Since the mid-1980s, producers and serviceproviders have struggled to remain profitable asunstable oil prices moved generally lower. In the1990s, oil companies downsized and started rely-ing on outside services for functions that are notconsidered core business activities. They turnedto outsourcing, alliances, partnerships and, lately,to mergers. The oilfield supply sector also restruc-tured, formed joint ventures, consolidated, andbegan providing integrated products and servicesto fulfill operator needs. Once again, market con-ditions and emerging trends are driving the indus-try to adopt fresh approaches, including bettermanagement of oil and gas fields.

To squeeze optimal value from petroleumassets, management of production operationsbegins at near-well regions of a reservoir, pro-ceeds through completion equipment and surfacefacilities, and may even extend to sale or exportpoints (next page). Ideally, production manage-ment begins before field startup to limit risk andfinancial exposure, reduce capital investmentand minimize time to first commercial output,particularly since many new reservoir discoveriesare in frontier areas where expenses are high.For mature reservoirs, this process involvesreducing expenses, enhancing productivity and

extending field life to improve profitability andmaximize recovery. Effective production manage-ment may be the difference between saving anasset and divesting or abandoning a property.

This tactical process takes quality, health,safety and environmental (QHSE) as well as eco-nomic factors into consideration. Local experi-ence and expertise in applying new or existingtechnology help reduce costs while optimizingfield output and hydrocarbon-processing capacity.Use of innovative methodology is a key element.Because technical, managerial and operationalaspects are combined to support optimization andasset development strategies, this renewedemphasis on production differs from traditionaloutsourcing of field operations, often referred toas contract lease, or pumping, services.

The past 15 years have been extremelydynamic in the upstream petroleum business.Companies continually reinvented and reposi-tioned themselves in response to businesspressures and challenges. This article reviewstrends behind a production management renais-sance and explains why new approaches areneeded. In addition to what and why, we discusshow this process is being reengineered,improved and implemented.

2 Oilfield Review

New Tactics for Production Management

W. Bruce LoweMidland, Texas, USA

Gary L. Trotter Sugar Land, Texas

For help in preparation of this article, thanks to Henry Clanton, Houston, Texas, USA; and Alan Means,Midland, Texas.IRO (Integrated Reservoir Optimization), NODAL andPlatform Express are marks of Schlumberger.

Focused efforts are helping oil and gas producers realize more economic potential

from hydrocarbon assets. Through savvy operating practices and new cooperative

relationships with an integrated service provider, field personnel and production

analysts use local experience and the latest technology to achieve the best results

from available infrastructure, resources, products and services.

Oil storage

Productionmanifold

Compressorstation

Gas exportpipeline

Producedgas

Injection-gasmanifold

Rod pump

Meteringand control

Producingwells

Producedfluids Gas and oil

separator

Waterdisposal

well

Oil exportpipeline

Producedwater

Producedoil

Wellheadtubing and

casingpressure

Gaslift

Naturalflow

Electricsubmersible

pumps

Injection gas

> Managing field operations. Production managementefforts encompass activities from near-well regions of producing formations through subsurface well completion equipment to surface facility networks that initially process and move hydrocarbons topipelines for transfer to a point of sale. For oil and gasdevelopments—large or small—a focused process isneeded to develop plans, establish budgets, overseeschedules, control capital investments and operatingexpenses, meet timetables, reduce artificial-lift costs,increase field output, improve hydrocarbon handlingand administer joint-interest revenue.

3Autumn 1999

Industry TrendsThe upstream petroleum sector has not alwaysperformed as well as other industries. Underpressure to increase shareholder return, effi-ciency and costs were targeted for improvement.As a result, integrated oil and gas companies andlarge independents began breaking the histori-cally linked, long-chain E&P business into smallersegments that are flexible, efficient and easier tohandle. These specialized asset-based units arestructured to be more responsive. After restruc-turing and reorganizing to improve performance,unit resources—properties, employees and sup-pliers—are consolidated so that a streamlinedorganization can concentrate on activities inareas where assets can best be exploited.Service companies, which are also focusing onkey competencies and activities that deliver morevalue or offer the most competitive advantage forclients, are undergoing a similar rationalization.

Breakup of the traditional value chain is caus-ing operators to look hard at organizational effec-tiveness, and many companies are finding thatin-house functions can be improved by partneringwith other producers and by forming strategicrelationships with service providers throughlong-term contracts and alliances. Some opera-tors continue to use a periodic low-bid approachthat may fulfill immediate needs, but is oftencounter to finding the best applications for

today’s technology and service solutions. Oil andgas companies that consistently emphasize over-all production and asset management are settingstandards and benchmarks for operations andperformance in the next decade.

Long-term relationships have facilitated con-solidation in the service sector, which has been agenesis for wider ranges of products and servicesthat deliver customized as well as reliable, cost-effective solutions. Operators, however, now

expect service companies to provide integratedprocesses for products, services and solutionswithin their areas of expertise (see “ProcessesWithin a Process,” page 6 ). New product and ser-vice combinations applied through the appropri-ate integrated support process free up operatorresources that were previously committed to indi-vidual projects, allowing them to be used forother core business functions. In this way, oilcompanies can add even more value and further

4 Oilfield Review

Gainshare program

OIL

COST

Actual results

Assetowners

Servicecompany

Businessplan

> A gainshare joint venture. Under value-pricing arrangements, alliancepartners and team members responsible for project design, construction,installation, operation and management share financial rewards for resultsthat add value beyond plan projections from enhanced production rates,improved recovery or cost reductions.

Subsurface Wells ServicesProduction andfacilities

Dación Asset Management

AssetManager:LASMO

ProjectManager:

Schlumberger

Caracas

Dación fields

CARIBBEAN SEA

LakeMaracaibo

Orinoco River

Bachaquero fieldEl Tigre

VENEZUELA

FinanceProductionenhancement

> An integrated alliance. Working closely with clients in a joint project organization, Schlumberger Reservoir Management coordinates field developmentthrough Integrated Project Management (IPM) services. Multidisciplinary teams oversee all aspects of production management and reservoir optimization. A board comprised of senior client and Schlumberger managers stewards alliance goals and objectives, and acts as an interface between the joint projectteam and sponsoring companies.

Autumn 1999 5

increase shareholder return by directing companyenergy and efforts toward managing risks, assetportfolios, competitive acreage positions, acquisi-tions, mergers and exploration programs thatreplace and add reserves.

Further supporting this trend in service inte-gration is a willingness among operators to baseservice compensation, or rewards, on results thatare achieved and the incremental value added bya service company in proportion to the degree ofrisk that is shared—value pricing (previous page,top).1 More than any other, this factor helps alignobjectives and set the stage for agreementsbetween producing and service companies tojointly manage production operations.

A type of risk-reward structure is used in theDación oil fields of eastern Venezuela.2 This large-scale project involves redevelopment of a majorasset. When the current production contract wasawarded in 1998, these fields had 111 active wellsand 136 inactive wells, and output was less than10,000 BOPD [1590 m3/d]. The work scope foralliance partners LASMO and Schlumbergerincludes seismic data acquisition and evaluation,300 new wells, 180 remedial well interventions,facility upgrades and artificial-lift optimization.Several teams responsible for design and man-agement of this tactical development effort inter-act on a daily basis (previous page, bottom). The

goal of this technology alliance is to improve out-put above 90,000 BOPD [14,300 m3/d] and achieveultimate recovery of at least 35%.

Under this agreement, Schlumberger partici-pates in production management and reservoiroptimization by providing products and serviceson a preferred-supplier basis, but does not have anequity interest. Value pricing for this technologyalliance is a gainshare system with incentivesbased on maximizing project net-present-value(NPV) over a 20-year production contract. Othercompanies participate through third-party con-tracts awarded by tender and bids. One year afterthe fields were handed over to LASMO in April1998, production had been increased from 10,000to over 30,000 BOPD [4770 m3/d].

The Case for ChangeOil company asset portfolios encompass numer-ous properties, some of which include maturefields near the end of the development life cyclewhen production is declining. Many new fieldsare in high-cost heavy-oil, gas, deepwater, remoteor environmentally sensitive provinces, requiringoperators to redirect internal resources. Morethan ever, because of continually changing marketconditions and corporate priorities, producersneed the flexibility to access experienced person-nel who can work exclusively on a project.Because of downsizing, consolidations, reorgani-zations, joint ventures and mergers, the older,smaller or nonstrategic fields are often sold,traded, or perhaps worse, ignored. For thesetypes of assets, production management servicesmay be best (above).

Some of these reservoirs will produce at eco-nomic rates for many years; others like theDación fields can yield more if companies haveresources to operate and manage them effec-tively. Optimal use of critical internal and exter-nal resources, and relying on an alliance partnerwith expertise in a particular area can improvefield performance. By using technology and inte-grated processes to fully exploit reservoirsthrough improved cost control and efficiency,companies can establish, sustain and, ultimately,increase asset value.

Use of outside providers for some businessfunctions or operating activities, and alliancesbetween clients and service companies that sup-port them are not new to industry in general orthe oil and gas sector in particular. Automobilemanufacturers were among the first to formalliances with suppliers. These mutual arrange-ments leveled the playing field for supply compa-nies by stabilizing demand and establishing abase income level that ensured a dependablerevenue stream. In return, product and serviceprices were lower, and automobile companiesreduced costs by participating in and helpingdirect supplier research and development.

Oil and gas producers and service companiesbenefit from alliances in the same ways as theautomobile industry. By the end of the 1980s,cost-reduction efforts by operators resulted in

Cash flow

Grow

thCompetitiveadvantage

No competitive advantage

Cash valuegreater thantrade value

Trade valuegreater thancash value

Market valuegreater than

owner perceivedvalue

Owner perceivedvalue greater

than market value

Frontier exploration Core assets and key properties

Fields near abandonment Mature harvest andsecondary recovery

Sellportfolio

Outsourceportfolio

Divestportfolio

Retainportfolio

Tradeportfolio

Operateportfolio

Assetportfolio

> A niche for production management. Rather than sell and trade properties or defer schedules and expand organizations to work on small, noncore and mature field projects, a viable alternative may be managing production through an oilfield services organization. This innovative, cost-effectiveapproach can be used when operators have limited infrastructure in an area or choose not to use in-house resources exclusively, and for large,mature or complex fields.

1. Bartz S, Mach J, Saeedi J, Haskell J, Manrique J,Mukherjee H, Olsen T, Opsal S, Proano E, Semmelbeck M,Spalding G and Spath J: “Let’s Get Most Out of ExistingWells,” Oilfield Review 9, no. 4 (Winter 1997): 2-21.

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

(continued on page 8)

Increasing asset value through improved reser-voir performance has been pursued for decades,but productivity and recovery results were oftendifficult, sometimes impossible, to attainbecause crucial tools and technologies wereeither unavailable or inadequate. Today,advanced technologies and rigorous process-driven approaches offer ways to reach produc-tion goals and take oilfield efficiency to newlevels. The IRO Integrated ReservoirOptimization methodology is a well-defined,closed-loop process to help operators maximizereservoir performance (below).1

For new fields, this macro-process representsan approach to understanding reservoirs thatencompasses activities from exploration anddiscovery through reservoir development andproduction management to abandonment. Inexisting fields, most, if not all, of these princi-ples can be applied with emphasis on renewing,or rejuvenating, production, and remedialactions to enhance productivity, extendlongevity, increase recovery and improvefinancial results.

