, Edwards S, Pidcock G, Lee D and Stacey B:“The Mechanical Earth Model Concept and ItsApplication to High-Risk Well Construction Projects,”paper SPE 59128, presented at the IADC/SPE DrillingConference, New Orleans, Louisiana, USA, February 23–25, 2000.

> Sources of information used to build an MEM.

Property profiled

Mechanical stratigraphy

Pore pressure (Pp)

Overburden stress (σv)

Minimum horizontal stress (σh)

Maximum horizontal stress (σH)

Elastic parameters [Young’smodulus (E), shear modulus (G),Poisson’s ratio (ν)]

Rock-strength parameters[unconfined compressive strength(UCS), friction angle (Φ)]

Failure mechanisms

Source logs

Gamma ray, density, resistivity,sonic compressional velocity (Vp)

Vp, check-shot survey, resistivity

Bulk density

Vp and sonic shear velocity (Vs),wireline stress tool

Borehole images

Vp and Vs, bulk density

Vp and Vs, bulk density,mechanical stratigraphy

Borehole image, orientedmultiarm caliper

Other sources

Cuttings, cavings,sequence stratigraphy

Interval velocity from seismicdata, formation-integrity test,daily drilling reports

Cuttings

Stress direction Oriented multiarm calipers,borehole images, orientedvelocity anisotropy

Structural maps,3D seismic data

Pp , leakoff tests, extendedleakoff tests, microfrac,step-rate injection tests, localor regional database, dailydrilling reports, modeling

Pp , σh, rock strength, database,wellbore stress model

Database, laboratory coretests, cavings

Database, laboratory coretests, cavings

Daily drilling reports, cavings

Summer 2003 25

of the drilling process and obtain superior resultsin subsequent development. An MEM can beupdated using newly acquired informationincluding logging-while-drilling (LWD) and measurements-while-drilling (MWD) data.

Small problems encountered while drillingcan become costly when decisions must be maderapidly based on insufficient and incompleteinformation. With an MEM in place, the team cananticipate potential trouble and check incomingdata for consistency with the model. When problems do occur, the team can make rapid,informed decisions and prevent minor occur-rences from becoming major problems.

Sometimes stress conditions indicate that awellbore should be stable, but field experienceshows it is not. In these cases, an MEM providesguidance for drilling-fluid selection. For example, if the instability is due to sensitive,expandable clays such as smectite, a drillingfluid compatible with this type of formationshould be used. Often, the wellbore instability isassociated with planes of weakness, such as bedding planes or small, centimeter-scale, pre-existing fractures, and a low-fluid-loss drillingfluid with crack-blocking additives is recommended. In some Gulf of Mexico fields, thesafe pressure window is so small that the gelstrength of the drilling fluid must be reduced toavoid fracturing a formation.

The investment in developing an MEM canrepay itself many times during the life of a field(below). Most MEMs to date have been devel-oped during a drilling program, but that is chang-ing as more MEMs are being developed forrecompletion programs.

An actively updated MEM provides a vital toolfor managing the field throughout its life, so datamanagement is a key issue. Many times, opera-tors obtain information for one purpose that canbe useful for a broader understanding of theirasset. Without a single, coherent model, engi-neers may be unaware of important informationthat the company already has, or they may beunaware of the potential value in the informationthey have. Constructing an MEM is an importantstep in extracting that value.

Schlumberger has significant expertise inconstructing and using MEMs. The company provides geomechanics expertise worldwide,with centers at Houston, Texas, USA; Gatwickand Cambridge, England; Kuala Lumpur,Malaysia; and Abu Dhabi, UAE. New technologybeing developed by Schlumberger in Abingdon,England, couples 3D stress calculations with the ECLIPSE reservoir simulator. WithinSchlumberger, an organized geomechanics com-munity shares knowledge through meetings andbulletin boards, ensuring that best practicesspread quickly throughout the company.

Auditing Camisea Data The first step in constructing an MEM is to orga-nize available information through a data audit.This is more than a tabulation of quantitative andqualitative information; the audit team seeksunderstanding of potential problems in drillingfuture wells or other activities. A team collectsinformation relating not only to a reservoir butalso to formations above, below and beside it.Such supplementary information may be difficultto find, because many data-acquisition programsfocus only on logging productive formations.

Much of the information in a data auditcomes from past drilling and production experiences. A data audit proceeds throughdefined steps:

1. Define target area.2. Gather geological, geophysical and

petrophysical data associated with the target area.

3. Review drilling, completion and productiondata from offset wells, starting with thoseclosest to the area of interest and addingrelevant information from other wells farther away.

4. Review this data to determine the nature ofany previous drilling, completion or produc-tion problems and their probable cause.

5. Determine the need for additional data toconstruct an MEM.

6. Summarize the results.

> Value of MEM for life-of-field activities. The bars indicate the usefulness of an MEM for determiningthe indicated properties or performing the indicated activities during different stages of oilfield activities.

Exploration Delineation Development ExploitationEnhancedRecovery

Pore pressureFractured reservoirsWellbore stabilityWell placementCasing pointDrill-bit selectionDrilling fluidCompaction and subsidenceCompletion methodSand controlDrilling wasteMultilateral designHorizontal wellsReservoir stimulationEnhanced recoveryDiagnosis of failures

26 Oilfield Review

Schlumberger spent several years develop-ing a process for constructing a mechanicalearth model (MEM). Although the detailsvary depending on the availability of dataand specific business needs for a given situa-tion, the methodology carries across a varietyof instances.

The first step in the method is to accumu-late and audit available data. All the relevantinformation is combined into a consistentframework, the MEM, that allows prediction ofgeomechanical properties—such as stresses,pore pressure and rock strength.

Some stress components in a formationcan be measured directly, and others can bederived from known quantities, but somemust be estimated based on correlations(above right). Core tests determine theunconfined compressive strength (UCS) andsome other quantities, such as friction angleand Poisson’s ratio, ν.1

Vertical stress, σV, is often obtained by inte-grating the density through the overburden.In some cases, shallow formations are notlogged, so an exponential extrapolation of ver-tical stress sometimes is used to model theunlogged region.

The pore pressure, Pp, and minimumhorizontal stress, σh, can be determined fromformation-integrity tests (FITs) and minifracs,such as those obtained using an MDT ModularFormation Dynamics Tester tool in a dual-packer stress-test configuration. Measurementsof these quantities at specific points calibratelog correlations throughout the formations.

Stress models, such as the Mohr-Coulombmodel, are often used to relate σh to Pp, σV,and the internal friction angle. Other correla-tions also can be used, but they require addi-tional input parameters that are oftendifficult to obtain. The internal friction anglecan be correlated to clay content obtainedfrom logs.

The maximum horizontal stress, σH, cannotbe determined directly, so clues must be eval-uated to determine the best correlationwithin a chosen stress model. Informationrelating to constraints on σH includes thepresence or absence of borehole breakouts,minifrac measurements, rock strength andlocal or regional databases.

The direction of σH is important for well-bore-stability determination and for fractureorientation. Seismic data provide informationabout regional stress direction by indicatingtensile and compressional faults and featuresrelated to those earth stresses. However, prox-imity to such faults and major features—suchas the Andes Mountains—may alter both themagnitude and direction of local stresses,even if forming such a feature did not alterthe regional stress.2 A local measure of stressdirection is often needed to supplement theregional information. Faults and natural frac-tures can be interpreted from UBI UltrasonicBorehole Imager data.

By recording data in crossed-dipole mode, aDSI Dipole Shear Sonic Imager tool indicatesthe direction of σH. Shear waves travelingthrough a formation split between fast-travel-ing waves moving along the stiffer σH directionand slower waves along the more compliant σh

direction. The data also provide a measure ofthe azimuthal stress anisotropy.

Young’s modulus can be determined fromcompressional and shear velocities recordedby acoustic logs. However, there is a differ-ence between this dynamic Young’s modulusand the static Young’s modulus in a test oncore material.3 To use this information toobtain rock strength, commonly in the form ofthe UCS, two correlations are used. First isthe conversion from dynamic modulus tostatic modulus, then the transformation fromstatic modulus to UCS.

Tensile strength, T, in most formations isassumed to be about one tenth of the com-pressive strength. In some situations, such asopening a preexisting fracture, the tensilestrength of the rock body is zero.

These mechanical properties are usefulfor drilling, completion and production activ-ities. One important question in drillingthat the MEM answers is the range of mudweights that can be used safely without dam-aging a formation.

A formation shears at the borehole wall ifthe wellbore pressure drops below the forma-tion breakout pressure (next page, top). Thegradient of breakout pressure is determinedfrom Pp, σH, σh, T and ν. The breakout gradi-ent typically defines the minimum mudweight for safe drilling.

The maximum mud weight for safe drillingis usually obtained from the fracture gradient.This maximum mud weight is one that creates aborehole pressure that exceeds the sum of theformation tensile strength and the tangentialstress at the borehole wall (next page, bottom).

Components of a Mechanical Earth Model

> Stress state. The vertical stress, σV, is nor-mally obtained by integrating a density logfrom the surface. The minimum horizontalstress, σh, can be obtained from minifracs, andthe pore pressure, Pp, from an MDT ModularFormation Dynamics Tester measurement. Themaximum horizontal stress, σH, must beobtained from correlations to logs.

σV –density logs

σh –minifracs

σH –correlation

Pp –MDT measurement

Summer 2003 27

A safe drilling window is the range of mudweights between the breakout pressure andthe fracture pressure, including a safety fac-tor when possible. Combining the breakoutand fracture gradients with the direction ofmaximum horizontal stress provides a keyinput for stability of deviated and horizontalwells. The most stable direction is usuallyalong the minimum horizontal stress direction.

With the stress gradients and formationproperties defined, the MEM is ready forgeomechanics experts to use to make predic-tions. A DrillMAP drilling management andprocess software plan, developed from theMEM, indicates the locations and types ofexpected risks, along with a means to miti-gate those risks. New information can becompared with predictions from the MEM.Anomalies between the new information andthe model provide opportunitiesfor improving the model and ultimately forimproving understanding of the field.

1. Unconfined compressive strength is the maximumvalue of axial compressive stress that a material canwithstand, under the condition of no confining stress.

2. For mathematical details of stress changes nearfaults: Jaeger JC and Cook NGW: Fundamentals ofRock Mechanics. London, England: Chapman and Hall,Ltd. and Science Paperbacks (1971): 400–434.

3. A dynamic modulus is derived from a traveling acous-tic wave with a frequency of a few kilohertz, perturb-ing the material at a constant stress. A static modulusis derived from laboratory tests performed atextremely low rates of stress change, but over a muchlarger stress range.

> Stress direction and borehole damage. Drilling-induced fractures can occuralong the maximum horizontal stress direction if the mud weight is too high.Borehole breakouts can occur in the minimum stress direction when the mudweight is too low.

Maximumhorizontalstress (σH)

Borehole breakout

Drilling-inducedfractures

σh

Borehole

Minimum horizontalstress (σh)

σH

> Schematic of breakout and fracturing gradients. The equivalent static den-sity (ESD) is greater than the mud weight (MW), due to cuttings in the mud andmud compressibility. The equivalent circulating density (ECD) also includesdynamic effects. Both ESD and ECD should stay within the safe window(green on bar). The illustrations indicate the type of failure possible withineach stress regime (top). The middle condition is a stable borehole. Moving tomud weights less than the minimum ESD (left), the formation can break outinto the wellbore in shear failure; if it drops below the pore pressure, well con-trol can be lost, a severe condition. At mud weights greater than the stablerange (right), ECD could exceed the minimum horizontal stress, generatingtensile damage in the formation; if it exceeds the fracture pressure, a fracturecan propagate into the formation.

MW

Porepressure

MinimumESD

Minimumhorizontal

stress

Fracturepressure

ECDESD

A data audit is primarily a data review andsummary, but it also identifies gaps in informa-tion needed to prepare an MEM. Missing datacan be highlighted and prioritized for collectionin the next drilling or data-collection program.

In many cases, consolidating information intoa 3D graphical format is the best way to appreci-ate the amount and quality of data available.Geophysical and geological interpretations,including locations of faults and formation tops,can be combined with qualitative or quantitativeinformation obtained from drilling reports andmud-log data. Problem zones and geologic eventlocations are easier to correlate when both typesof information are combined into one 3D display.

Predrill data—When Pluspetrol and its part-ners Hunt Oil Company, Tecpetrol and SKCorporation received rights to the Camisea blockin the Peruvian Andes, they also obtained a largequantity of information from another companythat had explored in the block previously (belowleft). Because the target in this block along theSan Martin anticline lies atop an environmen-tally sensitive rain forest, the partners had to useexisting development locations, or pads, on thesurface. New trajectories would be deviated toreach targets from these pads.

The earlier wells had been difficult to drill,with severe wellbore-instability and lost-circula-tion problems. Wells took 60 to 120 days to drilland complete because of stuck-pipe incidents,delays caused by LWD tools lost in the hole andthe need to drill sidetracks.

Pluspetrol asked Schlumberger to complete adata audit for the prospects in the block.Pluspetrol provided 40 compact discs (CDs) containing a wide variety of data from previouswells (below right). Wireline logs cover most ofthe depth range, although there is scant log coverage from surface to about 1700 m [5600 ft](next page, top).

Drilling data from the CDs were classified bytype of drilling event or problem:• Act of God: for example, the rig being shut

down because of torrential rains, electricalthunderstorms or small earthquakes

• Bit and bottomhole assembly (BHA): for exam-ple, low rate of penetration and undesired buildor drop tendencies

• Equipment: events relating to rig-equipmentperformance, for example, pump or topdrivefailures

• Hole cleaning • Kicks and influx, including gas influx into

drilling mud

28 Oilfield Review

> Camisea prospect, Peru. The Camisea prospect is located in the Andes Mountains (top). The welltrajectories for most of the wells in the drilling program were directionally drilled from a few pads tominimize ecological impact at the surface (bottom).

+1000

Sealevel

-1000

Dept

h, m

-2000

SE NW

SM-1004

13 3⁄8-in.

11 3⁄4-in.

9 5⁄8-in.

VivianBasal ChontaUpper NiaLower Nia (fluvial)Lower Nia (eolian)ShinaiUpper NoiLower NoiEneCopacabana

SOUTH AMERICA

PERU

Camisea prospect

An

de

sM

o u n t a i n s

9 5⁄8-in.

> Camisea information ranked by class and type.The qualitative ranking indicates the value ofexisting data for drilling planning. Rank 1 infor-mation is of sufficient quality and depth coverageto meet drilling-planning objectives. Rank 3 indi-cates that significant gaps exist in the type andcoverage of data; Rank 2 is of intermediate value.

Class Type Ranking

Regional Tectonic settingRegional structureBasin history

112

Drilling Daily drilling reportsEnd-of-well reportsMud logsBit recordsBottomhole-assembly recordsWell surveys

21222

1

Geology Structure mapsSeismic interpretationsWell-location mapsFormation topsLithologic descriptionsCore descriptionsGeological studiesFormation pressures

12113222

Geophysical Seismic linesCheck-shot surveysWireline logs

123

Summer 2003 29

• Downhole mud losses, typically losses greaterthan 10 bbl [1.6 m3] per incident

• Leakoff or formation-integrity tests • Stuck-pipe incidents• Tight-hole and wellbore-stability problems,

including excessive backreaming, reamingwhile tight in hole or packoffs.

The analysis indicated that tight hole andwellbore-stability problems caused more than athird of the events and occupied 36% of the non-productive time. Other major causes of drillingproblems included bit and BHA, equipment andstuck-pipe events.

Stresses—With the drilling events identified,the audit team began evaluating the stress condi-tions. The direction of the local maximum hori-zontal stress is NNE. This is almost orthogonal tothe regional stresses that created the Andesmountain range. These regional stresses upliftedthe mountains and altered the texture of therocks, for example by generating fractures. Thisconclusion from the audit pointed to an importantquestion that needed to be resolved: Is wellboredeformation dominated by local stresses or byeffects the regional tectonics had in creating therock structure? This question was answered laterusing data obtained while drilling the first well.

