SCHLUMBERGER OILFIELD REVIEW

WIN

TER 1998VOLUM

E 10 NUM

BER 4

Winter 1998

Integrated Drilling Software

Multilateral Well Technology

Formation Evaluation While Drilling

Annular Pressure While Drilling

Oilfield Review

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A decade ago, I introduced Schlumberger Oilfield Reviewas a multidisciplinary, quarterly journal dedicated to communicating the latest advances in E&P technology.Today, Oilfield Review continues to function as a techni-cal forum, focusing on timely, relevant topics of interest to oilfield professionals—both specialists and generalists.With 2400 pages published to date, this issue completesthe journal’s tenth year. Total circulation worldwide hasreached 23,000 per issue. In addition to Schlumberger’stechnical community, more than 11,000 oil and gas com-pany technical experts and executives receive the publica-tion, along with several hundred consultants and univer-sity professors, governmental agencies and libraries.

Like Schlumberger itself, the flavor of Oilfield Reviewhas been and remains international and multicultural,with direct involvement and participation by our oilfieldclients. To date, 345 client experts, representing 121 oiland gas companies and their affiliates, have contributedto Oilfield Review articles. Underscoring a commitment to present global viewpoints and technological successes,Schlumberger authorship has been almost evenly dividedbetween the western hemisphere (398) and the easternhemisphere (355).

This milestone comes at a time when the oil and gasindustry has, perhaps, the greatest need to access emerg-ing technology. During periods of depressed oil prices,global economic uncertainty, industry consolidation andE&P spending cutbacks, cost-effective technologies pro-vide a clear path to improve oilfield efficiency. Here atSchlumberger, we maintain an unwaivering commitmentto technology development, supported by R&D programsthat generate the greatest value for operators.

The technology of the 1990s has had a profound impacton how reservoirs are discovered, developed and pro-duced. Individual technical innovations have changed theface of the industry. Time-lapse, 4D seismic acquisitioncan characterize changes in the reservoir over time, providing new opportunities for enhanced recovery effi-ciency. Great strides have been made in processing andinterpreting data that feed advanced reservoir models andsimulators. Data management, combined with the latest

information technology tools, has formed a foundation for knowledge management. Directional drilling, logging-while-drilling and measurements-while-drilling techniquesfor extended-reach, horizontal and multilateral wells facil-itate reservoir access and improve drainage. New-genera-tion rigs drastically reduce drilling time and permit cost-effective operations in frontier areas, such as deep water.

New chemistry, additives and total fluids managementhave improved the efficiency of drilling muds, cements,and completion and stimulation fluids. New perforatingtechniques reduce formation damage while expandingwellbore flow area. Compact, reliable platforms of inte-grated sensors for openhole and cased-hole logging yieldbetter answer products and represent a quantum advancein imaging and multiphase fluid-flow determination.

Permanent monitoring systems and intelligent comple-tions promise to expand real-time decision-making to helpenhance productivity and optimize reservoir performance,while limiting the need for well interventions. When reme-dial actions are required, coiled tubing permits cost-effec-tive reentry drilling and a host of workover options basedon advanced downhole tool technology.

Improvements have also been made in the safety of oilfield operations and in protection of the environmentthrough developments in rig automation, environmentallyfriendly products, improved disposal methods anddecreased reliance on radioactive sources.

Capitalizing on synergies across disciplines, integratedservices—used only in isolated cases ten years ago—arenow commonplace. Technology application has been aidedby teamwork between operators and service companiesthat is best illustrated by business relationships such asalliances and partnerships.

Each of these topics, plus numerous others, has beendiscussed in Oilfield Review during the past decade. Welook forward with enthusiasm to the next ten years and the innovative oilfield technologies that await us.

D. Euan Baird Chairman, President and Chief Executive OfficerSchlumberger Limited

Ten Years of Technical Communication

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

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

© 1998 Schlumberger. All rights reserved. No part of this publicationmay be reproduced, stored in a retrieval system or transmitted in anyform or by any means, electronic, mechanical, photocopying, recordingor otherwise without the prior written permission of the publisher.

Address editorial correspondence to:

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Annual subscriptions, including postage, are 160.00 US dollars, subject to exchange rate fluctuations.

Executive EditorDenny O’BrienSenior Production EditorMark E. TeelSenior EditorLisa StewartEditorsRussel C. HertzogGretchen M. GillisDavid E. Bergt

Contributing EditorsRana RottenbergDev George IllustrationTom McNeffMike MessingerGeorge StewartDesignHerring DesignPrintingWetmore Printing Company, USA

Advisory PanelTerry AdamsAzerbaijan International Operating Co., Baku

Syed A. AliChevron Production Co.New Orleans, Louisiana, USA

Antongiulio AlborghettiAgip S.p.AMilan, Italy

Svend Aage AndersenMaersk Oil Qatar ASDoha, State of Qatar

Michael FetkovichPhillips Petroleum Co.Bartlesville, Oklahoma, USA

George KingAmocoTulsa, Oklahoma

David Patrick MurphyShell E&P CompanyHouston, Texas, USA

Richard WoodhouseIndependent consultantSurrey, England

Winter 1998Volume 10Number 4

Schlumberger

40 Using Downhole Annular Pressure Measurements to Improve Drilling Performance

A simple concept like measuring pressure downhole can profoundly impact a broadrange of applications. Combined with other well parameters, these measurements are used to monitor borehole fluid conditions, which leads to early detection ofproblems such as stuck tools, annulus packoff, lost circulation and fluid influx.Monitoring annular pressure at the drilling bit also provides accurate formationstress measurements, making the process of drilling ahead safer and more exact.

14 Key Issues in Multilateral Technology

Wellbores with mutiple forked branches and laterals reduce overall costs,increase production and improve reservoir drainage. These types of wells can increase recoverable reserves, make reservoirs easier to manage, and are growing in popularity. However, constructing complicated well profiles ischallenging and risky. The latest applications and system developments areconvincing operators that multilateral advantages outweigh the disadvantages.

2 Planning and Drilling Wells in the Next Millenium

Because of recent developments in integrated computing, the initiation andimplemention of well construction processes is moving from a step-wisemethod to a more interactive approach By sharing a database, teams of multidisciplinary professionals can increase efficiency and reduce cycletimes. During operational phases, specialized software modules and systemsreduce cost and risk by allowing plans to be easily amended on the fly.

29 Pushing the Limits of Formation Evaluation While Drilling

Logging measurements taken while drilling reveal previously elusive formationcharacteristics. Real-time resistivity and density readings made at a variety ofinvestigation depths and azimuths are the cornerstons of this new formationevaluation capability. These measurements supply interpreters with data toassess reservoir quality and structure in spite of filtrate invasion, formation dip,resistivity anisotropy and thin beds, and from smaller hole sizes than ever before.

56 Contributors

58 Coming in Oilfield Review and 1998 Index

Oilfield Review Services and MORA Order Form (inside back cover)

Oilfield Review

1

Planning and Drilling Wells in the Next Millennium

For help in preparation of this article, thanks to MarkBurgoyne, Bobbie Ireland, Joe Jacquot, Mark Lochmannand Victor Ward, GeoQuest, Houston, Texas; and YvesMorel, Dowell, Clamart, France.CemCADE, DESIGN-EXECUTE-EVALUATE, Drilling Office,DrillSAFE, Finder, GeoFrame, GeoViz, PowerPlan,PowerPulse, QLA, SideKick, TDAS (Tubular Design andAnalysis System), WellTRAK and WEST (WellboreSimulated Temperatures) are marks of Schlumberger. UNIX is a mark of X/Open Company Limited. Windows NT,Windows 95 and Windows 98 are marks of MicrosoftCorporation.

Computing technology is changing the way engineers and geoscientists work

together to plan and drill wells interactively. Project teams can now use specially

designed software to capture best practices and integrate all available data.

The results are optimized drilling and improvements in cost control, safety and efficiency.

Until recently, exploration and production (E&P)projects that led to drilling a well were viewedas a sequential series of separate tasks ratherthan as a continuum, or a smooth workflow, andseldom involved drilling engineers. Geologistsgenerated subsurface maps using formationtops picked from well logs. Geophysicistsmapped seismic data to confirm, refine orexpand the geological interpretation. Once adrilling target was selected by the geologist andgeophysicist, the location was provided to thedrilling engineer to begin planning and designingthe well. In this manner, the project was handedoff from one person to the next as tasks werecompleted without necessarily sharing the rele-vant data that supported critical interpretationsand decisions. In fact, databases were generallydiscipline-specific, incompatible and unable toshare or exchange data readily.

Procedures for interpreting well logs or seis-mic data, generating maps, performing log andengineering calculations, and planning well con-struction varied from one professional to thenext. The lack of interaction and continuityamong project participants often resulted ininterpretations and methods that were not chal-lenged or tested, and solutions that sometimesinvolved estimates and compromises rather thanrigorous technical analysis. Industry newcomersfaced a steep learning curve until they achievedsufficient training or experience to decide forthemselves how to accomplish critical, ofteninterpretive tasks correctly.

In those days, iteration and multiple sce-nario planning were not performed unless a par-ticularly costly or high-profile project wasinvolved. The lack of routine iteration was in

François ClouzeauGilles MichelDiane NeffGraham RitchieHouston, Texas, USA

Randy HansenDominic McCannSugar Land, Texas

Laurent ProuvostClamart, France

3Winter 1998

4

part a consequence of the difficulty and timenecessary to revise and reproduce hand-draftedmaps and well plans. Problems may be com-pounded in the stepwise approach to projects ifthe objectives of geologists and geophysicistsdiffer from those of drilling engineers. This lackof teamwork ultimately means that reservesmay be missed because of poor collectiveunderstanding of assets and effective means ofexploiting them.

Multidisciplinary asset teams are now work-ing together more effectively to reduce cost, riskand delay in all aspects of the workflow from thebeginning of exploration projects to the end ofthe productive life of a field. This new, optimizedprocess stems from using integrated softwareand a shared database. This change parallels atrend in the industry toward increased account-ability of asset team members to manage andimprove asset value.

The increase in teamwork comes at a criticaltime. Cost is more of an issue than ever before.New discoveries are typically smaller and moresubtle. Some of the most promising environ-ments for exploration and production are harsher(deep-water and high-pressure, high-tempera-ture environments, for example). As existing oilfields mature, recovering the remaining reservesis increasingly difficult. Operators must leverageall available intellectual capital and data,whether historical or real-time, to compete withother operators and to compensate for depressedcrude oil and natural gas prices.1

Efficiency, cost control and risk reduction inall phases of the exploration and productionworkflow, but particularly those that optimize thedrilling process, have the potential to temperE&P spending. In this article, we focus on thedrilling workflow, that is, the portion of the E&Pcycle from identification of a drilling targetthrough well construction. In the drilling work-flow, technical integrity, or the use of skills in acore competence that ensures a high level of per-formance and adherence to technical standards,is achieved with the help of software applica-tions whose algorithms reflect the best industrypractices. We begin by examining a traditionaldrilling workflow and then describe how the pro-cess has been improved by using integrated soft-ware to achieve consistently sound results.

Traditional Drilling WorkflowAs the traditional drilling workflow was accom-plished through a series of disconnected steps,project participants did not benefit from sharingof data, interpretations and experiences (nextpage, top). After geologists and geophysicistsselected a target, engineers assessed the feasi-bility of drilling to it. If the target were unac-ceptable from a drilling viewpoint, time-consuming iterations to settle on a mutually sat-isfactory target ensued.

Once a satisfactory target had been identi-fied, engineers calculated pore pressures andfracture gradients to design the casing program.These calculations and designs could varywidely depending on the expertise of the engi-neer and company policies and procedures.Typically, the next step would be for engineers orservice companies to design mud and cementprograms on the basis of the operating com-pany’s requirements. The input data for thesedesigns would be given by telephone or on paperrather than electronically. Again, depending onthe companies and engineers involved, as wellas the drilling environment, engineering prac-tices varied considerably. Operations proceededonce permits were obtained and other logisticalarrangements were made.

During drilling operations, real-time datamight have consisted of a daily drilling report andmud log transmitted by fax or telephone to theoperator’s drilling department, data not necessar-ily disseminated to the project geologist, geo-physicist, petrophysicist or reservoir engineer. Ifunanticipated drilling events occurred, the pro-ject participants would share information andwork together to resolve problems, but real-timechanges involving the entire team were oftenimpractical given the time constraints and com-munication tools available. More recently, multi-disciplinary teamwork and new software toolshave demonstrated the benefits of an iterativemethod, real-time data sharing and consultationamong project team members.

Ideal Drilling WorkflowAn optimized workflow allows team membersto collaborate fully without consuming addi-tional time (next page, bottom). The success ofintegrated geological and geophysical (G&G)software in streamlining exploration hasinstilled a desire for a complementary suite ofintegrated applications to improve the drillingworkflow. Thus, the ideal process describednext assumes the use of such tools and a com-mon, shared database.

Geologists and geophysicists select adrilling target, update their interpretations andvisualize the proposed well trajectory with G&Ginterpretation tools. Engineers select a surfaceor kickoff location using geological data andemploy drilling engineering tools to design theoptimal well path to satisfy drilling constraints.Because these processes occur simultaneouslyand data and interpretations are shared amongthe team members, iterations between geolo-gists, geophysicists and engineers in selectingtarget and surface locations are fewer andfaster than before.

Once the surface location and trajectory havebeen decided, the well prognosis for the litho-logic column, pore pressure and fracture pressureare determined. This might also require iterationsof the surface location and trajectory to avoiddrilling hazards such as shallow gas or overpres-sured zones. Next, the engineer designs the cas-ing program on the basis of geologicalinterpretations and offset well information.Service companies can then assist the engineerwith the appropriate drilling mud program,cementing program and other well constructionservices. At the end of the planning phase, theoperator applies for permits and makes logisticalarrangements to commence drilling.

It is during drilling operations that an idealworkflow scenario allows the operator to reapthe considerable benefits of data sharing and col-laboration among the team members. Real-timeupdates while drilling help optimize operations,avoid hazards and anticipate problems as theentire team works together sharing information.New real-time data are generated and input intothe database in the appropriate format to updateengineering calculations, so engineers need notreenter data into different applications at the riskof data entry errors. As experience grows andhistorical data accumulate in the database, theneeds and abilities of geologists, geophysicistsand drilling engineers will be understood betterfrom the broader perspective of a shareddatabase. Operations can proceed more effi-ciently and at lower cost and risk.

1. Close DA and Stelly OV: “New Information SystemsPromise the Benefits of the Information Age to theDrilling Industry,” paper IADC/SPE 39331, presented atthe IADC/SPE Drilling Conference, Dallas, Texas, USA,March 3-6, 1998.

Oilfield Review

5

Engineeringdatabase

Geological andgeophysicaldatabase

Optimize welldesign

Engineering

Discuss well plan; reiterateprocess until finished

All Groups

Gather information forpost-drilling review

Engineering

Generate welltrajectory

Geology and Geophysics Geology and Geophysics

Finalize mud andcasing design

Engineering

Reports

Compile and updatereports weekly

Engineering

Finalize economicsand Authorization for

Expenditure (AFE)

Engineering

Preliminary Well Planning Detailed Well Design Drilling Operations Post-drilling

Load welltrajectory

> Traditional drilling workflow. A linear workflow requires more people and incurs higher cost because of inefficiency in the process. Iteration is time-consuming and costly, particularly at the stage when drilling target selection occurs. The lack of a shared digital database inhibits integration of dataand interpretations among team members. Integration, in this situation, depends on human interaction as well as duplication of data entry efforts inincompatible databases.

Retrieve latestversion

Finalize economicsand Authorization for

Expenditure (AFE)

Engineering

Preliminary Well Planning Detailed Well Design Drilling Operations Post-drilling

Project database

Update currentwell trajectory

Compile and updatereports

Engineering

Optimize welldesign

Engineering

Finalize mud andcasing design

Engineering

Drillingparameters

Drillinghistory

Hazards

3D reservoirmodel

Productionhistory

Structure

Stratigraphy

Prospectivetargets

Productionhistory

Reservoirproperty

distributions

Generate welltrajectory

Geology and Geophysics Geology and Geophysics

> Ideal drilling workflow. With team members using the same database and model of the earth, the drilling process becomes less linear. At each point in theprocess, validation occurs earlier, saving time and money. Inferior solutions are weeded out early in the process. The use of real-time data allows optimiza-tion of operations during drilling. After completion of drilling operations, results are readily available in the database to improve subsequent operations.

Winter 1998

Many exploration and production companieshave carefully examined their unique drillingworkflow to maximize the productivity of eachmultidisciplinary team and the value of eachasset. Schlumberger has worked with a numberof operators to identify the process best suited tothat company and the changes necessary toachieve it. Several common priorities emergedfrom these studies:• The ability to move targets and surveys easily

between G&G and drilling software to finalizethe drilling target early

• Standardized survey, well naming and coordi-nate systems

• Three-dimensional workspace and multi-useraccess with conferencing flexibility so that allteam members, be they at the wellsite, in theoperator’s office or in a service company office,can access data and the latest interpretations

• A link between G&G models and well-planningapplications that simplifies and speeds changesto drilling plans in real time, optimizing the wellpath and reducing the need to sidetrack

• The use of real-time data in application format,so that data entered in one application areautomatically available in all other applications

• An automated process for capturing actualversus planned results in operational andfinancial parameters

• Access to databases using query tools to pro-mote effective use of data and formal compila-tion and archiving

• The ability to move data easily between multi-user projects and stand-alone projects.

Technical HurdlesIntegrated software to streamline the drillingworkflow is a key to improving the process.Among the technical hurdles that must beaddressed, perhaps most pressing is the need fordigital data and a database architecture that pro-motes sharing of data and interpretations for theduration of a project. The amount and variety ofdata used to plan and drill wells are mind-bog-gling: seismic data, well logs, mud logs, coresamples and their descriptions, drilling fluidreports, directional surveys, drilling histories andproduction histories are but a few examples.

A clear understanding of both the existingand ideal workflows is essential, requiring a timecommitment up front to assess possible scenar-ios and solutions, such as what software to use,and the roles and responsibilities of each teammember. Willingness by team members to adaptand improve can ease the transition from the tra-ditional method to an improved process usingnew software. Many professionals are reluctantto abandon products with which they are familiar,even in favor of those that are better integrated.This is related to another cultural obstacle, a fearof many professionals—being replaced by com-puters. The reality is that as reserves becomemore scarce and difficult to exploit and wellsbecome more complex (multilateral andextended-reach wells, for example), multiplehypotheses or scenarios must be evaluated.Asset managers need to get more from existingresources. One solution is to provide better soft-ware tools that increase the efficiency of eachperson involved.

Integrated Drilling SoftwareAll software programs, even those performingcommon engineering calculations, must be vali-dated: the underlying algorithms must reflectappropriate, correct approaches to a given task.A management system in which the workflow,software and underlying policies and proce-dures are sound ensures both technical integrityand appropriate management of informationused in the system.

Several companies have developed individualsoftware tools to perform specific tasks in thedrilling workflow. Schlumberger also developed anumber of applications to assist with well plan-ning and design, cementing and other tasks. Asintegrated project management became a keyconcern, the need to use all the applications andavailable data together led GeoQuest to inte-grate its applications, which are collectivelycalled the Drilling Office system (next page).

More than merely performing specific tasksand integrating them seamlessly, the DrillingOffice system had to meet the Schlumbergerstandard of technical integrity, meaning that ithad to meet technical standards of performance,reliability and robustness for a given project: theworkflow, the applications used in the workflow,and the underlying methods and calculationsreflect appropriate procedures and technology.Each application uses validated algorithms foreach task, and within each task a selected pro-cess or flow reflects appropriate technical proce-dures for performing that task.

The Drilling Office suite currently includes:the PowerPlan modules for well trajectory plan-ning and design, torque and drag, anticollisionanalysis, bottomhole assembly (BHA) design andhydraulics analysis; the CemCADE tool forcement design and evaluation; the QLA well loganalysis software; the MudTRAK application fordrilling fluids management; the SideKick gas kickand underbalanced drilling simulator; the TDASTubular Design and Analysis System casingdesign system; and the WEST WellboreSimulated Temperatures program. Like allGeoQuest products, the Drilling Office system isYear 2000-ready. Validated by both Schlumbergerand the industry, these applications reflect bestpractices. The commercial software has beenused extensively within Schlumberger. For exam-ple, Dowell engineers have used the CemCADEprogram for over ten years to design cement jobsand Anadrill engineers have planned hundreds ofdirectional wells using PowerPlan modules.

6 Oilfield Review

Asset managers need to get more fromexisting resources. One solution is to

provide better software tools that increasethe efficiency of each person involved.

New applications in development include theWellTRAK system for well tracking and report-ing, a unique drilling data management system.The WellTRAK program is used at the wellsite tocapture drilling data and knowledge. In addition,it allows actual drilling activities to be trackedagainst the original plan so that the project teamcan readily identify suboptimal conditions andunplanned events and their costs. A linkbetween the WellTRAK program and the Findercorporate database will provide data manage-ment tools for well construction data as well asG&G information. Enhancements are under wayto allow engineering calculations to be updatedand calibrated using operations data whiledrilling. Reporting features that ensure compli-ance with quality control procedures are alsobeing developed for the software.

These modules can be used as relatively inex-pensive stand-alone applications or as part of afully integrated system that is designed to allowthird-party applications to be linked. The soft-ware runs on a personal computer (PC) using

Windows NT 4.0 or Windows 98 or 95 (with aminimum of 64 MB of RAM) and a recommendedprocessing speed of 166 MHz or greater.

In any software package, user friendliness iskey to acceptance and training. This is particu-larly true for integrated drilling software becauseworkflow analysis has shown that drilling engi-neers often use the software intermittently andhave little time to learn new packages. DrillingOffice applications follow the standard Windows“look and feel” to shorten the learning period andaccommodate cross-disciplinary use. End userswho have worked with only one module can learnthe entire system quickly. The modules will even-tually have a more common look and feel, whichvisually reinforces the movement of data and cal-culations from one application to another.

