Winter 2005/2006

Timely Reservoir Interaction

Gas-Condensate Reservoirs

Hydraulic Fracture Monitoring

Sonic Measurements While Drilling

Oilfield Review

06_OR_001_0

A decade ago, Oilfield Review published an article on per-manent monitoring that documented the early benefits ofcontinuous data in managing reservoirs.1 At that time, theidea of enabling remote control of sensors and making con-tinuous surface or downhole data accessible from officesanywhere in the world was new. Since then, there has beena revolution in the degree and sophistication of availablesensors, in addition to rapid technology development in awide variety of key areas such as analysis, automation,optimization, information technology and communications.A 2002 Oilfield Review article summarized some of thisadvancement within real-time reservoir management.2 Inshort, there has been a major shift from episodic to contin-uous data use in the upstream oil and gas industry.

The vision of a digital oil field is that of real-time moni-toring, analysis and control for optimum field management.A key component of this vision is an integrated approachallowing more real-time control of asset management.Recent technology developments have begun to providedata to enable this change, and the digital oil field israpidly gaining attention within the industry. Among themany different names used to describe this trend areSmart Fields, Digital Oil Field, Next-Generation Oil Field,Field of the Future, e-field, i-field, Instrumented Field andIntelligent Energy. Several operators and service companiesare transitioning from the initial envisioning and abstrac-tion phase to projects that create measurable value.

As the concept of the digital oil field has matured overthe last few years, several excellent examples of single-discipline, point solutions have been published. Theseinclude success stories with data validation, smart wells,advanced monitoring, rapid update of numerical models,optimization and visualization technology. Lately, examplesof a more integrated approach across several disciplineshave been published, including increased use of onshoreoperational rooms supporting offshore activities. Unliketraditional geology and geophysics visualization centers,these operational rooms support drilling or productionwork processes in real time, visualizing both spatial andtemporal data.

Despite continuous efforts in the upstream industry,there is still room for substantial improvement in assetperformance. With the development of new downhole andsurface sensors, our ability to measure outstrips our abilityto utilize the data. The vision moves a step nearer reality

Gaining Ground on Real-Time Reservoir Management

when the hardware and the data gathered are connected tofield performance models, in which the information is con-tinually analyzed and reactions optimized to align with agiven strategy, such as maximizing oil production. An inter-esting opportunity is technology transfer from downstreamto upstream. Downstream has been data-rich for decades,with sensors, measures, controls and optimization as well-established concepts. Increasing the number of sensorsand controls in oil and gas fields allows introduction of thepractice of alarms, continuous analysis and optimization,and knowledge transfer from our downstream colleagues.

Some perceive the digital oil field as futuristic. However,a substantial improvement in asset performance is possiblethrough integration and deployment of technology that isavailable today. To get a broader uptake of digital oil fieldpractices, there is a need for compelling success storiesdocumenting the value of new and existing technology.This will increase opportunities for broader implementationamong operators. As part of this effort, a natural path is tolaunch feasibility and pilot studies, and to develop tools todetermine the value of monitoring and control technologies.Willingness to share such success stories across companiesis an important factor in achieving faster deployment ofreal-time technology in the industry.

Clearly, this has been a decade of tremendous progressin the area of continuous monitoring, analysis and control.However, fully harvesting the potential of the digital oilfield remains a major challenge to our industry in the yearsto come.

Trond UnnelandChevron Norway Country ManagerOslo, Norway

Trond Unneland manages Chevron activities in Norway. Previously, he wasthe Chevron Denmark country manager in Copenhagen and technology accountmanager in San Ramon, California. Before joining Chevron in 2000, he heldengineering and management positions in exploration, offshore operationsand reservoir management at Statoil, Norway for 16 years. Trond has an MSdegree in reservoir engineering from Stavanger University and a PhD degree inpetroleum engineering from the Norwegian University of Science and Technology,Trondheim. He has published many SPE papers on reservoir management, sandcontrol and well performance, and has served on numerous SPE committeesand forums.

1

1. Baker A, Gaskell J, Jefferey J, Thomas A, Veneruso T and Unneland T:“Permanent Monitoring Systems—Looking at Lifetime Reservoir Dynamics,”Oilfield Review 7, no. 4 (Winter 1995): 32–46.

2. Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T, Cosad C, Fitzgerald J,Navarro J, Gabb A, Ingham J, Kimminau S, Smith J and Stephenson K:“Advances in Well and Reservoir Surveillance” Oilfield Review 14, no. 4(Winter 2002/2003): 14–35.

Schlumberger

Oilfield Review4 Acting In Time to Make the Most of

Hydrocarbon Resources

A prerequisite to efficiently meeting increased demand for oil and gas is to acquire and act on well and reservoir data intime to influence decisions. Timely interaction with wells andequipment—and ultimately with the reservoir—improves efficiency, accelerates production and maximizes ultimaterecovery. In this article, we examine the gains achievable when companies adopt real-time technology.

14 Understanding Gas-Condensate Reservoirs

Liquid separates from the gas phase when pressure in a gas-condensate field drops below its dewpoint, leaving valuable liquid components trapped in the reservoir and reducing wellproductivity. This article describes how these mechanismsimpact reservoir management, illustrated by case studies fromRussia, the USA and the North Sea.

28 Coiled Tubing: Innovative Rigless Interventions

From reentry drilling and reservoir stimulation to wellborerecompletions, recent developments in coiled tubing technol-ogy have further advanced through-tubing, or concentric,workover capabilities and efficiency. This article presentsfour specialized applications that use new systems or uniquecombinations of tools and techniques to reduce the overallcost, timing and risk of remedial operations.

Executive Editor

Advisory EditorLisa Stewart

Senior EditorsMark E. TeelMatt Garber

EditorsDon WilliamsonRoopa GirMatt Varhaug

Contributing EditorsRana RottenbergJoan Mead

Design/ProductionHerring DesignSteve Freeman

IllustrationTom McNeffMike MessingerGeorge Stewart

PrintingWetmore Printing CompanyCurtis Weeks

Address editorial correspondence to:Oilfield Review1325 S. Dairy AshfordHouston, Texas 77077 USA(1) 281-285-7847Fax: (1) 281-285-1537E-mail: editorOilfieldReview@slb.com

Address distribution inquiries to:Matt GarberSchlumberger Cambridge ResearchHigh Cross, Madingley RoadCambridge, England CB3 0EL(44) 1223 325 377Fax: (44) 1223 361 473E-mail: mgarber@cambridge.oilfield.slb.com

Useful links:

Schlumbergerwww.slb.com

Oilfield Review Archivewww.slb.com/oilfieldreview

Oilfield Glossarywww.glossary.oilfield.slb.com

On the cover:

Geoscientists and a well-placementengineer track drilling data against aprospect model at a Houston supportcenter. Multiple screens allow assetteams to optimize wellbore placementremotely by monitoring drilling progressand wellbore-navigation measurementsin real time.

2

Wi /Winter 2005/2006Volume 17Number 4

79 Contributors

83 New Books and Coming in Oilfield Review

86 Annual Index

3

42 The Source for Hydraulic Fracture Characterization

Microseismic methods provide crucial information abouthydraulic fractures. Fracture geometry and propagationbehavior can be monitored to help engineers improvereservoir stimulation, increase production and enhancefield-development strategies. This article describes hydraulicfracture monitoring and presents case studies that demonstrateits use in the USA and Japan.

58 Testing Oilfield Technologies for Wellsite Operations

Minimizing tool problems and failures is a top priority foroperators and service companies alike. To that end, innovativeoilfield technologies are subjected to full-scale testing underactual wellsite conditions before reaching the field. Theknowledge gained by this rigorous assessment helps buildtools that perform as designed, even under the most demand-ing conditions.

68 A Sound Approach to Drilling

New-generation sonic logging-while-drilling (LWD) toolsare providing data that help reduce uncertainty and allowengineers to make effective, sound and timely drillingdecisions. Sonic LWD tools provide accurate acoustic datathat, in turn, are being processed to accurately determinepore pressure. When combined with seismic and other while-drilling data, this information helps geoscientists look aheadof the bit to the next geologic horizon and beyond.

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

Abdulla I. Al-KubaisySaudi AramcoRas Tanura, Saudi Arabia

Roland HampWoodside Energy, Ltd.Perth, Australia

George KingBPHouston, Texas

Eteng A. SalamPERTAMINAJakarta, Indonesia

Y.B. SinhaIndependent consultantNew Delhi, India

Sjur TalstadStatoilStavanger, Norway

Richard WoodhouseIndependent consultantSurrey, England

Advisory Panel

Oilfield Review subscriptionsare 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 180.00 US dollars, subject toexchange-rate fluctuations.

Oilfield Review is published quarterly bySchlumberger to communicate technicaladvances in finding and producing hydro-carbons to oilfield professionals. OilfieldReview is distributed by Schlumberger toits employees and clients. Oilfield Reviewis printed in the USA.

Contributors listed with only geographiclocation are employees of Schlumbergeror its affiliates.

© 2006 Schlumberger. All rights reserved.No part of this publication may be repro-duced, stored in a retrieval system ortransmitted in any form or by any means,electronic, mechanical, photocopying,recording or otherwise without the priorwritten permission of the publisher.

Oilfield Review is pleased to welcomeRoland Hamp to its Advisory Panel.Roland is Corporate Reserves Coordinatorfor Woodside Energy Ltd. in Perth,Western Australia. His responsibilitiesinclude reserves reporting, reservesmanagement processes and standards,and reserves assurance program planningand implementation. Prior to joiningWoodside in 1996, he worked for NorthSea Sun Oil and Enterprise Oil. He iscurrently chair of the SPE Council forAustralia, New Zealand and Papua NewGuinea, and has served as editorial com-mittee chair for the SPE News magazineand chair of the SPE Western AustraliaSection. Roland graduated with firstclass honors from Imperial College,London, in 1987, with an ME degree inpetroleum engineering.

4 Oilfield Review

Acting in Time to Make theMost of Hydrocarbon Resources

For help in preparation of this article, thanks to AndrewCarnegie, Beijing; Chip Corbett, Karen Sullivan Glaser,Alex Kosmala, David Rossi, Melissa Symmonds andIan Traboulay, Houston; Charles Cosad and Stephen Pickering,Gatwick, England; Go Fujisawa, Sagamihara, Kanagawa,Japan; Gretchen Gillis, Sugar Land, Texas, USA;Leonardo Giménez, Ahmadi, Kuwait; Judson Jacobs,Cambridge Energy Research Associates, Cambridge,Massachusetts, USA; Caroline Kinghorn, Aberdeen, Scotland;Marc Pearcy, Oklahoma City, Oklahoma, USA; and TrondUnneland, Chevron, Oslo, Norway.DecisionPoint, espWatcher, InterACT, Litmus, MDT(Modular Formation Dynamics Tester), PeriScope 15,ProductionWatcher and StethoScope are marksof Schlumberger.Q, Q-Marine and Q-Xpress are marks of WesternGeco.

Maximized hydrocarbon recovery and accelerated production are just two of the

benefits of acting on the right data at the right time. Immediate access to downhole

and surface data, enabled by recent technological developments, is improving

efficiency and profitability in new and mature fields.

Today, the oil and gas industry is called upon toprovide an increasing supply of hydrocarbonswhile also enhancing ultimate recovery,increasing the cost-effectiveness of explorationand production operations and improving safetyand environmental performance. Meeting theseobjectives will require a new generation ofprocesses, new measurements and timely accessto all the information necessary for informeddecision making.

Several expressions have been coined todescribe the level of immediacy required for datato have impact on a decision. Real-time, in-time,relevant-time, interactive-time and just-in-time allconnote the time frame in which engineers andgeoscientists can use data and technology to makea decision. The decision may be to fine-tune a welltrajectory, change mud weight while drilling,revise logging programs, adjust production chokevalves, detect downhole equipment or artificial liftpump malfunctions, shut off water injection orperform any number of routine or exceptionalactions in the quest for hydrocarbons.

Whatever words are used to convey the idea ofthis new, accelerated interaction with a well or areservoir, the objective is to improve economicreturns by increasing efficiency, reducing risk,accelerating production and maximizingrecovery. This article begins by reviewing the timeframes of decision processes common to manyexploration and production (E&P) operations.Then, to understand what gains oil and gas

companies stand to make, we examine thebusiness case for acquiring and analyzing data intime to bring about changes in a wide range ofwell and reservoir activities. We present exampleshighlighting some of the technology available forfacilitating faster, more accurate decisionmaking. Finally, we discuss limitations that mustbe overcome to advance our capabilities for real-time interaction with the reservoir.

Decision TimeFor every action taken to optimize an oil or gasasset or to react to an unforeseen event, there is awindow of opportunity in which new informationcan have an impact. The window is loosely definedas the time elapsed between the recording of dataand the decision to act upon the implications ofthose data. The data must be acquired, processedand interpreted, then integrated with existingknowledge before a decision can be made to takeaction—all within the relevant time scale. Thescale may be short, on the order of seconds, orquite long, even years, depending on the E&Pdecision at hand (next page).

The quickest actions typically are automatedprocesses that shut down wells or equipment whenpressure, temperature, voltage or other factorsexceed a preset threshold. These shut-in events,such as the activation of subsurface safety valves,often used to involve delays between occurrenceand reaction, but today, the process occurs withoutany decision or human interaction.1

Winter 2005/2006 5

Many other incidents affecting health, safety,the environment and drilling activities requirequick decisions. Within this shortest time scale,from a few seconds to several hours, lie well-control decisions, such as increasing drilling-mud weight to prevent a blowout or decreasingmud weight to avoid formation fracturing andloss of well control. Borehole-trajectorydecisions, such as steering a drill bit to maximizewellbore contact with productive formations,occur on a similar time scale. To take advantageof rig and tool availability, preliminaryinterpretation of logging-while-drilling (LWD)and wireline logs and images must be performedwithin hours of logging to determine if additionallogging or sampling runs are required. Once awell is on production, safety decisions such asrapid shutdown of rotating equipment demandtimely streams of key monitoring data. Manyactions in this time frame are automated bysupervisory control and data acquisition(SCADA) systems. Other production-relateddecisions impact production and injection flowrates. For decisions in this time frame of“operator optimization,” data are needed withinseconds, minutes or hours and often need to beupdated with the same frequency.

On the next time scale, roughly from a day toa few months, detailed interpretation of well logsmust be performed so that completion andstimulation operations can be designed andimplemented or so the well can be abandoned.Well or production tests lasting days or weeksprovide pressure and fluid information forevaluating discoveries, booking reserves anddeveloping or revising reservoir models.Stratigraphic and textural information fromimage logs is incorporated along with seismicdata into geological models, forming thefoundation for selection of offset well locations.Production optimization occurs within this timescale, for example, by modifying productionchoke and valve settings and by acting ondiagnostics from artificial lift systems. Andwithin this time scale, a new generation ofintelligent wells can change their downholeconfigurations in response to downhole andsurface production measurements.

In the one- to two-year time frame, asset teamsmake field-optimization decisions. Geoscientistsand engineers integrate multiwell data toconstruct and calibrate models and run numericalsimulators to optimize field development. Efforts

to optimize reservoir drainage include selection ofinfill well locations, remedial well operations,recompletions and other scheduled interventions.

At the longest time scale, decisions guideoverall asset and portfolio optimization tomaximize recovery. Secondary and enhancedrecovery programs are proposed and implemented.Decisions may be made to develop or tie inmarginal or satellite fields or utilize existinginfrastructure to tap deeper or bypassed targets.Most reservoir-optimization decisions made in thistime frame use data acquired over a period ofyears. However, when the time comes to executelong-term plans, data and interpretationsavailable in relevant time will be vital tosuccessful optimization.

> Time scales for exploration and production (E&P) decisions. From drilling and logging through completion and production, the decision time framechanges, but consistent among stages is the need to obtain data, make decisions and implement actions.

Operator optimization Production optimization Field optimization Reservoir recovery optimization

Time Scales for E & P Decisions

1 day 3 months 2 years1 second 10 years

Detailed loginterpretationWell testsGeologic modelsProductionchoke and valveadjustmentArtificial liftdiagnosticsTime-lapseseismic surveys

Multiwell dataintegrationReservoirsimulation

Infill and offsetwell locations

RecompletionsRemedial welloperations

OverallinvestmentoptimizationSecondaryrecoveryprograms

Tie-in ofsatellite fields

Well control

Geosteering

Early loginterpretation

Productionand processautomation

1. Hansen H, Salaber A, Meyers S, Redd E and Shannon R:“Pursuing the Case for Safety,” Oilfield Review 5, no. 4(October 1993): 36–45.Christie A, Kishino A, Cromb J, Hensley R, Kent E,McBeath B, Stewart H, Vidal A and Koot L: “SubseaSolutions,” Oilfield Review 11, no. 4 (Winter 1999/2000):2–19.Garner J, Martin K, McCalvin D and McDaniel D: “At theReady: Subsurface Safety Valves,” Oilfield Review 14,no. 4 (Winter 2002/2003): 52–64.

Time Is MoneyUsing oilfield data in a timely fashion has severaleconomic benefits. Recent assessments of thevalue of real-time technology cite manyimprovements when oil and gas companies applyrapid decision making to new and mature assetsin all cost environments.2 These improvementscome in the form of minimizing losses andmaximizing opportunity to increase recovery:• Improving safety—Using LWD and borehole

seismic data while drilling results in safer wellconstruction (see “A Sound Approach toDrilling,” page 68). Accessing well dataremotely means fewer visits to the wellsite,exposing fewer workers to risk.

• Avoiding penalties—Certain events, such asspills, leaks, equipment failure and otherlapses in compliance, may have significantinstantaneous as well as sustained costs. Real-time monitoring adds value because it canreduce the risk of these events.

• Minimizing lost or deferred production—Workflows that incorporate continuousproduction monitoring can mitigate gradualeffects, such as skin factor increase and pre-mature water breakthrough, and episodicevents, such as equipment failure, therebyeliminating factors that keep productionbelow planned levels.

• Improving efficiency—Efficiency gainsinclude savings related to performing taskswith lower operating expense and improvingfacility utilization. Validating hydraulic fracture behavior during treatment can allow

adjustments to be made during the job, improv-ing stimulation and preventing unwantedfracture growth (see “The Source for HydraulicFracture Characterization,” page 42).Improving the efficiency of production equip-ment reduces wear and repair costs, protectingassets and minimizing production losses.

• Accelerating production—Proactive optimiza-tion can help operating companies surpass theiroriginal production targets. Revising suboptimalwell trajectories while drilling may expediteproduction. Updating cementing plans duringdrilling and verifying cementing operations soonafter execution may hasten production.

• Increased recovery—Using real-time technol-ogy to steer wells into highly productive payintervals enhances recovery. Workflows thatdiagnose equipment problems or predictunwanted fluid inflow early allow timely adjust-ments that may prolong profitable production.Real-time production monitoring and optimiza-tion can extend field life by changing economiclimits for field abandonment.

In a recent study of oil and gas companypractices, Cambridge Energy ResearchAssociates (CERA) polled companies to quantifysavings or gains that could be expected by usingreal-time technology in a variety of well andreservoir scenarios.3 Industry respondents feltthat real-time asset management could improveultimate recovery by 1% to 7%, accelerateproduction by 1% to 6%, reduce downtime by 1%to 4%, and reduce drilling costs by 5% to 15%.

These proposed gains documented by CERAmay be overly conservative; a report on internalinterviews of asset teams at Chevron estimatesthat implementation of workflows that take

advantage of timely data delivery and decisionmaking can achieve higher added value than theCERA estimates. Production decline could bereduced by 3.5% to 12%; production could beaccelerated by 4% to 18%; and workoverfrequency could be reduced by 30% (left).4

The value realized by other oil and gascompanies will depend on current levels ofefficiency and on the extent to which real-timemeasures are implemented. In the followingsections, we describe how some companies areimproving asset management by acting on datawithin the appropriate time scale.

The Essence of TimeThree essential elements for successful in-timedecision making are technology, processes andpeople. Technology is key because it enablesacquisition, transmission and integration of datain a timely fashion. Processes also play a majorrole because the amount of incoming data can bestaggering, and processes provide information tothe right people at the right time. And the final,essential element is people, learning to makedecisions in accelerated time frames.

One aspect of technology that is a fundamen-tal enabler of all real-time decision making isinformation technology (IT). To many oil and gasprofessionals, and for the purpose of this article,IT is assumed to be present and functioningflawlessly—no small assumption. The oil and gasindustry has been a leader in applying advancedIT for data acquisition and secure datacommunication from harsh and remotelocations. It is this expertise in connectivityinfrastructure that has made in-time reservoirinteraction possible from anywhere in the world.

Because successful real-time reservoir manage-ment requires highly reliable connectivityinfrastructure, it follows that an imperfectconnectivity infrastructure may be responsiblefor failures in implementing real-time reservoirmanagement workflows. Success is more likelywhen infrastructure and workflow are designedin a highly integrated fashion. However, manycompanies have legacy installations that are toocostly to modify or replace, so suppliers arerequired to develop open, flexible systems.

The way in which people are connected totheir data is important for timely asset manage-ment. The most reliable and universally acceptedmethod of accessing data in real time is througha Web portal, a Web site that acts as an entrypoint to other Web sites.

6 Oilfield Review

> The value of managing assets in real time. Cambridge Energy Research Associates (CERA) and Chevronprovide estimates of the potential value to be gained by application of real-time asset management.(Data obtained from Cambridge Energy Research Associates, reference 2 and Unneland and Hauser,reference 2.)

CERA Category CERA Estimate

Improve ultimate recovery

Accelerate production

Reduce downtime

1% to 7%

1% to 6%

1% to 4%

Improve efficiency 3% to 25%

5% to 15%Reduce drilling cost

Chevron Category Chevron Experience

Reduce production decline 3.5% to 12%

4% to 18%

5% to 10%Reduce well downtime

Reduce steam system downtime 8% to 10%

Reduce well workover frequency 30%

Increase facility uptimeby reducing sand

33%

25%

50%

Reduce fuel costs

Reduce regulatory events

Accelerate production

Winter 2005/2006 7

When Kuwait Oil Company (KOC) wanted toprovide employees with fast access to itscorporate E&P databases, the company workedwith Schlumberger to create a secure Webportal for petroleum engineers, reservoirengineers, geoscientists, team leaders,supervisors and managers.5

The result, the KOC GeoPortal, provides aframework and workspace for 1,500 KOC users.In addition to accessing a default page createdfor each user community, users are also able topersonalize their own sites with the GeoPortalWeb components of their choice. The GeoPortalfacilitates improved collaboration between

diverse KOC communities, increasing personalproductivity, accelerating data browsing for allcritical information and improving the ability tomonitor key business measures.

Before data can be viewed from any portal,the data must be uploaded, or delivered in asecure manner, to the user’s site. One of the mostpowerful systems for uploading and viewing datain the E&P industry is the SchlumbergerInterACT real-time monitoring and data deliverysystem. Using a standard Web browser and anInternet or intranet connection, the systemconnects experts from multiple locations toremote job sites anywhere in the world (above).Offsite specialists can collaborate with onsite

2. Unneland T and Hauser M: “Real-Time AssetManagement: From Vision to Engagement—AnOperator’s Experience,” paper SPE 96390, presented atthe SPE Annual Technical Conference and Exhibition,Dallas, October 9–12, 2005.For more on the digital oil field of the future (DOFF):Cambridge Energy Research Associates: “Making theLeap Toward DOFF Adoption,” white paper, January 2005.

3. Cambridge Energy Research Associates, reference 2.4. Unneland and Hauser, reference 2.5. “Case Study: DecisionPoint Solution Integrates with

MyKOC Corporate Portal,” http://www.slb.com/content/services/resources/casestudies/im/cs_decisionpoint_koc.asp (accessed January 3, 2006).Giménez L: “En Route to the e-Field: Effective DecisionMaking Assisted by E&P Web Portal Solutions,” paperSPE 93668, presented at the 14th Middle East Oil and GasShow and Conference, Bahrain, March 12–15, 2005.

> The InterACT real-time monitoring and data delivery system. The InterACT system allows real-time surveillance of operations from any location, at anyttime. Users can retrieve data and view logs, images and wellsite measurements as they are acquired. The system is active in approximately 1,800 wellsand is accessed by more than 11,000 users in 800 organizations worldwide.

Partner

InterACTserver

Satellite array

Information sharingand collaboration

Customer

Real-time productiondata and control

Real-time model recalibration

Real-time drilling data

Real-timedata viewers

> The Aberdeen Operation Support Center (OSC). The OSC provides acollaborative workspace for well planning, modeling and real-time datamanagement and visualization.

crew members, reducing travel to remotelocations and allowing the limited number ofavailable experts to participate in multiple jobs,leading to both improved efficiency and results.

The InterACT system is used in manyapplications, including monitoring and optimizingdrilling and LWD operations, wireline logging,testing and sampling operations, cementingservices, coiled tubing services, stimulationtreatments and production operations. Data fromthe wellsite are communicated via high-bandwidth, low-latency satellite transmission tothe InterACT secure Web server, then to users viaInternet, intranet or cell phone.6 Users can seetheir data within seconds of acquisition.

In an example of one of the thousands ofrecent InterACT jobs, Schlumberger reservoirengineers in the Middle East were field testing anew tool designed to characterize chemicalproperties of formation water. The Litmus pHsensor for the MDT Modular Formation DynamicsTester measures flowline fluid pH, which must bemeasured downhole under reservoir conditionsbecause the pH of samples that are collected forlaboratory analysis can change irreversibly whenbrought to surface. The oil company wasinterested in using the tool to help identify anoil/water contact (OWC), for which it wasimportant to differentiate formation water fromwater-base mud filtrate of different pH.7

Interpreting pH data while the fluid is flowingat each MDT station is vital to applications thatdistinguish fluid-property variations with depth,such as delineating OWCs and characterizing oil-water transition zones. This involves determiningthe shallowest depth at which only formationwater flows and the deepest depth at which oilflows. The procedure necessitates analysis of thepH while the tool is available for repositioning atnew depths as required.

Over a period of some days, at both theirrespective offices and residences, a team of oilcompany experts and the lead Schlumbergerreservoir engineer used the Internet to monitorthe entire downhole fluid analysis operation withthe InterACT system. The Litmus modulescanned fluids at 15 depths to define the OWCand characterize the transition zone withouthaving to collect a single sample.8

Real-time monitoring has helped formationtesting to grow beyond a routine logging serviceinto a new and highly effective method for testingwells. A virtual team of oil company and service

8 Oilfield Review

6. Latency is the time it takes for a packet of data to travel from source to destination. Latency and bandwidth together characterize the speed andcapacity of transmission.

7. Raghuraman B, Xian C, Carnegie A, Lecerf B, Stewart L,Gustavson G, Abdou MK, Hosani A, Dawoud A, Mahdi Aand Ruefer S: “Downhole pH Measurement for WBMContamination Monitoring and Transition ZoneCharacterization,” paper SPE 95785, presented at theSPE Annual Technical Conference and Exhibition, Dallas,October 9–12, 2005.

8. Carnegie AJ, Raghuraman B, Xian C, Stewart L,Gustavson G, Abdou MK, Al Hosani A, Dawoud A, El Mahdi A and Ruefer S: “Applications of Real-TimeDownhole pH Measurements,” paper IPTC 10883,presented at the International Petroleum TechnologyTTConference, Doha, Qatar, November 21–23, 2005.

9. “E-Field Demand Spreading Beyond Norway,” Offshore65, no. 8 (August 2005): 109.

10. Reference 9.11. “Schlumberger and Sense Intellifield Sign Agreement to

Collaborate on Interactive Drilling Operation Centers,”http://newsroom.slb.com/press/newsroom/index.cfm?PRID=19502 (accessed January 2, 2006).

12. Allen D, Bergt D, Best D, Clark B, Falconer I, Hache J-M,Kienitz C, Lesage M, Rasmus J, Roulet C and Wraight P:“Logging While Drilling,” Oilfield Review 1, no. 1 (April 1989): 4–17.

13. Chou L, Li Q, Darquin A, Denichou J-M, Griffiths R,Hart N, McInally A, Templeton G, Omeragic D, Tribe I,Watson K and Wiig M: “Steering Toward EnhancedProduction,” Oilfield Review 17, no. 3 (Autumn 2005):54–63.

14. Net-to-gross ratio compares length of pay to length ofhorizontal wellbore drilled.

15. Barriol Y, Glaser KS, Bartman B, Corbiell R, Eriksen KO,Laastad H, Laidlaw J, Manin Y, Morrison K, Sayers CM,Terrazas Romero M and Volokitin Y: “The Pressures ofDrilling and Production,” Oilfield Review 17, no. 3(Autumn 2005): 22–41.

16. Time-lapse seismic data are sometimes known as four-dimensional, or 4D, seismic data. Three of thedimensions are the spatial dimensions of the survey.Time adds the fourth dimension.

17. Aronsen HA, Osdal B, Eiken O, Goto R, Khazanehdari J,Pickering S and Smith P: “Time Will Tell: New Insightsfrom Time-Lapse Seismic Data,” Oilfiield Review 16, no. 2(Summer 2004): 6–15.

Winter 2005/2006 9

company experts, who may be at differentlocations around the globe, interpret data fromand direct the operations of a sophisticatedtoolstring while it tests fluids, pressures,reservoir deliverability and geomechanicalproperties across target formations.

In-Time Drilling AnswersGeoscientists and engineers use in-timetechnology at different stages in every E&Pproject. Interaction with the drilling process forwell construction and placement was one of theearliest applications of real-time technology togain wide acceptance in the E&P industry.

Some companies are building special onshorefacilities dedicated to remote real-time manage-ment of offshore drilling operations. In the NorthSea, shore-based management of offshoreoperations has become common practice. SenseIntellifield, a company specializing in purpose-built remote drilling operation centers, hasconstructed more than 85 such centers, mostly inthe North Sea, but also in Brunei and China.9

By concentrating real-time drilling operationsmanagement in one location, companies canmake better and faster decisions, and reducethe need for personnel to travel offshore.ConocoPhillips in Norway reports that it is savingUS$ 20 million per year through its onshoredrilling center.10

Schlumberger currently operates 27 in-housedrilling operation centers worldwide and alsoprovides technical support in oil companycollaboration and operation centers (previouspage). For example, the Statoil Åsgaard fieldreceives around-the-clock technical expertise,linking the Statoil drilling operation supportcenter in Stjørdal, Norway, with Schlumbergercenters in Aberdeen and Stavanger.11

For drilling operations that require only atemporary setup, a modular operations supportcenter can easily be moved into any office (seefront cover). This setup provides temporary butfull-service facilities for real-time monitoring ofdrilling and LWD operations.

For years, geosteering teams have relied onLWD measurements to help steer wells intohydrocarbon-rich intervals.12 But conventionalLWD measurements are too shallow to warn ofapproaching bed boundaries and fluid contactsin time to prevent excursions from the pay zone.

The PeriScope 15 directional, deep imagingwhile drilling service can detect the presenceand direction of contacts and boundaries up to15 ft [4.6 m] away.13 This early detection of

upcoming changes in formation properties allowsfor more effective real-time asset managementover field life.

In one example, ConocoPhillips sought tomaximize productive well exposure through theForties sands of the Callanish field in the UKNorth Sea. Raw responses from measurement-while-drilling (MWD) and LWD tools weretransmitted by mud-pulse telemetry to thesurface for decoding. From the rig, MWD andPeriScope 15 data were sent via the InterACTservice to a dedicated geosteering control roomat the ConocoPhillips office in Aberdeen. There,Schlumberger specialists downloaded and pro-cessed data for interpretation by ConocoPhillipsgeologists, which resulted in new geosteeringinstructions for the rig.

The while-drilling measurements helpedConocoPhillips achieve a 98% net-to-gross ratio.14

These results and those for the other three wellsdrilled in the field using the PeriScope serviceled to an improvement of approximately 15% overnet-to-gross results projected by ConocoPhillips.

In another example of rapid decision makingusing LWD data, Shell began redevelopment in2004 of the Ram Powell field in the deepwaterGulf of Mexico. Reaching new targets requiredcomplicated wells that risked encountering inter-vals depleted after seven years of production.15

Shell used the StethoScope formation pressure-while-drilling service to optimize completiondesign and to validate dynamic reservoir models.Acquiring formation pressure while drillingeliminated the need for wireline formation tester services, reducing cost and boreholeexposure times.

Pressure-measurement points were selectedafter real-time analysis of LWD density-neutronlogs. Results showed good pressure supportwithin the target reservoir, but also indicatedthat the low resistivities noted at the bottom ofthe target sands were from a higher-than-expected OWC. With this in-time knowledge,Shell engineers decided to sidetrack the wellupdip. Additional StethoScope measurementsconfirmed good pressure connectivity within thereservoir, so casing was run to total depth.

Shell estimates that formation pressure-while-drilling and associated measurementssaved more than US$ 1 million by eliminating theneed for two conventional drillpipe-conveyedpressure-measurement runs.

Time-Sensitive ImagesWith the right effort, any type of data can bemade available in time to impact asset-manage-ment decisions—even time-lapse seismic data.16

Time-lapse seismic surveys are produced bycomparing seismic data or attributes acquiredbefore and then after hydrocarbon production orinjection has induced changes in reservoirconditions. The first, or baseline, survey isusually recorded before production begins, but asurvey acquired after production starts can serveas a baseline against which subsequent surveysare compared. To realize the potential value oftime-lapse seismic information for subsequentwell planning and reservoir developmentdecisions, results must be available soon aftercompletion of the second, or monitor, survey.

When the first time-lapse surveys wereacquired in the 1980s, it took several months toprocess the data. A great deal of time was spentmatching surveys from different vintages—timeduring which reservoir conditions could changesignificantly. Now, survey repeatability can beachieved with WesternGeco Q single-sensorseismic acquisition and processing technology, sodata processing is simplified and can beperformed during acquisition. The differencebetween surveys can be interpreted within daysof completing acquisition.

Statoil decided early to use time-lapseseismic surveys to optimize field development ofthe Norne field in the Norwegian Sea.17 Thisbillion-barrel [160 million-m3] field has beenproducing oil since 1997, and gas since 2001, witha separate reservoir coming on production in2001. Statoil hopes to increase recovery in theNorne field from 40% to 60%, and to extend fieldlife beyond 2015.

Multiple time-lapse surveys have beenacquired to monitor changes in saturation andpressure throughout the field. Following abaseline survey in 2001 using Q-Marine single-sensor marine seismic technology, a monitorsurvey was acquired in June 2003. The resultswere to be used to plan the trajectory of ahorizontal well planned for August 2003.

The June 2003 survey was quickly comparedwith the 2001 baseline survey, in time toinfluence the well-location decision. Fast-trackprocessing of Q data aboard the WesternGecoTopaz acquisition vessel produced a time-lapsedifference volume 10 days after the survey wascompleted. Two more days of processingproduced the difference in relative acousticimpedance, which, when correlated withsaturation, showed a higher OWC than that

indicated by the reservoir simulation model(left). The well path was modified to avoid thewater zone and to intersect untapped reserves,saving US$ 29 million in the cost of a remedialhorizontal sidetrack.

As of 2004, Statoil had used time-lapseseismic surveys to identify reserves valued atUS$ 750 million and to select 34 additional welllocations.18 Statoil now shoots a monitor surveyonce a year over the Norne field and benefits fromfurther decreases in seismic turnaround timemade possible by the new Q-Xpress integratedseismic data acquisition and processing workflowfor near real-time seismic data analysis. A recentsurvey was processed and the time-lapsedifference produced onboard only 2 days and7 hours after acquisition and inverted to relativeacoustic impedance on the vessel 12 hours later.

Monitoring ProductionAfter a well has been constructed and placed onproduction, the need for timely decision makingcontinues. Many producing wells presentopportunities for reducing operational costs andincreasing output. For example, as of 2003, morethan 90% of producing oil wells required sometype of artificial lift.19 In more than 100,000 wells,artificial lift is achieved by electricalsubmersible pump (ESP).

10 Oilfield Review

> Norne time-lapse seismic results. A relative acoustic impedance (AI) section from the Norne 2003fast-track monitor survey (top) shows the planned well path as a thin dashed black line. The verticalcylinders are renditions of AI at nearby well locations. The brown surface is near-base reservoirsand. The oil-depletion zone (middle, dark blue) interpreted from the time-lapse difference is higheretthan expected, and close to the planned well path. The revised well path (bottom, solid black line) ismhigher, to avoid water production.

Planned well pathRevised well path

Oil/water contact

Oil/water contact

18. Aronsen et al, reference 17.19. Spears and Associates, Inc.: “Oilfield Market Report 2005,”

Tulsa, Oklahoma, USA: 7, http://www.spearsresearch.com/OMR/OMRMain.htm (accessed January 3, 2006).

20. Theuveny B, Nieten J, Kosmala A, Sagar R, Donovan Mand Cosad C: “Web-Based Hosting of Multiassets andMultiusers Production Workflows,” paper SPE 91041,presented at the SPE Annual Techical Conference andExhibition, Houston, September 26–29, 2004.

21. Oberwinkler C and Stundner M: “From Real-Time Data toProduction Optimization,” SPE Production & Facilities 20,no. 3 (August 2005): 229–239.Theuveny B, Kosmala A, Cosad C, Pulido F andDestarac P: “The Challenge of Federation of Informationfor Automated Surveillance of ESPs: Field Examples,”paper SPE 95129, presented at the SPE Latin Americaand Caribbean Petroleum Engineering Conference,Rio de Janeiro, June 20–23, 2005.

22. Theuveny et al, reference 20.23. Theuveny et al, reference 20.24. Bates R, Cosad C, Fielder L, Kosmala A, Hudson S,

Romero G and Shanmugam V: “Taking the Pulse ofProducing Wells—ESP Surveillance,” Oilfield Review 16,no 2 (Summer 2004): 16–25.

25. Bates et al, reference 24.26. Corbett C: “Advances in Real-Time Simulation,” The

Leading Edge 23, no. 8 (August 2004): 802–803, 807.Bradford RN, Parker M, Corbett C, Proano E, Heim RN,Isakson C and Paddock D: “Construction of GeologicModels for Analysis of Real-Time Incidental Transients ina Full-Field Simulation Model,” presented at the AAPGInternational Conference and Exhibition, Cancun,Mexico, October 26, 2004.

27. Differential pressure is the difference between reservoirpressure near the wellbore and flowing bottomholepressure just inside the borehole.

Winter 2005/2006 11

Operators count on actively monitoring,diagnosing and controlling ESP performance tobring value to producing assets. Downhole sensordata, connectivity and interpretation expertisehelp operating companies assess pumpperformance, predict pump failure, identify wellproblems and control pumps remotely. Thesenew capabilities help producers decreaseoperating costs and increase production andcash flow. Analysis of more than 600 ESPmonitoring installations worldwide indicatesthat implementation of real-time productionoptimization workflows can result in immediateproduction increases of up to 50%, with typicallong-term gains at 3% to 8%.20

Downhole sensors can continuously acquireESP intake and discharge temperatures andpressures, motor temperatures, and vibrationand electrical current-leakage data. These datamust be turned into information and delivered toproduction experts in a timely and securemanner so that pumps can be adjusted, ifnecessary, before conditions cause equipment orproduction losses.

The abundance of available data is itself aproblem. Some operators report that dataconsumers spend 80% of their time looking forand organizing data and 20% performing usefulanalysis. Automated processes help collect andcontrol the quality of data and compare theresults with expected values.21 The amount ofdata that can be generated from a producing wellis forcing a change in the way data are acquired.The traditional view of data acquisition falls intotwo broad categories. One view is to acquire whatcan be acquired, then figure out how to use it.This results in enormous amounts of data thatare nearly impossible to mine for value. Analternate view is to use the data available at themoment, although it could be archived for longerterm applications. Most existing SCADA datagathering systems work in these two ways. Onestudy reports that of the 380 MB of data thatcould be gathered by an ESP monitor per month,only 9 kB is relevant to assess the essentialworkings of the pump.22

The preferred approach to acquiring data isto consider what data are needed to allow for anongoing process or successful completion of atask. Data acquisition from the point of view ofthe workflow allows for streamlined monitoringand decision-making processes.23

Schlumberger has developed the espWatchersurveillance and control system for electricalsubmersible pumps to connect production teamsto their well data in time to make production-

optimization decisions.24 Secure, two-waycommunications enable the transmission of datafrom wells and instructions from offsite expertsto the pump. The espWatcher service featuresalarms and alerts set to user-defined thresholds,which can be monitored by the real-timeInterACT system on multiple ESPs in hundredsof wells simultaneously (above).