Geologic information was put into a 3D visu-alization model. This model demonstrated thethrust and fold structure in the formation tops ofthe overburden (right). The audit for Camiseaunderscored the importance of understandingthe state of stress throughout the depositionalhistory. It indicated that there was a periodsometime between reservoir deposition and thepresent when both maximum and minimum hor-izontal stresses exceeded the vertical stress.These intense compressive paleostresses gener-ated evidence such as fractures that were pre-sent in the geologic record.6

Fractures in cores taken from nearby wellsprovided information on the stress state. Thepresence of low-angle shear fractures that areparallel to bedding is consistent with concentricfolding, so those fractures probably developedduring regional tectonic folding. However, theNoi and Nia formations contain normal shearfractures, so locally the maximum paleostresswas vertical when the fractures were formed.This must have occurred after initial foldingabsorbed some of the tectonic compression andcaused the principal stresses to rotate.Furthermore, tensile fractures instead of normalshear fractures present in the uppermost, com-petent Vivian formation indicate that furtherfolding and stretching must have increased

the deviatoric stresses.7 The folding of a thick,underlying, competent formation, possibly theCopacabana, created a concentric folding of thereservoir formations. The resultant movementprobably relieved some of the horizontal stress in

the Camisea block. Today, the vertical stress isthe maximum principal stress.

Risks—The final stage of the data audit wasto predict potential drilling risks. Most stuck-pipe events had occurred in deviated boreholes,

6. Paleostress indicates the stress state at the time ofdeposition or some other time before the present.

> Montage of available well-log data. These logs from 12 offset wells indicate gamma ray (green) andcaliper (black) in the first track of each set; resistivity (red and black) in Track 2; and sonic (green),neutron porosity (blue) and density (red) in the third track. The blue bands to the right of Track 1—inwell logs 1, 2, 3, 4 and 12—show where FMI Fullbore Formation MicroImager data are available. Thered bands to the left of Track 2—in well logs 3, 5 and 12—show depths at which USI UltraSonicImager or UBI Ultrasonic Borehole Imager data are available. The logs are aligned by depth.

1 2 3 4 5 6 7 8 9 10 11 12

> Eastward view through the Camisea San Martin anticline and thrust-fault system. The folds in thetop of the Noi and Ene formations (white surface) indicate regional deformation from compressivestresses. The other colored surfaces show fault locations. The trajectories of previously drilled wells(black) start at the surface of the Earth at the well location, and a white dash on the trajectory indi-cates sea level. The maximum horizontal stress direction is NNE (inset).

W

N

N

σH

σh

7. Deviatoric stress is a measure of the differencesbetween principal stresses.

which was significant because the planned boreholes would be deviated. However, previouswells with stuck-pipe problems were deviatedinto a direction almost parallel to the strike ofthe San Martin anticline, while the proposedwells would strike in directions either oblique ororthogonal to the anticlinal trend (above).

The proposed Camisea wells potentiallywould have more drilling risks than the previouswells. Pluspetrol authorized Schlumberger toconstruct an MEM for the Camisea prospects.This MEM included a DrillMAP plan that provided a forecast of probable risks—ranked for each drilling section—and their impact on drilling.8

Monte Carlo modeling helped identify thepotential variability in some of the quantitiesthat were poorly constrained by data from earlierwells. For example, modeling showed that theunconfined compressive strength (UCS) had thegreatest impact on predicting shear failure, butmeasurements of UCS were not in the auditeddata. After evaluating this Monte Carlo result,Pluspetrol determined UCS from tests on corefrom a previously drilled well.

A Schlumberger No Drilling Surprises (NDS)team and Pluspetrol used the MEM and DrillMAPresults to create a drilling plan.9 To improve bore-hole cleaning, Pluspetrol upgraded the drillmotor to a PowerDrive rotary steerable system.10

The team monitored drilling performance usingLWD and MWD systems.

Drilling—The NDS team updated the MEMand DrillMAP plans while drilling the first well inthe block, filling in data where the data audit indi-cated gaps. Information gathered while drilling thiswell confirmed the stress directions. The drillingdata from the new well provided the answer to thequestion about the influence of current localstresses and paleostresses. Borehole image analysisof breakouts showed that local stresses, rather thanremnant texture due to regional tectonics, domi-nated wellbore deformation.

The previously predicted stress magnitudeswere close to the while-drilling observations inthe reservoir, but the model had to be adjusted inthe overburden, where minimal predrill data hadbeen available (next page, top).

The operator’s first well was completed in82 days without incident, five days fewer thanplanned. Pluspetrol was pleased with the results

of using the No Drilling Surprises approach, andcontinued working with Schlumberger on additional wells.

Drilling on the second well proceededuneventfully through the reactive clays in thelower Red Beds and casing was set successfully.The bit got stuck in a lower section, so the wellwas sidetracked to achieve total depth, which wasreached only three days behind schedule becauseof the preplanning provided with the MEM.

While drilling the third well, the NDS teamobserved an unusual formation-integrity test(FIT). This test, usually performed after settingand drilling through a casing shoe, provides a calibration for minimum horizontal stress. TheFIT behavior in the first pressure cycle was normal, but a second cycle had an abnormallyrapid pressure decline. To confirm a hypothesisthat the behavior was caused by natural frac-tures, the team modeled the FIT result in a frac-ture simulator using parameters available in theMEM. Understanding this phenomenon providedan explanation of losses that had occurred whilecementing and helped reduce the risk of lost cir-culation in deeper sections.

30 Oilfield Review

> Drilling-trajectory risk map. Drilling risk changes according to the orientation of a wellbore relative to the major stresses and incidence angle of the tra-jectory to bedding. The five trajectories show (1) a vertical well through the reservoir crest, (2) a flank near-vertical well penetrating the formation roughlyperpendicular to bedding, (3) a near-vertical well intersecting bedding planes at an angle, (4) deviated wells trending downdip parallel to bedding and (5)highly deviated wells at an oblique angle to bedding dip (middle). Drilling difficulty can be represented schematically through a drilling-difficulty diagram(left). The larger the lobe, the more difficult it is to drill in that direction. For example, Trajectory 1 is relatively easy to drill, and being vertical, shows nopreferential direction of difficulty. However, Trajectory 5 is very difficult to drill in the σH direction. Elsewhere in the Andean foothills, Trajectories 4 and 5have been the most difficult to drill. Wells in Camisea oblique to the anticlinal trend are similar to Trajectory 4. A color-coded trajectory-risk map can becreated for each horizon (right). This map for the Shinai formation indicates that it is easier to drill near-vertical wells (blue), and that it is hardest to drillalong σH at high inclination (red). Moderate-difficulty drilling is represented in yellow. Similar maps were made for other horizons. The trajectory throughthe Shinai formation for SM1001 was in an easy direction, while SM1002 and SM1004 were more difficult. Generally, increased mud weight is needed tocontrol wells that are drilled in the more difficult directions.

0.95

1.00

1.05

1.20

1.10

1.15

1.35

1.25

1.30

1.40

1.45

00

10

20

30

40

50

60

70

80

90

10 20 30 40Azimuth, degrees

Incl

inat

ion,

deg

rees

Vertical

Horizontal

Mor

e di

fficu

lt

Drillingdifficulty

50 60 70 80 90

SM1004

SM1002

SM1001

σH σh

2

4

5

31

σH

σh3

4

5

1 2

8. For more on the DrillMAP plan: Bratton T, Edwards S,Fuller J, Murphy L, Goraya S, Harrold T, Holt J, Lechner J,Nicholson H, Standifird W and Wright B: “AvoidingDrilling Problems,” Oilfield Review 13, no. 2 (Summer 2001): 32–51.

9. For more on the No Drilling Surprises initiative: Bratton,reference 8.

10. For more on rotary steerable drilling: Downton G,Hendricks A, Klausen TS and Pafitis D: “New Directionsin Rotary Steerable Drilling,” Oilfield Review 12, no. 1(Spring 2000): 18–29.

Summer 2003 31

The first two wells indicated that carefuldrilling practices were required in the 81⁄2-inchsection through the Shinai formation. The MEMprovided guidelines for drilling, and no problemswere encountered.

Pluspetrol valued the preplanning and theability to make informed decisions quickly. Closecommunications among team members gaveSchlumberger and Pluspetrol the capability toimmediately incorporate new information andlessons learned into the work plan.

Modeling Local Stresses in Mirren FieldRegional stresses provide a useful starting pointfor estimating stresses in many basins. However,major structures can affect local stresses near afield or well. For example, mountain ranges thatwere formed by compressive stresses long agohave an effect on present-day stresses nearby.Mountains can distort local stresses so much thatnone of the principal stresses are vertical, andthey can rotate horizontal stresses away from theregional orientation.

Faults and fracture zones also can affect alocal stress field. Movement along a fault relievesstress locally, particularly shear stress across thefault, while the regional stress far from the faultmay not be significantly altered.

To understand the effects of local distortionon present-day stresses, it is sometimes neces-sary to create a geomechanical simulationmodel. One case requiring such a simulation isMirren field, located about 200 km [125 miles]east of Aberdeen, Scotland, in the North Sea. Thefield is connected by subsea tiebacks to theNorth Sea ETAP (Eastern Trough Area Project)platform. The reservoir sands are tucked beneatha salt diapir (right).

The operator, BP, had data from an explo-ration well and a sidetrack, but the informationwas insufficient to develop a reliable stress profile for drilling or for completion planning.The properties from this well and its sidetrackwere used to calibrate a numerical model.

The diapir in the Mirren field is almost symmetric in vertical cross section, and therewas no indication of local structural anisotropy,so the team developed a radially symmetric

> Updating stresses while drilling. The minimum horizontal stress, σh, prediction before drilling wasvalid in the regions where data coverage from offset wells was good, deeper than about 1700 m [5600 ft].The leakoff test (LOT) at the higher casing shoe, about 1000 m [3280 ft], indicated that σh was higherthan predicted. The model was corrected while drilling to incorporate this result. The backgroundillustration shows a LOT at a casing shoe.

Equi

vale

nt m

ud w

eigh

t, lb

m/g

al

0 500 1000True vertical depth, m

1500 2000 2500

18

16

14

12

10

8

6

4

2

0

σh predictedσh from LOT

UK

Mirrenfield

NORWAY

N o r t h

Se

a0

1000

NW SE

2000

Dept

h, m

3000

Top salt

Ter 1

Ter 2Ter 3

Ter 4

Ter 5

Sele

Ekofisk

Seabed

> Location and stratigraphy (top) of the Mirren field in the North Sea. A salt diapir created the Mirrenfield, with hydrocarbon accumulations in the Sele formation. Formation properties and calibration datawere obtained from the previously drilled exploration well and its sidetrack (blue).

model of the diapir and field. Far-field stresseswere derived from a Mohr-Coulomb model. Sincesalt is highly plastic and does not sustain shearstresses, the stress condition was hydrostaticwithin the salt.

Formation properties were taken from theexisting well logs. Overburden stress came fromdensity logs; the minimum principal stress,which was not necessarily horizontal, was cali-brated using leakoff tests (LOTs). Calculationsfrom a finite-element model provided the princi-pal stress directions and magnitudes around thediapir. Caliper data gave further confirmation ofthese principal stresses.

Once the model was calibrated, the resultingproperties were rotated around the axis of sym-metry to create a 3D model. The model revealedareas of high deviatoric stresses—where theminimum and maximum stresses differ greatly—adjacent to the salt diapir. Drilling in those areaswould require high mud weights to avoid bore-hole instability. However, in that same area nearthe diapir, the modeled fracture pressure waslow, requiring low mud weights. Since the mudweight could not be simultaneously high and low,the chosen well trajectory avoided these problemareas next to the diapir (right).

Properties along each selected trajectory weretaken from the 3D model. This information pro-vided wellbore-stability and sanding projectionsthat were used to drill new wells and to plan completions that would minimize solids produc-tion. Two wells in Mirren field were drilled andcompleted successfully with information from themodel; production began in November 2002.

Managing Drilling Tolerances in thePetronius FieldIn addition to providing input for simulation mod-eling, an MEM is useful in predrilling assessment.A predrill MEM provides the drilling team with adrilling plan that includes a forewarning of haz-ards. Verifying stresses in real time allows a teamto refine the MEM and the drilling plan whiledrilling progresses. Real-time monitoring can bevital to the success of a well, particularly whenthe safe drilling window is extremely narrow.

Pore pressure and horizontal stresses arepredicted ahead of the bit based on sonic andresistivity log correlations developed for a field’sMEM. With a narrow drilling window, these quantities must be updated continuously to avoidmoving out of the safe window. In addition, themud density within the openhole section has tobe monitored.

Mud density is not the same at the surface asit is at the bit, and the bottomhole densitychanges even more when the mud is circulating.The equivalent static density (ESD) of the mudat the BHA differs from the surface mud weightbecause of suspended solids and mud compress-ibility. Mud properties aside, the primary influ-ences on fluctuations in the equivalent

circulating density (ECD) are hole size, BHA anddrillstring configuration, pipe movements andtripping speed, rate of penetration, and pumpingrates and pressures.

Equivalent density can be measured around aBHA using an APWD Annular Pressure WhileDrilling tool. The ECD is transmitted to surfacein real time. The ESD is recorded downhole while

32 Oilfield Review

> Modeling results around the Mirren salt diapir. A zone of high stress contrast hugs the bottom of thesalt diapir [dark purple and orange zones (top)], and the fracture pressure is also low in this area [lightand dark purple zones (bottom)]. A well trajectory (green) was selected to avoid this problem area.

0

1000

0 1000 2000 3000Offset, m

Stress Contrast

Fracture Pressure

4000 5000 6000

0 1000 2000 3000Offset, m

4000 5000 6000

2000

Dept

h, m

3000

4000

0

1000

2000

Dept

h, m

3000

4000

0 to 1 MPa

20 to 30 MPa >40 MPa Surfaces30 to 40 MPa

1 to 2 MPa 2 to 5 MPa 5 to 10 MPa 10 to 20 MPa

0 to 1 MPa

20 to 30 MPa >40 MPa Surfaces30 to 40 MPa

1 to 2 MPa 2 to 5 MPa 5 to 10 MPa 10 to 20 MPa

Summer 2003 33

the mud is not circulating, and the minimum andmaximum ESD values are transmitted as soon acirculation begins again. When the safedrilling—or mud-weight—window becomessmaller than the difference between ESD andECD, normal drilling operations are likely tocause either fracturing or breakouts, or, in somecases, both types of failure in the same wellbore.

The importance of maintaining a safe mud-weight window was seen during predrill planningof wells in the Petronius field. The platform forthe Petronius field is at the boundary of shelf anddeep waters in the Gulf of Mexico Viosca Knollarea. The operator, ChevronTexaco, began development in 2000, and planned to drill threeextended-reach wells with up to 19,000 ft[5800 m] of horizontal displacement.11

Seabed depth changes rapidly near the platform (above). The water depth at the plat-form is 1750 ft [533 m], but the north end of thereservoir is under only 700 ft [213 m] of waterand the south end is under almost 3200 ft[975 m]. This extreme change of water depth,

with its accompanying change in overburdenstress, had to be considered when designingthese extended-reach wells.

Drilling problems had been encountered inearlier wells with less lateral extent than thethree planned wells. The earlier wells had prob-lems with hole cleaning, excessive circulationtime, tight hole, packoffs and tools lost-in-hole.These problems became worse with greater wellinclination because the safe mud-weight windowbecame narrower.

ChevronTexaco set several goals for drillingthese extended-reach wells. The companywanted to avoid well problems, specifically stuckpipe and the high pulls associated with stickingpipe, lost tools and lost circulation. The drillingprogram called for a high mud weight to avoidbreakout in an upper section, then setting the95⁄8-in. casing past this unstable zone. With casingset, the mud weight was reduced to avoid lost cir-culation due to a lower fracture gradient in thenext zone. It was imperative to monitor ECD andESD while drilling and keep them within safelimits at all times.