The Drilling Office suite is based on theGeoFrame heterogeneous computing environ-ment that uses the Standard Data Model devel-oped by the Petrotechnical Open SoftwareCorporation (POSC). POSC is a nonprofit organiza-tion supported by Schlumberger and other indus-try sponsors. The Standard Data Model was

initially designed for G&G data, so Schlumbergerhad to add the drilling view of data to the model.The applications in the various domains aredesigned to allow end users to access relevantdata without being overwhelmed by data they donot need—drillers do not see most G&G dataunless they seek them.

Future database functionality will includeimproved access privileges, whereby only theowners of a particular interpretation, the projectgeologists, geophysicists and engineers, canchange the interpretation, but the interpreta-tions appear to others as “read only” versions.For example, geophysical interpretations by theproject geophysicist or formation tops edited byonly the geologist can be viewed by well plan-ners. Versions of interpretations are retained inthe database, so if personnel changes occur dur-ing a project, the evolution of a particular inter-pretation can be established and reproduced,which prevents unnecessary, expensive duplica-tion of interpretive effort.

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Wellsite database Query tools

Wellbore stability monitoringCasing design

Trajectory planning

Mud and cementing designsThird-party applications

Project database

Master database

Well proposal and drilling policies Basis of design document Programs Operations tracking End of well reports

Planning and Design Execution Evaluation

Knowledge Management and Decision Support Tools

Validate and quality control

Print reports

Capture dataDrilling Office applications

Integrated data and reports

Reports and real-time data

Wellsitedata entry

> How the Drilling Office system works. A master database and integrated software tools are the foundation for Drilling Office integrated drilling software.Links to the wellsite allow real-time data transfer to optimize operations and continuous archiving for future reference. Such a system improves all phases of the drilling workflow from design and planning to execution and evaluation.

7Winter 1998

Well Logs

Petrophysical Modeling

Drilling Data

Seismic Modeling

Geological Modeling

Classification System

Reservoir Simulations

3D and 4D Seismic Data

Shared Earth Model

> Shared earth model. A central project database houses the numerical representation of the subsurface, the shared earth model, which is developed fromgeological, geophysical, petrophysical and drilling data. The shared earth model is used in the drilling workflow to improve drilling planning and operations.The database can be expanded, and the model enhanced, by adding real-time drilling data.

8 Oilfield Review

Changes in the geological interpretationaffect the well design, so a link has been devel-oped in the Drilling Office system between welldesign steps and the shared earth model. Theshared earth model is a concise numerical repre-sentation of the subsurface based on geological,geophysical and petrophysical data and modelsor simulations generated from them (previouspage).2 Such models, however, are inherentlyuncertain because of limited subsurface data,measurement errors and, in some cases, incor-rect models. Integrated software, the appropriatedatabase and a shared earth model allow real-time flow of data and interpretations to improvedecision-making during planning and operations.

The shared earth model affects many areas ofwell planning, including selection of surfacelocation, trajectory design, pore pressure predic-tion and wellbore stability, to name a few. Theuse of shared earth models for well planning hasalready had a positive impact in a number of fielddevelopment projects by reducing drilling costsdue to wellbore instability and stuck pipe. Thepending release of GeoFrame version 3.6 will, forthe first time, give drilling professionals using theDrilling Office suite on a PC direct access to theshared earth model developed by geoscientistson UNIX workstations to improve the drillingplanning and operations workflow.

Implementing Integrated Drilling SoftwareAs is true of any fundamental change in howsomething is done, integrated drilling software isnot a panacea. This new software consists of aset of tools, but does not automatically dictate aparticular workflow. Therefore, to realize themaximum benefit from the Drilling Office system,companies that adopt the system must evaluatetheir procedures critically and carefully. A givenworkflow can be modified to suit individualrequirements because the software is modularand flexible. In addition, if the entire suite ofapplications is not needed, a particular modulecan be used, such as a single application on astand-alone computer at the wellsite. The soft-ware facilitates the iterative nature of teamworkto achieve the best planning and real-time opti-mization of operations. Iterative and collabora-tive project planning and execution are enhancedby making individual applications compatible, asthe following generic case study illustrates.3

At the start of the drilling workflow, geosci-entists typically identify drilling targets on thebasis of attractive potential pay rather than thefeasibility of actually drilling to the target, whichis the primary concern of the planning engineer(above left). With properly integrated applica-tions, geological and geophysical data and inter-pretations in a project database are accessedwith software that generates a preliminary welltrajectory to select a drillable target. In the past,selecting the optimal drillable target from a num-ber of choices was a time-consuming process.With integrated software and a shared database,iterations between engineers and geoscientistsare reduced in number and duration whileachieving superior results (above right).

Target 1

Target 2

> Drilling target selection. Visualization software is used to overlay wellpaths on three-dimensional geological or geophysical interpretations. In this example from the West Cameron area of the Gulf of Mexico, the trajectory intersects two attractive targets in the surface interpreted from seismic data.

Target 1Target 2

>Well design visualization. Visualization software is used with the DrillingOffice PowerPlan tool to overlay a well design on a geological or geophysi-cal interpretation. In this example from the West Cameron area of the Gulf ofMexico, the trajectory selected by geoscientists (blue) has been modified bythe planning engineer to create a drillable trajectory (yellow) to both targets.

2. Beamer A, Bryant I, Denver L, Saeedi J, Verma V, MeadP, Morgan C, Rossi D and Sharma S: “From Pore toPipeline, Field-Scale Solutions,” Oilfield Review 10, no. 2(Summer 1998): 2-19.

3. McCann DP, Ritchie GM and Ward VL: “The IntegratedSolution: New System Improves Efficiency of DrillingPlanning and Monitoring,” paper IADC/SPE 39332, pre-sented at the IADC/SPE Drilling Conference, Dallas,Texas, USA, March 3-6, 1998.

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Survey Q

Survey A

Survey B

Survey C

Survey E

Survey J

Survey K

Survey QSurvey T

Survey P

Survey 0

Survey MSurvey L

Survey D

Survey NNorth

Once a target has been selected, the optimalwell design is created. The well design applica-tion in the PowerPlan module uses input designconstraints to rapidly create both plan view andvertical section plots. The design includes anno-tations of formation tops, casing seats andother critical points (left).4 Collision avoidance isachieved through the use of the Close Approachmodule and survey data from offset wells foranticollision analysis (below left). These appli-cations, along with the ones that follow, areused to create drilling proposals quickly. If thearea of the well target can be enlarged withoutcompromising well objectives, further cost sav-ings might ensue.

Information about offset wells is accessiblein the database and used to improve drilling per-formance in successive wells. BHA selection isoptimized during initial planning or during drillingby using the BHA Editor and DrillSAFE DrillstringForces Analysis modules in the PowerPlan appli-cation (next page, top). In complex wells, such asextended-reach drilling situations, BHA perfor-mance is especially important to the success ofthe operation. The DrillSAFE module is routinelyused for both torque-and-drag analysis and BHAtendency, including computing build and turnrates according to the hardness and other char-acteristics of formations drilled. Output from theDrillSAFE module is graphical and numerical andcapitalizes on both historical and real-time data.

With the PowerPlan Hydraulics application,drilling experience can be used to improve holecleaning and circulating hydraulics (next page,bottom). Circulating pressure losses and equiva-lent circulating densities are calculated, whichallows bit parameters, motor performance andhole cleaning to be optimized using the module’svalidated algorithms (see “Using DownholeAnnular Pressure Measurements to ImproveDrilling Performance,” page 40).5

> Anticollision traveling cylinder plot. A traveling cylinder map generated using the PowerPlan anticollision tool is valuable for both planning and drilling wells in densely drilled areas, such asfrom an offshore platform. The planned or actual subject survey is always at the center of the plotand the offset wellbores (red lines) show the distance and direction from the subject well. Real-timedirectional survey measurements while drilling are used to update the map and reduce the risk ofcollision with existing wells.

Plan view

Verticalsection view

< Directional well design. Drilling tools providedetailed trajectory information. Graphical outputincludes plan and vertical section views of thewell trajectory. Drilling Office applications have a look that is similar to common spreadsheet applications, making them user friendly.

4. Chapman CD: “The PowerPlan System Integrated DrillingPlanning: The Key to Optimization,” Petroleum EngineerInternational 71 (September 1998): 87-95.

5. Chapman, reference 4.

10 Oilfield Review

>

> Bottomhole assemblies. The BHA Editor can be used for well planning. During drilling operations, real-time data allowdrillers to optimize BHA configuration and performance. The up-to-date information and new software capabilities are especially useful in complicated drilling situations, such as extended-reach drilling. In this view of the BHA Editor screen, the driller displays a schematic diagram of the BHA in use (center) and its performance specifications (right). In the left part of the view, the driller navigates to detailed views of the drillstring.

>Wellbore hydraulics. The Drilling Office system contains a wellbore hydraulics module that can help improvehydraulics planning and operations. The wellbore hydraulics tool allows calculation of pressure loss (left), equivalentcirculating density, and motor performance (right) and hole cleaning analysis.

11Winter 1998

When well construction begins, real-timedata are available to all team members so thatoperations are optimized and hazards are antici-pated and avoided. The well design can be mod-ified if predrill predictions are not correct, such aswhen a formation top associated with a casingpoint is higher or lower than predicted.

Planning might involve a spectrum of possi-bilities, whereas operations occur within a lim-ited range of conditions. Individual modules ofintegrated drilling software make use of differentalgorithms depending on the operational rangesor assumptions. Real-time changes during opera-tions are incorporated readily into plans toimprove predictions and anticipate potentialproblems. For example, as a mud system changeswhile drilling, hydraulics calculations incorporateits variations. Real-time torque-and-drag dataallow drillers to make more accurate predictionsahead of the bit. The well trajectory can be mod-ified and performance of the BHA optimized byincorporating real-time data into modeling appli-cations for calibration purposes.

In addition to core drilling applications,there is a need for integrated petrophysicalanalysis, casing and cementing design and tem-perature simulation. Interactive well log analy-sis is performed using the QLA Well LogAnalysis module. The TDAS application includesan expert system that guides engineers toquickly design the lowest cost casing or tubingstring from available inventory using an overallcorporate design philosophy. The TDAS applica-tion also ensures that casing designs meetAmerican Petroleum Institute (API) standardsand International Organization for Standards(ISO) criteria. The CemCADE cementing soft-ware helps engineers plan successful cement-ing jobs from large-diameter surface casing tothe deepest liner. Efficient scenario planningreduces waiting-on-cement time, avoids reme-dial cementing and ensures well safety.

For planning and drilling high-pressure, high-temperature (HPHT) wells, the Drilling Office sys-tem includes advanced simulators for gas kickand temperature modeling, critical aspects forsuccess in these wells.6 The gas-kick simulatorwas the result of extensive research bySchlumberger and BP International Ltd. The pro-ject was initiated by the UK Health and SafetyExecutive (HSE) Offshore Safety Division follow-ing a number of well-control incidents on HPHTwells. Anadrill commercialized the resulting soft-ware as the SideKick program. Additional devel-opment was funded by the European UnionThermie program. The SideKick simulator modelsinfluxes, such as gas kicks, and can evaluate risk,design casing programs and plan procedures forcontrolling HPHT wells.7 The WEST programimproves temperature predictions by engineersduring drilling and cementing operations.

Complex wells constitute perhaps 20 to 30%of total wells drilled, and the benefits of teamwork and data sharing in these cases areobvious. Simpler wells can also be improved,

however. A major benefit of integrated softwareand streamlined workflows can be achievedthrough an assembly-line approach to the simplerwells: the planning cycle is shortened, workbecomes consistent and repeatable, productivityand cost savings increase dramatically. The workbecomes less of an art and more of a streamlinedoperation, with greater efficiency, simplicity andreliability. This shortens the drilling time-depthcurve and ultimately reduces cost per barrel. Bymastering simple, routine operations, engineerscan then concentrate on improving processes,procedures and ways of operating (below).

For example, an engineer developing amature oil field might realize that a single multi-lateral well is a cost-effective replacement fornumerous vertical holes, or that it is possible toreduce the number of casing strings (see “KeyIssues in Multilateral Technology,” page 14). Theability to study scenarios and improve on tradi-tional approaches leads to reduced cost and riskin both simple and complicated situations.

EVALUATE

EXECUTE

DESIGN

Conceptualdesign

Detaileddesign andplanning

Rig sitecontinuousimprovement

> DESIGN-EXECUTE-EVALUATE. Project teams develop a learning culture by constantlyimproving planning and operations. Integrated drilling software and a shared database support such continuous improvement. By working together and understanding each other’sroles better, geoscientists and engineers increase efficiency and reduce cost and risk.

6. For more on use of the SideKick simulator in HPHT wells:Adamson K, Birch G, Gao E, Hand S, Macdonald C, MackD and Quadri A: “High-Pressure, High-Temperature WellConstruction,” Oilfield Review 10, no. 2 (Summer 1998):36-49; and Rezmer-Cooper IM, James JP, Fitzgerald P,Johnson AB, Davies DH, Frigaard IA, Cooper S, Luo Y andBern P: “Complex Well Control Events Accurately Repre-sented by an Advanced Gas Kick Simulator,” paper SPE36829, presented at the SPE European PetroleumConference, Milan, Italy, October 22-24, 1996.

7. MacAndrew R, Parry N, Prieur J-M, Wiggelman J,Diggins E, Guicheney P, Cameron D and Stewart A:“Drilling and Testing Hot, High-Pressure Wells,” Oilfield Review 5, no. 2/3 (April/July 1993): 15-32.

12 Oilfield Review

Companies that incorporate the Drilling Officesystem in their technical computing strategieswill benefit from better data management, dataintegration and evolving computing standards.Integrated drilling software will improve planningand execution of drilling operations by reducingerror and redundancy in the workflow. The com-panies can also expect to manage, use, integrateand understand their data better.

A major oil company has tested the DrillingOffice tool suite and provided feedback toGeoQuest developers. The company is adoptingthe system as part of their internal computing ini-tiative. Several E&P companies seek to buy ratherthan develop their own applications for general,mainstream needs and to develop proprietarysoftware only for rare cases of unique needs. Forsuch companies, the Drilling Office system willmeet the need for both general drilling planningneeds and specialized real-time calculations.

Looking AheadIntegrated software for drilling planning andoperations is a response to the need for productsthat support integrated, multidisciplinary work-flows and today’s more exacting requirements fordesign and accurate placement of wells. Ideally,such software should follow the drilling processnaturally, have a single database for each projectand house applications that represent the bestpractices of the industry. Schlumberger will con-tinue to enhance the capabilities of the DrillingOffice system. In contrast to stand-alone applica-tions that focus on individual tasks, the mostpowerful drilling software will integrate andunify tasks into smooth processes. As assetteams focus more on the overall process at hand,the value of corporate assets, that is, reserves inoil and gas fields, will be maximized (above).

As the use of integrated drilling softwareincreases, members of project teams will betterunderstand each other’s disciplines and rolesthrough the new perspective of a shareddatabase. By implementing the use of integratedsoftware whose technical integrity has beenclearly demonstrated at each stage of the work-flow, companies can document their compliancewith regulatory requirements, such as zonal iso-lation of water from hydrocarbons or shallow gaszones, more readily.

Just as integrated drilling software providesa seamless link back to geological and geophysi-cal exploration applications, future functionalitywill include a similar link forward to the produc-tion phase that follows. A single database and anintegrated suite of applications will simplify theexploration and production workflow from projectconception to maturity. —GMG

Oper

ator

val

ue

Task

Process

Corporate asset

Stand-a

lone

Conten

t

Usabilit

y

Conne

ctivit

y

Integ

ration

Standa

rds

Unified

infras

tructu

re

Unifyin

g

appli

cation

sFul

l

integ

ration

> Value of technology. The value of corporate assets increases as software is used to integrate tasks and improve thefocus on the total process rather than discrete tasks. Value, the y-axis, is both the perceived value to team membersas well as the monetary value to the corporation. The value attributed to each item listed along the x-axis depends onwhether one is task-oriented (bottom curve), process-oriented (middle curve) or taking the viewpoint of a corporation(top curve). Task-oriented people are most concerned with content and usability. Process-oriented professionals seekintegration and standards. Corporate leaders recognize that data and process integration maximizes asset value.

13Winter 1998

Key Issues in Multilateral Technology

Steve BosworthUnion Pacific ResourcesFort Worth, Texas, USA

Hussein Saad El-SayedDubai, United Arab Emirates

Gamal IsmailZakum Field Development CompanyAbu Dhabi, United Arab Emirates

Hervé OhmerMark StrackeChris WestSugar Land, Texas, USA

Albertus RetnantoJakarta, Indonesia

For help in preparation of this article, thanks to LennisCook, Anadrill, Sugar Land, Texas, USA; Chip Corbett,GeoQuest, Houston, Texas; Vladimir Doroshenko,Schlumberger Wireline & Testing, Moscow, Russia; Doug Durst, Weatherford, Houston, Texas; AlexanderMikhailovich Grigoryan, Los Angeles, California, USA; David Hill, Anadrill, Shekou, Shenzhen, China; DavidMalone, Camco, Houston, Texas; Pat McKinley, Anadrill,Midland, Texas; Eric Neme, Schlumberger Oilfield Services,Lagos, Nigeria; and Claire Vishik, Austin Product Center,Austin, Texas.

Drilling, completing and later reentering wells with multiple branches to improve

production while saving time and money are becoming commonplace, but complications

remain, as do the risks and chances of failure. Existing techniques have been applied

and fresh approaches are being developed to overcome technical hurdles, establishing

new standards and a specialized vocabulary for these well types and applications.

In 1953, a unique oil well called simply 66/45was drilled with turbodrills in the Bashkiria fieldnear Bashkortostan, Russia. This well ultimatelyhad nine lateral branches from a main boreholethat increased exposure to the pay zone by 5.5times and production by 17-fold, yet the cost wasonly 1.5 times that of a conventional well.1 It wasthe world’s first truly multilateral well, althoughrudimentary attempts at multilaterals had beenmade since the 1930s. Under the auspices of theSoviet Oil Industry Ministry, another 110 suchwells were drilled in Russian oil fields over thenext 27 years (see “The Father of MultilateralTechnology,” page 16 ). Not until ARCO drilledthe K-142 dual-lateral well in New Mexico’sEmpire field in 1980, did another operatorattempt such a feat, for multilaterals were simplytoo difficult and too risky, requiring substantialinvestment of both time and technology.

A multilateral well is a single well with oneor more wellbore branches radiating from themain borehole. It may be an exploration well, aninfill development well or a reentry into an exist-ing well. It may be as simple as a vertical well-bore with one sidetrack or as complex as ahorizontal, extended-reach well with multiplelateral and sublateral branches. General multi-lateral configurations include multibranchedwells, forked wells, wells with several lateralsbranching from one horizontal main wellbore,wells with several laterals branching from onevertical main wellbore, wells with stacked later-als, and wells with dual-opposing laterals (nextpage, top). These wells generally represent twobasic types: vertically staggered laterals andhorizontally spread laterals in fan, spine-and-ribor dual-opposing T shapes.

14 Oilfield Review

INFORM (Integrated Forward Modeling), PowerPak,RapidAccess, RapidConnect, Slim 1, USI (UltraSonicImager) and VIPER are marks of Schlumberger.1. Horizontal Well Technology Unit, Heriot-Watt University

and The Petroleum Science and Technology Institute,Multi-Lateral Well Technology Technical Study (1995): 6-9.

2. Horizontal Well Technology Unit, reference 1: 6-14.

Vertically staggered wells usually target sev-eral different producing horizons to increase pro-duction rates and improve recovery frommultiple zones by commingling production.Wells in the Austin Chalk play in Texas (USA) aretypically of this type (below right). Their produc-tion is a function of the number of natural frac-tures that the wellbore encounters. A horizontalwell has a better chance of intersecting morefractures than a vertical well, but there is a limitto how far horizontal wells can be drilled. Bydrilling other laterals from the same wellbore,twice the number of fractures can often beexposed at a much lower cost than drilling longhorizontal sections or another well.

Horizontal fan wells and their relatedbranches usually target the same reservoir inter-val. The goal of this type of well is to increaseproduction rates, improve hydrocarbon recoveryand maximize production from that zone.Multiple thin formation layers can be drained byvarying the inclination and vertical depth of eachdrainhole. In a naturally fractured rock with anunknown or variable fracture orientation, a fanconfiguration can improve the odds of encoun-tering fractures and completing an economicwell. If the fracture orientation is known, how-ever, a dual-opposing T well can double thelength of lateral wellbore exposure within thezone. In nonfractured, matrix-permeability reser-voirs, the spine-and-rib design reduces the ten-dency to cone water. Lateral branches aresometimes curved around existing wells to keephorizontal wellbores from interfering with a ver-tical well’s production.

A successful multilateral well that replacesseveral vertical wellbores can reduce overalldrilling and completion costs, increase productionand provide more efficient drainage of a reservoir.Furthermore, multilaterals can make reservoirmanagement more efficient and help increaserecoverable reserves. But why has it taken so longfor multilateral technology to catch on?

Between 1980 and 1995, only 45 multilateralwell completions were reported; since 1995,hundreds of multilateral wells have been com-pleted and many more are planned over the nextfew years.2 This increased number of multilateralwells is related to a rapid sequence of advancesin the methods for drilling multilateral wells—directional and horizontal drilling techniques,advanced drilling equipment and coiled tubingdrilling. However, the levels of well complexityhave remained low due to a lack of comparableadvances in multilateral completion equipmentand designs. As a consequence, the primary risksinvolved in multilateral wells have been in lateraljunction construction and completion rather than

Multibranched Forked

Laterals into horizontal hole

Stacked laterals

Laterals into vertical hole

Dual-opposing laterals

Multilateral Well Configurations

> Common forms of multilateral wells in use today. Wellbore design and configuration are dictated byspecific formation and reservoir drainage requirements.

5700

6100

6500

6900

73000 800 1600 2400 3200 4000 4800

Lateral section displacement, ft

True

ver

tical

dep

th, f

t

Top ofAustin ChalkBentonite

EaglefordFalse BudaBuda

Georgetown

> Typical Austin Chalk well in south Texas, USA. Stacked drainholes target multiple zones to increaseproduction rates and improve recovery by commingling production. Horizontal wells have a betterchance of intersecting natural fractures than vertical wells; production is a function of the number offractures that the wellbore encounters.