The espWatcher service can be used tochange pumping rate, detect pump malfunctionprior to complete failure and highlight pumpsoperating at anomalous pressures. For example,Signal Hill Petroleum has exploited the remote-command capabilities of espWatcher service todetect pumps with damaged chokes and tochange operating practices that wereinadvertently disrupting output. The espWatchersystem and associated technology helped SignalHill boost production in its Wilmington fieldwells in California, USA, by 70%.25

Another important type of productioninformation that helps oil company engineersoptimize reservoir output comes from permanentdownhole pressure gauges. These gauges providecontinuous real-time monitoring of the

reservoir’s response to production. An example ofusing up-to-the-minute pressure informationcomes from the Gulf of Mexico, where WestportResources (now Kerr-McGee) had a discovery inBlock 316 of the South Timbalier area.26

The reservoir consists of highly over-pressured, unconsolidated sands. Completionprograms in this field feature short, widefractures to maximize production and minimizedifferential pressure to prevent sand produc-tion.27 Because high differential pressure at thesandface could promote influx of sand, causingpremature failure of downhole equipment, it wasimportant to monitor and control the differentialpressure. A quartz pressure gauge was thereforepermanently installed above the perforations inWell A3 to monitor flowing bottomhole pressure.To obtain differential pressure, the measuredflowing bottomhole pressure must be comparedwith the near-wellbore reservoir pressure, whichcould not be measured, but could be modeledusing reservoir simulation.

> The espWatcher surveillance system for monitoring electrical submersible pumps. With secure,ttwo-way communications, the espWatcher service enables data transmission from wells and relaysinstructions from operators back to the pump. The service includes alarms and alerts set to user-defined thresholds, and allows remote monitoring of hundreds of pumps. Color-coding makes it easytto see which pumps are working within or outside acceptable ranges: pumps operating withincustomized range (green), pumps with some measurement operating outside range (yellow) andpumps not operating (red).

Every 15 seconds, data were sent from thepermanent downhole gauge to a temporarystorage computer at surface, then via satelliteto a land-based terminus (above). TheProductionWatcher real-time remote surveillanceservice provided continuous monitoring of thedata using plots such as the safe productiondifferential-pressure window. The automatedalarms allowed the operator to maximizeproduction rate while avoiding sand influx.

Permanent gauges can also capture otherdata, in the form of pressure transients.Disruptions in production flow create pressuretransients that reach a boundary or permeabilitybarrier within the reservoir and return to thewell, where they are recorded by the gauge. Thisinformation can be used to constrain and updateinterpretations of reservoir extent. In this case,pressure-transient data transmitted from thepermanent downhole gauge in Well A3 were putback into the reservoir simulation. The updatedreservoir model was delivered to the customer

within a few days of drilling. This modelindicated unanticipated reservoir extent thatcould be tapped by sidetracking the A3 well usingthe rig that was still on location. Compared withproduction from the main A3 well, the sidetrackproduced substantial recovery improvement.

Production ExpertiseSome companies are beginning to create value bycolocating production operations expertise inone location, similar to the drilling operationscenters already discussed. For example,ConocoPhillips in Norway is finding significantsavings through its onshore drilling center and isextending the concept with a recently inaugu-rated onshore production center.28 Shell has builtits Production Operations Management Center inNew Orleans for monitoring production from allGulf of Mexico operations.29

Along similar lines, the first SchlumbergerProduction Center of Excellence (PCoE) openedin Oklahoma City, Oklahoma, USA, in 2005. ThePCoE will help producing companies significantlyimprove the way they run their business byproviding support for real-time technology anddelivering surveillance, diagnostics and optimi-zation services on producing wells worldwide.

Experts at the center focus on three mainactivities in production services:• artificial lift well and field surveillance

and optimization• field-wide stimulation optimization with

potential for real-time surveillance• production testing, advanced pressure-

transient analysis, fluids chemistry, wellstartup and production allocation.

PCoE engineers recently worked with an oilproducer in West Texas and central Oklahomathat has more than 200 wells under surveillanceusing the espWatcher service. On one of theirwells, decreasing intake pressure triggered ayellow alarm, alerting the surveillance engineerto a potentially underperforming well (nextpage). The trend analysis of the data indicateddecreasing flow rate and intake pressure withother parameters remaining constant. Toevaluate the reservoir’s potential, the intakepressure response was examined, and twotransient events were identified in the recordedpressure response over time. Both events wereexamined, and a pressure-transient interpretationwas performed. The analysis indicated apermeability of 197 mD and a near-wellbore skin

12 Oilfield Review

28. Reference 9.29. Henderson G and Kapteijn P: “Smarter Business,”

Offshore Engineer (March 14, 2005), http://www.oilonline.com/news/features/oe/20050314.Smarter_.17395.asp(accessed January 4, 2006).

30. Cambridge Energy Research Associates, reference 2.

> ProductionWatcher data-transmission stream. Data are sent from the permanent gauge to the surface, where they are temporarily stored on a rig computerdisk. From there, data are transmitted via satellite to the Schlumberger Data Management Center, where they are edited, verified and transmitted via Webportal to the desktops of authorized users. The engineering team updates the simulation model as often as is appropriate, usually once a week after stableproduction is reached, but much more frequently during the early life of the reservoir.

gauge

Temporarystorageon rig

transmission

Data quality controland storage

Simulationupdate

Winter 2005/2006 13

factor increase from 2.2 to 4.0, causing a pressuredrop of 350 psi [2.4 MPa].

Production modeling software validated themodel derived from the pressure-transientanalysis and predicted the production that wouldoccur if the near-wellbore skin effect wereremoved by stimulation. This analysis showedthat the production could be increased from 450to 640 bbl/d [72 to 102 m3/d]. After stimulation,3

the pump was reinstalled and the well was putback on production, resulting in a stabilizedproduction rate of 550 bbl/d [87 m3/d] at a much3

higher intake pressure.

Adopting Timely Asset-Management PracticesSome companies or their operating units havebeen aggressively adopting real-time asset-management practices, but others remaincautious. Such differences in acceptance aretypical when new technologies are introduced toan industry.

Some of the hurdles to embracing real-timeasset management are specific and evident, andpertain to IT and data. IT infrastructure, if notstandardized, is costly to build, modify andsupport. To be used efficiently, the massiveamounts of data require standardization, qualitycontrol and automated analysis.

Other inhibiting factors may be more generaland less obvious. In its recent report on real-timetechnology, CERA found that the adoption ofreal-time practices is being slowed by threefactors: the broad operational scope thatcompanies are attempting to address, deeplyengrained work processes and operationalmindsets, and technical and organizationalintegration issues.30

To accelerate adoption of new technologies,the CERA report proposes four steps: publicizingthe business case, promoting cross-industryefforts, engaging senior management andminimizing operational disruptions by modifying

work practices and looking beyond short-termtargets to maximize potential benefits.

The oil field of the future will harness real-time technical advances and efficient workflowsto continually optimize field performance. As thisconcept becomes a reality in more fields, industryand consumers will enjoy increased efficiency andultimate recovery at lower cost. –LS

> Production surveillance at the Production Center of Excellence (PCoE). In one well, decreasing pump intake pressure (left) triggered an espWatcher yellowttalarm, alerting the PCoE staff to a production problem. Pressure-transient analysis consisted of diagnostic plot type-curve matching (upper middle) and apressure simulation analysis plot (lower middle). The results of these interpretations indicate a permeability of 197 mD and an increase in near-wellbore skinfactor from 2.2 to 4.0. The production rate rose following stimulation (right) and eventually stabilized at 550 bbl/d.tt

600

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14 Oilfield Review

Understanding Gas-Condensate Reservoirs

Li FanCollege Station, Texas, USA

Billy W. HarrisWagner & Brown, Ltd.Midland, Texas

A. (Jamal) JamaluddinRosharon, Texas

Jairam KamathChevron Energy Technology CompanySan Ramon, California, USA

Robert MottIndependent Consultant Dorchester, UK

Gary A. PopeUniversity of TexasAustin, Texas

Alexander ShandryginMoscow, Russia

Curtis Hays WhitsonNorwegian University of Science andTechnology and PERA, A/STrondheim, Norway

For help in preparation of this article, thanks to Syed Ali,Chevron, Houston; and Jerome Maniere, Moscow.ECLIPSE 300, LFA (Live Fluid Analyzer for MDT tool), MDT(Modular Formation Dynamics Tester) and PVT Express aremarks of Schlumberger. CHEARS is a mark of Chevron.Teflon is a mark of E.I. du Pont de Nemours and Company.

How does a company optimize development of a gas-condensate field, when

depletion leaves valuable condensate fluids in a reservoir and condensate blockage

can cause a loss of well productivity? Gas-condensate fields present this puzzle.

The first step must be to understand the fluids and how they flow in the reservoir.

A gas-condensate reservoir can choke on itsmost valuable components. Condensate liquidsaturation can build up near a well because ofdrawdown below the dewpoint pressure,ultimately restricting the flow of gas. The near-well choking can reduce the productivity of awell by a factor of two or more.

This phenomenon, called condensateblockage or condensate banking, results from acombination of factors, including fluid phaseproperties, formation flow characteristics andpressures in the formation and in the wellbore.If these factors are not understood at thebeginning of field development, sooner or laterproduction performance can suffer.

For example, well productivity in the Arunfield, in North Sumatra, Indonesia, declinedsignificantly about 10 years after productionbegan. This was a serious problem, since welldeliverability was critical to meet contractualobligations for gas delivery. Well studies,including pressure transient testing, indicatedthe loss was caused by accumulation ofcondensate near the wellbore.1

Arun is one of several huge gas-condensatereservoirs that together contain a significantglobal resource. Other large gas-condensateresources include Shtokmanovskoye field in theRussian Barents Sea, Karachaganak field inKazakhstan, the North field in Qatar thatbecomes the South Pars field in Iran, and theCupiagua field in Colombia.2

This article reviews the combination of fluidthermodynamics and rock physics that results incondensate dropout and condensate blockage.We examine implications for production andmethods for managing the effects of condensatedropout, including reservoir modeling to predictfield performance. Case studies from Russia, theUSA and the North Sea describe field practicesand results.

Forming DewdropsA gas condensate is a single-phase fluid atoriginal reservoir conditions. It consistspredominantly of methane [C1] and other short-chain hydrocarbons, but it also contains long-chain hydrocarbons, termed heavy ends. Under

1. Afidick D, Kaczorowski NJ and Bette S: “ProductionPerformance of a Retrograde Gas Reservoir: A CaseStudy of the Arun Field,” paper SPE 28749, presented atthe SPE Asia Pacific Oil & Gas Conference, Melbourne,Australia, November 7–10, 1984.

2. For a case study of the Karachaganak field: Elliott S,Hsu HH, O’Hearn T, Sylvester IF and Vercesi R: “TheGiant Karachaganak Field, Unlocking Its Potential,”Oilfield Review 10, no. 3 (Autumn 1998): 16–25.

3. Gas-condensate fluids are termed retrograde becausetheir behavior can be the reverse of fluids comprisingpure components. As reservoir pressure declines andpasses through the dewpoint, liquid forms and theamount of the liquid phase increases with pressuredrop. The system reaches a point in a retrogradecondensate where, as pressure continues to decline,the liquid revaporizes.

4. Injection of cold or hot fluids can change reservoirtemperature, but this rarely occurs near productionwells. The dominant factor for fluid behavior in thereservoir is the pressure change. As will be discussedlater, this is no longer the case once the fluid is producedinto the wellbore.

Winter 2005/2006 15

certain conditions of temperature and pressure,this fluid will separate into two phases, a gas anda liquid that is called a retrograde condensate.3

As a reservoir produces, formation temper-ature usually doesn’t change, but pressuredecreases.4 The largest pressure drops occurnear producing wells. When the pressure in agas-condensate reservoir decreases to a certainpoint, called the saturation pressure ordewpoint, a liquid phase rich in heavy endsdrops out of solution; the gas phase is slightlydepleted of heavy ends (right). A continueddecrease in pressure increases the volume of theliquid phase up to a maximum amount; liquidvolume then decreases. This behavior can bedisplayed in a pressure-volume-temperature(PVT) diagram.

The amount of liquid phase present dependsnot only on the pressure and temperature, butalso on the composition of the fluid. A dry gas, bydefinition, has insufficient heavy components togenerate liquids in the reservoir, even with near-well drawdown. A lean gas condensate generates

> Phase diagram of a gas-condensate system. This pressure-volume-ttemperature (PVT) plot indicates single-phase behavior outside the two-phase region, which is bounded by bubblepoint and dewpoint lines. Linesof constant phase saturation (dashed) all meet at the critical point. Thenumbers indicate the vapor phase saturation. In a gas-condensatereservoir, the initial reservoir condition is in the single-phase area to theright of the critical point. As reservoir pressure declines, the fluid passestthrough the dewpoint and a liquid phase drops out of the gas. Thepercentage of vapor decreases, but can increase again with continuedpressure decline. The cricondentherm is the highest temperature at whichttwo phases can coexist. Surface separators typically operate atconditions of low pressure and low temperature.

Temperature

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SeparatorSeparatorconditioncondition

C i d thCricondentherm

Two phase regionTwo-phase region

60%60%

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100% vapor00% apo

BBBuu

bbbblleepp

ooinntt liinneeDDewwppooiinntt liinnee

a small volume of the liquid phase, less than100 bbl per million ft3 [561 m3 per million m3],and a rich gas condensate generates a largervolume of liquid, generally more than 150 bblper million ft3 [842 m3 per million m3] (above).5

There are no established boundaries in thedefinitions of lean and rich, and furtherdescriptors—such as very lean—are alsoapplied, so these figures should be taken merelyas indicators of a range.

Determining the fluid properties can beimportant in any reservoir, but it plays aparticularly vital role in gas-condensatereservoirs. For example, condensate/gas ratioplays a major role in estimates for the salespotential of both gas and liquid, which areneeded to size surface processing facilities. Theamount of liquid that may be stranded in a fieldis also an essential economic consideration.These considerations and others, such as theneed for artificial lift and stimulationtechnologies, rely on accurate fluid sampling.Small errors in capturing samples, such as anincorrect amount of captured liquid, can havesignificant errors in measured behavior, so greatcare must be taken in the sampling process (see“Sampling for Fluid Properties,” next page).

Once reservoir fluids enter a wellbore, bothtemperature and pressure conditions maychange. Condensate liquid can be produced intothe wellbore, but liquid also can drop out withinthe wellbore because of changes in conditions. Ifthe gas does not have sufficient energy to carrythe liquid to surface, liquid loading or fallback inthe wellbore occurs because the liquid is denserthan the gas phase traveling along with it. If theliquid falls back down the wellbore, the liquidpercentage will increase and may eventuallyrestrict production. Gas lift and pumpingtechnologies that are used to counter thisbehavior will not be discussed in this article.6

16 Oilfield Review

> Examples of rich and lean gas-condensate behavior. When pressure decreases at reservoir temperature, a rich gas (top left) forms a higherttpercentage of liquid than a lean gas (top right). The rich gas drops out more condensate than the lean gas (tt bottom left). The liquid dropout curvettassumes the two phases remain in contact with one another. However, in a reservoir, the mobile gas phase is produced; the liquid saturation in thenear-well region builds until it is also mobile. As a result, eventually condensate blockage can affect formations with both lean and rich gases, andtthe normalized well productivity index (J/J J0) of both can be severely impacted (0 bottom right).tt

Liqu

id d

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5. Gas volumes in this article are given at the conditions thatare considered standard at the measurement location,which is not the same around the world. Conversionsbetween metric and oilfield units are volumetric.

6. For more on artificial lift: Fleshman R, Harryson andLekic O: “Artificial Lift for High-Volume Production,”Oilfield Review 11, no. 1 (Spring 1999): 48–63.

Winter 2005/2006 17

Fluid composition is determined by capturinga representative sample of reservoir fluid.Surface samples can be obtained relativelyeasily by collecting liquid and gas samplesfrom test or production separators. Thesamples are then recombined in a laboratory.However, the result can be unrepresentativeof reservoir conditions, particularly whensampling from a gas-condensate reservoir. Afew examples of potential problems includerecombining the gas and liquid samples atan incorrect ratio, changing productionconditions prior to or during sampling andcommingling zones with different properties.If the liquid content is low when capturingsurface samples, a small loss of the liquid inproduction tubulars or separators couldrender the condensate sample unrepresen-tative of the formation fluid.

Samples can also be collected downholefrom wellbore fluids in gas-condensatereservoirs. This is practical and desirable ifthe wellbore flowing pressure is above thedewpoint pressure, but it is generally notrecommended if the pressure anywhere in thetubing is lower than the dewpoint pressure. Inthat condition, there is two-phase flow in thewellbore. Any liquid forming in the tubingduring or prior to the sampling may segregateto the bottom of the tubing string—where abottomhole sampler collects fluids—potentiallyresulting in an unrepresentative sample withtoo much of the heavier components.

Formation testers have improved signifi-cantly over the past decade. The MDT ModularFormation Dynamics Tester collects fluids bypressing a probe against an uncased boreholewall and withdrawing fluids from a formation.1

The LFA Live Fluid Analyzer module on thetool measures the cleanup of contaminationfrom oil-base drilling or completion fluids,minimizing the wait time and assuring qualitysamples.2 The LFA detector also provides anindication of the amount of methane, otherlight components and liquids. From thesedata, the ratio of methane to liquid providesa measure of the condensate/gas ratio, animportant consideration for early economicevaluation of a prospect. The analysis canalso show zones with different compositionsor compositional gradients.

Measured data from the MDT tool are trans-mitted to surface immediately, so samplingdecisions can be made based on knowledgeof approximate composition and reservoirpressure, another measured parameter. Ifdesired, fluid samples can be collected beforemoving to another downhole location.

For gas condensates that are at pressuresabove the dewpoint in the reservoir, it isimportant to capture and maintain single-phase fluid. If the fluid pressure drops belowdewpoint, it may take a long time torecombine the sample. Even worse, somechanges that occur in a sample on its trip tosurface may be irreversible. By providing

evidence when a fluid goes through itsdewpoint, the LFA measurement can indicatewhen the pressure drawdown is too large andshould be decreased before sampling to keeppressure above the dewpoint.

A sample that is single-phase when collectedshould be kept in a single phase when broughtto surface. Special MDT sample bottles areavailable for this purpose. A single-phasebottle uses a nitrogen cushion to increase thepressure in the sampled fluid.3 The samplecools as it is brought to surface, but thenitrogen cushion on the sample keeps itspressure above the dewpoint.

In most cases, the PVT Express onsite wellfluid analysis service can provide fluidproperty measurements at the wellsite inabout 24 hours, saving the weeks or monthsthat may be needed to get results from alaboratory.4 The PVT Express systems canmeasure gas/liquid ratio, saturationpressure—bubblepoint or dewpoint—composition to C30+, reservoir fluid density,viscosity and oil-base mud contamination.5

These measurements are critical because anoperating company can use them immediatelyto make a decision to complete or to test awell. Rapid turnaround may be crucial whendrilling exploration or development wells froman expensive offshore rig. More completeanalyses can be obtained later from samplessent to a laboratory.

With the basic understanding of whereand how condensate drops out of the gasphase, engineers can devise ways to optimizeproduction of gas and condensate.

Sampling for Fluid Properties

1. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC,Rylander E and Van Dusen A: “QuantifyingContamination Using Color of Crude and Condensate,”Oilfield Review 13, no. 3 (Autumn 2001): 24–43.

2. Betancourt S, Fujisawa G, Mullins OC, Carnegie A,Dong C, Kurkjian A, Eriksen KO, Haggag M, JaramilloAR and Terabayashi H: “Analyzing Hydrocarbons in theBorehole,” Oilfield Review 15, no. 3 (Autumn 2003):54–61.

3. Jamaluddin AKM, Ross B, Calder D, Brown J andHashem M: “Single-Phase Bottomhole SamplingTechnology,” Journal of Canadian PetroleumTechnology 41, no. 7 (July 2002): 25–30.

4. Jamaluddin AKM, Dong C, Hermans P, Khan IA,Carnegie A, Mullins OC, Kurkjian A, Fujisawa G,Nighswander J and Babajan S: “Real-Time and On-Site Reservoir Fluid Characterisation Using SpectralAnalysis and PVT Express,” Australian PetroleumProduction & Exploration Association Journal (2004):605–616.

5. The nomenclature “composition to C30+” indicatescompounds up to 29 carbon atoms are separatelydiscriminated, with the remainder combined into afraction indicated as C30+.

Dewdrops in a ReservoirWhen condensate liquid first forms in a gasreservoir, it is immobile because of capillaryforces acting on the fluids. That is, a microscopicliquid droplet, once formed, will tend to betrapped in small pores or pore throats. Even for rich gas condensates with substantial liquid dropout, condensate mobility, which is theratio of relative permeability to viscosity,remains insignificant away from wellbores. As aconsequence, the condensate that forms in mostof the reservoir is lost to production unlessthe depletion plan includes gas cycling. Theeffect of this dropout on gas mobility is typically negligible.

Near a producing well, the situation isdifferent. Once bottomhole pressure dropsbelow the dewpoint, a near-well pressure sinkforms around the well. As gas is drawn into thepressure sink, liquid drops out. After a brieftransient period, enough liquid accumulatesthat its mobility becomes significant. The gasand liquid compete for flow paths, as describedby the formation’s relative-permeabilityrelationship. Condensate blockage is a result ofthe decreased gas mobility around a producingwell below the dewpoint (right).

Reservoir pressure dropping below thedewpoint has two main results, both negative:gas and condensate production decreasebecause of near-well blockage, and the producedgas contains fewer valuable heavy ends becauseof dropout throughout the reservoir, where thecondensate has insufficient mobility to flowtoward the well.

Large productivity losses have been reportedfor wells in gas-condensate fields. In the Arunfield, which was operated by Mobil, nowExxonMobil, the loss in some wells was greaterthan 50%.7 In another case, Exxon, nowExxonMobil, reported two wells that died due tocondensate blockage.8 Shell and PetroleumDevelopment Oman reported a 67% productivityloss for wells in two fields.9

In another field, the initial productivitydecline has reportedly reversed. The productivityof wells in the moderately rich gas-condensatereservoir declined rapidly when bottomholepressures dropped below dewpoint. This declinecontinued until pressure throughout thereservoir dropped below dewpoint, then gasproductivity began to increase. Compositionalmodeling showed that condensate saturationincreased near the wells to approximately 68%,decreasing gas permeability and therefore gasproductivity. However, when pressure throughoutthe reservoir dropped below dewpoint, some

liquid dropped out everywhere. The gas movingtoward the wellbore was leaner and had lesscondensate to drop out in the near-well region,resulting in decreased condensate saturation toabout 55% and increased gas productivity.10 Thecondensate blockage decreased as the near-wellgas mobility increased.

Condensate BlockageNot all gas-condensate reservoirs are pressure-limited because of near-well condensateblockage, even though all of these fields willexperience condensate blockage. The degree towhich condensate dropout is a productionproblem depends on the ratio of the pressuredrop that is experienced within the reservoir tothe total pressure drop from distant areas of thereservoir to a control point at surface.

If reservoir pressure drop is significant, thenadditional pressure drop due to condensateblockage can be very important for welldeliverability. This condition typically applies ina formation with a low kh, the product ofpermeability and net formation thickness.Conversely, if little of the total pressure dropoccurs in the reservoir, typical of high kh

formations, then adding more pressure drop inthe reservoir due to condensate blockage willprobably have little impact on well deliverability.As a general guideline, condensate blockage canbe assumed to double the pressure drop in thereservoir for the same flow rate.

Conceptually, flow in gas-condensate fieldscan be divided into three reservoir regions,although in some situations not all three arepresent (next page).11 The two regions closest toa well can exist when bottomhole pressure isbelow the dewpoint of the fluid. The third region,away from producing wells, exists only when thereservoir pressure is above the dewpoint.

This third region includes most of thereservoir away from producing wells. Since it isabove the dewpoint pressure, there is only onehydrocarbon phase, gas, present and flowing.The interior boundary of this region occurswhere the pressure equals the dewpointpressure of the original reservoir gas. Thisboundary is not stationary, but moves outward ashydrocarbons are produced from the well andthe formation pressure drops, eventuallydisappearing as the outer-boundary pressuredrops below the dewpoint.

18 Oilfield Review

> Condensate blockage. Once bottomhole pressure in a well fallsbelow the dewpoint, condensate will drop out from the gas phase.Capillary forces favor having condensate in contact with the grains(inset, right). After a brief transient period, the region achieves attsteady-state flow condition with both gas and condensate flowing(inset, top). The condensate saturation, So, is highest near theowellbore because the pressure is lower, which means more liquiddropout. The oil relative permeability, kro, increases with saturation.oThe decrease in gas relative permeability, krg, near the wellboreillustrates the blockage effect. The vertical axis, represented by awellbore, is schematic only.

Distance from borehole

kro

So

ativ

e pe

rmea

bilit

yRe

l

0

0.5

1.0

0 0.5 1.0Condensate saturation

kkkkkrororokkkkkrgrgrgg

krg

Condensateflow channel

Sand grain

Gas flowchannel

Winter 2005/2006 19

In the second region, the condensate-buildupregion, liquid drops out of the gas phase, but itssaturation remains low enough that it isimmobile; there is still single-phase gas flow.The amount of liquid that drops out isdetermined by the fluid’s phase characteristics,as indicated by its PVT diagram. The liquidsaturation increases and the gas phase becomesleaner as gas flows toward the wellbore. Thisregion’s inner-boundary saturation usually isnear the critical liquid saturation for flow, whichis the residual oil saturation.

In the first region, closest to a producingwell, both gas and condensate phases flow. Thecondensate saturation here is greater than thecritical condensate saturation. This regionranges in size from tens of feet for leancondensates to hundreds of feet for rich

condensates. Its size is proportional to thevolume of gas drained and the percentage ofliquid dropout. It extends farther from the wellfor layers with higher permeability than averagesince a larger volume of gas has flowed throughthese layers. Even in a reservoir containing leangas with low liquid dropout, condensateblockage can be significant, because capillaryforces can retain a condensate that builds to ahigh saturation over time.

This near-well condensate blockage regioncontrols well deliverability. The flowingcondensate/gas ratio is essentially constant andthe PVT condition is considered a constant-composition expansion region.12 This conditionsimplifies the relationship between gas and oilrelative permeabilities, making the ratiobetween the two a function of PVT properties.

However, additional relative-permeabilityeffects occur in the near-well region because thegas velocity, and therefore the viscous force, isextreme. The ratio of viscous to capillary forcesis called the capillary number.13 Conditions ofpressure gradient caused by high velocity or lowinterfacial tension have high capillary numbers,indicating that viscous forces dominate, and therelative permeability to gas is higher than thevalue at lower flow rates.

At even higher flow velocities nearer thewellbore, the inertial or Forchheimer effectdecreases the gas relative permeabilitysomewhat.14 The basis of this effect is theinertial drag as fluid speeds up to go throughpore throats and slows down after entering apore body.15 The result is a lower apparentpermeability than would be expected fromDarcy’s law. The effect is usually referred to asnon-Darcy flow.

The overall impact of the two high-velocityeffects is usually positive, reducing the impact ofcondensate blockage. Laboratory corefloodexperiments are needed to measure the inertial and capillary number effects onrelative permeability.

Although the first indication of condensateblockage is typically a productivity decline, itspresence is often determined by pressuretransient testing. A pressure-buildup test can beinterpreted to show the distribution of liquidbefore the well is shut in. The short-timebehavior in the transient test reflects near-wellconditions. Condensate blockage is indicated bya steeper pressure gradient near the wellbore.With longer test times, the gas permeability farfrom the wellbore dominates the response;permeability can be determined from thederivative curve on a log-log plot of pseudo-pressure and shut-in time. If the test continueslong enough—and that shut-in test timedepends on the formation permeability—flowproperties far from the well will be evident.

Gas-Condensate Reservoir ManagementHistorically, condensate liquids have beensignificantly more valuable than the gas, andthis is still true in a few places far from a gasmarket or transport system. The pricedifferential made gas cycling a commonpractice. Injecting dry gas into a formation tokeep reservoir pressure above the dewpointslowly displaces valuable heavy ends that arestill in solution in the reservoir gas. Eventually,the reservoir is blown down; that is, the dry orlean gas is produced at a low bottomhole pressure.

7. Afidick et al, reference 1.8. Barnum RS, Brinkman FP, Richardson TW and

Spillette AG: “Gas Condensate Reservoir Behaviour:Productivity and Recovery Reduction Due toCondensation,” paper SPE 30767, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,October 22–25, 1995.

9. Smits RMM, van der Post N and al Shaidi SM: “AccuratePrediction of Well Requirements in Gas CondensateFields,” paper SPE 68173, presented at the SPE MiddleEast Oil Show, Bahrain, March 17–20, 2001.

10. El-Banbi AH, McCain WD Jr and Semmelbeck ME:“Investigation of Well Productivity in Gas-CondensateReservoirs,” paper SPE 59773, presented at the SPE/CERIGas Technology Symposium, Calgary, April 3–5, 2000.

11. Fevang Ø and Whitson CH: “Modeling Gas-CondensateWell Deliverability,” SPE Reservoir Engineering 11, no. 4(November 1996): 221–230.

12. In a constant-composition expansion condition, the fluidexpands with pressure decline and two phases may form,but no components are removed. This contrasts with thesecond region, which is considered a constant-volumedepletion region, because the liquid phase that formsdrops out from the gas phase and becomes trapped.

13. Henderson GD, Danesh A, Tehrani DH and Al-Kharusi B:“The Relative Significance of Positive Coupling andInertial Effects on Gas Condensate RelativePermeabilities at High Velocity,” paper SPE 62933,presented at the SPE Annual Technical Conference andExhibition, Dallas, October 1–4, 2000.Whitson CH, Fevang Ø and Sævareid A: “GasCondensate Relative Permeability for Well Calculations,”paper SPE 56476, presented at the SPE Annual TechnicalConference and Exhibition, Houston, October 3–6, 1999.

14. Forchheimer PH: “Wasserbewegung durch Boden,”Zeitschrift ver Deutsch Ingenieur 45 (1901): 1782–1788.

15. Barree RD and Conway MW: “Beyond Beta Factors: AComplete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media,” paper SPE 89325,presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

> Three reservoir regions. Gas-condensate field behavior can be dividedinto three regions once bottomhole pressure, PBH, drops below theHdewpoint pressure, PD. Far from a producing well (3), where the reservoirpressure is greater than PD, there is only one hydrocarbon phase present,Dgas. Closer to the well (2), there is a region between the dewpoint pressureand the point, r1, at which the condensate reaches the critical saturationfor flow. In this condensate-buildup region, both phases are present, butonly gas flows. Once condensate saturation exceeds the critical saturation,both phases flow toward the well (1).

Pres

sure

PD

PBH

r1

Dewpoint pressureDewpoint pressure

Reservoir pressureReservoir pressure

Distance

2 32 32 3reorbo

ell

We

W1

The price of gas has risen to a value thatmakes reinjection a less attractive strategy,unless the fluid is very rich in heavy ends. Gasinjection is now more commonly used as atemporary activity, until a pipeline or othertransport facility is built, or as a seasonalactivity during periods of low gas demand.

Operators also work to overcome condensateblockage. Some techniques are the same in agas-condensate field as they are in a dry-gasfield. Hydraulic fracturing is the most commonmitigating technology in siliciclastic reservoirs,and acidizing is used in carbonate reservoirs.Both techniques increase the effective contactarea with a formation. Production can beimproved with less drawdown in the formation.For some gas-condensate fields, a lowerdrawdown means single-phase production abovethe dewpoint pressure can be extended for alonger time.

However, hydraulic fracturing does notgenerate a conduit past a condensate saturationbuildup area, at least not for long. Once thepressure at the sandface drops below thedewpoint, saturation will increase around thefracture, just as it did around the wellbore.

Horizontal or inclined wells are also beingused to increase contact area within formations.The condensate still builds up around theselonger wells, but it takes a longer time. Theproductivity of the wells remains high longer,but the benefit must be weighed against theincreased well cost.

Some operators have tried shutting in wellsto allow time for the gas and condensate torecombine, but fluid phase behavior generallydoes not favor this approach. Separation of afluid into a gas and liquid phase in the two-phase region of the phase diagram happens

quickly, and after this the phases tend tosegregate, either within a pore or on a largerscale. This phase separation dramatically slowsthe reverse process of recombining gas andliquid. This reversal requires immediate contactbetween the gas and liquid phases.

Another method, cyclic injection andproduction from one well, sometimes called huffand puff injection, uses dry gas to vaporizecondensate around a well and then produce it.This can have short-term benefit for increasedproductivity, but the blockage returns whenproduction begins again and the formation dropsbelow the dewpoint pressure of the currentgas mixture.

In a field test, methanol solvent was injectedinto Hatter’s Pond field, Alabama, USA. In thisfield, production of a gas condensate comesmainly from the lower Norphlet sandstone, butthe field also produces from the Smackoverdolomite. Wells in Hatter’s Pond field are about18,000 ft [5,490 m] deep with 200 to 300 ft [60 to90 m] of net pay. Gas productivity had declinedby a factor of three to five because of condensateand water blockage. The operator, Texaco (nowChevron), pumped 1,000 bbl [160 m3] ofmethanol down tubing at a rate of 5 to 8 bbl/min[0.8 to 1.3 m3/min] into low-permeabilityformations.16 The methanol treatment removesboth oil and water through a multiple-contactmiscible displacement.17 As a result of thetreatment, gas production increased by a factorof three initially, then stabilized at 500,000 ft3/d3

[14,160 m3/d], a factor of two over thepretreatment rate. Condensate productiondoubled to 157 bbl/d [25 m3/d]. Both gas andcondensate rates persisted for more than10 months after treatment.18

Treatment methods have been suggested forremoving condensate blockage through injectionof surfactants mixed with solvents to alterwetting preference in the reservoir. This topicwill be discussed later in this article.

Remobilizing Stranded CondensateThe Vuktyl gas-condensate field in the KomiRepublic, Russia, has been in production since1968. Although productivity was not severelyimpacted by condensate blockage in the field, asignificant amount of condensate dropped out inthe carbonate reservoir. Several condensaterecovery pilots were run in this field.

The field is a long anticline with productionfrom the Middle Carboniferous Moscow andBashkir sequences (above left). The 1,440 m[4,724 ft] thick structure comprises alternating

20 Oilfield Review

> Vuktyl field, Russia. The Vuktyl field in the Komi Republic in western Russia (top) is an anticline,80 km [50 mi] long and up to 6 km [3.7 mi] wide (bottom). The Roman numerals denote gas-processingfacility collection areas. The fluid is predominantly methane [C1], but with a significant amount ofintermediate hydrocarbon components and nitrogen (table, right). The field has three lithotypestt(table, left).tt

0 mi 4

Komi

RRRRRR U S S II I I S S S S S S S S S U U U U U

AAAAAA

ComponentComposition,

% by molevolume

C2

C1

C3

C4

C5+

N2

74.68.93.81.86.44.5

Porosity, %Permeability, mDTypeFine porosity, microvugs, microfracturedPorous, microvugs, microfracturedFractured, microvugs, porous 0.1 to 4513

0.01 to 0.1<0.1 0.1 to 3

3 to 6>6

Winter 2005/2006 21

limestone and dolomite layers, with an averageinterbed thickness of 1.5 m [5 ft]. The reservoirproperties vary widely throughout the field, butthe field has been divided into seven paysequences of three basic types. All three typeshave microfractures and microvugular porosity.Fine pores, low permeability and low porositydistinguish the first type. The third type hasfractures large enough to contribute topermeability. The other type is intermediate.

At discovery, reservoir conditions were36 MPa [5,200 psi] and 61°C [142°F], with 77.5%initial gas saturation. There is a small rimcontaining light oil. Initial gas in place wasabout 430 x 109 m3 [15 x 1012 ft3] and initialcondensate was about 142 million metric tons[1,214 million bbl].19 The initial, stable,producing condensate/gas ratio was 360 g/m3

[87.1 bbl per million ft3].20 The field has anunderlying aquifer, but the water drive wasinsignificant and laterally uneven.

The complex geology of the field, includinghigh-permeability zones that could have acted asthief zones, led the operator, Gazprom, to developthe field with no gas cycling, using depletion gasdrive as the primary production mechanism.

Approximately 170 vertical wells at a typicalspacing of 1,000 to 1,500 m [3,280 to 4,920 ft]were placed in an irregular triangular grid. Mostof the production wells had 10-in. intermediatecasing and 65⁄5

8⁄⁄ -in. production casing. Severalprolific wells had larger, 7 ⁄5⁄⁄ -in. production casing,

allowing 4 ⁄5⁄⁄ -in. tubing. Typical completions in the500- to 800-m [1,640- to 2,625-ft] producing zonewere perforated casing, but some wells usedscreen or openhole completions. The deepestproducers were drilled about 100 to 150 m [328to 492 ft] above the gas/water contact. Atwo-stage hydrochloric acid treatment was themain method of well stimulation.

After nine years, the production plateau was19 x 109 m3/yr [671 x 109 ft3/yr]. A peak stablecondensate production of 4.2 million tons/yr [36 million bbl/yr] occurred during thesixth year of development.

Currently, the Vuktyl field is in its finaldevelopment phase. Reservoir pressure is 3.5 to5 MPa [508 to 725 psi]. Approximate fieldrecoveries are 83% of the gas and 32% of thecondensate, so about 100 million tons[855 million bbl] of condensate remain inthe field.

Experts from Severgazprom, a part of theGazprom Russian Joint Stock Company, and theVNIIGAZ and SeverNIPIgaz institutes conducteda variety of pilot projects in Vuktyl field torecover additional condensate. In 1988, thecompany began the first pilot experiment, usinga solvent to recover stranded condensate.21 Thepilot included six producers, one injection welland three monitor wells (above). The solvent,25,800 tons [293,000 bbl at formation

conditions] of a mixture of propane [C3] andbutane [C4], was injected into the formationfollowed by 35 million m3 [1.24 x 109 ft3] ofseparator gas.22 The intent was to recovercondensate through miscible displacement ofthe solvent bank.

Geophysical observations conducted duringthe experiment indicated that solvent andinjected gas entered the producing intervals ofthe injection well unevenly. Component analysesof samples from the production and monitorwells indicated solvent and injected gas brokethrough only in the two closest monitor wellsand in none of the production wells. Two eventswere seen in these two monitor wells, a changein condensate/gas ratio from 43 to 65 g/m3 [10.4to 15.7 bbl per million ft3] with a decline to theinitial ratio, followed by a second increase from43 to 54 g/m3 [to 13 bbl per million ft3].

Production logging in the monitor wellsrevealed two-phase flow—gas and solvent—onlyin the bottom part of the productive section.Overall, 95% of the solvent was produced from thetwo monitor wells, but condensate recovery wasonly about 0.4%. The pilot study concluded thatthe propane and butane solvent bank was notsufficiently effective in recovering condensate.

A different recovery method, injecting drygas, began in the Vuktyl field in 1993. The gas,from a trunk pipeline that originated in theTyumen district, is injected under pipelinepressure at 5.4 to 7.4 MPa [780 to 1,070 psi]

16. Al-Anazi HA, Walker JG, Pope GA, Sharma MM andHackney DF: “A Successful Methanol Treatment in aGas-Condensate Reservoir: Field Application,” paper SPE 80901, presented at the SPE Production andOperations Symposium, Oklahoma City, Oklahoma, USA,March 22–25, 2003.

17. In a miscible displacement, a solvent allows fluids to mixfreely in a homogeneous mixture. Multiple-contactmiscibility requires sufficient mass transfer between thesolvent and hydrocarbons to achieve miscibility.

18. Al-Anazi et al, reference 16.19. Zhabrev IP (ed): Gas and Gas-Condensate Fields—

Reference Book. Moscow: Nedra, 1983 (in Russian).kTer-Sarkisov RM: The Development of Natural Gas Fields.Moscow: Nedra, 1999 (in Russian).Conversion from mass to volume is based on condensatedensity of 8.55 bbl/ton.

20. Vyakhirev RI, Gritsenko AI and Ter-Sarkisov RM: TheDevelopment and Operation of Gas Fields. Moscow:sNedra, 2002 (in Russian).

21. Ter-Sarkisov RM, Gritsenko AI and Shandrygin AN:Development of Gas Condensate Fields UsingStimulation of Formation. Moscow: Nedra, 1996(in Russian).Vyakhirev et al, reference 20.

22. For more on the role of propane in lowering the dewpointof a gas-condensate field: Jamaluddin AKM, Ye S,Thomas J, D’Cruz D and Nighswander J: “Experimentaland Theoretical Assessment of Using Propane toRemediate Liquid Buildup in Condensate Reservoirs,”paper SPE 71526, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, September 30–October 3, 2001.

> Plan view with depth to the formation top at a solvent-injection pilotproject near gas-processing facility number 1 (GPF-1). Propane and butanewere injected into Well 103, followed by separator gas. Six productionwells—designated 91, 92, 93, 104, 105 and 106—and three monitor wells—designated 38, 256 and 257—made up the pilot study area. Solvent wasobserved and produced only from the two closest monitor wells: Wells 38and 256.

2 32,30000

2 4002,4002 5002,500

2 6002,600

2 7002,7002 8002,800

2 9002,9003 000 m3,000 m

64

90

95

1011011 1021515

159

66 93

2573838

103

104

256

105

92

9186

12

1919

264

106

GPF-1

Pilot areaProduction well

Injector wellMonitor well

without local compression.23 Formation gas,which is in equilibrium with the retrogradecondensate, is replaced by injected dry gas. Thelight C2 to C4 components and intermediate C5+

fractions evaporate into the dry gas.24 Thus,recovery is improved both by producing moreformation gas, which still contains componentsother than methane, and by vaporizing strandedliquids and producing them along with theinjected gas. In addition, the injected gas causesno problems for the production facilities when itbreaks through. However, a significant volume ofdry gas has to be injected to produce tangibleamounts of condensate.