Mechanical earth model—Planning theseextended-reach wells in Petronius field requiredconstruction of a 3D MEM to integrate existingdata and to model missing information. Dipmeterand FMI Fullbore Formation MicroImager logsidentified unconformities and faults, which wereused to establish stress directions.

Ordinarily, the vertical stress due to the weightof the overburden is determined by integratingthe density of the overlying formations. AtPetronius, the steeply dipping seabed compli-cated this approach. The No Drilling Surprisesteam created a 3D model of the reservoir toaccount for the varying water depth and resultinglateral stress change. Density logs from offsetwells had not covered the complete depth inter-val, so the data were extrapolated to the seabed.A 3D seismic velocity survey provided informa-tion for a 3D density cube, with quality controlfrom a sonic log. The dipping seabed causedmore than a 1-lbm/gal [0.12-g/cm3] difference in the predicted overburden stress gradient atthe end of the well trajectory, compared with avertical well of the same total depth.

Input data for the MEM came from predrilldata. A complete petrophysical analysis estab-lished the mineralogy of the formations and therock properties. A 3D seismic cube providedinput for a pore-pressure prediction. Formationbreakdown tests in offset wells gave minimumhorizontal stress in the shales and constrainedthe maximum horizontal stress. MDT and RFTRepeat Formation Tester pressure measure-ments and leakoff tests calibrated these profiles.

The team extracted a wellbore-stability prediction along the specified well trajectoryfrom the MEM. A stable mud window betweenthe mud weight needed to prevent initiation ofbreakouts and the minimum horizontal stresswas less than 1 lbm/gal. The predicted differencebetween ESD and ECD was greater than this, sosome wellbore damage would likely occur.

The team decided that limited breakoutswere easier to manage than formation fracturing,so they set a less restrictive limit on the low sideof the mud-weight window. Given the boreholesize and drillstring design, the MEM helpeddetermine the maximum magnitude of failurethat could be handled by the rig hydraulics witha minimum probability of losing the well. Theteam determined that borehole breakouts con-tained within an angle of 60° could occur without

11. For information on the Petronius field contained in thissection: Smirnov NY, Tomlinson JC, Brady SD and Rau WE III: “Advanced Modeling Techniques with Real-Time Updating and Managing the Parameters forEffective Drilling,” paper presented at the XIV DeepOffshore Technology Conference and Exhibition, New Orleans, Louisiana, USA, November 12–15, 2002.

> Location (top) and well trajectories (bottom) for the Petronius field, Gulf of Mexico. The seabeddepth changes significantly above the Petronius field.

TexasLouisiana

Mississippi

Petronius field

Alabama

Florida

Georgia

G u l f o f M e x i c o

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10,000

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6000

Dept

h, ft

–20,000 –15,000 –10,000 –5000

PlatformN S

0Offset, ft

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Seabed

impacting borehole cleaning and well integrity,so this was the design criterion for the mudweight (above). However, the conditions had tobe monitored carefully. Once borehole-wall fail-ure initiated, there was no way to predict howthe breakout would behave. Failure would likelyworsen with time as the stress conditionremained outside the safe condition. The ECDand ESD were monitored carefully while drilling.

A model of the drilling mechanics indicatedthat a PowerDrive PD900 rotary steerable systemimproved borehole cleaning and permitted flowwith less pressure drop in the tool than a downhole drilling motor. The wellbore-stabilityanalysis predicted the ECD and annular

velocities necessary to optimize hole cleaning. Acomplete drillstring stress analysis establishedoperating limits to avoid failure and eliminatepotential downtime.12

The lessons learned and good practices discovered during predrill preparations werecaptured in the MEM database. Using root-causeanalysis, the team developed preventive andremedial actions for potential events.

Drilling—With a plan in place, drillingbegan in 2002. Engineers at the rig site continu-ously monitored drilling operations and real-timelogging, including gamma ray, resistivity, sonic,density and neutron porosity logs. A multidisci-plinary team onshore gave 24-hour support.

Borehole cleaning was critical. The ECD issensitive to borehole condition, and, in this case,the margin between collapsing and fracturingthe formation was narrow. Stress calibrationrequired monitoring of ECD to within 0.1 lbm/gal[0.012 g/cm3], as well as calibrations of the pre-dicted gradients from formation-integrity, leakoffand extended leakoff tests. Conventional holecleaning by bottoms-up circulation to surfaceyielded few cavings from breakouts. However, by logging the drilling mechanics conditions—such as torque and drag—the likelihood of generating cavings larger than drilling cuttingswas monitored.

34 Oilfield Review

> Use of breakout analysis to set minimum mud weight. The wellbore-stability analysis (Track 2) indicates that the minimum mud weight to prevent breakoutinitiation, MW0 (green), does not have sufficient separation from the minimum horizontal stress, σh (gold). The No Drilling Surprises team analyzed drillingdynamics and decided the borehole could be kept clean with breakouts up to an angle of α=60º (right). Using this MW60 criterion (red), the locations ofexpected borehole failures were predicted (Track 3). In Track 2, a leakoff test (LOT) confirmed the correlation for σh. The overburden stress gradient is onthe right (magenta). Track 1 shows a petrophysical analysis of the formations.

σh σh

σH

σH

Potential fractures

Zones of shearfailure (breakout)

α α

α–breakout angle

Mea

sure

d de

pth,

ft10

00 ft

LOT

LOT

Lithology

Total Porosity

Bound Water

Overburden Gradient Borehole Circumference0° 360°

Sand

Illite

Minimum Horizontal Stress

Mud Weight, α=60°

Mud Weight, α=0°

Pore Pressure

1 lbm/gal/divisionStress Gradients

Breakout Prediction

Summer 2003 35

Special hole-cleaning and tripping proce-dures provided a mechanical action to removelarger cavings. Circulation time was increasedbefore pulling the drillpipe out of the boreholewhen drilling reached the casing-shoe depth, theborehole bottom and at certain critical inclina-tion angles. Caving material reached the shaleshakers after several full circulations, when normal drilling cuttings were no longer cyclingonto the shakers, and cavings continued to makeit to surface for several hours.

The acceptable mud-weight window was sonarrow that the possibility of fracturing the for-mation remained. The drilling team saw someborehole ballooning followed by mud losses.Fractures in this interval were located by analyz-ing time-lapse MWD resistivity logs acquiredwhile drilling and again while pulling out of theborehole.13 The drilling team treated the frac-tures with loss-control material and lowered themud weight to an acceptable level based on thereal-time MEM.

Analysis indicated minimum horizontal stressgradient in the sand bodies was 0.3 lbm/gal[0.035 g/cm3] less than that of the shales, so themodel was updated to account for this lithologicdifference in strength properties.

Full-time monitoring of the wells, coupledwith an MEM that allowed an understanding of unwanted events, resulted in three wells successfully reaching total depth. There were nostuck-pipe incidents, tools lost-in-hole or side-tracks. The minor fluid losses encountered weremanaged successfully. All targets were reached;all the casing strings landed at the planneddepth. On average, the total time savings on constructing these three wells was 15%.Considering only the time spent drilling, the savings was about 45% compared with thePetronius predrill plan.

Controlling Sand Production The MEM also plays a role in controlling sand production that is often seen in weak and uncon-solidated formations. Sand moving in the flowstream erodes tubulars and can damage surfaceand subsurface equipment. Preventing sand pro-duction at the formation face is often the bestapproach to minimize this damage, using eitheroriented perforating or screenless completions.14

In some situations, indirect vertical fracturing(IVF) provides sand control by perforating into acompetent zone and fracturing into an adjacent,less competent productive zone.15 The properapplication of IVF requires a detailed understand-ing of formation lithology and geomechanicalproperties, which can be obtained from an MEM.

In 2000, operator Sakhalin Energy InvestmentCompany applied the IVF technique in thePiltun-Astokhskoye field, located about 12 km[7 miles] northeast of Sakhalin Island, Russia(above).16 Wells in the field are prone to sand pro-duction from poorly consolidated pay zones.

Wells had been completed using frac-packand high-rate water-pack (HRWP) treatments.17

After treatment, the wells had a high positiveskin.18 The operator tried IVF to test whether theformation itself could control sand production,working with Schlumberger to examine thelithology and geomechanics of the candidate wellin detail. Several wells were studied to generatean MEM.

12. The drillstring analysis included bending stresses, sinusoidal buckling, effective axial load, total and incli-national side forces, and torsional and tensile capacity.

13. Inaba M, McCormick D, Mikalsen T, Nishi M, Rasmus J,Rohler H and Tribe I: “Wellbore Imaging Goes Live,”Oilfield Review 15, no. 1 (Spring 2003): 24–37.

14. For more on screenless completions: Acock A, Heitmann N, Hoover S, Malik BZ, Pitoni E, Riddles C and Solares JR: “Screenless Methods to Control Sand,”Oilfield Review 15, no. 1 (Spring 2003): 38–53. For more on frac-packing: Ali S, Norman D, Wagner D,Ayoub J, Desroches J, Morales H, Price P, Shepherd D,Toffanin E, Troncoso J and White S: “CombinedStimulation and Sand Control,” Oilfield Review 14, no. 2(Summer 2002): 30–47.

15. Bale A, Owren K and Smith MB: “Propped Fracturing asa Tool for Sand Control and Reservoir Management,”paper SPE 24992, presented at the SPE EuropeanPetroleum Conference, Cannes, France, November16–18, 1992. For an early use of this technique to control chalk pro-duction: Moschovidis ZA: “Interpretation of Pressure

> Piltun-Astokhskoye field, offshore Sakhalin Island, Russia.

RUSSIA

RUSSIA

SakhalinIsland

Piltun-Astokhskoyefield

CHINA

JAPAN

T a t a rS

o un

d

O k h o t s k S e a

Decline for Minifrac Treatments Initiated at the Interfaceof Two Formations,” paper SPE 16188, presented at theSPE Production Operations Symposium, Oklahoma City,Oklahoma, USA, March 8–10, 1987.

16. Akbar Ali AH, Marti S, Esa R, Ramamoorthy R, Brown Tand Stouffer T: “Advanced Hydraulic Fracturing UsingGeomechanical Modeling and Rock Mechanics—AnEngineered Integrated Solution,” paper SPE 68636, pre-sented at the SPE Asia Pacific Oil and Gas Conferenceand Exhibition, Jakarta, Indonesia, April 17–19, 2001.

17. High-rate water packing is a sand-control methodinvolving fracturing a formation to place gravel outsideof casing and perforations beyond the damage radius of a well. The fracture is typically designed to have a 2- to 10-ft [0.6- to 3-m] half-length with moderate (2- to 3-lbm/ft2) [10- to 15-kg/m2] fracture conductivity; usually it is created with Newtonian fluids such as completion fluid.

18. Skin is a dimensionless factor calculated to determinethe production efficiency of a well by comparing actualconditions with theoretical or ideal conditions. A positiveskin value indicates that some damage or influences areimpairing well productivity.

The highest permeability portion of the oil-bearing zone consists of poorly consolidatedsandstone comprising fine- to medium-grainedclean sands with little clay. The depositionalenvironment was a marine shelf, featuring acoarsening-upward sequence; lower sections aremore consolidated because of higher clay

concentrations and cementation. Barrier zonesthat are highly consolidated vary from shaly silt-stone and sandstone to shales.

Although the average formation permeabilityis about 150 to 200 mD, the clean sandstoneshave high permeabilities, up to 4 D. The perme-ability in the well was calculated using the

Timur-Coates permeability transform from theCMR Combinable Magnetic Resonance log.19

Core data calibrated these measurements.The direction of maximum horizontal

stresses, σH, was determined using a DSI DipoleShear Sonic Imager tool operating in a crossed-dipole mode. The DSI response indicated that σH

lay in a northeast-southwest direction. This wascorroborated by breakout results from a four-armcaliper tool.

Other properties for the MEM, such asPoisson’s ratio and Young’s modulus, also wereobtained from the DSI log. Core measurements ofunconfined compressive strength calibrated theUCS from a DSI log correlation.

Perforating—The locations selected for per-forations accounted for the stress magnitudesand directions to minimize perforation tunnelfailure.20 Although the preferred orientation forthe perforations in these highly deviated wellswas vertical, it was not always possible to usethat orientation.

A perforation interval was selected in thelower permeability, more consolidated intervalslightly below the highly permeable target zone.Based on information from the MEM, FracCADEfracturing design and evaluation softwaremodeling indicated the IVF would grow from thecompetent zone into the weaker, more produc-tive interval above (left). The model helpeddesign the perforation density, penetration andhole size to minimize the chance of proppant orformation sand production.

The first well treated with IVF in Piltun-Astokhskoye field had considerably higher flowefficiency than wells treated with conventionalfrac-pack and HRWP treatments. A pressurebuildup test provided information about the IVFfracture treatment. The well was shut in atsurface, so wellbore-storage effects—pressurechanges caused by the wellbore and fluidresponse to the shut-in—masked the short-timeresponse of bottomhole pressure data frompermanent downhole gauges. Buildup data afterwellbore storage effects ended showed a success-ful completion. The results indicated the fractureextended from all perforations, and the conduc-tivity of the fracture was so high that the buildupbehaved as though there were no fracture, onlydirect completion into both the consolidated,perforated zone and the weak, high-permeabilitypay zone.

36 Oilfield Review

> Geomechanics of the Piltun-Astokhskoye field. A FracCADE fracture simulator uses petrophysics(Track 3) and formation lithology (Track 1) to evaluate formation mechanical properties (Track 2). InTrack 2, the variability of fracture closure stress (red), a measure of minimum horizontal stress, isrepresented in the model as zones of constant stress (blue).

GammaRay

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Summer 2003 37

The buildup tests in this and later Piltun-Astokhskoye wells with IVF treatments showedlow to no skin, indicating successful treatments.This series of wells completed using IVF had anaverage production of 9800 BOPD [1560 m3/d]after 90 days, and produced essentially sand-free through June 2003 (right). The IVF methodprovided the operator with an efficient comple-tion at a substantially lower price than with afrac-pack.

Jauf reservoir—The Jauf reservoir in SaudiArabia also has unconsolidated layers that areprone to sanding, but, in contrast to the Piltun-Astokhskoye field, they have low to moderatepermeability.21 Beginning in 2000, the operatorcollaborated with Schlumberger to use aPowerSTIM well-optimization process to success-fully stimulate and control solids production. Thewells were completed in a gas zone usingpropped fractures and screenless completions.22

A petrophysical analysis, including examina-tion of cores from several wells through thiszone, showed weak and unconsolidated sandsseparated by tighter zones of sand containingillite clay as pore-lining and pore-filling cement.23

The team constructed an MEM based on core and log information, which confirmed the weak-ness of many of the gas-bearing sands (right).

19. For more on nuclear magnetic resonance logging: Allen D, Crary S, Freedman B, Andreani M, Klopf W,Badry R, Flaum C, Kenyon B, Kleinberg R, Gossenberg P,Horkowitz J, Logan D, Singer J and White J: “How toUse Borehole Nuclear Magnetic Resonance,” OilfieldReview 9, no. 2 (Summer 1997): 34-57.

20. Almaguer J, Manrique J, Wickramasuriya S, Habbtar A,López-de-Cárdenas J, May D, McNally AC and Sulbarán A: “Orienting Perforations in the RightDirection,” Oilfield Review 14, no. 1 (Spring 2002): 16-31.

21. Solares JR, Bartko KM and Habbtar AH: “Pushing theEnvelope: Successful Hydraulic Fracturing for SandControl Strategy in High Gas Rate ScreenlessCompletions in the Jauf Reservoir, Saudi Arabia,” paper SPE 73724, presented at the SPE InternationalSymposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, USA, February 20–21, 2002.