For either type of asset, this is a complextask, requiring innovative solutions and the

latest fit-for-purpose technology. The IRO pro-cess hinges on closing a loop that consists offour principal elements: reservoir characteriza-tion through seismic and wireline formationevaluation, reservoir development throughpetroleum and facility engineering implementedusing oilfield drilling and production services,and reservoir management through project, pro-duction and asset management, supported byconsulting services and permanent downholemonitoring with well process control (see“Controlling Reservoirs from Afar,” page 18).

Time-lapse seismic surveys help pinpointbypassed hydrocarbons, and comprehensiveproduction logs confirm flow profiles and fluidsegregation. As more data are collected andanalyzed to refine reservoir and economic simu-lations, a clearer picture of reservoirs emergesto aid decision-making on capital-intensiveprojects such as infill drilling or horizontal wells to access bypassed formation intervals and intersect more producing intervals ornatural fractures.

The motivation behind an integratedapproach to reservoir optimization was to define step-wise procedures for optimal reser-voir development and management as a way of identifying deficits in existing technology and new wellsite services that were needed toimprove field production and reserve recovery.For example, areas that will benefit fromfurther technological improvements includeenhanced time-lapse seismic acquisition, down-hole process control, a new generation of soft-ware for geological and reservoir modeling, andrevolutionary formation evaluation tools, likethe Platform Express well logging platform.2

Processes Within a Process

6 Oilfield Review

Reservoir Characterization

IntegratedReservoir

Optimization

Field Implementation

DevelopmentPlanning

Rese

rvoir

Mon

itorin

gan

dCo

ntrol

1

5 6

78

2

34

> The complete optimization circuit. Four steps form the IRO Integrated Reservoir Optimization iterativeprocess loop—reservoir evaluation and characterization using oilfield services to acquire, process andevaluate seismic and well log data (1 and 5), reservoir exploitation planning through production manage-ment (2 and 6), and reservoir development plan implementation with custom solutions from integratedproducts and services (3 and 7). The final step is reservoir management, which includes monitoring, controland processes to optimize field operations (4 and 8). During initial appraisal and development (1 through4), formation properties and conditions are determined along with basic structure and boundaries. Basedon drilling and evaluation during subsequent development, exploitation and production (5 through 8),models are updated to better reflect reservoir behavior. For example, compartments may be identified asreservoir assessment proceeds.

1. See reference 2, main text.2. Barber T, Jammes L, Smits JW, Klopf W, Ramasamy A,

Reynolds L, Sibbit A and Terry R: “Real-Time OpenholeEvaluation,” Oilfield Review 11, no. 2 (Summer 1999): 36-57.

3. See reference 1, main text.

The IRO approach represents an extendedcommitment, often requiring the life cycle of a field—20 years or more in some cases—toachieve full success. While always involvingshort-term decisions, the IRO process concen-trates on major tasks to improve total reservoirperformance (above). Production managementis a micro-process, a subset of this integratedprocess, which is used on a daily basis to evalu-ate and reassess factors that control reservoirbehavior and field performance. Development

and operating plans are reviewed and updated,revised plans are implemented, and results aremonitored against established benchmarks.

Applied within the framework of productionmanagement, production enhancement, gettingthe most production from existing wells, is animportant subset of the IRO process and a keyto reservoir optimization. Using proven NODALanalysis techniques, a multidisciplinaryProduction Enhancement Group (PEG) proac-tively identifies wells with a performance gapbetween actual and potential productivity—candidate recognition—so remedial action can

be taken (below).3 Production enhancement isone of many functions that drive productionmanagement activities by increasing the overalleffectiveness of integrated well services, whichin turn, are pivotal in improving reserve recov-ery and maximizing value through reservoiroptimization and portfolio-level asset manage-ment over longer time periods.

As a key reservoir or asset management toolwhen field output declines and a key to main-taining plateau oil and gas production for aslong as possible, production management is ofcritical importance.

Autumn 1999 7

Implement capital program

IRO,

per

iod

1 ye

ar

Field development plan

Reservoir model

Macro-monitoring

Field operations

Monitor results

Execute plan

Review operating plan

Identify drivers

Prod

uctio

n m

anag

emen

t, pe

riod

1 da

y

> Integrated reservoir optimization and produc-tion management. The IRO approach incorpo-rates major tasks associated with improvinglong-term reservoir performance, but alsoinvolves making near-term decisions. The pro-duction management process flow, which is usedto reevaluate and address factors that deter-mine day-to-day reservoir behavior and fieldperformance, is a subset of this process.

Productionenhancement

Reservoir IPRReservoir IPR

Flow-co

nduit

perfo

rman

ce

Flow-conduit

performance

Pres

sure

Pote

ntia

l

Curre

nt

Productivity gap

Rate

Reservoir and completion

Add pay

Reperforate

Acidize

Fracture

Drill lateral or horizontalwellbore

Control sand

Control water and gas

Flow conduit and facilities

Clean out fill

Remove scale

Optimize tubular designs

Redesign artificial lift

Coiled tubing completions

Early production facilities

> Proactive production enhancement. Closing single-well performance gaps in wells when output is lessthan potential productivity is the objective of production enhancement. This goal is achieved by apply-ing integrated services and custom solutions that move reservoir inflow performance relationship (IPR)curves up and to the right, and move flow-conduit performance curves down and to the right.

formation of the first oil-industry alliances. Thesepartnerships involved varying levels of participa-tion and took different forms. Alliances havebeen formed between one or more producers,between producing and service companies, andbetween product and service suppliers.

Through the 1980s and 1990s, these effortsreduced costs significantly, which improved theindustry’s economic picture and financial struc-ture (right).3 Now, the question is how can per-formance and efficiency be improved further?

One answer is long-term production manage-ment enhanced in four ways: by focusing on keybusiness segments and strategic geographicareas; by optimal use of personnel andresources; by applying appropriate E&P technolo-gies; and by leveraging the competencies ofother companies—operators and service.Addressing these factors simultaneously ensurescost-effective operations, helps maintain highreserve-replacement ratios and improves returnon investment. A common thread that runsthrough this process is selection and applicationof custom integrated solutions over the remain-ing life of a field. Generating customized solu-tions to get the most return from oil and gasassets is best achieved through cooperation andthe combined strengths of all parties involved.

Managing production was always a serviceactivity, even though traditionally handled by oilcompany in-house groups. A contract operator orproduction management team that hires localspecialists can concentrate on a project, trimexpenses and increase value for asset owners byboosting field output and extending the economiclife of a reservoir. Using the best practices formanaging production, well and facility interven-tions, field operations, reservoir performance orentire asset portfolios, an integrated servicecompany can supply engineering design, welldrilling and completion planning, artificial-liftoptimization, production and injection analysis,joint-interest billing and other financial account-ing, including petroleum export marketing forsome projects. Production management servicescan also provide functions ranging frompetroleum land, and E&P permit or contract workto exploration and geologic evaluations.

A production management alliance or part-nership strengthens QHSE performance, reduceslifting costs, increases field output, improvesprofitability and adds long-term value. Through

ongoing research programs, product devel-opment and service expansion, Schlumbergercapabilities facilitate production management(see “Integrated Projects and Consulting: A Continuing Commitment,” page 12 ). Innovativeand cost-effective approaches achieve successby combining global expertise and state-of-the-art technology with local experience, and areavailable when operators have limited infrastruc-ture in a particular location or choose not to useinternal resources exclusively, and for large,mature or complex fields.

A New Approach Day-to-day management of production is tacti-cal, but in practice, it impacts strategic reservoirand asset management. In this way, it differsfrom contract operations of the past, whichfocused only on daily or monthly productiontargets for cost-plus or day-rate compensa-tion. Also, these contract “lease-pumping”arrangements seldom included geoscience orpetroleum engineering consulting support. TheSchlumberger approach is to provide an alterna-tive process that supports cost-reduction efforts,

8 Oilfield Review

14

12

10

8

6

4

2

0 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97

Finding and development costs

Lease-operating expenses

General andadministrative costs

Cost

, $/b

bl o

f oil

equi

vale

nt

Year

> Oilfield efficiency. Targeting expenses and performance throughout the 1980s and 1990s significantlyimpacted the economic picture and cost structure in the upstream petroleum business. Cost reductionefforts during the past 15 years resulted in a 48% decrease in finding and development costs, a 27%drop in lease-operating costs and a 20% reduction in general and administrative costs.

Explorationdrilling

Seismicsurvey

Discovery

Infill drilling

Production management

Appraisal AbandonmentDevelopment Production decline

Production profile

Production operations

Well and facilityintervention

Petroleum andfacilities engineering

Data feedback

> Production management. Efforts to manage field operations through an alliance or partnershipinvolve working with asset owners to achieve mutual goals. This process consists of three activities—petroleum and facilities engineering, well and facilities engineering, and production operations—linked to deliver project management and associated integrated-service solutions while overcoming the limitations of traditional joint producer and service-company relationships.

3. 1998 Sterling Consulting report.

Autumn 1999 9

delivering initial step-function improvements inlifting costs and further levels of production effi-ciency later in a project.

This fundamentally new way to manage pro-duction enhances asset value through leading-edge technologies, best-in-class products andservices, custom solutions, engineering consult-ing and an integrated process carried out inconjunction with oil and gas company organiza-tions. This comprehensive performance-basedeffort consists of three principal activities—engineering, intervention and operations.Linked in an integrated process, these activitiesdeliver production management and associatedservices while overcoming the disadvantages oftraditional producer and service-provider rela-tionships (previous page, bottom).

Production management functions include per-sonnel and human resources, information technol-ogy, financial issues and accounting, material orequipment procurement and logistics, oilfield ser-vices, QHSE compliance, commercial contracts,joint-interest relations and other relationships orcommunications outside of the alliance. Althoughtargeted initially for onshore basins in North andSouth America, this model is applicable acrossgeographic regions and offshore.

To achieve mutual objectives and optimalresults, operator and Schlumberger organizationsmust work together to integrate services, pro-cesses and management. In a natural progres-sion from multidisciplinary asset groups in an oilcompany, successful alliances with a servicecompany include a cross section of personnelfrom each company in a project team that over-sees daily operations. Executives from both com-panies steward long-term goals and performanceas members of an oversight committee.

A joint production management effort mayinvolve a Joint Leadership Team (JLT) committeeand Joint Project Management Team (JPMT). TheJLT integrates the two companies on a manage-ment level to align strategic issues, measure per-formance and determine future goals, objectivesand directions for the asset. The JPMT integratesalliance partners and third-party vendors on a tac-tical level (see “An Alliance to Manage Production,”page 15 ). Dación project management in Venezuelais organized using this approach.

The engineering phase includes asset-leveland reservoir-level activities. On a technical,basin or regional level, geologic aspects of a pro-ject are typically handled by the operating com-pany, or asset owners, as part of their portfoliomanagement and financial responsibilities. Thisensures a proper E&P perspective and diligentoversight. Reservoir-specific activities pertinent

Portfolio levelRegionalBasin

Asset levelFieldReservoir

Petroleumand facilitiesengineering

Well andfacility

intervention

Productionoperations

Reserves evaluationIdentifyAnalyzeEstimateReport

Economic evaluationExploration justificationDevelopment justificationProject planningBudgetingBusiness planningAsset management

Performance evaluationMonitoring and surveillanceModelingSimulation

Geology

Reservoirengineering

Productionengineering

Facilitiesengineering

Geologic evaluationDepositionalPetrophysicsGeophysicsDevelopmentCorrelations

Formation evaluationDrilling coresWireline well logsFluid samplesHydrocarbon analysis

Well planning and designGeometryTubularsSubsurface equipmentInitial completionPerforationProduction analysisStimulationWell interventionsArtificial-lift evaluation

Facilities planning and designInstallationOptimizationPreventive maintenanceFailure repairsUpgradesSystem debottleneckingField operationsField compressorsCentral processing stationsGas plants

E & P data serviceGatheringManagementTechnical analysis

Project planning and productionengineering. The petroleum andfacilities engineering phase ofproduction management involvescorporate asset-level, regional-leveland basin-level strategies as well asreservoir-level considerations. In aproduction management servicearrangement, asset owners typicallyaddress strategic issues, whilealliance teams handle activitiesrelated to tactical field operationsfor specific reservoirs. This phaseincludes reservoir performance and economic analysis, formation characterization and evaluation, and initial completion technology.

to production management and reservoir develop-ment are a JPMT responsibility. This includes for-mation evaluation, reservoir performance andeconomic analyses, and completion technology(above). Production planning, petroleum and facil-ity engineering, data gathering and informationprocessing are part of this phase, which, in addi-tion to technical excellence and strong manage-ment skills, requires effective evaluation,planning, budgeting and accounting software.