Engineers monitored the process in bothinjection and production wells using gas-liquidand gas-adsorption chromatography (below).25

Since the injection gas did not contain nitrogen,the nitrogen content was used as the indicatorof formation gas.26

The 1993 pilot test program was expanded toadditional pilot locations in 1997, 2003 and 2004.By the middle of 2005, the operator had injected10 x 109 m3 [354 x 109 ft3] of dry gas into thepilot wells, and recovered a significant amountof liquid. Comparing the recovery with estimatesof production through depletion alone showedthat the pilot area produced an additional

785 thousand tons [9.45 million bbl] of C2 to C4

and 138 thousand tons [1.22 million bbl] of C5+.27

The operators also ran single-well pilotprojects in Vuktyl field. Although blockage wasnot severe enough to cause a dramatic drop inproductivity in this field, the operator soughtways to counteract the increased saturation thathad formed around wells. The treatmentincluded injecting solvent—a mix of ethane andpropane—into a well, followed by dry gas. Aftera sufficient volume of injection, the well wasreturned to production.

When the solvent contacts the trappedcondensate, the solvent, formation gas andcondensate mix freely into a single phase. Thedry gas that follows is able to mix freely with thesolvent mixture. Thus, when the well producesagain, the injected gas, solvent and condensateare produced as a single fluid. As a result,the condensate saturation is at or near zero inthe treated zone. As formation gas follows themixture back through the treated zone, a zone ofincreased condensate saturation will reform,but well productivity can be improved byperiodic treatments.

Treatment volumes ranged from 900 to2,900 tons [10,240 to 33,000 bbl] of solvent and1.2 to 4.2 million m3 [42 to 148 million ft3] of drygas.28 Although the effectiveness varied from wellto well, the treatments generally had goodresults. The productivity of four of the wellsincreased by 20% to 40% over a period rangingfrom 6 months to 1.5 years, followed by a declineto the original production levels (next page).

Modeling Condensate BlockageReservoir-simulation models are commonly usedto predict the performance of gas-condensatefields. The models incorporate rock and fluidproperties to predict the dynamic influence ofcondensate blockage on gas and condensateproduction. However, a typical gridblock of afull-field model (FFM) can be much larger thanthe blockage zone, so a coarse grid model maysignificantly overestimate well deliverability.

The most accurate way to determine near-well behavior of a gas-condensate field is byusing a simulator with a fine grid. There are twoways to do this: use a FFM with local gridrefinement (LGR), or use a single-well modelwith a fine grid near the well.

Modern simulators, such as the ECLIPSE 300reservoir simulation software, include capabilityfor LGR. Small gridblocks can be used nearwellbores or other features—such as faults—that can significantly impact local flow. Farther

22 Oilfield Review

> Dry-gas injection pilot. Separator gas injected into three wells— designated 269, 270 and 273—vaporized stranded condensate for production from surrounding wells (top). Dry gas (blue) broketthrough a few months after the pilot began (middle). Nitrogen in the produced gas (green) graduallydecreased, indicating that less formation gas was being produced. The liquid C5+ fraction (red)indicates a slow decline after gas breakthrough. The results show significant production of formationgas, light (C2 to C4) and intermediate components (C5+) from both produced formation gas andremobilized stranded condensate (table, bottom).

Oct93

Jan94

April94

July94

Oct94

Jan95

April95

July95

Oct95

Jan96

April96

July96

Oct96

Jan97

April97

July97

Oct97

Jan98

Com

pone

nt c

onte

nt, m

ole

%

0

1

2

3

4 40

30

20

10

0

Gas

fract

ion,

%

Date

Component from:

Formation gas,million m3

Formation gas,thousand tons

Strandedcondensate,

thousand tonsDry gas,

million m3

5,9731,996

380238208

Produced gasInjected gas

Produced C2 to C4Produced C5+

10,0357,366

130

270129

2697

195

158

273

133

254151

128

127

100

2,700 m2,700 m2 6002,6002,5002,5002,4002,4002 3002,300

2,2002,2002,1002,100

2,1002,1002,2002,2002,3002 300

131/150132

Injector wellProduction wellPilot area

Winter 2005/2006 23

away from such features, the gridblocks grow toa size typical of a FFM. The cost of using LGRmay be a significant increase in computationtime in some cases.

Another way to examine gas-condensateblockage effects is by using a single-well model.In many cases, radial symmetry allows a well tobe treated in a two-dimensional model, using thedimensions of height and radial distance. Thegridblocks nearest the well are small, nominallyhalf a foot [about 15 cm] in the radial direction.The radial dimension increases with eachgridblock away from the wellbore, until itreaches a maximum size used for the rest of themodel. The fine grid provides good resolutionwhere the flow is highest and the formationsaturation behavior is at its most complex.Capillary, viscous and inertial forces can beappropriately modeled. Far from the wellbore,conditions of pressure and flow can be takenfrom a FFM and applied as boundary conditions.

Sometimes, gas-condensate reservoirsimulations can be performed using a black-oilmodel. This type of model assumes that thereare only two hydrocarbon components in thefluid, oil and gas, and it allows for somepressure-dependent mixing of gas in oil. Thismodel is inappropriate when the compositionschange significantly with time, such as throughgas injection, or when there is a significantcompositional gradient. In those cases, acompositional model with many hydrocarboncomponents is necessary. In addition, some

black-oil models do not include capillarynumber effects, which are important fordetermining well deliverability.

Another way to account for condensateblockage in a full-field model is through the useof pseudopressures. The equation for flow of gasfrom a reservoir to a wellbore can be expressedin terms of a pseudopressure, which is anintegral over pressure. By separately treatingthe three regions described before—two-phaseflow near the well, gas flow with condensatebuildup next, and single-phase gas flow far fromthe well—it is possible to calculate thepseudopressure from the producing gas/oil ratio,PVT properties of the fluid, and gas and oilrelative permeabilities.29 As discussed previously,the constant-composition expansion condition inthe first region simplifies the relative-permeability ratios. This pseudopressuremethod adds little time to running a FFM.

Pseudopressure methods have also beenimplemented in spreadsheet format.30 Thesespreadsheets assume a homogeneous reservoirand a simple black-oil model. They provide fastpredictions that can be used when manysensitivity runs are necessary. A similarsemianalytical method was combined with theeffects of non-Darcy flow and permeabilitylayering. Comparisons using a compositionalsimulator with a fine grid showed that the semianalytical method captured all thenear-well effects accurately and was easy toembed in a FFM at essentially no increase incomputational time.31

Modeling Behavior Around a FractureReservoir simulation modeling was used todetermine the effectiveness of fracturing in theSW Rugeley field in south Texas, USA. Thisfield produces gas condensate from low-permeability—about 1-mD—Frio sand. A well inthis field, which was drilled and completed byWagner & Brown, was hydraulically fracturedinitially, but a rapid decline in productivity ledthe company to refracture the formation aboutthree months later, in June 2002. Productivityimproved, but then continued to decline overthe next few months. The drawdown in thevicinity of the well was below the dewpointpressure, so the company investigated the accumulation of condensate saturationaround a fracture.

Engineers at Schlumberger developed ahomogeneous, radially symmetric, single-wellmodel. This simple model demonstrated thatcondensate blockage could result in a rapidfalloff in productivity. It also provided a meansto quickly check the impact of permeabilityreduction due to compaction caused by pressure decline.

23. Ter-Sarkisov RM, Zakharov FF, Gurlenov YM, Levitskii KOand Shirokov AN: Monitoring the Development of Gas-Condensate Fields Subjected to Dry Gas Injection.Geophysical and Flow-Test Methods. Moscow: Nedra,s2001 (in Russian).Dolgushin NV (ed): Scientific Problems and Prospects ofthe Petroleum Industry in Northwest Russia, Part 2: TheDevelopment and Operation of Fields, ComprehensiveFormation and Well Tests and Logs, A Scientific andTechnical Collection. Ukhta: SeverNIPIgaz, 2005 (in Russian).Vyakhirev et al, reference 20.Ter-Sarkisov et al, reference 21.Ter-Sarkisov, reference 19.

24. For a laboratory study of methane injection into coreswith condensate saturation: Al-Anazi HA, Sharma MMand Pope G: “Revaporization of Condensate withMethane Flood,” paper SPE 90860, presented at theSPE International Petroleum Conference, Puebla,Mexico, November 8–9, 2004.

25. Dolgushin, reference 23.26. Vyakhirev et al, reference 20.27. Dolgushin, reference 23.28. Gritsenko AI, Ter-Sarkisov RM, Shandrygin AN and

Poduyk VG: Methods of Increase of Gas CondensateWell Productivity. Moscow: Nedra, 1997 (in Russian).yVyakhirev et al, reference 20.The density of the solvent mixture is 553 kg/m3.

29. Fevang and Whitson, reference 11.30. Mott R: “Engineering Calculations of Gas-Condensate-

Well Productivity,” SPE Reservoir Evaluation &Engineering 6, no. 5 (October 2003): 298–306.

31. Chowdhury N, Sharma R, Pope GA and Sepehrnoori K:“A Semi-Analytical Method to Predict Well Deliverabilityin Gas-Condensate Reservoirs,” paper SPE 90320,presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

> Changes in well productivity as a result of injection of ethane andpropane followed by dry gas. The difference of the squares of the reservoirpressure, PR, and the bottomhole pressure,R PBH, as the flow rate increasesHprovides a measure of productivity. Before treatment (blue), the wellrequired a larger pressure difference to produce than it needed afterttreatment (red). Four months after treatment, productivity had degradedslightly (green), but it was still significantly better than productivity beforetthe treatment.

P2 Rese

rvoi

r - P

r2 Bo

ttom

hole

, MPa

2

0

4

8

12

16

0 50 100 150 200 250

Gas-condensate mixture production, thousand m3/d

With these results in hand, Wagner & Brownhad Schlumberger develop a more detailedreservoir model, using ECLIPSE 300 reservoirsimulation software (above). The model wasrefined by history-matching to the gasproduction rate, which also provided a goodcorrelation to the condensate production.Drawdown in the fracture induced the buildupof condensate saturation along the fracture(next page). The average reservoir pressuredropped below the 6,269-psi [43.22-MPa]dewpoint pressure during the modeled period.

With a good history-match, Wagner & Browncould determine whether the fracture providedsignificant gains in productivity. The model wasrerun without the fracture, which resulted in aproduction curve that continued the previousdecline rate (left). The difference between thenonfractured case and the measured productionindicates the success of the fracture job. Over aseven-month period, the cumulative productionattributed to the fracture job was 256 million ft3

[7.25 million m3] of gas and 15,300 bbl [2,430 m3]of condensate. This modeling study verified thesuccess of a field application.

24 Oilfield Review

> History-match of model of SW Rugeley field with a hydraulic fracture. The ECLIPSE 300 model of one well in the Frio sand has small grids around thewell and along the fracture (top left). Smaller grids were also placed at the fracture tips. The field gas-rate history was matched by the simulation (tt topright), yielding good results for condensate rate (tt bottom right). The changes in production after the fracture job were due to fracture cleanup andttchanges in pressure in flowlines. The model indicated the average reservoir pressure dropped below the 6,269-psi dewpoint pressure during thisproduction period (bottom left).tt

Fracture Well

Mar2002

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Aver

age

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> The hydraulic fracture effect. Rerunning the Frio well model with no fracture generated a simpledecline curve indicating a significant productivity increase could be attributed to an induced fracture.

Mar2002

April2002

Production historyModel with no fracture

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Winter 2005/2006 25

2,500

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< C d bl k dCondensate blockage around afracture, Frio model. For each timestep, model results indicatepressure decline (top), condensatesaturation (middle) and gas relativepermeability (bottom). The first twottime steps in July 2002 (left) focustton the immediate vicinity of thefracture and the later three timesteps (below) show a wider viewwof the whole model area. Pressuredeclines rapidly along the fracture(left, top). The approximate dewpointpprofile (oval curves) expands outwardfrom the fracture. The low gaspermeability around the fracture at later time steps indicates thecondensate blockage.

Application of Best PracticesChevron recently completed a study of five gas-condensate reservoirs that are at differentstages of development. The objective was totransfer best practices among variousdevelopment teams.

One of the fields in the study, a North Seareservoir, is a marine turbidite with gross-payinterval of more than 120-m [400-ft] thickness.The average reservoir permeability is 10 to15 mD, with average porosity of 15%. Theoriginal reservoir pressure of 6,000 psi[41.4 MPa] is a few hundred psi [a few Mpa]above the dewpoint pressure, although thedewpoint varies from east to west.32

The bottomhole pressure was below thedewpoint from first production. Thecondensate/gas ratio ranged from 70 bbl permillion ft3 [393 m3 per million m3] in the east to110 bbl per million ft3 [618 m3 per million m3] inthe west. Some wells experienced a productivityreduction of about 80%, most of which occurredin early production.

Chevron followed a step-by-step procedure tounderstand and history-match the field’s gas-condensate behavior. The operator selected coresamples that spanned the range of permeabilityand porosity of the field and fluids that mimicreservoir-fluid behavior—liquid dropout as afunction of pressure, viscosity and interfacialtension—at lower temperature. The companymeasured relative permeability over a rangeof flow conditions and fitted those datato several relative-permeability models for usein simulators.

A spreadsheet using an analyticalpseudopressure method was used to calculatedeliverability. The calculation showed thatproductivity index (PI) decreased from about 80 to about 15 thousand ft3/d/psi [33 to 6 thousand m3/d/kPa], with little differencebased on bottomhole pressure until late in fieldlife (above).

A detailed single-well, compositional flowsimulation using the Chevron CHEARS reservoirsimulator was performed with realistic geology.Far-field boundary conditions came from a full-field model. The simulation honored wellproduction practices and differential depletionin the field. The predictions provided a goodmatch to results from three vertical wells andone inclined well (next page).

This study led to several initiatives in thefield. Hydraulic fracturing to improveproductivity is an active effort in this field, sothese models are being used to betterunderstand fracture effectiveness. In addition,lessons learned from this field regarding theimpact of condensate blocking have been usedextensively in planning for wells in new projectsin other gas-condensate fields.

A Fundamental AlterationThe high price of natural gas on world marketsin recent years has stimulated interest indeveloping gas reservoirs. Companies seek newways to optimize their gas-condensate resources.

Hydraulic fracturing can mitigate the effectof condensate blockage, but it does noteliminate the accumulation of condensate in

26 Oilfield Review

> Spreadsheet model results for a North Sea well. A homogeneous single-well model in a spreadsheetprovided a way to quickly examine different effects. For example, the bottomhole pressure had littleeffect on gas productivity index, PI.

0

10

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40

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hous

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32. Ayyalasomayajula P, Silpngarmlers N and Kamath J:“Well Deliverability Predictions for a Low PermeabilityGas Condensate Reservoir,” paper SPE 95529, presentedat the SPE Annual Technical Conference and Exhibition,Dallas, October 9–12, 2005.

33. Fahes M and Firoozabadi A: “Wettability Alteration toIntermediate Gas-Wetting in Gas/Condensate Reservoirsat High Temperatures,” paper SPE 96184, presented atthe SPE Annual Technical Conference and Exhibition,Dallas, October 9–12, 2005.

34. Kumar V, Pope G and Sharma M: “Improving Gas andCondensate Relative Permeability Using ChemicalTreatments,” paper SPE 100529, to be presented at the SPE Gas Technology Symposium, Calgary, May 15–18, 2006.

Winter 2005/2006 27

areas where the pressure in the formation isbelow dewpoint. Dry gas and solvent injectionsare able to mobilize some condensate, but theliquid saturation profile near a producing wellreforms and the blockage effect returns.

New alternatives are being examined inlaboratories. For example, some studies havefocused on ways to prevent fluid buildup byaltering reservoir-rock wettability.

Although mineral surfaces such as quartz,calcite and dolomite prefer to be wetted byliquids rather than gas, there are solids thathave a gas-wetting preference. In particular,fluorinated compounds such as Teflon surfacesare gas-wetting. So, fluorinated solvents havebeen used to alter the wettability of cores.Recently reported results at high temperature—140°C [284°F]—typical of gas-condensatereservoirs showed a strong reversal of wetting ina gas-water-reservoir rock system, but was lesssuccessful in a gas-oil-reservoir rock system.33

Researchers at the University of Texas atAustin conducted laboratory tests using 3Mfluorocarbon surfactants.34 The results onreservoir core samples blocked by condensateindicate about a doubling of the gas andcondensate relative-permeability values aftertreatment. Based upon these promisinglaboratory data, Chevron may test this treatmentin a blocked gas-condensate well sometime in2006. Treatments such as these must be fieldtested under a variety of conditions to fullydevelop and prove the technology. If thetechnique is ultimately successful, then the costof the surfactants used in the treatment will bevery small compared to the benefits of increasedgas and condensate production rates.

The alteration these solvents make in therock addresses a fundamental cause ofcondensate blockage: capillary accumulation ofliquid because of the wetting preference of therock. Avoiding liquid buildup alleviates theproblem of choking production, so that a highproduction rate can be achieved. —MAA

> Single-well simulation results. The simulator gave a good match to bothgas PI (top) and bottomhole pressure (middle) for behavior in a North Seawell. Different layer properties resulted in different extents of condensatesaturation buildup (bottom).

Gas

PI, t

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Si l iSimulation

Oil saturation, fraction0 0.40.2

Bore

hole

3.5 4.0 4.5 5.0 5.5

3.5 4.0 4.5 5.0 5.5

Abderrahmane BoumaliSonatrachAlgiers, Algeria

Mark E. BradyDoha, Qatar

Erik FerdiansyahSanthana KumarStan van GisbergenPetroleum Development Oman Muscat, Oman

Tom Kavanagh Sharjah, United Arab Emirates

Avel Z. OrtizSugar Land, Texas, USA

Richard A. OrtizBP Sharjah Oil CompanySharjah, United Arab Emirates

Arun PandeyMuscat, Oman

Doug Pipchuk Calgary, Canada

Stuart WilsonMoscow, Russia

Winter 2005/2006 29

Many operating companies are turning tothrough-tubing, or concentric, operations tosolve difficult production problems and to meetdemanding well-intervention or wellbore-recompletion challenges. Steeply decliningproduction output and insufficient replacementof oil and gas reserves have compelled operatorsto reexamine field-development strategies andreservoir-management efforts. Increasingly, assetmanagers need to optimize the performance ofboth new and existing wells to meet globaldemand for petroleum.

Long strings of relatively small-diameter steelpipe, or coiled tubing, can be mobilized quickly todrill new wells or reenter wells through existingwellbore tubulars. This technology also is used toperform initial completions, remedial interven-tions and workovers, or recompletions. Comparedwith conventional rotary drilling, workover andsnubbing units, coiled tubing spooled onto a reelfor transport and the associated surfaceequipment for deployment and well insertion offerseveral advantages.

Increased efficiency comes throughcontinuous pipe deployment and retrieval underpressure, or “live” conditions, without having tocontrol, or kill, a well. In addition, there is noneed to pull production tubulars from thewellbore and perform downhole operations byrerunning individual joints of a conventionalworkstring with threaded connections.

The capability of working under pressure andthe unique ability to pump fluids at any time,regardless of coiled tubing depth or direction oftravel in a wellbore, offer distinct benefits andoperational flexibility. Compared with wireline or

slickline, coiled tubing provides relatively highload capacities for deeper vertical or extendedhigh-angle reach, and for greater tensilecapacity, or overpull, downhole.

These capabilities facilitate wellborecleanouts; jetting or lifting wells with inert gases or lighter fluids; perforation washes; acidand hydraulic fracturing stimulations, sand-consolidation or sand-control treatments;cementing; fishing or milling; and both direc-tional and underbalanced drilling. Installingwireline, data or power cables inside a string ofcoiled tubing allows real-time well logging,downhole monitoring and control, measurementswhile drilling and operation of electricalsubmersible pumps.1

Using application-specific downhole systems,coiled tubing concentric operations are helpingoperators increase well and field productivitythroughout the entire life cycle of producingreservoirs. Even under adverse economicconditions and harsh subsurface operatingenvironments, coiled tubing facilitates cost-effective interventions that can optimizehydrocarbon output from wells, increase reserverecovery from reservoirs and greatly improvefield profitability.

Coiled tubing is a viable alternative in manydemanding applications that must be performedwithout a rotary drilling rig or workover unit tomaximize profitability. New integrated systemsand innovative combinations of tools andtechniques have been keys to recent success usingcoiled tubing in several specialized applications.

Coiled Tubing: Innovative Rigless Interventions

Reentry drilling, reservoir stimulation and wellbore recompletions often need to be performed

without rotary rigs or conventional workover units as a means of maximizing production economics.

Coiled tubing allows remedial operations to be performed under pressure, or “live” conditions,

without pulling well tubulars. Collaboration between operators and providers of this technology

continues to yield tools and techniques that improve productivity in both new and mature fields.

For help in preparation of this article, thanks to Fardin AliNeyaei, Ruwi, Oman; and Allan Lesinszki, Talisman EnergyCompany, Calgary, Alberta, Canada.Blaster MLT, CoilFLATE, DepthLOG, Discovery MLT,Jet Blaster, NODAL and Secure are marks of Schlumberger.Allen-Bradley and FrontView are marks of Allen-BradleyCompany, Inc.

28 Oilfield Review

This article begins with an overview of coiledtubing equipment and practices that are beingused for underbalanced drilling in the MiddleEast. We then present a new downhole systemthat was used to locate and stimulate individuallateral branches of multilateral wells in Canada.That discussion is followed by a case history fromAlgeria demonstrating selective isolation andstimulation of closely spaced intervals. Thearticle concludes by presenting a methodology forperforming multiple through-tubing operationsduring a single rig-up and wellsite operation.

Underbalanced Reentry Drilling The Sajaa field in the United Arab Emirates(UAE) produces from a deep, low-pressurecarbonate reservoir. Amoco, now BP, drilled thefirst wells in this prolific gas field during theearly 1980s. Initial development activity involvedabout 40 vertical wells drilled with overbalancedpressures by conventional rotary rigs. Later,many of these wells were recompleted withcemented 7-in. liners tied back to surface and5-in. production tubing without a downholepacker (right).

During the 1990s, BP Sharjah sidetracked afew of these wells using rotary rigs andunderbalanced drilling techniques. Morerecently, this experience was helpful duringplanning and implementation of a new infilldrilling campaign. As reservoir pressure and wellproductivity declined, BP needed to accessreserves in areas that were not being drainedeffectively by the original wellbores.

A team of BP personnel from North SlopeAlaska operations, Houston EngineeringTechnical Practices (ETP), UK ETP, SunburyResearch and Sharjah engineering and operationsgroups evaluated several methods for reenteringwells and drilling underbalanced. They foundcoiled tubing to be the best option. In March 2003,BP Sharjah began drilling multilateral sidetracksfrom existing wellbores using coiled tubing forunderbalanced operations.2

The BP team chose 2 ⁄3⁄⁄ -in. outside diameter(OD) coiled tubing with an internal wirelinecable as a means of continuously transmittingdownhole data and measurements to surface.Initially, BP used an 80,000-psi [552-MPa] yieldstrength, uniform wall thickness tube that couldbe swapped end for end, or reversed, on the spool

30 Oilfield Review

2. Kavanagh T, Pruitt R, Reynolds M, Ortiz R, Shotenski M,Coe R, Davis P and Bergum R: “Underbalanced CoiledTubing Drilling Practices in a Deep, Low-Pressure GasReservoir,” paper IPTC-10308-PP, presented at theSPE Annual Technical Conference and Exhibition, Dallas,October 10–12, 2005.

> Typical wellbore configuration in the Middle East Sajaa gas field. BP SharjahOil Company initiated coiled tubing underbalanced reentry drilling operationsfrom existing wellbores in the Sajaa gas field of the United Arab Emirates (top).Most of these wells had been recompleted with cemented 7-in. liners tied backtto surface and 5-in. production tubing (bottom left). A few wells were reenteredttin the 1990s to drill lateral sidetracks with conventional rotary rigs andunderbalanced drilling techniques (bottom right).tt

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30-in. casing at 100 ft

13 3⁄3 4⁄⁄ g-in. casing at 6,000 ft

9 5⁄5 8⁄⁄ -in. casing at 11,000 ft

7-in. packer at 12,000 ft

5-in. tubing

7-in. whipstock 6-in. bit

4 3⁄3 4⁄⁄ -in. motor

3 1⁄1 2⁄⁄ -in. drillpipe

7-in. liner at 14,000 ft

20-in. casing at 600 ft

Winter 2005/2006 31

to extend fatigue, or usable, life. This stringdesign evolved to a 90,000-psi [620-MPa] yieldtapered-wall tube with high yield strength andsufficient hydrogen sulfide [H2S] resistance. Thefootage that could be drilled with these taperedstrings was found to be acceptable even thoughthe tapered strings could not be reversed.

Tapered strings minimize loads on thesurface injector head, reduce pickup weightsduring normal operations and increase availableoverpull downhole in stuck-pipe situations. Lessweight on bit (WOB) is available for drillingcompared with the uniform-wall strings, but thishas not been a disadvantage because of therelatively soft formations in this area andsuccessful efforts to optimize bit performance.

Most laterals are limited in length becausethe pickup weight at total depth (TD) becomestoo high, not because of limited WOB. Inaddition, drilling longer laterals may berestricted by increased friction pressures whiledrilling, which cause a higher equivalentcirculating density and a degree of overbalanceat the bit that formations can no longer tolerate.

A coiled tubing drilling tower builtspecifically for Sajaa field operations supportedthe coiled tubing injector; the wellhead andblowout preventer (BOP) stack supported theweight of the coiled tubing string (right).

The tower work decks were positioned foreasy access to BOP systems, which provide dualbarriers while deploying tools under pressureand drilling underbalanced. The BOP system alsoprovides two mechanical barriers duringnonroutine events, such as elastomer-sealfailures or leaking BOP rams, and other minor contingencies.

A hydraulically operated choke manifold onthe fluid-return line controls flow from thewellbore and downhole pressure during drillingoperations. This manifold is fitted withredundant isolation valves for each of the twochokes to maintain constant flow even if one sidebecomes plugged or inoperable. All of thecommon drilling contingencies and well-controlsituations that have occurred have been handledsafely using these surface systems.

If gas went directly to the pipeline, high linepressure might preclude underbalanced opera-tions on many Sajaa field wells. Therefore,produced gas from returning fluids is sent to avertical flare stack or to a compression system.Sending gas to the Sajaa processing plant whiledrilling minimizes lost or deferred production.

> Sajaa field surface equipment for coiled tubing. Schlumberger built a four-piece coiled tubing drilling tower specifically for the Sajaa project (top).This modular structure supports only the injector head. It was designed towithstand maximum sandstorm winds, but is lightweight for easy transportand setup. The blowout preventer (BOP) stack (bottom), which ensuresdouble pressure barriers at all times, and the wellhead support the weightof the coiled tubing string.

-in. shear/seal preventer

7 1⁄1 16⁄⁄ -in. annular preventer

3-in. inverted pipe/slip preventer

3-in. pipe/slip preventer

-in. pipe/slip preventer

-in. pipe/slip preventer

-in. shear/seal preventer

The bottomhole assembly (BHA) forunderbalanced drilling is a 3-in. OD, wiredassembly powered from the surface through awireline cable inside the coiled tubing (left).This BHA includes two upper and two lower ballvalves that can isolate both wellbore pressureand coiled tubing pressure. The upper valveseliminate the need to bleed pressure from thecoiled tubing every time a BHA is assembled ordisassembled.

A downhole data system acquires pressure,temperature, WOB, lateral and stick-slipvibration, gamma ray, casing collar location,azimuth and inclination measurements. BP alsohas used a resistivity logging tool with multipledepths of investigation while drilling some of the wells.

To reduce vibration-related failures, BakerHughes Inteq moved electronic components inthe BHA away from the downhole motor andswitched from bicentered 4 ⁄1⁄⁄ -in. polycrystallinediamond compact (PDC) bits to 33⁄3⁄⁄ -in. gaugePDC bits. The gauge bits provided a higher rateof penetration (ROP) and less vibration withoutadversely impacting borehole size and wellproductivity. Engineers also monitored lateraland axial vibrations closely, and reducedinjection rates to minimize BHA vibrationsduring hole-cleaning, or wiper, trips.

These measures reduced BHA failures causedby excessive vibrations when drilling with two-phase liquid and gas. A BHA can now operate forseveral days to more than a week at a time. BPuses a 2 ⁄7⁄⁄ -in. air-drill motor (ADM) with anexcellent performance history, so motor failuresare rare. BP and Baker Hughes Inteq optimizedthe rotor-stator clearance and materials used inthese motors to extend ADM operating life underharsh wellbore conditions. The longest motor runto date lasted more than 12 days and drilled9,763 ft [2,975 m].

BP drills with underbalanced pressures usingnitrogen [N2] and fresh water with a biodegrad-able friction reducer to reduce pickup weightsand pumping pressures. Typically, BP drills threeor more multilateral sidetracks, each about3,000 ft [914 m] in length, through a singlecasing-exit window (next page).

Milling windows with through-tubing,inflatable whipstock assemblies has been themost challenging part of this project, and the onethat has improved the most. Optimized millingtechniques resulted in better casing-exitwindows to allow easier passage of 33⁄3⁄⁄ -in. gaugePDC bits. BP also developed a molded resin cap,which disintegrates during the first few minutesof drilling, to guide bits through a casing window.

32 Oilfield Review

> Coiled tubing bottomhole assembly (BHA) for underbalanced drilling intthe UAE. The BHA used for underbalanced reentry drilling in the Sajaa fieldincludes dual upper and two lower ball valves to isolate both wellborepressure and coiled tubing pressure. This eliminates the need to bleedinternal pressure from the coiled tubing every time the BHA is assembledor disassembled. It also includes sensors to acquire internal and externalpressure, external temperature, weight-on-bit (WOB), lateral and stick-slipvibration, casing collar locator (CCL), directional azimuth and inclination,and gamma ray measurements. Baker Hughes Inteq positions electroniccomponents in the BHA as far as possible from the 27⁄7⁄⁄ -in. downhole air-drillmotor (ADM). In addition, BP now uses a 33⁄3⁄⁄ -in. gauge polycrystallinediamond compact (PDC) bit instead of a bicentered 4 ⁄1⁄⁄ -in. PDC bit to reducedownhole vibrations and related BHA failures.

Dual

bal

l val

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onne

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. coi

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Winter 2005/2006 33

The BHA for this project was designed foropenhole drilling and could not survive for longunder the severe vibrations of milling windowsusing liquid and gas. Therefore, BP initiallyperformed milling operations with single-phaseliquids, but this often resulted in the loss of largevolumes of water to the formation. In some wells,excessive losses made it difficult to reestablishwell flow and underbalanced conditions when itwas time to start drilling a sidetrack because thesurrounding formation was saturated, or loaded,with water.

In wells that will not tolerate excessive fluidlosses, BP mills casing windows using liquid andgas two-phase drilling fluids and PDC bitsspecifically designed for milling with no

electronics in the BHA. BP has successfullymilled five 3.8-in. windows in underbalancedconditions using two-phase fluids withoutdownhole pressure sensors.

BP shuts wells in before mobilizing the coiledtubing unit to allow the near-wellbore pressure tobuild up. Extremely low-pressure intervals requirelonger shut-in periods to achieve and maintainunderbalanced conditions. In this way, availablereservoir pressure is conserved for as long aspossible while drilling. As lateral drilling proceedsand frictional pressures increase, additionalreservoir pressure must be encountered to ensureunderbalanced conditions.

In areas of the reservoir with higherpressures, BP maintains underbalanced drilling

conditions by manipulating the choke manifoldat the surface. At some point, however,bottomhole pressure exceeds reservoir pressureand drilling becomes overbalanced from thatpoint on. If the formation permeability is lowenough to tolerate some degree of overbalance,drilling can continue to extend the lateralbranches as far as possible.

While drilling with slightly overbalancedpressure, engineers limit the ROP, make shorterwiper trips to remove excess cuttings, reducefluid injection rates and minimize or eliminateN2 foam sweeps to avoid additional increases inpressure. BP continues drilling until theoverbalance gets too high, pickup weights get tooclose to the coiled tubing yield strength, or thereis no additional forward penetration.

Using these techniques, BP Sharjah hasreentered 37 wellbores and drilled more than 150lateral sidetracks with a combined footage thatexceeds 300,000 ft [91,440 m]. To date, thelongest single lateral drilled has been 4,350 ft[1,326 m], and the most footage drilled during asingle reentry has been 14,487 ft [4,416 m] witheight laterals. Accessing reserves that were notbeing drained by the original wellbores reducedthe production decline in Sajaa field, signifi-cantly extending the life of this field.

From health, safety, cost and environmentalperspectives, this program also has beenextremely successful. During more than two and ahalf years of drilling, encompassing more than1 million staff-hours of work, there have been nolost workdays.

In the early phases of this project, BPencountered rig-up, equipment and operationsproblems that required 79 days to complete thefirst well. Wells are currently drilled in only 20 to30 days. Rig moves, which initially took almostnine full days, now require only 2.5 days.

BP maintains an extensive database thatfacilitates knowledge sharing and continuousimprovement by capturing operational practicesand experience from each contractor. Thedatabase includes everything from rigging down,rig moves and rigging up, to milling casing-exitwindows and drilling laterals.

Multilateral wells maximize wellbore contactwith a reservoir, increase well productivity andoptimize reserve recovery. However, productionenhancement and maintaining well productivityin these types of completions require cost-effective methods for performing stimulationtreatments. In addition to reentry drilling, coiledtubing also plays a vital role in wellbore remedialoperations and reservoir stimulation treatmentsfor multilateral wellbores.

> Sajaa field reentry multilateral drilling. BP set a whipstock above existingperforations or openhole sections to allow milling of an exit window in the7-in. casing of the main wellbore below the end of the production tubing.Plans called for drilling at least three horizontal lateral sidetracks in eachwell using coiled tubing and underbalanced drilling techniques.

5-in. tubing

2 3⁄3 8⁄⁄ -in. coiled tubing

3-in. BHA

2 7⁄7 8⁄⁄ -in. ADM

3 3⁄3 4⁄⁄ -in. PDC bit

7-in. packer

Through-tubingexpandable whipstock

>Multilateral well interventions and lateral access. The corrosion-resistant Discoveryt MLT multilateralttool includes an adjustable bent subt and a controllable orienting device to rotate the tool. Lateralwellbore branches are located by moving the tool, which is actuated by fluid flow, up and downacross a target interval (1). When fluid flow exceeds a threshold rate, the lower tool section changesfrom straight to bent (2). Each actuation cycle rotates the tool 30°, producing a surface-displayedpressure profile that confirms lateral orientation (3). This coiled tubing system allows selectiveaccess to any type of lateral junction for cleanouts, logging, perforating, stimulation and cementingoperations (4 and lower right).tt

1 2 3 4

Multilateral Well StimulationsTalisman Energy drillsy wells in the Turner Valleyrfield of Alberta,f Canada, that consist of af mainawellbore and two or morer horizontal openholelaterals targeting porous, upper and lowergeologic units of thef dolomitic Rundle formation.Remedial operations in these wells traditionallywere inefficient, ineffective and expensive.Engineers needed an effective means of conveyingfacid into the individual well branches to optimizeproduction from multilateral completions.3

Previous methods of blindlyf searchingy for andrandomly accessingy laterals often left Talismanand other operating companies in this areauncertain about the effectiveness of cleanoutfoperations and acid treatments. Schlumbergerintegrated two technologies—the Discovery MLTymultilateral tool and the Jet Blaster jetting scaleremoval service—to access and stimulateindividual lateral branches without the need forcomplex, permanent well-completion equipment.

Initially, producers in this area performedstimulation treatments on multilateral wells inseveral steps. They madey separate runs with twodifferent BHA configurations, hoping torandomly accessy each lateral. The Jet Blasterservice was used during the first run to scour theborehole wall with a high-energy fluidy jet andreconnect with the rock-matrix permeabilityx(above left).

A secondA run followed with a flexible BHAthat had different bend angles than the naturalcurvature at the lower end of thef coiled tubing.The disadvantage of thisf “hunt-and-hope”approach was that operators had no control overwhich lateral the BHA wouldA enter, so thesame well branch might get treated twice.

Even when applied repeatedly, this methoddid not significantly improvey well productivity.Subsequently, companies began using a jettingtool only duringy the first run followed by ay secondrun without the jetting tool, using only ayDiscovery MLTy tool to locate and treat individuallaterals (left).

This technique routinely accessedy the secondlateral in one run, but only they first lateral wasoptimally treatedy with the high-energy rotaryyjetting tool. Operators considered the benefit ofmechanically removingy damage with a high-energy fluidy jet in just one branch worth the costand risk ofk makingf multiple runs.

In wells with closely spacedy laterals, therewas still uncertainty abouty which lateral hadbeen accessed, especially ify measuredf depthswere within about 50 ft [15 m] or if helicalf

34 Oilfield Review

>Mechanical scale-removal. The Jet Blastert tool consists of a rotating head,a drift ringt and opposing offset nozzlest that removet formation damage andscale from borehole or tubular walls.

Jet nozzleRotating head Scale

Drift ring

Borehole wall

Winter 2005/2006 35

lockup of the coiled tubing occurred. There alsowere the possibilities of treating a lateral twiceor not at all. To address these problems and tofacilitate effective stimulation of multilateralwells, Schlumberger developed an integratedlateral-locating and rotary jet-wash tool.

This new Blaster MLT multilateral reentrystimulation and scale removal system combinesthe capabilities of a Discovery MLT tool and aJet Blaster tool. This unique system can accessall of the lateral branches in a well to convey acidand scour the borehole with a high-energy fluidjet. Several laterals can be treated in a singletrip, which reduces job time at the wellsite.

Qualification testing and verification ofBlaster MLT system capabilities were performedat the Schlumberger Reservoir Completions(SRC) Center in Rosharon, Texas. Varioustests were conducted to determine operatingparameters, develop treatment procedures andcorrelate a theoretical model that aids inpredicting tool performance at specific flowrates. Engineers ran the system in a 7,000-ft[2,134-m] test well to compare surface-testresults with actual downhole performance dataand were able to predict operating flow rateswith reasonable accuracy.

Schlumberger also performed a series ofrigorous flow-loop tests, ranging from 10 to12 hours, to evaluate the durability of thissystem. During extended operating periods,injection rates were increased and decreasedwhile pumping fresh water, N2 or fluids foamedwith N2. The Blaster MLT system performedwithin the initial design parameters without anytool failures.

Talisman Energy performed stimulationtreatments in two similar wells of the TurnerValley field, one with a Jet Blaster tool followed bya Discovery MLT tool and the other with the newintegrated multilateral jet-wash tool. The BlasterMLT system was run in a multilateral well toperform separate acid treatments in each lateralbranch during a single trip into the wellbore.

This newly drilled openhole completionconsisted of a main borehole and two lateralsidetracks. The true vertical depth (TVD) of thiswell was 8,888 ft [2,709 m]. The longest lateralleg extended to 11,387 ft [3,471 m] measureddepth (MD). The multilateral jet-wash tool wasrun into each openhole lateral.

The lateral-locating mechanism was notrequired to enter the first well branch. However,the Blaster MLT tool was activated to locate andaccess the other two branches. Lateral accessand tool location were verified by correlating theTVD and MD of each branch, which confirmed thefunctionality of the Blaster MLT system (above).

After the bottom of each lateral was reached,the BHA was slowly pulled back to the entrypoint while the high-energy jet-wash componentscoured the borehole wall. Sharp increases incirculating pressure confirmed continuousjetting action throughout each lateral. Injectionpressures and flow rates indicated that the

system performed as expected. Treating fluidswere effectively conveyed to the formation withno downtime.

At the top of each lateral, the fluid injectionrate was reduced to zero to equalize the internaltool pressure with the wellbore pressure. Afterall three laterals were treated, the BHA waspulled into the intermediate casing to purge thetool and tubing, and to lift the well with N2.Schlumberger found no indications of tool failure or wear when the system was inspected atthe surface.3. Lesinszki A, Stewart C, Ortiz A, Heap D, Pipchuk D and

Zemlak K: “Multilateral/High-Pressure Jet Wash ToolSystem Successfully Employed in Multilateral Wells,”paper SPE 94370, presented at the SPE/ICoTA CoiledTubing Conference and Exhibition, The Woodlands,Texas, USA, April 12–13, 2005.

> Multilateral jet-wash system in a well with three lateral branches (top). The integrated Blaster MLTmultilateral tool combines the lateral-access capabilities of the Discovery MLT system and thehigh-energy rotary jetting action of the Jet Blaster tool. This unique single-trip tool conveys a high-energy stream of acid or other stimulation fluid directly onto the borehole wall to scour the formationrock face. Compared with previous combinations of tools and techniques, this method ensuredaccess to every lateral in a well and provided more effective application of treatment fluids torestore the undamaged matrix permeability of the Rundle formation in the Turner Valley field ofAlberta, Canada (bottom).