22. For more on the Jauf reservoir: Acock, reference 14. For more on the PowerSTIM process: Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S, Rowe W,Fairhurst D, Kaiser B, Logan D, McNally AC, Norville MA,Seim MR and Ramsey L: “From Reservoir Specifics to Stimulation Solutions,” Oilfield Review 12, no. 4(Winter 2000/2001): 42–60.

23. Al-Qahtani MY, Rahim Z, Biterger M, Al-Adani N, Safdar M and Ramsey L: “Development and Applicationof Improved Reservoir Characterization for OptimizingScreenless Fracturing in the Gas Condensate JaufReservoir, Saudi Arabia,” paper SPE 77601, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, September 29–October 2, 2002.

> Comparison of productivity for screenless completions and other methods inthe Piltun-Astokhskoye field. The screenless completions used indirect verticalfracturing. The designation N/A indicates that information is not available.

Wellnumber

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> Sanding tendency for a Jauf reservoir well. Mechanical-strength parameters provided a predictionof sanding tendency (far right track), color-coded to distinguish areas of greater sanding potential.

XX000

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million psi0.50

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Young’s modulus, and the correlated UCS value,decreased by about a factor of six from the competent zones to the unconsolidated layers.The weak layers were prone to sanding. On the basis of the MEM, wherever possible, perforations were placed 10 to 20 feet [3 to 6 m]away from these areas, and the perforation inter-val was restricted to be shorter than 30 or 40 feet[9 or 12 m].

The MEM and stimulation plan were updatedwith results from each well. Close collaborationbetween the operator and Schlumberger expertswas essential in successfully designing and imple-menting this stimulation program. The operatorestablished a balance between eliminating solidsproduction and achieving maximum well deliver-ability. Cleanup time and cleanup costs declinedas the PowerSTIM program progressed.24

Coupling Geomechanics and Fluid Flow Schlumberger performed a data audit and created an MEM of the Miskar field for operatorBG. The field is located about 110 km [68 miles]east-southeast of Sfax, Tunisia in the Gulf ofGabes. The predrill report identified hazards and recommendations for safe drilling in thisgas-condensate field. Most of the drilling difficul-ties in earlier wells occurred while drilling intomechanically weak, overpressured, chemicallyactive, and fractured or faulted formations. Usingthe MEM, BG began a new drilling campaign in the field.

During the drilling of the lower portion of thefirst well in the program, a Schlumberger geome-chanics engineer was present on the rig to moni-tor the daily drilling reports and update theMEM. This well was drilled without the non-productive time incidents of previous wells. BGused the updated MEM for two additional wells,which successfully reached their primary andsecondary directional targets without instabilityevents. With each well drilled, the databasecould be updated, providing a basis for continu-ing drilling improvements in Miskar field.

With an MEM constructed for the field,Schlumberger applied a new tool for reservoir

studies (above). The ECLIPSE-GM coupledgeomechanical and reservoir model provides abasis to determine the effect of rock stresschanges on reservoir flow properties.

In the absence of pressure support from anaquifer or injection of water or gas, production ofhydrocarbons from a field decreases pressure information pore spaces. The weight of the over-burden shifts from being supported by pore pres-sure to being supported by the rock fabric,increasing the stresses on that solid framework.This change of stress state can result in loss ofporosity and permeability and, in extreme cases,can cause wellbore deformation or failure.

In the past, modeling this behavior usedloosely coupled flow and mechanical models.25

Reservoir flow simulators generally contain rela-tively simple rock-mechanical models, andmechanical simulators generally contain simplesingle-phase flow models. In a loosely coupledsimulation, the pressure and volume results fromone step in the flow model become inputs to themechanical model, and vice versa. The processiterates this same time step until the input andoutput values are within an acceptable tolerance.Then the models move to the next time step.

38 Oilfield Review

24. Ramsey L, Al-Ghurairi F and Solares R: “Wise Cracks,”Middle East & Asia Reservoir Review 3 (2002): 10–23.

25. Ruddy I, Andersen MA, Pattillo PD, Bishlawi M andFoged N: “Rock Compressibility, Compaction, andSubsidence in a High-Porosity Chalk Reservoir: A CaseStudy of Valhall Field,” Journal of Petroleum Technology41, no. 7 (July 1989): 741–746.

> Reservoir simulation map of Miskar field. The color code indicates vertical rock displacement as a result of stress changesafter one year of depletion.

0 7.8 15.6

Vertical rock displacement, m

23.4 31.2

Summer 2003 39

Modeling using loose coupling is awkwardand slow. Separating the detailed flow from thedetailed mechanical modeling also creates apotential for inconsistencies and incorrect physical modeling of coupled flow and mechani-cal phenomena.

The ECLIPSE-GM simulator uses a modelthat couples geomechanics and flow physics intoone set of equations, eliminating the problems ofloose coupling and ensuring a more accurate representation of reservoir dynamics.

The simulation of Miskar field combined thefield geology with synthetic values for flow andfluid properties. The simulation showed how a stress-dependent permeability decreased pre-dicted gas production (right). In a separate run,sand-management software predicted therestriction on drawdown required to prevent for-mation failure at the wellbore. The resultingreduced drawdown was used with the ECLIPSE-GM Miskar field model to show the predicted pro-duction loss due to that restriction (below right).Output from ECLIPSE-GM modeling also candefine stress conditions for fracture analysis,wellbore stability and compaction.

Watching Models DevelopThe number of fields worldwide with a well-developed mechanical earth model is increasing,but it is still a small number. Many fields have asubstantial body of geomechanical data, butthose data have not been put into a single, coherent framework, and a complete audit of thedata usually is not available.

While it is not economical to generate anMEM for every field in a company’s portfolio, it isprudent to ask, before embarking on a major fielddevelopment or redevelopment, whether con-structing an MEM as part of the project planningwill save money for the company in the long term.

Most earth models to date have been con-structed for drilling purposes, but that is chang-ing, as the well-completion cases describedabove indicate. One of the many advantages ofusing the MEM process is that the information isthen readily available for other purposes, such asreservoir management or production enhance-ment. The investment in building a model can berepaid throughout the life of the field, as theMEM becomes a tool for monitoring and manag-ing reservoir stress changes. —MAA

> Productivity reduction with stress-dependent permeability. The ECLIPSE-GMsimulator can incorporate a stress-dependent permeability (inset) coupledwith changes in the stress field. Taking the stress-dependent permeability intoaccount decreases the predicted gas productivity by 29% after 20 years (pur-ple), compared with the base case (blue). Gas rates are also shown.

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> Productivity decline with formation failure. Predictions of formation failurein different locations of the production interval were obtained from sand-management software. The result can be input to the ECLIPSE-GM model toshow the predicted decline of gas productivity (green) compared with thebase case (blue), when these failed locations are isolated to minimize solidsproduction. Gas rates are also shown.

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40 Oilfield Review

Nuclear Magnetic Resonance Logging While Drilling

R. John Alvarado Houston, Texas, USA

Anders Damgaard Pia Hansen Madeleine Raven Maersk OilDoha, Qatar

Ralf HeidlerRobert HoshunJames KovatsChris Morriss Sugar Land, Texas

Dave Rose Doha, Qatar

Wayne Wendt BPHouston, Texas

For help in preparation of this article, thanks to Emma JaneBloor, Jan Morley, Marwan Moufarrej and CharlesWoodburn, Sugar Land, Texas, USA; Kevin Goy, Doha,Qatar; Mohamed Hashem, Shell, New Orleans, Louisiana,USA; Martin Poitzsch, Clamart, France; Joe Senecal,Maersk Oil, Doha, Qatar; and Brett Wendt, ConocoPhillips,Houston, Texas.CMR (Combinable Magnetic Resonance), CMR-200, CMR-Plus, IDEAL (Integrated Drilling Evaluation andLogging), MDT (Modular Formation Dynamics Tester),PowerDrive, PowerPulse, proVISION and VISION are marks of Schlumberger.

Innovative drilling and measurements technologies now provide increasingly

comprehensive borehole and formation-evaluation data in real time. Recent

developments in nuclear magnetic resonance logging while drilling are helping

operators make more informed drilling and completions decisions, reduce risk and

nonproductive time and optimize wellbore placement and productivity.

Nuclear magnetic resonance (NMR) logging whiledrilling (LWD) represents a significant advance-ment in geosteering and formation-evaluationtechnology, bringing the benefits of wireline NMRto real-time drilling operations. Critical petro-physical parameters, such as permeability andproducibility estimates, can now be obtainedwhile drilling, providing information that helpspetrophysicists, geologists and drillers achieveoptimal wellbore placement within a reservoir.

Real-time while-drilling measurements areespecially important in high-cost and time-sensitive drilling environments. With rig costsrunning as high as USD 175,000 per day, errors in well placement, formation evaluation or well-completion design can result in significant additional well costs or the drilling of expensive sidetracks.1

In this article, we review basic NMR con-cepts, introduce developments in NMR loggingwhile drilling and discuss how operators areusing this technology for wellbore placement andformation evaluation in real time.

Development of Wireline NMRIn the decade that NMR logs have been available,they have undergone continual improvement.2

The CMR Combinable Magnetic Resonance toolfamily, beginning with the introduction of theCMR-A service in 1995, provided measurementsof effective porosity, bound-fluid volume (BFV),permeability and T2 distributions, a conceptdescribed later in this article. The CMR-200Combinable Magnetic Resonance tool introducedadvances in electronics that provide an increasedsignal-to-noise ratio (S/N) while shorter echo

1. 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.Bargach S, Falconer I, Maeso C, Rasmus J, Bornemann T,Plumb R, Codazzi D, Hodenfield K, Ford G, Hartner J,Grether B and Rohler H: “Real-Time LWD—Logging forDrilling,” Oilfield Review 12, no. 3 (Autumn 2000): 58–78.Bratton T, Edwards S, Fuller J, Murphy L, Goraya S,Harrold T, Holt J, Lechner J, Nicolson H, Standifird W

and Wright B: “Avoiding Drilling Problems,” OilfieldReview 13, no. 2 (Summer 2001): 32–51.

2. Kenyon B, Kleinberg R, Straley C, Gubelin G and Morriss C: “Nuclear Magnetic Resonance Imaging—Technology for the 21st Century,” Oilfield Review 7, no. 3(Autumn 1995): 19–33.Allen D, Crary S, Freedman B, Andreani M, Klopf W,Badry R, Flaum C, Kenyon B, Kleinberg R, Gossenberg P,Horkowitz J, Logan D, Singer J and White J: “How toUse Borehole Nuclear Magnetic Resonance,” OilfieldReview 9, no. 2 (Summer 1997): 34–57.Allen D, Flaum C, Ramakrishnan TS, Bedford J, Castelijns K,Fairhurst D, Flaum C, Gubelin G, Heaton N, Minh CC,Norville MA, Seim MR and Pritchard T: “Trends in NMRLogging,” Oilfield Review 12, no. 3 (Autumn 2000): 2–19.For more on the history and development of NMR logging:Dunn KJ, Bergman DJ and LaTorraca GA: NuclearMagnetic Resonance—Petrophysical and LoggingApplications, Seismic Exploration No. 32. Amsterdam,The Netherlands: Pergamon Press (2002): 3–10.

3. Allen et al (2000), reference 2.

Summer 2003 41

spacing, on the order of 200 µs, improved petro-physical measurement quality, including totalporosity. Further improvements led to the CMR-Plus logging tool with high-speed capability toacquire data at logging rates up to 2400 ft/hr[730 m/hr] for full porosity logging and 3600 ft/hr[1100 m/hr] for bound-fluid logging, rates three tofive times faster than the CMR-200 tool.3

To date, more than 7000 CMR logging jobshave been performed. For many applications,NMR measurements are superior to other loggingtechniques and can provide critical answers to

questions concerning the presence, type and producibility of reservoir fluids. For many operators, NMR logging has become a routineservice in typical logging programs.

Dance of the ProtonsNMR logging measures the magnetic moment ofhydrogen nuclei (protons) in water and hydro-carbons. Protons have an electrical charge andtheir spin creates a weak magnetic moment.NMR logging tools use large permanent magnetsto create a strong, static, magnetic-polarizingfield inside the formation. The longitudinal-relaxation time, T1, describes how quickly thenuclei align, or polarize, in the static magneticfield. Full polarization of the protons in pore fluids takes up to several seconds and can be

done while the logging tool is moving, but thenuclei must remain exposed to the magnetic fieldfor the duration of the measurement. The rela-tionship between T1 and increasing pore size isdirect, yet inverse, to formation fluid viscosity.

A series of timed radio-frequency (rf) pulsesfrom the logging-tool antenna can be used tomanipulate proton alignment. The aligned protonsare tilted into a plane perpendicular to the staticmagnetic field. These tilted protons precessaround the direction of the strong induced magnetic field. The precessing protons createoscillating magnetic fields, which generate aweak but measurable radio signal. However,since this signal decays rapidly, it has to beregenerated by repeatedly applying a sequenceof radio-frequency pulses. The precessing protonsin turn generate a series of radio-signal pulses orpeaks known as spin echoes. The rate at whichthe proton precession decays, or loses its align-ment, is called the transverse-relaxation time, T2.

T1 and T2 processes are affected predomi-nantly by interaction between pore-fluidmolecules, or bulk-relaxation characteristics,and from pore-fluid interactions with the grainsurfaces of the rock matrix, also known as surface-relaxation characteristics. In addition, inthe presence of a significant magnetic-field gradient within the resonant zone, there is relax-ation by molecular diffusion that influences onlyT2 processes.4

NMR While DrillingFollowing the widespread acceptance of wirelineNMR, development and field-testing of LWD NMRtools began in the late 1990s.5 Research anddevelopment efforts and lessons learned fromwireline-conveyed NMR logging ultimately led tothe introduction of the proVISION real-timereservoir steering service in 2001, capable of

providing precise high-resolution NMR measure-ments under the harsh conditions typicallyencountered while drilling. Similar to the CMRtool, the proVISION LWD tool delivers measure-ments that include mineralogy-independentporosity, bound-fluid volume (BFV), free-fluidvolume (FFV), permeability, hydrocarbon detec-tion and T2 distributions.

Flexible design allows engineers at the well-site to modify the measurement sequence andoperational characteristics of the tool for one ofthree drilling modes: rotating, sliding or station-ary. The tool can be programmed manually or set to switch automatically based on drilling conditions (below). Engineers can program thetool to measure T1, T2, or both simultaneously.Although both measurements can generate NMRformation-evaluation data, the proVISION sys-tem relies primarily on T2 measurements, whichproduce higher statistical repeatability and ver-tical resolution.

Both T1 and T2 measurements sample anexponential time evolution process. T1 measure-ments sample an exponential buildup and T2

measurements, an exponential decay. The T1

measurement consists of a few samples on thisbuildup, each of which requires an additionalwait time depending on the point measured. TheT2 measurement, on the other hand, captures thecomplete decay within a single Carr-Purcell-Meiboom-Gill (CPMG) measurement after onlyone wait time, resulting in a greater number ofechoes per measurement. Thus the T2 measure-ment can be taken more quickly leading to eithera higher sample rate or to more averaging and,therefore, enhanced data quality.

For LWD NMR measurements to be availablein real time, they must be transmitted to the surface by mud-pulse telemetry. From the rawmeasurements performed by the tool, an optimal

signal-processing algorithm is implementeddownhole to perform the critical T2 inversionprocess. As a result of this inversion, importantpetrophysical measurements can be derived in real time, namely: lithology-independentporosity, T2 spectral distributions, bound- andfree-fluid volumes, permeability and informationabout fluid saturations and characteristics.However, because of telemetry bandwidth limita-tions, real-time data transmission is limited tomagnetic resonance-derived porosities, BFV,FFV, motion-dependent quality control parame-ters and T2LM, or logarithmic mean of the T2 dis-tribution. These are used in conjunction with thestandard formation evaluation and survey mea-surements to optimize wellbore placementwithin the reservoir.