15Winter 1998

(continued on page 18)

As with many advances in petroleum technology,the first multilateral well was accomplished by aSoviet drilling engineer. Alexander MikhailovichGrigoryan was born during 1914 in Baku, thecapital of today’s Republic of Azerbaijan, then aprincipal center of oil production. After gradua-tion from high school, he worked as a driller’sassistant, became an apprentice and ultimatelygraduated as a petroleum engineer in 1939 fromAzerbaijan Industrial Institute (right).

During most of the Soviet era, the official pol-icy was to produce as much oil as possible, sinceit was a strategic commodity and one of the fewexports that could be exchanged for grain andother consumer goods. High quotas wereimposed on drillers to bore as many holes asthey could. The prevailing attitude was that themore holes drilled, the greater the likelihood ofsuccessfully tapping a reservoir and therebyachieving greater production.

Grigoryan was an innovator and inventor.Upon graduation, he began working as an oil-field driller and soon was attached to theMinistry of Oil. Believing that he could producemore oil by following a known oil sand than bymerely penetrating it with a number of bore-holes, he drilled one of the world’s first direc-tional wells—Baku 1385—in 1941, nearly 20years before anyone else attempted such a feat.Without a whipstock or a rotating drillstring, heused a downhole hydraulic motor to penetrateoil-bearing rock and significantly expand reser-voir exposure and production. It was the firsttime that a turbodrill was used for both verticaland horizontal sections of a borehole.1

Grigoryan’s pioneering work in horizontaldrilling technology led to scores of other suc-cessful horizontal wells across the USSR and his elevation to department head at the All-Union Scientific-Research Institute forDrilling Technology (VNIIBT). He was not, however, satisfied with these accomplishments.He developed a new borehole sidetrack kickofftechnique and a device for stabilizing and

controlling curvature without deflectors. But allof these innovations were in preparation for hismajor contribution to drilling technology.

Inspired by the theoretical work of Americanscientist L. Yuren, who maintained thatincreased production could be achieved byincreasing borehole diameter in the productivezone, Grigoryan took the theory a step furtherand proposed branching the borehole in theproductive zone to increase surface exposure,“just as a tree’s roots extend its exposure to thesoil.” In 1949, he took his ideas to notedRussian scientist K. Tsarevich, who confirmedthat branching a well in a productive zone withuniform rock permeability should yield anincrease in oil production in proportion to thenumber of branches.

Grigoryan put this new theory into practice inthe Bashkiria field complex in what is todayBashkortostan, Russia (right). There, in 1953,he used downhole turbodrills without rotatingdrillstrings to drill Well 66/45, the first multilat-eral well. Bashkiria field complex lies in south-ern Bashkortostan (next page, left). Late

Carboniferous carbonate reefs built by rugosecorals trap vast oil reserves (next page, right).The fields had been in production since before1930, and most wells produced low volumes atthe time Grigoryan first attempted a multilat-eral well. 2

Grigoryan chose to drill Well 66/45 inBashkiria’s Ishimbainefti field, which evidencedan interval of Artinskian carbonate rocks withgood reservoir properties and wide areal distri-bution. His target was the Akavassky horizon, an interval that ranged from 10 to 60 m [33 to 197 ft] thick.

Grigoryan drilled the main bore to a totaldepth of 575 meters [1886 ft], just above the payzone. From that point, he drilled nine branchesfrom the open borehole without cement bridgesor whipstocks; the window configurationenabled insertion of tools on drillpipe into the

The Father of Multilateral Technology

> Alexander Mikhailovich Grigoryan. Now 84years of age, Grigoryan immigrated to theUnited States in the 1980s and became anAmerican citizen. He kindly granted OilfieldReview an interview and made documentsabout his technique available.

Russ ian Fede ra t i o

n

Ufa

Neftekamsk

Salavat

Sterlitamak

Oktyabrski

Ishimbai

B a s h k o r t o s t a n

Beley

aRi

ver

> Map of Bashkortostan inset in a map of the Rus-sian Federation. The first multilateral wells weredrilled in the Ishimbai region in the south-centralregion of the republic.

16 Oilfield Review

sidetracks without instrumentation. He drilledby touch alone, “slanting away from the verticalbore like roots of a tree, each branch extendingfor 80 to 300 meters [262 to 984 ft] in differentdirections into the producing horizon.” 3

Grigoryan allowed the drill bit to follow the payzone into the most productive zones, thebranches curving automatically to the plannedtrajectory. Drilling speed and penetration ratedepended entirely on the hardness of the rockand downhole motor capabilites.

When completed, Well 66/45 had nine produc-ing laterals with a maximum horizontal reachfrom kickoff point of 136 meters [447 ft] and atotal drainage of 322 meters [1056 ft].

Compared with other wells in the same field,66/45 penetrated 5.5 times the pay thickness. Its drilling cost was 1.5 times more expensive,but it produced 17 times more oil at 755 B/D[120 m3/d] versus the typical 44 B/D [7 m3/d].4

Under the auspices of the Soviet Oil IndustryMinistry, another 110 multilateral wells weredrilled in Russian oil fields over the next 27years, with Grigoryan drilling 30 of them him-self. About 50 of these first multilaterals wereexploratory, the remainder were for delineationof reefs and channel structures.

223

425455

473

490

521

617 TD

506

595 TD595 TD605 TD

617 TD

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660 TD

582 TD

627 TD

Artinski limestone

Well 66/45

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d de

pth

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> An early multilateral well. Drilled in Bashkiria, now Bashkortostan, one of Russia’s most prolific regions, the first multilateral well had nine lateral branches that tapped the Ishimbainefti field reservoir.

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Kasimovian

Moscovian

Bashkirian

Serpukhovian

Strunian/Etroeungtian

Couvinian

ZlichovianPragian

Lochkovian

Millionyears

> Bashkiria stratigraphic column. The first multilateral well target waswithin the Akavassky horizon, in the center of the lower Bashkiriansequence, middle Carboniferous era. [Adapted from Haq BU and Van Eysinga FWB: Geological Time Table, 4th ed. Amsterdam, The Netherlands: Elsevier Science BV, 1994.]

1. Gaddy D: “Pioneering Work, Economic Factors ProvideInsights into Russian Drilling Technology,” Oil & GasJournal 96, no. 27 (July 6, 1998): 67-69.

2. Boisseau T, Chuvashov B, Ivanova R, Maslo A, Masse P,Proust J-N, Vachard D and Vennin E: “EtudeSedimentologique et Biostratigraphique du Stratotype duBashkirien (Oural du Sud, Russie),” Bulletin, CentresRecherche Exploration-Production, Elf Aquitaine 20, no. 2(December 1996): 341-365.

3. Bakke D: “Russia Gears Up Offshore Activity for BiggestProduction Gains in Its History,” Offshore 35, no. 5 (May1975): 303-306.

4. Horizontal Well Technology Unit, Heriot-Watt Universityand The Petroleum Science and Technology Institute,Multi-Lateral Well Technology Technical Study, 1995: 6-9.

17Winter 1998

drilling. Of the hundreds of multilateral wellsdrilled, most have been simple openhole comple-tions in hard rock; many have been reentries tosalvage wells or boost output from old fields, butan increasing number represents new, develop-ment wells seeking to maximize drainage ofknown reservoirs.

Regardless of the level of complexity, multi-lateral wells today are drilled with state-of-theart directional drilling technology. Even so, thedrilling of multilateral wells involves certain risksranging from borehole instability, stuck pipe andproblems with overpressured zones to casing,cementing and branching problems. And therecan be a high risk of drilling or completion forma-tion damage and difficulties locating and stayingin the productive zone while drilling the laterals.

Multilateral technology may be at about thesame level of development that horizontal anddirectional drilling were 10 years ago. Horizontaland reentry multilateral drilling has increased50% over the past five years and is expected togrow another 15% a year through 2000.3 Thisrapid growth is attributed to operators realizingthat the advantages of multilateral systemsincreasingly outweigh the disadvantages.

For years, because there were so few reliableand sophisticated examples of successful multi-lateral applications, few such wells were drilledbecause operators lacked benchmarks by whichto determine whether prospects were suitablecandidates for multilateral development (right).There were concerns about higher initial costsand the risk of possible interference of lateralswith each other, crossflow and difficulties withproduction allocations. An increased sensitivityto and concern about reservoir heterogeneitieslike vertical permeability deterred multilateraldevelopment. The prospect of complicateddrilling, completion and production technologies,complicated and expensive stimulation, slow andless effective cleanup, and cumbersome well-bore management during production also madeoperators cautious.

As more multilaterals were drilled success-fully, however, even the simplest wells demon-strated the potential of this emergingtechnology. The main benefits of these success-ful wells have been increased production,increased reserves and an overall reduction inreservoir development costs.

Production from known reserves has tradi-tionally been expanded by drilling additionalwells to increase drainage and sweep efficiency.As a consequence, both capital expenditures andoperating costs have also increased with every

new well. To counteract these cost increases,multilateral technology is now being employed toincrease borehole contact with the reservoir,improve operating efficiency and reduce wellcosts. These goals are achieved primarily bydrilling the main trunk and overburden from sur-face to the reservoir only once and by reducingsurface equipment to a single installation at asignificant cost-savings. Furthermore, this can beachieved in both offshore platform and subseasituations where a limited number of slots isavailable and in onshore locations where surfaceinstallations are expensive or where the leasehas an irregular configuration.

Multiple lateral penetrations in the samereservoir or in independent reservoirs not onlyproduce significant cost-savings, but increaseproduction rates appreciably (next page). Suchpenetrations are commonly used to increase theeffective drainage and depletion of a reservoir,particularly when reservoirs have restrictedhydrocarbon mobility due to low permeability,low porosity or other characteristics that limitproduction flow. When independent reservoirsare targeted, production can either be commin-gled into a single production tubing string or pro-duced separately in multiple production tubingstrings. Multilateral wells are also an economical

YesNo

YesNo

YesNo

YesNo

YesNo

YesNo

YesNo

YesNo

YesNo

YesNo

Does the reservoir contain hydrocarbons in small or isolated accumulations?

Is there an accumulation of oil abovethe reservoir's highest perforations?

Is the reservoir separated into low-transmissibilityvertically stacked segments?

Is the reservoir naturally fractured or does it havehigh permeability only in one direction?

Does the reservoir have numerouslens-shaped pay zones?

Are there two different, or distinct sets ofnatural fractures in the reservoir?

Does the reservoir require waterflood?

Does waterflood of the reservoir cause a breakthrough inhigh-quality zones before low-quality zones are swept?

If offshore, is the platform unable to accomodate anadditional well that is needed to drain additional fault blocks?

Are future rigless completions plannedfor additional zones?

Drill a conventional verticalor horizontal well.

Consider amultilateral well.

> Determining if multilateral technology is applicable.

18 Oilfield Review

3. Longbottom J and Herrera I: “Multilateral Wells CanMultiply Reserve Potential,” American Oil & Gas Reporter40, no. 9 (September 1997): 53-58.

way of rapidly depleting a reservoir, effectivelyaccelerating production, shortening the field lifecycle and reducing operating costs.

Multilateral wells are often able to overcomethe shortcomings of both horizontal and conven-tional wells, particularly if there are geologicalfactors like thinly layered formations or a signifi-cantly fractured system, and in specific enhancedoil recovery scenarios such as steam-assistedgravity drainage. In addition, the application ofmultilateral technology can result in decreasedwater and gas coning.

Because of the capability to more thoroughlydrain reservoirs vertically and horizontally, recov-erable reserves per well and per field areincreased considerably while both capital andoperating costs per well and per field are mini-mized. In fact, the cost of achieving the samedegree of drainage with conventional wellswould be prohibitive in most cases, especiallysituations like deepwater subsea developments.Multilateral wells allow costs to be amortizedover several reservoir penetrations and in somecases have eliminated the need for infill drilling.In heterogeneous reservoirs with layers, com-partments or randomly oriented natural fractures,more pockets of oil and gas can be exploited andan increased number of fractures can be inter-sected by drilling multilateral wells.

In anisotropic formations with unknowndirections of preferred permeability, drillingmultibranched wells can reduce economic risk.Lateral branches can balance the nonuniformproductivity or injectivity of different layers.Multilateral wells provide extensive informationabout the reservoir and can be useful for explo-ration and formation evaluation in addition totheir capability to efficiently and economicallydrain reservoirs.

TAML ClassificationUntil 1997, there was considerable confusionregarding multilateral technology. Few terms thatdescribed the technology were universally agreedupon, and a classification of multilateral wells bydifficulty and risk was lacking. As a consequence,under the leadership of Eric Diggins of Shell UK Exploration and Production, a forum called“Technology Advancement—Multi Laterals(TAML)” was held in Aberdeen, Scotland, in theSpring of 1997. Its goal was to provide a moreunified direction for multilateral technology devel-opment. Experts in multilateral technology fromleading oil companies shared experiences andagreed to a classification system that ranks multi-lateral wells by complexity and functionality.Today, multilateral wells are referred to by levelof complexity from Level 1 through 6S, anddescribed with a code to represent type and func-tionality (see, “Classifying Multilateral Wells,”page 20).

The three characteristics used to evaluatemultilateral technology are connectivity, isolationand accessibility. Of these, the form of connec-tivity or junction between the main trunk and lat-eral wellbore branches is not only the mostdistinguishing feature, but also the riskiest andmost difficult to achieve. For this reason, about95% of multilateral wells drilled worldwide havebeen Level 1 or 2. Some 85% of 1998 multilater-als have been Levels 1 to 4, with 50% of thoseLevels 1 and 2. But the race is on; virtually allmajor operators and drilling service companiesare developing multilateral connectivity, isolationand accessibility capabilities. In addition, newjunction systems are emerging to facilitateincreasingly higher levels of difficulty.

Level 1 is essentially a simple openhole side-tracking technique, much like the first multilater-als drilled in Russia. The main trunk and lateralbranches are always openhole with unsupportedjunctions. Lateral access and production controlare limited.

In Level 2 wells, the main bore is cased, butthe lateral junction remains openhole, or possiblywith a “drop-off” liner—casing placed in lateralsections without mechanical connection orcementing—to provide full-opening main well-bore access and improve the potential for reentryinto the lateral.

Anadrill performs Level 1 and 2 multilateralconnections throughout North America and theMiddle East (see, “Multilaterals in the MiddleEast, “ page 24). Drilling is usually carried outwith either short-radius or medium-long radiusdrilling assemblies. The Anadrill RapidAccesssystem and third-party casing exiting serviceslike those of Smith International are used to pro-vide support. Milling can also be carried out inexisting wells using conventional retrievablewhipstock or cement plug techniques. Otherproviders can supply similar systems or junctionswith windows precut.

Level 2 wells commonly require a window, orhole, to be cut in the casing with a milling assem-bly. Generally, this level of multilateral consistsof whipstock sidetracks from existing casing

Shallow ordepleted reservoirs

Layered reservoirs

Fractured reservoirs

> Enhancing productivity with multilateral well configurations. In shallow or depleted reservoirs, branched horizontal wellbores are often most efficient,whereas in layered reservoirs, vertically stacked drainholes are usually best. In fractured reservoirs, dual-opposing laterals may provide maximum reservoir exposure, particularly when fracture orientation is known.

19Winter 1998

Classifying Multilateral Wells

1

2

3

4

5

6

6S

< Multilateral well complexity ranking (Level 1 to 6S).This general classification is based on junction complexity. Level 1 is an openhole sidetrack or unsupported junction. Level 2 has a cased and cementedmain bore, or trunk, with openhole lateral. Level 3 is acased and cemented main bore with lateral cased, but notcemented. Level 4 has both main bore and lateral casedand cemented at the junction. Level 5 pressure integrity isachieved at the junction with completion equipment. ForLevel 6, junction pressure integrity is achieved with casingand without the assistance of or dependence on comple-tion equipment. In the subcategory Level 6S, a downholesplitter, basically a subsurface dual-casing wellhead,divides a large main bore into two equal-size laterals.

Single Bore

Dual Bore

Concentric Bore

> Multilateral well descriptions. Inaddition to criteria such as the num-ber of junctions and well type—pro-ducer with or without artifical lift,injector or multipurpose—the com-pletion type, whether single, dual or concentric, has a major impact onthe type of equipment that is neededat the junction.

NR–No selective reentry

PR–Reentry by pulling completion

TR–Through-tubing reentry

NON–None

SEL–Selective SEL–Selective

REM–Remote monitoringRMC–Remote monitoring and controlSEP–Separate

Accessibility

Flow Control

> Junction types. The categories of accessibility are no selective reentry, reentry by pulling completion andthrough-tubing reentry (top). Flow control (bottom) is the degree to which fluid flow across a junction can be adjusted—no control, selective or separate control, and remote monitoring or remote monitoring and control.

20 Oilfield Review

(right). Premilled window casing subs are alsoused frequently to avoid the higher risk task ofmilling. Although retrievable whipstocks areemployed to drill laterals, their removal alongwith the packer assembly from the main wellboremakes locating laterals and reentry accessalmost impossible. Accurate positioning of sub-sequent guide assemblies and azimuthal orienta-tion are also difficult if not impossible. For thisreason, the Anadrill Level 2 RapidAccess multi-lateral completion system was enhanced byadding a mechanical connection with a fullborecasing profile nipple for positioning and orientingwhipstocks or other assemblies to provide selec-tive drainhole access.

The Level 2 RapidAccess construction wasengineered with robust simplicity to be transpar-ent to the drilling operation, while retainingoptions for higher level multilateral completions.RapidAccess couplings do not require orientationor special procedures during installation and arecemented using conventional equipment and pro-cedures. These couplings are full opening, per-manent reference points from which multiplebranches can be constructed and reentered fromthe main wellbore. Since orientation prior tocementing is not required, casing movement dur-ing primary cementing helps ensure a successfulcement bond. Multiple RapidAccess couplingscan be installed in casing strings to allow numer-ous reservoir penetrations for optimum fielddevelopment. Depth and orientation of each cou-pling can be determined by measurements-while-drilling (MWD) survey after cementing andby wireline or coiled-tubing conveyed USIUltraSonic Imager surveys (right).

Level 3 multilateral technology offers bothconnectivity and access. The main trunk and lat-erals are cased; the main bore is cemented, butlaterals are not. Until recently, only premilledwindows were used at this level if access intoeach lateral needed to be maintained. Lateral lin-ers are anchored to the main bore by a linerhanger or other latching system, but cementing isnot required. There is no hydraulic integrity orpressure seal at the lateral liner and main casingjunction, but there is main bore and lateral reen-try access.

The Level 3 RapidConnect system will providemechanical connectivity to both the lateral andmain wellbore and high-strength junctions forunstable formations. This enhancement is criticalwhen sands or shales become unstable over theproductive life of a well. Completion options thatmay be required by the reservoir depletion planallow upper laterals to be isolated at the junctionwhile producing from lower laterals. Selectiveaccess to laterals is made possible by placing anoriented diverter at the junction.

The most common completion performed inLevel 2 and 3 wells is uncemented, predrilled orslotted liners and prepacked, but not gravel-packed screens. Anadrill uses a drop-off linercompletion design in which the top of the liner inthe lateral is immediately released outside theexit from the casing through a hydraulic sub.External casing packers are often used in thedrop-off liner completion assembly to isolatezones, anchor the liner top and facilitate reentryaccess to the liner.

Another mid-tier approach to multilateralcompletion offers only individual hydraulic isola-tion of a lateral. In this case, laterals are drilledusing whipstock sidetracking procedures and ifany completion is performed in the lateral, it usesa drop-off liner. Conventional casing packers inthe main casing with tubing between them—straddle packers—are used to isolate each of

Step 1

Run multilateral packer onstarter millassembly

Step 3

Completemilling ofwindow

Step 2

Set packer

Shear startermill

Begin millingwindow

Window from USI log

Index casing couplingfrom USI log

Window toICC spacing

< Window orientation,depth and quality. AUSI UltraSonic Imagerlog can determine theorientation and depthof a cemented coupling relative tocasing collars andgamma ray (GR) logs.A USI log can also be used to providefeedback about window quality dur-ing well construction.These images showan index casing coupling (ICC) and a window milled in 7-in., 26-lbm/ft casingusing a downholemotor. This log wasrun to verify thelength of a full-gaugewindow. A USI logcan be run in mostcommon drilling fluids.

>Window milling. Lateral openings are cut into the casing wall with whipstock and milling equipment.The whipstock packer is run and set on a mill assembly. The starter mill is then sheared off the top ofthe whipstock and a window is cut into the wall and formation to begin a lateral drainhole branch.

21Winter 1998

the laterals hydraulically. Production from the lat-erals is controlled with sliding sleeves and otherflow-control devices. This is an inexpensive andrelatively straightforward multilateral completionmethod that was proven in the North Sea and isnow being adapted for deepwater subsea wells.

The critical technology in these completionsis operation of flow-control devices downhole.Schlumberger Camco intelligent well technologyis now capable of activating and controllingthese flow control devices remotely.

Level 4 multilateral wells have both the mainbore and lateral cased and cemented at the junc-tion, which provides a mechanically supportedjunction, but no hydraulic integrity. The lateralliner is, in fact, cemented to the main casing. Themost common sidetracking procedure relies onwhipstock-aided milling of casing windows,although premilled window-casing subs are alsoemployed. There is no pressure seal at the junc-tion interface of the lateral liner and the maincasing, but the main bore and the laterals havefullbore access. This level of multilateral technol-ogy, although complex, high risk and still indevelopment, has been successful in multilateralwells worldwide.

A Level 5 multilateral well is characterized byeither the Level 3 or Level 4 lateral connectiontechnique with addition of completion equipmentto provide a pressure seal across the junction ofthe lateral liner and main casing. The main well-bore is fully cased and the junction is hydrauli-cally isolated; cement is not acceptable as thehydraulic isolation. Reentry access to both themain bore and the laterals is available. Hydraulicisolation is achieved with the use of auxiliarypackers, sleeves and other completion equip-ment in the main casing bore to straddle the lat-eral junction with production tubing.

Level 5 and 6 wells are distinguished from themid- and lower tier levels by hydraulic isolation ofthe laterals as well as connectivity and accessi-bility characteristics. The most difficult aspects ofmultilateral technology are hydraulic isolationand integrity at high pressure, and most providersare still seeking ways of improving these.