Discovery MLTassembly

Jet Blasterassembly

The Blaster MLT system ensured lateralaccess and reduced the number of trips into thiswellbore from three to one, which resulted in a50% reduction in time required at a wellsite.Talisman Energy successfully treated four otherwells, and believes that the multilateral jet-washsystem will aid production optimization efforts inthe Turner Valley field and other area fields. Eachof these jobs, including rig-up and rig-down, werecompleted in about 48 hours.

New multilateral wells can be treatedeffectively and existing underperforming wellscan be reentered to enhance production andhydrocarbon recovery. Exploratory wells withopenhole sidetracks and multilateral comple-tions in low-permeability formations now can bestimulated more effectively to better evaluate,characterize and produce a reservoir.

Combining coiled tubing tools and tech-niques also provides novel solutions in otherstimulation and remedial applications, includingselective zonal isolation and diversion ofhydraulic fracturing or acid treatments.

Accurate Zonal IsolationSonatrach needed a reliable, rigless techniquefor isolating and selectively stimulating closely spaced perforated intervals in theHassi-Messaoud field, Algeria.4 This NorthAfrican field produces from a thick sandstone atabout 3,300 m [10,827 ft] with four distinctreservoir intervals and a transition zone. Most ofthe wells have cemented liners with multipleperforated intervals.

Traditionally, Sonatrach circulated oil-basefluids to control these wells prior to any well-

intervention operations, which often resulted innear-wellbore formation damage. This operatorperforms about 50 acid stimulations each year to remove damage and restore or optimizewell productivity.

Well MD 264 was producing from twoperforated intervals: a hydraulically fracturedupper zone and two deeper, low-permeabilityzones that were underperforming (below left).Only 3 m [10 ft] of unperforated casing wasavailable from 3,430 to 3,433 m [11,253 to11,263 ft] between the upper and lowerunderperforming intervals.

This well, which was drilled to 3,503 m[11,493 ft] and completed open hole in the late1970s, initially produced 329 m3/d [2,069 bbl/d].3

36 Oilfield Review

> Concentric zonal isolation and selectivestimulation. Sonatrach wanted to isolate anupper hydraulically fractured zone in Well MD264 of the Hassi-Messaoud field, Algeria, withoutkilling the well. This would allow selectivestimulation of a lower perforated interval withhydrofluoric [HF] organic acid. Through-tubingttreatment success depended on using coiledttubing to set an inflatable packer in a 3-m [10-ft]section of unperforated casing between thettwo intervals.

4 1⁄2-in. liner

InflatedCoilFLATEpacker

10 ft

Organic acidtreatment

> Inflatable coiled tubing packers. Heavy-duty tapered slats, a high-strength carcass restraint system,a composite inflation bladder and a chemically resistant elastomer element anchor CoilFLATE high-pressure, high-temperature (HPHT) packers in place and provide a high-pressure seal even at largeexpansion ratios—a 5,000-psi [34.5-MPa] differential at a 2 to 1 expansion and a 2,000-psi [13.7-MPa]differential at a 3 to 1 expansion. These packers withstand extended exposure at temperatures up to375°F [191°C] in almost any chemical environment. The 2 ⁄1⁄⁄ -in. OD CoilFLATE HPHT packer can expandtto more than three times its initial OD and can set in casing sizes up to 7 ⁄5⁄⁄ -in. OD. After expansion,tthese packers allow injection above and below the packer or both. Following a stimulation treatmentand while still connected to the coiled tubing, the packer can be deflated back to approximately itsoriginal 2 ⁄1⁄⁄ -in. OD for retrieval through wellbore restrictions of about 2.205 in.

Winter 2005/2006 37

In the mid-1990s, Sonatrach installed a cemented4 ⁄1⁄⁄ -in. liner and perforated the upper intervalfrom 3,406 to 3,418 m [11,175 to 11,214 ft].

That zone failed to produce economicallyeven after proppant fracture stimulation.Sonatrach added perforations from 3,421 to3,464 m [11,224 to 11,365 ft], which produced57 m3/d [359 bbl/d] after an acid stimulation. A3

pressure buildup test and a NODAL productionsystem analysis indicated a high positive skin, orformation damage, and a potential undamagedproductivity of 94 m3/d [592 bbl/d]. Sonatrach3

wanted to selectively treat the lower perforatedintervals from 3,433 to 3,464 m [11,263 to11,365 ft] with hydrofluoric [HF] organic acid.

To avoid further damage from killing the well,engineers decided to perform this treatmentthrough the existing production tubing usingcoiled tubing and an inflatable packer to isolatethe upper hydraulically fractured interval.Treatment success depended on accuratelysetting the packer.

If the packer were set too high, treatmentfluid might take the path of least resistance anddivert into the upper previously fracture-stimulated zone; if set too low, a large part of thelower perforated interval might not be treated,increasing risk of damage to the outer packerelements and internal bladder, which mightprevent inflation.

The inflatable packer had to withstand highdifferential pressures across the packer withoutleaking or failing because the deeper, low-permeability intervals might require treatmentinjection pressures as high as 3,500 psi [24 MPa],even at minimal pumping rates. Sonatrach usedthe CoilFLATE coiled tubing through-tubinginflatable packer, which was designed towithstand harsh downhole wellbore conditionsand corrosive treatment chemicals underextended periods of exposure at up to 375°F[191°C] (previous page, right).

An initial attempt to position and inflate thepacker without real-time downhole depthcorrelation failed, reinforcing the need foraccurate depth correlation. Sonatrach could notinject fluid after setting the packer based onsurface measurements of coiled tubing length,which only have an accuracy of about10 ft/10,000 ft [3 m/3,048 m]. Packer damageafter retrieval indicated that the packer hadbeen set across a perforated interval.

Sonatrach considered two methods forcorrelating downhole depths and positioning thepacker. One method was coiled tubing with aninternal wireline cable to transmit data fromdownhole logging tools, and the other was amemory log. Coiled tubing with wireline providesreal-time depth correlations, but addsoperational complexity, risk and cost. Inaddition, acid stimulations cannot be performedunless armored cable with a special plasticcoating is installed.

Memory logging requires an extra trip toretrieve data from the downhole memory anddoes not provide real-time depth correlations. Italso relies on computer modeling to estimatecoiled tubing length because running in and outof the wellbore plastically deforms and stretchesthe coiled tubing. To achieve an increased level ofaccuracy on the second attempt, Sonatrach usedthe DepthLOG CT depth correlation log (above).

This wireless casing collar locator (CCL)system with pump-through capability providesaccurate, real-time depth measurements, allowspumping of corrosive fluids and is compatible withthe CoilFLATE high-pressure, high-temperature(HPHT) packer as an add-on assembly.

4. Boumali A, Wilson S, Amine DM and Kinslow J:“Creative Combination of New Coiled TubingTechnologies for Stimulation Treatments,” paperSPE 92081, presented at the SPE/ICoTA Coiled TubingConference and Exhibition, The Woodlands, Texas,April 12–13, 2005.

> Depth control. The wireless DepthLOG CT tool uses a traditional casing collarlocator to detect magnetic variations at jointed casing collars (left). Hydraulicttpressure-pulse telemetry transmits data to the surface through fluid inside thecoiled tubing, eliminating the need for an internal wireline cable. Flow-throughcapability provides an unobstructed coiled tubing string for pumping cementand stimulation treatments. A signal booster can be added for depth correlationwhen transitioning from smaller production tubing into casing sizes larger tthan 7 in. (right).tt

SignalerSignalerSi l

ProcessorProcessor

Battery power forBattery power forB fsignal processorsignal processori l

Casing collarCasing collarC i lllocatorlocatorl

The tool sends telemetry pulses to the surfacethrough fluid in the coiled tubing and outputs aninstantaneous and continuous CCL log withoutthe need for a wireline cable inside the coiledtubing. A real-time depth correlation log allowedSonatrach to accurately position the packerbetween the two perforated intervals.

Combining these two innovative technologiesin a modular toolstring met all operationalobjectives of this demanding application. Duringa single run into the well with coiled tubing,Sonatrach could acquire a CCL log for accuratedepth correlation and optimal packer placementin the 3-m casing section, set and inflate theCoilFLATE HPHT packer, pump the HF acidtreatment, deflate the packer and initiate wellflow by injecting nitrogen.

The DepthLOG CT system required aminimum fluid rate of 0.5 bbl/min [0.08 m3/min]3

to produce a positive pressure signal at thesurface. An additional 0.5 bbl/min was needed tokeep the coiled tubing continuously full of fluid.Surface testing verified that the pressure pulsesand flow rates required to generate wireless CCLsignals would not cause premature inflation ofthe CoilFLATE packer.

At the well location, an initial coiled tubingrun used the high-pressure Jet Blaster tool topump nitrified fluids and clean the productiontubulars. This operation confirmed clear passageto the packer setting depth, cleaned theperforations to ensure optimal acid penetrationand removed any possible debris and scalebuildup from the casing walls where the packerwas to be set.

Schlumberger performed two DepthLOGcorrelation logs to accurately position theCoilFLATE packer within the 3-m casing section.Sonatrach confirmed packer inflation andanchoring by setting coiled tubing weight downon the packer and performed an injection test toconfirm a positive seal before pumping 120 bbl[19.1 m3] of HF acid foamed with N2. Thestimulation treatment was pumped in two stages,each consisting of a hydrochloric [HCl] acidpreflush, HF acid stage and HCl overflush stage, with a chemical diversion system betweeneach stage.

The inflatable packer was designed towithstand high differential and injectionpressures, so it was possible to pump thistreatment at 3,500 psi [24 MPa] and still

maintain a margin of safety to avoid packerfailure. Formation injectivity increased from0.2 to 1 bbl/min [0.03 to 0.16 m3/min] while3

maintaining a constant wellhead pressure,indicating no packer leakage and confirming thatthe acid was dissolving formation damage,opening the perforations and reducing skin.

After Sonatrach completed this treatment,overpull was applied to the coiled tubing at thesurface to deflate the CoilFLATE packer.Nitrogen was then circulated through the coiledtubing to reinitiate well flow as quickly aspossible. This helped recover the spent acid,which can cause severe damage if it remains inthe formation for an extended period of time.

After the CoilFLATE packer was retrieved, avisual inspection of the outer element revealedno indentations or damage to the metal slats orrubber seal from perforations or casing collars,which verified that the packer had been set incasing between the perforated zones.

The proposed workover required only a singletrip into the well, and the production tubing did nothave to be retrieved. Depth correlation, acidizingand initiating production were performed on thesame run as setting the packer, saving two runs.After the stimulation treatment, oil productionmore than tripled from 38 m3/d [239 bbl/d] to3

120 m3/d [755 bbl/d] 3 (left).For more than one year after the treatment,

production remained at the same improved level.The use of the inflatable-anchoring packer andwireless CCL tool curtailed the conventional rigoperation that pulled the production tubing priorto any selective stimulation treatment. Thisworkover operation was the beginning of aplanned campaign for treating additional wells inthe same field that had similar completions andrequired stimulation.

Field experience using a 2 ⁄1⁄⁄ -in. OD CoilFLATEinflatable-anchoring packer proved that zones inwells with multiple completion intervals can bereliably isolated and stimulated using coiledtubing. Fast turnaround times and accurate fluidplacement allow production enhancement inwells that previously could not be treatedsatisfactorily or economically with otherintervention techniques and methods.

38 Oilfield Review

5. Kumar PS, Van Gisbergen S, Harris J, Al Kaabi K,Ferdiansyah E, Brady M, Al Harthy S and Pandey A:“Eliminating Multiple Interventions Using a Single Rig-UpCoiled-Tubing Solution,” paper SPE 94125, presented atthe SPE/ICoTA Coiled Tubing Conference and Exhibition,The Woodlands, Texas, April 12–13, 2005.

6. Kumar PS, Van Gisbergen S, Harris JM, Al-Naabi AM,Murshidi A, Brady ME, Ferdiansyah E, El-Banbi A andAl Harthy S: “Stimulation Challenges and Solutions inComplex Carbonate Reservoirs,” paper SPE 93413,presented at the SPE Middle East Oil & Gas Show andConference, Bahrain, March 12–15, 2005.

> Coiled tubing stimulation results in the Hassi-Messaoud field, Algeria. Production from Well MD264 increased more than threefold from 38 m3/d [239 bbl/d] to 120 m3 3/d [755 bbl/d] after pumping ahydrofluoric [HF] organic acid stimulation treatment through coiled tubing using an inflatable-anchoring packer to isolate the lower target interval from an upper interval, which had previouslybeen hydraulically fractured.

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Winter 2005/2006 39

Selective zonal isolation and treatment ofindividual intervals under extreme wellconditions provide new options and alternativesfor well construction and reservoir evaluation,including rig-based or rigless operations, such aswell testing of individual zones, pressure andtemperature monitoring, and pressure-declinetesting. Combining tools and multiple concentricoperations also has helped improve the overallefficiency of remedial workovers and wellrecompletions across an entire field in theMiddle East.

Single Rig-Up, Multiple OperationsPetroleum Development Oman (PDO) andSchlumberger collaborated on a novel method-ology to facilitate well recompletions in a maturenorthern Oman field. This new techniquecombined a series of operations into a single intervention, eliminating multiple trips

to a wellsite and the need to mobilize bothcoiled tubing units and conventional workoverrigs (above).5

Most of the wells in this field produce fromthe Shuaiba carbonate formation, and arecompleted with cemented and perforated4 ⁄1⁄⁄ -in. OD horizontal liners. Water productioncurrently exceeds 90% of the total field output, sothese wells are produced by artificial lift—gaslift or electrical submersible pump. Highdrawdown pressures cause scale deposition,which necessitates wellbore cleanouts prior toperforming workover operations.

Well interventions also include acquisition ofa pulsed-neutron log to measure fluid saturationsand prioritize potential completion intervalsaccording to oil content and potentialproductivity. These evaluations are followed byperforation and stimulation of selected intervals.

Initially, PDO performed these interventionsusing two coiled tubing units, one with and one

without an internal wireline. The operator alsoperformed jobs with two coiled tubing units and aworkover rig. Both methods, however, were costly.

Operations without a workover rig required atleast four separate coiled tubing runs. During thefirst run, PDO used conventional coiled tubing toclean out the wellbore liners. On the second run,the company used coiled tubing with an internalwireline to acquire a pulsed-neutron log.

On subsequent runs PDO perforated newintervals using conventional coiled tubing with ahydraulic firing head and stimulated each newcompletion interval during a series of wellboreentries that involved running and retrievingperforating guns under pressure.

From wellbore cleanout and pulsed-neutronlogging through perforating and stimulation,these operations required about 10 days onlocation and at least three months to complete,even when the intervention proceeded withoutsignificant problems.

Compared with these multiple coiled tubinginterventions, operations involving twointerventions with coiled tubing and oneintervention with a workover rig required moretime on location, about 12 days, but less totaltime, about two months. However, costs werehigher. During the first operation, PDO usedconventional coiled tubing to clean out thewellbore. The second operation involved runninga pulsed-neutron log using coiled tubing with aninternal wireline.

Perforating and stimulation were performedduring operations with a workover rig. Cleanoutand logging operations were not performed withthe workover rig because pulsed-neutron logsneeded to be acquired under live-well, orflowing, conditions.

This approach avoided flushing of the near-wellbore region by wellbore fluids under static oroverbalanced pressure conditions, which cancreate false saturation readings in perforatedhigh-permeability and naturally fractured zones.PDO also observed that stimulation results with apolymer-base diverting system were not optimalin this naturally fractured formation, even whencombined with mechanical diversion systems,such as an isolation straddle packer.

PDO evaluated alternative methods ofacquiring pulsed-neutron logs and quickly usingthis information to identify productionoptimization and recompletion opportunities.Various methods were considered to maximizewell productivity and reduce costs, including anondamaging, surfactant-base, self-divertingacid system.6

>Well interventions in northern Oman. PDO has performed workovers usingone coiled tubing unit with an internal wireline for logging and perforatingoperations (top), and one unit without an internal wireline for cleanouts andstimulation treatments (lower right). These operations have also beenttperformed with two coiled tubing units and a workover rig, or pulling unit(lower left). Both methods, however, were expensive and required multiplettoperations and trips to a wellsite.

PDO and Schlumberger proposed aninnovative solution for these gas lift wells: a singlerig-up intervention with coiled tubing. During onecontinuous operation, a single coiled tubing unitwould be used for wellbore cleanouts, logging, perforating and stimulation treatments.Schlumberger developed a specialized string ofcoiled tubing and modular bottomhole assembliesfor performing these operations and productionlog spinner surveys to evaluate if water shutoff isrequired (below right).

This coiled tubing string includes a modifiedwireline cable with an armored outer sheath, orjacket, to provide stability under unstable loadconditions and sudden compressive forces insidethe coiled tubing. A special plastic coatingprotects the wireline from corrosive treatmentfluids that could degrade the mechanical orelectrical performance of the cable.

The system is compatible with the Securedetonator, which requires more than 200 volts toactivate and initiate the firing of perforatingcharges, is safe against stray or static voltage,and does not require radio silence on locations.Underbalanced perforating also can beperformed during these interventions byactivating the gas lift system or by displacing thewellbore with lighter fluids.

PDO first applied this system in Well A toperforate and stimulate in a single operationwith the same coiled tubing unit. This wellproduced 430 m3/d [2,705 bbl/d] of total fluid,3

29 m3/d [182 bbl/d] of oil and about 93% water3

before this remedial intervention, which wasexpected to increase oil production by 30 m3/d3

[189 bbl/d].The operator perforated new intervals in

three runs. After perforating, well productionincreased to 500 m3/d [3,145 bbl/d] with 57 m3 3/d3

[359 bbl/d] of oil and about 89% water. Afterstimulation of two upper perforated intervalswith a surfactant-base, self-diverting acidsystem, the well produced 572 m3/d [3,598 bbl/d]3

of total fluid with 63 m3/d [396 bbl/d] oil, an3

increase in oil production of 34 m3/d [214 bbl/d].3

During the second application, PDOperformed a single rig-up coiled tubing workoveron Well B to shut off the existing perforations andperforate new intervals that had more than 65%oil saturation. PDO made a trial, or dummy, runto tag TD followed by a wellbore cleanoutoperation and a pulsed-neutron logging run.

Based on the pulsed-neutron log evaluation,engineers decided to isolate the existingperforations with a bridge plug and perforate41 m [135 ft] near the end of the horizontalsection. During the same operation, PDO

stimulated these perforations with thesurfactant-base, self-diverting acid system.Engineers expected an additional 24 m3/d[151 bbl/d] of oil output. The well produced523 m3/d [3,290 bbl/d] of total fluid with 25 m3 3/d3

[157 bbl/d] of oil.PDO evaluated objectives, procedures, risks

and results on these first two wells to optimizeoperational efficiency, and to further reduce thetime requirements and costs of these operations.As a result, PDO eliminated the dummy run onsubsequent jobs. This integrated well-intervention method required about six days onlocation over a 15-day period, or less than half a

month. Compared with 10 to 12 total days overtwo to three months for previous multiple-entry methods, this saved PDO US$ 60,000 toUS $100,000 per well (next page, top).

PDO applied this new remedial technique toacquire fluid saturations and quickly identifyrecompletion opportunities on 10 wells, resultingin less deferred production and early returns onworkover investments. Using this approach toperform various combinations of remedialoperations, PDO exceeded production targets forthis field and saved more than US$ 1 million in2004. PDO is currently evaluating the applicationof this technique in other areas.

40 Oilfield Review

> Single rig-up well interventions with coiled tubing. PDO and Schlumbergerdeveloped a specialized string of coiled tubing and modular tool assembliesspecifically to perform wellbore cleanouts, well logging, perforating andstimulation operations. The customized logging and perforating head requiressimultaneous pumping of fluid at a predetermined rate and overpull todisconnect the head. This dual-release mechanism avoids an unintentionaldisconnect from the head.

Stimulation

Coiled tubing

Coiled tubing connector

Dual flow-release and overpulllogging and perforating headwith internal check valve

Mechanicaldisconnect

Perforating

Perforating

Mechanicaldisconnect

Deploymentbar

Jetnozzle

Mechanicaldisconnect

Downholefilter

Jet Blasterswivelassembly

Jet Blasternozzleassembly

Wellborecleanout Logging

Loggingtools

Winter 2005/2006 41

Continuous Tubing, Continuous ImprovementThe reliability of coiled tubing equipment andoperational practices continues to improve.From the most basic applications to the mostcomplicated, advances in coiled tubing tools,techniques and concentric operations ensuresafer and more efficient day-to-day operations.As a result, coiled tubing technology has becomefirmly established in many areas of oil and gasactivity that cannot be adequately addressedusing conventional well-intervention operations,techniques and services.

The modular nature of coiled tubing systems,rigless operations, quicker well-turnaroundtimes and accurate selective placement of fluidsor stimulation treatments are helping producingcompanies optimize well performance.Increasingly, operators are reevaluating fieldsand individual wellbores for remedialintervention or recompletion operations usingcoiled tubing, including many wells thatpreviously were considered too risky even forconventional operations (below left).

However, not all concentric well interven-tions require new technology or mandate thatexisting coiled tubing equipment and techniquesbe pushed beyond their current limits. Operatorsand providers of coiled tubing services also arecollaborating to develop innovative tool combina-tions and integrated systems, operational bestpractices and new approaches that can improvewell productivity and increase reserve recoveryin new and mature fields alike. By building onthese cooperative efforts, Schlumberger isimproving and expanding concentric servicesthrough ongoing development and optimizationof coiled tubing equipment, proceduresand techniques.

Improvements in materials and manufac-turing, advances in design software, and real-time monitoring and control have significantlyreduced the frequency of coiled tubing failuresand increased the success of through-tubingoperations. There are still some operatingcompanies that have not forgotten about thelimitations and problems that were associatedwith early coiled tubing strings and equipment.However, through knowledge sharing and bettercommunication, more oilfield companies arecomfortable performing concentric wellinterventions using coiled tubing. —MET

> Improving the profitability of concentric operations. Multiple-entry remedial operations withouta workover rig required that PDO perform at least four separate coiled tubing runs, requiring about10 days on location over three months (red). Well interventions involving two coiled tubing operationsand one operation with a workover rig required less total time, about two months, but 12 totaldays on location with costs that were higher (blue). The integrated single rig-up method using aspecialized string of coiled tubing and one coiled tubing unit required only about six days on locationover a 15-day period (black).

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onononon,on,,d d tid productid productid productid productid productippd f dss deferredss deferredss deferredss deferredss deferredLLesLesLesLesLes ddddddsssssttmentmentmentmentmentmentmentii ti ton investmon investmon investmon investmon investmon investmon investmtter return oer return oer return oer return oer return oer return oer return off tf tfastefastefastefastefastefastefaste mmmmmmmoooooooeeeeeee

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7 8 9 10 11 12

> Expanding the application of coiled tubing reentry drilling. Producing companies are becoming more confident in conducting remedial interventions or recompletions through existing productionttubulars. During December 2004, BP Sharjah Oil Company reentered a well in the Sajaa field for asecond time and drilled four additional laterals using underbalanced techniques and coiled tubing. BP initially had reentered this well with coiled tubing drilling three laterals in August 2003.

42 Oilfield Review

The Source for HydraulicFracture Characterization

Les BennettJoël Le CalvezDavid R. (Rich) SarverKevin TannerCollege Station, Texas, USA

W.S. (Scott) BirkGeorge WatersOklahoma City, Oklahoma, USA

Julian DrewGwénola MichaudPaolo PrimieroSagamihara, Kanagawa, Japan

Leo EisnerRob JonesDavid LeslieMichael John WilliamsCambridge, England

Jim GovenlockChesapeake Operating, Inc.Oklahoma City, Oklahoma

Richard C. (Rick) KlemSugar Land, Texas

Kazuhiko TezukaJAPEXChiba, Japan

For help in preparation of this article, thanks to Gilles LeFloch, Montrouge, France; and Bill Underhill, Houston.DataFRAC, FMI (Fullbore Formation MicroImager),HFM (Hydraulic Fracture Monitoring), StimMAP andVSI (Versatile Seismic Imager) are marks of Schlumberger.PS3 is a mark of Vetco Gray, now owned by Schlumberger.SAM43 is a mark of Createch. Primacord is a mark of DynoNobel Incorporated.

Improved understanding of hydraulic fracture geometry and behavior allows asset

teams to increase stimulation effectiveness, well productivity and hydrocarbon

recovery. Although seismic methods for characterizing hydraulic fractures have

existed for years, new seismic hardware and processing techniques make this type

of monitoring significantly more effective than in the past.

Many of the world’s large, high-permeabilityreservoirs are now approaching the end of theirproductive lives. Increasingly, the hydrocarbonsthat fuel nations and economies will come fromlow-permeability reservoirs, and those tightformations require hydraulic fracture stimu-lation to produce at economical rates.

In the USA alone, operating companies spentroughly US$ 3.8 billion on hydraulic fracturing in2005.1 This huge expenditure is expected toincrease in the near future and to spreadthroughout the world. Companies need tools thathelp them determine how successfully theirhydraulic fractures have optimized wellproduction and field development. To do this,these tools should provide information abouthydraulic fracture conductivity, geometry,complexity and orientation.

While indirect well-response methods—fracture modeling using net-pressure analysis,well testing and production-data analysis—areused routinely to infer the geometry andproductivity of hydraulic fractures, measure-ments of the formation’s response to fracturingare now feasible to quantify fracture geometry,complexity and orientation.2 This articlediscusses the importance of characterizinghydraulic fractures when trying to optimizeproduction rates and hydrocarbon recoverywithin a field. We highlight a method ofmonitoring hydraulic fractures that uses seismictechnologies, including data acquisition, proces-sing and interpretation, and some associated

complexities. The microseismic hydraulic frac-ture monitoring technique is demonstrated incase studies from the USA and Japan, featuringtwo different fracturing environments.

Fracture StimulationFrom the first intentional hydraulic fracturestimulation of a reservoir in the late 1940s,engineers and scientists have sought tounderstand the mechanics and geometry ofhydraulically created fractures.3 Although anincrease in productivity or injectivity of astimulated reservoir may imply a successfultreatment, it does not necessarily mean that thereservoir and fracture models correctly pre-dicted the outcome.

Reservoir characteristics should always beconsidered when designing hydraulic fracturetreatments. In moderate- to high-permeabilityreservoirs, fractures are designed to improveproduction by bypassing near-wellbore formationdamage.4 In these reservoirs, the most importantfracture characteristic is dimensionless fractureconductivity—a function of the width, permea-bility and length of the fracture and of formation-matrix permeability. In permeable but weaklyconsolidated reservoirs, fracturing methods areused in conjunction with gravel packing toreduce the pressure drop and fluid velocitiesaround a wellbore during production, andtherefore mitigate sand production.5

Winter 2005/2006 43

1. Spears R: “Oilfield Market Report 2005,” Spears &Associates, Inc., http://www.spearsresearch.com/(accessed on October 14, 2005).

2. Barree RD, Fisher MK and Woodroof RA: “A PracticalGuide to Hydraulic Fracture Diagnostic Technologies,”paper SPE 77442, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas,September 29–October 2, 2002.Cipolla CL and Wright CA: “Diagnostic Techniques toUnderstand Hydraulic Fracturing: What? Why? andHow?” paper SPE 59735, presented at the SPE/CERI GasTechnology Symposium, Calgary, April 3–5, 2000.

3. Brady B, Elbel J, Mack M, Morales H, Nolte K and Poe B:“Cracking Rock: Progress in Fracture Treatment Design,”Oilfield Review 4, no. 4 (October 1992): 4–17.

4. Meng HZ: “Design of Propped Fracture Treatments,”in Economides MJ and Nolte KG (eds): ReservoirStimulation. Schlumberger Educational Services:Houston, 1987.

5. Ali S, Norman D, Wagner D, Ayoub J, Desroches J,Morales H, Price P, Shepherd D, Toffanin E, Troncoso Jand White S: “Combined Stimulation and Sand Control,”Oilfield Review 14, no. 2 (Summer 2002): 30–47.

6. Meng, reference 4.7. Peterman F, McCarley DL, Tanner KV, Le Calvez JH,

Grant WD, Hals CF, Bennett L and Palacio JC: “HydraulicFracture Monitoring as a Tool to Improve ReservoirManagement,” paper SPE 94048, presented at theSPE Production Operations Symposium, Oklahoma City,Oklahoma, April 16–19, 2005.

8. Aly AM, El-Banbi AH, Holditch SA, Wahdan M, Salah N,Aly NM and Boerrigter P: “Optimization of GasCondensate Reservoir Development by CouplingReservoir Modeling and Hydraulic Fracturing Design,”paper SPE 68175, presented at the SPE Middle East OilShow and Conference, Bahrain, March 17–20, 2001.

9. Hashemi A and Gringarten AC: “Comparison of WellProductivity Between Vertical, Horizontal andHydraulically Fractured Wells in Gas-CondensateReservoirs,” paper SPE 94178, presented at the SPEEuropec/EAGE Annual Conference, Madrid, Spain,June 13–16, 2005.

In low-permeability reservoirs, by far themost common reservoir type to be fracturestimulated, industry experts have establishedthat fracture length is the overriding factor forincreased productivity and recovery.6 From areservoir-development standpoint, having areasonable understanding of hydraulic fracturegeometry and orientation is crucial fordetermining well spacing and for devising field-development strategies designed to extract morehydrocarbons.7 Reservoir modeling is alsoenhanced with improved knowledge of hydraulicfractures within a field.8

Natural fractures, often the primarymechanism for fluid flow in low-permeabilityreservoirs, severely compromise the ability topredict the geometry of hydraulic fractures andthe stimulation’s effect on production anddrainage. Understanding how hydraulicallycreated fractures interact with natural fracturesystems—open and mineral-filled—requiresknowledge of both hydraulic and naturalfracture types.

Hydraulic fractures tend to propagateaccording to the present-day stress directionsand preexisting planes of weakness, such asnatural fractures. The orientations of naturalfracture systems reflect ancient and possiblylocalized stress regimes.

In low-permeability reservoirs, the combinedeffects of natural and hydraulic fractures arelargely responsible for improved productivityfrom horizontal wells as compared with theproduction from vertical wells.9 The charac-teristics of both fracture types dictate the

preferred azimuth in which highly deviated andhorizontal wells should be drilled. Theoretically,in a horizontal well drilled parallel to themaximum horizontal stress direction, hydraulicstimulation produces a single longitudinalfracture along the horizontal wellbore. Thisscenario simplifies fluid flow out of the wellboreduring stimulation and into the wellbore duringproduction. However, depending on thecharacteristics and orientations of the naturalfracture systems, a transverse hydraulicfracturing strategy may actually result in higherproductivity, especially when multiple zones arebeing stimulated.10

While it is possible to have a good under-standing of existing natural fracture systems, ourability to determine hydraulic fracture geometryand characteristics has been limited. Geologicdiscontinuities such as fractures and faults candominate fracture geometry in a way that makespredicting hydraulic fracture behavior difficult.Clearly, the exploration and production (E&P)industry still has much to learn abouthydraulic fractures.

Characterization of the ComplexMore than simple curiosity drives petroleumindustry engineers and scientists to seekunderstanding of hydraulic fractures. Fracturestimulation is an expensive process, which canreap huge returns if done correctly. Yet tocomprehend hydraulic fracture propagation,accurate measurements of fracture growth,geometry and orientation are needed. These dataprovide a starting point for asset teams to assesspost-stimulation production performance andoptimize future stimulation treatments—tolower the cost or increase the effectiveness ofstimulation or both. This information can then beused to drive reservoir-development strategies.

Fractures from both horizontal and verticalwells can propagate vertically out of the intendedzone, reducing stimulation effectiveness, wastinghorsepower, proppant and fluids, and potentiallyconnecting up with other hydraulic fracturingstages or unwanted water or gas intervals. Thedirection of lateral propagation is largelydictated by the horizontal stress regime, but inareas where there is low horizontal stress

anisotropy or in reservoirs that are naturallyfractured, fracture growth can be difficult tomodel. In shallow zones, horizontal hydraulicfractures can develop because the vertical stresscomponent—the overburden weight—is smallest.A horizontal hydraulic fracture reduces theeffectiveness of the stimulation treatmentbecause it most likely forms along horizontalplanes of weakness—presumably betweenformation beds—and is aligned preferentially toformation vertical permeability, which is typicallymuch lower than horizontal permeability.

After a hydraulic fracture is initiated, thedegree to which it grows laterally or verticallydepends on numerous factors, such as confiningstress, fluid leakoff from the fracture, fluidviscosity, fracture toughness and the number ofnatural fractures in the reservoir.11 All hydraulicfracture models fail to predict fracture behaviorprecisely, and in many cases, models failcompletely, largely because of incorrectinformation and assumptions used in the models.Nevertheless, modeling is a necessary tool infracture engineering.

Stimulation engineers use hydraulic fracturesimulators to design and predict optimal fracturestimulation treatments. Basic inputs to thesemodels include fluid and proppant propertiesand volumes, closure stress, pore pressure,formation permeability and mechanical rockproperties, such as Poisson’s ratio and Young’smodulus. The risk of an inadequate treatmentoccurring is increased by estimating theseinputs. Asset teams can take steps to reduce thisrisk by using better models and by morethoroughly characterizing the reservoir andassociated stresses. These steps may includeacquiring petrophysical and mechanicalproperties from logs, obtaining borehole stressand natural fracture information from boreholeimages, and directly measuring the stresses byperforming the DataFRAC fracture datadetermination service.

Fracture modeling is a necessary part of thestimulation design and improvement process.However, even the most complex models fallshort in predicting reality.12 In the last 15 years orso, the industry has learned that hydraulicfractures are much more complex than the

biwing, single-plane cracks depicted in models.Investigation of actual hydraulic fracturegeometries, from minebacks, core-throughs andthousands of mapped fractures, has shown analmost limitless range of complexities, startingwith fracture asymmetry and the creation ofmultiple competing fractures.13

Given the complexities introduced by thepresence of natural fracture systems, reservoirheterogeneity and stress anisotropy, there islittle reason to believe that a hydraulicallyinduced fracture would maintain symmetry as itpropagates outward from the borehole.Asymmetrical hydraulic fractures formasymmetrical drainage patterns that should beconsidered when planning development drillingand modeling fluid flow within the reservoir. Inaddition, unexpected hydraulic fracture behaviorcan occur in depleted reservoirs or duringrefracturing operations.14

Assess and MonitorVarious methods are available to assess hydraulicfracture geometry before, during and afterfracture creation (next page).15 The accuracy ofindirect well-response techniques is linked tothe accuracy of the fracture and reservoir modelsthat generate the prediction. By far the mostcommon way to judge how well the treatmentwas delivered and its resulting geometry is toperform a net-pressure fracture analysis shortlyafter, or even during, the fracture treatment. Theresult of this analysis is closely linked to treatingpressure and therefore suffers when actualbottomhole pressure data are not available.Unfortunately, on a large percentage of jobs,treating pressure is measured at the surface—corrected for hydrostatic head and pipe friction.A more accurate treating pressure is measureddownhole, but even accurate treating pressuredata do not necessarily reflect fracture geometry.16

Another indirect way to deduce the geometryof hydraulic fractures uses post-treatmentproduction data. This method determines thewell productivity and is represented as aneffective fracture geometry that reflects theportion of the hydraulic fracture that is open,cleaned up and contributing to production. It mayrequire months to years of production history to

44 Oilfield Review

10. Brown E, Thomas R and Milne A: “The Challenge ofCompleting and Stimulating Horizontal Wells,” OilfieldReview 2, no. 3 (July 1990): 52–63.

11. Fracture propagation occurs when the stress-intensityfactor exceeds the degree of fracture toughness nearthe fracture tip. Fracture toughness, or the criticalstress-intensity factor, can be measured by performingcore burst tests in the laboratory.

12. Barree et al, reference 2.

Jeffery RG, Settari A and Smith NP: “A Comparison of Hydraulic Fracture Field Experiments, IncludingMineback Geometry Data, with Numerical FractureModel Simulations,” paper SPE 30508, presented at theSPE Annual Technical Conference and Exhibition, Dallas,October 22–25, 1995.

14. Dozier G, Elbel J, Fielder E, Hoover R, Lemp S, Reeves S,Siebrits E, Wisler D and Wolhart S: “RefracturingWorks,” Oilfield Review 15, no. 3 (Autumn 2003): 38–53.

15. Cipolla and Wright, reference 2.16. Barree et al, reference 2.

Wright CA, Weijers L, Davis EJ and Mayerhofer M:“Understanding Hydraulic Fracture Growth: Tricky butNot Hopeless,” paper SPE 56724, presented at the SPEAnnual Technical Conference and Exhibition, Houston,October 3–6, 1999.

13. Peterson RE, Warpinski NR, Lorenz JC, Garber M,Wolhart SL and Steiger RP: “Assessment of theMounds Drill Cuttings Injection Disposal Domain,” paper SPE 71378, presented at the SPE AnnualTechnical Conference and Exhibition, New Orleans,September 30–October 3, 2001.

Winter 2005/2006 45

perform the analysis, and the fracture geometrythat has been cleaned up may be vastly differentfrom the fracture geometry created hydraulically.The effective producing geometry is importantfor production estimation, but will, in general,underestimate the hydraulic fracture length.

Similar to the production analysis method,estimating fracture geometry from well testingmethods—buildup and drawdown—betterdefines the effective production geometry thanwhat has been created hydraulically.

Near-wellbore methods have been used toinvestigate the presence of hydraulic fractures.These include radioactive tracers, and temper-ature and production logs. While these tech-niques are widely used to detect the presence ofhydraulic fractures and estimate fracture height,their limitation is that they measure in a regionthat is at or near the wellbore and may not berepresentative of what is occurring away fromthe borehole.

Advances in radioactive isotope taggingduring injection and in the interpretationmethods that use hundreds of spectral channels

allow stimulation engineers to better discernfluid and proppant placement during multiple-stage stimulation treatments. Temperaturesurveys run after stimulation treatments identifynear-wellbore regions that have been cooled bythe injection of fracturing fluids and thereforeprovide an estimate of fracture height.Production logs—measurements such as fluidflow, fluid density and temperature—are used toidentify perforation intervals that are open andcontributing to flowback or production. Apositive flow response from a perforated interval

> Capabilities and limitations of indirect and direct hydraulic fracture diagnosis techniques. (Adapted from Cipolla and Wright,reference 2.)

• Cannot resolve individual and complex fracture dimensions• Mapping resolution decreases with depth (fracture azimuth 3° at 3,000-ft depth and 10° at 10,000-ft depth)

cannot determinemay determinecan determineTechniques

Main Limitations

Ability to Estimate

FractureDiagnostic

MethodGroup

Capabilities and Limitations of Fracture Diagnostics

Leng

th

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ht

Asym

met

ry

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, dur

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frac

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Mod

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ased

Surfacetiltmetermapping

Downholetiltmetermapping

Microseismicmapping

Radioactivetracers

Temperaturelogging

Productionlogging

Boreholeimage logging

Downholevideo

Net-pressurefracture analysis

Well testing

Productionanalysis

• Resolution in fracture length and height decreases as monitoring-well distance increases

• No information about proppant distribution and effective fracture geometry

• Limited by the availability of potential monitoring wells

• Measurement in near-wellbore volume• Provides only a lower limit for fracture height if fracture and well path are not aligned

• Limited by the availability of potential monitoring wells

• No information about proppant distribution and effective fracture geometry

• Dependent on velocity-model correctness

• Thermal conductivity of different formations can vary, skewing temperature log results

• Post-treatment log requires multiple passes within 24 h after the treatment

• Provides only a lower limit for fracture height if fracture and well path are not aligned

• Run only in open hole• Provides fracture orientation only near the wellbore

• May have openhole applications

• Run mostly in cased holes and provides information only about zones and perforations contributing to production

• Results dependent on model assumptions• Requires accurate permeability and reservoir pressure estimates

• Results dependent on model assumptions• Requires accurate permeability and reservoir pressure estimates

• Results depend on model assumptions and reservoir description• Requires “calibration” with direct observations

• Provides only information about zones or perforations contributing to production in cased-hole applications

suggests that the zone has been stimulated,especially if it compares favorably with apretreatment logging pass. However, flow intothe wellbore from a set of perforations may notmean that a specific interval has been treatedmore effectively because reservoir fluids can flowthrough communicating hydraulic fractures fromone zone to the next.

In an effort to better characterize hydraulicfracture behavior and geometry away from thewellbore, two HFM Hydraulic FractureMonitoring techniques have proved enormouslysuccessful. These far-field fracture-mappingmethods are surface and downhole tiltmetersand microseismic monitoring (above). Availablefor more than a decade, tiltmeters measure

hydraulic fracture-induced tilt, or deformation.By placing these devices in an array of shallowboreholes—20 to 40 ft [6 to 12 m] deep—deformation induced by fracture creation ismeasured. A map of deformation at the surfacecan be constructed from these surface data,allowing estimation of the azimuth, dip, depthand width of the hydraulic fracture.