>

The well and facility intervention phaseinvolves new construction or remedial work thatencompasses completion technology and designsupported by formation evaluation, regulatory andclient approval, contingency and risk management,purchasing and material logistics, and drilling orworkover activities (left). These activities can behandled by the operator or service company sepa-rately, or by a JPMT, depending on contractualagreements or defined project scope. An under-standing of field development objectives, planningand cost control, and exceptional QHSE perfor-mance are required in this phase.

10 Oilfield Review

Petroleumand facilitiesengineering

Well andfacility

intervention

Productionoperations

Subsurface

Surface

Well work coordination, materials and execution

Drilling operations Rigs Pressure controlDrilling fluids and hydraulicsDrilling bitsCementingPerforating and completionWell testingStimulationRoutine repairsCased-hole loggingRecompletions Workover fluidsProduction enhancementArtificial-lift repair and optimization

Facility work coordination, materials and execution

Installation and constructionOptimizationPreventive maintenanceFailure repairsEquipment upgradesSystem debottleneckingCompressor installation

> Execution of the development plan. The well and facilities intervention phase of production management consists of well and surface facility upgrades or newconstruction, formation evaluation support for completion technology and designs,obtaining regulatory and client approvals,managing risks and contingencies, materialpurchasing and logistics, and well drilling or remedial interventions.

Feb MarJan Apr May June July Aug Sep Oct Nov Dec

Well IWell H

Well GWell FWell EWell D

Well CWell BWell A

0

1

2

3

4

5

Oil r

ate,

100

0 B/

D

N

Charlie

Delta

Bravo

AlphaEcho

Forties field

UK

Aberdeen

> Artificial-lift optimization. A systems approach to gas-lift analysis, design and performance monitoring within the framework of a structured production management process increased individual well output rates and helped optimize production from the BP Amoco Forties field inthe North Sea.

Petroleumand facilitiesengineering

Well andfacility

intervention

Productionoperations

SubsurfaceWell operations

Daily field activitiesMonitoring and surveillanceData acquisitionProduction reportingCost reportingDiagnosticsTroubleshooting

Well maintenance

Wellhead equipmentArtificial-lift equipmentPreventive maintenanceFailure repairsSuspensionAbandonment

Well optimization

NODAL analysisProduction enhancementSurface equipmentFlowlinesData management and analysis

Facility optimization

Production separation vesselsField batteriesFlowlinesField gathering system

Facility operations

Daily field activitiesMonitoring and surveillanceData acquisitionProduction reportingCost reportingDiagnosticsTroubleshooting

Facility maintenance

Production separation vesselsField batteriesFlowlinesField gathering systemPreventive maintenanceFailure repairsEquipment replacement

Surface

Support Project management

QHSERegulatory compliance and approvalsClient contacts and approvalProduction administrationAccountingBusiness planningExpense and capital budgetingFinancial and operational reportingMaterial purchasing, inventory control and logisticsSupplier and subcontractor supervisionService coordinationHuman resources and payroll

Managing production operations. Surfaceand subsurface surveillance, enhancementand maintenance are encompassed by theproduction operations phase of productionmanagement. This phase includes fieldoperations, equipment lease or purchase,maintenance of wells and facilities, controlof the production process, hydrocarbon volume reports, finance and revenueaccounting, and, in some cases, marketingof produced oil and gas. These activitiesyield the results of plans formulated in thepetroleum and facilities engineering phase.

4. Fleshman R, Harryson and Lekic O: “Artificial Lift forHigh-Volume Production,” Oilfield Review 11, no. 1(Spring 1999): 48-63.

Autumn 1999 11

In the production operations phase, effortsinvolving production surveillance, enhancementand maintenance can be divided into surface andsubsurface processes that include field opera-tions, equipment purchasing or leasing, well andfacility maintenance, well-process control andoptimization, production volume and revenuereporting, finances and accounting, and hydro-carbon delivery or export (right). This phaseyields the results of plans set in motion duringthe first phase—petroleum and facilities engi-neering—and includes a feedback loop to pro-vide analysis and evaluations for continuallyimproving the next stage of reservoir develop-ment. Rigorous monitoring and control ofexpenses, production and QHSE performance arerequired as well as an understanding of fielddevelopment and production plans, and portfo-lio-level or asset-level strategies.

Artificial-lift analysis is recommended as anactivity during the production operations phase.These evaluations identify inefficiencies anddeliver near-term production enhancement.4 Anexample of artificial-lift optimization is the BPAmoco Forties field in the North Sea where bothgas lift and electric submersible pumps are used.This field has four main platforms produced pri-marily by gas lift and one lifted solely with elec-tric submersible pumps. Production is declining,but substantial recoverable reserves remain.

Working closely with Camco Products andServices and later the enhanced oil recovery(EOR) group, the operator began submersiblepump operations in the late 1980s, and gas-liftsystems were installed in the early 1990s.Initially, gas-lift and submersible pump teamsconcentrated on their specific technology andperformance, but over time, a total systemsapproach evolved that encompassed all aspectsof artificial lift, reservoir surveillance and pro-duction engineering. Gas-lift optimizationinvolving analysis, design and performancemonitoring resulted in incremental rate gains on individual wells (previous page, bottom).

(continued on page 14)

>

The Schlumberger commitment to reservoir per-formance optimization and project managementbegan in 1995. In that year, the IntegratedProject Management (IPM) organization wasformed to fulfill operator requirements throughglobal expertise in combination with local expe-rience.1 The Production Enhancement Group(PEG) initiative was started and Holditch &Associates was acquired in 1997. This was followed by launch of the IRO IntegratedReservoir Optimization service.

Performance on major projects worldwide hasprovided extensive integrated service activityand project management experience. During thepast four years, these organizations have workedsuccessfully on projects ranging from integrateddrilling and well servicing for the North SeaAndrew and Cyrus fields, and the Eastern TroughArea Project (Mungo, Marnock, Machar andMirren fields) to the Hibernia, Wytch Farm andMachar field alliances. Projects in Africa andSouth America, like the Dación field redevelop-ment, are also included in this track record.

Within major or stand-alone projects, pro-duction management services have gainedacceptance and are increasingly important inthe upstream petroleum sector. Acquisition of

Coastal Management Corporation (CMC) in1998 further strengthened Schlumberger capa-bilities in this area. Formed in 1989, the CMCorganization, which developed from a produc-tion operating company background, compiled a strong record of implementing projects fromlarge-scale coalbed methane developmentdrilling to production management of majorwaterflood operations (below). Schlumbergergoals paralleled those of CMC, creating a natu-ral fit that led first to formation of an integratedalliance and then, ultimately, to the acquisition.

In addition to an existing waterflood produc-tion management project in West Texas, CMCpreviously operated the Bryan-Woodbine fieldnear Bryan, Texas, USA, which involved handlingworking-interest relations and accounting for435 joint-interest and 15,000 royalty owners,and dealing with complex environmental issues.In the Alabama, USA, Black Warrior basin,CMC scheduled and managed a 14-rig coalbed-methane program for more than a year, drillingmore than 400 wells and coordinating a $175million budget.

Integrated Projects and Consulting: A Continuing Commitment

12 Oilfield Review

Cerro Priesto Geothermal ProjectBaja California, Mexico

M.A.K. ProjectMartin County, Texas

Oak Hill fieldRusk County, Texas

Phillips Reef ProjectPermian BasinWest Texas and New Mexico

South Kilgore WaterfloodEast Texas field

Loco Hills ProspectEddy County, New Mexico

Two Freds (Delaware) FieldLoving, Reeves and Ward Counties, Texas

Waterflood ProjectCrane County, Texas

Bryan-Woodbine unitBrazos County, TexasWaterflood

Turner Town ProjectEast Texas fieldRusk County, Texas

Lisbon fieldClaiborne Parish, Louisiana

Robinson’s BendCoalbed Methane developmentTuscaloosa County, Alabama

Canyon Reef CarriersPermian BasinCO2 Pipeline (220 miles)

Alabama Perry North UnitLeon County, Texas

> Production and project management in practice. The CMC organization, which was developed in 1989 froma background of operating company experience, has a strong project implementation track record fromdevelopment drilling programs to large waterflood operations and major production management projects.

Each project had different parameters. TheBryan-Woodbine field involved solving revenueproblems. In Alabama, the project includedengineering design, accounting, control of capitalexpenditures and regulatory issues associatedwith tax credits for unconventional gas.

Recently, the Schlumberger Oilfield Servicesproduct lines were reorganized into three prod-uct groups—Reservoir Evaluation, ReservoirDevelopment and Reservoir Management—encompassing 13 service segments. Thesegroups develop and support the products andservices offered in four existing geographicareas: Asia; Europe, Commonwealth ofIndependent States and Africa; the Middle East;and North and South America. The ReservoirEvaluation group includes land and marine seis-mic surveys, and openhole and cased-hole wire-line well logging data acquisition, processingand evaluation activities. The ReservoirDevelopment group includes Anadrill, Camco,Dowell and Testing products and services. TheReservoir Management group, which combinesGeoQuest, Data and Consulting Services,Production Operators, Inc. from Camco andIPM, supports IRO Integrated ReservoirOptimization and production management processes (right).

Reservoir management embodies severalelements, including a strong commitment toexcellence in service delivery at the wellsite,integrated solutions and services, alliances,partnerships, value pricing and project man-agement skills. The Reservoir Managementgroup draws on Schlumberger technology andexpertise for field development planning andimplementation, but also relies on other best-in-class service providers and third parties to forma strong team.

Participation takes several forms, from simplecoordination of oilfield services to full involve-ment in design and management of field opera-tions. To facilitate effective communication andcooperation for life-of-reservoir projects, theimportance of involvement during conceptualengineering and detailed design phases isstressed. In addition to a critical mass of opera-tional expertise and a complete range of

drilling, completion, development planning andproduction management services, Schlumbergerhas forged engineering and constructionalliances with premier firms, including CoflexipStena Offshore, Bechtel Offshore and FluorDaniel. These arrangements are nonexclusive,with alliance partners representing preferred,first-choice suppliers in various areas.

Autumn 1999 13

Drilling andMeasurements

Well Completionsand Productivity

Cementing andStimulation

ReservoirDevelopment

Drilling Bits

Well Intervention

Seismic

ReservoirEvaluation

Wireline

Land Open Hole

Marine Cased Hole

GeoQuest

Data andConsulting Services

Integrated ProjectManagement

ReservoirManagement

Compression andProduction Systems

> A framework for reservoir management.

1. Bourque J, Tuedor F, Turner L, Gomersall S, Hughes P Jr,Klein R, Nilsen G and Taylor D: “Business Solutions forE&P Through Integrated Project Management,” Oilfield Review 9, no. 3 (Autumn 1997): 34-49.