Transmission of T2LM, BFV or FFV and poros-ity allows calculation of permeability using theSchlumberger-Doll Research (SDR) or Timur-Coates equations.6 Although T2 distributionsthemselves can be provided in real time, teleme-try bandwidth limitations require prioritizationof data; less critical information is stored inmemory for later processing.

Data are transmitted to surface in real timeby the PowerPulse MWD telemetry system. Aswith other VISION Formation Evaluation andImaging While Drilling LWD tools, maximumenvironmental conditions for the proVISION toolare 300°F [150°C], 20,000 psi [138 MPa], anddogleg severity of 8°/100 ft [8°/30 m] while rotat-ing and 16°/100 ft [16°/30 m] while sliding.

The proVISION opposing-dipole magnetdesign produces a symmetric magnetic field. Thevertically oriented tubular samarium-cobalt permanent magnets are stable within the operat-ing temperature range of the tool. A predictableand repeatable NMR measurement is produced(next page, top).

The interaction of the rf field and static mag-netic field produces a resonant region, or shell,with a diameter of 14 in. [36 cm] and height of6 in. [15 cm] (next page, bottom). Magnetic-fieldstrength within the shell is approximately 60gauss, with a field gradient of about 3 gauss percentimeter. The width of the measurement shellallows formation measurement in slightlyenlarged or deviated wellbores and when the toolis eccentered. The formation depth of investiga-tion (DOI) varies with borehole diameter. Forexample, in an 81⁄2-in. diameter borehole, the DOIis 23⁄4 in. [7 cm]. At a drilling rate of 50 ft/hr[15 m/hr], vertical resolution is 3 to 4 ft [0.9 to1.2 m] after data stacking.

42 Oilfield Review

> The proVISION tool pulse-sequence parameters. The tool’s programmabilityis demonstrated in this triple-wait-time acquisition sequence that was usedto evaluate oil-productive (upper set) and oil- and gas-productive (lower set)intervals in a deepwater Gulf of Mexico well, USA.

Anticipatedproductivity

Wait time,sec

Repetitions Number ofechoes

Oil 6.000.600.04

22

40

500300

20

Oil and gas 13.000.600.04

22

40

500300

20

Summer 2003 43

For geosteering purposes, field engineers canplace the tool directly behind the downholemotor or PowerDrive rotary steerable system ordirectly above the bit sub. To further enhancegeosteering capabilities, the proVISION antennasection, which contains the permanent magnets,is located at the bottom of the tool, placing themeasurement point as close to the bit as possible.

The existence of powerful magnets within thebottomhole assembly (BHA) has the potential toadversely affect azimuthal magnetic-surveyinstruments used for determining spatial coordi-nates of the borehole. However, Schlumbergerengineers have demonstrated through modelingand experimentation that the axially symmetricmagnetic field of the proVISION tool has littleinfluence on azimuthal magnetic measurement.Since the magnitude of magnetic-field interfer-ence is small and directly proportional to theintensity of the magnetic field produced by theproVISION tool, errors are significant only whenthe proVISION tool is placed directly above thesurvey instrument. Based on numerical modelsand physical measurements, Schlumberger engineers have developed survey correction algorithms for NMR magnetic interference.These algorithms are included in the IDEALIntegrated Drilling Evaluation and Logging well-site software.

4. For more on T2 relaxation mechanisms: Kenyon et al andAllen et al (2000), reference 2.

5. Prammer MG, Drack E, Goodman G, Masak P, Menger S,Morys M, Zannoni S, Suddarth B and Dudley J: “TheMagnetic Resonance While-Drilling Tool: Theory andOperation,” paper SPE 62981, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 1–4, 2000Drack ED, Prammer MG, Zannoni SA, Goodman GD,Masak PC, Menger SK and Morys M: “Advances in LWDNuclear Magnetic Resonance,” paper SPE 71730, pre-sented at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September 30–October 3, 2001. Horkowitz J, Crary S, Ganesan K, Heidler R, Luong B,Morley J, Petricola M, Prusiecki C, Speier P, Poitzsch M,Scheibal JR and Hashem M: “Applications of a NewMagnetic Resonance Logging-While-Drilling Tool in aGulf of Mexico Deepwater Development Project,”Transactions of the SPWLA 43rd Annual LoggingSymposium, Oiso, Japan, June 2–5, 2002, paper EEE.Morley J, Heidler R, Horkowitz J, Luong B, Woodburn C,Poitzsch M, Borbas T and Wendt B: “Field Testing of aNew Magnetic Resonance Logging While Drilling Tool,”paper SPE 77477, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,September 29–October 2, 2002.

6. Akbar M, Vissapragada B, Alghamdi AH, Allen D, Herron M, Carnegie A, Dutta D, Olesen J-R, Chourasiya RD, Logan D, Stief D, Netherwood R, Russell SD and Saxena K: "A Snapshot of CarbonateReservoir Evaluation," Oilfield Review 12, no. 4 (Winter 2000/2001): 20–41.

> The proVISION tool design. Housed within a 37 ft [11.3 m] long, 63⁄4-in.[17.1-cm] diameter drill collar, the tool’s outside diameter is 73⁄4 in. [19.7 cm].When configured with no external upsets and with wearbands in place, thetool can be run in boreholes ranging from 83⁄8 in. up to 105⁄8 in. diameter. On-site field engineers may attach a screw-on stabilizer to reduce lateral motionand centralize the tool in a borehole. Telemetry connections on both ends ofthe tool assembly allow configuration to any section of a bottomhole assem-bly (BHA). The tool is turbine-powered, rather than battery-powered, and canaccommodate flow rates ranging from 300 to 800 gal/min [1136 to 3028 L/min].

Tubularsamarium-cobalt

magnetsOptional stabilizer

Mud flow

Magnetic field (14-in. diameter x 6-in. height)

> Cross sections of the proVISION tool. The axial section through theantenna (left) illustrates the symmetric tool design. The dark blue bars arehollow cylindrical magnets. Lines of constant field strength (blue) indicate agradient magnetic field that decays away from the tool. The section throughthe coaxial wound antenna coil is shown in black. The interaction of theantenna and the magnets produces a cylindrical resonant shell (red stripes)that is 6 in. [15 cm] long, 0.4 in. [10 mm] thick, with a 14-in. [36-cm] diameter ofinvestigation. The transverse section through the coaxial wound antenna coil(right) illustrates the axisymmetric resonant shell (red). The resonant shell isthe only place the measurement is made—no measurement is madebetween the tool and the resonant shell or from the resonant shell fartherinto the formation. The formation depth of investigation (DOI) in an 81⁄2-in.[21.5-cm ] diameter borehole is 23⁄4 in. [7 cm].

Mud

flow

Diameter of investigation

Resonant zone

Magnetic field

Annular magnet

14 in.

8 1⁄2-in.borehole

8 1⁄2-in.borehole

2 3⁄4 in. DOI

14 in.

6 in.

Making MeasurementsThe proVISION tool operates in a cyclic moderather than a continuous mode. The operatingcycle consists of an initial polarization wait timefollowed by the transmission of the high-frequency rf pulse and then the reception of thecoherent echo signal, or echo train. The cycle ofpulsing and echo reception is repeated in succession until the programmed number ofechoes has been collected. Typically, the acquisi-tion is defined by the Carr-Purcell-Meiboom-Gill(CPMG) sequence. An initial 90° pulse followedby a long series of timed 180° pulses character-izes the CPMG sequence. The time intervalbetween the successive 180° pulses is the echospacing and is generally on the order of hundredsof microseconds.

To cancel the intrinsic noise in a CPMGsequence, the CPMGs are collected in pairs. Thefirst of the pair is a signal with positive phase.The second of the pair is collected with an 180°phase shift, also known as the negative phase.The two CPMG sequences are then combined togive a phase-alternated pair. Compared with theindividual CPMG sequence, the combined orstacked CPMG sequence has an improved S/N.

Measurements of T1 and T2 and their distri-butions are key elements of NMR logging. Theprimary T1 quantity measured is signal amplitudeas a function of polarization recovery time. Theprimary T2 quantities measured are echo-signalamplitudes and their decay. Pulse parameterssuch as echo spacing, wait times and the NMRmeasurement cycle define all aspects of the NMRmeasurement and are completely programmablein the proVISION tool.

Drillstring Dynamics and NMR MeasurementsNMR measurements are not instantaneous. Toolmovement may cause the resonant or excitedregion to move during data acquisition (aboveleft). The proVISION tool is equipped with sen-sors that measure the amplitude and velocity oflateral motion, and instantaneous revolutionsper minute (rpm).

Tool movement can affect both T1 and T2 mea-surements. Motion-induced decay primarilyaffects long T2 values, resulting in faster echodecays that may reduce the accuracy of NMRmeasurement, particularly in light hydrocarbonand carbonate formations. These motion effectsare most severe when the measurement shell isthin in relation to the tool displacement, oftenresulting in movement of the resonant shell outof the region of investigation, even for small toolmovements. A high-gradient static magnetic field

44 Oilfield Review

> Effect of lateral motion on the proVISION NMR measurement. The tool iscentered in the borehole at the beginning of the measurement cycle (left).Subsequent to the initial polarization, drillstring motion causes the tool to restagainst the borehole wall, partially outside the polarized region (right). Ideally,the tool would not move during the course of a CPMG pulse-echo sequence.However, lateral motion of the tool during rotation causes the measurementshell, or resonant region, to move out of the polarized region of investigation.This can result in T2 amplitude and distribution errors.

Borehole wall

Resonant region

Polarizedregion

Reso

nant

regi

on

13 1⁄2 in. 13 1⁄2 in.

> Lateral drillstring motion plots. During the 20-sec time interval, the lower left and right panels showexamples of benign and severe motion recorded by the proVISION tool while rotary drilling. Intervalsof motion amplitude less than 1 mm (bottom left) correspond to the low-rpm intervals shown (top) andrepresent a nearly stationary condition. Violent motion occurs during the remaining time intervals,when the tool is spinning freely and has lateral motion amplitudes up to 5 mm.

-5-5

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Summer 2003 45

results in a thin measurement shell, whichrapidly decays with distance away from the tool.In contrast, the proVISION tool has a low gradi-ent design that results in a thick measurementshell and insensitivity to tool motion.

Since lateral motion can potentially shortenT2 decay rates, understanding this motion is critical for developing data quality-control techniques. To assess motion-induced effects,engineers must know the frequency, amplitude,trajectory and timing of the motion.7 Rapid-sampling accelerometer and magnetometer systems measure real-time drillstring motion(previous page, bottom). Motion data are pro-cessed in 20-sec snapshots. Raw snapshot dataare compressed and can be stored in memory,while the processed results are recorded contin-uously to provide an uninterrupted log of lateralmotion. The theoretical maximum T2 valueresolvable during motion is calculated and a flagindicating NMR data quality is transmitted withthe real-time data set.

Motion data obtained with the proVISIONtool have broad independent utility. These datacan alert the driller to excessive lateral motion,an unfavorable resonant mode or excessiveshocks allowing corrective action to be taken toreduce potential BHA or drill-bit damage and tooptimize drilling rates, improving drilling effi-ciency. Timely response to excessive drillstringmotion can also minimize borehole enlargement(above right).

Optimizing Well ProductivityProper well placement and completion designare key to optimizing productivity. To accomplishthis, drillers must place wellbores in the mostproductive part of a target reservoir, and engi-neers must design completions to maximize oilproduction and recovery while simultaneouslylimiting water production. Real-time LWD NMRlogging provides the data necessary for informeddecision-making.

Determining which intervals of a reservoirshould be completed requires an estimate of awell’s productivity index (PI). Traditionally, thisquestion has been addressed after completion ofdrilling, wireline logging and production testing.The PI is based on a permeability profile, whichis the product of reservoir permeability and vertical thickness. These measurements areobtained from well logs, formation tests, or both.

For more than a decade, operators havesought real-time estimates of permeability andPI. In 1994, BP engineers successfully experi-mented with real-time PI determination methods

at their Wytch Farm project located in the southof England. Geological studies of the Sherwoodsandstone oil reservoir established that reservoirproductivity is a function of permeability, andthat permeability is controlled by grain size and porosity. Core data were used to create permeability bulk-density transforms for eachgrain-size class and these, in turn, were used toestimate PI. As drilling progressed, a permeabil-ity log was generated in real time using grain sizeobtained from sieve analysis of drill cuttings andcombining porosity measurements from a litho-density-neutron logging tool. Petrophysiciststhen calibrated the model against offset wells.

Engineering and petrophysical teams usedthese early real-time permeability-productivityestimates to model and optimize a well’s eco-nomic potential in several ways. Decisions toadjust well trajectory were based on real-timeproductivity predictions. By optimizing perfora-tion intervals, the team maximized productionand minimized the potential for water break-through. These data were used to estimatereserves remaining in wells where intervals hadbeen plugged back for water shutoff.8

At Wytch Farm, BP’s method was relativelysimple to implement. The Sherwood sandstone isnot highly cemented and grain size, porosity andpermeability have a clearly defined relationship.Also, well cores were available for model calibra-tion. In many other reservoirs, the petrophysicalcharacteristics are less straightforward. Whilesimilar processes might provide comparableresults while drilling in more complex reservoirs,the petrophysical community wanted a moreaccurate and complete formation-evaluationsolution. NMR in real time can provide this information and help in optimizing wellboreplacement and completion design.

7. Speier P, Crary S, Kleinberg RL and Flaum C: “ReducingMotion Effects on Magnetic Resonance Bound FluidEstimates,” Transactions of the SPWLA 40th AnnualLogging Symposium, Oslo, Norway, May 30–June 3, 1999,paper II.

8. Blosser WR, Davies JE, Newberry PS and Hardman KA:“Unique ESP Completion and Perforation MethodologyMaximises Production in World Record Step-Out Well,”paper SPE 50586, presented at the SPE EuropeanPetroleum Conference, The Hague, The Netherlands,October 20–22, 1998.Harrison PF and Mitchell AW: “Continuous Improvementin Well Design Optimises Development,” paper SPE30536, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October 22–25, 1995. Hogg AJC, Mitchell AW and Young S: “Predicting WellProductivity from Grain Size Analysis and Logging WhileDrilling,” Petroleum Geoscience 2, no. 1 (1996): 1–15.

> An example of extreme stick-slip. The upper graph shows instantaneous rotation (rpm). At about8 sec into the time interval, the BHA becomes stuck for about 7 sec until the continued buildup in torquereleases the BHA and the stored energy accelerates the drillpipe to over 300 rpm after which the BHAbecomes stuck again. The lower graph shows the number of cumulative rotations. The number of rota-tions increases until the BHA becomes stuck, at which point the topdrive continues turning and buildsseven wraps in the drillstring before the BHA breaks free. The BHA releases the built-up energy, andinertia causes it to overrotate and advance six wraps ahead of the topdrive, potentially unscrewingsections of the BHA.

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NMR in Real Time Modern NMR logs measure mineralogy-independent porosity and provide an estimate ofpermeability and bound-fluid volumes. They canalso detect the presence of hydrocarbons. Whencombined with other LWD measurements, NMR data can be used to generate potential production estimates in real time.

In 2002, BP engineers applied the proVISIONsystem on a deepwater project in the Gulf ofMexico, USA (right). During drilling with oil-basemud, real-time NMR logs were obtained in threeseparate 81⁄2-in. diameter wells. The proVISIONpulse sequence consisted of a single wait timeand burst sequence. A relatively long wait time of12 sec was used to ensure adequate polarizationof the light hydrocarbons that were expected in this reservoir. Six hundred echoes were col-lected after the long wait time. The burst sequence consisted of 20 echoes following a 0.08-sec wait time. Echoes were collected withspacing of 0.8 and 1.2 msec. The overall NMRcycle time was about 30 sec at a drilling rate ofapproximately 70 ft [21 m] per hour. This combi-nation of cycle time and rate of penetration(ROP) gave a depth sample rate of about 0.75 ft[0.23 m] per phase-alternated pair.