Level 6 multilateral systems incorporate anintegral pressure seal in the junction of the lat-eral liner and the main casing. A pressure-tightjunction, achieved with an integral sealing fea-ture or a monolithic formed or formable metal

design, is the goal and will be valuable in deep-water offshore and subsea installations.

Schlumberger first evaluated Level 6 multilat-eral technology in 1995 with a system developedby Anadrill, Camco and Integrated DrillingSystems. With multilateral technology develop-ment transferred from Anadrill to the CamcoAdvanced Technology Group, Schlumberger isevolving these techniques into newer systemsrather than proceeding with this particular version. The company is continuing developmentof multilateral technology with a new Level 6 design.

Level 6S, a generally recognized Level 6 sub-level, uses a downhole splitter, or subsurfacewellhead assembly, that divides the main boreinto two smaller, equal-size lateral bores.

Positioning MultilateralsRegardless of the design level or multilateraltechnology used, for lateral branches to achievethe desired contact with productive intervals,borehole direction must be an integral part ofwell plans. Determining these trajectoriesdepends on reservoir properties, the rock stress

1 2 3 4 5 6 7

ICC

Slim 1MWD

Gelledfluid

SLT

ICC

> The Level 2 multilateral process.

1. The main wellbore casing is run with indexcasing couplings (ICC) as integral compo-nents. The ICC, normally of standard couplingOD and pipe ID sizes, does not need to be oriented when run. It can be placed below,above or in angle-build sections.

2. The main bore casing is cemented using stan-dard procedures and casing wiper plugs.

3. The lower branch is drilled, completed andisolated with a retrievable bridge plug.

4. The coupling orientation is determined fromthe USI log or by running a Selective LandingTool (SLT) with Slim 1 MWD in the UniversalBottomhole Orienter (UBHO). During this tripthe coupling can be cleaned with a specialjetting tool and a gel pill may be spotted in thekickoff section to suspend debris.

5. The whipstock face is then properly alignedwith the landing tool orientation key and runinto the well. This assembly automaticallyaligns and latches in the appropriate coupling. The milling tool is then releasedfrom the whipstock.

6. A casing window and short pilot hole into theformation are cut with a special millingassembly powered by a downhole motor, inthis case, an XP series PowerPak motor.

22 Oilfield Review

4. Ehlig-Economides CA , Mowat G and Corbett C:“Techniques for Multibranch Well Trajectory Design inthe Context of a Three-Dimensional Reservoir Model,”paper SPE 35505, presented at the European 3-DReservoir Modeling Conference, Stavanger, Norway,April 16-17, 1996.

5. Roberts M, Kirkwood A and Bedford J: “Real-TimeGeosteering in the Tern Field for Optimum MultilateralWell Placement,” paper SPE 50663, presented at the 1998SPE European Petroleum Conference, The Hague, TheNetherlands, October 20-22, 1998.

Allen D, Dennis B, Edwards J, Franklin S, Livingston J,Kirkwood A, Lehtonen L, Lyons B, Prilliman J and Simms D:“Modeling Logs for Horizontal Well Planning andEvaluation,” Oilfield Review 7, no. 4 (Winter 1995): 47-63.

regime and the geometries of productive reser-voir units. Laterals can be vertical, inclined orhorizontal, as can the main wellbore, butbecause production from several laterals can becommingled in the main wellbore, it is possibleto drill more drainholes in the reservoir thanwould be feasible with a conventional well.4

Trajectories for the main wellbore and later-als are determined using various informationsources, including 3D surface and borehole seis-mic data, well logs and core analyses, formationand well testing, and other data like fluid proper-ties and production histories. Predrill planningalso ideally includes geological and petrophysi-cal forward modeling with tools like INFORMIntegrated Forward Modeling software to helpidentify risks and the value of logging-while-drilling (LWD) measurements. Such modelingprovides initial petrophysical descriptions alongproposed trajectories by using imported geologi-cal models (above). Thereafter, 2D and 3D LWDtool response functions are generally used toproduce synthetic log datasets to complete for-ward models.5

Well path designs begin in the producing for-mation where the optimal lateral location isdetermined. From the farthest point in the later-als, the design proceeds to the main bore, thenupward to the surface or seafloor wellhead. Bothpermeability and stress anisotropy are important

considerations when selecting an optimal wellpath orientation in three dimensions. Productionand perhaps drainage volume can be severelyrestricted by pressure gradients associated withconverging flow in formations. Productivity canbe enhanced if laterals are oriented to takeadvantage of permeability differences in produc-ing zones or across an interval of different layers.For this reason, slanted and horizontal lateralsare most productive when oriented perpendicularto natural fractures. When vertical permeabilityis much less than horizontal permeability, slantedlaterals are best.

Closely spaced lateral branches increase thepossibility of accelerated production andimproved recovery efficiency in large reservoirswith thin zones or in thick zones underlain bywater or overlain by gas. In reservoirs with struc-turally or stratigraphically isolated zones, multi-lateral wells are able to target the various layerswith several laterals.

While multilateral wells are from the bottomup, risks involved in actually drilling drainholesdevelop from the top down. The best drillingand completion strategy is to construct lateralsfrom the deepest branch up. This isolates risksat the lowest point and ensures that developingproblems leave the wellbore above that pointfree of difficulty.

Drilling MultilateralsThe majority of multilateral wells drilled since1953 have been Level 1 and 2 openhole com-pletions in hard rock. Much of this drilling usedrelatively simple technologies, but as openholecompletions with limited functionality give wayto higher level multilaterals to meet therequirements of complicated reservoir and geo-logical conditions, standard directional drillingis being replaced by increasingly complex tech-nologies (previous page and below).

m 4m 3m 2

m1

Trunk

> Subsurface models. Petrophysical descriptionsalong proposed well trajectories can be gener-ated using imported geological models. Here fourlaterals (m 1, m 2, m 3 and m 4) branch from a mainwellbore in a vertically stacked configuration.

8 9 10 11 12 13

RDT

SLT

7. After a lateral is drilled to depth, it may be leftopenhole or a simple cemented or drop-offliner may be run. The landing tool is releasedand the entire assembly is retrieved from thewell. The hole is cleaned out and the bridgeplug is retrieved.

8. The process is changed for a cemented linerby replacing the full-size whipstock with asmaller diameter reentry deflection tool (RDT)that is run and latched into an ICC.

9. The bottomhole assembly (BHA) is run and alateral branch is drilled.

10. A liner is run into the lateral and possiblycemented back into the main casing.

11. The liner running tool is released, the holecleaned up by reverse circulating, and thenthe liner running tool is pulled out of the hole.

12. After the lateral is completed, the RDT isretrieved by releasing the selective landingtool (SLT), and both the RDT and SLT arepulled from the well.

13. The lower wellbore section is cleaned out, theisolating bridge plug is retrieved and the mainbore is ready for completion.

23Winter 1998

(continued on page 27)

Since multilateral drilling began in the MiddleEast during the mid-1990s, it is estimated thatmore than 200 horizontal wells have beendrilled in the region. In the United ArabEmirates, Zakum Field Development Co.(ZADCO) and its operating company Abu DhabiMarine Operating Co. (ADMA-OPCO) are devel-oping one of the largest Middle East oil fields.The experience of ZADCO with various aspectsof multilateral horizontal drilling is typical ofthe state of this technology.

Zakum field, discovered in 1963, is situatedoffshore in the Arabian Gulf about 80 km [50 miles] northwest of Abu Dhabi. The producing formation is a large Cretaceous limestone with various layers in three mainstacked reservoirs (above). Development beganin 1977 with conventional drilling. Horizontaldrilling was introduced in 1989 and extensivemultilateral drilling commenced in 1994 as a

result of improvements in horizontal technology.The first multilateral well was completed inMarch 1995. Encouraged by a significant pro-duction increase, ZADCO decided to develop thestacked reservoirs using horizonal and multilat-eral drilling. To date, 39 dual-lateral and 45 mul-tilateral wells have been drilled and completed,and more are planned.1

During initial development, the complex ofreservoirs was penetrated by a deviated well-bore and then by a single horizontal drainholethrough most of the layers. These two tech-niques increased borehole exposure to thereservoir and allowed oil to be produced fromthe highest permeability layers, but oil in lesspermeable layers was left behind with subse-quent substantial loss of reserves. Drilling sepa-rate drainholes for subzones provides a betteropportunity for stimulation and enhanced pro-duction because each horizontal hole is con-nected directly to the main wellbore.

Drilling MultilateralsLevel 2 multilateral wells at Zakum field beginwith a deviated section. After surface and inter-mediate casing are cemented, wells are deep-ened to 95⁄8-in. production casing or 7-in. linerdepth just above lower reservoir targets withmaximum inclination of 55° to facilitate wire-line operations. Using a retrievable whipstock, acasing window is milled near the top reservoirand the upper drainhole is drilled using inter-mediate- and short-radius techniques. The whip-stock is removed so that multiple openholesidetracks and laterals can be drilled. The nexthorizontal hole is kicked off below the produc-tion casing string. Wellbore inclination isincreased to horizontal and a lateral is drilledinto the reservoir. A new deviated section isdrilled from the last kickoff point and anotherlateral is drilled using the same procedures.Specialized or custom profiles, like stair-steps tomaximize footage in certain intervals, can alsobe used (next page, top).

Curves are drilled with dogleg severity rang-ing from 6°/100 ft [31 m] to 10°/100 ft depend-ing on reservoir requirements and whethermedium- or short-radius techniques are used.Horizontal sections are typically 750 to 3000 ft[229 to 396 m] and the common hole size is 6 in. Position and direction in thin oil layers are achieved using measurements-while-drilling(MWD) and logging-while-drilling (LWD) tokeep well trajectory within the required reser-voir target interval.

Successful multilateral drilling depends onseveral factors, including zonal insolation, win-dow milling, drilling dense barriers, early waterbreakthrough, low-departure targets, low-per-meability zones, staying within targets, multipleholes from a single casing window and stimula-tion of multilateral openholes (next page, bottom left).2

Multilaterals in the Middle East

0 100 km

0 63 m

Zakumfield

Bahrain

United ArabEmirates

Qatar

SA

UD

IA R A B I A

less than5 mD

less than5 mDWest East

I1, I2I3I4I5I6I7

IIIA

IIIBIIIC

IIIDH

IIIJ

IIAIIBIICIID

IIEIIF

AbuDhabi

> Zakum field location and geology. Locatednorthwest of AbuDhabi in the ArabianGulf, Zakum field pro-duces from threestacked reservoirswith various layers in a large Cretaceouslimestone. Threemajor producing reser-voirs—I, II and III—are subdivided according to lithology.

1. Siddiqui TK, El-Khatib HM and Sultan AJ: “Utilization Of Horizontal Drainholes In Developing MultilayeredReservoir,” paper SPE 29879, presented at the SPEMiddle East Oil show, Bahrain, March 11-14, 1995.

2. El-Khatib H and Ismail G: “Multi-Lateral Horizontal DrillingProblems & Solutions Experienced Offshore Abu Dhabi,”paper SPE 36252, presented at the 7th Abu DhabiInternational Petroleum Conference and Exhibition, Abu Dhabi, UAE, October 13-16, 1996.

24 Oilfield Review

Zonal isolation— The ability to achieve isola-tion is key to multilateral well success. Betweenupper laterals and lower drainholes, zonal isola-tion is extremely important due to pressure dif-ferential between the two reservoirs. Cementadditives and operations were optimized toimprove primary cement bond in addition to theuse of external casing packers (ECP) on the pro-duction casing in some wells (above).

> Drilling Zakum field multilateral wells. The drilling sequence for a Level 2 Zakum field multilateral is as follows: A. Surface and intermediate casing are set and wells are deepened to production casing or liner depth just above the reservoir targets. Maximum inclination is 55° to facilitate wirelineoperations. B. A window is milled in the casing and the upper drainhole is drilled using intermediate- and short-radius techniques. C. The next horizontalhole is kicked off below the production casing string. D and E. New deviated sections are drilled from previous kickoff points so that more laterals can bedrilled. F. Multilaterals with stair-step, traverse or other profiles can be drilled to minimize drilling in tight barriers, maximize horizontal footage in pro-ductive intervals and delay water breakthrough.

(dense) (dense) (dense)

(dense)

(dense)

IAIIIIA

IIBIICIID

133/8-in. casing 30-in. casing

95/8-in. casing

133/8-in. casing 30-in. casing

95/8-in. casing

133/8-in. casing 30-in. casing

95/8-in. casing

133/8-in. casing 30-in. casing

95/8-in. casing

IAIIIIA

IIBIICIID

IA

IIA

IIBIICIID

IAIIIIA

IIBIICIID

A B C

D E

II

IA

IIAIIB

IIC

IID

IIE

II(dense)II

F133/8-in. casing 30-in. casing

133/8-in. casing 30-in. casing

95/8-in. casing

95/8-in. casing

81/2-in.hole

IAII (dense)IIAIIBIIC

IIEIID

133/8-in. casing

95/8-in.casing

200010000

-1000-2000-3000

IA

IIDEIIBIIC

Departure, ft

IAIIAIIBIICIIDIIE

II (dense)

81/2-in. hole

95/8-in. casing shoe 6-in. hole

6-in. hole6-in. hole

dense

-1000

0

-2000-3000-4000

1000

2000

3000

4000

Departure, ft

Latit

ude,

ft

IIIJ branch 1IIIJ branch 2

IIIF IIIG

95/8-in. casing shoe

95/8-in.casing shoe

III

IIIF

IIIG1

IIIJ Branch 1 Branch 27-in. liner shoe

IIA

IIA-D

IIG-F

IIA

95/8-in. casing

95/8-in.whipstock

133/8-in. casing

New 7-in. liner shoe

1000

-100

0

-200

0

-300

0

2000

3000

Latit

ude,

ft

Departure, ft

IA

IA

IICDIICD

IIEF

IIEF

Sidetrack

Original hole

-1000

0

-2000-3000-4000

1000

2000

3000

4000

Departure, ft

Latit

ude,

ft

IA IIC

IIFIIDIIE

Branch 2 Branch 1

Branch 1

Branch 1

Branch 2

Branch 2

TH.IATH.IIATH.IIBTH.IICTH.IIDTH.IIE

TH.IIFTH.III (dense)

60°inclination

35° inclination 75° inclination

7-in.liner shoe

A B

C D

(dense)

> Multilateral wellbore profiles these can include: A. Hook shapes for low-departure multilateralwells. B. Two branches in thin and tight reservoirs. C. Two opposing branches for target centralization.D. Multilateral holes from one window to minimize casing cement bond failure.

TH.IA reservoir

TH.II (dense)

TH.II reservoir

95/8-in. casing shoe

Perforations

95/8-in. Externalcasing packer (ECP)

81/2-in. hole

> Zonal isolation. In addition to optimizingcement slurries to improve primary cement jobs, external casing packers (ECP) are sometimes used to separate certain intervals.

25Winter 1998

(continued on page 26)

Window milling—Using retrievable whip-stocks and removal of these assemblies are criti-cal to successful drilling of multilateral wells.More than 40 horizontal wells have been side-tracked with retrievable whipstocks. New single-trip whipstocks reduce the number of trips andthe time necessary to exit the casing (right).

Drilling dense barriers—Because Zakumfield porous layers are separated by tight reser-voir rock, different techniques were adopted tominimize drilling in these dense, low-permeabil-ity barriers and maximize horizontal footagewithin specific reservoir zones to improve oilrecovery. The technique of stair-step drillingthrough various reservoir layers is operationallydifficult because of low angles of incidencewhen trying to cross barriers. Another tech-nique, drilling separate drainholes for eachreservoir zone, resulted in postdrilling problemsassociated with production monitoring and stim-ulation of individual drainholes.

Early water breakthrough—Multilateralwells are drilled to avoid or delay water break-through by selecting the horizontal section posi-tion and length within desired layers based onspecific reservoir requirements.

Low-departure targets—Another challengewas drilling multilateral wells with targets lessthan 1000 ft [305 m] from the platform well-heads. Various options were considered to drillthe deviated sections of these low-departuremultilateral wells, but a hook-shaped profilewas found to be operationally and economicallythe best. This well profile can be designed tohave sufficient inclination to use previously suc-cessful medium-radius drilling. Several hook-shaped multilateral wells with four drainholesfrom the main bore were successfully drilledand completed.

Low-permeability zones— One benefit of amultilateral approach is the ability to exploitthin reservoirs. Developing stacked low-perme-ability limestone oil reservoirs is typicallyunattractive because of anticipated early waterbreakthrough in vertical or deviated wells. Oneof the field’s reservoirs that held substantial oilin place was a 8 ft [2.5 m] thick zone with 6-mDpermeability. Two branches were drilled in dif-ferent directions to increase the drainage areaand improve production. The number and geom-etry of the branches were dictated by reservoircharacteristics.

Staying within targets—Another challengefor drilling multilateral wells is to correctlyposition and maintain horizontal sectionswithin existing sweep patterns. Since branchesdrilled in opposing directions were found to be

optimum, severe left- and right-turning trajec-tories must be drilled to achieve the requiredreservoir exposure. A significant increase inproduction rates was observed in wells drilledin this manner.

Multiple holes from a single casingwindow—Several drainholes were successfullydrilled from the same main borehole after exit-ing casing in reentry and new wells. This proce-dure can avoid the time and expense of multiplecasing exits, but does limit the ability to moni-tor and stimulate laterals.

Stimulation of multilateral openholes—ZADCO uses openhole completions that com-mingled production from reservoirs I and II.Production from these two main reservoirs iskept separate using dual-tubing completion.Because of the inability of current through-tub-ing stimulation systems to access each drain-hole selectively, common practice is tobullhead stimulation treatments—pump downthe production tubing from suface. When possi-ble coiled tubing was run through the produc-tion tubing to selectively treat individualopenhole laterals in the main reservoirs.

Permeability variation in each productivelayer requires that acid be diverted across allintervals where coiled tubing is unable toreach total depth. Techniques using divertingadditives and procedures integrally combinedwith stimulation acid treatments are successfulin increasing the productivity of some multilat-eral wells, but in many wells these diversiontechniques cannot effectively stimulate the

desired number of laterals. Production logs arebeing used to further evaluate stimulationeffectiveness as well as design and proceduralmodifications.

Future MultilateralsMultilateral drilling in Zakum field provided anopportunity to improve recovery and managefield production more efficiently. Some 84 newand reentry Level 1 and Level 2 multilateralwells, from single and dual laterals up to sevenlaterals, were drilled and completed success-fully in the last four years. Multilateral horizon-tal drilling brought new life to the field’s thin,low-permeability reservoirs where developmentby deviated or vertical wells had not been effec-tive. Horizontal wells with branches in opposingdirections were the optimum solution. Thefuture challenge is to conduct independentoperations in each lateral and overcome zonalisolation difficulties.

After comparing drilling costs for differenthorizontal well types—medium, intermediate-radius and short-radius—ZADCO determinedthat short-radius drilling is more expensive thanmedium-radius wells, but short-radius wells arebetter in terms of production compared withvertical wells. Through rapid growth in short-radius drilling technology, the cost per foot ofhorizontal drilling was reduced by 30% afterdrilling 27 horizontal sections in ten wells.Lower costs, resulting from steerable drillingtechnology, encouraged ZADCO to continuedrilling multilateral horizontal wells.

4.8

2.6

1.6

0

1

2

3

4

5

6

Mechanical

Hydraulic

Single-triphydraulic

Win

dow

mill

ing

dura

tion,

day

s

Mechanical Hydraulic Single-triphydraulic

> Retrievable whipstock and anchor window milling performance.

26 Oilfield Review

Short-radius wells, small-diameter wells andmultiple radial slimholes are now being drillednot only in the Texas Austin Chalk region, butalso in areas like the Middle East and SoutheastAsia. In Alaska, USA, for instance, BP and Camcohave drilled multilaterals with build angles ofaround 1.8°/ft, changing the well from vertical tohorizontal in approximately 50 ft [15 m]. Thissteep build rate produces less formation damage,requires less time for drilling to target, uses lessdrilling fluid, and is generally more economical.

Small-diameter boreholes are drilled toreduce cost, and multiple slimhole horizontalreentries can be drilled from small-diameterwells to further increase reservoir exposure.Coiled tubing is also employed to drill multipleradials from the main bore. Coiled tubing drillingis frequently used to remove near-wellbore for-mation damage to increase reservoir flow poten-tial, but in the Snorre field, Norway, for example,has also been used for drilling drainholes toreplace perforations.

Multilateral reentry is not the sidetrackingtechnique used for decades to salvage old well-bores that would otherwise have to be aban-doned. Rather, it is an evolving technology forproducing from and working over both the mainbore and the laterals. Determining the right tech-niques for reentering multilateral wells to per-form stimulation, acidizing, perforating or anyother fluid pumping operation is a key problemconfronting the oil industry today. As well config-urations become more complex, the degree ofdifficulty increases.

Two major challenges are reentering a singlebranch at a specific depth and reentering multi-ple branches at the same depth. In addition, com-pletion type, whether openhole or cased, thehole size and the vertical-to-lateral build raterepresent primary factors involved in the selec-tion of proper reentry techniques. The need tohydraulically isolate laterals impacts the choiceof solution as well.

Reentry is a two-step operation: recognize theentry point and enter the lateral. One recognitionmethod is accomplished by running a tool oncoiled tubing that rotates to reentry depth. Thetool has a bend on the end that provides a surfaceweight change indication when the bend enters alateral opening. The Schlumberger coiled tubingVIPER system also has a bottom orientation subthat is used to locate and access laterals.

Mechanical methods are another way ofachieving lateral entry. In a minimum of threeruns, a whipstock diverting device is set; coiledtubing work is performed; and the diverter isretrieved. The tool carrying the diverter controlsdepth as it lands on a predefined tubing or casingprofile nipple. The nipple provides tool orientationand allows the diverter to be located accurately atthe lateral opening. This technique is used withcompletion equipment designed specifically forthrough-tubing reentry into laterals.