Substantial improvement in submersible pumprun times were also realized (above).

Daily field operations may include operatingsurface equipment or valves to initiate and con-trol production or increase gas-lift injection ratesand pressures for artificial lift, but productionenhancement through proactive candidate recog-nition addresses individual well performance tocollectively increase total output from a field.These short-term rejuvenation efforts, which alsomay be part of the production management pro-cess, involve well servicing, modifying orinstalling artificial lift, pumping matrix acid orhydraulic fracturing stimulation treatments, andother remedial well interventions to improve orrenew production.

Developing aligned objectives is essential in any production management initiative.Commercial agreements combine near-term fixedcompensation based on lifting-cost improvementswith long-term rewards based on adding assetvalue (below). This model is applied on individualprojects, but can be used as a template for futurecollaboration across an asset portfolio to optimizereservoir performance and maximize value forboth the operator and the integrated serviceprovider. A mutual relationship that balances risksand rewards can deliver immediate results andensure continuous improvement.

14 Oilfield Review

1990 1991 1992 1993 19961994 1995

90

160210

270

400

520

600Run days600

500

400

300

200

100

0

Elec

tric s

ubm

ersib

le p

ump

run

time,

day

s

> Improved artificial-lift efficiency. A systems approach similar to the one used for gas-lifted wells in the North Sea Forties field significantly decreased electric submersible pump failures and increased the run life of these artificial-lift systems.

Lifting-cost model Value-based model

Initial reduction

Lifti

ng c

ost,

$/bb

l of o

il eq

uiva

lent

Net

pre

sent

val

ue (N

PV),

$

Actual results

Business plan

Base decline

Time

1 year

> Value-based production arrangements. Production management services require the support of value pricing through an alliance model that helps asset owners and the integrated service provider develop mutual goals and objectives. Most production management proposals involve near-term compensation based on reducing lifting cost,and a long-term risk-reward arrangement related to additional asset value based onproject net-present-value or a combination of NPV and lifting cost.

5. Haines L: “Is Outsourcing Your Out?” Oil and GasInvestor 12, no. 10 (October 1992): 69.

Autumn 1999 15

An Alliance to Manage Production In February 1991, Coastal ManagementCorporation (CMC) was selected from among sixcompanies to provide project management for agroup of oil and gas fields in the heart of thePermian Basin of West Texas, USA.5 CMC wasgiven responsibility for normal operator functions,including general management, exploration andpetroleum engineering, field production opera-tions, revenue accounting, joint-interest billing,accounts payable and material procurement.

At the time, the asset operator’s staff wasfully committed to other assets and projects. Thecompany estimated that a substantial number ofemployees would be needed to operate the project, but did not want to expand their organi-zation. Granted authority to manage and operatethis project, CMC hired 85 people with localexperience and assumed the production manage-ment role.

The project, which covers about 80,000 acres[324 km2] and includes more than 1350 activewells (2000 total wells) producing from multiplepay zones over 12 horizons in 47 fields, illustratesthe impact of focused production management.Before CMC assumed operations in May 1991,little upside potential was believed to exist in thefield, and previous operators had identified thisas a noncore asset. A multidisciplinary team wasassembled to carry out engineering and geologicevaluations, oversee operations and rejuvenateproduction output.

Study results led to several actions. Electricsubmersible pumps were installed in selectedwells. With reinterpreted seismic maps, 16 wellswere drilled. All but one of these wells were suc-cessful. Peripheral waterflood injection patternswere implemented along and between up-dipedges of overlapping formation sequencesacross the field (right). These boundaries wereidentified by two large-scale, Schlumberger-man-aged three-dimensional (3D) seismic surveys,which also resulted in new field discoveries forthis 70-year-old asset.

Working closely with a petroleum and facili-

Seismicboundaries

N

N

Seismicboundaries

Onlappingboundary

TEXAS

Seismic survey and waterflood results. A multidisciplinaryteam carried out engineering and geologic evaluations, managed field operations and began rejuvenating productionoutput. Peripheral waterflood injection patterns were initiatedalong and between up-dip edges of overlapping formationsequences identified by two large-scale, three-dimensional(3D) seismic surveys. Several new field discoveries weremade as a result of these surveys.

>

Working closely with a petroleum and facili-ties engineering team, groups responsible forwell and facility intervention, and productionoperations completed the initial stages of pro-duction rejuvenation. Total production rose fromabout 7000 to almost 12,000 BOPD [1120 to 1906 m3/d] in 1995 (right). Annual capital expen-ditures of less than $5 million in 1992 wereincreased each year to $35 million in 1998.Investment results were competitive and rates ofreturn compared favorably with other spendingopportunities of the working interest owners.

Control of lease-operating expenses is animportant part of effective production manage-ment for the project. In addition to the large num-ber of active production and injection wells, thereare 37 surface equipment batteries for productionseparation, three electrical distribution grids and anumber of other facility installations in the fields.Lease-operating expenses were reduced from his-torically high levels, but not to the point of ignor-ing prudent operating procedures and QHSEpractices. With an estimated reserve life of morethan 20 years, short-term spending limits are notallowed to override maintenance requirementsthat will ensure lease equipment and operationallongevity.

An integral part of managing lease-operatingexpenses and overall economic success on theproject is the enhanced relationships with ven-dors who participate directly in repairing wells.The objective was to promote cooperationbetween operational groups and companies thatprovide well servicing rigs, pumps and specialtychemicals. Well failure rates, at more than twofailures per well per year, exceeded a benchmarkof one failure per well per year for similar opera-tions. The dilemma was how to reduce rod, tubingand pump failures. A strong culture of teamworkin the CMC organization pointed to a new modelfor integrating best-in-class service providerswho could add value to the existing productionprocess.

The field organization was restructured aroundwell maintenance activities by organizing fieldproduction foremen into a Business Focus Teamwith management and supervisory personnel fromwell servicing rig, chemical treatment and subsur-face pump companies as members. This team con-centrated on improving well maintenanceactivities. In addition, the task of implementingimprovements in the field was assigned to a newWell Reliability Team, again consisting of alliancerepresentatives and specialists from each of thethird-party service providers charged with initiat-ing well maintenance improvements. Failures inrods, tubing and subsurface pumps weredecreased from 175 per month in 1991 to 40 permonth in 1998 (left).

16 Oilfield Review

200

180

160

140

120

100

80

60

40

20

Mon

thly

wel

l fai

lure

s

Mid-1991

Mid-1998

Chemical supplier

Downhole pumpmanufacturer

Productionmanagement team

Well servicing rig company

Prod

uction foreman

Well servicing rig company

Chemical supplier

Lease operatorDownhole pumpmanufacturer

> Improving efficiency. By implementing well maintenance improvements, rod,tubing and subsurface pump failures were decreased from 175 per month atthe end of 1991 to 40 in 1998. This reduced well failure rates from more thantwo to less than one-half failure per well per year, saving asset owners morethan $1 million per year.

> Optimizing production. Before CMC took over operations in May 1991, littleupside potential was believed to exist in the field. With reinterpreted seismicmaps, 16 wells were drilled. Production rejuvenation included switching toelectric submersible pumps for artificial lift in selected wells and peripheralwaterflood injection.

1

10

100

1

10

100

Oil r

ate,

100

0 B/

D

Gas

rate

, 100

0 M

cf/D

1982 1984 1986 1988 1990 1992 1994 1996 1998 2000

Oil production Initial oil decline Gas production Initial gas decline

Production managementalliance begins

Autumn 1999 17

Well failure rates were reduced significantlybelow the benchmark of one per year to less thanone-half failure per well per year. As a result, lift-ing costs were decreased by 34%, and well fail-ures were reduced 75%. These reductions savedworking-interest owners more than $1 millionover six years. At the same time, efficiencyimprovements through more direct involvementof the service partners allowed some alliancepersonnel to move to production managementtasks that add more value to the project. Wellmaintenance cost reductions were achievedwhile reducing the staff allocated to this activity.

By 1998, these teams had reduced well fail-ures to a point where further improvement wasnot cost-effective. The focus then shifted fromfailure reduction to production enhancement.Well servicing specialists have further improvedrevenue through artificial-lift analysis, optimiza-tion and modification. Developing a broader inte-grated services model than was used in thepast—one that provides continuity and concen-trates on process activities rather than individualdisciplines or narrowly defined tasks—helpedachieve these results.

Why is this approach successful? One key isthe ability of production management teams tofocus energy, creativity, expertise, technologyand local experience on a single project and tohave the flexibility to analyze problems anddevelop innovative solutions. Unique because itis a service organization that evolved from a pro-ducing company operational background, CMCmaintains a life-cycle perspective on the assets itmanages. This approach provides a model forcoordinating and administering production man-agement activities that is flexible and also deliv-ers maximum field performance.

Project administrative structure is transparentto clients and differs little from any other oil com-pany operation. Through mutually agreeablegoals and objectives, both parties share a long-range vision and the corresponding rewards ofthis value-adding production management pro-cess. Developed over ten years of well mainte-nance and field operating experience, CMCinternal systems and methods for managing day-to-day project activities by monitoring and track-ing field data allow operations personnel to makecost-effective decisions (below).

An Ongoing Management ProcessMarket conditions and emerging business trendsoffer compelling tactical, strategic and financialincentives to adopt a new production manage-ment approach. The challenges of declining pro-duction and a mature asset base can be met byaltering the way reservoirs are developed andmanaged from discovery to ultimate depletionand abandonment. By relying on alliances or part-nerships for production management, functionsand processes developed by an integrated serviceorganization like Schlumberger significantlyreduce demands on operator resources—finan-cial and personnel—to acquire, integrate andmanage the technologies, products and servicesinvolved in field operations. Oil company staffsare able to pursue business opportunities thatimprove asset value and financial return by redi-recting internal resources to activities of greaterstrategic importance.

Additional advantages come through costreductions from better application of technologyand expertise, more efficient purchasing, pricingand material sources, and expanded R&D capa-bilities. New approaches to reservoir develop-ment and management are not just a repackagedcollection of products and services that wereoffered piecemeal previously in response to clientrequests; they are customized solutions repre-senting the best technologies and methodologies.

Project management services gained accep-tance in the early 1990s. More recently, thesearrangements became established as viablemethods for meeting near-term tactical objectivesand achieving long-range strategic goals. Thistrend is likely to continue over the next decade asproducing companies pursue further productionoptimization and cost reductions. Controlling cur-rent expenses is important, but over the long-term, many mature properties around the worldneed engineering and operational attention. Thesepetroleum assets contain resources that theworld economy needs and producing countriescan’t afford to lose as a result of operational over-sights or resource limitations. –MET

AS 400FinanceProduction

Production management

FinanceLand

FinanceSource documents

REPORT

REPORT

REPORT

Billing

Revenue distribution

Production andregulatory reporting

Internal operationalreporting

Client reporting

Finance

Treasury

Purchasing

> Production management methodologies. Internal CMC systems and methods developed during a decade of well maintenance, field operating and production management outsourcing experienceallow alliance operations personnel to make cost-effective decisions.

It is human nature to seek to experience the inac-cessible. The planet Mars fascinates us, but itsremoteness, cold temperatures and thin atmo-sphere preclude a visit by humans for the timebeing. Just as it is difficult to study Mars first-hand, we cannot directly view all the compli-cated interactions within a hydrocarbon reservoirfrom the Earth’s surface.

In the case of the faraway planet Mars, thespecial Sojourner rover explored places humanscouldn’t. Removing enough rock from a wellboreto accommodate a human would be prohibitivelyexpensive, so we have traditionally used toolsconveyed by wireline, coiled tubing or drillpipeduring or after well construction to measure andrecord what we can’t see ourselves.