To determine BFV, a T2 cutoff of 90 msec waschosen. This T2 cutoff value was based on experi-ence with wireline NMR measurements in thisfield. Evaluation by the petrophysical team indi-cated that neutron, density and NMR porositywere in agreement through the sandstone, whichhas a porosity of about 28 p.u. In addition to NMRdata, the proVISION data set provided the opera-tor with drilling performance, lateral motion anddownhole RPM logs to detect erratic drilling con-ditions, such as stick-slip motion, and allowedthe driller to take corrective actions, potentiallyextending the life of the bottomhole assemblyand optimizing ROP.

The Quest for Carbonate EvaluationHydrocarbons in the Al Shaheen field, offshoreQatar, are currently produced from threeCretaceous formations, the Kharaib, Shuaiba andNahr Umr. The Kharaib and Shuaiba reservoirsare carbonate, while the Nahr Umr comprisesthin sandstones (next page, top).

Maersk Oil operating the Al Shaheen field incooperation with Qatar Petroleum is developingthese complex formations with extended-reachhorizontal wells that occasionally exceed30,000 ft [9144 m] measured depth (MD) while

only 3000 ft [914 m] in true vertical depth.9 Insuch wells, drillpipe cannot be rotated in thehole with logging cable attached. Frictionaleffects eventually prohibit sliding beyond about13,000 ft [3962 m]. Thus, wireline-conveyed log-ging tools are typically unable to reach the far-thest part of a horizontal section. LWD tools areconveyed over the entire length of the boreholewhile providing data for geosteering and primaryformation evaluation.

NMR techniques can help determine reser-voir fluid flow and permeability characteristics.These characteristics may vary significantly withchanges in geologic facies. Detection of faciesvariation is critical to reservoir understandingand optimal wellbore placement. Often, particu-larly in carbonate reservoirs, the lack of consis-tent relationships between porosity andpermeability on a reservoir scale limits LWD

46 Oilfield Review

> Formation analysis in deepwater Gulf of Mexico, USA. The proVISION resistivity-independent oil-indicator information, bound-fluid volume data and permeability data are integrated with wireline log-derived water-saturation information to deliver key producibility estimates while the well is beingdrilled. Tracks 1 through 4 are available as real-time data channels. Changes in the signature of therecorded mode T2 distribution (Track 5) confirm the oil/water contact. The hash marks in the depthtrack are NMR raw-data sample points.

XX650

ft/sec

Rate of Penetration

Rate of Penetration

Rotation

Hydrocarbon Flag

Water

Hydrocarbon

Bound Water

Sample

Washout

00.25

XX700

XX750

mD

Real-time proVISIONPermeability

20000.2

RPS

100

API

Gamma Ray

1500

in.

Caliper

4-2

ohm-m

Attenuation Resistivity

20000.2

ohm-m

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ft3/ft3

Hydrocarbon Flag

-101 ft3/ft3

proVISION BFV

00.6 msec

proVISION T2LM

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10,0001

400ft3/ft3

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00.6

g/cm3

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2.651.65

ft3/ft3

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00.6

ft3/ft3

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00.6

Summer 2003 47

petrophysical characterization using porositylogs. Conventional wireline-conveyed NMR logginghas improved the characterization of geologicfacies and other petrophysical carbonate proper-ties such as permeability (bottom).

Drilling extended-reach wells in the AlShaheen field is challenging. Rotary steerableBHAs are typically used for directional controlin the drilling of the long horizontal sections. Thepetrophysical team was concerned aboutdiminished LWD NMR data quality due tomotion-dependent T2 decay resulting fromthe typically high levels of BHA shock, stick-slipand lateral tool motion during drillstring rota-tion. With ROPs occasionally in excess of500 ft/hr [152 m/hr], further data-quality losswas expected.

Carbonate rocks typically have lower surface-relaxation times, which leads to extended T2

times. Since much of the important petrophysi-cal information is contained in the later echoes,acquisition sequences in carbonates typicallyrequire a longer wait time and a greater numberof echoes than in clastic formations. It wasunknown whether the late T2 components typi-cally seen in the Al Shaheen carbonate rockswould be detected under the expected difficultdrilling conditions.

Engineers attempted to alleviate as manyvariables as possible during prejob planning. Toimprove the S/N, raw echo stacking was alsoplanned. Since facies changes typically occurover tens or hundreds of feet in extended-reachwells, and the detection of small-scale variationswas not the main objective, a loss of resolution inexchange for improved S/N was acceptable.

The world’s first proVISION deployment in acarbonate reservoir was in an extended-reach,81⁄2-in. diameter horizontal well, drilled to morethan 24,000 ft [7315 m] MD with water-base mud.A rotary steerable assembly controlled trajectorywhile LWD NMR data were obtained in real timealong the entire borehole length.

Limited amounts of core material were avail-able from this particular section of the Shuaibareservoir. Historically, carbonate facies identifi-cation and interpretation were based on a com-bination of drill cuttings, thin sections and log

9. Damgaard A, Hansen P, Raven M and Rose D: “A NovelApproach to Real Time Detection of Facies Changes inHorizontal Carbonate Wells Using LWD NMR,”Transactions of the SPWLA 44th Annual Symposium,Galveston, Texas, USA, June 22–25, 2003, paper CCC.

TURKEY

YEMEN

SYRIA

IRAQ IRAN

OMAN

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UNITED ARAB EMIRATES

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Al Shaheenfield

0

0 50 100 150 miles

100 200 300 km

> Location of the Al Shaheen fieldoperated by Maersk Oil Qatar AS incooperation with Qatar Petroleum.

> Identifying changes in the Shuaiba limestone reservoir with wireline NMR data. The NMR data showa large decrease in free fluid, an increase in bound fluid (Track 3, shown shaded yellow) and a decreasein NMR permeability (Track 2) from a depth of XN010 to XN070. It would be difficult, if not impossible,to identify these changes with standard porosity (Track 3, neutron porosity in blue and bulk density inred) and gamma ray logs (Track 1, solid green curve).

Free Fluid

Bound Fluid

Bins 1-2

Bins 7-8

API

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1000

Timur-Coates Permeability

msec

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NMR T2 Distribution

60000.3

29 ohm-m

Deep Image

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122

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00.6

3.45

11.2

516

.67

19.4

922

.77

2?.1

430

.38

34.4

237

.57

40.3

242

.?7

4?.2

750

.05

54.8

362

.42

82.8

822

115.

12

U BR L U

analysis. The borehole was expected to penetratemultiple carbonate facies with varying perme-abilities and producibility characteristics.Maersk Oil hoped to gain significant reservoirinformation in real time from the proVISION

tool, including differentiating various carbonatefacies along the wellbore path and comparingLWD NMR log quality with that of selected intervals of wireline-conveyed NMR logs.

As expected, a high level of downhole shockand stick-slip occurred. ROP was variable, some-times exceeding 500 ft/hr. Because of tool motionand fast ROP, NMR LWD data had a moderatedegree of noise compared with a wireline-

48 Oilfield Review

> A clear image of borehole trajectory. The LWD resistivity image (Track 5) shows the wellbore trajec-tory encountering an overlying marl. The NMR data clearly show a bimodal T2 (Track 4) with the shortT2 peak, centered at 6 msec, coming from the argillaceous material above the borehole from XX329 toXX429 ft, and the longer T2 peak, centered at 200 msec coming from the limestone below the borehole.Lateral changes in the limestone are also indicated. Facies 3 occurs from XX460 to XX474 ft and XX488to XX500 ft, characterized by the lower T2LM value (Track 4).

Gamma Ray

Binned NMR PorosityEarly Late

API 100 00 500

ROP

XX200

XX300

XX400

XX500

XX600

ft/hrBFV–NMR

6000msec3 U R LB U

NMR T2LM Image Orientation

NMR T2 Distribution

Timur-Coates Permeability

SDR Permeability Total NMR Porosity

Thermal Neutron Porosity

2.71.7

Bulk Density

Free Fluid

Bound Fluid

g/cm3

Summer 2003 49

conveyed NMR log. However, data stackingimproved the S/N. Results from multiple MDTModular Formation Dynamics Tester runs pro-vided data to estimate fluid mobility and adjustthe constants in NMR permeability equations.

Analysis based on NMR permeabilities,porosities, T2LM, bound-fluid volumes and free-fluid volumes discerned three distinct porositysystems. The team used changes in T2 characterto map facies variation along the borehole

(previous page). A low bound-fluid volume and ahigh ratio of free to bound fluid typify Facies 1(above). Facies 2 has moderate bound-fluid vol-ume and a lower bound- to free-fluid ratio. Theaverage T2 of Facies 2 is shorter than that of

> Facies 1 from LWD NMR. The LWD data shown indicate an interval of clean carbonate where the T2(transverse relation time) distribution (Track 4) contains a significant percentage of late T2 values. Thesolid blue line is an empirically determined T2 cutoff that is used to partition the T2 distribution into afast component representing bound fluids and a slow component indicating the free fluids. The redtrace represents the T2LM distribution. The T2LM is generally well above the T2 cutoff value, indicatingthat most of the fluid in the pore space is free fluid. The total porosity computed from the NMR data,shown as a dashed black line in Track 3, is in agreement with the conventional limestone matrix neu-tron porosity in blue, and with the formation bulk density displayed in red. The yellow area representsthe bound-fluid volume, while light green indicates the portion of the total porosity that is filled withfree fluids, or the effective porosity. The longest T2 times indicate the largest pores, while the shortestare attributed to the smallest pore sizes. Large pores appear to make up a significant portion of thetotal porosity, with only a small percentage comprising small and very small pores.

Free Fluid

Bound Fluid

Gamma Ray

API

Early Late

1000 0500

ROP

ft/hr 6000msec3

NMR T2LM

NMR T2 Distribution

Timur-Coates Permeability

SDR Permeability

Binned NMR Porosity

BFV–NMR

Total NMR Porosity

Thermal Neutron Porosity

2.71.7

Bulk Density

g/cm3

XX800

XX900

XY000

XY100

Facies 1 and the complete data spectrum isshifted to shorter T2 values. Facies 3 is typified byhigh bound-fluid volume and a low ratio of free tobound fluid. In Facies 3, the T2 spectrum isshifted farther toward shorter values. Thin sections made from cuttings confirmed the faciessignificance of the LWD NMR T2 response.

LWD NMR porosity agreed with density poros-ity in Facies 1 and 2 with an average 3 p.u. deficitin Facies 3 believed to be due to a percentage offaster-decaying T2 signals. LWD NMR data indi-cate different T2 decay rates for each of the threefacies, allowing clear differentiation; this wouldnot have been possible with neutron-porositymeasurements alone (left).

To improve confidence that the LWD NMRdata were identifying petrophysical changes inthe carbonate facies, the team had to rule out thepossibility that the interpreted T2 response wasbeing dominated by motion-induced T2 decay.Measured lateral velocity data were used to con-firm that the T2 data were accurate and correctly indicating changes in the carbonate facies (nextpage, top left). This particular data set shows alarge amount of T2 data acquired even at ele-vated lateral velocities. The current proVISIONdesign does not directly allow compensation fordownhole tool motion in the T2 decay measure-ment. However, highlighting intervals of increasedtool motion can be used as a log-quality indicator.

To examine the effects of downhole toolmotion on LWD NMR data, wireline CMR mea-surements acquired after drilling were comparedwith real-time proVISION data. Porosity, FFV,BFV, T2LM and NMR permeabilities all comparefavorably (next page, right). The CMR data wereacquired over limited intervals for comparison,primarily in the proximal part of the well thathad been open to invasion the longest. SomeCMR logged intervals displayed a small decreasein T2LM values consistent with the additional fil-trate invasion time prior to wireline logging.None of the LWD NMR intervals indicated anyidentifiable motion-induced T2 decay. The favor-able comparison of the late T2 components indi-cates that downhole lateral tool motion is not adominant T2 decay mechanism in this data set.

The proVISION system was configured totransmit porosity, T2LM and FFV in real time toallow use of measurements for geological charac-terization and to aid geosteering. Although furtherevaluation will be required to completely under-stand the NMR T2 response in carbonate rocks,the team working in the Al Shaheen field demon-strated that carefully interpreted LWD NMR datacan be used to help detect variation in carbonatefacies and their petrophysical characteristics.

50 Oilfield Review

> Contrasting NMR data with resistivity images. An LWD resistivity image log is shown in Track 5. Theimage is scaled such that conductive formations are dark and more resistive formations are light withno absolute scale. The resistivity image shows a significant change in the formation resistivity whilethe porosity remains more or less constant, implying a possible textural change. The NMR log over theinterval identified as Facies 2 indicates some large pores. The T2LM is above the cutoff value, but witha broad distribution of pore sizes resulting in a significant percentage of the total porosity being occu-pied by bound fluid. The estimated permeability of Facies 2 is lower than that of Facies 1 (see figure,page 49 ). The NMR log over the interval identified as Facies 3 indicates few, if any, large pores. TheT2LM is below the cutoff value, and most of the total porosity is occupied by bound fluid. The estimatedpermeability of Facies 3 is lower than that of Facies 1 or 2.

Free Fluid

Bound Fluid

Gamma Ray

Binned NMR PorosityEarly Late

APIft/hr

ROP

100 5000 0BFV–NMRTimur-Coates Permeability

SDR Permeability

U R LB UImage Orientation

6000msec3

NMR T2LM

NMR T2 DistributionTotal NMR Porosity

Neutron Porosity

Bulk Density

2.71.7 g/cm3

XX400

XX500

XX600

XX700

XX800

XX900

XX000

Facies 2

Facies 3

Summer 2003 51

The Next GenerationThe proVISION system has demonstrated its ability to acquire real-time logs in both clasticand carbonate reservoirs, potentially identifyingless obvious or otherwise undetected facieschanges. Even for longer T2 components in carbonate formations drilled at elevated ROP,the tool delivers sufficient data resolution forfacies determination and for permeability andbound- to free-fluid volume calculations. TheLWD proVISION tool provides essential real-time reservoir information and data useful formaking geosteering decisions in complex reservoir settings.

Severe stick-slip and BHA shock are oftenassociated with drilling long horizontal sections.Bottomhole shock, combined with high ROP, mayincrease noise in the data sets. However, fielddata demonstrate that the proVISION tool is sufficiently robust to handle these conditionsand provide reliable T2 data.

Future generations of NMR tools hold greatpromise. The industry can look forward to the con-tinued evolution of LWD NMR technology, which isexpected to provide drilling engineers and petro-physical teams with significant advancements inreal-time formation evaluation for geosteering andproductivity optimization. —DW, SP

> Lack of motion-induced decay. The data acquired in this field showno apparent reduction in T2 values associated with the lateral velocityof the LWD NMR tool, implying that in this well, tool motion does notaffect T2 decay.

0

50

100

Late

ral v

eloc

ity, m

m/s

T2LM, ms150 225 3000 75

150

200

> Agreement of wireline CMR and proVISION data. The wireline NMR poros-ity is seen to follow the same trend as the LWD NMR porosity with a smallsystematic shift to lower porosity (Track 1). This difference in total porosity isinfluenced by the differing depth of investigation of the tools and the difference in mud-filtrate invasion related to the formation exposure time.Computed bound-fluid volumes are in agreement (Track 1). The vertical, orspatial, resolution of the LWD NMR tool is reduced because of the high levelof stacking utilized to increase the S/N. Likewise, the physics of measurementimposes a temporal, or time, resolution limit on the LWD tool relative to thatseen with the wireline sensor. The overall effect is a smoothing of the T2 dis-tribution over time and depth. The T2LM of the LWD NMR is shown overlaidon the CMR data (Track 2). Considering the difference in tool design, acquisi-tion parameters, environmental conditions, and the time lapse betweendrilling and drillpipe-conveyed wireline logging, the comparison is excellent.