Downhole tiltmeters are deployed in nearbymonitoring wells at a depth similar to that of thecreated fracture. Because this technique allowsthe sensors to be placed much closer to apropagating fracture than the surface method,the fracture geometry measurements tend to bemore accurate and include fracture azimuth,height, length and width.17 The success of

tiltmeter methods usually depends on the spatialrelationship between the tiltmeters—surface ordownhole—and the treatment well.

Mapping with surface tiltmeters haslimitations when attempting to characterizehydraulic fractures deeper than 10,000 ft[3,050 m]. As a general rule, downhole tiltmeterslose their effectiveness when the distance fromthe hydraulic fracture to the tiltmeter exceedsthree times the length of the created fracture.Another method, first investigated in 1982,monitors far-field fracture growth and geometryusing sensitive seismic receivers, such as theSchlumberger VSI Versatile Seismic Imager tool, deployed in nearby wells to detectmicroseismic events.18

46 Oilfield Review

17. Barree et al, reference 2.Cipolla and Wright, reference 2.

18. Albright JN and Pearson CF: “Acoustic Emissions as a Tool for Hydraulic Fracture Location: Experience at the Fenton Hill Hot Dry Rock Site,” SPE Journal 22(August 1982): 523–530.

20. Warpinski NR, Wolhart SL and Wright CA: “Analysis andPrediction of Microseismicity Induced by HydraulicFracturing,” paper SPE 71649, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, September 30–October 3, 2001.

19. Arroyo JL, Breton P, Dijkerman H, Dingwall S, Guerra R,Hope R, Hornby B, Williams M, Jimenez RR, Lastennet T,Tulett J, Leaney S, Lim T, Menkiti H, Puech J-C,Tcherkashnev S, Burg TT and Verliac M: “SuperiorSeismic Data from the Borehole,” Oilfield Review 15,no. 1 (Spring 2003): 2–23.

> Tiltmeter and microseismic methods of far-field fracture monitoring. Tiltmeters (top) measure smallchanges in earth tilt. When these are mapped they show the deformation in response to the creationof hydraulic fractures. Tiltmeters can be deployed on surface or downhole in a monitoring wellbore.Microseismic monitoring (bottom) uses sensitive, multicomponent sensors in monitoring wells torecord microseismic events, or acoustic emissions (AEs), caused by rock shearing during hydraulicfracture treatments. The microseismic data are then processed to determine the distance andazimuth from the receiver to the AE and the depth of the AE.

Treatment well

Microseismic eventReceivers

Reservoir

Hydraulic fracture

Monitoring well

Downhole tiltmetersin monitoring well

Fracture-induced trough at surface Surface tiltmeters

Fractureracture

Dept

h

Winter 2005/2006 47

Tracking the CrackingMicroseismic events, or small earthquakes, occurwhen the normal stress is reduced alongpreexisting planes of weakness until shearslippage occurs. These shear movements emitboth compressional and shear waves that can bedetected by geophones. However, many believethe tensile cracking of rock that occurs duringfracture stimulation has a minimal contribution todetectable microseismic activity. Because thiszone of shearing accompanies the fracture tiparea, locating the source of these waves in spaceand time allows scientists and engineers toconstruct a map of the created fracture by plottingthe location of acoustic emissions (AEs) over timewhile fracturing. However, AEs may also occuraway from the fracture tip where there is fluidleakoff into the matrix or where stress changescause shear slippage in natural fractures.

To record compressional and shear waves,multicomponent—for example, three-component(3C)—geophones are placed in a monitoring wellto determine the location of microseismic events.The distance to the event can be calculated bymeasuring the difference in arrival timesbetween the compressional, or primary (P-(( )

waves, and shear, or secondary (S-(( ) waves. Also,hodogram analysis, which examines the particlemotion of the P-waves, may determine theazimuth angle to the event. The depth of theevent is constrained by using the P- and S-wavearrival delays between receivers observed at the monitoring well (above). This localizationtechnique requires an accurate velocity modelfrom which to calculate event locations, a low-noise environment, highly sensitive geophones torecord microseismic events and knowledge of theexact location and orientation of the receivers.Although this may seem simple, the process iscomplex and challenging.

The quality of hydraulic fracture charac-terization is directly linked to the quality of thevelocity model, or velocity structure, on whichthe interpretation is based. Initial velocitymodels typically are built using borehole soniclogs that describe the vertical velocity changes atwellbores. However, the time it takes for an AEto go from the source—near the hydraulicfracture—to the receiver and the direction fromwhich it comes into the receiver are influencedby the interwell geology. Borehole seismic

measurements, such as vertical seismic profiles(VSPs), provide detailed velocity informationaround the monitoring well. VSP surveys helprelate the time domain to the depth domain andtherefore help calibrate the velocity model. TheVSI tool used to acquire the VSP data alsorecords the microseismic events, ensuringconsistency in data acquisition, processing and interpretation.19

Reservoir-fluid type may also impact micro-seismic activity. Fluid factors can reduce stressand pore-pressure changes in the formation thatoccur during fracturing. Having gas in theformation instead of less compressible liquidsdecreases the area of microseismic activity.Consequently, some in the industry believe thatgas-filled reservoirs produce a narrower band ofmicroseismic events that more clearly definesthe geometry of the fracture.20

To locate AEs, a monitoring tool—typically anarray of eight 3C geophones for the VSI tool—isdeployed in a monitoring well within 2,000 ft[610 m] of the treatment well at roughly the samedepth as the treatment interval. The optimalplacement and geometry of the microseismic toolwithin the monitoring well are heavily dependent

> Locating acoustic emissions. The distance (D) to the event can be derived by measuring theDDdifference (∆T ) between the compressional, or primary (P-) wave and the shear, or secondary (S-)wave arrival times, Tp and Ts, respectively (top left). The valuett D is heavily dependent on the velocitymodel (bottom left), which is usually described by the tt P- and S-wave velocities, - Vp and Vs, respectively,of each layer in the model. The second coordinate, azimuth to the microseismic event, is determinedby examining the particle motion of the P-waves using hodograms (- top right). The depth of thettmicroseismic event, the third coordinate, is derived by examining the P- and S-wave arrival delaysbetween receivers, or moveout, at the monitoring well (bottom right).tt

Depth Determination

4,000 8,000 12,000 16,000

Velocity, ft/s

6,300

5,300

4,300

Dept

h, m

Velocity Model

Treatment well Monitoring well

Distance Determination

Azimuth-Angle Determination

P S

TpTT TsTT

∆T∆T = T TsTT – T .pTTD = ∆D T .p s / (s p s)

on the surrounding velocity structure, so accurateearth models help optimize the monitoringconfiguration.21 Unfortunately, the ideal spatialconfiguration between the treatment wellboreand potential monitoring wellbores occurs in only a small percentage of cases. Consequently,there is an ongoing effort to enable the recordingof AEs from treatment wells—a harsh and noisy environment.

Producing oil fields have many sources ofnoise that may have a negative impact on themicroseismic HFM technique, includingelectrical noise, nearby drilling activity andhydraulic fracturing jobs or fluid flowing fromperforations in the monitoring well. Much of thenoise can be eliminated on site or throughadaptive filtering during data processing.Improved seismic response can also be achievedthrough advances in acquisition technology.

For example, the Schlumberger microseismicHFM technique uses the VSI device, whichprovides excellent vector fidelity (right).22 TheVSI tool is deployed on wireline cable and usesthree-axis technology in each sensor package, orshuttle; eight sensor packages are typicallydeployed. The tool’s sensors were designed to beacoustically isolated from the main body of thetool but acoustically coupled to the casing duringthe HFM operation. This helps minimize thepotential for noise and maximize data qualitywhen recording very small microseismic events.The number of sensor sections and their spacingwithin the VSI configuration can be adjusted,depending on what is required.23

Optimal positioning of the sensor arrayshould be determined using network survey-design techniques.24 Once the VSI tool is set atthe appropriate depth in a monitoring well, theHFM engineer must determine the orientation ofthe tool to make use of particle-motion data fordetermining the azimuth angle. This isaccomplished by monitoring a perforation shot,string shot or other seismic source in thetreatment well, or in another well near thetreatment well.25 The utility of perforations orstring shots to calibrate velocity models has beendocumented.26 However, shot-based velocities areoften substantially different—sometimes higher,sometimes lower—than velocities calculatedfrom sonic data. These differences may be due toperforation-timing problems, imprecise locationsof perforations and receivers because ofinaccurate or nonexistent wellbore-deviationsurveys, reservoir heterogeneity between thetreatment and monitor wells, and inherent

differences between the velocity measurementsbeing compared—including anisotropy andinvasion effects.27

With the tool orientation determined, thesurface equipment is set up for continuousmonitoring, and when an event is detected,buffered data are recorded. On-site processinglocates the microseismic events, using one ofseveral available processing techniques, and theresults are transmitted to the fracturingoperations team at the treatment well location.The data are also sent to a processing center formore detailed interpretation.28

48 Oilfield Review

> Measuring acoustic emissions. The Schlumberger VSI Versatile Seismic Imager tool (left) usestttthree-axis (x, y, z) geophone accelerometers (right) that are acoustically isolated from the tool bodyttby an isolation string to acquire high-fidelity seismic data. The VSI device is mechanically coupled totthe casing or formation by a powerful anchoring arm. The coupling quality can be tested by using aninternal shaker before operations commence. Up to 40 sensor packages, or shuttles, can be linkedttogether to increase vertical coverage; however, eight shuttles are normally used in HFM operations.The tool is available in 3.375-in. and 2.5-in. diameters.

xz

y

Shaker Couplingcontacts

Threecomponents

Isolationspring

Texas Proving GroundIn the mining, waste disposal, geothermal andgas-storage industries, microseismic methodshave long been used to help understand thenature of hydraulically created fractures.However, recent improvements in tool design,processing and mapping accuracy, coupled withthe growing importance of low-permeability,hydraulically fractured reservoirs as a resource,have increased this technology’s utility in the oiland gas industry. The Barnett Shale reservoir inthe north-central Texas Fort Worth basin—oneof today’s most active gas plays in the USA—highlights the importance of direct and timelymicroseismic hydraulic fracture character-ization.29 Today, Barnett Shale fields produce

Winter 2005/2006 49

more than 1,200 million ft3/d3 [34 million m3/d],3

58% of thef total gas production from US gasshales (left).30

The Barnett Shale formation is anaturally fractured, ultralow-permeability—about 0.0002 mD—reservoir. Because of thisfextremely lowy permeability,w a large hydraulicfracture surface area is required to effectivelystimulate the reservoir. Consequently, largevolumes of fluidf are pumped at high rates duringstimulation treatments.

The Barnett Shale is a Mississippian-age,organic-rich, marine-shelf shalef deposit thatcontains fine-grained, nonsiliciclastic material.This formation overlies a major unconformitysurface that truncates the Ordovician-age rocksbelow. Throughout much of thef productive area,the Viola limestone creates a lower barrier tohydraulic fracturing and separates the under-lying, water-bearing Ellenberger formation fromthe Barnett Shale. Hydraulic fractures thatbreak through the Viola limestone typicallyresult in unwanted water production anddecreased gas production.

Stimulation of thef Barnett Shale has hadvariable effectiveness for reasons that are poorlyunderstood. The companies initially operatingy inthe Barnett Shale soon observed that thisreservoir did not respond to stimulation in thesame way asy conventional gas reservoirs. Unusualpost-treatment occurrences in which neigh-boring wells watered out indicated extremelylong hydraulic fracture growth, often inunexpected directions from treatment wells.Modern hydraulic fracture monitoring methods,most notably microseismicy monitoring, haveshown that Barnett Shale stimulation anddevelopment are complicated by naturalfractures and faults, which drastically influenceyhydraulic fracture behavior along with reservoirproductivity andy drainage. Moreover, the stressanisotropy iny the Barnett Shale is low, soattempts to model hydraulic fracture behaviorand geometry asy simple, single-plane events havebeen ineffective.

In the last five years, engineers and scientistshave learned more about the natural andhydraulic fracture systems in the Barnett Shaleformation. With that knowledge, they haveyadapted drilling strategies to improve gasproduction and recovery.31 One of thesef strategiesis the incorporation of horizontalf wells. Whileapproximately twicey as expensive as a verticalwell, horizontal wells typically generateyestimated ultimate recoveries that are threetimes greater than those of verticalf wells.

21. Le Calvez JH, Bennett L,t Tanner KV, Grant WD,t Nutt L,tJochen V, Underhill W and Drew J: “MonitoringMicroseismic Fracture Development tot OptimizeStimulation and Production in Aging Fields,” TheLeading Edge 24, no. 1 (January 2005): 72–75.

22. Vector fidelity is the property of multicomponent seismictreceivers to respond correctly to an impulse. A correctresponse occurs when a given impulse applied parallelto one of the three components registers only on thatcomponent andt when applied parallel to eachcomponent individuallyt registers the same magnitudeon each of the three components. The motion that istdetected by multicomponent seismict receivers ideallyis the same as the original impulse.Nutt L,t Menkiti H and Underhill B: “Advancing the VSPEnvelope,” Hart’s E&P 77, no. 10 (October 2004): 51–52.

23. Nutt ett al,t reference 22.24. Curtis A, Michelini A, Leslie D and Lomax A: “A

Deterministic Algorithm for Experimental Design Appliedto Tomographic and Microseismic Monitoring Surveys,”Geophysical Journal International 157, no. 2 (May 2004):595–606.

25. A string shot ist made up of Primacord detonating cordfired at strategict locations, for example near thetreatment depth,t to transmit at seismic wave withoutcreating a hole in the casing.

26. Warpinski NR, Sullivan RB, Uhl JE, Waltman CK andMachovoe SR: “Improved Microseismic FractureMapping Using Perforation Timing Measurements forVelocity Calibration,” paper SPE 84488, presented at thetSPE Annual Technical Conference and Exhibition,Denver, October 5–8, 2003.

27. Eisner L and Bulant P:t “Borehole Deviation Surveys AreNecessary for Hydraulic Fracture Monitoring,” preparedfor presentation at thet 86th EAGE Conference andExhibition, Vienna, Austria, June 12–15, 2006.

28. Durham LS: “Fracture ‘Groans’ Quietly Noisy:Microseismic Detection Emerging,” AAPG Explorer 25,no. 12 (December 2004): 16–18.

29. Frantz JH, Williamson JR, Sawyer WK, Johnston D,Waters G, Moore LP, MacDonald RJ, Pearcy M,Ganpule SV and March KS: “Evaluating Barnett ShaletProduction Performance Using an IntegratedApproach,” paper SPE 96917, presented at thet SPEAnnual Technical Conference and Exhibition, Dallas,October 9–12, 2005.Maxwell SC, Urbancic TI, Steinsberger N and Zinno R:“Microseismic Imaging of Hydraulic Fracture Complexityin the Barnett Shale,”t paper SPE 77440, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, September 29–October 2, 2002.Fisher MK, Wright CA,t Davidson BM, Goodwin AK,Fielder EO, Buckler WS and Steinsberger NP:“Integrating Fracture Mapping Technologies to OptimizeStimulations in the Barnett Shale,”t paper SPE 77441,presented at thet SPE Annual Technical Conferenceand Exhibition, San Antonio, Texas, September 29–October 2, 2002.

30. http://www.pickeringenergy.com/pdfs/TheBarnettShaleReport.pdf (accessedf November 30,r 2005).

31. Fisher MK, Heinze JR, Harris CD, Davidson BM, Wright CAtand Dunn KP: “Optimizing Horizontal CompletionTechniques in the Barnett Shalet Using MicroseismicFracture Mapping,” paper SPE 90051, presented at thetSPE Annual Technical Conference and Exhibition,Houston, September 26–29, 2004.

> Map of the north-central Texas Fort Worth basin showing Barnett Shaleactivity. There are currently more than 3,400 vertical and 300 horizontalwells producing from the Barnett Shale reservoir.

USAUU

Texas

Gainesville

Dallas

Fort Worth

Wichita Falls

O K L A H O M A

T E X A S

250 miles

0 25k

Producing wellsHorizontal-wellpermits

They have also been instrumental in opening upareas of the play where vertical wells have hadlimited success: in areas where the Violalimestone is absent and fracturing down into thewet Ellenberger is common. Optimum completiondesign in these wells is made more problematic

because of the complex nature of the hydraulicfracturing. Factors such as perforation-clusterspacing along laterals, stimulation stagingstrategies, fracture treatment sizing and offset-well placement all must be addressed to optimizeresource development.

Chesapeake Energy is one of severaloperators investigating the complexity offracturing the Barnett Shale from horizontalwellbores and its implications for acreagedevelopment. In February 2005, Chesapeakeused the StimMAP hydraulic fracture stimulationdiagnostics service in a vertical monitoring wellto determine fracture height, length, azimuthand complexity during a four-stage “slickwater”stimulation treatment on a horizontal well in theNewark East field.32 The design objective was toplace hydraulic fractures normal, or transverse,to the lateral. After perforating for each stage, apretreatment injection test was performed todetermine closure pressure and the rate ofpressure decline, which is a function of thedegree of natural fracturing because the matrixpermeability is too low to allow leakoff.

During all four stages, the primary fracturepropagation azimuth determined from micro-seismic monitoring was N60°E-S60°W, with anobserved preference for southwesterly growth(below and left). Most of the detected microseismicemissions were located to the southwest becauseof the monitoring configuration—bias existedbecause the monitoring well was positionedapproximately 2,000 ft to the southwest of thehorizontal treatment wellbore. In this case,formation heterogeneities were unlikely to bethe cause of the southwesterly bias. Chesapeakewas able to observe cross-stage communicationalong the lateral between Stages 1 and 2 andbetween Stages 2 and 3, which reduced theeffectiveness of those treatments.

50 Oilfield Review

32. Slickwater treatments use low proppant concentrations—in this case, less than 0.8 lbm/gal US [9.6 kg/m3]—allowing high-volume treatments at reduced cost. Thistype of treatment has been successful in the BarnettShale because it creates long fractures that connectwith crosscutting natural fractures, thereby increasingthe total effective hydraulic fracture length and drainagearea in a single well.

> Maps of microseismic events from the four-stage hydraulic fracture stimulation. The StimMAP displays include a three-dimensional (3D) view (top) anda plan view (middle). The treatment stages are color-coded: Stage 1 is purple, Stage 2 is blue, Stage 3 is green, and Stage 4 is yellow. Also included is asummary of each stage, including acoustically determined fracture system length, width and preferential azimuth (bottom). Depths are given relative totthe kelly bushing (KB).

91

517

369

444

Number ofN b fNumber ofNumber ofNumber ofNumber ofeventseventseventseventsevents

Z,360

Y,740

Y,025

X,358

PerforatedP f dP f t dPerforatedPerforatedPerforatedPerforatedintervali t lintervalintervalintervalintervaltop, MDt MDtop MDtop MDtop MDtop, MDp,

from KB, ftf KB ffrom KB ftfrom KB ftfrom KB ftfrom KB, ft,

Z,853

Z,227

Y,588

X,513

PerforatedP f dP f t dPerforatedPerforatedPerforatedPerforatedintervali t lintervalintervalintervalinterval

bottom, MDb tt MDbottom MDbottom MDbottom MDbottom, MD,from KB, ftf KB ffrom KB ftfrom KB ftfrom KB ftfrom KB, ft,

X,797

X,734

X,784

X,740

FractureFF tFractureFractureFractureFracturesystemtsystemsystemsystemsystemy

top, TVDt TVDtop TVDtop TVDtop TVDtop, TVDp,from KB, ftf KB ffrom KB ftfrom KB ftfrom KB ftfrom KB, ft,

Y,290

Y,305

Y,305

Y,309

FractureFF tFractureFractureFractureFracturesystemtsystemsystemsystemsystemy

bottom, TVDb tt TVDbottom TVDbottom TVDbottom TVDbottom, TVD,from KB, ftf KB ffrom KB ftfrom KB ftfrom KB ftfrom KB, ft,

493

571

521

569

FractureF tFractureFractureFractureFracturesystemtsystemsystemsystemsystemy

height, fth i h fheight ftheight ftheight ftheight, ftg ,g

1,918

1,728

1,556

1,521

SWSWSWSWSWSWextent, ftfextent ftextent ftextent ftextent, ft,

299

409

482

424

NENENENENENEextent, ftfextent ftextent ftextent ftextent, ft,

2,217

2,137

2,038

1,945

FractureF tFractureFractureFractureFracturesystemtsystemsystemsystemsystemy

length, ftl h flength ftlength ftlength ftlength, ftg ,g

1,143

2,275

1,138

527

FractureF tFractureFractureFractureFracturesystemtsystemsystemsystemsystemywidth, ftid h fwidth ftwidth ftwidth ftwidth, ft,

N60°E

N60°E

N60°E

N60°E

AzimuthA i hAzimuthAzimuthAzimuthAzimuth

Stage 2

Stage 3

Stage 4

WellW llWellWellWellWell

Stage 1

N

Hydraulic Fracture Data

Event rateTreating pressure, psiSlurry rate, bbl/min

N

Winter 2005/2006 51

During Stage 2, engineers on locationobserved that the bottomhole treating pressuresmatched those of Stage 1, so Chesapeake askedthe Schlumberger engineer to produce a quicksnapshot of the Stage 2 microseismic eventlocations. When compared to the Stage 1StimMAP results, the snapshot confirmed thatthe Stage 2 fracture was communicating with theprevious stage. To remedy this, three slugs ofproppant sand were pumped at a reduced rate todivert the treatment fluid away from theperforations that were taking the majority of thetreatment. Microseismic data confirmed that thetreatment had communicated with a complex setof parallel and conjugate natural fractures.

The Stage 3 perforation intervals werealtered to avoid a fault. Hydraulic fracturemonitoring confirmed that two primary fractureswere created on each side of the fault and werepossibly also affected by the presence of naturalfractures. Stage 4 did not appear to overlap withother stages.

In August 2005, Chesapeake used theStimMAP service on another horizontal well inNewark East field to determine the influence of afaulted karst zone on hydraulic fracturegeometry and orientation. Again, the stimulationinvolved four stages—slickwater treatments forStages 1, 3 and 4, and a CO2-fluid system forStage 2. The treatments were monitored from awell south-southwest of the east-southeast-oriented horizontal leg of the treatment well. Thedistance from the hydraulic fracturing to themonitoring well ranged from less than 500 ft[150 m] to more than 2,000 ft, depending on thelocation of the stage along the horizontalwellbore (below and right).

> Maps of microseismic events from another four-stage hydraulic fracture treatment. The StimMAP displays include a three-dimensional (3D) view (top)and a plan view (middle). The treatment stages are color-coded: Stage 1 is purple, Stage 2 is blue, Stage 3 is green, and Stage 4 is yellow. Also included isa summary of each stage, including acoustically determined fracture system length, width and preferential azimuth (bottom). Depths are given relative tomean sea level (MSL).

140

98

68

94

Number ofN b fNumber ofNumber ofNumber ofNumber ofNumber ofeventsteventseventseventsevents

Stage 1

Stage 2

Stage 3

Stage 4

WellW llW llWellWellWellWell

X,970

X,954

X,954

X,949

PerforatedP f dP f t dPerforatedPerforatedPerforatedPerforatede o a edinterval, TVDi t l TVDinterval TVDinterval TVDinterval TVDinterval, TVDinterval, TVD,from MSL, ftf MSL ff MSL ftfrom MSL ftfrom MSL ftfrom MSL ftfrom MSL, ft,

491

863

985

637

FractureFF tFractureFractureFractureFractureac u esystemtsystemsystemsystemsystemsystemy

height, fth i h fh i ht ftheight ftheight ftheight ftheight, ftg ,g

419

739

799

1,038

SSWSSSSWSSWSSWSSWSSWSSWextent, ftft t ftextent ftextent ftextent ftextent, ft,

264

178

676

630

NNENNENNENNENNENNENNEextent, ftft t ftextent ftextent ftextent ftextent, ft,

1,105

1,168

1,247

1,942

FractureFF tFractureFractureFractureFractureac u esystemtsystemsystemsystemsystemsystemywidth, ftid h fidth ftwidth ftwidth ftwidth ftwidth, ft,

N15°E

N15°E

N15°E

N15°E

AzimuthA i hA i thAzimuthAzimuthAzimuthAzimuth

X,744

X,483

X,670

X,682

FractureF tFractureFractureFractureFractureFracturesystemtsystemsystemsystemsystemsys ey

top, TVDt TVDtop TVDtop TVDtop TVDtop, TVDtop, TVDp,from MSL, ftf MSL ff MSL ftfrom MSL ftfrom MSL ftfrom MSL ftfrom MSL, ft,

Y,235

Y,346

Y,655

Y,319

FractureF tFractureFractureFractureFractureFracturesystemtsystemsystemsystemsystemsys ey

bottom, TVDb tt TVDbottom TVDbottom TVDbottom TVDbottom, TVDbottom, TVD,from MSL, ftf MSL ff MSL ftfrom MSL ftfrom MSL ftfrom MSL ftfrom MSL, ft,

683

917

1,475

1,168

FractureFF tFractureFractureFractureFractureac u esystemtsystemsystemsystemsystemsystemy

length, ftl h fl th ftlength ftlength ftlength ftlength, ftg ,g

758

551

400

393

NNWNNWNNWNNWNNWNNWNNWextent, ftft t ftextent ftextent ftextent ftextent, ft,

347

617

847

1,549

SSESSSSESSESSESSESSESSEextent, ftft t ftextent ftextent ftextent ftextent, ft,

E

Time

Legend

Hydraulic Fracture Data

Event rateTreatment time, minTreatment pressure, psi

Chesapeake knew the location of four faultsin the area from seismic images and well control,so engineers placed multiple perforation clusterswithin each stage to avoid directly fracturing intothe faults. Even with these precautions, fractureinitiation was influenced by the presence offaults near Stages 1, 2 and 4 (above). Stage 1most likely communicated with a fault. Themicroseismic and pressure evidence supportedthis scenario. The bulk of the microseismicevents occurred between the second and thirdset of perforations, and the instantaneous shut-inpressure for Stage 1 was significantly lower thanthat of the other three stages.

The StimMAP service achieved Chesapeake’sobjective of defining the orientation andgeometry of the hydraulically created fracturesin the treatment well. Engineers determined thatthe dominant fracture azimuth was N15°E. Whilefracture-height growth was largely symmetricaland upwardly contained within the BarnettShale, downward growth was observed in allstages. Laterally, Stage 3 demonstrated symmet-rical growth, whereas growth in Stages 1, 2 and 4appeared asymmetrical.33 The StimMAP interpre-tation also concluded that there was littlecommunication between the different stages.

Today, much of the effort to monitor hydraulicfracture growth is directed toward fracturestimulations in horizontal wells to assessfracture height and complexities associated withfracture interference. These issues cannot beaddressed in horizontal wells with the near-wellbore evaluation methods previouslymentioned. The ability to measure hydraulicfracture characteristics allows engineers tojudge the impact of completion and stimulationdesign changes—for example, varying theplacement or spacing of perforation intervalsalong the horizontal wellbore or alteringproppant carrier fluids. Because of improvedhydraulic fracture characterization, theeffectiveness of hydraulic fracture treatments inthe Barnett Shale has been linked to the openingof secondary natural fracture systems, whichincreases the width of the treated volume.

Testing Technologies, Models andLimits in JapanEven though microseismic monitoring tech-niques have been available for years, the quest toimprove velocity modeling, data acquisition,processing and interpretation continues. Japan Exploration Company (JAPEX) andSchlumberger collaborated on a project to test

the feasibility of microseismic monitoring in theYufutsu gas field, Hokkaido, Japan.34

The reservoir in the Yufutsu field is a naturallyfractured, Cretaceous-age granite and overlyingconglomerate located at depths from 4,000 m[13,124 ft] to 5,000 m [16,405 ft]. Within the field,there is no apparent correlation between gasproduction and well location or well orientation.However, JAPEX has determined that produc-tivity is controlled by the local stress conditionand by the distribution and orientation of severalnatural fracture systems across the field.35 Morespecifically, large-aperture natural fractures, or“mega” fractures, oriented parallel to themaximum horizontal stress, act as gas conduits,while small-scale fractures affect gas storage andmigration. Characterization of the fracturesystems has been successful at the wellbore,using borehole-imaging devices such as the FMIFullbore Formation MicroImager tool. However,to understand more about reservoir behavior andto improve reservoir modeling using a discretefracture network simulator, JAPEX needed toinvestigate a larger reservoir volume.36

A preliminary injection test using a four-levelVSI tool occurred in October 2003. In December2004, JAPEX installed tubing-deployed, perma-nent seismic monitoring technology, the Vetco

52 Oilfield Review

> Influence of faults on Barnett Shale stimulation. Chesapeake placed perforations along thehorizontal completion interval to avoid fracturing into four known faults. Even with theprecautions, the StimMAP hydraulic fracture stimulation diagnostics interpretation indicatedtthat the microseismic activity was concentrated around some of the fault planes and influencedby the presence of faults near Stages 1, 2 and 4.

Lower Barnett top

Ellenberger top

Monitoring well

Stage 4 Stage 3 Stage 2 Stage 1

EW

Winter 2005/2006 53

Gray PS3 system, in the SK-2D treatment well torecord production-induced AEs. JAPEX observedonly minimal microseismicity in the field,probably because of the lack of pressure drop inthe reservoir. However, microseismic activity wasinduced during injection operations thatinitiated shearing along preexisting naturalfractures. Consequently, recording and analyzingthese AEs using hydraulic fracture monitoringtechniques could help define the geometry andextension of the natural fracture systems. A VSPand a small-scale injection experiment wereconducted in February 2005, and a large-scaleinjection experiment was performed in May 2005 (right).

The VSP data were used to enhance the existingvelocity model and ultimately proved important inthe fracture analysis. Using a seismic airgun sourceplaced in a specially designed pit at surface and11 ⁄1 6⁄⁄ -in. Createch SAM43 seismic acquisition toolsdeployed within production tubing in near and farmonitoring wells, a 49-level VSP was recordedacross the pertinent interval in both wellssimultaneously. The VSP provided good quality z-component—vertical-component—data thatallowed Schlumberger and JAPEX scientists toevaluate the coupling quality of the Createch toolsand to find the optimal tool position for amicroseismic monitoring survey. Velocityinformation from the VSP survey was also used tocorrect the existing velocity model, which in turnimproved the accuracy of calculated AE locations.

Another objective of the project was toevaluate the hydraulic fracture monitoringperformance of the permanent, tubing-conveyedVetco Gray PS3 prototype system. An upper and alower sensor were deployed in the SK-2Dinjection well. The PS3 sensors were affected byelectrical noise. However, once the noise wasreduced by error-prediction filtering, P- andS-wave arrivals were observed. Although theprototype sensors also were affected by noisefrom pumping fluid in this completion, some ofthe AE events had sufficient signal-to-noiseratios to identify P- and S-wave arrivals. This testrepresented the first successful use of multiplesensors to map hydraulically induced AEs froman injection well.

Using criteria from multiple monitoringsensors for event discrimination, the 40-h, 500-m3 [3,145-bbl] fluid-injection program inFebruary produced 920 detectable events, ofwhich 40 exhibited detectable P- and S-wavephases at three or four sensors and werelocatable with reasonable confidence. Acomparison of event locations was made between

33. The large distance between the monitor well and thereservoir volume affected by Stage 4 may be responsiblefor the asymmetry observed in the event locations.

34. Drew J, Primiero P, Leslie D, Michaud G, Eisner L andTezuka K: “Microseismic Monitoring of a HydraulicInjection Test at the Yufutsu Gas Reservoir,” paper B,presented at the 10th Formation Evaluation Symposiumof Japan, Chiba, Japan, September 29–30, 2004.

> Geometry of the injection well, two monitoring wells and sensors with a map (inset) showing thettexperiment location.

Dept

h, m

–2,000

–2,500

–3,000

–3,500

–4,000

–4,5003

21

0Distance, km 0 1 2 3 4 5 6 7

Distance, km

Near monitoring well Injection wellFar monitoring well

3,141 m3,141 m 3,188 m3 188 mm

3,656 m3,656 m,

3,339 m3,339 3

Injection pointn pointn pointection 4 0134,013 m4,013 m13 m

2000 miles

0 200k

S e ao f

J a p a n

Pa

ci f

ic

Oc

ea

n

Ea

s tC

hi n

aS

ea

J A P A N

Sapporo

Far monitoring wellInjection wellNear monitoring well

10 miles

0 1k

35. Tezuka K, Namaikawa T, Tamagawa T, Day-Lewis A andBarton C: “Roles of the Fracture System and State ofStress for Gas Production from the Basement Reservoirin Hokkaido, Japan,” paper SPE 75704, presented at theSPE Gas Technology Symposium, Calgary, April 30–May 2, 2002.

36. Tamagawa T and Tezuka K: “Validation of Clusteringof Fractures in Discrete Fracture Network Model byUsing Fracture Density Distributions Along Boreholes,”paper SPE 90342, presented at the SPE Annual Technical Conference and Exhibition, Houston,September 26–29, 2004.

those calculated using the existing velocitymodel and those calculated using the VSP-refined velocity model (left). The revised velocitymodel significantly improved the source-locationcalculations, reducing uncertainty. The resultsusing the new model showed a tighter cluster ofactivity than was evident using the previousvelocity model, which had been built from VSPinformation obtained in other parts of the field.

The larger injection experiment in Maypumped 5,600 m3 [35,223 bbl] of fluid duringsix days in four different tests, or stages.37 Theexperiment produced 447 located events out of atotal of 2,515 detected events, some of whichoccurred after pumping had stopped (next page).

To determine the impact of monitoring frommultiple wells, the event locations calculatedusing only data from the near monitoring wellwere compared with the event locationscalculated using data from multiple monitoringlocations. The criteria for multiwell localizationwere that clear P-wave and S-wave arrivals couldbe picked at the near well, that at least oneP-wave arrival could be picked at the farmonitoring well and that at a minimum one P- orS-wave arrival could be picked from the PS3

treatment well data.The localization algorithm was then run on

both the single-well data and the multiwell data,using the new velocity model. With single-welldata, distance to the event was calculated usingthe P- and S-wave traveltime data, and angles ofray incidence were determined using hodogramanalysis. For single-well and multiwell processing,hypocenter estimates were made using theprobability density functions formed frommeasured and modeled time delays and angles.38

The single-well location cluster is more dispersedand more difficult to interpret than the multiple-well distribution, which also shows additional

54 Oilfield Review

> The impact of having a VSP-calibrated velocity model. A comparisonof the February 2005 test microseismic event localizations using thepreexisting velocity model (top) versus using the local VSP-calibratedvelocity model (bottom) shows a tighter clustering of events using theupdated model. This significantly reduces the uncertainty in defininghydraulic fracture geometry and orientation. In each of the displays, aplan view is shown on top, a north-to-south cross section is located in thelower left and a west-to-east cross section is shown in the lower right.

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37. Primiero P, Armstrong P, Drew J and Tezuka K:“Massive Hydraulic Injection and Induced AEMonitoring in Yufutsu Oil/Gas Reservoir—AEMeasurement in Multiwell Downhole Sensors,”paper 50, presented at the SEGJ 113th Annual FallMeeting, Okinawa, Japan, October 16–18, 2005.

38. Michaud G, Leslie D, Drew J, Endo T and Tezuka K:“Microseismic Event Localization and Characterizationin a Limited-Aperture HFM Experiment,” ExpandedAbstracts, SEG International Exposition and 74th AnnualsMeeting, Denver (October 10–15, 2004): 552–555.Tarantola A and Valette B: “Inverse Problems: Quest forInformation,” Journal of Geophysics 50 (1982): 159–170.

Winter 2005/2006 55

> Examining acoustic emission (AE) magnitude and quantity during the second injection stage in Yufutsu gas field, Japan.This test started with a 2.5-h step-rate injection, followed by a series of 1-h high-rate injections, each followed by 1-hshut-in cycles. Next, a continuous injection rate of 14 bbl [2.2 m3] per minute was maintained for 19 h, with an exceptionfor scheduled pump maintenance. The middle plot displays estimated event magnitude. The size of the green ellipses isproportional to the signal-to-noise ratio. The number of microseismic events is shown on the bottom plot. Tubingpressure (blue) and pump rate (magenta) are displayed on both plots. A plan view (top) shows the located events thatwere attributed to this particular stage (black) of the total number of located events during the entire May 2005 injectionexperiment (gray). The beginning of the step-rate injection shows a pressure and rate threshold before AEs start tooccur and, while the number of events decreases during the shut-in periods, AEs still occur in large numbers afterpumping has stopped.

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activity significantly farther to the north of the point of injection (right). The comparisonbetween the two results highlights the challengeof monitoring hydraulic fracture behavior in thefield, where monitoring options can be limited toa single well.

One of the primary motivations for acquiringpressure and AE measurements whilemonitoring the Yufutsu stimulation was the useof that information to validate reservoir-simulation models. JAPEX has developed anumerical simulator, which simulates theshearing of rocks, the associated AEs and thepermeability enhancements during hydraulicsimulation.39 Comparison of simulated andmeasured AE event locations along with iterativematching of pressure histories was used to helpconfirm the validity of the simulations.

In addition to improving the characterizationof natural fracture systems and reservoirmodeling in the Yufutsu gas field, the injectionexperiments have confirmed the value of anaccurate velocity model and the advantages ofmonitoring AEs from multiple stations. Althoughlonger monitoring distances are less desirable,the experiment shows that monitoring can bedone from considerable distances, depending onthe geology. In this case, the farthest monitoringtool in the far monitoring well was about 2.5 km[8,200 ft] from the microseismic activity.

AE data provide information about the spatialdistribution of the fracture system. Advancedmapping techniques such as the double-difference method and multiplet analysis providesource locations so precisely that AE clusters andfracture-related structures can be extracted.40

For instance, the results of the double-differencemethod applied to the Yufutsu dataset givesmultiple linear structures, which are interpretedas a medium-scale fracture system, bridging the

56 Oilfield Review

> A comparison of event localization from one monitoring well and frommultiple monitoring locations. The AE data from the May 2005 injectionexperiment were located based on the hodogram analysis—to determineangle—and P- and S-wave traveltimes—to determine distance. Fracture-maps that used only data from the near monitoring well (top) werecompared with fracture maps that used data from three monitor welllocations (bottom). The use of multiple monitoring locations constrainedtthe number of possible event localization solutions to yield fewer, buthigher quality localizations, which produces a clearer representation oftthe activity.

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39. Tezuka K, Tamagawa T and Watanabe K: “NumericalSimulation of Hydraulic Shearing and Related AE Activityin Fractured Gas Reservoir,” paper A, presented at the10th Formation Evaluation Symposium of Japan, Chiba,Japan, September 29–30, 2004.

40. The double-difference method is a mapping techniquethat relates multiple pair of events relative to each other.Multiplets are clusters of nearly identical wavelets frommultiple events with a similar focal mechanism thatoriginate at the same, or very nearly the same, locationbut occur at different times.

41. Tezuka K, Tamagawa T and Watanabe K: “NumericalSimulation of Hydraulic Shearing in FracturedReservoir,” paper 1606, presented at the WorldGeothermal Congress, Antalya, Turkey, April 24–29, 2005.

42. Drew J, Leslie D, Armstrong P and Michaud G:“Automated Microseismic Event Detection and Locationby Continuous Spatial Mapping,” paper SPE 95513,presented at the SPE Annual Technical Conference andExhibition, Dallas, October 9–12, 2005.

43. Eisner L and Sileny J: “Moment Tensors of EventsInduced in Cotton Valley Gas Field from WaveformInversion,” paper P227, presented at the EAGE 66thConference and Exhibition, Paris, June 7–10, 2004.

First step-rate test

Second step-rate test,first high-rate test

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Winter 2005/2006 57

gap between the fault system and fracturesobserved on borehole images.

Another advantage of AE data is that theyprovide spatial constraints for reservoirsimulation. JAPEX developed the Simulator forHydraulic Injection and Fracture Treatment(SHIFT) to simulate hydraulic injectionexperiments.41 This simulator works on a discretefracture-network model and simulates theshearing of preexisting fractures, related AEactivity and permeability enhancement in adynamic process. It does this by coupling fluid-flow analysis and shear-induced fracture-dilationanalysis. The AEs and the injection pressuresobserved during the experiment were used forthe postjob matching analysis. The size,orientation and migration history of the AE cloudhelped constrain the model parameters. Inaddition, AE clusters can be used as

deterministic information to modify the fracturenetwork directly. The Yufutsu project involvingJAPEX and Schlumberger tested some of theinherent limits of hydraulic fracture monitoring.

New Microseismic Activity One of the major limitations in microseismicmonitoring methods is finding candidatetreatment wells that have a nearby monitoringwell, or wells, in which to install the VSI tool. Notonly does the monitoring well need to berelatively close to the treatment well, dependingon the acoustic properties of the surroundingrock, but it must also be well cemented andacoustically quiet during fracturing operations.Ensuring that the monitoring wellbore is in theappropriate condition prior to running the VSItool often requires significant time and expense.