18 Oilfield Review

Controlling Reservoirs from Afar

John AlgeroyA.J. MorrisMark StrackeRosharon, Texas, USA

François AuzeraisIan BryantBhavani RaghuramanRuben RathnasinghamRidgefield, Connecticut, USA

John DaviesHuawen GaiBP Amoco plcPoole, England

Orjan JohannessenNorsk HydroStavanger, Norway

Odd MaldeJarle ToekjeStavanger, Norway

Paul NewberryLasalle Project ManagementPoole, England

For help in preparation of this article, thanks to Joe Eck,Houston, Texas, USA; Stephane Hiron and Younes Jalali,Clamart, France; and Mike Johnson, David Malone andTony Veneruso, Rosharon, Texas.ECLIPSE, TRFC-E (electric tubing-retrievable flow-controlvalve), Variable Window and WRFC-H (hydraulic wireline-retrievable flow-control valve) are marks of Schlumberger.

Understanding reservoir behavior is difficult enough; controlling it is an even

greater challenge. New, remotely operated flow-control technology is helping

make full use of reservoir knowledge and increasing production efficiency.

Autumn 1999 19

For a hydrocarbon reservoir, it is not just amatter of satisfying our natural curiosity, though.It is an economic imperative to understand andcontrol what is happening in the reservoirbecause ignorance can be very costly. For exam-ple, significant reserves may be lost to us foreverif water bypasses the hydrocarbons and breaksthrough into a producing well. In addition, fluids inthe reservoir might not be flowing where we wantor expect them to flow, especially in complexdevelopments featuring multilateral wells andcompletions in multiple pay zones.

Fortunately, we are now able to deploy down-hole completion devices that allow us to not onlymonitor the well from the surface, but alsoremotely control flow from specific zones into thewell and production tubing. As wells produce fluidfrom reservoirs, downhole sensors gather real-time or near real-time measurements that can beinput to computer programs that help analyze thereservoir and production operations. Engineerscan then determine how to adjust downholevalves to optimize production.

Through these advances in completion tech-nology, the industry can increase or acceleraterecovery from reservoirs while minimizing risks,lifting costs and expensive well interventions. Inthis article, we examine downhole measurementand control solutions that optimize production andreserve recovery.

The Complete PictureThe goal of any well completion is to safely,efficiently and economically produce fluids fromthe reservoir and bring them to the surface.1

While drilling a well to the desired depth mightseem like an end in itself, there are many moreoperations and decisions that precede productionfrom the wellbore (right). Casing or other tubularsmust be designed, selected and installed in thehole along with any tools and equipment neededto convey, pump or control production or injec-tion of fluids. Completion integrity depends on a good cement job or else the completion iscompromised from the start. Of course, thecompletion design must address reservoir type,drive mechanism, fluid properties, well config-uration and any complications that might exist,such as sand production or paraffin deposition,for example (next page).

Develop objectives forcompletion design •Safety •Efficiency •Economics

Consider location,wellsite andenvironmentalconstraints

Establish conceptualcompletion design

•Well construction,evaluation andstimulation considerations

•Workover requirements

Review design incontext of well andfield life (long-termissues)

Develop detailedcompletion design •Tubulars •Perforations •Stimulation •Completion fluids

Drill and test well Cement casing in place Install wellbore tubulars

Complete the well Install wellhead Initiate flow

Monitor and evaluate production Stimulate if necessary Install artificial lift if needed

Workover Reevaluate completion Production optimization

Assess expectedwell performance•Reservoir parameters

- Rock type and properties- Structure, boundaries

and dimensions•Fluid properties•Drive mechanism

> Steps toward well completion and optimized production.

1. For information on well completions: Economides MJ,Dunn-Norman S, Watters LT: Petroleum WellConstruction. New York, New York, USA: John Wiley and Sons, 1998.Hall LW: Petroleum Production Operations. Austin, Texas, USA: Petroleum Extension Service of The University of Texas at Austin, 1986.Van Dyke K: A Primer of Oilwell Service, Workover, and Completion. Austin, Texas, USA: Petroleum Extension Service of The University of Texas at Austin in cooperation with Association of Energy Service Companies, 1997.

20 Oilfield Review

Mechanical considerations

Subsea wellsDeepwater wellsExtended-reach wellsHorizontal wellsMultilateral wellsSlimhole wells

Tubular diametersReliabilitySimplicity SafetyCasing and tubing configurations

Drive mechanism and use of artificial lift

Water driveGas-cap driveDissolved gas drive

Reservoir type

Reservoir that produces sandReservoir with a water legFractured reservoirReservoir with a gas cap

Production complications

Sand productionStimulation needsSecondary recovery needs

Operating theaters

Remote areasOnshore or offshoreDeepwater or subsea

Reservoir fluids

GasOilWater

Completion practices

> Completion considerations. All aspects of the reservoir and well must enter into completion design.

Sensors Actuators IntelligentCompletion

Software

> Elements of an intelligent completion.

Standard completion technology—cementingcasing in the borehole, installing production tub-ing, packers and other production equipment, andthen perforating zones of interest to allow flowfrom the reservoir to the wellhead—has bene-fited the industry for decades. Moving forwardinto new operating environments and more com-plicated well designs requires better ways tooptimize production from wells without risky orpossibly ill-timed mechanical intervention.Surface intervention can be extremely difficult.Deepwater or subsea well intervention is oftenexpensive.2 Completion technology that relies onsurface flow-control valves alone precludesselective production from multiple flow units in asingle wellbore or one lateral of a multilateralwell. In the past, this has resulted in an inabilityto control production from commingled flow units,crossflow or suboptimal production. The lack ofdownhole flow-control technology can delay pro-duction and negatively affect net present value ifeach zone is produced sequentially.3

The absence of downhole monitoring devicesin traditional “dumb iron” completions, whichmake up the vast majority of completions, resultsin limited reservoir data. Total flow rate, well-head pressure and fluid composition might beknown from surface measurements, but theactual conditions in a producing zone and thecontributions of individual zones cannot beknown with certainty unless “smart” measure-ment devices downhole provide a more completeunderstanding of what each part of a wellborecontributes. Other options, such as well testingand production logging, provide data from dis-crete points in time, rather than a continuous his-tory. They present costs and risks, a key riskbeing the fact that a well test requires interrup-tion of production.

No matter what completion technology andpractices are used, reservoirs behave in unex-pected ways, particularly new reservoirs aboutwhich little is known. The ability to adjust down-hole equipment in response to real-time datamakes production surprises less worrisome. Thefirst installation of an intelligent completion, bySaga Petroleum in August 1997, initiated aninteractive phase in production optimization.4

Two years later, fewer than 20 advanced comple-tions exist around the world, but they areincreasing reserve recovery and proving theireconomic and operational worth.

Advanced Completion TechnologyThe design goal for intelligent completiondevices is safe, reliable integration of zonal iso-lation, flow control, artificial lift, permanent mon-itoring and sand control. An intelligentcompletion is defined as one that provides theability to both monitor and control at least onezone of a reservoir (below).5 There are manydifferent names for intelligent, or advanced,completions, but each suggests a significantimpact on asset management. Data acquisition,interpretation and the ability to optimize pro-duction by remotely adjusting downhole valvesdistinguish advanced completions from traditionalcompletions and offer the ability to interactivelyaddress a situation before it becomes a problem.

The foundation for successful use of surface-operated flow-control equipment downhole isreservoir data that help in decisions about effi-cient production of reserves. In an ordinary com-pletion, reservoir monitoring occurs only at

2. A well intervention might add as much as 30% to the $6 million to $8 million construction cost of a subsea well,whereas the initial intelligent completion might cost lessthan the intervention and provide better results over thelife span of the well. See: Greenberg J: “IntelligentCompletions Migrating to Shallow Water, Lower CostWells,” Offshore 59, no. 2 (February 1999): 63-66.

3. For examples of intelligent completion economics: Jalali Y, Bussear T and Sharma S: “IntelligentCompletion Systems—The Reservoir Rationale,” paper SPE 50587, presented at the 1998 SPE European Petroleum Conference, The Hague, The Netherlands, October 20-22, 1998.

4. Robinson MC and Mathieson D: “Integration of an Intelligent Completion into an Existing Subsea Production System,” paper OTC 8839, presented at the 1998 Offshore Technology Conference, Houston, Texas, USA, May 4-7, 1998.Other sources indicate that that first intelligent completion installation actually occurred in September 1997: See Greenberg, reference 2.von Flatern R: “Smart Wells Get Smarter,” Offshore Engineer (April 1998): 45-46.

Autumn 1999 21

specific times. Well tests, production logs andseismic surveys provide one-time snapshots ofthe reservoir and might not represent the reser-voir’s normal behavior or record events thatrequire corrective action. In complex well config-urations, such as multilateral wells, productionlogging is difficult. Simply getting to the reservoirto acquire data can be risky, time-consuming andexpensive. Subsequent workover operations,such as plugging and abandoning a zone, can bechallenging and costly because a workover rigmust be brought to the wellhead and remediationequipment placed in the wellbore.

Permanent downhole gauges are incorpo-rated in intelligent completions to allow continu-ous data acquisition. Historically, oil companyreservoir engineers came up with the idea tomonitor downhole conditions in onshore USAwells in the 1960s. The first gauge installationswere actually modified wireline equipment.Significant developments in permanent monitor-ing technology have been made since those earlydays. Today, permanent gauges have establishedan impressive worldwide track record for reliablymonitoring downhole pressure, temperature andflow rate.6 Real-time or near real-time pressure,temperature and flow-rate data show the contin-uous variation in reservoir performance. Whilesecond-by-second data collection might seemexcessive during routine production operations,the abundance of data ensures that high-qualityanalysis can be performed when needed.

The wealth of data afforded by permanentgauges means that the reservoir team no longerhas to speculate about what is going on down-hole. By gathering and analyzing reservoir data,the team can decide if or when adjustments tothe completion might be appropriate. Once reser-voir behavior has been carefully evaluated, theteam can use actual data rather than assumedinput values in reservoir simulations and continueoperations or adjust downhole conditions usingremotely controlled valves operated from surface.

Field-proven flow-control valves are hydrauli-cally actuated Variable Window valves that canbe incrementally adjusted to control the flowarea more accurately. In contrast, their less reli-able predecessors, sliding sleeves, are eitherfully opened or completely closed and cannot beadjusted between those two positions. By vary-ing the slot width of the Variable Window valve,flow rates can be adjusted. In essence, the flowrate of each control valve is tailored to theindividual zone.

The flow-control valve is mounted in a side-pocket mandrel, or a cylindrical section offsetfrom the tubing, so that the valve can beretrieved by wireline or slickline if necessary(above left). By applying hydraulic pressure, a

Variable Window valve can assume one of sixsequential positions to set the rate at which flu-ids are produced from the formation into the tub-ing or injected from the tubing into the formation.Reservoir management requires both productionand injection capabilities. Check valves preventcrossflow between reservoirs.

An electrically controlled valve is in devel-opment (above). The electric version allowsinfinite adjustment between the opened andclosed positions rather than the incrementaladjustments of the hydraulic version. Like wire-line-retrievable flow controllers, the electricallyand hydraulically operated, tubing-retrievable flowcontrollers in development have no practical depthlimitations and can include instruments to mea-sure formation temperature, pressure and flow.

Section B-B

AA

Section A-A

B B

Retrievablevalve

Hydraulicactuator

Productiontubing

Control linesto surface andlower zones

> Flow-control valves. The WRFC-H hydraulic wireline-retrievable flow-control valve can beadjusted to six positions, one of which is closed.The middle position is a setting that meets anticipated requirements. From this median setting, there can be two adjustments downwardor upward to control fluid production or injection.