Free Fluid

Bound Fluid

0500 290

ROP

ft/hrCMR Porosity

NMR T2LM

NMR T2 Distribution

290

NMR T2 Distribution

CMR T2LM CMR T2LM

XX250

XX300

XX350

XX400

NMR Porosity

CMR–BVF

NMR–BVF

Anwar Husen Akbar Ali, who is based in Cairo, Egypt,is Schlumberger advisor for Production Engineering,and Oilfield Services Solutions and TechnologyIntegration manager for the East Africa and EastMediterranean region. Prior to this he wasPowerSTIM* and Sand Management Solutions busi-ness development manager for the Middle East andAsia. Since joining Schlumberger in 1988, he hasworked on projects in the Middle East and Asia, rang-ing from field engineer to operations manager andtechnical advisor. He worked in Houston, Texas, USA,for two years as senior technical engineer in theProduction Enhancement group and later managedthe Asia Technology Hub in Kuala Lumpur, Malaysia.Anwar received his BS degree (Hons) in petroleumand natural gas engineering from UniversityTechnology of Malaysia and obtained an MS degree inintegrated reservoir management from InstitutFrançais du Pétrole in Rueil-Malmaison, France.

John Alvarado is Schlumberger Drilling &Measurements (D&M) account manager in Houston,Texas. There he is project coordinator for measure-ments-while-drilling (MWD) and logging-while-drilling(LWD) operations and overall D&M business manage-ment including involvement with BP’s deepwaterexploration and development. He joined Schlumbergerin 1995 as a field engineer in Stafford, Texas, and sub-sequently became district engineer and field servicemanager. John earned a BS degree in mechanical engi-neering at University of Houston in Texas.

Kevin Bellman is international operations geologistfor EnCana Corporation. He is based in Calgary,Alberta, Canada, where his main areas of operationsare the Middle East and Ecuador. Previously he waswith AEC International for three years.

Scott Bittner, Schlumberger Product Champion forABC* Analysis Behind Casing services, is based inSugar Land, Texas. He is responsible for businessdevelopment of cased hole formation evaluationincluding product development and marketing of newtechnologies. He began his career with Schlumbergerin 1987 as a junior field engineer in Brooks, Alberta,Canada, performing production and evaluation ser-vices. After 10 years in various field locations through-out North America, he became alliance coordinator,Chevron Canada Inc. in Calgary, Alberta, Canada, andthen North America staff technical engineer for forma-tion evaluation in Sugar Land, Texas. He has alsoserved as Reservoir Evaluation–Wireline (REW) opera-tions manager in Alaska (USA), northern Canada andOman. Scott holds a BS degree in mechanical engi-neering from Carleton University in Ottawa, Ontario,Canada.

Tim Brown, Marathon Oil Company Asset TeamManager for northern Oklahoma, is based in OklahomaCity, Oklahoma, USA. Since he joined Marathon in1982, he has had various domestic and internationalpositions in production and operations, both onshoreand offshore. Tim earned a BS degree in mechanicalengineering at Rose-Hulman Institute of Technology inTerre Haute, Indiana, USA.

David Cameron, Schlumberger Account Manager forReservoir Evaluation–Wireline, is based in Stavanger,Norway. There he manages accounts in Scandinavia forConocoPhillips, Agip, Shell, Total, Marathon,ExxonMobil, Mærsk, Amerada Hess and DONG. Hebegan his career in 1988 as a field engineer forWestern Atlas Logging Services and had assignmentsin Scotland, Saudi Arabia, Norway and Indonesia.From 1998 to 2000, he was a senior consultant withIndependent Project Analysis in The Hague, TheNetherlands. He assumed his current position withSchlumberger in 2000. David received a BS degree inmechanical engineering at Brunel University inLondon, England, and also received an MBA degreeafter studying at Erasmus University in Rotterdam,The Netherlands, and at the Stern School of Businessat New York University, New York, USA.

Edwin Cervantes is a sales and support engineer forSchlumberger Reservoir Evaluation–Wireline in Quito,Ecuador. There he provides technical support for fieldoperations and for all clients in Ecuador, primarilyPetroproducción. He joined Schlumberger in 1994 andsubsequently had field engineering positions inColombia and Ecuador. Edwin obtained a degree inmechanical engineering from Escuela PolitecnicaNacional in Quito.

Anders Damgaard is petroleum engineering managerwith Maersk Oil in Doha, Qatar. He joined Maersk Oilin 1981 and has held various petroleum and drillingengineering positions in Denmark and abroad. Andershas a degree in electronic engineering from TechnicalUniversity of Denmark in Copenhagen.

Roger Delgado, a senior drilling engineer withPluspetrol Peru Corporation in Lima, Peru, is responsi-ble for planning and design of wells in the Camisea gasfield. He began his career in 1990 as a drilling engi-neer with Petróleos del Perú S.A. From 1996 to 1999,he was with Pluspetrol Peru Corporation, planning anddesigning wells in the Peruvian jungle. Before takinghis current position, he was a drilling engineer withPluspetrol Bolivia Corporation, designing high-pres-sure, high-temperature wells in Bolivia. Roger has adegree in petroleum engineering from UniversidadNacional Ingeniería, and a degree in accounting andfinance from Escuela de Administración Negocios paraGraduados, both in Lima, Peru.

Jim Farnsworth is BP Technology vice presidentresponsible for worldwide exploration and is also thesenior manager for the BP Global Initiative for SeismicServices. Prior to this he was vice president of NorthAmerica Exploration. His other positions with BP haveincluded vice president of deepwater exploration forBP in Houston, Texas; Alaska exploration manager;and Central North Sea subsurface manager. Jimreceived BS and MS degrees in geophysics and geologyfrom University of Western Michigan and IndianaUniversity, respectively.

Anthony Fondyga is Schlumberger Data & ConsultingServices manager for Ecuador. He joinedSchlumberger Canada as an openhole logging engineerin 1980 after earning a degree in electrical engineer-ing from the University of Toronto, Ontario, Canada.After many operations and sales assignments in openhole, cased hole, and production logging and drillstemtesting, he was seconded to the Petrophysics depart-ment of PanCanadian Petroleum in 1994. Tonyreturned to the Schlumberger InterpretationDevelopment group in Calgary, where he worked ondeveloping new applications and technologies in log-ging services. Before his current assignment, he spenttwo years as senior petrophysicist for the HiberniaAsset team in Saint John’s, Newfoundland, Canada.

David Gibson is the WesternGeco global EcoSeis†champion for land operations worldwide and is respon-sible for integration of an environmental inspectiontool into the company’s quality, health, safety and envi-ronment (QHSE) and knowledge managementprocesses. He previously served as manager of SouthTexas operations. He joined Western Geophysical in1980. David holds a BS degree in geology from VictoriaUniversity at Wellington, New Zealand.

Ankur Gupta joined Schlumberger in 1988 as a wire-line field engineer and spent the next three years infield operations in offshore Great Yarmouth, England.His subsequent positions were in India and Kuwaitwhere he was general field engineer, engineer incharge and field service manager. In 1998, he joinedthe Evaluation Services Technique staff in Montrouge,France. From 1999 to 2000, he was the Wireline &Testing (W&T) asset manager at SchlumbergerWireline headquarters in Clamart, France. Beforebecoming ABC product champion in Sugar Land,Texas, in 2001, he was W&T operations manager, India,and then Oilfield Services manager, Mumbai, India.Ankur earned a BS degree in electrical engineering atthe Indian Institute of Technology in New Delhi, India.

Pia Hansen is currently a senior petrophysicist withMaersk Oil Qatar. She joined Maersk Oil in 1980 andhas been working in various petroleum and drillingengineering positions both in Denmark and abroad.

Contributors

52 Oilfield Review

Ralf Heidler is the section manager for theproVISION* engineering project at the SchlumbergerSugar Land Product Center in Texas. There he over-sees ongoing tool development and new answer prod-ucts. He joined Schlumberger in 1997. Since then, hehas been associated with various aspects of proVISIONdevelopment including data processing and softwaredevelopment. Ralf received a PhD degree in physicsfrom University of Leipzig in Germany.

Robert Hoshun is Schlumberger field operations coor-dinator for the proVISION tool. Since joiningSchlumberger in 1996, he has worked in various loca-tions including Saudi Arabia, Australia, Papua NewGuinea and Qatar. Before taking his current assign-ment in Sugar Land, Texas, he was an LWD geosteeringspecialist in Qatar. Robert holds a BE degree (Hons) inaerospace engineering from the Royal MelbourneInstitute of Technology, Australia.

Trent Hunter is Schlumberger Oilfield Services man-ager, Lloydminster, Alberta, Canada. He joined thecompany in 1992 and had many field engineering posi-tions in Canada, Alaska and Texas. From 1997 to 2000,he worked in technical sales for Hercules Canada Inc.Before taking his current position, he wasSchlumberger Reservoir Evaluation–Wireline accountmanager in Calgary, Canada. Trent has a BE degree inengineering from the University of Saskatchewan,Saskatoon, Canada.

Diego Jaramillo is a Schlumberger petrophysicist forData & Consulting Services in Quito, Ecuador. Hiswork mainly involves processing and interpretation ofopenhole and ABC logs. He joined Schlumberger in1999 after receiving a degree as a geologist engineerfrom Universidad Central del Ecuador in Quito.

Oscar Kelder, who is based in Stavanger, Norway, hasbeen working as a consultant for Statoil on the Snorrefield. He joined the Snorre Team in January 2002. Priorto this assignment, he was a petrophysicist with Statoilin Bergen and Stavanger. Oscar earned an MS degreein petroleum engineering and a PhD degree in petro-physics at Delft University of Technology in TheNetherlands. He recently accepted a position withSaudi Aramco.

James Kovats, Nuclear Magnetic Resonance (NMR)Product Champion at the Sugar Land Product Centerin Texas, is responsible for overseeing developmentand introduction of wireline and logging-while-drillingNMR technology. He began his career as a hydrologistworking on the Yucca Mountain project with the USGeological Survey in Denver, Colorado, in 1989. Hejoined Schlumberger as a field engineer in 1991 andworked in various locations in the North Sea and theUnited Arab Emirates (UAE). Before taking his cur-rent position, he was field service manager for UAEOffshore Operations, involved in coordinating allaspects of wireline formation evaluation, workover andcompletion activities. James earned BS and MSdegrees in geophysical engineering from the ColoradoSchool of Mines in Golden, USA.

Don Lee is a principal geoscientist with SchlumbergerData & Consulting Services in Houston, Texas. Hiswork involves processing and interpreting informationrelating to formation mechanical properties, porepressure prediction and petrophysics for projectsworldwide. After earning a BS degree in electricalengineering from Tennessee Technological Universityin Cookeville, USA, he joined Schlumberger in 1980 asa field engineer in Texas. His subsequent positionsincluded special services engineer, log analyst, seniorlog analyst, application development engineer, seniorinterpretation application engineer and data centermanager.

Rob Marsden, who is based in Abu Dhabi, UAE, man-ages Schlumberger geomechanics and No DrillingSurprises projects in the Middle East. He joinedSchlumberger in 2000, after spending 10 years assenior lecturer and head of the Rock MechanicsLaboratories and Wellbore Mechanics Research Groupat Imperial College in London, England. Since gradu-ating with a degree in civil engineering fromSunderland Polytechnic in England, and with MS andDIC degrees in engineering rock mechanics fromImperial College, Rob has had about 19 years of con-sulting, field, research and teaching experience inpetroleum rock mechanics. A chartered engineer, hehas published more than 40 papers, and has served onnumerous international and industry committees.

Bruce Miller, Schlumberger Formation EvaluationSales and Marketing Manager for Scandinavia, is basedin Stavanger, Norway. There he is responsible for mar-keting and sales of Wireline, LWD and Data &Consulting Services products. He joined Schlumbergerin 1995 as a general field engineer in Opelousas,Louisiana. In 1998, he led the Schlumberger-TexacoAlliance Process Improvement team to streamlineopenhole operations between the two companies inthe Gulf Coast area. Before taking his current position,he was wireline field service manager in Houma,Louisiana. Bruce obtained BS and MS degrees in geologyfrom the University of Illinois, Champaign-Urbana, USA.

Chris Morriss joined Schlumberger in 1978 and hasworked as a field engineer, log analyst and petrophysi-cist at various locations. He is currently principal engi-neer for the proVISION group at the SchlumbergerSugar Land Product Center in Texas. Chris received anengineering degree in 1975 from Aston University,Birmingham, England.

Ruperto Orozco is an operations geologist with AECEcuador Ltd. (EncanEcuador) in Quito, Ecuador. Hebegan his career in 1992 with Baker Hughes Inteq,working in the Oriente and Neuquen basins. He joinedTripetrol Company in Ecuador as chief geologist in1995. Prior to joining AEC he worked for PetrokemLogging Services doing mud logging in the Orientebasin. Ruperto earned a degree as a geologist engineerat Universidad Central del Ecuador in Quito.

Venkat Pacha is operations manager, SchlumbergerReservoir Evaluation–Wireline (REW) in Quito,Ecuador. He joined Schlumberger in 1996 and had sev-eral engineering assignments in India and Indonesia.In 2000, he became REW field service manager in Duri,Indonesia. Before taking his current position in 2002,he was REW location manager in South Sumatra,Indonesia. Venkat holds a BS degree in chemical engi-neering from the Indian Institute of Technology inKharagpur, India, and is currently enrolled in the MBAprogram at Erasmus University in Rotterdam, TheNetherlands, and in an MS degree program at Heriot-Watt University, Edinburgh, Scotland.

Richard Plumb, Geomechanics Metier, SchlumbergerOilfield Services, is based in Houston, Texas.Previously, he was principal consultant and managerof Geomechanics for Schlumberger Data & ConsultingServices and Holditch-Reservoir Technologies, teamleader of Geomechanics for Integrated ProjectManagement (IPM) Engineering, and Geosciencescoordinator for the IPM Support Center in Houston.Prior to joining IPM, he was responsible for case stud-ies in the Interpretation and Geomechanics depart-ment at Schlumberger Cambridge Research inEngland. He also worked at Schlumberger-DollResearch, Ridgefield, Connecticut, USA, where hedeveloped log interpretation techniques for fracturecharacterization, in-situ stress measurement andhydraulic fracture containment. Dick has a BA degreein physics and geology from Wesleyan University,Middletown, Connecticut; an MA degree in geologyfrom Dartmouth College, Hanover, New Hampshire,USA; and a PhD degree in geophysics from ColumbiaUniversity, New York, New York.

Erling Prado-Velarde, who is based in Al-Khobar,Saudi Arabia, is the Schlumberger coordinator forPowerSTIM activities in Saudi Arabia, Kuwait, Bahrainand Pakistan. He joined Schlumberger in 1980 as awell cementing services engineer in Peru. After anassignment at the UK training center, he became atechnical engineer in Macae, Brazil, providing trainingto young engineers. From 1990 to 1993, he was districttechnical engineer, overseeing cementing and stimula-tion in south Argentina. After a two-year assignment atthe Kellyville Training Center in Oklahoma, he becamedistrict technical engineer in Mexico. In 1999, hebecame fracture design manager for theSchlumberger- Nefteyugansk Yukos alliance in westernSiberia. Erling obtained a degree in chemical engi-neering from Universidad Nacional de San Agustin,Arequipa, Peru.

Lee Ramsey is global PowerSTIM training and supportmanager based in Sugar Land, Texas. His main role isto help organize new production optimization teams todevelop solutions in areas where past stimulations orcompletions have not met client expectations. Hebegan his career with Dowell as a field engineer in1974 in Williston, North Dakota, USA, and has held var-ious positions in operations, engineering and market-ing in the United States and Canada. He recentlyheaded the PowerSTIM initiative in North America asproduct champion. The PowerSTIM team was nomi-nated for several “Performed by Schlumberger”awards. Lee attended Kansas State University inManhattan, Kansas, USA, where he received a BSdegree in geology.

Summer 2003 53

Madeleine Raven is a lead geologist with Maersk OilQatar. She joined the company in 1998 and has beeninvolved in geological interpretation, modeling anddevelopment operations. Prior to joining Maersk, shewas projects manager for IEDS, and also a seniorreservoir geologist with Robertson ResearchInternational. Madeleine holds a BS degree in earthsciences from University of Leeds and a PhD degreefrom University of Nottingham, both in England.