Reentry technology is evolving towards viableand reliable systems most likely based on a cas-ing profile nipple or a tubing nipple and portedtubing sub aligned with the casing window, towhich a bottomhole assembly will attach. An ori-entation locator coupled with upper and lowerpacker assemblies will find the orientation nippleand align the lateral access joint in the correctdirection. A landing nipple plug will be used toisolate the lower packer or window joint for test-ing. An orientation device to accept a coiled tub-ing-conveyed diverter will facilitate access to thelateral opening for reentry.6

Wellbore ManagementIn production engineering and operation of multi-lateral wells, the key considerations are whethera well needs artificial lift and the degree to whichimposed formation pressure drawdown isaffected by frictional pressure drop inside thewell. For example, short opposed laterals arepreferable to a long, single horizontal well in onedirection if drawdown is about the same as pres-sure drop in the wellbore. Conversely, if draw-down is several hundred psi, or more, a singlehorizontal leg may be adequate.

Selective wellbore control is provided bythree basic completion configurations: individualproduction tubing strings tied back to surface,commingled production, and commingled produc-tion from individual branches that can be reen-tered or shut off by mechanical sliding sleeves orplugs. These options relate directly to reservoirmanagement because the need for selective con-trol increases as wellbores are opened to moreareas of the reservoir. For example, laterals thatdrain multiple layers or different formationsrequire selective management if pore pressuresand fluid properties differ widely between zones.The degree of communication between thedrainage areas of individual laterals may be themost important reservoir engineering issue inmultilateral applications.

There are logistical and operational issues incompleting certain well systems that may bedictated by obvious reservoir exploitation strate-gies and schemes. Currently, multilateral wellscan be constructed with connectivity, isolationand access. Numerous completion choices areavailable. The following three configurations arecommon: • Drain several stacked layers that may not be in

communication• Drain a single layer in which areal permeability

anisotropy is critical• Drain geologic compartments that may not be

in communication.Draining stacked layers favors a vertical

main bore, but heterogeneous and com-partmentalized reservoirs favor a singlehorizontal well, dual-opposing laterals, or multi-branched wells. Commingled production fromstacked laterals is analogous to commingledproduction from two or more layers in a verticalwell. The two main advantages of stacked later-als are that each lateral has greater productivitythan a conventional vertical completion throughthe same layer, and that control of verticalinflow, or conformance, is facilitated becausethe productivity of each lateral is approximatelyproportional to its length. Vertical flow confor-mance avoids differential depletion under pri-mary production and uneven water or gasbreakthrough under secondary production.7

Future Multilateral TechnologyOptimal multilateral connectivity will depend onthe development of reliable junctions betweenthe main bore and laterals as well as new com-pletion strategies to connect more lateral well-bores with productive reservoir intervals. A firststep will be the improvement of casing windowsto facilitate efficient drilling and reentry of multi-ple lateral drainholes. Many in the industrybelieve that a technique must be developed toseal casing window connections. Considerableeffort is being expended to perfect a reliablemechanical seal or new chemical sealants forTAML Level 6 wells to provide pressure integrityat the junction. Others maintain that the vastmajority of multilaterals exit the main bore intothe same reservoir, where the pressure differen-tial at the junction is negligible. They advocatethat, rather than pressure integrity, priority begiven to developing fit-for-purpose junctionintegrity to increase production and the ability tomanage laterals over the life of a well.

27Winter 1998

6. Turcich TA: “Pressure-Control Engineering,” presented atthe SPE Fourth European Coiled Tubing Roundtable,Aberdeen, Scotland, November 19-20,1997.

7. Ehlig-Economides et al, reference 4.

Downhole construction of lateral junctionshas associated problems such as generatingdebris and lack of cementing options. Surfaceconstruction, as in Level 6S wells, which can bedone for new wells only, is debris-free, but lim-ited to shallow wells.

There are also opposing opinions about con-struction of casing windows. Construction down-hole favors milling standard casing byreferencing inexpensive casing profile nipples orpackers. Multiple nipples can be designed intocasing strings, permitting operators to choose

sidetrack locations when they are ready and pro-viding a reentry sleeve reference as well.Another possibility is to run a composite casingsection with a profile nipple below it from whichthe drilling whipstock and lateral entry systemsleeve can be spaced. Although there is nomilling, casing strength is compromised (left).

Premilled windows or casing stock that hasremovable sleeves or is encased in drillable mate-rial are promoted by many to provide tensilestrength without having to mill downhole. As withcomposites, the whipstock and lateral entry sys-tem sleeve are deployed through casing nipples.Generally, lateral casing is allowed to protrudeinto the main casing, where it is cemented inplace and then milled or washed over to restorefull main bore diameter. Both mechanical andpressure-tight tie-backs are being developed.8

Other technical issues need to be resolved aswell, including the management and monitoringof production. Downhole control of flow withremotely operated chokes and other flow devicesthat independently optimize individual lateralsand selectively shut-off zones to block water andgas—intelligent completions—will aid produc-tion management. Downhole permanent gaugesfor each lateral are also on the drawing board tomonitor changes in pressure, temperature, flowrate, and water and gas cut. When connected tosurface systems, these advances will permitadditional surface measurement and eventually,the allocation of flow from each lateral. Selectivereentry will permit servicing of these devices andsensors, and allow batch treating of each lateral.

Future multilateral wells will involve fewertrips into the well, incorporation of sealed lateraldevices, and a full range of downhole controlsand sensors to regulate flow, pressure and multi-phase differentials. Downhole fluid separationand injection will be accomplished with surfacecontrol, and expensive rig interventions will bevirtually eliminated by electrohydraulic control ofdownhole functions. This trend will reverse therisk-reward ratio offshore, where risks are highand reserves are large, in favor of multilaterals(left). Ultimately, multilateral well technologywill be the basis for the intelligent completionsthat will one day yield remotely operated subter-ranean and subsea factories with oil and gas asthe finished products. –DG, DEB, RR, MET

41/2-in. upper tubing 133/8-in. casing

Top of liner3680 ft, TVD

M-seal sealant

Window bushingassembly

Top of window3858 ft, TVD

7-in. composite joint

Hollow whipstockOrienting latch

Multilateral packerOrienting nipple

Retrievable packer

TD 8439 ft, MD

41/2-in. predrilledcasing

61/8-in. open hole61/8-in. open hole

9

5/8-in. casing 7-in. liner 4798 ft, MD

TD 8439 ft, MD

> Composite casing section with a nipple profile.

> Intelligent completions. Future multilateral completions may involve many processes, from formationdrainage to downhole separation, inflow control, injection and reservoir monitoring.

28 Oilfield Review

8. Turcich, reference 6.

Tim J. BourgeoisKen BramlettPete CraigShell Deepwater Production, Inc.New Orleans, Louisiana, USA

Darrel CannonKyel HodenfieldJohn LovellSugar Land, Texas, USA

Ray HarkinsIan Pigram ARCO British LimitedGuildford, Surrey, England

For help in preparation of this article, thanks to Dave Bergt, Schlumberger Oilfield Services, Sugar Land,Texas, USA; Ted Bornemann, Bill Carpenter, Frank Shrayand Rachel Strickland, Anadrill, Sugar Land, Texas; Joseph Chiaramonte and Darwin Ellis, Schlumberger-DollResearch, Ridgefield, Connecticut, USA; Craig Kienitz,Anadrill, The Hague, The Netherlands; Martin Lüling,Schlumberger Riboud Product Center, Clamart, France;Dave Maggs, Anadrill, New Orleans, Louisiana, USA; andDavid Robertson, Forest Oil, Denver, Colorado, USA.ADN (Azimuthal Density Neutron), ARC5 (Array ResistivityCompensated), ARC675, CDR (Compensated DualResistivity), ELAN (Elemental Log Analysis), FMI (FullboreFormation MicroImager), GeoVISION675, PowerPulse, RAB(Restivity-at-the-Bit), TLC (Tough Logging Conditions),VISION475, VISION675, VISION First Look and VISION TelemetryProtocol are marks of Schlumberger.

Logging-while-drilling (LWD) technology becameavailable a mere ten years ago. At that time, thetools fulfilled the primary purpose of theirdesign, which was to aid in correlation. Within acouple of years, the industry had found six mainapplications for these tools—applications thatremain key today:

Formation evaluation—Real-time correlationand evaluation allow coring and casing pointselection. Logging before extensive invasionoccurs may reveal hydrocarbon zones that can besaturated with borehole fluid by the time wire-line logs are run.

Multiple-pass logging—Comparison logsmade at different times can help distinguish payfrom water zones, locate fluid contacts and iden-tify true formation resistivity (Rt). Permeablezones may be identified from time-lapse filtratemovement.

Insurance logging—Logs obtained whiledrilling provide contingency data in case the wellis lost or when conditions create boreholes thatyield poor-quality wireline logs.

Cost reduction—Running wireline tools inhigh-deviation wells requires conveyance bydrillpipe. In some cases, these wells can belogged with LWD tools, either while or immedi-ately after drilling, saving rig time offshore or inwells otherwise needing the TLC Tough LoggingConditions system.

Enhancing drilling safety and efficiency—Measurements while drilling provide real-timedata on drillstring mechanics, fluid dynamics andpetrophysics for assessing pore pressure andwellbore stability and for drilling program andcompletion strategies (see “Using DownholeAnnular Pressure Measurements to ImproveDrilling Performance,” page 40 ).

Geosteering—By comparing real-time logresponses to an expected model, the wellboretrajectory is modified, thereby placing the well inthe most productive portion of a pay zone.

As the real-time nature of LWD informationbegan to be fully exploited, the early emphasison correlation in the late 1980s gave way to dom-inance by geosteering and well-placement appli-cations. Availability of LWD data permitted safeand efficient drilling of exotic trajectories andextended-reach and multilateral wells that wereunimaginable ten years ago (see “Key Issues inMultilateral Technology,” page 14 ). These wellsfrequently make headlines in industry journalswhen technological advances contribute tobreaking existing directional drilling records.1

Pushing the Limits of FormationEvaluation While Drilling

Through a few case studies this article demonstrates how new

logging-while-drilling measurements are being used to open

frontiers and evaluate formations as soon as they are encountered.

29Winter 1998

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

Many of the LWD innovations that havehelped directional drillers master the art and sci-ence of geosteering are also advancing the causeof assessing reservoir quality while drilling.Forward modeling routines have been developedthat allow real-time comparison between pre-dicted and observed logs, helping drillers stay inthe pay.2 This modeling capability also lets inter-preters evaluate LWD data for petrophysical andfluid properties and for geologic structure.

Oil company interpreters are becoming morefamiliar with while-drilling measurements,understanding their departure from wireline-style logs, and trusting them. Operators are alsodemanding more measurements for more holesizes, and as a result, a broader range of servicesis being offered. The more comprehensive reser-voir assessment that is now possible makes LWDformation evaluation results valuable not only forwellsite decisions, but also for longer term reser-voir planning and development—as wireline log-ging results have been all along.

Ten years ago, the available LWD measure-ments were gamma ray, neutron porosity, litho-density, photoelectric effect and phase-shift andattenuation resistivities.3 In the interim, techno-logical advancements have vastly improved andenhanced these basic measurements and evenadded new formation evaluation measurementsnot previously available in the logging industry.First came azimuthal or quadrant measurementssuch as the quadrant density and photoelectricfactor (Pe) on the ADN Azimuthal Density Neutrontool and the quadrant gamma ray and real-timeresistivities on the RAB Resistivity-at-the-Bit tool.Then came quantitative images with multiple-depth resistivity images from the RAB tool anddensity images from the VISION475 system. Theaddition of multiple depths of investigation to theazimuthal data has created new opportunities tocomplete the formation evaluation picture.

The comprehensive Schlumberger VISION475system (the nominal outer diameter of the tool is4.75 inches) encompasses the enhanced technol-

ogy to provide formation evaluation and drillingmeasurements in 53⁄4- to 63⁄4-in. holes. In additionto direction, inclination and toolface, theVISION475 tool makes a neutron porosity mea-surement, azimuthal readings of lithodensity, Peand gamma ray, and records 2-MHz phase-shiftand attenuation resistivities at up to ten depthsof investigation.

Deciphering phase-shift measurements withmultiple depths of investigation for resistivityinterpretation has become common practice inthe industry. However, the inclusion of attenua-tion resistivity measurements with multipledepths of investigation has brought additionalvalue to the petrophysicist. Although acquiredwith the same transmitter-receiver spacing, theattenuation measurement has a greater depth ofinvestigation than the corresponding phase-shiftmeasurement. These complementary measure-ments offer an opportunity to understand moreabout the fluid and resistivity characteristics ofthe formation. For example, comparison of atten-

> Possible oil-water contacton phase-shift resistivity. The gamma ray (GR) in track 1 shows sand from7740 to 8020 ft, and thephase-shift resistivity intrack 2 indicates the zoneabove 7920 has high resistivity—a possible payzone above the oil-watercontact. Attenuation resistivity in track 3 showsthe possible oil layer to be toa zone of resistive invasion,and not worth completing.

30 Oilfield Review

>

uation and phase-shift resistivities provides adiagnostic method for differentiating betweenborehole fluid invasion and formation anisotropy,a technique discussed later in this article

In one case from a Forest Oil well in the Gulfof Mexico, the while-drilling gamma ray (GR)indicated a sand from 7740 to 8020 ft and thephase-shift resistivities identified a possible oil-water contact at 7920 ft (previous page). The fivephase-shift resistivities, each with a differentdepth of investigation, have very little separa-

tion, which indicates little to no invasion. A sim-ple resistivity index calculation yields 38% watersaturation, making the potential oil layer a candi-date for testing.

However, the attenuation resistivities that aresimultaneously recorded by the VISION475 toolappear to contain evidence to the contrary. Thesedeeper reading resistivities show significant sep-aration, with the deepest measurement—anapproximately 30-in. [75-cm] depth of investiga-tion from the 34-in. receiver-transmitter spac-ing—recording the lowest resistivity of about 0.4ohm-m. This profile indicates resistive invasion,which might be expected for wells drilled withoil-base mud, but this was water-base mud witha resistivity, Rm, of 0.1 ohm-m. However, forma-tion water resistivity, Rw, in this zone is approxi-mately 0.03 ohm-m, causing the resistiveinvasion profile. When formation resistivity iscomputed by inversion processing that takesinvasion into account, the zone shows 100%

water saturation. If this zone had been com-pleted, a significant investment would have pro-duced only water. The extra information broughtby the deeper reading attenuation measurementsavoided the cost of an unnecessary completion.

Extracting meaningful information from thetwo-receiver, five-transmitter tool configuration toprobe five depths of investigation each for phase-shift and attenuation resistivity requires carefulborehole compensation and borehole correctionof the measurements. Without borehole correc-tion, washouts together with conductive mud canmasquerade as invaded or anisotropic zones.Borehole rugosity can cause spikes, or resistivityhorns that may be misinterpreted as laminatedformations (above). Borehole compensation isnecessary because it significantly reduces theeffects of borehole rugosity and precisely cancelsmeasurement errors caused by gain and phase-shift differences in the receivers’ electronics,which typically vary with temperature.

> Borehole compensation for accurate VISION475 multidepth measurements. Without borehole compensation and correction (top), spikes andseparations in the curves of the phase-shift resistivity measurements cannot be interpreted reliably. With correction (bottom), high-resolutiondata and curve separations can be identified and interpreted.

31Winter 1998

2. Bonner S, Burgess T, Clark B, Decker D, Orban J,Prevedel B, Lüling M and White J: “Measurements at theBit: A New Generation of MWD Tools,” Oilfield Review 5,no. 2/3 (April/July 1993): 44-54.Bonner S, Fredette M, Lovell J, Montaron B, Rosthal R,Tabanou J, Wu P, Clark B, Mills R and Williams R:“Resistivity While Drilling—Images from the String,”Oilfield Review 8, no. 1 (Spring 1996): 4-19.Allen D, Dennis B, Edwards J, Franklin S, Livingson J,Kirkwood A, White J, Lehtonen L, Lyon B, Prilliman J andSimms G: “Modeling Logs for Horizontal Well Planningand Evaluation,” Oilfield Review 7, no. 4 (Winter 1995): 47-63.

3. Bonner S, Clark B, Holenka J, Voisin B, Dusang J,Hansen R, White J and Walsgrove T: “Logging WhileDrilling: A Three-Year Perspective,” Oilfield Review 4, no. 3 (July 1992): 4-21.

A series of logs from a Shell deep-water pro-ject in the Gulf of Mexico demonstrates theimpact of adding still more LWD measurementsto the interpretation. In this highly deviated well,the standard GR, rate of penetration (ROP),phase-shift resistivity and average density andneutron data indicate a homogeneous formationin this potential pay zone (above). The well wasdrilled with high-salinity drill-in fluid, and phase-

shift curves exhibit a conductive invasion profilewith the deepest spacing at 34-in. measuring thehighest resistivity, about 4 ohm-m. Resistivityprocessing to compensate for the invasioneffects would correct Rt to above 4 ohm-m.

This is the limit of information available froma conventional “triple combo” be it LWD or awireline system, and it appears to give arespectable interpretation of the reservoir, butthe VISION475 system provides more informationand sheds new light on the reservoir interval.

If this were truly a conductive invasion profile,as the phase-shift measurement indicates, thedeepest attenuation curves would show higherresistivity than the deepest phase-shift curves.However, all the attenuation outputs read alower resistivity than even the shallowest phase-shift curve. This is an example of resistivityanisotropy—a difference in resistivity valuedepending on the direction in which the mea-

> Formation evaluation while drilling in the Gulf of Mexico. In this highly deviated well the GR and ROP in track 1, phase-shift and attenuation resistivities intracks 2, 3 and 4, and average density and neutron data in tracks 3 and 5 indicate a homogeneous pay formation. Phase-shift resistivity curve separationsuggests conductive invasion, but this is not confirmed by attenuation resistivities; resistivity anisotropy is responsible. Quadrant displays of density, on top,bottom, left and right of the borehole, are in tracks 6 and 7.

32 Oilfield Review

surement is made (see the first case study from 7700 to 7740 ft for anotherexample of anisotropy, page 30 ).4

In vertical wells penetrating horizontal layers with no invasion, 2-MHztools measure horizontal resistivity, Rh. This is taken as equivalent to Rt, theresistivity input to most formulae derived to predict fluid saturation, and soserves as the reference, or threshold, by which formations are judged to con-tain pay or not. At other angles, for example, in highly deviated and horizon-tal wells passing through horizontal layers, 2-MHz tools respond to somecombination of vertical and horizontal resistivities. Vertical resistivity (Rv), orresistivity perpendicular to bedding, is always at least as much as, and usu-ally more than, horizontal resistivity—sometimes reaching a 10 to 1 ratio (see“Anisotropy and Invasion,” next page ).

In the case at hand, the phase-shift curves are each reading a differentcombination of horizontal and vertical resistivity, depending on the transmit-ter-receiver spacing. Formation resistivity, Rt, is not greater than 4 ohm-m, aswould have been calculated by a radial-invasion resistivity inversion program.An anisotropy inversion program can be used to calculate Rh and Rv, and thenRh is used in water saturation calculations to derive Sw.

Density curves from the VISION475 log also provide more information thanprevious-generation LWD density tools, which combine weighted averages ofdensity from all around the borehole. The density and Pe measurements ofthe VISION475 tool are recorded in 16 oriented sectors. These can be displayedeither as an image, or presented as four quadrants—top, bottom, right andleft—as the drillstring rotates (below).

For a first view, the bottom and average densities can be compared forconsistency (previous page). This log was recorded in a highly deviated well,so the bottom-quadrant density, in closer contact with the borehole, shouldgive the best quantitative data. In this interval, not only does the bottom-quadrant density disagree with the average density, but it also occasionallymeasures a lower bulk density. This appears strange because assuming thebottom of the tool is in contact with the formation also implies that the topof the tool is not. When that occurs, the mud density, which here is less thanthat of the formation, should influence the top-quadrant reading and as aresult, the average density would tend to be lower.

Taking the next step in evaluating this well, all four quadrant densities arepresented with photoelectric factor and bulk density correction for each quad-rant (left). The right and left density quadrants agree well throughout theentire interval. The top and bottom quadrant densities not only disagree, butcross each other. A threaded borehole, borehole breakout, or a combinationof heavy mud and hole conditions could explain this unusual response. Theresponse could also be due to a position change of the borehole assembly in

< What quadrant densities mean. Density mea-surements are gathered into four quadrants—top, bottom, right and left—as the drillstringrotates. If the VISION475 tool cuts across a layerboundary with a near full-gauge stabilizer (left),all quadrant measurements are quantitative. The view is along the tool axis, which in thiscase is also in the plane of the layer boundary.Quadrant density measurements readily definethis boundary, providing a distinct bulk density in each layer. Without a stabilizer (right) the tooltends to lie on the bottom side of the hole, givingbetter borehole contact and so better quality to the bottom quadrant measurement. The topquadrant measurement would be qualitative due to the standoff distance.

33Winter 1998

4. Anderson B, Bryant I, Lüling M, Spies B and Helbig K: “Oilfield Anisotropy: Its Origins andElectrical Characteristics,” Oilfield Review 6, no. 4 (October 1994): 48-56.Lüling MG, Rosthal RA and Shray F: “Processing and Modeling 2-MHz Resistivity Tools inDipping, Laminated, Anisotropic Formations,” Transactions of the SPWLA 35th AnnualLogging Symposium, Tulsa, Oklahoma, USA, June 19-22, 1994, paper QQ.

>

Many resistivity logs exhibit a combination ofanisotropy, invasion and shoulder (adjacent)bed effects, and each effect must be taken intoaccount to deduce true formation resistivity.

Resistivity anisotropy can be caused by layer-ing, lithology or fluid content. It is typicallyexpressed as the ratio of vertical to horizontalresistivity, Rv/Rh, and its effects on tool responsecan be understood by modeling. The standardresponse of 2-MHz tools in vertical wells pene-trating horizontal layers with no invasion istaken as the reference, and tool response to lay-ers at other relative angles can be computed(below left).

In this model the formation consists of a sandinterbedded with an equal amount of shale foran anisotropy ratio Rv/Rh of 6.7. As the relativeangle increases, the apparent resistivity mea-sured by both phase shift and attenuationincreases. Above 45 degrees, the effect isgreater on the longer spacings; for example, thephase-shift 34-in. curve measures a higherapparent resistivity than the phase-shift 28-in.curve. The curve order resembles a conductiveinvasion profile, and therefore may be misinter-preted. Anisotropy can cause resistivities mea-sured in high-angle wells to be deceptively high.