5. For other descriptions of intelligent completions: Beamer A, Bryant I, Denver L, Saeedi J, Verma V, Mead P, Morgan C, Rossi D and Sharma S: “From Pore to Pipeline, Field-Scale Solutions,” Oilfield Review 10, no. 2 (Summer 1998): 2-19.Huck R: “The Future Role of Downhole Process Control,”Invited Speech, Offshore Technology Conference,Houston, Texas, USA, May 3, 1999.

6. Baker A, Gaskell J, Jeffery J, Thomas A, Veneruso T and Unneland T: “Permanent Monitoring—Looking atLifetime Reservoir Dynamics,” Oilfield Review 7, no. 4(Winter 1995): 32-46.Permanent monitoring and the reliability engineeringbehind the current generation of permanent gauges willbe the focus of an upcoming Oilfield Review article.

Permanent gauges

Electricactuator

Choke

> Flow-control valve developments. The TRFC-Eelectric tubing-retrievable flow-control valve can be adjusted to an infinite number of positions,providing greater control than its hydraulic counterpart. This advanced all-electric systemcontains a single cable for power and telemetry.Qualification tests are ongoing.

Reliability of flow-control devices is a criticalconcern because, like permanent gauges, theyare meant to last for the life of the well and, withthe exception of wireline-retrievable devices, arenot usually recovered for repair, maintenance or post-mortem failure analysis.7 These demandsmake long-life field trials impractical and identifi-cation of risks through other techniques essen-tial. Simple, robust and field-proven equipment isfundamental to the designs. Therefore flow-con-trol valves incorporate proven technology, suchas hydraulic motors from subsurface safetyvalves. Newly developed components havepassed rigorous qualification tests.

Initially, it might be difficult to choose frommyriad options for completing a wellbore in anew reservoir. Until the reservoir has been char-acterized to the satisfaction of the operationsteam, completion specialists recommend ensur-ing flexibility, continuously acquiring data andthen using reservoir-modeling tools to comparepredictions with actual results.

Flow Control in ActionIn two well-known fields, reserves that mighthave been left in the ground are being recoveredthrough the use of flow-control devices. Forexample, a thin oil zone in the massive Troll fieldis being drained by extended-reach or horizontalwells that contact a greater area of the reservoirthan vertical wells and reduce the drawdown perunit area to avoid premature gas coning. Aninnovative multilateral well in the Wytch Farmfield enables production from two different sec-tions of an oil reservoir.

Troll field, operated by Norsk Hydro andStatoil, contains the world’s largest offshore gasreserves. There is a thin oil zone below the enor-mous gas cap. When the field was discovered inthe 1970s, and as recently as 1985, technologyhad not yet been developed to recover the oilreserves. Advances in horizontal drilling nowmake it possible to drill 3000- to 4000-m [9840- to 13,120-ft] sections horizontally throughthe relatively uniform, unfaulted sandstone

22 Oilfield Review

HELIKOPTER SER V

ICE

NORTH SEA

NORWAY

UK

Troll field. The Troll C platform willinitially produce oil from the Troll OilGas Province. All Troll field wells aresubsea completions, five of whichhave flow-control devices.

7. Veneruso AF, Sharma S, Vachon G, Hiron S, Bussear Tand Jennings S: “Reliability in ICS* IntelligentCompletions Systems: A Systematic Approach fromDesign to Deployment,” paper OTC 8841, presented atthe 1998 Offshore Technology Conference, Houston,Texas, USA, May 4-7, 1998.

reservoir to drain the oil. Troll C platform, whichwill begin production during the fourth quarter of1999, will initially produce oil from a highly per-meable sandstone reservoir at a depth of 1580 m[5184 ft] in the Troll Oil Gas Province (below).

The key technical issue for the 40 wellsplanned from the Troll C platform is to recover oilfrom the 2- to 18-m [6.5- to 59-ft] thick oil legwithout gas coning. The completions, which aresubsea, produce oil in the presence of nearbywater more readily than in the presence ofnearby gas. Use of advanced completion technol-ogy was considered at the outset, before drillingthe first well from the platform.

Troll field

>

Autumn 1999 23

A traditional approach in this region wouldhave been a directionally drilled well with a slot-ted-screen completion (above). The risk in thiscase is gas or water coning. The preferredapproach was to directionally drill the well intothe lower part of the oil zone and install a wire-line-retrievable flow-control valve to help withgas lift (right). The well now produces oil andwater, but eventually will produce gas. Untilthen, alternating cycles of production with orwithout gas lift through the flow-control valveallow oil production without gas coning.

The combination of horizontal drilling tech-nology to drill low in the oil pay, downhole gas-lift technology rather than injection from surfaceto accelerate production, and downhole flow-control valves enhanced project economics. Theelimination of gas-gathering and high-pressuredistribution systems helped reduce costs, in partbecause a smaller, less expensive platform with-out compression facilities could be used. In theabsence of flow-control technology, significantamounts of oil in the Troll field might have beenleft behind, but advanced completions willimprove ultimate recovery by an estimated 60million barrels of oil [9.5 million m3]. At present,five wells in the field have intelligent comple-tions, with four or five more planned for 2000 andseven installations in 2001.

Gas coningTraditional completionWater coning

Gas

Oil

Water

Gas coning. Standard completiontechnology (center) would haveresulted in limited total oil recovery dueto premature gas coning (right). Oil isnow produced along with water (left).

Gas-lift cycle

No gas lift during this cycle

Perforations

Gas

Oil

Water

Preferred solution. By carefullysteering the well into the lowerpart of the thin oil leg, oil reservescould be produced along withwater (top). Periodic gas-liftcycles provide artificial lift (bottom left).

>

>

Poole

Poole Harbor

Bournemouth

IRELAND UK

PooleLondon

Sherwood sandstone reservoir

Well M-2 TD location

Poole Harbor

Poole

Surface wellsite M

Purbec

Bournemouth

In another example of the use of intelligentcompletions, record-setting extended-reachwells drain portions of the Triassic Sherwoodsandstone reservoir beneath Poole Bay in theWytch Farm field, operated by BP Amoco inDorset, England (above).8 Because these wellsare without precedent, the BP Amoco operatingteam has developed and benefited from a will-ingness to consider new technologies, resultingin pioneering approaches to well constructionand completion design.9

The Wytch Farm M-2 well was drilled in 1994.During cementing operations, the cement slurryflash set inside the casing and could not bepumped up the annulus to isolate the sandstonereservoir effectively. The 51⁄2-in. liner could not beremoved, so the team elected to perforate theliner and produce the well. When the water cutrose sharply, the team explored other options forthe well. A key economic driver was the internalceiling on lifting costs. Therefore, during its anal-ysis, the team considered the impact of the com-pletion throughout the life span of the well ratherthan focusing on the initial cost of the completion.

Around this time, the flow-control devicedeveloped by Camco was successfully installedin the Troll field. The Wytch Farm team was moti-vated to consider applying new technology, suchas an adaptation of the flow-control device usedin the Troll field. The economics for an advancedcompletion with flow-control valves were favor-able, so the team explored ways to incorporatethe new technology in the M-2 wellbore.

Eventually, the group decided to plug the M-2wellbore and convert the well—renamed the M-15—to a multilateral well with two side-tracks.10 A multilateral well with an advancedcompletion functions much like two wells, butwithout doubling the construction expenses (nextpage, top). The primary Sherwood sandstonereservoir would be tapped by a simple openholecompletion. Another lateral would penetrate afaulted portion of the Sherwood reservoir thathad high potential for water production. An elec-tric submersible pump would provide artificial lift(next page, bottom).11

24 Oilfield Review

>Wytch Farm field. Significant oil reserves lie beneath Poole Bay and are drained byextended-reach wells. The M-2 well, shownin black, was renamed M-15 and converted toa multilateral well that contains hydraulicallyactuated flow-control valves.

8. For more on extended-reach drilling at Wytch Farm field: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.McKie T, Aggett J and Hogg AJC: “Reservoir Architectureof the Upper Sherwood Sandstone, Wytch Farm Field,Southern England.” in Underhill JR (ed): Development,Evolution and Petroleum Geology of the Wessex Basin,Special Publication 133. London, England: GeologicalSociety, 1998: 399-406.Smith GS and Hogg AJC: “Integrating Static andDynamic Data to Enhance Extended Reach WellDesign,” paper SPE 38878, presented at the SPE AnnualTechnical Conference and Exhibition, San Antonio,Texas, USA, October 5-8, 1997.

9. Gai H, Davies J, Newberry P, Vince S, Miller R and Al-Mashgari A: “World’s First Down Hole Flow ControlCompletion of an ERD Multilateral Well at Wytch Farm,”abstract submitted to the IADC/SPE Drilling Conference,New Orleans, Louisiana, USA, February 23-25, 2000.

10. For more on multilateral wells: Bosworth S, El-Sayed HS,Ismail G, Ohmer H, Stracke M, West C and Retnanto A:“Key Issues in Multilateral Technology,” Oilfield Review10, no. 4 (Winter 1998): 14-28.

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

Autumn 1999 25

Flowmeter

Electricsubmersiblepump shroud Formation

savervalve

Multisensor Original M-2 wellbore plugged and cemented

Electricsubmersible

pump packers

Electricsubmersible

pump

Hydraulicdisconnect 8 1/2-in. lateral

Packer 7-in. linerSumppacker

4 1/2-in.WRFC-H

> Flow-control solution. A multilateral well with three WRFC-H flow-control valves proved to be economically and technically viable because it allowed separate control of each lateral as well as independent testing of each wellbore. The M-15 well is the first in which remotely operated flow-control valveshave been installed below an electric submersible pump.

Oil

Water

Oil

Water

ORAUT99-Completion-Fig.13.2

Oil

Oil

Water

Water

> Noncommercial solutions. Drilling two wells would have been prohibitively expensive (left). A single well would have left behind reserves (right).

The M-15 well design addressed three key areas of concern:• Flow control• Pressure drawdown• Well testing.

Flow control to deal with expected water pro-duction from one lateral—The team anticipatedthat flow control would allow recovery of anadditional 1 million barrels [158,900 m3] of oilthat might not have been recovered otherwise.

Drawdown control to avoid hole collapse inthe openhole completion—The sandstone reser-voir drained by the primary lateral was expectedto be relatively unfaulted and competent. Casingthis lateral would have been uneconomic. Themudstone caprock was penetrated nearly hori-zontally, so there was potential for collapsing themudstone if drawdown were higher than a cer-tain specified level. Hole collapse could alsodamage the electric submersible pump.

Well testing and data acquisition concerns—BP Amoco wanted to better understand the pro-duction profiles of extended-reach wells bycapitalizing on the monitoring equipmentplanned for the M-15. In addition, a completionwith downhole flow control would allow the twobranches to be tested independently. The abilityto observe the dynamics of the reservoir usingdownhole equipment, rather than having to inter-pret ambiguous measurements made at the sur-face, was a key concern for the team.

After evaluating flow-control devices avail-able at the time, the completion team chose todeploy three WRFC-H hydraulic wireline-retriev-able flow-control devices, two in the primary lat-eral and one in the second lateral. This equipmentwould allow the water leg predicted in the faultedreservoir to be shut off while producing from theother lateral (above). In addition to flow-

control devices, the M-15 equipment includes athird-party flowmeter above and a sensor imme-diately below the electric submersible pump. Theflowmeter measures total flow through the pump,pump discharge pressure and pressure upstreamof the flow-control valve that controls the south-ern lateral. The multisensor, mounted at the bot-tom of the electric submersible pump, measuresfluid and motor-winding temperatures, vibrationand intake pressure in the barefoot lateral anduses the pump cable for signal transmission. Themultisensor and flowmeter were positioned tohelp the team understand the performance ofeach lateral, but early failure of the upperflowmeter impeded investigation of the interac-tion of the two wellbores. Fortunately, the teamwas able to establish the integrity of the installa-tion and the drawdown level before gauge failure.