Shawn Rice is quality, health, safety and environment(QHSE) manager for WesternGeco worldwide opera-tions and serves on the executive board of theInternational Association of Geophysical Contractors.He previously was the business services manager forWestern Geophysical Company, responsible for QHSE,human resources and training. He has held numerousother positions since joining the company in 1984.Shawn holds a BS degree in geophysical engineeringfrom Colorado School of Mines in Golden, USA.

David Rose is a Schlumberger interpretation develop-ment petrophysicist in Doha, Qatar. He joinedSchlumberger in 1989 as a field engineer and had var-ious assignments in Norway, Denmark and Indonesia.From 1995 to 1997, he was a log analyst inBakersfield, California, USA. Before taking his currentpost in 2000, he was interpretation and computingcenter manager in Midland, Texas. David has a BSdegree in geophysical engineering from the ColoradoSchool of Mines in Golden.

Al Salsman is Schlumberger cased hole wireline busi-ness development manager in Canada. After complet-ing two years of training for a BS degree in businessadministration at Acadia University in Wolfville, NovaScotia, Canada, he joined Schlumberger in 1977 as afield engineer in Canada. After postings in Aberdeen,Scotland, and Ras Shukeir, Egypt, he became a tubing-conveyed perforating (TCP) coordinator in the MiddleEast. He served as wireline country manager in Qatar,manager of TCP and drillstem testing operations inIndonesia, and technical staff engineer for SoutheastAsia. From 1993 to 1996, he was marketing managerfor the Schlumberger Perforating and Testing Centerin Rosharon, Texas. Before assuming his current posi-tion in 2000, he was Oilfield Services account man-ager for deepwater services in Nigeria.

Nikolay Smirnov is a Schlumberger geomechanicsscientist assigned to Integrated Project Managementand Data & Consulting Services in Houston, Texas. Heis currently working on No Drilling Surprises projectsinvolving pore pressure prediction, stress and drilling-risk analysis, and completion design. He joinedSchlumberger in 1997 as a field engineer in Moscow,Russia. The following year he became a drilling engi-neer in Port Gentil, Gabon. Before taking his currentassignment in 1999, he was a drilling engineer inAngola. Nikolay obtained BS and MS degrees in geo-physics from Novosibirsk State University in Russia.

Trevor Spagrud, Vice President of Engineering atEnterra Energy Corp. in Calgary, Alberta, Canada, isresponsible for technical and economic evaluation ofoil and gas assets as well as technical support in com-pletions and operations. He began his career in 1990at Wascana Energy Inc. (Saskoil) in Regina,Saskatchewan, and subsequently had assignments in

production, operations, reservoir engineering andcompletions. From 1993 to 1996, he worked with thecompany’s deep-gas exploration and risk-assessmentteam in Calgary. The following year he was engineer-ing manager at Truax Resources. Before joiningEnterra in 2001, he was vice president of operationsfor Big Horn Resources Ltd. Trevor received a BSdegree in mechanical engineering from the Universityof Saskatchewan in Saskatoon.

David Spooner is a senior drilling engineer with BPin Aberdeen, Scotland. He joined BP Exploration in1988 and three years later, moved to Amoco UK aslead drilling engineer on various projects includingthe Everest development. From 1998 to 1999, he was asenior drilling engineer with Global MarineIntegrated Services. He returned to BP in 2000 assenior drilling engineer on the South Everest, Mirrenand South Magnus subsea developments. David has aBS degree (Hons) in naval architecture and offshoreengineering, and an MS degree in marine technology,both from the University of Strathclyde in Scotland.

Terry Stone is principal software consultant withSchlumberger Information Solutions in the AbingdonTechnology Centre in England. A developer of theECLIPSE* reservoir simulator, he has worked on vari-ous technical options in the simulator including geo-mechanical stress equations, thermal simulation andprocesses, and advanced well modeling. Previously heworked for Scientific Software Intercomp in Denver,Colorado; Mobil Oil in Dallas, Texas; and the AlbertaResearch Council in Canada. In 1995, he joinedINTERA, which was subsequently bought bySchlumberger GeoQuest. Terry earned an undergradu-ate degree in mathematics at University of Windsor,and a PhD degree in nuclear engineering at McMasterUniversity in Hamilton, both in Ontario, Canada.

Tim Stouffer is first deputy general director,Technical Support, Khanty Mansiyshk Oil Corporation(recently acquired by Marathon Oil Company) inMoscow, Russia. In his 25 years with Marathon he hashad various positions around the world in productionoperations, reservoir engineering, liquid natural gasoperations, and evaluation of prospective acquisitions.He also served as the reservoir engineer for theSakhalin II project, Piltun-Astokhskoye field, SakhalinIsland, Russia. Tim obtained a BS degree in petroleumengineering from Colorado School of Mines in Golden.

Wayne A. Wendt is a petrophysicist at BP DeepwaterProjects Business Unit in Houston, Texas. There heworks in field development, specializing in well plan-ning and operations, seismic rock properties, andpressure prediction and detection. He began hiscareer in 1978 as a geophysicist with Natural GasCorporation in San Francisco, California. He joinedBP (Sohio) in 1983 and worked on reservoir descrip-tion of the Prudhoe Bay field, and next moved toAnchorage, Alaska, to work in reservoir surveillanceand field operations. In 1987, he moved to Houston towork on various exploration projects. Wayne has a BSdegree in mathematics from Indiana University ofPennsylvania, USA, and an MS degree in engineeringgeoscience from University of California, Berkeley.

54 Oilfield Review

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

Coming in Oilfield Review

Coalbed-Methane Reservoirs.Exploitation of coalbed-methanereservoirs is becoming more eco-nomical as energy markets changeand new technologies take hold.Coalbed-methane reservoirs do notbehave like ordinary gas reservoirs,prompting operators and servicecompanies to reexamine traditionalwell-construction, formation-evalua-tion, completion and productiontechniques. In this article, we inves-tigate this unconventional resourceand the industry’s efforts to unlockthe enormous potential of coalbed-methane reservoirs.

Refracturing. Hydraulically fractur-ing the same interval after initialtreatment can restore production tonear original rates. Research indi-cates that stress changes aroundexisting wells allow new fractures to reorient and contact undepletedareas. Restimulations are particu-larly effective in low-permeability,highly anisotropic, naturally frac-tured or laminated gas reservoirs.This article presents candidateselection criteria and design con-siderations. US and Canada examplesillustrate field implementation and results.

Gas-Well Construction. The worldenergy market is becoming increas-ingly reliant on natural gas. Operatorsare challenged to drill highly produc-tive and durable gas wells in difficultenvironments. This article reviewsthe state of existing gas wells andexplores wide-ranging aspects ofmodern gas-well construction fromwell planning to completion.

Nontechnical Guide toPetroleum Geology, Exploration,Drilling and ProductionNorman J. HynePennWell Books1421 South Sheridan RoadP.O. Box 1260Tulsa, Oklahoma 74112 USA2001. 575 pages. $64.95ISBN 0-87814-823-X

The book contains 27 chapters with anextensive glossary, index and colorplates that show common minerals and3D seismic views of the subsurface.While explaining basic geologic con-cepts and terms, it follows the processof petroleum exploration from identify-ing its features within the Earth’s crust,to its extraction from production wells.

Contents:

• The Nature of Gas and Oil

• The Earth’s Crust—Where We Find It

• Identification of Common Rocks and Minerals

• Geological Time

• Deformation of Sedimentary Rocks

• Sandstone Reservoir Rocks

• Carbonate Reservoir Rocks

• Sedimentary Rock Distribution

• Mapping

• Ocean Environment and Plate Tectonics

• Source Rocks, Generation, Migration, and Accumulation of Petroleum

• Petroleum Traps

• Petroleum Exploration—Geologicaland Geochemical

• Petroleum Exploration—Geophysical

• Drilling Preliminaries

• Drilling a Well—The Mechanics

• Drilling Problems

• Drilling Techniques

• Testing a Well

• Completing a Well

• Surface Treatment and Storage

• Offshore Drilling and Production

• Workover

• Reservoir Mechanics

• Petroleum Production

• Reserves

• Improved Oil Recovery

• Glossary, References, Index

I highly recommend this book forgeology students and professionals inthe field of petroleum geology…non-geoscientists who would like to learnabout the oil and gas industry wouldbenefit from this book.

Hyne presents the material in aneasy-to-read format with many illus-trations to aid the reader in visualiz-ing subsurface geologic conditions.

Bednar DM Jr: Geotimes 47, no. 9

(September 2002): 36.

Death AssemblageSusan Cummins MillerTexas Tech University PressBox 41037Lubbock, Texas 79409 USA2002. 200 pages. $23.95ISBN 0-8967-2481-6

In this work of mystery fiction, stratig-rapher Frankie MacFarlane is unravel-ing a fossil puzzle that could bring her aprofessorship. Frankie dodges deaththree times before she unravels the puz-zle that links the fossils, a murder and amissing manuscript. Set in Nevada, thisfast-paced book combines a suspensefulplot and well-drawn characters. InDeath Assemblage, the paleontologicalterm for fossils brought together afterdeath, the author vividly describesmountain and desert life, and offersinsights into western history and thelives of ranchers.

Miller turns a phrase. Her prose isa pleasure to read.

I hope to see more of FrankieMacFarlane. As the story ends, she’soff to a teaching post, which, I trust,cannot fail to serve up another ampleration of murder and mayhem.

Andrews S: Geotimes 47, no. 9

(September 2002): 36.

Organo-Clay Complexes and InteractionsShmuel Yariv and Harold Cross (eds)Marcel Dekker, Inc.270 Madison AvenueNew York, New York 10016 USA2002. 688 pages. $195.00 ISBN 0-8247-0586-6

This reference provides comprehensivecoverage of the structures, propertiesand interactions of organo-clay com-plexes as well as their role in the originof life.

Contents:

• Structure and Surface Acidity ofClay Minerals

• Introduction to Organo-Clay Complexes and Interactions

• Interactions of Vermiculites withOrganic Compounds

• Organophilicity and Hydrophobicityof Organo-Clays

• Adsorption of Organic Cations onClays: Experimental Results andModeling

• Nuclear Magnetic Resonance Spectroscopy of Organo-Clay Complexes

• Thermal Analysis of Organo-ClayComplexes

• IR Spectroscopy and Thermo-IRSpectroscopy in the Study of theFine Structure of Organo-Clay Complexes

• Staining of Clay Minerals and Visible Absorption Spectroscopy of Dye-Clay Complexes

• Clay Catalysis in Reactions ofOrganic Matter

• Organo-Minerals and Organo-ClayInteractions and the Origin of Life on Earth

• Indexes

Overall, I felt that the volumewas a useful resource that coveredselected areas well. It contains a min-eral, organic compound and authorindex and…the references are sup-plied complete with titles....

NEW BOOKS

55Summer 2003

The quality of a number of thefigures is disappointing and I felt thatoccasionally some authors paid toomuch attention to well-establishedstudies with which they were familiar,rather than presenting new andemerging work.

Breen C: Clays and Clay Minerals 50,

no. 4 (2002): 533-534.

An Introduction to Seismology, Earthquakes, and Earth StructureSeth Stein and Michael WysessionBlackwell Publishing350 Main StreetMalden, Massachusetts 02148 USA2003. 498 pages. $79.95ISBN 0-86542-078-5

This classic textbook targets upper-levelundergraduate or first-year graduatestudents. Although it deals mainly withseismology, the presentation and coverage should be of interest to thosestudying earth sciences. The text is supported by plots, graphs, illustrationsand maps, and each chapter containsproblem sets, with answers given at theend of the book. Appendix material provides the bulk of the mathematicalsupport discussions.

Contents:

• Introduction

• Basic Seismological Theory

• Seismology and Earth Structure

• Earthquakes

• Seismology and Plate Tectonics

• Seismograms as Signals

• Inverse Problems

• Appendix, References, Index

Along with all the classical stuff,[the authors] explain the recentadvances from tracking plates rightdown to the core-mantle boundary todescribing large-scale deformation ofthe continents. This book shouldbecome a mainstay of many under-graduate courses.

Butler R: New Scientist 177, no. 2387

(March 22, 2003): 52.

The Hydrogen Economy: The Creation of the WorldwideEnergy Web and the Redistribution of Power on EarthJeremy RifkinPenguin Putnam Inc.375 Hudson StreetNew York, New York 10014 USA2002. 294 pages. $24.95ISBN 1-58542-193-6

Depletion of world oil reserves is compounded by the rise of Islamic fundamentalism in oil-rich regions. The author believes the answer is toembrace a new energy source: hydrogenfuel cells. The book outlines the meritsof hydrogen as a “forever fuel” andoffers a vision of a worldwide hydrogenenergy web, much like today’s WorldWide Web.

Contents:

• Between Realities

• Sliding Down Hubbert’s Bell Curve

• Energy and the Rise and Fall of Civilizations

• The Fossil-Fuel Era

• The Islamist Wild Card

• A Global Meltdown

• Vulnerabilities Along the Seams

• The Dawn of the Hydrogen Economy

• Reglobalization from the Bottom Up

• Notes, Bibliography, Index

Is Rifkin’s proposed solution phys-ically possible? Well, yes, sort of, butit’s extremely implausible that all thepower generated today by fossil fuels,about 10 terawatts world wide, couldever be replaced from those sources[renewable resources including photo-voltaic, wind, hydroelectric, geother-mal, and biomass].

Rifkin is certainly right to say thatwe will soon start running out of oil,that continued burning of fossil fuels isa grave threat to the Earth’s climate,and that hydrogen, either in fuel cellsor by combustion, is the best bet for thefuture of transportation. He has cor-rectly identified the biggest problem wehave. But this book is not part of thesolution.

Goodstein D: American Scientist 91, no. 2 (March-

April 2003): 183-184.

Geophysics in the Affairs of MankindL.C. Lawyer, Charles C. Bates andRobert B. RiceSociety of Exploration GeophysicistsP.O. Box 702740Tulsa, Oklahoma 74170 USA2001. 429 pages. $25.00ISBN 1-56080-087-9

Since World War I, major changes haveoccurred within the interrelated fieldsof exploration geophysics, seismologyand oceanography in the search for newoil and natural gas reserves. This bookfocuses on the people and organizationsthat led the technical improvements inthe field, including advances in com-puter hardware and software, and inmarine geophysical techniques.

Contents:

• Some Antecedents to the Modern-Day Profession of GeophysicsThrough World War I

• Geophysics Comes of Age—The Roaring Twenties and theDepressing Thirties

• Geophysicists at War—1939-45

• Reversion to Peacetime, 1945-50

• The 1950s—A Burgeoning Era ofGeophysics

• Science in Government and Government in Science—The 1960s

• Geophysics Interacts with the Environmentalists and OPEC—The1970s and the Early 1980s

• An Industry in Turmoil—The Mid-to-Late 1980s

• Geophysical Advances in the Midstof Uncertainty—The 1990s

• Geophysics as a Business—Thenand Now

• Corporate Profiles of Yesteryear

• Today’s Geophysical Industry: The Full-Service Companies

• Some Niche Firms

• The GeophysicalProfessional—Worldwide

• Appendices

• References, Index

This is a very readable “person-alized” history of applied geophysics,from three eminently qualified authors.

Minor quibbles aside, this bookwill be an excellent addition to anygeophysicists’s library. It is loadedwith useful information and interest-ing anecdotes and does a fine job ofshowing how the business of geo-physics relates to global economicsand politics.

There are a few minor problems in production that could have beenimproved. Some sections appear tohave been repeated directly from thebook’s 1982 predecessor…a fewspelling mistakes, errors innames…missing references, andoccasional repetitions.

My only significant complaint isthe almost complete lack of attentionto geophysics in mining and othernonpetroleum industries.

Green WR: The Leading Edge 21, no. 9

(September 2002): 936-938.

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