Two keys are used to distinguish conductiveinvasion from anisotropy. The first is comparisonof phase-shift to attenuation measurements:although phase-shift resistivities indicate a con-ductive invasion profile, corresponding attenua-tion outputs measure lower resistivity. Ifconductive invasion were causing the phase-shiftcurve separation, the deeper reading attenuationoutputs would measure a higher apparent resis-tivity than the phase-shift curves. This is animportant use of attenuation measurements. Thesecond key is revealed in the modeled exam-ple—the curves are uniformly separated whenviewed on a logarithmic scale. Uniform separa-tion is less common with invasion.

If anisotropy can be identified in sands, it isusually an indication of hydrocarbons. However,in anisotropic formations that are hydrocarbon-bearing, deep invasion could hide theanisotropic response if Rmf and Rw are similar.1

To understand the effect of invasion on ananisotropic formation, a state-of-the-art 3Dfinite-difference code was developed that com-putes phase-shift and attenuation responseswith increasing diameter of invasion.2

Resistivity responses were modeled for ananisotropic formaton whose anisotropy changeswith invasion (below right). The virgin forma-tion anisotropy ratio, Rvt/Rht, is 6.8, but onceinvaded, the anisotropy ratio falls to 1.25—nearly isotropic. This change will have differenteffects on the phase-shift and attenuation resis-tivity responses, depending on their depth ofinvestigation. For invasion diameters less than15 in., the anisotropy effect dominates.Anisotropy is recognizable by separated phase-shift curves reading higher than attenuationcurves. At invasion diameters greater than 50inches, the effects of invasion rule curve separa-tion. Measuring phase-shift and attenuationresistivities before extensive invasion is there-fore crucial when anisotropy is present.

Anisotropy and Invasion

> Effects of anisotropy on phase-shift and attenuation resistivities. Anisotropybecomes evident as the relative angle between bedding and tool axis increases.The curves resemble those seen in a conductive invasion profile except that withanisotropy, phase-shift curves read more resistive than attenuation.

> Effect of invasion on an anisotropic formation. In this formation, which isanisotropic before invasion, but less so after, modeling shows that for invasiondiameters less than 15 in., the anisotropy is still interpretable from phase-shiftand attenuation resistivity curves. After invasion diameters surpass 50 in., theeffects of invasion mask the anisotropy of the virgin formation.

34 Oilfield Review

1. Klein JD, Martin PR and Allen DF: “The Petrophysics ofElectrically Anisotropic Reservoirs,” Transactions of theSPWLA 36th Annual Logging Symposium, Paris, France,June 26-29, 1995, paper HH.

2. Anderson B, Druskin V, Habashy T, Lee P, Lüling M, Barber T, Grove G, Lovell J, Rosthal R, Tabanou J,Kennedy D and Shen L: “New Dimensions in ModelingResistivity,” Oilfield Review 9, no. 1 (Spring 1997): 40-56.

the wellbore caused by changes in wellbore incli-nation. But no interpretation guesses are neces-sary because the VISION475 system clearlyprovides the answer with density image data.

The density images reveal the detail of reser-voir configuration—a series of thin sands andshales dipping at varying angles relative to theborehole (below left). These VISION475 imagesprovide an easy and efficient means of interpret-ing complex data. The first track image is color-scaled to represent measured quantitativedensity variations, while in the second track thevariations have been enhanced by changing thecolor scale to bring out detail.

Throughout this interval, the azimuthal densityimaging was the only measurement to flag thesubtle sand-shale layering. The lessons learnedare twofold: first, the standard suite of GR, resis-

tivity, neutron and average density measurementsmay not always be sufficient for complete forma-tion evaluation. In this case, all the standard mea-surements pointed to a homogeneous zone.Clearly the revelation of a laminated sand-shalesequence can have an impact on the appraisal ofreservoir quality and its subsequent drainage.Second, techniques that assume maximum den-sity to be the correct density would greatly under-estimate porosity and distort the true reservoircharacter. This new information is valuable notonly to drillers in real time, but also to well plan-ners who may need to change future drilling tra-jectories, to completion engineers for effectingmore efficient completions, to reservoir engineersfor modeling and simulating production and togeologists for calculating structural dip.5

Invasion, Dip and GasThe previous examples show how LWD logsimprove formation evaluation in deviated oilwells with invaded zones, anisotropic layers andthin dipping beds. Determining accurate valuesof porosity and water saturation in gas wellsunder these conditions, however, has been aspecial problem that only recently is seeingsome resolution.

In vertical wells, depth of invasion of mud fil-trate into a formation depends on many factors,including mud properties and lithology, porosityand absolute and relative permeability of the for-mation. In the simplest case of a vertical hole ina homogeneous permeable formation, the inva-sion profile is radially symmetric. But whenimpermeable or dipping layers, or both, areencountered, the volume invaded by boreholefluid takes on a new shape (below right).

The invasion front becomes even more dis-torted in a gas zone, because the borehole fluid isso much heavier than the formation gas. Invasionbegins radially, but with time the heavier phase

g/cm3

ROP

RHOB Image

Gamma RayAPI

Image Orientation

g/cm3

Image OrientationU R B L U degrees0 90200 0

ft/hr

1:240 ApparentDip

TrueDip

0 90degrees

U R B L U

0 100

Dynamic RHOB Image

DEVI Deviation

Mea

sure

dDe

pth,

ft

2.05 2.45

XX300

XX250

XX200

XX350

> Density image from the VISION475 system. Measured densities appear in track 1, andare redisplayed to highlight detail in track 2. Structural dips (green dots in track 3) arehand picked using the same process as for wireline FMI Fullbore Formation Micro-Imager data and relative dip to the borehole is calculated (blue dots). These imagesare also useful for calculating a sand count or determining the net-to-gross sand ratio.

Filtrate

Impermeablelayer

Impermeablelayer

Slumpedfiltrate

Wellbore

Wellbore

> Invasion and slumping filtrate. A radial invasion front becomes distorted in the presence of a horizontal layer (top) or dippingimpermeable layer (bottom).

35Winter 1998

5. Bornemann E, Bourgeois T, Bramlett K, Hodenfield K andMaggs D: “The Application and Accuracy of GeologicalInformation from a Logging-While-Drilling Density Tool,”Transactions of the SPWLA 39th Annual LoggingSymposium, Keystone, Colorado, USA, May 26-29, 1998,paper L.

slumps in the down-dip direction. The rate ofslumping depends on the vertical permeability ofeach zone: the higher the vertical permeability,the more rapid the slumping. In addition, perme-ability anisotropy will distort slump geometry. Informations with permeability on the order of onedarcy, strong azimuthal variations in invasionhave been observed less than an hour after thebit penetrates the formation.

In gas zones, such variations can make quan-titative porosity interpretation from nuclear toolsan even greater challenge than usual. Porosity

determination from nuclear tools requires thatthe effects of gas be removed. For this, knowl-edge of the gas volume and both radial andazimuthal location is needed. Further complicat-ing the problem, the neutron and density mea-surements respond differently to the radial andazimuthal location of gas. The neutron tool readsdeeper and is sensitive to any gas near the bore-hole, relatively independent of the azimuthallocation of the gas. The density tool reads shal-lower and is sensitive only to the gas in front ofits detectors.

What is needed is a way to quantify the vol-ume of gas radially and azimuthally over thesame region of formation that the density andneutron logs investigate. Then those volumes areused to apply appropriate gas corrections to thenuclear tools for final computation of porosity.

Radial and azimuthal gas quantification isaccomplished by analyzing while-drilling quad-rant resistivity data acquired as the RAB toolrotates in the borehole. The RAB tool investi-gates a region similar to that probed by nucleartools, and has five depths of investigation. By

Dept

h, ft

X050

X100

X150

X200

ohm-m

Porosity

p.u.

RAB Resistivity

RABResistivity

VISIONDensity

Top

Botto

m

Top

Botto

m

Top

0.1 100 40 0

Shallow Button Down

Shallow Button Up

Deep Button Up

CDR

Density Up

Density Down

Neutron

> Images of invasion slump. Density and RAB images show filtrate slumping, but not always down. Track 1 displays resistivities:three from the RAB tool and attenuation resistivity from the CDR Compensated Dual Resistivity tool. Additional filtrate detected bythe resistivity in the down direction compared to the up direction is shaded. Similarly for the porosity curves in track 2, the leftcurves are from the up and down quadrants of the density tool and the right curve is from the neutron tool. Track 3 contains the RABimage, with white most resistive, and track 4 shows the density image with dark as the most dense, and lighter colors as less dense.

36 Oilfield Review

using readings from all around the borehole,three of those depths of measurement can bepartitioned azimuthally into 56 segments. Fromthese three measurements, three quantities canbe solved for—the diameter of invasion, DI;invaded zone resistivity, Rxo ; and true formationresistivity, Rt —in any or all of the 56 azimuthalsegments. Rxo and Rt are assumed to be constantaround the hole; only DI varies. The determina-tion of Rt is most robust from the direction withminimum DI, and Rxo is most robust from thedirection with maximum DI.

Correcting the LWD density and neutron toolsrequires an appropriate radial response functionand appropriate DI; both are different for eachtool. The qualitative response of density and neu-tron tools has long been understood.7 The radial

response function of the density tool has beenquantified and is relatively independent of thefluids involved. The neutron radial response func-tion has been elusive, but Ellis and Chiaramonteof Schlumberger-Doll Research, Ridgefield,Connecticut, USA have recently completed amodeling code to allow the response to be calcu-lated under all conditions. Their modeling showsthat the neutron responds to the gas closest tothe borehole. Therefore the DI needed to correctthe neutron is the minimum DI computed aroundthe wellbore. In the typical slumping-filtratecase, the closest gas usually is at the top of thehole or possibly on the sides, but definitely not atthe bottom. The DI for the density correction isthe one computed in the direction the densitysensor is pointing.

Finally Rxo, Rt, invasion factors for density andneutron, bulk density, neutron porosity, plusappropriate parameters are entered in ELANElemental Log Analysis software to solve forporosity and water saturation.

This method was tested by partners ARCOand Enterprise on a North Sea gas well deviatedabout 40° encountering formations with 70°apparent dip. Images from the ADN and RABtools plot the location of the higher density,lower resistivity mud filtrate, which did notalways slump straight down (previous page). Thediameter of invasion is plotted, and the com-puted porosity displayed for comparison withcore measurements (above).

in. 300

in. 300

Dept

h, ft

X050

X100

X150

X200

Porosity

p.u. 040

Depth of Invasion

RAB Down

RAB Up

Neutron

Quadrant Corrected Effective Porosity

Density Down

Density Up

Core porosity

> Porosity computed from corrected neutron- and density-while-drilling data. Track 1 displays the diameter of invasion, DI,used to calculate corrections. The area between DI calculated from the up- and down-RAB measurements is shaded. Track 2contains porosities from up- and down-quadrant density measurements, neutron measurements and core (red dots). The effective porosity computed after corrections (orange curve) compares favorably with core measurements.

7. Sherman H and Locke S: “Depth of Investigation ofNeutron and Density Sondes for 35-Percent-Porosity Sand,”Transactions of the SPWLA 16th Annual LoggingSymposium, New Orleans, Louisiana, USA, 1975, paper Q.

37Winter 1998

Getting a First LookHigh-quality images provide valuable input to theinterpretation process. Geological information,such as laminations, location of the wellborewith respect to bed boundaries and the apparentdip magnitude and direction of bedding planes, isessential for interpreting log responses in highlydeviated wells. Images quickly reveal whetherthe bit is drilling down into or up through beddingplanes—critical for geosteering a well and refin-ing geological interpretations.

The VISION First Look display is a wellsiteanswer product that combines images with thecomplete VISION dataset to provide a format for

quickly interpreting logs in highly deviated wellsand making drilling decisions. In this real-timeinterpretation for the Shell deep-water RamPowell field in the Gulf of Mexico, the horizontalwellbore is drilled in a clean sand sheet depositnearly parallel to bedding. During drilling, severaltight or hard features were encountered unex-pectedly (above). Rate of penetration droppedsignificantly, and resistivity and bulk densityincreased while neutron porosity approachedzero p.u. These tight streaks were a surprise,because two vertical wells drilled in this areahad not encountered such a feature.

These tight streaks were of concern, as theymight influence production, perhaps necessitat-ing a change in wellbore trajectory. They firstwere assumed to be depositional features lyingparallel to bedding. However, careful examina-tion of the signature of the events on the densityand neutron curves reveals that these are verticalinterfaces. If the hard streaks were parallel tobedding planes, the tool would encounter theboundary more gradually and the measurementtransition from reservoir to tight streak wouldoccur over some distance. These transitions arequite abrupt, indicating a high-angle boundary.

100

Gamma Ray

API0

100 0ft/hr

ROP5

Dept

h, ft

XX500

XX550

XX600

1 100ohm-m

Density, Bottom

g/cm31.65 2.65

Neutron Porosity

0.6 0ft3/ft3

22-in. Phase-ShiftResistivity

Real-time data revealing tight treaks.While drilling in the Ram Powell field,Gulf of Mexico, tight streaks wereencountered unexpectedly. Theseevents show up as high-density, low-porosity interfaces in track 3. Rate ofpenetration (track 1) dropped signifi-cantly each time, and resistivityincreased (track 2).

38 Oilfield Review

>

This interpretation of vertical boundariesraised new concerns for the operator: Was thereservoir compartmentalized? Were thesestreaks mineralized fault planes? What is thevertical extent of these features? Should thewellbore trajectory be changed? The VISION FirstLook log, played back with recorded mode data,was able to answer these questions (above).

The density images displayed on the VISION

First Look log reveal the true nature of the“tight streaks.” The boundaries of the featuresare not planar, but rather calcite-cemented nod-ules. The features are not continuous verticalplanar events and will not have a large-scaleimpact on production.

The deeper reading attenuation resistivitymeasurement confirms this interpretation. Theattenuation measurements are not influenced bythe high-resistivity hard streaks to the degreethat phase-shift measurements are, and thereare no polarization horns, which indicates thatthese events do not extend far from the wellbore.

The Future VisionThe ability to achieve better reservoir qualityassessments in real time has satisfied some, butnot all, formation evaluation while-drilling needs.Already operators are asking for these LWD mea-surements in more hole sizes, and this demand isbeing met with the imminent introduction of theVISION675 and GeoVISION675 systems for 8- to 12-in. holes. The VISION675 system will encompassthe ARC675 Array Resistivity Compensated mea-surement, an enhanced PowerPulse MWD toolwith the new VISION Telemetry Protocol systemand a new 6.75-in. VISION675 density-neutrontool. The VISION675 density-neutron tool extendsthe capabilities of the existing 6.75-in. ADN toolby adding multisector density, Pe and caliperimages for both oil-base and water-base mud. Arelated tool for geological imaging while drillingwill appear in the GeoVISION675 system, whichwill contain a new-generation laterolog imagingtool in place of the ARC675 module.

Other measurements are making their way tothe 4.75-in. format, including downhole annularpressure and bit inclination for precision trajec-tory control.

To keep pace with the introduction of newmeasurements, interpretation experts are devis-ing new techniques for getting the most from thenew data. Programs for interpreting measure-ments in layers that are anisotropic, invaded, thin,dipping, or all of the above, are finding new chal-lenges when applied to time-lapse LWD data—LWD logs acquired before and after bit changesor other delays in drilling. Researchers are devel-oping methods for faster modeling and inversionof tool responses in more complex geometriesand more realistic formations. These efforts willenhance our ability to perform formation evalua-tion while drilling, and also will improve all otherLWD applications. —LS

PhaseShift

TVD

API

ResistivityTime After Bit

Gamma Ray

Rw-corrected Bulk Volumes

Effective Porosity

MatrixBound Water

0.02 200ohm-m

Attenuation Resistivities

Phase Shift-Resistivities

0.2 2000ohm-m

Bottom Density

Neutron Porosity

Attenuation

Mea

sure

d De

pth,

ft

Clay

XX200

XX250

ft3/ft30 60

1.65 2.65g/cm3

BHA sliding

Image orientationU R B L U0 hours 10

0 0 0.5

0 150

ft ohm-m100

Azimuth andDeviation

0 90

34 in.

10 in.16 in.22 in.28 in.

g/cm3

RHOB Image

2.05 2.45

> VISION First Look wellsite images. Bulk volume analysis (track 2) and an Rw curve (track 1) corrected forclay volume and type are computed and displayed. [Adapted from Cannon D: “Shales: An Alternate Source forWater Resistivities,” Transactions of the SPWLA 36th Annual Logging Symposium, June 26-29, 1995, Paris, France,paper LLL.] Phase-shift and attenuation resistivity curves are displayed in track 3, densities are in track 4. Density images (track 5) of tight streaks show that these features are clearly not planar.

39Winter 1998

40 Oilfield Review

Using Downhole Annular Pressure Measurementsto Improve Drilling Performance

Walt AldredJohn CookCambridge, England

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

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

Pearl Chu LederHouston, Texas

For help in preparation of this article, thanks to Dave Bergt,Schlumberger Oilfield Services, Sugar Land, Texas, USA;Tony Brock, Kent Corser, Kenneth Sax and James Thomson,BP Exploration, Houston, Texas; Tony Collins, Liz Hutton,John James, Dominic McCann, Rachel Strickland and Dave White, Anadrill, Sugar Land, Texas; Tim French,Anadrill, New Orleans, Louisiana, USA; Vernon H. Goodwin,EEX Corporation, Houston, Texas; Aron Kramer, GeoQuest,Youngsville, Louisiana; and Technical editing Services (TeS),Chester, England.APWD (Annular Pressure While Drilling), CDR(Compensated Dual Resistivity tool), LINC (LWD InductiveCoupling tool), SideKick, VISION475, VISION675 and VIPERare marks of Schlumberger. PWD (Pressure-While-Drilling)service is a mark of Sperry-Sun.

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

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

prevent serious operational drilling problems from developing.

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

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

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

The pressure window. In some wells, especially deviated and extended reach, themargins (right) between pore pressure (redcurve) and fracture gradient (yellow curve) may be small—500 psi [3447 kPa] or less—and very accurate annular pressure (whitecurve) information is essential to maintainoperations within safe limits. Well controlrequirements are such that circulation of aninflux through the long choke and kill linesthat run from the subsea blowout preventer(BOP) also imply a lower kick tolerance(orange dashed curve). The influence of well deviation angle on the pressure window(below) shows that managing the mud weight in extended-reach wells is made more difficult by annular pressure losseswhich are inherently high for wells with longhorizontal sections.

Winter 1998 41

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

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

Such measurements are provided by a number ofservice companies, and operators have beenusing them for a wide variety of applicationsincluding monitoring the effects of pipe rotation,cuttings load, swab and surge, leak-off tests(LOT), formation integrity tests (FIT), and detect-ing lost circulation (see “How Downhole AnnularPressure is Monitored,” page 42).2

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

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

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

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

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

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

Wellbore Stability Successful drilling requires that the drilling fluidpressure stay within a tight mud-weight windowdefined by the pressure limits for wellbore sta-bility. The lower pressure limit is either the porepressure in the formation or the limit for avoidingwellbore collapse (above). Normal burial trendslead to hydrostatically pressured formations,where the pore pressure is equal to that of awater column of equal depth. If the drilling fluidpressure is less than the pore pressure, then for-mation fluid or gas could flow into the borehole,with the subsequent risk of a blowout at surfaceor underground.

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

Mud

wei

ght,

sg

Collapsegradient

0.00 20 40

Well deviation, degrees60 80

0.4

0.8

1.2

1.6

2.0

2.4Fracturegradient

Stable

Dept

h

Pressure

Annularpressure

Kicktolerance

FracturegradientPore

pressure

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

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

42 Oilfield Review

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

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

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

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

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

How Downhole Annular Pressure is Monitored

> Annular pressure sensor. Resistor-based bellowsgauges (insert) are used for APWD measurementsin the CDR Compensated Dual Resistivity tool, andare available in three pressure ranges to meet theexpected wellsite conditions. These tools are mudpulse-operated, so no information is sent in realtime when the mud pumps are off. However, theycan record pressures when the pumps are off, andonce pumping is re-established, this information can be sent to the surface. Master calibrations are performed over a range of temperatures using a dead-weight tester. At the location or wellsite,hydraulic tests using a hand pump are performed on these gauges before and after use in each well to verify calibrations.

6.5 ft

Pressure port

Resistivity

Gamma ray

Annular pressure sensor

CDR tool

1. Hutchinson and Rezmer-Cooper, reference 5, main text.2. Ward CD and Andreassen E: “Pressure While Drilling

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

Winter 1998 43

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

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

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

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

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

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

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

Understanding the different pressureresponses under varying drilling conditions alsorequires an appreciation of the drilling fluid’s rhe-ological properties, including viscosity, yield andgel strength, and dynamic flow behavior. Is theflow laminar, transitional or turbulent? The varia-tion of the rheological properties with flowregime, temperature and pressure singly, and incombination, affects the total pressure measureddownhole.4 Some of these downhole parameters,such as flow rate, can be controlled by the driller.Others, such as downhole temperature, cannot.

Pressure Losses Until recently, the industry had been divided onthe effects of drillpipe rotation on pressurelosses. Some researchers have explicitly statedthat rotation acts to increase axial pressure drop,while others have taken the opposing view, thatan increase in rotation rate decreases annularpressure drop. In fact, both of these seeminglyconflicting views can be correct, and both effectshave been observed. Annular pressure losses oraxial pressure drop depend upon which part of the flow regime predominates when the rotationrate is changed (below).

Rotation rate

Flow

rate

Pressure increasing

Turbulent

Turbulent with vortices

Laminar

Laminar with vortices

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

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

4. For a detailed discussion of static, dynamic and cuttingspressure contributions to the total downhole pressure:Adamson K, Birch G, Gao E, Hand S, Macdonald C, MackD and Quadri A: “High-Pressure, High-Temperature Well Construction,” Oilfield Review 10, no. 2 (Summer1998): 36-49.