Installation proceeded according to plan. The flow-control equipment continues to allowthe two laterals to be controlled individually fromthe surface.

26 Oilfield Review

Oil

Water

Oil

Water

Oil

Water

Oil

Water

> Shutting off water. Both laterals are producing oil (left). If the lower lateral waters out, the flow-control valve can be closed to prevent water production (right).

Autumn 1999 27

Like other extended-reach wells in the WytchFarm field, the M-15 well set several records. TheM-15 has the greatest reach of any dedicatedmultilateral well. It set additional records with3400 m [11,155 ft] of horizontal 81⁄2-in. hole in one lateral, 2600 m [8530 m] of 7-in. liner floatedinto position, whipstock retrieval at 5300 m[17,390 ft] and 85 degrees, and 1800 m [5905 ft]of perforating guns run to 8000 m [26,248 ft]—arecord since broken by the M-16 well. It is alsothe first well worldwide in which a surface-con-trolled flow device has been installed below anelectric submersible pump.

The M-15 example confirms that flow-controldevices work as designed, so future decisionsabout using them will be based on project eco-nomics and long-term performance reliability.Installing advanced completion equipmentrequires a properly trained wellsite crew. Carefulpreparation is a key to success. A completionsimilar to the Wytch Farm M-15 example wouldbe appropriate in other areas to control draw-down or water production from layered reservoirsand reservoirs with high contrasts in pressure,permeability and water cut.

Currently, advanced completions are used inareas where interventions are most costly—deep-water, arctic and environmentally sensitive loca-tions—which also tend to have more complicatedwells. To date, five valves have been installed inthe Troll field and three valves in the Wytch Farmcompletion, all of which continue to function.

Other applications of flow-control valves andpermanent gauges are available. For example, ina field that has gravity-drainage oil production,downhole gas production and autoinjection mayeliminate the need for gas-production and gas-injection wells, in addition to replacing costly sur-face facilities (right). Such downhole repressuringin the wellbore is not only cost-effective, but envi-ronmentally more benign.

Another application is for commingling pro-duction in stacked reservoirs with potential forcrossflow or in areas where government regula-tions require separate accounting for productionfrom separate hydrocarbon zones.12 In fieldsundergoing secondary recovery, such as water-floods, flow-control devices and permanentgauges can help maintain critical injection rates.

This will help avoid premature breakthroughcaused by injecting fluid too rapidly and preventinefficient displacement of reservoir fluids due to an injection rate that is too low.13 Clearly,remote monitoring and control of flow canaddress complications presented by multiplereservoirs, multiple fluid phases, formations thatare sensitive to drawdown pressures and com-plex well configurations.

Producer Autoinjector

Injector

> Producing gas-free oil. Gas separation typically requires surface facilities to remove gas from oil-and gas-injection wells. The left wellbore produces gas. The middle wellbore is a gas-injection well.Downhole gas production and autoinjection using flow-control technology, shown at the right, canreplace costly surface facilities and gas-injection wells.

12. See Jalali et al, reference 3.13. See Jalali et al, reference 3.

Future Remote Monitoring and Flow Control Monitoring and controlling flow from the surfaceare the first stages in optimizing reservoir plumb-ing. Ideally, future reservoir management willroutinely involve observation and data gathering,interpretation and intervention (below). Dynamicupdating of the reservoir model using feedbackfrom real-time monitoring maximizes the value of the data and allows the operator to makeinformed adjustments to downhole valves thatcontrol flow from the reservoir by determiningthe optimal flow.

To assess the impact of real-time data collec-tion and flow control on recovery, a laboratoryexperiment was designed by the ReservoirDynamics and Control group at Schlumberger-Doll Research, Ridgefield, Connecticut, USA. Theexperimental apparatus simulates a deviatedwell in an oil reservoir near an oil-water contact(right). The Berea sandstone reservoir in the

28 Oilfield Review

> Experimental apparatus. The laboratory setup (right) represents a deviated well with three valvesthat control flow from the producing zones (left). The reservoir is initially saturated with fresh water,which is displaced by injecting salt water from below, simulating an underlying aquifer.

14. The Berea 500 sandstone, a quartz-rich, LowerCarboniferous sandstone from Ohio that is prized for itsdurability, is widely used in petroleum industry tests.For more on the Berea sandstone:http://www.amst.com/red_sandstone_products.html.

Reservoir monitoringand control - Sensor type and location - Flow-control equipment and location

Shared earthmodel

Project goals andconstraints - Maximize recovery - Maximize net present value - Flow rate - Pressure - Water cut

Dynamic Updating

Simulation andoptimizationalgorithm

> Designing an optimization strategy through monitoring, simulation and control. Dynamic updating isthe critical ingredient in reservoir monitoring and control. Depending on the field and the operator, production goals differ. In one field, maximizing flow rate might be the objective. In other cases, maximizing ultimate recovery or net present value might be more important. Once the objectives are defined, flow-control equipment and sensors can be properly placed in the well. As more databecome available, the shared earth model is updated. Reservoir simulation and an optimization algorithm incorporate economic and practical constraints into the shared earth model. Simulation and optimization output values of control variables, such as flow rate and pressure, allow the operatorto adjust completion devices appropriately.

experiment was saturated with fresh water torepresent oil in an actual reservoir.14 The “oil”was displaced by salt water that represents con-nate water in an actual reservoir.

The “well” has three flow-control valves.When the valves were opened fully, “oil” pro-duction was followed by early “water” break-through at the deepest completion in thewellbore because this part of the well is closestto the “oil-water” contact and is the path of leastresistance. Consequently, the reservoir waspoorly swept.

An optimal production strategy was thendesigned using the model that had been preparedfor the laboratory reservoir. A simulation, per-formed with ECLIPSE reservoir simulation soft-ware, was linked to an optimization algorithm thatincorporated an objective of maximum recoveryand practical constraints, such as the reservoirpressure at each part of the wellbore, fixed totalproduction rate and maximum water cut. The sim-ulation showed that more oil could be recoveredby varying the offtake in the different segments ofthe well. By adjusting the valves in the next phaseof the experiment, more “oil” was indeed recov-ered because the “water” front approached thewellbore evenly rather than breaking through onezone of the completion prematurely.

Autumn 1999 29

In the experiment, adjustment of flow intoeach of the valves was made on the basis ofobservations of the front movement usingcomputer-assisted tomographic scans (left). Insubsurface reservoirs it will also be necessary toimage the front movement in order to devise acontrol strategy, and research is under way todevelop reliable sensors for this purpose.

The experiment clearly demonstrated thatproducing each zone at its optimal rate improveshydrocarbon recovery from the well (below left).When the valves in the wellbore were fullyopened, only 75% of the “oil” was displaced. Byjudiciously adjusting the three valves in theexperimental apparatus, sweep efficiencyincreased to 92%.

State-of-the-art monitoring and flow-controltechnology minimize the need for well interven-tions and make those that are necessary morecost-effective by simplifying them or timing themoptimally. As demonstrated in the Wytch Farmand Troll field examples, additional incrementalreserve recovery is more likely when individualzones or wellbores can be operated indepen-dently, produced at precise rates to avoid wateror gas coning or excessive drawdown, andassisted by artificial-lift systems.

Intelligent completions also affect the waypeople work. Design of these systems involvescloser interactions on a technical basis betweenoperators and service and equipment providers toensure safer and more effective completions. Aremotely operated intelligent completion mayreduce the number of people needed at the well-site, so field operations become less expensiveand more people can remain in their offices.

Application of this technology is in itsinfancy—there are now fewer than 20 advancedcompletions worldwide. Advanced completiontechnology is currently most useful in high-costareas, but ultimately will enter lower tier costmarkets as the technology is simplified andproven in other operating theaters. A future chal-lenge will be to build intelligent completionsequipment for casing less than 7-in. in diameter.The combination of the expertise of Camco in flow-control valves and the track record ofSchlumberger in downhole electronics offers aunique ability to both monitor and control flow.The joint efforts of reservoir specialists and com-pletion experts will put downhole process controlon the road to ubiquity. —GMG

No control

Oil

Water

Control

> Impact of flow control. Tomographic images from the experiment convey the impact of flow control.The top photographs, taken during the initial phase of the experiment with the valves open throughout,show the water contact migrating unevenly toward the wellbore. The photograph at the far right shows premature water breakthrough at the lowest valve. The bottom photographs show greater sweep efficiency because the valves are adjusted during production. The “water” contact approaches the wellbore evenly.

180 cm3/hrInjection

180 cm3/hr

180 cm3/hr cm3/hr27 49.5 103.5

No controlFlow rate

Control

75% 92%

> Results of the optimization strategy. Without any control of flow, premature waterbreakthrough at the lowest valve and poor sweep led to displacement of 75% of the “oil” (left). Careful adjustments of the three valves allowed the same flow rate, but better sweep efficiency and recovery of 92% of the “oil” (right). In both illustrations, the white curve represents the “oil-water” contact. In this experiment, the objective was to maximize sweep efficiency while maintaining constant total flow and water cut less than 30%.

Fighting Scale—Removal and Prevention

Imagine an oilfield menace that can smother a productive well within 24 hours. The buildup

of scale inside wellbores does exactly that, causing millions of dollars in damage

every year. New understanding of scale accumulation is allowing production

engineers to predict when scale formation will occur, so that adverse

operating conditions can be prevented with new inhibitor

techniques. New tools are also available to blast

scale away from casing and tubulars.

Few production problems strike fear into thehearts of engineers the way scale can. Scale isan assemblage of deposits that cake perfora-tions, casing, production tubing, valves, pumpsand downhole completion equipment, therebyclogging the wellbore and preventing fluid flow.Scale, just like the scale found in home plumbingor tea kettles, can be deposited all along waterpaths from injectors through the reservoir tosurface equipment. Most scale found in oil fields forms either by direct precipitation fromthe water that occurs naturally in reservoir rocks,or as a result of produced water becoming

oversaturated with scale components when twoincompatible waters meet downhole. Wheneveran oil or gas well produces water, or water injec-tion is used to enhance recovery, there is the pos-sibility that scale will form. In some areas, suchas the North Sea and Canada, where entireregions are prone to scale, it is recognized as oneof the top production problems.

Scale can develop in the formation pores nearthe wellbore—reducing formation porosity andpermeability. It can block flow by clogging perfo-rations or forming a thick lining in production tub-ing (above). It can also coat and damagedownhole completion equipment, such as safety

30 Oilfield Review

Mike CrabtreeAberdeen, Scotland

David EslingerTulsa, Oklahoma, USA

Phil FletcherMatt MillerSugar Land, Texas, USA

Ashley JohnsonRosharon, Texas

George KingBP Amoco CorporationHouston, Texas

For help in preparation of this article, thanks to AndrewAcock, Houston, Texas, USA; Willem van Adrichem andWarren Zemlak, Sugar Land, Texas; Mike Barrett, SteveDavies, Igor Diakonov and Jon Elphick, Cambridge, England;Leo Burdylo, Sugar Land, Texas; Ingrid Huldal and RaymondJasinski, Aberdeen, Scotland; and Scott Jacobsen,Houston, Texas. Blaster Services, Bridge Blaster, CoilCADE, CoilLIMIT, JetAdvisor, Jet Blaster, NODAL, ScaleFRAC, Sterling Beadsand StimCADE are marks of Schlumberger. Hipp Tripper is amark of Baker Oil Tools; Hydroblast is a mark of Halliburton;and RotoJet is a mark of BJ-NOWSCO.1. Brown M: “Full Scale Attack,” REview, 30 The BP

Technology Magazine (October-December 1998): 30-32.