Scientists continually search for the balancebetween dependable AE detection andlocalization, and expedient processing andinterpretation that provides useful answers atthe treatment site. With the advent of fastercomputers, a new method that uses coalescencemicroseismic mapping (CMMapping) hasachieved fast and reliable event localization forreliable real-time fracture mapping.42

Another challenge addressed by Schlumbergergeophysicists when detecting and locating AEs isthe identification and interpretation of multiplets.For example, multiplets have been observed tooccur during two different pumping stages.Identical microseismic responses arise from, andare mapped back to, the same source locations.Therefore, multiplets indicate the reactivation ofa fracture or fault for which activity was detectedearlier. During a multistage hydraulic fracturetreatment, this may indicate crossflow betweenstages, resulting in an ineffective stimulation. Thekey is being able to identify the occurrence ofmultiplets in real time so that actions can betaken while pumping. Schlumberger scientistshave developed a crosscorrelation method todetect crossflow between stages that also providesanother layer of quality control in real-time eventlocalization (left).

Scientists at Schlumberger CambridgeResearch are also developing a robust seismicinversion to determine the mechanisms of theobserved microseismic events, for example,shear or tensile mechanisms.43 This techniqueallows going beyond “dots in a box” and, forexample, quantifying stress changes resultingfrom microseismic events. This information isused to further constrain geomechanical modelsand provide companies with a betterunderstanding of hydraulic fracture propagationor stress changes in the fractured reservoir.

Hydraulic fracture mapping has much to offerthe E&P industry, especially in tight reservoirdevelopment. Accurate fracture models, cali-brated using direct measurements of hydraulicfracture geometry, lead to improved reservoirsimulation and development. After decades ofsearching for the best way to characterizehydraulic fractures, the industry has returned tothe best source for the answers to our questions—the hydraulic fractures themselves. —MGG

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> Detecting cross-stage hydraulic fractures using multiplets. The technique is based on the identificationof multiplets as a result of reactivation of fractures from a previous stage. In this example from Texas,tthe upper graph is a crosscorrelation of all microseismic events from Stages 1, 2 and 3 (top left).ttStage 1 includes Events 1 through 157, Stage 2 includes Events 158 through 471, and Stage 3 includesEvents 472 through 769. The crosscorrelation coefficient is color-coded, identifying microseismicevents in different stages that originate from the same fractures—multiplets. When Stages 3 and 4—Events 1 through 298, and 299 through 497, respectively—are crosscorrelated, the coefficient remainsvery low except where the stages correlate with themselves (bottom left). The event map reflects thisttobservation (right).tt

58 Oilfield Review

Testing Oilfield Technologies forWellsite Operations

Michele ArenaStephen DyerRosharon, Texas, USA

Larry J. BernardAllen HarrisonWalter LuckettThomas ReblerSundaram SrinivasanSugar Land, Texas

Brett BorlandRick WattsConocoPhillipsHouston, Texas

Bill LessoHouston, Texas

Tommy M. WarrenTesco CorporationHouston, Texas

For help in preparation of this article, thanks to Claire Bullen,Luanda, Angola; Robert Edmondson, Joe Fuentes and TeresaGarza, Cameron, Texas; and John Hobbins, Randy LeBlanc,Thomas Querin and Don Shapiro, Sugar Land, Texas.EcoScope, FIV (Formation Isolation Valve), InterACT,PowerDrive, StethoScope and TeleScope are marksof Schlumberger. Casing Drilling is a mark ofTesco Corporation.

At full-scale test facilities, new drilling, logging and completion technologies can be

tested under actual wellsite conditions in a controlled and confidential environment,

before they are utilized in the field. The industry is now taking the ultimate step in

quality assurance by providing full-scale system integration tests and testing while

drilling. The knowledge gained by this rigorous assessment helps create tools that

perform as designed, even under the most demanding conditions.

Demand for resources is driving our industry toseek oil and gas in increasingly difficultlocations. Operators want new capabilities indownhole tools, but do not want to risk failureof a new tool in a high-cost wellbore.Predeployment testing has become a critical stepin the introduction of new tools.

Identification of problems with a newtechnology is best when done early in thedevelopment process, because solutions tend tobe more expensive when implemented later.Early testing is therefore crucial and forms anintegral part of product development, fromconception to design to deployment in the field.Tests should examine general usability, applic-ability, measurement accuracy and repeatability,product safety, manufacturability, and deliveryconfiguration and logistics.

Service companies are interested in testing atool under conditions that are as close aspossible to those likely to be experienced in thefield, but without the logistical and externaloperational constraints of the field. In acontrolled environment, a test can be focused,concise and complete. As a result, unanticipatedusage scenarios and measurement issues, as wellas hardware reliability, can be thoroughly investi-gated and worked through on site during thetesting phase. Having the ability to addressproblems when they are first encountered greatlyimproves the development process.

Oil and gas companies, on the other hand,want to minimize the financial risk resulting froma tool malfunction or failure. In a test facility, theycan explore tool functionality or system interfaceissues in a controlled and well-characterizedenvironment without the constraints of rig-timecosts or safety problems. Some of the latestadvances in drilling technology, including drillingwith casing in high-angle wells, can be evaluatedin settings that mimic the actual well conditions.

Equally important for both the operator andthe service provider is the need to comparetests on new tools with previously proventechnologies performed under similarconditions. The interpretation results of thecomparison are more accurate and reliable whentest conditions can be controlled and monitoredunder identical operating conditions, rather thantrying to extrapolate between different fields orwell conditions.

Various kinds and levels of testing areperformed at a number of centers around theworld.1 This article discusses qualificationtesting, which ranges from components to systemintegration, and collaborative experimentsbetween oil and gas companies and serviceproviders. Of particular interest are the finaltests and performance measurements made justprior to field deployment or before a customizedcomplex product configuration is deployed in acommercial well. The Schlumberger CameronTexas Facility (CTF) is designed to accommodatesuch advanced tests.

1. Schlumberger test centers include, among others, theAbingdon Technology Center, England; BeijingGeoscience Center, China; Cameron Texas Facility,Texas; Gatwick Technology Center, England; IntegratedProductivity & Conveyance Center, Singapore; OsloTechnology Center, Norway; Princeton TechnologyCenter, New Jersey; Schlumberger Conveyance andDelivery Center, Sugar Land, Texas; SchlumbergerEuropean Learning Center, Melun, France; SchlumbergerKabushiki Kaisha, Fuchinobe, Sagamihara, Kanagawa,Japan; Schlumberger Reservoir Completions TechnologyCenter, Rosharon, Texas; Schlumberger Reservoir FluidsCenter, Edmonton, Canada; Schlumberger RiboudProduct Center, Clamart, France; SchlumbergerStonehouse Technology Center, Gloucestershire,England; and Sugar Land Technology Center, Texas.For additional information on other test facilities: Lang K:“Oilfield Testing Centers: Nurseries for New Ideas,”Petroleum Technology Transfer Council Newsletter 9,no. 4 (2003): 6–9.

Winter 2005/2006 59

From Components to SystemIntegration TestingReliability is a key factor in the success andprofitability of any wellsite product. Althoughany new equipment or tool may be a wonderfulinnovation, it is destined to fail if it cannotwithstand the harsh environment of downholeoperations or drilling. Good engineering coupledwith rigorous performance and environmentaltesting is an effective means to success.2

For example, each component of a loggingtool is tested for a wide variety of factors such asthe operating environment, deployment methodsand measurement dynamic range. Environ-mental conditions in the oil field, both upholeand downhole, are quantified for extremes oftemperature, pressure, shock, vibration anddifficult logging conditions. Deployment andcontingency methods tested include wireline,

slickline and coiled tubing. Real-time interactionand control through each deployment methodare also tested. The absolute and relativeaccuracy of the measurement dynamic range andits repeatability are tested in different mud typesand lithologies.

Within Schlumberger, the rigorous productdevelopment process begins when the feasibilityof a project is first examined. Based on the tool’splanned operational environment, a requirementand specification document details the expecteduse and life of the product and the conditions itwill be subjected to over its lifetime. Thisdocument provides the basis for a plan thatspecifies the tests to be performed at thecomponent, subassembly, assembly and systemlevels to verify that the product’s design meetsquality and reliability requirements. The finallevel of tests is system integration testing (SIT),when multiple tools and pieces of equipment

from Schlumberger and third-party suppliers aretested in actual wellsite operating conditions.

Also during the project feasibility phase, thephysics of the measurements are verified in thelaboratory, in external test facilities or downhole.Once the project is shown to be technicallyfeasible and to have sufficient business justifi-cation to warrant further investment, the productmoves on to the development phase, in which testsare performed every step of the way (below).

During the development phase, component-level testing starts at the earliest possible stage.At this point, test costs are the lowest, yet designimprovements at this stage yield the mosteffective results. During component testing, testmachines and laboratory conditions producestresses on individual components similar to, orin excess of, what can occur in an actual well.

60 Oilfield Review

> Stages of testing—from components to system integration—during the development phase of tools or equipment.

Component setup for high-temperature testVibration test of subassembly

High-pressure, high-temperature test vessel for system testingCompression test of a tool assembly

Winter 2005/2006 61

The test conditions typically range from lowtemperature during transportation and storageto very high temperature at the bottom of a welland also include shock, vibration, low and highpressure, bending, corrosion and erosion.

Subassembly testing begins when theindividual components are qualified and multiplecomponents are assembled and combined.Verifications of performance and reliability areperformed. This is accomplished in a mannersimilar to component-level testing but requireslarger test machines. Each engineering center hascustomized test machines corresponding to thetype of subassemblies developed at that center.

The next stage is subsystem or assembly-leveltesting, when a downhole tool is built to a pointwhere it can stand alone and provide one or morefunctions at a wellsite. Subsystem testing may bechallenging because of equipment size andusually requires special facilities. Surface testsinclude mud flow through and around the tool,pressure, shock, vibration and rotation ofcomplete downhole tool sections.

In system-level testing or precommercialevaluation, measurements are verified foraccuracy and repeatability, especially withrespect to variations that occur during themanufacturing process. Many of these test

parameters can be examined under controlledconditions, for example, by drilling throughhardened well cement (left). Several questionsare addressed at this stage of testing. Doesthe production tool perform according to thespecifications of the engineering prototype? Do all the tools perform in a consistent manner? Are there unanticipated tool-to-toolproduction variations? What is the sensitivity of aspecific tool parameter to the overall measure-ment performance?

Finally, in the SIT phase, multiple toolcombinations are tested. For instance, the SITmay involve long well-completion assemblies;these strings may come from different centersand suppliers. Verification of system interop-erability and performance is crucial and isvirtually impossible to determine withoutassembling and testing the entire system at a testfacility that provides a complete dress rehearsal.In the past, rig qualification was performed on anoperator’s rig. Today, test facilities equipped withdrilling rigs are available to perform the samefunction without the constraints of costly rigtime and safety issues.

About Test FacilitiesSchlumberger offers several facilities for systemintegration testing, each with differentcapabilities. Beginning with the first test well in1956, the four test wells at the SchlumbergerReservoir Completions (SRC) Technology Centerin Rosharon, Texas, have been used for devel-opment and testing of perforating guns, wirelinelogging tools, tubing-conveyed perforatingequipment and, more recently, drillstem test andcoiled tubing equipment. The facility also has asmall artificial lake that has been used byWesternGeco to conduct tests with marineseismic sources.

The Schlumberger European Learning Center(SELC) in Melun, France, provides cased hole,openhole, downhole and surface well testingprimarily for wireline and some well services. Wellsat the Sugar Land Technology Center are used forcustomer acceptance testing of wireline andcertain logging- and measurements-while-drilling(LWD and MWD, respectively) tools. The GenesisDrilling Test Facility is a full-size drilling rig thatcan duplicate many conditions that occur at thewellsite in cased vertical boreholes. The rig notonly is an excellent facility for performing drillingtests, but also serves as a training facility.2. At Schlumberger, quality and safety assurance are

based on industry standards such as the InternationalOrganization for Standardization (ISO) 9001certificationfor engineering and manufacturing, Det Norske Veritas(DNV) certification, International Air TransportAssociation (IATA) qualification for transportation of

> Genesis Drilling Test Facility. Genesis is a 142-ft [43.3-m] cantilever-type,skiddable land-drilling rig with 1,250,000-lbf [5,560-kN] derrick capacity. Inservice at the Sugar Land Technology Center since 1988, Genesis is used toreproduce downhole field conditions for various types of tests. Mud flow,pressure, shock, vibration and rotation of downhole tools can be performedunder controlled conditions, either by drilling through cement or by using ashock-inducing device, also known as cam sub.

explosives and batteries, third-party safety audits,American Petroleum Institute (API) recommendedpractices for industry standards in hardware tests,NACE International and American Society of MechanicalEngineers standards for completion equipment, andrigorous quality control both on site and off site.

The Schlumberger Cameron Texas Facility(CTF) has a full-capability drilling rig forperforming drilling, borehole measurement andsystem integration tests. The CTF, whichencompasses several hundred acres, becameoperational in 2004 (below left). The CTF drillingrig provides boreholes with more than 6,000 ft[1,829 m] of horizontal reach. The formationspenetrated by CTF wells have a wide diversity ofporosities, permeabilities and mineralogies.Drilling, LWD, MWD and wireline tools may berun in carbonate and sandstone lithologies.Because the site covers such a large area, manydifferent borehole trajectories can be drilled topenetrate the various formations.

As a Schlumberger facility, CTF serves as aconfidential test bed for the latest downhole anduphole technologies. The high-bandwidthconnection within the Schlumberger firewallallows for easy, secure movement of confidentialdata and enables the involvement of remote

witnesses in extensive tests while drilling. Thefacility also provides hands-on experience forSchlumberger employees and clients, includingtesting of rig-up and transport logistics, andtraining of rig crews for complex deployment.

Wide arrays of tests have been run at CTF,ranging from feasibility to precommercializationand system integration. Tests associated with thelatest generation LWD tools—TeleScope high-speed telemetry-while-drilling service, EcoScopemultifunction logging-while-drilling service andStethoScope formation pressure-while-drillingservice—have been run at CTF. The tests run onthese tools were compared with results fromprevious generation LWD tools over the sameintervals in the same well and also with wirelinelogs run over the same intervals. Full-scalequalification tests of the newest while-drillingtools prior to field testing enabled earlydebugging of the tools and helped to preparethese services for successful introduction on

commercial wells.3 Clearly, this fast-track tooldevelopment would not have been feasiblewithout CTF.

Testing Integrated SystemsSIT is especially beneficial for critical develop-ment projects that must integrate many types ofwells and tools. The increasing number ofcomplex, deep offshore wells has heightened thevalue of performing SIT, potentially making SITan integral part of a risk-management plan forhigh-profile critical projects.

Completion SIT has been performed severaltimes over the past year at CTF and SRC,simulating as closely as possible actual wellconditions in different parts of the world.Completion SIT objectives include assemblyprocedures, interface verification, installationoptimization, intervention testing and contin-gency planning. An important goal is to reducethe learning curve through customized personnel

62 Oilfield Review

3. Adolph B, Stoller C, Archer M, Codazzi D, El-Halawani T,Perciot P, Weller G, Evans M, Grant BJ, Griffiths R,Hartman D, Sirkin G, Ichikawa M, Scott G, Tribe I andWhite D: “No More Waiting: Formation Evaluation WhileDrilling,” Oilfield Review 17, no. 3 (Autumn 2005): 4–21.

4. Edment B, Elliott F, Gilchrist J, Powers B, Jansen R,McPike T, Onwusiri H, Parlar M, Twynam A andvan Kranenburg A: “Improvements in Horizontal GravelPacking,” Oilfield Review 17, no. 1 (Spring 2005): 50–60.

5. The customized changes to the completion assemblyincluded a proprietary seal system, allowing bypass ofmultiple control lines and multiple-choke-position flow-

control valves that are set hydraulically. The gravel-packer circulating housing allowed slurry to be pumpedinto the annulus between the screen and the casing. Ithas a sleeve designed to close when the gravel-packpumping operation is completed.

6. The customized gravel-pack system features a single-trip service tool that provides a mechanism for packersetting and testing, fluid circulation and gravel-pack (GP)operation in a highly deviated wellbore. The GPcirculating housing is specially modified toaccommodate the inner completion string without therisk of opening the port sleeve.

> Cameron Texas Facility. This facility is equippedwith a drilling rig for performing drilling,borehole-measurement and system integrationtests. The rig is capable of handling three-jointstands of drillpipe and is equipped with high-volume mud pumps. The rig is mounted on railsfor convenient access to different well slots witha wide variety of directional wells that can beused for both openhole and cased-hole tests.

> Slack-off and pickup weight data during completion installation. The chart shows the effect of dragon the lower completion installation (left). A maximum overpull—the difference between the slack-offttand pickup weights—of more than 200,000 lbf observed at TD would have caused tubing stress abovethe specified rating. Based on the information gained during the SIT and data collected for the lowercompletion slack-off and pickup weight, the wellbore was cleaned out and the annular fluid waschanged to reduce friction. These steps reduced overpull to less than half the lower-completion value(right). The measurement of drag encountered during the inner completion installation was used tottimplement procedural changes both during the test and in the extended-reach offshore well.

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Lower Completion Installation Inner Completion Installation

Simulated slack-off weightsSimulated pickup weightMeasured slack-off dataMeasured pickup data

Winter 2005/2006 63

training and experience across service providers,third parties and client operations.

In one SIT example, the first of its kind for anextended-reach well, an intelligent flow-controldevice was placed within a triple-zone, cased-holegravel pack in a test well at SRC (right).4 Thecompletion assembly incorporated a number ofnewly customized items, including proprietaryseal assemblies, reduced outside-diameter flow-control valves and a hydraulically set, single-trip,step-bore gravel-pack system with a dedicatedservice tool and modified circulating housing.5 TheSIT plan for this well also included a full downholesystem test at SRC, followed by verification of thewellhead and control-line interfaces on locationprior to equipment mobilization offshore. Thesetests provided the optimum method for identifyingkey installation risks and were used tosubsequently modify procedures to reducenonproductive time or failures.

Several specific issues were addressed inthis SIT. The issue was interface testing of thelower sandface completion with the intelligentinner completion, particularly the frictionaleffects of multiple long-seal assemblies, theircorrect positioning—space out—within thewellbore, equipment eccentricity alignment, andminimization of seal-bore scratching and fatigueprior to landing the completion. Second, dragand wear issues for the inner completion whilerunning through a highly deviated environmentwere examined. Third was testing of a modifiedsingle-trip hydraulically set gravel-pack systemutilizing a step-bore and dedicated service tool.6

Finally, SIT was used to optimize runningmultiple hydraulic and electric-control lineswhile minimizing the number of splices to reduceinstallation time and risk.

SIT proved the feasibility of the completiondesign, the capability to install the equipmentsuccessfully and the device’s reliability for zonalisolation. A total of 35 recommendations basedon the SIT were incorporated into thepreparation and installation procedures as bestpractices, contingencies or special-attentionitems during the actual well installation. Asubsequent offshore installation was completedwith minimal nonproductive time, especiallyconsidering the high-drag environmentencountered during gravel packing, with amaximum difference of more than 200,000 lbf[890 kN] between slack-off and pickup weightat total depth (TD) (previous page, right).Knowledge gained during the SIT was used tocalibrate the installation drag model thatensured successful space out and landing.

> A three-zone, cased-hole gravel-pack (GP) intelligent completion layout used for system integrationttesting (SIT) (left). Installation of the inner completion string during the SIT was conducted at thettSchlumberger Reservoir Completions Technology Center in Rosharon, Texas (bottom right). The GPttpacker system includes the isolation packer and circulating housing. As part of the SIT, additionalttests on the wellhead called “stack-up tests” were performed in collaboration with the wellheadsupplier on location (top right).tt

Production packer

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Blast joints

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The three zones were individually stimulatedand tested using the flow-control valves, provingzonal isolation. Downhole production data,which are used for allocation of production, arecurrently captured by using InterACT real-timemonitoring and data delivery. The project—from inception through planning, testing andexecution—was accelerated for completion withina 12-month time frame.

In another example, a month-long SIT ofseveral newly designed completion tools wasperformed at the CTF in a purpose-built casedwell with an extended horizontal leg to simulateas closely as possible the conditions anticipatedduring an offshore installation (right). Theobjective of this test was to investigate anyinterface issues and to verify quality assuranceand quality control, assembly procedures,operating procedures and the accuracy of thecontingency plans. Additionally, it was importantto identify and implement lessons learned,including changes to the design and proceduresthat would result in increased efficiency,reliability or functionality in the operator’s field application.

Knowledge gained during the tests led toimprovements in the intervention phase. A newnipple profile used in conjunction with theexpandable shifting tool for the tubing-isolationvalve was redesigned to overcome an incom-patibility with the previously chosen config-uration. Additional tests with tractors forconveyance were also explored in conjunctionwith various intervention methods to avoid thecoiled tubing lockup, or helical buckling,anticipated at compressive loads greater than2,500 lbf [11.1 kN] that were observed during SIT.Additionally, more than 60 different action itemsrelated to safety, outlined procedures, equipmentmodifications and best practices were recorded toincrease efficiency, reliability and functionality.

Testing integrated systems has providedproven long-term cost savings, both by solvingproblems prior to first field installation and bylessons learned to improve efficiency and toreduce installation and nonproductive time.Despite detailed pre-engineering studies thathad been performed, SIT clarified the limitationsof what could be planned and verified in advanceand demonstrated the importance of conductinga field trial in a confidential manner and withoutrig-time constraints.

The ability to tailor integration tests in acontrolled and relatively low-cost environmentallows operators and service companies alike tosignificantly reduce the learning curve and risk.Test facilities, especially those equipped with a

64 Oilfield Review

7. Fontenot KR, Lesso B, Strickler RD and Warren TM:“Using Casing to Drill Directional Wells,” OilfieldReview 17, no. 2 (Summer 2005): 44–61.

8. A retrievable system for drilling with casing is requiredfor directional wells because of the need to recoverexpensive directional drilling and guidance equipment,to replace failed equipment before reaching casingpoint, and to quickly and cost-effectively accessformations below a casing shoe. A wireline retrievabledirectional-drilling assembly, positioned in the lowerend of the casing, replaces the directional tools used

> A subsea openhole gravel-pack (GP) completion used in a system integrationttest at CTF. The upper (green) and lower (blue) completion assembliesincorporated a number of newly designed completion tools—a gravel-packservice tool for gravel-pack operation (not shown here), single-assemblyintegrated products with permanent gauge and chemical injection, and threedifferent types of isolation valves.

Tubing hanger

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in a conventional bottomhole assembly. For more onretrievable tools for drilling with casing operations:Tessari R, Warren T and Houtchens B: “Retrievable ToolsProvide Flexibility for Casing Drilling,” presented at theWorld Oil 2003 Casing Drilling Technical Conference,Houston, March 6–7, 2003.

9. Borland B, Watts R, Warren T and Lesso B: “Drilling HighAngle Casing Directionally Drilled Wells with Fit-for-Purpose String Sizes,” paper IADC/SPE 99248, presentedat the IADC/ SPE Drilling Conference, Miami, Florida,USA, February 21–23, 2006.

Winter 2005/2006 65

full-scale drilling rig, such as the CTF, expand thehorizons of what can be achieved in simulatingcomplex well plans and testing new technologiesin collaboration with oil and gas companies andother third-party contractors.

A Collaborative Project: Directional Drillingwith CasingIn recent years, drilling with casing has steadilygained acceptance because it offers increasedwell control and safety, enhanced efficiency anddemonstrated cost savings.7 Although the mostsignificant savings can be achieved in offshoreenvironments, drilling with casing in matureassets presents significant challenges. Wellsdrilled from a platform are typically directional,and drilling deviated wells with casing mayrequire modifications to rig or platform equip-ment that could affect production at aprohibitive cost in an offshore operationalenvironment. Also, a learning curve typicallymust be developed with the first few wells drilledin a new application area.

ConocoPhillips, an industry leader in applyingretrievable Casing Drilling technology, hasmultiple offshore assets in which drilling withcasing has the potential to help deal with knownwell-construction problems.8 In mature fields,such as the Eldfisk field offshore Norway, reservoirdepletion leads to well-stability concerns. Drillingwith standard drillpipe may require extra casingstrings to avoid well-stability problems that arecaused by depleted formation pressures. Inaddition to solving drilling problems, thetechnology of drilling with casing has thepotential to reduce the number of casing strings,which could lead to improved well-constructionefficiency and substantial cost savings.

A collaborative project of ConocoPhillips,Tesco and Schlumberger was undertaken todesign and test directional drilling with casingfor two wells planned for Eldfisk field in 2006.The planned wells were to be drilled from acommon wellhead with 103⁄3⁄⁄ -in. and 73⁄3⁄⁄ -in. casing.At the start of the project, drilling with casingtools did not exist in these sizes and operationalproblems related to directional wells requiredredesign of the existing hardware.

The high risks associated with setting,directionally drilling and retrieving these newtools with modifications in untested boreholesizes warranted testing this technology indirectional wells in an onshore field. But therewere additional concerns about this approach.First, with multiple partners, it was difficult toconduct a test that would benefit the operatorbut potentially have little or no benefit to the

other partners. Quantifying the costs and riskswas complicated.

Second, because pay-zone targets and accom-panying directional-well trajectories frequentlychange as new information is learned about thefield, a directional build profile in one casingsection may be moved to another section becauseof a change in a geological model. These changesin the well plan severely constrained the testobjectives. Third, commercial wells are drilled tocompletion. The very nature of testing a drillingprocess, such as drilling with casing, may lead toproblems that are significant enough to abandonthe test or well. Once a section of directionaldrilling with casing is started, it must be finished.If there are problems with the tools, the ability torevert to directional drilling with drillpipe has tobe an available option. This fail-safe nature ofwell construction required extensive planningand budgeting of costs.

These issues, common in well construction,made it difficult to test new technologies for onebusiness unit in the fields of another business

unit, even for large multinational operatororganizations. Several months were spent inmodifying well designs before the decision wasmade to look for a different approach. Thealternative was to utilize CTF.

Two tests were planned. The wells at CTFwould mirror the directional sections, build ratesand operational parameters such as mud flowrates that are required for Eldfisk wells.9 Thefirst well would test setting and retrieving the75⁄5⁄⁄ -in.-casing bottomhole assembly (BHA) toolsin horizontal drilling operations. The secondwould test the 10 ⁄3⁄⁄ -in. system with multiple buildrates, kicking off a directional well from thevertical section.

The first test took place in July 2005 in apreviously drilled, high-angle borehole at CTFwith 133⁄3⁄⁄ -in. casing, which included about 600 ft[183 m] of horizontal section (below). Tests wereconducted for setting and retrieving the BHA inthe vertical section and at well deviations of 45°and 90°. A directional drilling with casing BHAincorporating a rotary steerable system (RSS)

>Well profile of the horizontal well at the Cameron Texas Facility for testing directional drilling withcasing (bottom). Four bottomhole assembly (BHA) setting and retrieval operations at vertical andvarious inclinations are shown. Test 5 included about 850 ft of horizontal drilling. Rig personnel havetthe ability to break equipment down and make minor design changes based on the test taking placeon the nearby rig, such as the Tesco crew here (top). Briefings that include safety guidelinesare held each day of the tests to outline procedures for the next 12 hours. During these and otherdirectional drilling with casing tests, two daily briefings included ConocoPhillips, Tesco andSchlumberger personnel (right).tt

Test 1

Test 2

Test 3 Test 4Test 5

Drill 850 ft horizontally

BHA setting and retrieval testsplanned at 0°, 45° and 90°

Previously drilled well with10 3⁄4-in. casing to 3,769 ft

Dept

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Distance

was tested (below).10 The test also included thedirectional performance of this equipment. Acommand was sent to the RSS to turn the wellpath to the right, at 1.0°/100 ft [1.0°/30 m]. After300 ft [91.4 m], a second command was sent toturn to the left, at 3.0°/100 ft [3.0°/30 m]. Finally,

a command was sent to maintain a constantinclination and azimuth until the end of the test.The first turn was accomplished at 1.4°/100 ft[1.4°/30 m], the second turn had a 4.3°/100-ft[4.3°/30-m] rate and the third command resultedin a constant azimuth. About 850 ft [259 m] ofnew horizontal borehole was drilled.

Setting and retrieving the drilling with casingBHAs were achieved using wireline. However,because of the high well inclination, pumping thetools down the borehole was also tested. TheBHA was successfully set and retrieved. It wasthen reset and then released using a pumpdown

66 Oilfield Review

> Directional drilling with casing BHA used in the 7 ⁄5⁄⁄ -in. test (left). The PowerDrive rotary steerable assembly included a motor that was run inside thettshoe joint of the casing to provide adequate drilling rotational speed while minimizing casing rotation to control wear and fatigue. The directional drillingwith casing BHA has a stick-out, or length, below the casing shoe of 85 ft [25.9 m], whereas a typical vertical BHA has a stick-out of only 15 ft [4.6 m]. Thedirectional performance of the rotary steerable system for three PowerDrive settings is shown (bottom right). Test results indicate the degree of successttof the horizontal drilling test. Tesco and Schlumberger personnel are seen making up the BHA (top right).tt

Motor bit box

Internal tandemstabilizer

Vibration sensorsub9 7⁄7 8⁄⁄ -in. underreamer

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Winter 2005/2006 67

releasing tool without a wireline attachment. Ata targeted depth, the releasing tool landed in theprofile nipple, releasing the drill lock andallowing BHA retrieval, thus completing a fullfunctional test of the hardware.

A downhole vibration sensor sub was runabove the underreamer to monitor lateral andtorsional accelerations. Shocks during theearlier part of the run were of greater intensity,but tapered off later. These shocks have thepotential of causing damage to the RSS. A fullinspection of the tools demonstrated that theysuffered none of the damage seen previously,probably because of the modifications to therotary steerable tool to make it more robust. Thesmall-diameter BHA used in drilling with casingis still susceptible to excessive vibrations andshocks and will continue to be monitored.However, modeling to mitigate shocks andimprovements in tool robustness have greatlyreduced this problem.

The 103⁄3⁄⁄ -in. test took place in November 2005.A previously installed 133⁄3⁄⁄ -in. casing had been setvertically at about 2,000 ft [609.6 m]. Thewireline installation for the 75⁄5⁄⁄ -in. test used anupper wireline sheave suspended below the rig’sconventional traveling block, whereas the 103⁄3⁄⁄ -in. test used a fixed crown sheave and splitblock to match the equipment on the Eldfisk rig.The directional BHA design was similar to thatused in the 75⁄5⁄⁄ -in. test. An RSS and MWD toolwere used for directional control in the pilotsection of the BHA (left).

Downhole vibration measurements—shockcounts—were transmitted uphole in real timefrom the MWD tool. Shock counts were alsorecorded downhole in the RSS. Additionally, threesensor packages were placed in the BHA; oneabove the underreamer and two below it, betweenthe MWD tool and RSS. Downhole recordedmeasurements included annular pressure;lateral, axial and torsional shocks; rotationalspeed; torque; and weight-on-bit. Two BHAs ofdifferent lengths were used to test differences invibration response.

The dataset from this test is the mostextensive recording of downhole data evercollected during an operation involving drillingwith casing. Data were recorded while kicking offa sidetrack plug, traversing through a maze ofother bores drilled from the same parentborehole and drilling to about 850 ft whilebuilding angle to about 20°. The well wasdirectionally drilled, first with a low build rateof 0.5°/100 ft [0.5°/30 m] and then a higher rateof 3.0°/100 ft.

The drilling mechanics and dynamics datagathered during these tests have led torecommendations in tactical changes that willimprove well designs for the ConocoPhillipsNorway operations at Eldfisk.

Expanding Horizons in Quality AssuranceDesigning equipment that can withstand theextreme environmental and drilling conditions ofglobal oil fields while making highly sensitivemeasurements continues to be incrediblychallenging. As tools become more complex andhydrocarbons hide in ever more difficult settings,the risk and costs associated with applying newtechnologies will only increase in the future.Therefore, qualifying oilfield technologies priorto their introduction in the field is essential.

With the need to mitigate exposure tohazardous oilfield environments and keep costsin check, remote testing involving clients andengineering and test facilities personnel hasbeen a growing trend. The high-bandwidthconnectivity within the Schlumberger networkfirewall provides the ability to conduct testsconfidentially and involve experts who might bethousands of miles away.11

The benefits of maintaining and operatingtest centers, including full drilling capability,are well-established. Rapid deployment of high-performance enabling technologies in thefield and an increasing demand for complex,multidisciplinary, turnkey completion projectsare some of the reasons for the necessity of test facilities such as SRC and CTF. In fact, thelimits of testing are prescribed only by the creativity boundaries of the technology developers.

The future is likely to see an increased numberof collaborative projects between operators,service companies and third-party suppliers totest new limits of technology and provide bothquality and safety assurance in tough, geologicallycomplex drilling environments. —RG

10. Copercini P, Soliman F, Gamal ME, Longstreet W, Rodd J,Sarssam M, McCourt I, Persad B and Williams M:“Powering Up to Drill Down,” Oilfield Review 16, no. 4(Winter 2004): 4–9.

11 Aldred W, Belaskie J, Isangulov R, Crockett B,Edmondson B, Florence F and Srinivasan S:“Changing the Way We Drill,” Oilfield Review 17, no. 1(Spring 2005): 42–49.

> Directional drilling with casing BHA used in the103⁄3⁄⁄ -in. test. The BHA used in the 103⁄3⁄⁄ -in.-casingttest is the heaviest and longest BHA ever usedin directional drilling with casing. The BHA hasa stick-out of 122 ft [37.2 m], and the BHA weighstthree times the weight of a BHA used in the7 ⁄5⁄⁄ -in. test.

Uppervibration sub

10 3⁄3 4⁄⁄ -in. casingshoe

PowerDrive rotarysteerable system

12 3⁄3 4⁄⁄ -in. underreamer

Motor sleevestabilizer

Nondirectionalmotor

Drill LockAssembly (DLA)

MWD system

Lowervibration subs

Internal tandemstabilizer

Roller reamer

Polycrystallinediamond compact(PDC) bit

68 Oilfield Review

A Sound Approach to Drilling

Jeff AlfordRoger B. GoobieColin M. SayersEd TollefsenHouston, Texas, USA

Jay CookeHelis Oil & GasHouston, Texas

Andy HawthornJohn C. RasmusSugar Land, Texas

Ron ThomasPPI Technology ServicesHouston, Texas

For help in preparation of this article, thanks to RonBlaisdell, New Orleans; Lennert den Boer, Calgary;Joaquin Armando Pinto Delgadillo and Egbonna Obi,Youngsville, Louisiana; Nick Ellson and Dale Meek,Sugar Land, Texas; and Ivor Gray, CJ Hattier andSheila Noeth, Houston.APWD (Annular Pressure While Drilling), CDR (Compen-sated Dual Resistivity), FPWD (Formation Pressure WhileDrilling), PERT (Pressure Evaluation in Real Time),sonicVISION, StethoScope and TeleScope are marks ofSchlumberger.

Of the many decisions drilling engineers make, selecting an optimal mud

weight is one of the most challenging and far-reaching. Today, sonic logging-

while-drilling tools are instrumental in making these decisions.

Generations of drilling engineers have struggledto visualize the dark and formidable downholedrilling environment. Today, engineers andgeoscientists rely on increasingly sophisticatedsensors to gather data from deep beneath the Earth’s surface, understand subsurfacelithology, identify geologic features, locatehydrocarbons and make a host of drilling andcompletion decisions.

Even though our sense of sight is highlydeveloped, it has its limitations. So, early in the20th century, scientists began development oftechnologies that would allow visualization ofenvironments that could not otherwise be seen.In 1906, Lewis Nixon invented the first soundnavigation and ranging, or sonar, device, as a wayof detecting icebergs.1

Early sonar devices were passive; they couldonly listen. However, between 1914 and 1918,World War I accelerated interest in and develop-ment of active sonar tools for submarine detection.

The first active sonar technology transmitteda sound, or ping, through water. Multiplereceivers called transponders detected thereturning sound echo, providing data on therelative positions of static and moving objects.Today, advanced acoustic technologies havemany uses in areas such as medicine, militaryapplications and oil and gas exploration andproduction (E&P).

Acoustic-based logging-while-drilling (LWD)tools provide data that help reduce uncertaintyand allow engineers to make effective and timelydrilling decisions. Data from sonic LWD tools notonly help establish pore-pressure gradients, butalso help define porosity and permeability, detectand type hydrocarbons, evaluate borehole

stability, interpret lithology changes, monitorfluid-flow effects in the borehole and pickaccurate casing-setting depths.2

More importantly, these data are available inreal time to help engineers and geoscientistsmake critical decisions that affect drilling costand efficiency (see “Acting in Time to Make theMost of Hydrocarbon Resources,” page 4). In thisarticle, we describe how advanced sonic toolsand interpretation techniques are helping tobetter define the safe mud-weight window, drilldeeper and optimize casing-setting depths. Fieldexamples from the Gulf of Mexico and offshoreAustralia show how operators are using real-timeacoustic data and wellsite-to-shore telemetrysystems to limit risk and uncertainty whilereducing well cost.

A Pressing Need for Pressure PredictionKey to the well construction process is anunderstanding of the subsurface pressureenvironment.3 Changes in the normal pressuregradient affect drilling safety, casing design andsetting depths, and in particular, the mud-weight window.

Engineers restrict the mud-weight range tosustain borehole stability, control downholepressures and optimize casing-setting depth.Most often, the mud weight is maintained abovethe formation pressure—at a level required tocontrol formation stress and prevent kicks orinfluxes that can lead to costly well-controlproblems—and below the fracture gradient toprevent the formation from breaking down andlosing returns. Wells are also sometimes drilledwith the static mud weight below formationpressure, or underbalanced.4

1. For more on the development of sonar devices:http://www.absoluteastronomy.com/reference/sonar(accessed February 6, 2006).

2. For more on sonic logging: 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.

3. Barriol Y, Glasser KS, Pop J, Bartman B, Corbiell R,Eriksen KO, Laastad H, Laidlaw J, Manin Y, Morrison K,Sayers CM, Terrazas Romero M and Volokitin Y: “ThePressures of Drilling and Production,” Oilfield Review 17,no. 3 (Autumn 2005): 22–41.

4. For more on underbalanced drilling: Bigio D, Rike A,Christensen A, Collins J, Hardman D, Doremus D,Tracy P, Glass G, Joergensen NB and Stephens D:“Coiled Tubing Takes Center Stage,” Oilfield Review 6,no. 4 (October 1994): 9–23.

W

> Predicting pore pressure in the Gulf of Mexicowith seismic data. In this example, the initialvelocity model based on conventional stacking-velocity analysis (above left)tt predicts thepresence of overpressure (black circle).Although pore-pressure predictions based ontthis information are not sufficiently accurate fordrilling, a higher degree of seismic-velocityresolution can be obtained by using tomographicanalysis and checkshot datat to refine the velocitymodel (above right).tt Further data processingallows construction of a three-dimensional (3D)pore-pressure cube (bottom right).tt

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The optimal mud-weight range is frequentlynarrow andw difficult to define; this is especiallytrue in tectonically stressedy regions and indeepwater environments. Within this narrowmud-weight window, engineers balance severalfactors, including the minimum flow ratewrequired for hole cleaning, downhole motor andtelemetry operationsy and equivalent circulatingand static densities. Drilling fluids such as oil-base and synthetic-base muds frequently exhibitythermomechanical and compressibility propertiesythat vary withy depth, making it difficult tooptimize drilling efficiency whiley maintainingmud weight.

Operating within the mud-weight windowallows engineers to improve drilling efficiencyand set casing at the best possible depth. Ifcasing is set too shallow, well-construction costtypically increases,y well depth is limited,production rate may bey compromised and, insome cases, the target may noty be reachable.

Maintaining the mud weight within a specificwindow reliesw on accurate determination andprediction of anomalousf changes in formationpressure. The analysis of shalef resistivity usingywireline log data is one of thef oldest methods fordetecting abnormal pressure.

Formation resistivity dependsy on porosity, thetype of thef fluid within the pore space and itsionic strength. Under normal compactionconditions, an increase in shale resistivity withydepth corresponds to a reduction in porosity(left). An anomalous change in formationpressure is usually associatedy with a shift in thenormal compaction trend, indicated on anelectric log by ay reduction in resistivity associ-yated with an increase in porosity.

For the purpose of maintainingf safe mudweight while drilling, information aboutabnormal pressure needs to be available whiledrilling. Although formation resistivity isy one ofthe most common LWD measurements, severalfactors can have a significant effect on the data,potentially masking changes in the normalcompaction trend and hindering the detection ofabnormal pressure.5

Changing temperatureg in the borehole withdepth alters the resistivity ofy formationf water,while the presence of hydrocarbonsf considerablyincreases resistivity. Large deposits of organicfmatter mayr alsoy increase resistivity, obscuringundercompaction indicators. Changes in thecondition of thef borehole, such as an increase inborehole diameter due to washout or caving,further increaser resistivity measurementy error.Although many ofy thesef effects can be

compensated for, reliance on resistivity datayalone for pore-pressurer prediction significantlyincreases drilling risk.g

Geoscientists can often identify abnormallyypressured formations using seismic velocities.For a given lithology, acoustic velocity usuallyydepends on porosity: the greater the porosity, thelower the acoustic velocity. In normally com-ypacted sediments, compaction increases withdepth. Porosity, in turn, decreases with depth,and so the velocity ofy sonicf and seismic wavestraveling through the formation generallyincreases with depth (below). Deviations fromthis trend can often be attributed to layers ofsediments that have not compacted, signalingabnormally highy pressure, called overpressure.However, uncertainties in seismic velocitiescommonly resulty in depth errors, making itdifficult to define exact distances to drillinghazards and geological targets.