44 Oilfield Review

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

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

Flow rate—Mud flow rate is the most impor-tant parameter in determining effective holecleaning. For fluids in laminar flow, fluid velocityalone cannot efficiently remove cuttings from adeviated wellbore. Fluid velocity can disturb cut-tings lying in the cuttings bed and push them upinto the main flow stream. However, if the fluidhas inadequate carrying capacity—yield point,viscosity and density—then many of the cuttingswill fall back into the cuttings bed. Mechanicalagitation due to pipe rotation or back-reamingcan aid cleaning in such situations, but some-times are inefficient or worsen the situation.Agitation that is too vigorous, such as rotatingtoo fast with a bent housing in the motor, can have a detrimental effect on the life of down-hole equipment.

Inadequate flow results in increased cuttingsconcentrations in the annulus (next page, top). Acuttings accumulation may lead to a decrease inannular cross-sectional area, and hence anincrease in the ECD—ultimately leading to aplugged annulus, called a packoff. The use ofreal-time downhole annular pressure measure-ments allows early identification of an increasingECD trend, caused by an increasing annularrestriction, and helps the driller avoid formationbreakdown resulting from high pressure surgesor a costly stuck-pipe event.

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

2500

2000

1500

1000

500

00 50 100 150 200 250

Rotation, rpm

Pres

sure

gra

dien

t, Pa

/m

300 350 400 450 500

Low flowMedium flowHigh flow

Experimental conditionsHole size = 4.9 in.Pipe outer diameter = 3.5 in.Plastic viscosity = 3.4 cpYield point = 3.8 lbf/100 ft2

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

Equi

vale

nt c

ircul

atin

g de

nsity

, sg

0 10 50 100 120 130 Rotation, rpm

600 gal/min

400 gal/min

200 gal/min

1.13

1.11

1.09

1.07

1.05

1.03

1.01

0.99

0.97

0.95

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

Drillpipeeccentricity

Mudweight

Cuttingsdensity

Cuttingssize

Hole sizeand angle

Drillpiperotation

FlowrateMud

rheology

Rate ofpenetration

Hard to control Easy to control

Largeinfluence

on cuttingstransport

Littleinfluence

on cuttingstransport

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

>

Winter 1998 45

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

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

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

Stat

iona

ry

Rolli

ng

Asymmetricsuspension

Symmetricsuspension

Low flow rate High flow rate

Low

ECD

High

ECD

Cuttings transport. The cuttings transport mode affects hole-cleaning ability, especially in deviated wells. At low flow rates, the cuttings can fallout of suspension to the low side of the borehole—building a cuttings bedand increasing the ECD due to cuttings restriction in the annulus. As theflow rate is increased, the cuttings will start to roll along the wellbore erod-ing the cuttings bed. As the cuttings bed is partially eroded, the annular gapincreases and the ECD will start to decrease. As the flow rate increases further, the majority of the cuttings are transported along the low side of thewellbore, with some suspended in the fluid flow above the bed (asymmetricsuspension) leading to an increase in ECD. At higher flow rates frictionalpressure losses are significant, and the cuttings are transported completelysuspended in the fast-moving fluid (symmetric suspension). [Adapted fromGrover GW and Aziz A: The Flow of Complex Mixtures in Pipes. Malabar, Florida,USA: Robert E. Krieger Publishing Company, Inc., 1987.]

ECD/ESD1410

Temperature°C 200

lbm/gal

0Standpipe pressure

40000

Total pump flow1000gal/min

psi

0Surface torque

300

Surface rotation150rpm

kft-lbf

0

TimeMeasured depth

110000

Surface weight on bit60klbf

ft

0

01:00

02:00

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

HookloadTime

Surface torquekft-lbf

Surfacerotation

Blockspeed

ftDepth

Rotationstops

Slidinginterval

Rotationstarts

2000 rpm500010-10 14.213.2 lbm/gal10000

gal/minft/s klbf

Totalpump flow

ECD / ESD

Standpipe pressure

Temperature

15:00

16:00

5000psi0

100°C0Effect of drillpipe

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

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

>>

>

46 Oilfield Review

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

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

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

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

Blockposition

Drilling cycle 1

Drilling cycle 2

Pumps on

Pipereciprocating

m0 50

Hookloadklbf0 400

ROPm/hr200 0

Bit depthvalue, m

Downholeweight on bit

klbf0 80

Surfaceweight on bit

klbf0 80

19:00Time

20:00

21:00

Downholetorque

kft-lbf0 20

Surface torque

kft-lbf20 60

Surfacerotation

rpm0 200

Total pumpflow

gal/min0 1500

Turbinerotationrpm0 5000

Standpipe pressurepsi0 4000

Annulus pressure

psi0 4000

Annulus temperature°C0 200

ECDsg1.65 1.75

Bit on bottom flag

Cuttingssettling out

Hole surged

Hole swabbed

Surge andswab

Pumps off

Rotary drilling

Slide drilling

Kelly down

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

Winter 1998 47

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

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

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

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

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

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

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

5:00

ECD

2000

3000

0

Block position0 50m

ROP100m/hr

Hookload0 500klbf

0 50Surface torque

kft-lbf

Standpipe pressure4000

Annulus pressure3000psi

1.2 1.3sgTotal pump flow

20000 gal/min

psi

12:00

Drillingbreak

1:00

4:00

5:00 ECDincrease

Standpipepressureincrease

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

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

48 Oilfield Review

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

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

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

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

Typical hole

4600

4800

5000

Slim hole

0

4

8

12

16

20

0

1000

2000

Shut-in Kill Shut-in Kill

Time, min

0

200

400

600

800

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

Friction pressure loss Pit gain Standpipe pressure Annulus pressure

Annu

lar p

ress

ure,

psi

Pit g

ain,

bbl

Stan

dpip

e pr

essu

re, p

si

Fric

tion

pres

sure

loss

, psi

> Kick detection. In a typical wellbore geometry (top left), the annular pressure (orange curve) can beseen to decrease as the displacement of heavier drilling fluids by a gas influx dominates the pressureresponse. For slimhole geometry (top right) the annular pressure (orange curve) can increase initiallyduring a gas influx as the inertia of the mud column dominates the response. One major benefit ofdownhole annular pressure monitoring is early kick detection. Mud-pit gain (red curves in upper plots),standpipe pressure (green curves in lower plots), and frictional pressure loss (yellow curves in lowerplots) help the driller identify gas kicks.

1200 200 300Block height

Annulustemperature

ft °F 13 18ECD

lbm/gal 3000 5000

Standpipepressure

psi 08:00Time

Rack backstand of pipe

Temperature rises, ECD drops

Flow checkand close in

12:00

11:00

10:00

09:00

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

Winter 1998 49

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

As drilling progressed after 18:10, the ECDmeasurement decreased slowly to 12.35 lbm/gal[1.48 g/cm3] over a period of 90 minutes. Sud-denly at 19:20, the ECD dropped to 12.0 lbm/gal[1.44 g/cm3] while drilling the next 9 ft [2.7 m] ofthe well. The drilling foreman noticed the largedrop in ECD readings—signaling an influx.Increased pit volumes were noticed at this timeand the well was immediately shut in at 19:50.The kill took 24 hours with an additional 30 hoursto repair blowout preventer (BOP) damage.

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

In another example, use of APWD data helpedsave a well. In this well, drilling was proceedingwithout any indication of an influx either from pitgain or in mud flow rates in or out of the well (pre-vious page, bottom). However, the ECD started todecrease at 11:00 and continued for 50 minutes.At the same time, an increase in the annulus tem-perature was observed, due to the formation fluidwarming the borehole fluid. Guided by the ECDresponse, the driller stopped drilling and safelycirculated out a small gas influx.

14:00

15:00

16:00

17:00

18:00

19:00

20:00

21:00

Block speed

ft/s-2 2

ROP

ft/hrBit depth

500 0

ft0 100

Surface weight on bit

klbf0 60Downhole weight on bit

klbf0 60

Surface torque

kft-lbf0 25

Bit on bottom flagDownhole torque

kft-lbf0 8

Totalpumpflow

gal/min0 1500

CDR annulus pressure

psi0 10000

ECD

lbm/gal9 11

Annulus temperature

°F100 300Standpipe pressure

psi0 5000

Time

Axial vibration

G4 0

Torsional vibration

ft-lbf4000 0

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

7. MacAndrew R, Parry N, Prieur J-M, Wiggelman J,Diggins E, Guicheney P, Cameron D and Stewart A:“Drilling and Testing Hot, High-Pressure Wells,” OilfieldReview 5, no. 2/3 (April/July 1993): 15-32.

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

50 Oilfield Review

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

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

Scientists at BP and Schlumberger CambridgeResearch, England have spent years studying thebehavior of gas kicks.1 Their work, along withengineering development at the SchlumbergerSugar Land Product Center in Texas, has pro-duced the Anadrill SideKick-PC software model,which simulates gas kicks and helps plan meth-ods of detecting and controlling them. SideKick-PC models include the effects of gas distributionin the annulus. This produces a more realisticand less conservative kick tolerance, whichleads to the use of fewer casing strings and sub-stantial cost savings. Kick tolerance is illus-trated in user-friendly, automatically generatedplots of safe pit gain versus safe formation pres-sure (below). The simulator helps engineersanticipate and meet the challenges of a widevariety of drilling environments.

The simulator can be used in planning under-balanced drilling programs, which require esti-mates of wellbore pressures and fluid produc-tion rates. In addition, the cost-effectiveness ofusing the underbalanced methods must also beevaluated. Other simulators have helped address

Simulating Gas Kicks

1000

900

800

700

600

500

400

Shut

-in d

rillp

ipe

pres

sure

, psi

0 10 20 30 40Pit gain, bbl

StaticCirculating

Safe

Unsafe

> SideKick-PC kick tolerance. The SideKick-PC program computes separate kick tolerances for the shut-inand kill periods of a simulation. The kick tolerance plot is used to differentiate kicks that can be safelyshut in (static) from those that can be safely killed (circulating). The determination depends on many factors such as pressures in the well, gas migration, circulating friction and kill-mud hydrostatic pressure.Kicks in the region to the left and below each curve are considered safe, and those severe enough to be inthe region above and to the right of each curve may cause lost circulation.

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

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

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

The SideKick-PC program has proved effectivein allowing engineers to run many complex sim-ulations easily and quickly. Coupled with defin-ing safe operating envelopes in minutes ratherthan hours or days of well planning, gas-kicksimulation is helping to enhance overall per-formance by improving efficiency and reducingwell construction costs.

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

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

3. James JP, Rezmer-Cooper IM, and Sørskår SK: “MABOPP– New Diagnostics and Procedures for Deep Water WellControl,” paper SPE 52765, submitted for presentation atthe 1999 SPE/IADC Drilling Conference, Amsterdam, TheNetherlands, March 9-11, 1999

Winter 1998 51

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

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

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

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

Dynamic kill procedure—Real-time analysisof downhole annular pressure helped BPExploration monitor a dynamic kill procedureused to stop an underground flow in a deep-water well in the Gulf of Mexico. Drilling unex-pectedly entered a high-pressure zone, where a

water influx fractured the formation at the casingshoe. Real-time APWD measurements werecombined with standpipe pressure to monitor theprocess of the dynamic kill.

The procedure circulated kill-weight mud fastenough to “outrun” the influx and obtain a suffi-cient hydrostatic gradient to kill the well. Drillingfluid used in this well weighed 11.8 lbm/gal [1.41 g/cm3], and the kill-weight mud was 17.0 lbm/gal [2.04 g/cm3]. During the killprocedure, BP’s Ocean America operating crewmonitored the standpipe pressure to determine if

Zone A

Zone B

Zone C

20

Casing, in.

16

133/8

113/4

95/8

Overburden gradient, lbm/gal

Resistivity pore pressure estimate, lbm/gal

ECD, lbm/gal

Seismic pore pressure estimate, lbm/gal

10.00 17.00

17.00

17.00

17.00

10.00

10.00

10.00

Kick

Kick

75/8

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

9. Brandt W, Dang AS, Mange E, Crowley D, Houston K,Rennie A, Hodder M, Stringer R, Juiniti R, Ohara S and Rushton S: “Deepening the Search for OffshoreHydrocarbons,” Oilfield Review 10, no. 1 (Spring 1998): 2-21.

52 Oilfield Review

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

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

Bit depth

ft0 100

Block speed

ft/s2 2

Annulus pressure

psi7000 9000

ECD

lbm/gal12 13

Annulus temperature

°F50 150Hookload

klbf400 600

ROPft/hr500 0

Surface torque

kft-lbf0 25

Standpipe pressurepsi2000 4000

Surface rotation

rpm0 200

Total pump flow

0 gal/min 100018:00Time

19:00

Kill starts

Kill stops

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

Sand

Sand

With riser

Without riser

ρwater

ρmud

ρmud

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

Winter 1998 53

In many deep-water wells, the first casing or conductor pipe is usually 30 or 36 in. [76 or 91 cm] in diameter. The next hole section, typi-cally 24 or 26 in. [61 or 66 cm], is often drilledwithout a riser. In these wells, spent drilling fluidand cuttings are returned to the ocean flooraround the wellhead (previous page, top). Sincethe drilling fluid is not recovered under theseconditions, expensive synthetic- or oil-base mudstypically are not used. Instead, either seawateror inexpensive water-base mud is used.

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

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

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

Improving Drilling Efficiency With higher rig costs on many drilling projects,such as extended-reach and deep-water wells,time savings and precise measurements arecritical. Accurate leakoff tests (LOT) are essentialto enable efficient management of the ECDwithin the pressure window, and the correspon-ding mud program.

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

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

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

Depthm

Attenuation resistivityGamma ray0

A

150 0 10 8 9

500 0 0 10 2000 3000

0 2 50 100Phase-shift resistivity

ohm-m

Phase-shift resistivityohm-m

ECD

Annulus pressurepsi

Annulus temperature°F

Rate of penetrationft/hr

lbm/galohm-mAPI

C

D

B-upper

B-lower

Water influx

Water influx

Water influx

X000

X100

X200

X300

X400

X500

X600

X700

X800

X900

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

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

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

13. Adamson et al, 1998, reference 4.

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

54 Oilfield Review

is the leakoff test pressure used to compute theformation fracture gradient. Sometimes, the pro-cedure is to stop increasing the pressure beforethe actual leakoff pressure is reached. In suchcases, the planned hole section requires a lowermaximum mud weight than the expected fracturepressure, and the test pressures only up to thislower value with no evidence of fracture initia-tion. This is called a formation integrity test (FIT).If pumping continues beyond the fracture initia-tion point, the formation may rupture, pressurewill fall, and the fracture will propagate.

APWD measurements helped monitor down-hole pressure in a leakoff test performed by BPExploration in a deep-water well in the Gulf ofMexico (below). As the pumped volumeincreased to 3.5 barrels, the standpipe pressureincreased to 520 psi [3585 kPa]. Downhole ECD

increased from 9.8 lbm/gal (hydrostatic) to 10.9 lbm/gal [1.17 g/cm3 to 1.31 g/cm3]. At this point, the pumping stopped, and the ECD dropped exponentially to 10.7 lbm/gal [1.28 g/cm3], indicating that the formation wastaking fluid. The pressure margin determinedfrom this test was sufficiently high to allowdrilling to proceed without incident.

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

sure measurements remove uncertainties causedby anomalies in mud gel strength or inhomo-geneities in the mud column density due to pres-sure and temperature effects.

Technologies from Schlumberger Wireline &Testing, Anadrill and Dowell were combined toperform a real-time downhole formation integritytest in a deep-water well in the Gulf of Mexico.During this test, an Anadrill CDR tool wasincluded in the BHA used to drill the casing shoe.The CDR tool contained an APWD sensor to mon-itor downhole pressure. In typical logging-while-drilling (LWD) applications, sufficient mud ispumped to enable the BHA to communicate tothe surface through mud-pulse telemetry. This isnot the case with slow pumping rates used dur-ing a typical LOT or FIT. However, downhole pres-sure can be monitored in real time through theuse of a wireline-operated LINC LWD InductiveCoupling tool that sits inside the CDR tool andtransmits pressure data to the surface.

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

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

Bit depth ft0 100

Block speedft/s2 2

Hookload klbf0 500

Surface torquekft-lbf10 30

Annulus pressurepsi0 10000

ECDlbm/gal9 12

Surface weight on bitklbf0 80

Total pumpflow

0 1500gal/min

14:00Time

Surfacerotation

rpm

16:00

15:00

600

500

400

300

200

100

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

Volume, bbl Time, min

Surfa

ce p

ress

ure,

psi

Pumping-upphase

Leakoffphase

Formation takingdrilling fluid

Leakoff test

80

165

260

350

430

480

520

460445

435 430 420 415 410 408 405 400

A

B

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

14. Hutchinson and Rezmer-Cooper, reference 5.15. Rojas JC, Bern P and Chambers B: “Pressure While

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

Winter 1998 55

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

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

The Big PictureIn wireline logging, the log represents a state ofthe well—showing the more-or-less static for-mation properties, such as lithological beds andfluid saturations. Getting the data is most impor-tant, but decisions made at the time of acquisi-tion are not necessarily critical. However, logs ofdownhole annular pressure and other drillingperformance parameters show a process—a process that is evolving with time. The evolu-tion of the log in real time must be monitored asdownhole conditions are dynamic, and timelydecisions are essential. Delay or indecision canlead to serious risks and added costs.

The format of drilling performance logs is dif-ferent from wireline logs. Drilling problems gen-

erally result in slower rates of penetration anddata are compressed on a depth scale.Therefore, a time-based presentation is oftenbetter suited for detailed analysis during prob-lematic drilling intervals. Still, depth-based pre-sentations are important for assessment ofdrilling events in the context of BHA position rel-ative to lithological boundaries.

Drilling parameters should be presented inrelation to one another on the log. Wireline logs,such as the triple-combo used for formation eval-uation, have a standard layout that helps ana-lysts learn how to quickly spot the importantproductive zones. A standard layout for drillingperformance logs has recently been proposed(previous page).14

The proposed layout enters geometric param-eters such as bit depth, ROP, and block speed intrack 1, followed by weight parameters such ashookload and downhole weight-on-bit in track 2.Time or true vertical depth (TVD) are shown in thenext column. Next, torque parameters in track 3,rotation rates along with lateral shock and motorstall in track 4, and flow parameters such as mudflow rates, differential flow, total gas, mud pitlevel and turbine rotation rate in track 5. Finally,pressure measurements such as ECD, ESD, annu-lar pressure, annular temperature, swab-and-surge pressures, estimated pore and fracturepressure limits and standpipe pressure are allshown in track 6.

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

Downhole real-time annular pressure meas-urements have a significant impact on today’sdrilling practices with applications in everyaspect of drilling. For example, many of the les-sons and efficiency improvements made in high-cost ERD and deep-water wells can be applied tosimpler wells. Monitoring downhole annularpressure along with other drilling parametersprovides an integrated view of a healthy drillingenvironment—one that puts emphasis on antici-pation and prevention rather than reaction andcure.15 Such improved operational procedureswill lead to decreases in nonproductive time andincreases in drilling efficiency. —RCH

Event or procedure ECD change Other indications Comments

Mud gelation / pump startup

Sudden increasepossible

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

Cuttings pick-up Increase then levelingas steady-statereached

Cuttings at surface Increase may be more noticeable with rotation

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

• High overpulls• “Steady” increase in standpipe pressure

Monitor both standpipepressure and ECD

Plugging annulus Intermittent surgeincreases

• Standpipe pressure• Surge increase?• Torque/RPM fluctuations• High overpulls

Packoff may“blow-through”before formationbreakdown

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

If near plugging, may getpressure surge spikes

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

Take care if estimatinggas migration rate

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

Monitor trip tank Effect enhanced ifnozzles plugged

Barite sag Decrease in staticmud density orunexplained densityfluctuations

High torque andoverpulls

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

Gas influx Decreases intypical size hole

Increases in pit leveland differential pressure

Initial increase inpit gain may be masked

Liquid influx Decreases if lighterthan drilling fluidIncreases if influxaccompanied by solids

Look for flow at mudlineif relevant

Plan response if shallowwater flow expected

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

Monitor trip tank Effect enhanced ifnozzles plugged

Making a connection Decrease to staticmud density

Pumps on/offindicatorPump flow rate lag

Watch for significant changes in static muddensity

Increase if well is shut-in

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

Walt Aldred is currently on secondment fromAnadrill to Schlumberger Cambridge Research inEngland, where he is working on the Real-Time Well-bore Stability project and projects related to drillinglearning. Part of this involves leading the PERFORMteam, which is dedicated to reducing drilling costsand improving drilling efficiency. He joined the com-pany in 1980, working in the field—in West Africa andthe North Sea. He later spent five years in SugarLand, Texas, USA, developing drilling interpretationproducts and then was in Nigeria for more than fouryears involved in drilling engineering and optimiza-tion. Holder of a patent in drilling motor optimization,Walt received a BS degree (Hons) from the Universityof Durham in England.

Peter Bern is a senior engineer in the BP ExplorationTechnology Provision Group in Sunbury-on-Thames,England. He joined BP in 1978 and has worked in anumber of areas related to fluid technology. Herecently accepted a temporary assignment to workwith BPX in Alaska, USA on issues related to fluidsand extended-reach drilling. Peter holds a degree inphysics from the University of Bristol, England.

Steve Bosworth, Drilling Manager-Land, for UnionPacific Resources (UPR) Company office in FortWorth, Texas, is responsible for Austin Chalk drillingin Texas and Louisiana, USA, and also supervisessome operations in the Rocky Mountains area. He hasworked for UPR (formerly called Champlin PetroleumCompany) since 1978 and has been drilling managersince 1998. In 20 years with the company he has heldvarious drilling superintendent jobs in Texas, Okla-homa, New Mexico, Colorado, Kansas, Wyoming andthe Gulf of Mexico, with international drilling experi-ence in Argentina, Venezuela and Canada. He earneda BS degree in natural gas engineering at Texas A&IUniversity in Kingsville. An SPE member, he serves as2nd vice-president for the American Association ofDrilling Engineers Dallas-Fort Worth chapter.

Tim Bourgeois, Senior Petrophysical Engineerwith Shell Deepwater Production Inc., is assigned

to the Ram-Powell team. Previously, he worked for a major service company and held various posi-tions in engineering and sales. Tim has a BS degreein petroleum engineering from Texas A&M Universityin College Station.

Ken Bramlett has been the Shell deep-water projectgeologist for the Ram-Powell project since early 1994.His efforts have focused on reservoir characterizationand development planning. Previously, he held vari-ous technical and managerial positions in the RockyMountains, Permian Basin and the Gulf of Mexico.Ken earned an MS degree in geology from the Univer-sity of South Carolina at Columbia, USA.

Darrel Cannon, Scientific Advisor and InterpretationMétier Leader, is based at the Sugar Land ProductCenter in Texas. Since 1965 his various assignmentsin the field organization and within engineering haveincluded field engineer, district manager, sales engi-neer, interpretation department manager and engi-neering department manager in California, Alaska,Canada, Texas and Louisiana. Darrel obtained a BAdegree in physics from the University of California atBerkeley, USA.

Bill Carpenter, the Anadrill North American logging-while-drilling (LWD) Business Development Managerbased in Sugar Land, Texas, is responsible for mar-keting, training and support in LWD and drillingperformance measurements. He held a number ofmanagement and sales positions in the US Gulf Coastprior to his current assignment. He began his careerwith Schlumberger in 1975 as a wireline field engi-neer in Louisiana. Author of several papers on gravel-pack evaluation and on LWD technology, Bill receiveda BS degree in electrical engineering from MemphisState University in Tennessee, USA.

François Clouzeau is Drilling Office* sales coordina-tor at GeoQuest in Houston, Texas. He joined Anadrillin 1984 as a directional driller with assignments inWest Africa and Italy. He was drilling service engineerin the Congo (1988 to 1989); field service manageroffshore Libya (1989 to 1990); and district manager in Libya (1990 to 1992). He spent the next year inSugar Land as staff engineer responsible for fieldintroduction of the PowerPak* motor. He has alsobeen manager in China, Congo, Angola and southEurope. François has an engineer’s degree fromInstitut National Polytechnique in Grenoble, France,with a specialty in signal processing.

John Cook is program manager for the geomechan-ics group in the well construction department,Schlumberger Cambridge Research in England. Hehas been at SCR since 1983. An SPE editor and mem-ber of the program committee for EUROCK98 held inTrondheim, Norway, John obtained a PhD degree inphysics from University of Cambridge, England.

Pete Craig, a geologist for Shell Deepwater Produc-tion, has worked on the Ram-Powell project for thepast two years. He is a graduate of Cornell Universityin Ithaca, New York, USA and received an MS degreein geology from University of California in Los Ange-les, specializing in sedimentology and stratigraphy.

Hussein S. El-Sayed, Anadrill Marketing Manager for the Middle East-Gulf Region, is based in Dubai,United Arab Emirates (UAE). His responsibilitiesinclude marketing analysis and studies, businessdevelopment and overseeing bids, tenders and con-tracts for major operating companies. He joinedSchlumberger in 1982 as a wireline engineer andworked in Oman, Pakistan, India and Kuwait. In 1989he became operations manager in Islamabad, Pak-istan. The following year he joined the newly formedLWD group in Sugar Land, Texas; and from 1991 to1993, he was LWD business development manager forthe Middle East. Hussein has also served as Gulf Areasales manager and then Anadrill operations managerfor the UAE, responsible for Abu Dhabi and the north-ern emirates. He assumed his current post in 1997.Author of several technical papers on LWD applica-tions, he holds a BS degree in mechanical engineeringfrom Ain Shams University in Cairo, Egypt.

Randolph (Randy) Hansen, Manager of PowerPlan*coordination, is in charge of implementing this soft-ware throughout the company. He has had 19 years of managerial experience in Schlumberger Wireline & Testing and Anadrill operations. His positions haveincluded UK District Engineer in Aberdeen, Scotland;District Manager Norway in Bergen, Norway; DivisionTechnical Manager Africa/Middle East in Pau, France;Manager LWD Europe in Aberdeen, Scotland; UnitTechnical Manager Europe/Africa in London, Eng-land; and Division Manager UK in Aberdeen, Scotland.Randy has a BS degree in physics from the Universityof Kansas at Lawrence, USA.

Ray Harkins, principal petrophysicist at ARCOBritish Ltd., is responsible for the petrophysics func-tion at ARCO British and ARCO Europe/North Africa.His varied experience has included petrophysics man-agement, evaluation of oilfield development plans,wireline operations management, personnel manage-ment, and financial and business planning. His careerwith Schlumberger (1977 to 1986) included serving asa field engineer in Europe; a production engineer inThe Shetlands; and location manager in South Oman.Before his current position, he was a reservoir evalua-tion specialist with the Oil and Gas Division of theDepartment of Trade & Industry in London, England(1989 to 1996). Ray received a BS degree (Hons) inphysics and mathematics from University College inDublin, Ireland, and an MBA degree in finance fromCity University Business School in London.

Kyel Hodenfield, who is in LWD New TechnologyMarketing at Anadrill in Sugar Land, Texas, is respon-sible for product introduction of the VISION475* andISONIC*IDEAL sonic-while-drilling tools. He joinedthe company in 1985 as a Schlumberger Wireline &Testing (W&T) field engineer and worked in Bakers-field and Sacramento, California. From 1990 to 1994,he was a W&T sales engineer in Bakersfield. Beforeassuming his current position in 1997 he was districtmanager in Evanston/ Rock Springs, Wyoming, USA.Kyel has a BS degree in petroleum and geologicalengineering from University of North Dakota in Grand Forks, USA.

Mark Hutchinson, Performance Drilling ServiceChampion for Anadrill in Sugar Land, is responsiblefor worldwide marketing of drilling-related mea-surements and the Perform service. He joinedSchlumberger in 1977 as a wireline field engineer,and then worked as a dipmeter interpretation spe-cialist. In 1982 he moved to the Conoco interna-tional well-planning department as a pore pressurespecialist, and two years later transferred to Conocoresearch to develop reservoir log interpretation soft-ware and coordinate an international research con-sortium for testing and evaluating MWD and LWDtechnology. In 1991 he joined Teleco/Baker Hughesto market LWD and drilling performance services,and in 1996 returned to Anadrill to market reentrydrilling and performance drilling services. Markreceived an MS degree (Hons) in aeronautical andelectrical engineering from University of Cambridgein England. He is currently serving as the MWDTechnical Interest Group Chairman for the SPE.

Gamal Ismail, Lead drilling Engineer for ZakumDevelopment Co. (ZADCO) in Abu Dhabi, United ArabEmirates, is responsible for planning and preparingdrilling programs of new sidetrack wells (140 horizon-tal wells including 50 multilateral wells), and for wellduration and cost estimation, operations monitoring,follow-up and evaluation. Before joining ZADCO in1994, he served 14 years with Belayim PetroleumCompany (PetroBel) in Egypt, involved in offshoreand onshore drilling operations and engineeringstudies in the Gulf of Suez, Mediterranean Sea, Sinai Peninsula and Nile Delta. His last position withPetroBel was offshore drilling operations departmentmanager. Author of several technical papers, Gamalearned a BS degree in petroleum engineering fromSuez Canal University in Egypt.

Contributors

56 Oilfield Review

Pearl Chu Leder, Deep-water Drilling Specialist at Anadrill in Houston, Texas, provides technical salessupport for Anadrill deep-water services, includingimproving drilling performance through the use ofAnadrill measurements and real-time pore pressureprediction at the wellsite. She began as a developmentengineer at Anadrill engineering in Sugar Land in 1990.Six years later she became a marketing specialist forAnadrill marketing, also in Sugar Land. Before her cur-rent assignment she was a client services engineer forAnadrill sales, at the BP office in Houston. She has aBS degree from Texas A&M University in College Sta-tion and an MS degree from Georgia Institute of Tech-nology in Atlanta, both in mechanical engineering.

John Lovell is currently marketing manager forAnadrill Measurement Services in Sugar Land, Texas.He joined the company as a research scientist atSchlumberger-Doll Research (SDR), Ridgefield, Con-necticut, USA, in 1984. While at SDR, he developedelectromagnetic forward and inverse algorithms basedupon finite-element and spectral methods. In 1993, hecompleted a PhD degree in electrical engineering atDelft University, The Netherlands and later that yeartransferred to Anadrill to develop answer products forthe RAB* Resistivity-at-the-Bit tool, including imaging,dip and invasion analysis. John joined the Anadrillmarketing department in 1996 and manages the mar-keting and business development of Anadrill MWD andLWD services. He holds MA degrees in mathematicsfrom the University of Oxford, England and CornellUniversity, Ithaca, New York.

Dominic McCann, Department Manager for thedrilling engineering and planning department in theSugar Land Product Center, is in charge of develop-ment of drilling engineering products used by bothAnadrill and the IPM field organizations. These includereal-time drilling interpretation products and drillingdata and process management tools for use at the well-site and in the project-planning phase. He joinedSchlumberger in 1984 in the drilling and rock mechan-ics department at Schlumberger Cambridge Researchin England. In 1988, he transferred to Sedco Forex inMontrouge, France to work on the MDS* managementdrilling system. Four years later he moved to Anadrillengineering in Sugar Land as section manager for theDrilling Interpretation Products group. He becamedepartment manager in 1998. Dominic holds a BSdegree in physics and computer science and PhDdegree in physics from the University of Wales, Cardiff.

Gilles Michel started his career with SchlumbergerWireline & Testing as an R&D project engineer in1978. He then occupied several managerial positionsin the development of computer systems for datainterpretation and management in Houston andAustin, Texas. He joined Dowell in 1987 as vice-president of Engineering and Manufacturing in cement-ing and acidizing. In 1994 he developed the well engi-neering and operations activities of SchlumbergerIntegrated Project Management (IPM). Since 1996, hehas occupied positions as IPM marketing manager andOilfield Services well construction marketing manager.Gilles has a degree in physics from Ecole Supérieurede Physique et de Chimie Industrielles de la Ville deParis, France, and a PhD degree in computer sciencefrom the University of Paris VI.

Diane Neff, who manages GeoQuest E&P consulting,in Houston, Texas, has been responsible for data man-agement and workflow solutions for the past two years.In her 10 years with GeoQuest she has primarily beeninvolved in product marketing, and managed thisgroup for five years. She has also spent three yearswith Terra Mar Resources providing technical supportfor petrophysical and geological PC-based applica-tions, and four years with an independent oil company(Canada Northwest) as exploration geologist. Diane’sBS degree in geology is from Michigan State Universityin East Lansing, USA.

Hervé Ohmer, Department Head of Multilateral Sys-tems Product Development at Camco in Rosharon,Texas, manages an engineering group responsible fordesign and development of multilateral junction tech-nology. He joined the company in 1977 in Clamart,France as project engineer on wireline downhole toolsand subsequently had several assignments as projectmanager with Schlumberger Wireline & Testing inFrance and then in Texas. In 1995 he became part of anew engineering team in Sugar Land, Texas, chargedwith developing multilateral well technology. Heassumed his current position in January 1999. Hervéhas a degree in mechanical engineering from InstitutNational des Sciences Appliqués (INSA) in Lyon,France. He helped develop several wireline tools andhas patents pending on several new concepts for Level3 and Level 6 multilateral applications.

Ian Pigram is a Senior Petrophysicist with ARCOBritish Limited covering the UK and Europe. He joinedARCO in 1979 initially as a contractor working on pro-jects ranging from reservoir volumetrics, log analysisand log database management to well planning andthen subsequently as an employee mainly involved indevelopment projects. His later projects concentratedon formation evaluation, petrophysics and reservoirdescription including some dedicated gas field work.He has also had short assignments in exploration andcommercial groups. Since 1995 Ian has concentratedon petrophysical issues for the company both in theUK and in Europe and the North Africa region. Heholds a BS degree (Hons) in geology from UniversityCollege of Wales, Aberystwyth, and an MS degree instructural geology and rock mechanics from ImperialCollege, London, England.

Laurent P. Prouvost has been Department Head ofProcess & Software products in the Dowell Well Con-struction Services group in Clamart, France since1993. There he manages several product developmentteams involved in physical modeling, validation andcommercial software development. He joined DowellWell Production Services in St. Etienne, France in1985 and later became section head for the Modelling& Software group in the Well Construction Servicesgroup. Three years later he started and led the DrillingFluids Services (DFS) Engineering group in St. Eti-enne concurrently with the startup of Dowell DFS inAberdeen, Scotland. This group developed wellsitemud monitoring equipment, mud reporting and data-base applications. Holder of several patents andauthor of many technical papers, Laurent has an Engi-neer’s degree from Ecole Centrale de Paris and a PhDdegree from University of Bordeaux, France.

Albertus Retnanto is a production enhancement engi-neer for Schlumberger Oilfield Services in Jakarta,Indonesia. He began his career in 1990 in petroleumengineering software development for PERTAMINA,Indonesia. From 1990 to 1994, he worked on field reha-bilitation and enhanced oil recovery projects inIndonesia. After graduate study on horizontal and mul-tilateral well production optimization at Texas A&MUniversity in College Station, he joined the Schlum-berger Production Enhancement Group in Lafayette,Louisiana. He moved to Schlumberger Wireline & Test-ing in Sugar Land in 1998. Albertus earned a BSdegree from Bandung Institute of Technology inIndonesia, and MS and PhD degrees from Texas A&MUniversity, all in petroleum engineering.

Iain Rezmer-Cooper is section manager of the DrillingInterpretation Products group in the Sugar Land Prod-uct Center, responsible for well control, and predictiveand real-time drilling hydraulics and mechanicsanswer products. He began his career at SchlumbergerCambridge Research in 1992 working on the SedcoForex MDS management drilling system. He subse-quently helped develop the SideKick* gas-kick simula-tor, and worked with Sedco Forex and the NorwegianPetroleum Directorate on the Voring Plateau Deep-Water Well Control Study in 1994. He joined Anadrillin 1994, developing the hydraulics application withinthe PowerPlan directional well-planning system. Iainholds a BS degree in mathematics and physics fromthe University of Bristol, and a PhD degree in numeri-cal weather prediction from the University of Reading,both in England.

Graham Ritchie, who is the Drilling Office championfor GeoQuest, is responsible for the coordination ofcommercial drilling software development in Schlum-berger. He began his career with BP Exploration as adrilling engineer in the North Sea and later with Pro-drill Engineering as engineering manager. He joinedSchlumberger in 1994 as well engineering team leaderfor the BP Machar early production scheme and BPClair extended well-test projects. He next served aswell engineering manager in the North Sea (1995 to1996), responsible for well engineering support for anumber of major field development projects. He wasalso a participant in the Schlumberger Forum 2005team charged with developing a ten-year vision for thecompany. Before assuming his current position in 1998,he was worldwide engineering manager for Schlum-berger Integrated Project Management. Grahamearned a BS degree in mining engineering from theUniversity of Nottingham, England, and an MBA degreefrom the University of Aberdeen in Scotland.

Mark Stracke, Multilateral Technology BusinessDevelopment Manager for the Schlumberger CamcoAdvanced Technology Group, is based in Rosharon,Texas. He began his career at Kerr McGee in drillingand for the next seven years had responsibilities rang-ing from drilling engineer to drilling superintendent.He spent the next 12 years with ARCO working on pro-duction engineering, completion engineering in theHouston district (now Vastar) and in drilling and com-pletion engineering and materials technology in theARCO technology department. He joined Anadrill in1995 as completion and drilling engineer in theRAPID* Reentry and Production Improvement Drillinggroup. Mark holds BS degrees in bioengineering andmechanical engineering from Texas A&M University inCollege Station.

Chris West is senior drilling engineer for multilateraldrilling projects at Anadrill and is based in SugarLand, Texas. His management and engineering experi-ence has included planning and supervising wells, anddesigning well stimulation and optimization programs.Prior to this (1995 to 1998), he was operation & assetdrilling engineer at ARCO/BP Shared Services Drillingin Anchorage, Alaska. He began with Amoco Produc-tion Company in 1982 as a drilling and productionengineer in Casper, Wyoming, USA. Five years later hejoined Conley and Associates, as drilling engineer andsuperintendent in Manila, The Philippines. He nextspent two years as sales manager and drilling engineerwith Eastman Christensen in Denver, Colorado, USA.He joined Schlumberger in 1990 as technical salesmanager of the Horizontal Integration Team, in Lon-don, England, and subsequently served as locationmanager in Al Khobar, Saudi Arabia and senior drillingengineer in Houston, Texas. Chris obtained BS degreein geological engineering from New Mexico Institute ofMining and Technology, Socorro, New Mexico, USA.

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

Winter 1998 57

Coming in Oilfield Review

Cement Technology. Oilfield cementing has critical roles in well construction,production and wellbore abandonment.In the past, slurry characteristics havenot always been compatible with themechanical properties that are requiredafter cement hardens. Today, we canoptimize pumpability and compressivestrength as well as zone isolation andslurry dependability. This article coversthe latest advances in oilwell cements.

Multicomponent Seismic Method. Bycombining compressional and shearwaves, the multicomponent seismicmethod reveals more about reservoirstructure and properties than surveysthat use only compressional waves.Advanced technology now allows thismethod to be applied in both marine and land surveys, with dramatic resultsin imaging and property mapping.

Production Services. Operators needcost-effective ways to maximize oil and gas output. Production servicestoday range from well completion, monitoring and diagnosis to remedialworkovers. This article discusses newdevelopments in production logging and analysis, completion services andwell interventions, and how economicsolutions are being found to keep wells producing at the highest rates possible.

Artificial Lift. Less than a fourth of producing oil wells flow naturally.The majority use rod pumps to bring fluids to surface, but more than 100,000wells use gas to lighten the fluid columnor an electrical submergible pump (ESP) for higher rates of flow. We lookat today’s broader gas lift and ESPapplications, and strategies that areused to determine the most economicsystem orcombination of methods.

Oilfield Review 1998 Index

ARTICLES

Coiled Tubing Drilling on the Alaskan North SlopeGantt LL, Leising L, Oba EM, Stagg T, Stanley M,Walker E and Walker R.Vol. 10, no. 2 (Summer 1998): 20-35.

Deepening the Search for Offshore HydrocarbonsBrandt W, Crowley D, Dang AS, Hodder M, Houston K,Juiniti R, Magne E, Ohara S, Rennie A, Rushton S and Stringer R.Vol. 10, no. 1 (Spring 1998): 2 -21.

The Evolution of Oilfield BatteriesHensley D, Milewits M and Zhang W.Vol. 10, no. 3 (Autumn 1998): 42-57.

From Pore to Pipeline, Field-Scale SolutionsBeamer A, Bryant I, Denver L, Mead P, Morgan C,Rossi D, Saeedi J, Sharma S and Verma V.Vol. 10, no. 2 (Summer 1998): 2-19.

The Giant Karachaganak Field, Unlocking Its PotentialElliot S, Hsu HH, O’Hearn T, Sylvester IF and Vercesi R. Vol. 10, no. 3 (Autumn 1998): 16-25.

High-Pressure, High-Temperature Well ConstructionAdamson K, Birch G, Gao E, Hand S, Macdonald C,Mack D and Quadri A. Vol. 10, no. 2 (Summer 1998): 36-49.

High-Pressure, High-Temperature Well Logging, Perforating and TestingBaird T, Drummond R, Fields T, Langseth B, Martin A,Mathison D and Silipigno L.Vol. 10, no. 2 (Summer 1998): 50-67.

Innovations in Wireline Fluid SamplingCrombie A, Halford F, Hashem M, McNeil R, Melbourne G, Mullins OC and Thomas EC.Vol. 10, no. 3 (Autumn 1998): 26-45.

Key Issues in Multilateral TechnologyBosworth S, El-Sayed HS, Ismail G, Ohmer H, Retnanto A, Stracke M and West C. Vol. 10, no. 4 (Winter 1998): 14–28.

Localized Maps of the SubsurfaceChang C, Coates R, Dodds K, Esmersoy C, Foreman J,Hoyle D, Kane M and Watanabe S.Vol. 10, no. 1 (Spring 1998): 56-66.

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

Planning and Drilling Wells in the Next Millennium Clouzeau F, Hansen R, McCann D, Michel G, Neff D,Prouvost L and Ritchie G. Vol. 10, no. 4 (Winter 1998): 2–13.

Pushing the Limits of Formation Evaluation While DrillingBourgeois TJ, Bramlett K, Cannon D, Craig P,Harkins R, Hodenfield K, Lovell J and Pigram I. Vol. 10, no. 4 (Winter 1998): 29–39.

Seismic Integration to Reduce RiskHope R, Ireson D, Leaney S, Meyer J, Tittle W and Willis M.Vol. 10, no. 3 (Autumn 1998): 2-15.

Streamlining Interpretation WorkflowBeardsell MB, Buscher H, Denver L, Gras R, Tushingham K and Vernay P. Vol. 10, no. 1 (Spring 1998): 22-39.

Using Downhole Annular Pressure Measurements to Improve Drilling Performance Aldred W, Bern P, Carpenter B, Cook J, Hutchinson M,Leder PC, Lovell J and Rezmer-Cooper I. Vol. 10, no. 4 (Winter 1998): 40-55.

NEW BOOKS

Environmental GeologyMurck BW, Skinner BJ and Porter SC.Vol. 10, no. 1 (Spring 1998): 70.

Fossil Hydrocarbons:Chemistry and TechnologyBerkowitz N.Vol. 10, no. 3 (Autumn 1998): 58.

Geophysics for Sedimentary Basins Henry G.Vol. 10, no. 1 (Spring 1998): 70.

A Handbook for Seismic Data Acquisition in ExplorationEvans BJ.Vol. 10, no. 2 (Summer 1998): 70.

McGraw-Hill Dictionary ofGeology & MineralogyParker SB (ed). Vol. 10, no. 3 (Autumn 1998): 58.

Micropaleontology inPetroleum ExplorationJones RW.Vol. 10, no. 2 (Summer 1998): 70.

The MIT Guide to Science and Engineering Communication Paradis JG and Zimmerman ML.Vol. 10, no. 3 (Autumn 1998): 58.

Modern Geophysics in Engineering GeologyMcCann DM, Eddleston M, Fenning PJ and Reeves GM (eds). Vol. 10, no. 2 (Summer 1998): 70.

On the Rocks: Earth Science for Everyone Dickey JS Jr.Vol. 10, no. 1 (Spring 1998): 70.

Petroleum and Basin EvolutionWelte DH, Horsfield B and Baker DR (eds).Vol. 10, no. 3 (Autumn 1998): 58.

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