Velocity modelsy created from seismic data canabe improved by addingy high-resolution informa-tion from sonic measurements obtained whiledrilling (next page). Today, geoscientists andengineers combine while-drilling and wireline

70 Oilfield Review

5. Aldred W, Bergt D, Rasmus J and Voisin B: “Real-TimeOverpressure Detection,” Oilfield Review 1, no. 3(October 1989): 17–27.

> Electric log analysis to predict pore pressure.In normally compacted sediment, electricalresistivity will increase with depth along anormal trend line (red). A deviation in resistivityfrom the normal trend may indicate abnormalformation pressure.

SpontaneousPotential (SP) Depth Resistivity

NormalN lNormalNormalaaa trendt dtrend trendlinelineline

R i ti itiResistivityResistivityiiR i ti itideviationdeviationii

Winter 2005/2006 71

> Defining mud-weight windows. Sonic velocity can be used to predict changes in the normal compaction trend that is often anindicator of abnormal pressure (top left). Unlike resistivity measurements, sonic velocity is unaffected by changes in boreholetttemperature and salinity. Real-time compressional-slowness measurements from sonic LWD tools are used to predict porepressure and help define kick and borehole breakout limits (top right). Adding sonic shear measurements (tt bottom), available infast formations, helps determine kick and mud-loss potential, fracture limits, and the safe mud-weight window shown in white(Track 4). Various types of shear failure can also be defined (Track 5).

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sonic data with checkshots to generate syntheticseismograms that are then correlated withpredrilling seismic measurements, providing thedrilling team with a way to locate the drill bitwithin the geophysical environment (above).6

These real-time processes help engineers preparefor pressure changes before drilling into them.

Generating a synthetic seismogram from LWDdata involves combining transit-time (∆t) datawith density measurements, to produce anacoustic impedance (AI) model. This model isconverted into a seismic reflectivity sequence,and then convolved with a selected wavelet toproduce a synthetic seismogram.7 A syntheticseismogram is much more useful when it isdepth-calibrated with either a wireline or while-drilling checkshot or vertical seismic profile(VSP). Although the synthetic seismogram canbe generated at the wellsite, more often, the real-time data are transmitted to an engineeringcenter for processing.

Correlating a synthetic seismogram withsurface seismic traces helps geoscientists andengineers place the borehole trajectory on aseismic section. Calculation of the spatial positionof the borehole relative to seismic markers, orreflectors, allows the drilling team to look aheadto abnormal changes in formation pressure.

Sonic Measurements While DrillingSoon after the introduction of sonic LWDmeasurements in the late 1990s, an operatorexperimented with using sonic LWD measure-ments to improve drilling efficiency in severalmajor operating areas. On an exploration well inthe Gulf of Mexico, USA, in an area known forabnormally pressured formations, sonic anddensity LWD data were transmitted from the rigto the operator’s office. There, geoscientistsgenerated a synthetic seismogram, which wascorrelated to the surface seismic section imagingthe target zone and an overlying overpressuredzone.8 The synthetic seismogram indicated thatthe top of the overpressured zone was 60 ft[18 m] deeper than what the seismic sectionpredicted. This information allowed engineers toplace the casing shoe significantly closer to theoverpressured zone, optimizing casing-settingdepth and improving the safety and drillingefficiency of subsequent borehole sections.

In another early example, BHP (now BHPBilliton) and Schlumberger demonstrated theuse of sonic LWD measurements not only tocalibrate seismic reflections, but also to updatepore-pressure calculations ahead of the bit.9

Several exploration wells offshore WesternAustralia had been abandoned prematurely dueto wellbore-stability problems associated withoverpressured formations.

As the bit approached the predictedoverpressured zone, acoustic velocity acquiredwhile drilling was used to continuously updatethe velocity models derived from existing surfaceseismic and VSP surveys. Simultaneously,engineers at the wellsite used real-time CDRCompensated Dual Resistivity data, sonic LWD,weight-on-bit (WOB), rotary torque and rate-of-penetration (ROP) measurements, in conjunc-tion with the PERT Pressure Evaluation in RealTime program, to monitor changes in porepressure a few meters behind the bit. Thisinformation was used to calibrate the pore-pressure predictions from the seismic andVSP data.

Using multiple techniques for pore-pressureprediction, the operator accurately predictedchanges in formation pressure, identified mini-mum mud-weight requirements and optimizedcasing-setting depth to construct a successfulwell in this hostile environment.

Narrowing the Window of UncertaintyDrilling in technically demanding areas is usuallyassociated with high cost and elevated levels ofrisk and uncertainty.10 Sonic LWD data availablein real time play a key role in reducing cost, riskand uncertainty by updating models createdbefore drilling. However, creating those models

72 Oilfield Review

> Placing a bit on the seismic map using synthetic seismograms. Sonic LWD slowness data are inverted with the densitymeasurement to produce an acoustic-impedance (AI) measurement (process from left to right). The AI is converted tottreflectivity and convolved with a 35-Hz wavelet at each reflector to obtain the synthetic seismogram (right). Geophysicalttanalysis of the seismic data determines the wavelet frequency. With increasing depth, higher frequency seismic signalsare attenuated, so a lower frequency, generally 20 Hz instead of 35 Hz, is used to correlate the sonic LWD data to surfaceseismic measurements. This helps engineers and geoscientists place the bit on the seismic map more accurately.

SonicslownessDensity

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Winter 2005/2006 73

in the first place can be a bottleneck. In 2000,geoscientists began looking at opportunities toincrease the speed and accuracy of while-drillingpore-pressure modeling and prediction.11

In the deepwater Gulf of Mexico (GOM),overpressure causes major drilling hazards.Overpressure is caused by Mississippi Riversedimentation that is rapidly buried comparedwith the time it takes for sediments to expelpore water. This prevents sediments fromcompacting as they are buried and causes thepore fluid to become overpressured. In under-compacted sediments, sediment grain contactsare weak, causing low rock strength and lowacoustic velocities.

Accurate determination of pore pressure is akey requirement to making optimized drillingdecisions in these overpressured environments.Before drilling, pore pressure can be predictedusing seismic velocities—assuming there is aseismic survey available and processed—together with a velocity-to-pore-pressure trans-form calibrated to offset-well data. However, thisprocedure takes considerable time. Syntheticseismograms can be generated quickly, comparedwith the time needed for analyzing seismicvelocities and creating a pore-pressure cube.

As engineers focus on ways to reduce risk anduncertainty, the time required to process andcorrelate seismic and sonic LWD data becomescritical. To speed up this process for prospects inthe northern GOM, Schlumberger geoscientistsdeveloped a pore-pressure cube for the entirearea using data released by the MineralsManagement Service (MMS) (right).12

Checkshot data from the MMS in the Gulf ofMexico were inverted to obtain compressionalvelocity versus depth below the mudline. Thesevelocity functions were then combined withupscaled sonic logs from deepwater wells andkriged to populate a three-dimensional (3D)mechanical earth model (MEM) displaying bothvelocity and levels of expected uncertainty.13

By applying a threshold to the predictedkriging error, maps of undercompaction andoverpressure can be restricted to specific areasof interest. For commercial projects, a confi-dential client subcube may be extracted from thefull GOM pore-pressure cube. Any additionalinformation provided by the operator and dataacquired during the drilling process with sonicLWD and real-time pore-pressure tools is used toupdate the client model, increasing resolution

6. A checkshot is a type of borehole seismic surveydesigned to measure the acoustic traveltime from thesurface to a known depth. Formation velocity ismeasured directly by lowering a geophone to each depthof interest, emitting energy from a source on the surfaceand recording the resulting signal. A checkshot differsfrom a vertical seismic profile in the number and densityof receiver depths recorded; geophone positions may bewidely and irregularly located in the wellbore, whereas avertical seismic profile usually has numerous geophonespositioned at closely and regularly spaced intervals inthe wellbore.

7. A wavelet is a pulse representing a packet of energyfrom the seismic source.

8. Hashem M, Ince D, Hodenfield K and Hsu K: “SeismicTie Using Sonic-While-Drilling Measurements,”Transactions of the SPWLA 40th Annual LoggingSymposium, Oslo, Norway, May 30–June 3, 1999, paper I.m

9. Tcherkashnev S, Rasmus J and Sanders M: “JointApplication of Surface Seismic, VSP and LWD Data forOverpressure Analysis to Optimize Casing Depth,”presented at the EAGE Workshop: Petrophysics MeetsGeophysics, Paris, November 6–8, 2000.

10. Malinverno A, Sayers CM, Woodward MJ andBartman RC: “Integrating Diverse Measurements toPredict Pore Pressure with Uncertainties While Drilling,”paper SPE 90001, presented at the SPE Annual Technical Conference and Exhibition, Houston,September 26–29, 2004.

11. Sayers CM, Johnson GM and Denyer G: “Predrill PorePressure Prediction Using Seismic Data,” paperIADC/SPE 59122, presented at the IADC/SPE DrillingConference, New Orleans, February 23–25, 2000.

12. Sayers CM, den Boer LD, Nagy ZR, Hooyman PJ andWard V: “Regional Trends in Undercompaction andOverpressure in the Gulf of Mexico,” ExpandedAbstracts, 75th SEG Annual Meeting, Houstons(November 6–11, 2005): 1219–1222.

13. Kriging is a statistical technique used with two-pointstatistical functions that describe the increasingdifference or decreasing correlation between samplevalues as separation between them increases, then todetermine the value of a point in a heterogeneous gridfrom known values nearby.

> Building a three-dimensional (3D) mechanical earth model in the Gulf of Mexico.Seismic, checkshot and sonic data released by the Minerals Management Service(green dots) were gathered from wells in the Gulf of Mexico (top) where pore pressureexceeded 10 lbm/galUS [1,198 kg/m3] and the predicted velocity error was less than ± 1,200 ft/s [± 366 m/s]. The data were then trend-kriged to predict pore pressure, andthen plotted in a 3D model (bottom).

10 11 12 13Pore pressure, lbm/galUS

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and reducing pore-pressure uncertainty both inthe immediate drilling environment and ahead ofthe bit (above).

Along with improved modeling, technologicaladvances in LWD tools and telemetry systems areyielding more accurate real-time measurementsand in greater quantities. The sonicVISION, newgeneration sonic-while-drilling LWD tool intro-duced in April 2004 has increased confidencein the accuracy of real-time compressional-wave velocities.

Until fairly recently, many believed that itwould be impossible to achieve sonic measure-ments while drilling. Engineers thought that thefast acoustic-signal arrival down the tool collarfrom the transmitter to the receivers woulddominate all the arrivals, making it impossible todiscriminate and record formation arrivals.

With this in mind, the designers of first-generation sonic LWD tools focused on mitigatingdirect collar arrivals. To accomplish this, the

tools were designed around what is referred to asthe hoop-mode frequency range of the collars.This frequency depends on the collar thicknessand diameter, but for most tools, falls in a narrowband between 11 and 13 kHz.

At the hoop-mode frequency, acoustic wavesattempt to expand the collar rather than traveldown to the receiver, thereby attenuating thecollar arrivals at the receivers. By designing thetransmitters to fire within the narrow hoop-modefrequency band and filtering received data to the

74 Oilfield Review

> Reducing uncertainty with pressure data from multiple sources. The degree of uncertainty in a pore-pressure gradient is exemplified by the width andlow resolution of the compressional-velocity (Vp) and pore-pressure gradient curves (1). Velocity data from sonic checkshots are added to the model,somewhat reducing pore-pressure uncertainty (2). Adding mud weights from drilling reports (3) and physical pore-pressure measurements (4) refinesestimates and dramatically improves pore-pressure resolution.

500500500

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10 15 2010 15 20P di t lb / lUSPore-pressure gradient lbm/galUSPore pressure gradient, lbm/galUS

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Winter 2005/2006 75

same range, engineers hoped to receive cleanand discernable formation arrivals, free fromdistortion caused by collar arrivals.

This technique proved somewhat satisfactoryfor fast formations where the excitationfrequency falls within the appropriate range.However, for slower formations, larger hole sizesand for lower frequency components of the wavetrain, such as shear and Stoneley waveforms,these first-generation tools did not excite theformation at the optimum frequency and werediscarding data outside of the narrow bandaround the hoop mode (right).

Narrow-band processing also promotedspatial aliasing, a condition in which non-formation arrivals, or processing artifacts,appear within the slowness time coherence(STC) search-band window. Aliasing depends onthe frequency of the transmitted pulse, therecorded waveform frequencies and the inter-receiver spacing. With an almost monofrequencysystem, aliasing was well-developed and led toincorrect picking of events that were notformation arrivals.

Misinterpretation of signal arrivals can alsolimit the usefulness of acoustic data. Previoustools analyzed all acoustic arrivals within a timewindow associated with a depth. So within thisdataset, there could be compressional, shear,mud, collar and aliased arrivals. The tool’sdownhole processors then discriminated thecompressional arrival from other signals basedon the coherency of those events. With compres-sional arrivals being one of the smallest eventsdiscernible in the wave train, their coherency istypically low when compared with other arrivals(below right). Early tools often confused ormisidentified the data, sending incorrect valuesto the surface.

To mitigate these problems, Schlumbergerengineers designed the sonicVISION tool totransmit and receive wide-band acoustic signalsin a frequency range from 3 to 19 kHz, a rangemore likely to generate a measurable responsefrom most formations. Acoustic shear waves aredifficult to acquire with narrow-band toolsbecause they contain lower frequencies thancompressional waves. The sonicVISION toolfrequency is optimized to excite the formationacross a significantly wider frequency band thanthat of previous tools. This allows both shear andcompressional measurements to be routinelymade while drilling in faster formations. Power-output levels were also increased 10-fold to moreeffectively couple the wide-band acoustic energyto the formation.

> Frequency range of the new tool design. The frequency ranges of previousttools were narrowly aligned within the collar attenuation frequency. Newerttools have an expanded frequency range covering a broader spectrum of softand hard formations (yellow bar). Lower frequency arrivals such as Stoneleyand leaky-P (not shown) are now captured.

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> Acoustic wave train. Once an acoustic signal is transmitted, it travels through the formation, annularfluid, and to some degree the tool, ultimately arriving at the receiver array. Low-amplitude compressionalsignals (red) arrive first, followed in harder rock by the shear arrival. Newer tools take advantage ofslower arrivals such as Rayleigh and Stoneley.

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The new design also transmits real-timecoherent events, called peaks. The sonicVISIONtool can send up to four peak arrivals uphole at anygiven time, enabling engineers at the surface toaccurately differentiate arrivals rather than relyingon downhole processing. These peaks are thenassembled to form an STC projection log that helpsimprove data accuracy and provides a significantstep forward in data quality control (above).

STC projection logs help engineers accuratelydifferentiate compressional, shear and othermodes in real time. The novel design of thesonicVISION tool now allows engineers to modifylabel limits at the surface thereby improvingextraction of the compressional ∆t and alsoproviding real-time shear data. Accurate discrim-

ination of arrivals improves pore-pressuremeasurement and allows geomechanical inter-pretation based on while-drilling compressional,shear and density data.

Acoustic data can now also be further refinedby acquiring data while the pumps are off.Background noise of the same frequency as sonicmeasurements, generated by drilling andcirculation, can be problematic for makingaccurate acoustic measurements. During adrillpipe connection, the sonicVISION tool canacquire real-time formation velocity measure-ments in a quiet environment, increasingconfidence in the STC projections and potentiallyallowing engineers to observe velocity changescaused by flow-induced stress variance.

To speed data to the surface, Schlumbergerrecently released the TeleScope high-speedtelemetry-while-drilling service. This newmeasurement-while-drilling (MWD) system iscapable of providing enough power to run eight ormore LWD tools while offering up to a fourfoldincrease in data rate over comparable tools. Fieldapplication of these new hardware technologies,in combination with improved pore-pressuremodeling described earlier, promises to enhancedrilling efficiency and reduce geologic and well-construction uncertainty.

Advancements in sonic LWD tool design andtelemetry systems have overcome many of theinadequacies previously inherent in while-drilling sonic measurements. New data proces-sing techniques and improvements in telemetrysystems have minimized earlier limitations,allowing real-time access to while-drilling soniccompressional measurements in almost anydrilling environment.

Seismic, Sonic and Pressure Measurement—Defining the Mud-Weight WindowIn many GOM fields, pore pressure changesrapidly with depth, and tight mud-weightwindows make drilling and completion difficult,or even impossible. One example of an extremelydifficult environment is the Vermillion offshorearea. Here, mud weights often reach 18 lbm/galUS[2,157 kg/m3], the risk of wellbore instability and lost circulation is high, and six or more casing strings are typically required to reachtarget reservoirs.

Today, operators use data retrieved duringdrilling from sonicVISION, StethoScope formation-pressure-while drilling service and other LWD toolsto help improve well-construction efficiency andreduce cost by accurately defining and managingthe effective stress and mud-weight window.

Sonic LWD, real-time formation pressure andother while-drilling tools were successfully usedto reduce risk and operational uncertainty whiledrilling a well in Vermillion Block 338 during2005. In this well, which was owned by Helis Oil &Gas LLC and operated by PPI TechnologyServices, engineers planned and executed anaggressive drilling program. This programextended both the 9 ⁄5⁄⁄ -in. intermediate casing and7-in. liner strings to sufficient depths to eliminatea string of casing common to wells in the area, inthis case, a 5-in. casing string. These efforts notonly reduced well cost, but more importantly,eliminated the difficulties associated withslimhole drilling and the completion limitationsinherent in small production casing.

76 Oilfield Review

> Compressional and shear peaks available in real time. Because of improvements in downhole tooland telemetry systems, slowness time coherence peaks can now be sent to the surface forevaluation and labeling while drilling (Track 2). Previously, the semblance projection was availableonly by processing tool memory after the tool was pulled from the borehole (Track 1). The semblanceprojection based on the real-time peaks (Track 3) is consistent with the memory-mode data. Stationmeasurements of compressional ∆t (white circles) acquired during quiet periods, such as whenpumps were off during pipe connections, also confirm the accuracy of the real-time data. ThesonicVISION system has the unique capability to modify label limits (Track 2) at surface for betterextraction of compressional data, and for the first time, real-time shear data. These improvements inreal-time quality control make the compressional input, used for pore-pressure calculation ofminimum mud weight, more robust. Combining the real-time compressional and shear data alsoenables geomechanical calculations of the maximum mud-weight window.

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Winter 2005/2006 77

Accurate prediction of geologic target depthand pore pressure is essential to the success ofaggressive drilling plans. Helis and PPI engineersbased their initial well design on mud weightsfrom wells in the area. They next approachedSchlumberger to refine these predictions usingthe GOM 3D mechanical earth model, to befurther refined with while-drilling sonic data.

While-drilling data were transmitted bysatellite to a remote operations and collaboration

center where the wellbore hydrodynamics andgeomechanical earth models were updated inreal time using data from the rig (above). Toaccount for variations in lithology and sediment-compaction rates, the nonlinear normal compac-tion transform established during predrillingplanning was validated and recalibrated whiledrilling using sonicVISION data and directpressure measurements from the FPWDFormation Pressure While Drilling tool.

Correlating data acquired from thesonicVISION and FPWD tools significantlyincreased confidence in the real-time pore-pressure prediction model. These measurementsallowed predrilling uncertainties associated withthe velocity-to-pore-pressure transform to beproperly defined while drilling. The calibratedtransform was then applied to revise and update

> Telemetry to engineering centers. The wellsite engineer collects drilling, mud and sonic LWD data,tthen transmits this information to the engineering center where a team of experts analyzes andprocesses the data. Once the results are returned to the wellsite, initial pore-pressure predictions(A) are updated with pore-pressure estimations (B), ultimately reducing the cone of uncertainty(C) and providing more accurate predictions of pore pressure ahead of the bit (D).

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the predrilling pore-pressure model, both behindand ahead of the bit (right).

The results, including the mud-weightrecommendations, were then conveyed to the rig,and action was taken to ensure that the surfacemud weight, the equivalent circulating density(ECD) and the equivalent static density (ESD)were kept within the limits of the mud-weight window.

The initial requirements for setting the 95⁄5⁄⁄ -in.casing were constrained by a 13-lbm/galUS[1,558-kg/m3] fracture point derived fromprevious experiences in the field. However, thecalculated fracture gradient derived from while-drilling formation velocity and density measure-ments indicated that the rock strength wassubstantially higher, and capable of accom-modating a heavier drilling fluid.

The mud weight was increased to13 lbm/galUS based on the real-time pore-pressure analysis as drilling approached 6,800 ft[2,072 m]. Using real-time sonic LWD data,while-drilling pressure measurements andadvanced data processing techniques, geo-scientists at the remote collaborative centerestablished a safe mud-weight range that allowedthe driller to reach a depth of 8,187 ft [2,495 m]before running 95⁄5⁄⁄ -in. casing; at casing depth, theECD was within 0.1 lbm/galUS [11.98 kg/m3] ofthe calculated fracture gradient.

Once the 95⁄5⁄⁄ -in. casing was set, drillingresumed with an 8 ⁄1⁄⁄ -in. bit. At 9,500 ft [2,896 m],the annular pressure exceeded the fracturegradient, and circulation was lost. Time-lapseresistivity analysis indicated two zones near theprevious casing shoe where the formation hadprobably been damaged.

On further evaluation, engineers believedthat the cost of remedial squeeze operationsoutweighed the risk of drilling ahead with tighthydraulic control and a maximum mud weight of17.5 lbm/galUS [2,097 kg/m3]. Carefully moni-toring and maintaining the annular pressureswithin an accurately calibrated hydraulic-pressure envelope allowed the operator to com-plete the well at 12,507 ft [3,812 m] in the targetreservoir without an additional string of casing.

The combined efforts of Schlumberger, PPIand Helis engineers eliminated the preplanned5-in. casing string and avoided the difficultiesassociated with slimhole drilling and completion.Sonic LWD, while-drilling pressure measurementsand careful hydrodynamic monitoring using theAPWD Annular Pressure While Drilling toolsucceeded in identifying pore-pressure changesand fracture points, and allowed drilling toproceed within the constraints of a narrow mud-weight envelope.

Engineers significantly reduced the uncer-tainty associated with pressure-predictionmodels by updating the predrilling velocity-to-pore-pressure transform using sonic LWD dataand measuring true formation pressure. Thecritical 95⁄5⁄⁄ -in. casing depth was pushed 1,187 ft[362 m] deeper than planned, eliminating anentire casing section and reducing well cost bymore than US$ 1.7 million.

A Sound Future for While-Drilling Acoustic ToolsA new generation of sonic LWD tools is helpingdrillers, engineers and geoscientists make manydecisions that facilitate safe and cost-effectivewell construction. By supplying timely infor-mation on formation velocity, while-drillingacoustic tools have proved to be a valuable assetto the well-engineering team.

Today’s sonic LWD systems are providingaccurate acoustic data that in turn, are beingprocessed in real time to reliably determine porepressure and the geophysical limits of formationsbeing drilled. When combined with seismic andother real-time data, this information helpsgeoscientists see ahead of the bit to the nextgeologic horizon and beyond. Defining the mud-weight window while drilling enables engineersto deviate from predrilling casing designs,pushing casing seats to greater depths andsignificantly reducing well cost.

Much like the development of sonar early in the 20th century, advances in modelingsoftware, acoustic tool design and decision-processing utilities are helping engineers see the unseen and make sound drillingdecisions, reducing cost and increasing well-construction efficiency. —DW

78 Oilfield Review

> Drilling in a narrow mud-weight window. The top of the pore-pressure rampis confirmed at around 6,800 ft by the sonic (red) and formation pressure while-drilling measurements (green diamonds). Between 7,000 and 8,000 ft[2,134 and 2,438 m], a significant divergence between the predrilling model(green curve) and actual pore pressure represents an example of theimportance of using real-time measurements to update the predrilling model.As drilling progressed below 9,000 ft [2,743 m], accurate pore-pressureprediction, pressure measurements and hydraulic modeling allowed thedrilling team to maintain the mud weight (black curve), equivalent static (bluediamond) and equivalent circulating (purple curve) densities within a narrowwindow just below the real-time fracture gradient (gold curve).

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Winter 2005/2006 79

Jeff Alford is a Senior Petrophysicist in theSchlumberger Interpretation Development (ID) groupin Houston supporting both logging-while-drilling(LWD) and wireline sonic and ultrasonic projects.Since joining the company at Belle Chasse, Louisiana,USA, in 1981, he has had experience in wireline soniclogging, well seismic and seismic acquisition tools as afield seismic specialist and more than 10 years as a loganalyst specializing in seismic, sonic and ultrasonicprocessing. He was responsible for measurement eval-uation of the original field tests of the DSI* DipoleShear Sonic Imager tool, and most recently was seniordevelopment engineer for the LWD sonic engineeringproject culminating in the sonicVISION* sonic-while-drilling tool series. Jeff holds an AS degree in electron-ics engineering from Delgado University, New Orleans,and a BS degree in geology from the University ofGeorgia, Athens, USA.

Michele Arena is West and South Africa ProjectManager for Schlumberger Well Completions andProductivity (WCP), based in Rosharon, Texas, USA.He is responsible for system integration testing,quality assurance and control documentation, andcompletion procedures and equipment development.He joined Schlumberger in 1998 as surface-testingchief operator in Gabon and then worked in Africa,Europe, the Middle East and Canada while based inParis. Michele transferred to WCP in 2000 and hasworked as engineer in charge and project engineeron reservoir monitoring and control and intelligentcompletion projects in Equatorial Guinea, Europe, theUSA and Cameroon before assuming his current post.He earned an AS degree in electrical engineering fromthe University of Roma La Sapienza.

Les Bennett, based in College Station, Texas, worksfor Schlumberger Data & Consulting Services (DCS)as Geophysical ID consultant. He provides a boreholeseismic knowledge base to the field of hydraulic frac-ture monitoring to develop advanced microseismicprocessing techniques. He previously worked on thedevelopment of a new borehole seismic system. Sincejoining Schlumberger as a field engineer in 1978, hehas worked in Mississippi, Louisiana and Texas, USA,as a log analyst, staff engineer, senior applicationsgeoscientist and manager of the borehole seismiccomputing center. Les received BS and MS degreesin electrical engineering from the University ofMississippi, Oxford, and an MS degree in computerscience from the University of Texas at Dallas.

Larry J. Bernard is Manager of Schlumberger OilfieldServices Product Qualification and Quality based inSugar Land, Texas. He oversees qualification testingduring development of products at the technology andproduct centers as well as product quality in manufac-turing. He joined Schlumberger in 1977 and worked sixyears in operations as repair and maintenance supervi-sor, quality manager and district engineer for measure-ments-while-drilling (MWD). He spent the next 14years in engineering working on several downhole toolprojects. As department manager for SchlumbergerTechnical Services, Larry provided internal qualifica-tion testing services, failure analysis, printed circuit-board design and assembly, microelectronics designand prototyping, and simulation and modeling services

to the technology centers. He earned an AS degree inelectronics technology from United ElectronicsInstitute in Little Rock, Arkansas, USA.

W.S. (Scott) Birk, who is based in Oklahoma City,Oklahoma, USA, is Schlumberger Account Managerfor Chesapeake Operating Inc. and has accountresponsibilities for several other companies in thesouthwest region including Carl E. Gungoll ExplorationLLC, Range Resources Limited and Bracken OperatingLLC. Scott joined Schlumberger in 1979 as a Dowellservice supervisor in Ohio and later worked as a salesengineer and senior sales engineer in Ohio,Pennsylvania, Arkansas and Oklahoma, USA.

Brett Borland, Manager of Drilling Technology forConocoPhillips, joined the company in 1990 after sixyears with Oryx Energy Co. and three years with Sedcoas a drilling contractor. With Oryx, he drilled the firsthorizontal wells in the Austin Chalk and, with Conoco,helped construct two of the first drillships designed tooperate in 10,000 ft [3,048 m] of water. He has exten-sive worldwide drilling operations experience on landand offshore in the Middle East, Russia, Norway, the UK,Congo and the western USA and Gulf of Mexico. Brett’sexpertise includes underbalanced drilling, high-pressure, high-temperature drilling, arctic drilling andoffshore operations on drillships, semisubmersibles,jackups and platform rigs. Before taking his currentpost, he was the deepwater drillship asset manager forthe Deepwater Pathfinder and Deepwater Frontier.

Abderrahmane Boumali, New Technology ServiceManager for Sonatrach in Algiers, Algeria, managesboth design and implementation of stimulation jobs,preparing annual and monthly reports and forecastingfor planning. Since 2000, he has been in charge of allstimulation, well selection, problem diagnosis andtechnical discussion with service companies in additionto postevaluation in the Hassi Messaoud field inAlgeria. He joined the company as a workover supervi-sor in 1988 after completing his BS degree in petroleumproduction engineering from the National Institute ofHydrocarbons in Boumerdes, Algeria. Abderrahmanealso worked as stimulation, fracturing and coiled tubingapplication supervisor and as stimulation design andevaluation engineer in Hassi Messaoud. He has writtenseveral papers on coiled tubing.

Mark E. Brady, Schlumberger GeoMarket* TechnicalEngineer based in Doha, Qatar, is working to increasethe matrix stimulation business by transferring keytechnologies to the field. He is responsible for providingdirect support to field organizations and developingand tailoring new technology to specific markets. Hismost recent projects were the successful introductionof VDA* Viscoelastic Diverting Acid service for carbon-ate acidizing in the USA and the growth of matrixacidizing for clients in the Gulf of Mexico. Since joiningSchlumberger in 1994, he has played a key role inintroducing many new technology applications. Beforeassuming his current position in 2004, he worked inSugar Land, Texas, as senior matrix stimulation supportengineer for North and South America. He also servedas development engineer for the sand-managementgroup. Mark has published numerous papers and holdsmany patents. He earned BS and PhD degrees inchemistry, both from The Queen’s University, Belfast,Northern Ireland.

Jay Cooke, based in Houston, is a Senior PetroleumEngineer for Helis Oil & Gas, LLC. He has a BS degreein ocean engineering from Texas A&M University,College Station.

Julian Drew joined Schlumberger Geco-Prakla in1993 at the Perth, Australia, seismic data processingcenter. He began his career as a geophysicist aftergraduation from the University of Western Australia,Perth, with a joint BS degree in physics and BE degreein mechanical engineering (Hons). In 1996, he trans-ferred to Schlumberger Wireline as a field engineerand seismic specialist in the Far East-Asia region.Julian later worked for Schlumberger D&M beforemoving to the SKK Technology Center at Fuchinobe,in Sagamihara, Kanagawa, Japan, where he is currentlya Project Manager.

Stephen Dyer is Schlumberger Completions ProjectOffice Manager, responsible for technical and projectsupport, front-end engineering design and projectmanagement for the WCP Wireline Completion andEquipment Services group in Rosharon, Texas. Hejoined Schlumberger in 1991 as a field engineer work-ing in the North Sea, Norway and the Far East. Aftersix years, he transferred to Jakarta as a productionenhancement engineer. In 2000, he returned to WCPTesting as instructor and senior instructor. Steve hasalso served as a WCP completion architect and projectmanager on advanced completion projects offshoreCalifornia, USA, and Nigeria. He has a BS degree inmechanical engineering from LoughboroughUniversity, England.

Leo Eisner is a Senior Research Scientist atSchlumberger Cambridge Research (SCR), England,focusing on hydraulic fracture monitoring, near-wellseismic modeling, reservoir characterization and fullwaveform inversion. He is also a coordinator of aEuropean Union project that involves SCR collaborationwith five European academic institutions on transferringearthquake seismology to hydraulic fracture monitor-ing. Leo earned an MS degree in physics from CharlesUniversity, Prague, Czech Republic, and a PhD degreein geophysics from California Institute of Technologyin Pasadena.

Li Fan is a Principal Reservoir Engineer and ReservoirEngineering Manager with Schlumberger ConsultingServices (formerly S.A. Holditch and Associates) inCollege Station, Texas. He holds a BS degree in electri-cal engineering from University of Petroleum of Chinain Dongying, and ME and PhD degrees in petroleumengineering from Texas A&M University, CollegeStation. Li has worked as a reservoir engineer withSchlumberger since 1997, and has been involved indomestic and international projects ranging from single-phase, single-well analysis to multiphase, multiwell,full-field modeling. He successfully led and managedmany large integrated field studies in tight-gas reser-voirs for reserve evaluation and field developmentplanning optimization onshore Texas and Louisiana.

Erik Ferdiansyah is a Shell Production Technologistcurrently assigned to Petroleum Development Oman.Before taking this post, he worked six years forSchlumberger in the USA, Middle East and Indonesia.Erik holds a BS degree in electrical engineering fromGadjah Mada University in Yogyakarta, Indonesia.

Contributors

80 Oilfield Review

Roger B. Goobie is the Perform/No Drilling Surprises(NDS) Manager for the Schlumberger D&M North andSouth America Operations Support Center, Houston.He is responsible for implementing the Performprocess, which is designed to reduce drilling costs bysignificantly improving project planning, executionand evaluation. In addition, he is involved in developingdrilling optimization software products for real-timeremote operations. He joined the company as aspecialist drilling engineer more than 10 years ago,after obtaining a BS degree in electrical engineeringfrom the University of the West Indies in St. Augustine,Trinidad and Tobago. Before taking his current post,Roger worked in Trinidad and Tobago, Venezuela, Gulfof Mexico, Colombia, Brazil and India as lead engineeron several Perform/NDS projects.

Jim Govenlock, based in Oklahoma City, Oklahoma,works for Chesapeake Operating Inc. as AssetManager, Barnett Shale formation. He is responsiblefor technical planning as well as regulatory complianceand profitability monitoring. Jim joined the companyafter nine years with Schlumberger Oilfield Services inCanada, New Mexico and Texas. He holds a BS degreein chemical engineering from the University ofAlberta, Edmonton, Canada.

Billy W. Harris is a Senior Petroleum Engineer forWagner & Brown Ltd. in Midland, Texas. He is responsiblefor supervising or performing all company reservoirengineering, for production forecasts and Security andExchange Commission evaluations, and for productionengineering in the Rocky Mountain region. After grad-uating from the Colorado School of Mines in Golden,USA, with a BS degree in petroleum engineering, Billyjoined Conoco as a production engineer. He laterworked as drilling engineer, operations engineer andreservoir engineer for several companies includingTenneco E&P and National Oil Company of Denver.Before joining Wagner & Brown in 1990, he was aninternational wellsite consultant and operator.

Allen Harrison, a Special Projects expert forSchlumberger Oilfield Services in Sugar Land, Texas,has worked on many oilfield projects from the designand manufacture of wireline logging tools to the devel-opment of encryption and e-commerce applications.His primary interests are research and engineeringmanagement, especially the coordination and develop-ment of intricate systems dependent on both hardwareand software components. Allen has been instrumentalin the site selection, design and construction of theCameron Texas Facility (CTF), which providesresources for testing and proving products and services.He has also worked in various positions includingmanufacturing and engineering department head forsonic, nuclear and electrical wireline products, vicepresident of engineering for Schlumberger AutomatedTest Equipment and as leader of many informationtechnology projects. He earned MA and PhD degreesin physics from Rice University in Houston.

Andy Hawthorn, Acoustic Product Champion forSchlumberger D&M, is based in Sugar Land, Texas.He is responsible for the sonicVISION tool,seismicVISION* seismic-while-drilling service and newacoustic engineering projects. Andy joined the companyin 1990 as a field engineer in Norway. Since then hehas held many positions around the world, mainly inthe North Sea and Middle East. He has a BS degree ingeology and an MS degree in geological engineeringfrom University of Durham in England.

A. (Jamal) Jamaluddin is currently establishingReservoir Fluid/Flow Assurance Advisory Services forSchlumberger. Based in Rosharon, Texas, he workswith operating engineers worldwide to understandreservoir fluids, reduce uncertainties in reservesbooking and assure flow from sandface to productionfacilities. He began his career as a research scientistat Noranda Technology Centre in Montreal, Quebec,Canada and served as project leader and programleader on projects related to oil and gas research andtechnology development. Before joining Schlumbergerin 1998, he was director of technical services at HycalEnergy Research Laboratories in Calgary. Jamalobtained a BS degree in petroleum engineering fromKing Fahd University of Petroleum and Minerals,Dhahran, Saudi Arabia, and MS and PhD degrees inchemical engineering from the University of Calgary.He is coinventor of five patented processes in petroleumproduction and optimization and coauthored morethan 70 technical papers. He chaired the InternationalQuality & Productivity Center (IQPC) Conference onFlow Assurance: A Holistic Approach in Kuala Lumpurin 2003 and served as SPE Distinguished Lecturer for2004–2005.

Rob Jones is Research Director and DisciplineManager, Geophysics, at Schlumberger CambridgeResearch, England. He has spent a major part of hiscareer in the field of passive seismic or microseismicstudies. He began work as a geophysicist in the UK HotDry Rock Geothermal Energy Project, Cornwall. Helater joined ABB, then CSMA, in Cornwall, as chiefgeophysicist, to develop new technologies, promotemicroseismic monitoring and develop new hardwareand software products. ABB later sold its upstream oiland gas interests to Vetcogray, which sold its micro-seismic technology to Schlumberger. Rob joinedSchlumberger in 2005 as program manager of boreholegeophysics. A prolific author and patent holder, hehas a BS degree (Hons) in physics from the Universityof Manchester, an MS degree in geophysics from theUniversity of Birmingham, and a PhD degree in geo-physics from the University of Cambridge, all in England.

Jairam Kamath is Team Leader, Well PerformanceMeasurements and Modeling, for Chevron EnergyTechnology Company in San Ramon, California. Histeam provides technology development and services toChevron’s operating companies worldwide in the areasof well-performance modeling, well testing, productionlogging, reservoir mechanisms and phase behavior.Jairam joined Chevron in 1985 as a research engineerafter acquiring a BS degree from the Indian Instituteof Technology in Madras, and a PhD degree in mechan-ical engineering, specializing in fluid mechanics andthermodynamics, from the University of Michigan atAnn Arbor, USA.

Tom Kavanagh is a Schlumberger Coiled TubingEngineer currently seconded to BP on the SharjahCoiled Tubing Underbalanced Drilling (UBD) projectas a Wellsite Drilling Engineer. Based in Sharjah,United Arab Emirates (UAE), he is responsible for thesmooth operation of all surface and downhole equipmentwhile drilling and for maintaining UBD conditions.Since joining Schlumberger in Alaska, USA, in 1995,Tom has been involved in many coiled tubing drillingprojects as project manager, engineer and wellsitesupervisor. He is a graduate of the University of Alaska,Fairbanks, with a BS degree in petroleum engineering.

Richard C. (Rick) Klem, Product DevelopmentChampion for HFM* Hydraulic Fracture Monitoringservices, is based in Sugar Land, Texas. He is responsiblefor the timely introduction and maximum commercialimpact of new products and services through anunderstanding of their physics, operation, hardware,software, applications, limitations and marketplacevalue. He began his career as a field engineer forDowell in 1980 and later worked for the Gas ResearchInstitute as coalbed methane project manager. Ricklater rejoined Schlumberger, working in various engi-neering, marketing and management positions in theUSA, Nigeria, Saudi Arabia and the UAE. He holds a BSdegree in geology from Arizona State University inTempe, USA, and has been secretary, treasurer andchairman of the Four Corners section of SPE.

Santhana Kumar holds a PhD degree from MaharajaSayajirao University of Baroda, Vadodara, Gujarat,India, an MTech degree from the Indian Institute ofTechnology, Kharagpur, and a BTech degree fromMadras University, India, all in chemical engineering.He has more than 21 years of experience in petroleumengineering. Currently, he is a Workover andStimulation Specialist (Production Technology) withPetroleum Development Oman. Previously, he workedfor Abu Dhabi National Oil Company, Kuwait OilCompany and India’s Oil and Natural Gas Corporation.

Joël Le Calvez, based in College Station, Texas, is aSchlumberger Senior Geologist, working on develop-ment and commercialization of the microseismic busi-ness. His main responsibilities are the processing andinterpretation of data for geological, geophysical andgeomechanical applications and client presentations.He also works with product centers on defining pro-grams and testing software, and with research centerson defining and testing of algorithms. Joël joinedSchlumberger in 2001 after acquiring his PhD degreein geology from the University of Texas at Austin. Hehas since worked on geological and seismic studiesthroughout the southwestern USA and offshore Angola.He holds a Diplôme d’Etudes Approfondies in tectonicsand condensed matter from the Université Pierre etMarie Curie in Paris, an MS degree in geology andgeophysics from the Université de Nice-SophiaAntipolis, and a BS degree in mathematics andphysics from the Université de Nice, France.

David Leslie is a Senior Research Scientist at SCR,England, working in the Geophysics Borehole Seismicprogram on hydraulic fracture monitoring and activeand passive reservoir characterization. His researchfocuses on algorithm development for event localizationand characterization, on survey design methodologiesand on interpretation of microseismic data. Beforejoining SCR in 1998, he worked in engineering positionsin Tokyo and Houston, in wireline ID in Montrouge,France, in research in Ridgefield, Connecticut, USA,and as a junior field engineer in Texas. David receiveda BS degree in electrical engineering from PrincetonUniversity, New Jersey, USA, an MS degree in oceanengineering from the Massachusetts Institute ofTechnology, Cambridge, USA, and was awarded thedegree of Ocean Engineer in the joint program inoceanographic engineering of the Woods HoleOceanographic Institution, Massachusetts, and theMassachusetts Institute of Technology.

Winter 2005/2006 81

Bill Lesso, Casing Drilling Advisor, works forSchlumberger D&M in Houston. He is currently working with ConocoPhillips in deploying casingdirectional drilling in Norway and China. He joinedthe company in 1976 as a field engineer in Dayton,Texas, after earning a BS degree in mechanical engi-neering from the University of Texas at Austin. Sincethen, Bill has held positions in Wireline, Well Servicesand D&M. He has managed horizontal-well andgeosteering projects in Malaysia, the UK, LatinAmerica and the USA. He became involved in casingdrilling after a visiting position at SCR, England.

Walter Luckett has worked as Test Facilities,Environmental Effects Calibration Facility and CustomerAcceptance Testing Manager at the SchlumbergerSugar Land Technology Center, Texas, since 2003.He joined Schlumberger in 1986 as a field engineerin Morgan City, Louisiana, after obtaining a BS degreein petroleum engineering from Mississippi StateUniversity, Starkville. He has also worked in SaudiArabia, Abu Dhabi, Nigeria and Brunei in positionsthat included MWD/LWD field engineer, field testengineer, technical manager and operations manager.

Gwénola Michaud is a Schlumberger Senior ResearchScientist at the SKK Technology Center at Fuchinobein Sagamihara, Japan. Previously, she worked in theborehole seismic research group at SCR. This groupwas charged with identifying and developing cost-effective seismic acquisition and processing technolo-gies for active and passive borehole data. She joinedthe company in 2001 after earning a PhD degree ingeophysics from the Colorado School of Mines inGolden. Concurrently, she worked as an engineer forCompagnie Générale de Géophysique, Massy, France.Gwénola also holds a BS degree in mathematics fromUniversité de Pau et des Pays de l’Adour, and an MSdegree in geophysics from Université Louis Pasteur,Strasbourg, both in France.

Robert Mott is an Independent Consultant on gas-condensate reservoir engineering, simulation and riskmanagement, based in Dorchester, UK. For the pastfive years he has worked with ECL Technology andPetroleum Engineering Reservoir Analysts (PERA a/s)and has presented public courses in gas-condensatereservoir management in London, Aberdeen,Trondheim and Dubai and in-house courses for SaudiAramco, Chevron and Veba Oil Operations. Robertalso served as SPE Distinguished Lecturer on the pro-ductivity of gas-condensate wells. Before becoming anindependent consultant, he spent 20 years with AEATechnology as a reservoir engineer, section leader andtechnical manager. He holds an MA degree inmathematics from University of Cambridge, England,and a PhD degree in theoretical physics fromUniversity of London.

Avel Z. Ortiz has been a Senior Engineer in theCoilSolutions group of the Schlumberger Coiled TubingServices department since 2001. Based in Sugar Land,Texas, he is involved in short-term projects for thedesign and implementation of tools such as theOptiSTIM MP* mechanical packer for CoilFRAC*stimulation through coiled tubing operations, BlasterMLT* multilateral reentry stimulation and scaleremoval system as well as OptiSTIM ST* straddlepacker for stimulation development. He began hiscareer as a process engineer for WorldPAK Corp. inTexas but moved to the oil industry as a design engineerwith Camco Products & Services, later SchlumbergerWCP in Houston. Avel holds a BS degree in mechanicalengineering from Texas A&M University, College Station.

Richard A. Ortiz is the Coiled Tubing DrillingSuperintendent for the BP Sajaa Field Coiled TubingUnderbalanced Drilling project. Before taking hiscurrent post with the BP Sharjah Oil Company MiddleEast & Pakistan business unit in the UAE, Richardhad petroleum engineering assignments in PrudhoeBay, Alaska, and was coiled tubing drilling advisor inAlgeria. He joined BP in 1984 after earning a BSdegree in natural gas engineering from Texas A&MUniversity in Kingsville.

Arun Pandey, who is based in Muscat, Oman, is aSchlumberger Sales Engineer for MaxPro* productionservices for well-performance diagnosis and mainte-nance. He has been with the company since 1986,working as a laboratory supervisor, in general field-testing services, as a wireline expert on field operationsinvolving cased-hole and openhole logging, and assales engineer for cased-hole organic mud-acid prod-ucts. Arun has a BS degree in electrical engineeringand an MS degree in petroleum engineering fromTrinity College, Carmarthen, Wales.

Doug Pipchuck, Schlumberger GeoMarket TechnicalEngineer, Coiled Tubing (CT) for Canada, is based inCalgary. After earning a BS degree in biochemistryand chemistry from the University of Calgary, hejoined Dowell as a laboratory technologist, working oncement systems. He later worked as a field engineeron perforating, cementing and CT drilling projects,designing and carrying out production logging,cleanout and fishing operations. He also was a wellsitesupervisor for underbalanced drilling projects inwestern Canada. Before assuming his current post in2005, Doug served as a Schlumberger DESC* designand evaluation services for clients engineer for TalismanEnergy, responsible for cementing, stimulation andwell intervention.

Paolo Primiero, based at the SKK Technology Center at Fuchinobe in Sagamihara, Japan, is aSchlumberger Geophysicist working in methanehydrate research and development. Before this, he wasa microseismic software engineer involved in hydraulicfracture monitoring and algorithm development, and apostdoctorate fellow under the European UnionInternational Cooperation (INCO)-Japan Program.Paolo earned a BS degree in geology at the Universityof Trieste, Italy, and a PhD degree in geophysics atImperial College, London.

Gary A. Pope is Director of the Center for Petroleumand Geosystems Engineering at the University ofTexas at Austin, where he has taught since 1977.He holds the Texaco Centennial Chair in PetroleumEngineering. His teaching and research focus ongroundwater modeling and remediation, groundwatertracers, enhanced oil recovery, chemical thermody-namics and phase behavior, and reservoir engineeringand simulation. He is an author or coauthor of morethan 160 technical papers. Gary obtained a BS degreefrom Oklahoma State University, Stillwater, and aPhD degree from Rice University, Houston, both inchemical engineering.

John C. Rasmus is an Advisor in LWD ReservoirCharacterization for Schlumberger, based in SugarLand, Texas. His current duties include LWD interpre-tation, InTouchSupport.com* online support andknowledge management system, resistivity andnuclear interpretation support and special projects.He has held various interpretation development posi-tions, such as innovative interpretation techniquesfor secondary porosity in carbonates, geosteering of

horizontal wells, geopressure quantification in under-compacted shales and downhole motor optimization.John holds a BS degree in mechanical engineeringfrom Iowa State University in Ames, USA, and an MSdegree in petroleum engineering from the Universityof Houston. He is a registered professional petroleumengineer in Texas as well as a registered professionalgeoscientist in geophysics.

Thomas Rebler has been Manager of Reliability andQualification Testing at the Sugar Land TechnologyCenter, Texas, since 2001. He is responsible for over-seeing qualification testing of all new downhole andsurface equipment developed there. He began hiscareer in 1984 as a field engineer with FlopetrolJohnston in Bakersfield, California, where he performedall testing services. He later worked as a wireline fieldengineer and as a D&M field engineer in various USAland and offshore locations. Before moving to SugarLand in 2000 as LWD environmental qualificationengineer, Thomas also served as field service managerand as sales engineer for MWD/LWD and directionaldrilling services. He earned a BS degree in petroleumengineering from Louisiana State University inBaton Rouge.

David R. (Rich) Sarver is a Senior ProductionEngineer with Schlumberger DCS, based in CollegeStation, Texas. He provides production engineeringconsulting services, including hydraulic fracturedesign, execution and evaluation, within the companyand to clients. He also performs rate transient analy-sis to evaluate specific Schlumberger products andservices. After receiving a BS degree in petroleumengineering from Marietta College, Ohio, Rich beganhis career with Mitchell Energy in California andColorado. He joined Schlumberger in 1993 as a fieldengineer and later worked as sales engineer andDESC engineer in Oklahoma and Texas before takinghis current post in 2004.

Colin M. Sayers is a Scientific Advisor with theSchlumberger DCS Geomechanics Group in Houston,providing consultancy in pore-pressure prediction,wellbore-stability analysis, geomechanics, rockphysics, geophysics and the properties of fracturedreservoirs. Since joining the company in 1991, Colinhas won several awards for his work, including theConrad Schlumberger Award. He obtained a BAdegree in physics from the University of Lancaster,England, a DIC degree in mathematical physics, anda PhD degree in theoretical solid-state physics fromImperial College, University of London. He is amember of the Research Committee of the SEG andhas published more than 100 technical papers.

Alexander Shandrygin, based at the SchlumbergerMoscow Research Center, is Advisor for ReservoirPhysics, responsible for the development of R&Dstrategy and scientific support of research projects.Prior to joining the company in 2002, he was the chiefengineer for ENCONCO, a petroleum consulting com-pany. He began his career as a scientist and thenbecame associate professor at the Grozny PetroleumInstitute, Russia, after receiving MS and PhD degreesin oil and gas reservoir development there. He alsoworked as senior research scientist at the Oil and GasResearch Institute of the Russian Academy ofScience, while doing postdoctoral research at theGubkin Russian State University of Oil and Gas.Alexander spent the next seven years as chiefresearch scientist in the condensate recovery

82 Oilfield Review

department of VNIIGAS, the All-Russia ResearchInstitute of Natural Gases and Gas Technologies, andas deputy director of the Field Development Plandepartment and deputy director of the engineeringcenter at the Yukos Oil Company in Moscow.

Sundaram (Sundy) Srinivasan, Manager of the OilfieldServices Test Facility for Schlumberger in Sugar Land,Texas, is responsible for the final field-testing of many of the latest downhole tools and technologies.He began his career with Schlumberger in 1985 as adrilling engineer and later was a district managerwith Sedco Forex. He worked as a district managerand marketing manager for the SchlumbergerWireline division before joining the Integrated ProjectManagement group as a project manager, country manager and area business manager. Sundy managedstartup offices for Schlumberger in Denmark andVietnam, was a principal consultant with theSchlumberger Oil and Gas Business Consulting Groupand has interacted with operating companies aroundthe world. His BTech degree in mechanical engineeringis from the Indian Institute of Technology in Delhi,India. He also earned an MBA degree from the SloanSchool of Management at the Massachusetts Instituteof Technology, Cambridge.

Kevin Tanner is a Senior Production Engineer withextensive experience in microseismic hydraulicfracture monitoring for Schlumberger DCS in CollegeStation, Texas. He joined the company in 1990 as afield engineer for Well Services in Wyoming, USA, afterearning a BS degree in chemical engineering from theUniversity of Colorado at Boulder. Before assuminghis current position, Kevin worked as DESC engineer,district engineer and technical sales engineer inWyoming, Colorado, Texas and Alaska.

Kazuhiko Tezuka is a Senior Manager of Developmentand Engineering Laboratory, JAPEX Research Center,Chiba, Japan. He joined JAPEX after graduation fromTohoku University, Sendai, Japan, with a BS degree ingeophysical engineering. He later worked as a visitingscientist at Earth Resources Laboratory at theMassachusetts Institute of Technology in Cambridge.Kazuhiko received a DE degree, also from TohokuUniversity in earth resources engineering and is a vicepresident of technology of the SPWLA Japan chapter.

Ron Thomas, President of PPI Technology Services,LP, has more than 27 years of oil and gas industryexperience in the Gulf of Mexico, inland waters andinternationally. Before joining PPI, he held a variety ofpositions with companies including Mobil Oil, CNGProducing and Hall-Houston Oil Company. He has a BSdegree in petroleum engineering from MississippiState University, Starkville, and an MBA degree fromHouston Baptist University. Ron is a registered profes-sional engineer in Texas, Louisiana and Mississippi.

Ed Tollefsen is New Technology Product Champion forSchlumberger D&M in Houston. His focus is on real-time pore-pressure prediction using LWD formationpressures and sonic and seismic data. He joinedSchlumberger in 1990 and has held several positions inwireline evaluation services, formation testing withthe MDT* Modular Formation Dynamics Tester tooland seismic services. He later served as a staff engineerwith responsibility for design changes to offshore unitsand as a field service manager for Gulf Coast SpecialServices. There, he worked to increase pressure rat-ings on tools, improve surface seismic capabilities and

make logging while fishing a standard means of con-veyance. Before taking his current post, Ed managedWireline US Land Seismic & Special Services Operations.He is a graduate of Georgia Institute of Technology inAtlanta with a BS degree in computer engineering.

Trond Unneland manages Chevron activities inNorway. Before moving to Norway, he was the ChevronDenmark country manager in Copenhagen (2004 to2005) and technology account manager in San Ramon,California (2000 to 2004). Before joining Chevron in2000, he held engineering and management positionsin exploration, offshore operations and reservoir man-agement at Statoil in Norway for 16 years. Trond holdsan MS degree in reservoir engineering from StavangerUniversity and a PhD degree in petroleum engineeringfrom the Norwegian University of Science andTechnology, Trondheim. He has published many SPEpapers on reservoir management, sand control andwell performance, and has served on numerous SPEcommittees and forums.

Stan van Gisbergen has a PhD degree from theUniversity of Amsterdam and an MS degree from theUniversity of Eindhoven, The Netherlands, both inphysics. Currently he is Team Leader, Well andReservoir Management at Petroleum DevelopmentOman, responsible for one of the largest waterfloodsin Oman. Before taking his current post in 2003, he ledthe Intelligent Well team at Shell International E&P,worked on the Bonga field, Nigeria, as a productiontechnologist, and worked for Sakhalin Energy as leadproduction technologist, responsible for productionoptimization and well completions.

Tommy M. Warren is Director, Casing Drilling Research and Engineering, for Tesco Corporationin Houston. He joined Tesco in 1999 after 26 yearswith Amoco in operations and drilling research. Hisresearch in roller-cone bit mechanics, drag bitmechanics, directional drilling, drillstring mechanics,high-speed drilling systems, rock mechanics and theCasing Drilling® system has led to the publication of60 technical papers and 35 patents. Tommy earnedBS and MS degrees in mineral engineering from theUniversity of Alabama, Tuscaloosa, USA, and wasselected as a University of Alabama DistinguishedEngineering Fellow in 1994. In 1999, he served aschairman of the SPE Annual Technical Conferenceand Exhibition and was an SPE Distinguished Lecturer.He also chaired the SPE Publications coordinatingcommittee and received the 1997 SPE DrillingEngineering Award.

George Waters is Technical Projects Leader forSchlumberger DCS in Oklahoma City. He joined DowellSchlumberger in 1985 and held various field engineer-ing positions in the USA. He has had numerouscompletion engineering assignments since 1992,primarily in hydraulic fracture optimization. Sincejoining the DCS Solutions Group in 2000, he hasfocused on identification, evaluation and completionoptimization of US shale-gas reservoirs. His recentfocus has been on shale-gas horizontal-well completionoptimization, with particular attention to microseimicmonitoring of stimulation. George has a BS degreefrom West Virginia University, Morgantown, USA, andan MS degree from Ecole Nationale Supérieure duPétrole et des Moteurs, Rueil-Malmaison, France, bothin petroleum engineering. He also received an MSdegree in environmental engineering from OklahomaState University in Stillwater.

Rick Watts is an Engineering Fellow, UpstreamTechnology Drilling Engineering and Operations(DEO) for ConocoPhillips in Houston. His currentresponsibilities include serving as the technology coordinator for the greater Ekofisk area and casingdrilling coordinator for DEO. In 2000, he joined thecompany in Bartlesville, Oklahoma, after working22 years for Arco. His experience includes drillingengineering, project management, well completions,workovers and stimulation. Before his current position,he was principal drilling engineer and Bayu Undandrilling manager, offshore Australia. Rick holds a BSdegree in petroleum engineering from the ColoradoSchool of Mines in Golden.

Curtis Hays Whitson is a Professor of petroleumengineering at the Norwegian University of Scienceand Technology (NTNU), Institute of PetroleumEngineering and Applied Geophysics in Trondheim,where he teaches courses on petroleum phase behav-ior, enhanced oil recovery, well performance and gasreservoir engineering. He also consults extensively oncompositionally sensitive reservoir processes with thepetroleum industry through PERA a/s, a company hefounded in 1988. Curtis received a BS degree in petro-leum engineering from Stanford University, California,and a PhD degree in petroleum and chemical engi-neering from the Norwegian Institute of Technology,now NTNU.

Michael John Williams works at SCR, England, wherehe is Program Manager, Fluid Physics. The programevaluates many aspects of fluid flow including artificiallift, downhole separation, flow assurance and multi-phase flow. He joined Schlumberger GeoQuest in 1997as a commercialization software engineer and workedas project leader and team leader in Abingdon, England,and Sugar Land, Texas, before moving to SCR as asenior research scientist in 2004. His recent workincludes hydraulic fracture monitoring and real-timereservoir monitoring. Michael holds a BS degree inphysics, and an MS degree in geophysics, both fromImperial College of Science, Technology and Medicine,University of London. He also has a PhD degree inphysics from the University of Wales, Aberystwyth.

Stuart Wilson, GeoMarket Technical Engineer forSchlumberger Well Services in Moscow, is responsiblefor the marketing and technical development of coiledtubing business throughout Russia. He joined thecompany as a field engineer in Stavanger, after earninga BS degree in mechanical engineering from theUniversity of Hertfordshire, England, and an MSdegree in business and operations management fromthe Norwegian Institute of Technology, Trondheim.Stuart spent five years in the North Sea region in vari-ous positions in Norway and Denmark. From 2002 untiltaking his current post in 2005, he served as worldwideproduct champion for the CoilFLATE* coiled tubingthrough-tubing inflatable packer. Stuart is the authorof several papers on inflatable packers and coiledtubing offshore equipment and technology and wasa World Oil New Horizons award finalist in 2003.

An Introduction to Materials ScienceWenceslao González-Viñas and Héctor L. ManciniPrinceton University Press41 William StreetPrinceton, New Jersey 08540 USA2004. 180 pages. $60.00 ISBN 0-691-07097-0

This introduction to materials sciencedescribes the electrical, mechanicaland thermal properties of matter; theunique properties of dielectric andmagnetic materials; the phenomenonof superconductivity; polymers; andoptical and amorphous materials. Newmaterials, such as fullerenes, liquidcrystals and surface phenomena, arealso covered.

Contents:

• What is a Material?

• Crystalline Solids

• Imperfections

• Electrical Properties

• Mechanical and Thermal Properties

• Magnetic Materials and Dielectrics

• Superconductivity

• Optical Materials

• Noncrystalline Materials

• Polymeric Materials

• Surface Science

• New Materials

• Appendix, Bibliography, Index

I can understand that the book, asan entry-level text, needs to be concise,but some key concepts are lost in theinterest of brevity.

…[the book] is a useful addition tothe texts in the field. Its broad range oftopics and brevity of coverage are bothassets and, in some cases,liabilities…its contribution to a materials-science course or its abilityto motivate individual study is likely to be significant.

Cahill CL: Physics Today 58, no. 7

(July 2005): 66–67.

Coming in Oilfield Review

Integrated Cement Design.Complete and durable zonal isolationis the foremost goal of a primarycement job. This article presents anew engineering solution to helpensure primary cementing success.Rather than treating the cement jobas an isolated event, the newapproach considers the entire wellconstruction process in real time,allowing operators to proactivelydesign and drill wells for excellentprimary cementing and zonal isolation.

New Sonic Capabilities. Sonicmeasurements help assess wellborestability, determine reservoir quality,detect fractures, design stimulationtreatments and estimate permeabil-ity. A new sonic tool providesimproved characterization of sonicand mechanical properties in threedimensions around the boreholeand tens of feet into the formation.Case studies from Norway, the USA,Mexico and offshore Brazil demon-strate some of the advancedapplications of this latest sonic tool.

From Inner Earth to Outer Space.Conrad and Marcel Schlumbergerintroduced technologies in the 1930sdesigned to explore Earth’s innerspace. Some 75 years later, innovativeSchlumberger sensors are helping scientists investigate the fundamentalnature and origin of objects in outerspace. In this article, we discuss theNear Earth Asteroid Rendezvous(NEAR) mission to the asteroid Eros,along with other examples showinghow oilfield technologies are beingused in the quest for knowledge andunderstanding of outer space.

NEW BOOKSNEW BOOKS

Thrust Tectonics and Hydrocar-bon Systems, AAPG Memoir 82K. R. McClay (ed)American Association of Petroleum GeologistsP.O. Box 979Tulsa, Oklahoma 74101 USA 2004. 675 pages. $94.00 ($69.00 forAAPG members)ISBN 0-89181-363-2

This book summarizes recent advancesin the study of thrust faults and theirassociated hydrocarbon systems. The 33papers and case studies cover the influ-ence of thrust faulting in many majorpetroleum provinces.

Contents:

• Geodynamics of Thrust Systems

• Analog Modeling of Thrust Systems

• Fault-Related Folds in Thrust Systems

• Case Studies

I was immediately impressed with the quality of the graphics in thismemoir. The writers of individualpapers used very high-quality graphicsto convey the complexities of thrustfault systems.

I found most papers quite usefulfor catching up on current research aswell as obtaining a historical perspec-tive of research on the subject. Manypapers throughout the work are heavily referenced….

I believe this work will be quiteuseful to geologists that are currentlyprospecting in thrust-faulted areas,those that are conducting research in thrust fault tectonics, and studentsseeking a general reference onthe subject.

Moore WD: AAPG Bulletin 89, no. 5 (May 2005):

667–668.

High Noon for Natural Gas: The New Energy CrisisJulian DarleyChelsea Green Publishing CompanyP.O. Box 428White River Junction,Vermont 05001 USA2004. 266 pages. $18.00ISBN 1-931498-53-9

A critical analysis of government energypolicy, this book outlines the implica-tions of the world’s increased relianceon natural gas and explains why this dependence may cause seriousenvironmental, political andeconomic consequences.

Contents:

• Introduction

• The Gas Itself

• Moving Gas

• Demanding Gas

• Gas Ability

• Where on Earth Are We Now?

• Energy Security

• Where the Hell Are We Going?

• But What Else Can We Do?

• Appendix, Notes, Bibliography, Index

Darley, an environmentalresearcher in the UK, offers a fresh look at a fuel that is widelymisunderstood.

…this author’s thesis is that a massive worldwide conservation effortis the only viable future course of action.Given the world’s political jumble, he isnot hopeful.…Recommended.

Comer AJ: Choice 43, no. 1 (September 2005): 132.

83Winter 2005/2006Winter 2005/2006

84 Oilfield Review

Structured Fluids: Polymers,Colloids, SurfactantsThomas A. Witten (withPhilip A. Pincus)Oxford University Press198 Madison AvenueNew York, New York 10016 USA2004. 216 pages. $99.50 ISBN 0-19-852688-1

The study of liquids containingpolymers, colloids and surfactantparticles has evolved into a coherentdiscipline with predictive power.Keeping mathematics to a minimum,the book seeks the simplest explana-tions for the scaling properties of polymers, colloids and surfactants. Italso includes many figures, tables andproblem exercises.

Contents:

• Overview

• Fundamentals

• Polymer Molecules

• Polymer Solutions

• Colloids

• Interfaces

• Surfactants

• Appendixes, References, Index

…he focuses on the topics men-tioned in the title: polymers, colloids,and surfactants. He covers the subjectswell and provides an excellentoverview of each.

…[the book] is well constructedand a pleasure to read. Its text coversabout two-thirds of each page, withspace alongside reserved for figuresand notes. Several of the chapters havelengthy appendixes in which the authordiscusses certain topics in more depth.

I suspect Structured Fluids will bewidely used and will be a must for anystudent of soft condensed matterphysics. Even practicing condensedmatter physicists will gain a great dealof insight from it, and I predict it willbecome a fixture on many bookshelves.

Weitz D: Physics Today 58, no. 7 (July 2005): 65–66.

Fundamentals of Seismic Wave PropagationChris ChapmanCambridge University Press40 West 20th StreetNew York, New York 10011 USA 2004. 632 pages. $75.00ISBN 0-521-81538-X

This volume develops the theory of seismic wave propagation in acoustic,elastic and anisotropic media toallow seismic waves to be modeled incomplex, realistic three-dimensionalEarth models. Each chapter includesexercises and suggestions forfurther reading.

Contents:

• Introduction

• Basic Wave Propagation

• Transforms

• Review of Continuum Mechanicsand Elastic Waves

• Asymptotic Ray Theory

• Rays at an Interface

• Differential Systems for Stratified Media

• Inverse Transforms for Stratified Media

• Canonical Signals

• Generalizations of Ray Theory

• Appendixes, Index

…mathematicians and mechanicians will certainly appreciatethe author’s elegant presentation of the field.

Romanowicz B: Physics Today 58, no. 8

(August 2005): 54–55.

Fundamentals of Seismic WavePropagation is a veritable treasuretrove of seismic high-frequency for-ward modeling techniques. It will be adefinitive reference work for a longtime to come.

Treitel S: The Leading Edge 24, no. 3

(March 2005): 320.

Powerdown: Options andActions for a Post-Carbon WorldRichard HeinbergNew Society PublishersP.O. Box 189Gabriola IslandBritish Columbia V0R 1X0 Canada2004. 209 pages. $16.00ISBN 0-86571-510-6

Focusing on the looming global peak inoil production, the book analyzes theoptions available to a world facingresource depletion, biosphere collapseand financial insolvency. The authorpresents an argument for reducingper-capita resource usage in wealthy countries, developing alternative energysources and distributing resourcesmore equitably.

Contents:

• The End of Cheap Energy

• Last One Standing: The Way of Warand Competition

• Powerdown: The Path of Self-Limitation, Cooperation, and Sharing

• Waiting for the Magic Elixir: FalseHopes, Wishful Thinking, and Denial

• Building Lifeboats: The Path ofCommunity Solidarity and Preservation

• Our Choice

• Notes, Index

…few readers would disagree witha nonpolluted, cooperative and peace-ful world. But to move toward thesenoble goals, we do not have to startfrom Heinberg’s assumptions andhasty assessments of the end of“cheap” oil…and the “collapse” of civilization.

Sourkhabi R: Geotimes 50, no. 3 (March 2005): 49.

Basin Analysis: Principles andApplications, 2nd editionPhillip A. Allen and John R. AllenBlackwell Publishing350 Main StreetMalden, Massachusetts 02148 USA2005. 549 pages. $89.95ISBN 0-632-05207-4

This book provides an overview of theessential processes of the creation andevolution of sedimentary basins, withparticular emphasis on the implicationsfor hydrocarbon resources. First pub-lished in 1990, this new edition takesinto account the new data, technologyand concepts developed in the past15 years.

Contents:

• The Foundations of SedimentaryBasins: Basins in Their PlateTectonic Environment; The PhysicalState of the Lithosphere

• The Mechanics of Sedimentary BasinFormation: Basins Due to Litho-spheric Stretching; Basins Due to Flexure; Effects of MantleDynamics; Basins Associated withStrike-Slip Deformation

• The Sedimentary Basin-Fill: TheSediment Routing System; BasinStratigraphy; Subsidence and Thermal History

• Application to Petroleum PlayAssessment: The Petroleum Play

• References, Index

The book is substantially revisedand updated from the 1990 first editionwith a new chapter on mantle dynam-ics. The discussions of facies modelsand risk assessment are scaled back,but the text is 15 percent longer. Manyof the graphics have been improved,30 percent of the references postdate1990, and practical exercises areslated to appear on a free Web site.

An excellent summary of basin analysis and significantlyenhanced relative to the first edition. …Highly recommended.

Simonson BM: Choice 43, no. 2

(October 2005): 320.

85Winter 2005/2006

A Guided Tour of MathematicalMethods for the PhysicalSciences, 2nd editionRRoel SneiderCambridge University Press40 West 20th StreetNNew York, New York 10011 USA2004. 519 pages. $60.00 hardcover;$45.00 softcoverISBN 0-521-83492-9

This second edition of an earlier bookprovides a comprehensive overview ofthe mathematical methods essential forwwork in the physical sciences and alsoincludes new chapters on dimensionalanalysis, variational calculus and theasymptotic evaluation of integrals. Incontrast to many traditional textbooksin the physical sciences, this onepresents its 26 chapters in the formof problems.

Contents:

• Introduction

• Dimensional Analysis

• Power Series

• Spherical and Cylindrical Coordinates

• Gradient

• Divergence of a Vector Field

• Curl of a Vector Field

• Theorem of Gauss

• Theorem of Stokes

• Laplacian

• Conservation Laws

• Scale Analysis

• Linear Algebra

• Dirac Delta Function

• Fourier Analysis

• Analytic Functions

• Complex Integration

• Green’s Functions: Principles

• Green’s Functions: Examples

• Normal Modes

• Potential Theory

• Cartesian Tensors

• Perturbation Theory

• Asymptotic Evaluation of Integrals

• Variational Calculus

• Epilogue, on Power and Knowledge

• References, Index

I commend this book to thoseinterested in physics (and geophysics)theory.…Students…will find enjoyablediscussions of the concepts of mathe-matical methods without getting lost inmazes of equations. Teachers will beinterested in the easy way conceptsare developed.

It’s easy to jump somewhere in themiddle of this book, enjoyably browsea bit, and then jump elsewhere.…I par-ticularly enjoyed some of the examplesthat draw erroneous conclusions wherethe author then points out where thereasoning went astray.

Sheriff RE: The Leading Edge 24, no. 5

(May 2005): 548–549.

Biodiesel: Growing a New Energy EconomyGreg PahlChelsea Green Publishing CompanyP.O. Box 428White River Junction, Vermont 05001 USA2005. 282 pages. $18.00ISBN 1-931498-65-2

Journalist Greg Pahl provides a compre-hensive evaluation of the alternativefuel, biodiesel—a crop-derived liquidfuel. His book explores the history andtechnology of biodiesel, its current usearound the world and its potential inthe United States and other parts of the world.

Contents:

• Biodiesel Basics: Rudolph Diesel;Vegetable Oil Revival; Biodiesel101; Biodiesel’s Many Uses

• Biodiesel Around the World: Europe,the Global Leader; Other EuropeanCountries; Non-European Countries

• Biodiesel in the United States: A Brief History; The Main Players; Biodiesel Politics;Recent Developments

• Biodiesel in the Future: Looking Ahead

• Organizations and Online Resources

• Notes, Glossary, Bibliography, Index

The book includes a list of sources, extensive notes, and a glossary. …Highly recommended.

Comer JC: Choice 42, no. 11/12

(July/August 2005): 2019–2020.

Jonah Field: Case Study of aTight-Gas Fluvial ReservoirJJohn W. Robinson and Keith W. Shanley (eds)AAmerican Association of Petroleum GeologistsP.O. Box 979Tulsa, Oklahoma 74101 USA 2004. 283 pages (softcover). $79.00($59.00 for AAPG members)ISBN 0-89181-059-5

Containing previously unpublished andproprietary material, this volume inte-grates information about the geology,geophysics, reservoir engineering,drilling and completion of the Jonahfield, an important natural gas discov-ery in Wyoming, USA. A CD-Rom ofappendices is also included.

Contents:

• Introduction: Jonah Field—CaseStudy of a Tight-Gas Fluvial Reservoir

• Jonah Field: T28-29N, R107-109W,Sublette County, Wyoming

• Discovery of Jonah Field, SubletteCounty, Wyoming

• Regional Stratigraphic Setting of theMaastrichtian Rocks in the CentralRocky Mountain Region

• Geology of Jonah Field, SubletteCounty, Wyoming

• Structural Geology, Seismic Imaging,and Genesis of the Giant Jonah GasField, Wyoming, U.S.A.

• Burial-History Modeling of the JonahField Area: An Unusual and PossiblyUnique Gas Accumulation in theGreen River Basin, Wyoming

• The Origin of Jonah Field, NorthernGreen River Basin, Wyoming

• Basin-Centered Gas Systems and the Jonah Field

• Fluvial Reservoir Description for aGiant, Low-Permeability Gas Field:Jonah Field, Green River Basin,Wyoming, U.S.A.

• Petrology and Petrophysics of theLance Formation (Upper Cretaceous),American Hunter, Old Road Unit 1,Sublette County, Wyoming

• Petrophysics of the Lance SandstoneReservoirs in Jonah Field, SubletteCounty, Wyoming

• Extending the Southwest Limits ofJonah Field: Using High-Quality, 3-D Seismic Data to Improve theStructural Definition

• The Effect of Stimulation and Completion Methodologies on Production in Jonah Field

• Jonah Field Completions: AnIntegrated Approach to StimulationOptimization with an Enhanced Economic Value

• From Prospect to Giant Gas Field:History of the Environmental Analyses of Jonah Field

Here, wonderfully, are 16 paperson Jonah field. Future United Statesgas resources may mainly come fromtight, low-permeability sandstone deepin basins. Many explorers will need thisvaluable book, which is rich in details,to find them.

Picard MD: AAPG Bulletin 89, no. 6 (June 2005):

836–837.

ARTICLES

Acting in Time to Make the Mostof Hydrocarbon ResourcesVol. 17, no. 4 (Winter 2005/2006): 4–13.

Changing the Way We DrillAldred W, Belaskie J, Isangulov R, Crockett B, Edmondson B, Florence F and Srinivasan S.Vol. 17, no. 1 (Spring 2005): 42–49.

Coiled Tubing: InnovativeRigless InterventionsBoumali A, Brady ME, Ferdiansyah E,Kumar S, van Gisbergen S, Kavanagh T,Ortiz AZ, Ortiz RA, Pandey A, Pipchuk Dand Wilson S.Vol. 17, no. 4 (Winter 2005/2006): 28–41.

Confronting the CarbonateConundrumAhr WM, Allen D, Boyd A, Bachman HN,Smithson T, Clerke EA, Gzara KBM, Hassall JK, Murty CRK, Zubari H andRamamoorthy R.Vol. 17, no. 1 (Spring 2005): 18–29.

Hydrogen: A Future EnergyCarrier?Bennaceur K, Clark B, Orr FM Jr, Ramakrishnan TS, Roulet C and Stout E.Vol. 17, no. 1 (Spring 2005): 30–41.

Improvements in HorizontalGravel PackingEdment B, Elliott F, Gilchrist J, Powers B,Jansen R, McPike T, Onwusiri H, Parlar M,Twynam A and van Kranenburg A.Vol. 17, no. 1 (Spring 2005): 50–60.

Integrated Wellbore CleanoutSystems: Improving Efficiencyand Reducing RiskAzhar A, Blount CG, Hill S, Pokhriyal J,Weng X, Loveland MJ, Mokhtar S,Pedota J, Rødsjø M, Rolovic R and Zhou W.Vol. 17, no. 2 (Summer 2005): 4–13.

New Dimensions in LandSeismic TechnologyAit-Messaoud M, Boulegroun M-Z, Gribi A, Kasmi R, Touami M, Anderson B,Van Baaren P, El-Emam A, Rached G,Laake A, Pickering S, Moldoveanu N and Özbek A.Vol. 17, no. 3 (Autumn 2005): 42–53.

New Fibers for HydraulicFracturingBivins CH, Boney C, Fredd C, Lassek J,Sullivan P, Engels J, Fielder EO, Gorham T,Judd T, Sanchez Mogollon AE, Tabor L,Valenzuela Muñoz A and Willberg D.Vol. 17, no. 2 (Summer 2005): 34–43.

No More Waiting: FormationEvaluation While DrillingAdolph B, Stoller C, Archer M, Codazzi D,el-Halawani T, Perciot P, Weller G, Evans M,Grant J, Griffiths R, Hartman D, Sirkin G,Ichikawa M, Scott G, Tribe I and White D.Vol. 17, no. 3 (Autumn 2005): 4–21.

The Pressures of Drillingand ProductionBarriol Y, Glaser KS, Pop J, Bartman B,Corbiell R, Eriksen KO, Laastad H, Laidlaw J, Manin Y, Morrison K, Sayers CM, Terrazas Romero M andVolokitin Y.Vol. 17, no. 3 (Autumn 2005): 22–41.

A Sound Approach to DrillingAlford J, Goobie RB, Sayers CM, Tollefsen E, Cooke J, Hawthorn A, Rasmus JC and Thomas R. Vol. 17, no. 4 (Winter 2005/2006): 68–78.

The Source for HydraulicFracture CharacterizationBennett L, Le Calvez J, Sarver DR, Tanner K, Birk WS, Waters G, Drew J,Michaud G, Primiero P, Eisner L, Jones R,Leslie D, Williams MJ, Govenlock J,Klem RC and Tezuka K.Vol. 17, no. 4 (Winter 2005/2006): 42–57.

Spectroscopy: The Key to Rapid,Reliable Petrophysical AnswersBarson D, Christensen R, Decoster E,Grau J, Herron M, Herron S, Guru UK,Jordán M, Maher TM, Rylander E andWhite J.Vol. 17, no. 2 (Summer 2005): 14–33.

Steering Toward Enhanced ProductionChou L, Li Q, Darquin A, Denichou J-M,Griffiths R, Hart N, McInally A, Templeton G, Omeragic D, Tribe I, Watson K and Wiig M.Vol. 17, no. 3 (Autumn 2005): 54–63.

Subsea Development from Poreto ProcessAmin A, Riding M, Shepler R, Smedstad E and Ratulowski J.Vol. 17, no. 1 (Spring 2005): 4–17.

Testing Oilfield Technologiesfor Wellsite OperationsArena M, Dyer S, Bernard L, Harrison A,Luckett W, Rebler T, Srinivasan S, Borland B, Watts R, Lesso B and Warren TM.Vol. 17, no. 4 (Winter 2005/2006): 58–67.

Understanding Gas-CondensateReservoirsFan L, Harris BW, Jamaluddin A, Kamath J, Mott R, Pope GA, Shandrygin A and Whitson CH.Vol. 17, no. 4 (Winter 2005/2006): 14–27.

Using Casing to DrillDirectional WellsFontenot KR, Lesso B, Strickler RD andWarren TM.Vol. 17, no. 2 (Summer 2005): 44–61.

NEW BOOKS

Basin Analysis: Principles andApplications, 2nd editionAllen PA and Allen JR.Vol. 17, no. 4 (Winter 2005/2006): 84.

Beyond Oil: The View from Hubbert’s PeakDeffeyes KS.Vol. 17, no. 3 (Autumn 2005): 68.

The Big One: The EarthquakeThat Rocked Early America and Helped Create a SciencePage J and Officer C.Vol. 17, no. 2 (Summer 2005): 66.

Biodiesel: Growing a NewEnergy EconomyPahl G.Vol. 17, no. 4 (Winter 2005/2006): 85.

A Concise History of Solar andStellar PhysicsTassoul J-L and Tassoul M.Vol. 17, no. 1 (Spring 2005): 64.

Energy, Waste and the Environment: A GeochemicalPerspective, Geological SocietySpecial Publication 236Gieré R and Stille P (eds).Vol. 17, no. 3 (Autumn 2005): 68.

Frozen Earth: The Once andFuture Story of Ice AgesMacdougall D.Vol. 17, no. 3 (Autumn 2005): 68.

Fundamentals of Seismic WavePropagationChapman C.Vol. 17, no. 4 (Winter 2005/2006): 84.

A Guided Tour of MathematicalMethods for the Physical Sciences, 2nd edition Sneider R.Vol. 17, no. 4 (Winter 2005/2006): 85.

High Noon for Natural Gas: The New Energy CrisisDarley J.Vol. 17, no. 4 (Winter 2005/2006): 83.

An Introduction to Materials ScienceGonzáles-Viñas W and Mancini HL.Vol. 17, no. 4 (Winter 2005/2006): 83.

Jonah Field: Case Study of aTight-Gas Fluvial ReservoirRobinson JW and Shanley KW (eds).Vol. 17, no. 4 (Winter 2005/2006): 85.

Out of Gas: The End of the Age of Oil Goodstein D.Vol. 17, no. 1 (Spring 2005): 64.

Out of This World: Colliding Universes, Branes, Strings, and Other Wild Ideas of Modern Physics Webb S.Vol. 17, no. 1 (Spring 2005): 64.

Pandora’s Breeches: Women, Science and Power in the EnlightenmentFara P.Vol. 17, no. 2 (Summer 2005): 66.

Powerdown: Options and Actionsfor a Post-Carbon WorldHeinberg R.Vol. 17, no. 4 (Winter 2005/2006): 84.

Structured Fluids: Polymers, Colloids, SurfactantsWitten TA and Pincus PA.Vol. 17, no. 4 (Winter 2005/2006): 84.

Thrust Tectonics and Hydrocar-bon Systems, AAPG Memoir 82McClay KR (ed).Vol. 17, no. 4 (Winter 2005/2006): 83.

Understanding RenewableEnergy SystemsQuaschning V.Vol. 17, no. 2 (Summer 2005): 66.

86 Oilfield Review

Oilfield Review Annual Index—Volume 17