Scale in production tubing. Calcium carbonatescale growth in production tubing here obstructsmore than 40% of the flowing area of the tubingand prevents access to lower sections by well-remediation tools.

Autumn 1999 31

valves and gas-lift mandrels. The effects of scalecan be dramatic and immediate: in one North Seawell in the Miller field, engineers were shocked tosee production fall from 30,000 B/D [4770 m3/d]to zero in just 24 hours.1 The costs can be enor-mous also. Curing scale problems costs the indus-try hundred of millions of dollars per year in lostproduction. Until recently, ways to treat theproblem were limited and sometimes ineffective.When scale forms, a fast, effective removal tech-nique is needed. Scale-removal methods involveboth chemical and mechanical approaches, eachwith its own niche—depending on the location ofthe scale and its physical properties.

Some mineral scales, such as calcium carbon-ate [CaCO3], can be dissolved with acids, whilemost others cannot. Sometimes tar-like or waxycoatings of hydrocarbons protect scale fromchemical dissolvers. Accumulated solid layers ofimpermeable scale can line production tubing,sometimes completely blocking it, and are lesseasily removed. Here, mechanical techniques orchemical treatments are traditionally used to cutthrough the scale blockages. Nevertheless, com-mon hard scales, such as barium sulfate [BaSO4],are extremely resistant to both chemical andmechanical removal. Before recent developmentsin scale-removal technology, operators with hard-scale problems in their production tubing wereoften forced to shut down production, move inworkover rigs to pull the damaged tubing out ofthe well, and either treat for scale at the surfaceor replace the tubing.

In this article, we review the physical causesof scale buildup during oil production. Knowingthe conditions that lead to scaling and when andwhere it occurs helps in understanding how toremove scale and in designing intervention treat-ments to restore long-term well productivity.Then, we survey the chemical and mechanicaltechniques used in scale removal—including thelatest developments in jetting techniques—andexamine the strengths and limitations of eachapproach. Finally, we look at advances in watertreatments and new inhibitors that help controlthe delicate chemical balance to prevent scaleprecipitation from recurring.

Sources of ScaleIn oilfield scale, water is of primary importance,since scale will occur only if water is produced.Water is a good solvent for many materials and cancarry large quantities of scaling minerals. All natu-ral waters contain dissolved components acquiredthrough contact with mineral phases in the naturalenvironment. This gives rise to complex fluids, richin ions, some of which are at the saturation limitfor certain mineral phases. Seawater tends tobecome rich in ions that are by-products of marinelife and water evaporation. Ground water andwater in the near-surface environment are oftendilute and chemically different from deep subsur-face water associated with gas and oil.

Deep subsurface water becomes enriched inions through alteration of sedimentary minerals.The water in carbonate and calcite-cemented

sandstone reservoirs usually contains an abun-dance of divalent calcium [Ca+2] and magnesium[Mg+2] cations. Sandstone formation fluids oftencontain barium [Ba+2] and strontium [Sr+2] cations.In reservoir fluids total dissolved solids can reach400,000 mg/L [3.34 ppg]. The precise compositionhas a complex dependence on mineral diagenesisand other types of alteration encountered as for-mation fluids flow and mix over geological time.

Scale begins to form when the state of anynatural fluid is perturbed such that the solubilitylimit for one or more components is exceeded.Mineral solubilities themselves have a compli-cated dependence on temperature and pressure.Typically, an increase in temperature increasesthe water solubility of a mineral. More ions aredissolved at higher temperatures (below).Similarly, decreasing pressure tends to decrease

Mineral solubilities versus temperature

Minerals solubilities versus pressure

1000

100

10

1

0.1

Solu

bilit

y, lb

m/b

bl

0.01

0.001

0.000177 120

Temperature, °F

Strontiumsulfate

Calcite Barite

Siderite

Halite

Gypsum

Anhydrite

170 210 260 300

Minerals solubilities versus salinity

0.004

0.0035

0.003

0.0025

0.002

0.0015

0.001

0.0005

5 x 10-3

4 x 10-3

3 x 10-3

2 x 10-3

1 x 10-3

25°C

150°C

250°C

070

10 2 3 4 5 6

120 170 220 270

14,000 psi

1500 psi

7000 psi

14.5 psi

Temperature, °F

Diss

olve

d Ba

SO4, lb

m/b

blSt

ront

ium

Sul

fate

sol

ubili

ty, m

ol/L

NaCl mol/LSeawater

Mineral solubilities have a complex dependencyon many variables including temperature (top),pressure (center) and salinity (bottom).

>

>

solubilities and, as a rule-of-thumb, the solu-bility of most minerals decreases by a factor of two for every 7000-psi [48-MPa] decrease in pressure.

Not all minerals conform to the typical tem-perature trend; for example, calcium carbonateshows the inverse trend of increasing water sol-ubility with decreasing temperature. The solu-bility of barium sulfate increases by a factor oftwo in the temperature range 25°C to 100°C[77° to 212°F] and then decreases by the samemagnitude as temperatures approach 200°C[392°F]. This trend is itself influenced by thebackground brine salinity.

An additional complexity is the solubility ofcarbonate minerals in the presence of acid gasessuch as carbon dioxide [CO2] and hydrogen sulfide[H2S]. Carbonate solubility increases as fluid acid-ity increases, and CO2 or H2S at high pressuresupply significant acidity. Consequently, forma-tion waters, in contact with both carbonate rockand acid gases, can be rich in dissolved carbon-ate. This trend has a complex nonlinear depen-dence on brine composition, temperature and thepressure of the gas above the liquid phase; thisgas pressure effect is orders of magnitude greaterthan the normal effect of pressure on the solubil-ity of a mineral. Generally, as pressure falls, CO2

leaves the water phase causing the pH to rise—leading to calcite scale formation.

Forming ScaleAlthough the driving force for scale formationmay be a temperature or pressure change, out-gassing, a pH shift, or contact with incompatiblewater, many produced waters that have becomeoversaturated and scale-prone do not alwaysproduce scale. In order for a scale to form it mustgrow from solution. The first development withina saturated fluid is a formation of unstable clus-ters of atoms, a process called homogeneousnucleation (left). The atom clusters form smallseed crystals triggered by local fluctuations inthe equilibrium ion concentration in supersatu-rated solutions. The seed crystals subsequently

grow by ions adsorbing onto imperfections on thecrystal surfaces—extending the crystal size. Theenergy for seed crystal growth is driven by areduction in the surface free energy of the crys-tal, which decreases rapidly with increasingradius after a critical radius is exceeded. Thisimplies that large crystals favor continuing crys-tal growth, and also implies that small seed crys-tals may redissolve.2 Thus, given a large enoughdegree of supersaturation, the formation of anyseed crystal will encourage an increase in thegrowth of scale deposits. The seed crystal, ineffect, is a catalyst for scale formation.

Crystal growth also tends to initiate on a pre-existing fluid-boundary surface, a process calledheterogeneous nucleation. Heterogeneous nucle-ation sites include surface defects such as pipesurface roughness or perforations in productionliners, or even joints and seams in tubing andpipelines. A high degree of turbulence can alsocatalyze scale deposition. Thus, the accumula-tion of scale can occur at the position of the bub-blepoint pressure in the flowing system. Thisexplains why scale deposits rapidly build ondownhole completion equipment. Through thisunderstanding of nucleation phenomena, scaleinhibitors—discussed later—have been devel-oped that use chemicals specifically designed topoison the nucleation and growth stages of scaleformation and reduce the rate of scale formationto almost zero.

32 Oilfield Review

Fluid flow

Pipe wall

Supersaturation

Supersaturation

Ion pairs

Clusters/nuclei

Imperfectcrystalites

Further growth at sitesof crystal imperfections

Transient stability

Ion pairs

Surface imperfections

SO4-2

Ba+2

Homogeneous nucleation

Heterogeneous nuleation

>Nucleation processes. Scale growth starts insupersaturated solutions with ion pairs formingsingle crystals in solution, called homogeneousnucleation (top). Scale can also grow on preex-isting surface defects—such as rough spots onthe liquid-tubing surface, called heterogeneousnucleation (bottom).

CaCO3

CaCO3cementedfish

FeS2 layer

Steeltubing

BaSO4 layer

CaCO3 layer

Wax layer

Production flow

Underdepositcorrosion

Asphaltenelayer

H2S pittingcorrosion

BaSO4 overperforations

Change inpressure atsafety valve

Gas lift

Scale Deposition in Tubing

Fish

CaCO3Tubingcrossover

>Scale in tubing. The location of scale deposits in tubing can vary from downhole perforations to thesurface where it constrains production through tubing restrictions, blocked nipples, fish, safety valvesand gas-lift mandrels. Scale is often layered and sometimes covered with a waxy or asphaltene coat-ing (insert). Pitting and corrosion on steel can develop under the scale due to bacteria and sour gas,diminishing steel integrity.

Autumn 1999 33

Identifying ScaleIdentifying the location and composition of thescale deposit is the first step in designing a cost-effective remediation program.

Production tubing and surface equipment—Scale in production tubing may occur as a thicklayer adhering to the inside of the tubing. It is often centimeters thick and has crystals up to1 cm or larger. The primary effect of scale growthon tubing is to lower the production rate byincreasing the surface roughness of the pipe andreducing the flowing area. The driving pressuretherefore goes up and the production goes down.If mineral growth increases, then access to lowersections of the well becomes impossible, andultimately the growth blocks production flowingthrough the tubing (previous page, bottom right).Tubing scale varies in chemical composition,being composed of layers of scale deposited dur-ing the well’s history. Often, scales includeasphaltene or wax layers, and the layers of scalethat are closest to the tubing may contain ironsulfides, carbonates or corrosion products.

Near-wellbore matrix—The carbonate or sul-fate scale that is typical of the near-wellboreregion has a finer particle size than tubing scale,on the order of microns rather than centimeters.It blocks gravel packs and screens as well asmatrix pores. Near-wellbore scale commonlyforms after long periods of well shut-in becausecrossflow mixes incompatible waters from differ-ent layers. Such scale is thought of as skin(above right). Removal by chemical dissolvers oracids can increase production rates dramatically.

Injector wells—Scale damage to injectionwells is usually caused by temperature-activatedautoscaling of the injection water. In addition,incompatible mixing can occur in the near well-bore when injection water contacts either naturalformation water or completion brine (right). Thisproblem is limited to the early stages of injection,when injection water is contacting incompatiblewater in the near-wellbore region. Scale formedhere can decrease the permeability of the forma-tion and reduce the effectiveness of the water-flood strategy.

Detecting scale—Physical evidence of scaleexists as samples of tubing scale or X-rayevidence from core analysis. Gamma ray loginterpretation often indicates barium sulfatescale since naturally radioactive radium Ra226

precipitates with this scale.3 As much as a 500-API increase in gamma ray activity over naturalbackground has been seen in many cases.

Evaluating production using NODAL analysiscan indicate tubing scale if a well suddenlydemonstrates tubing constraints that were notpresent during early production. In theory, NODALanalysis can indicate scale in matrix through theidentification of increasing reservoir constraintson production, although this is difficult to distin-guish from other forms of formation damage.

The onset of water production is often a signof potential scale problems, especially if it coin-cides with simultaneous reduction in oil pro-duction. Normally, operators track waterchemistry and in particular the dissolved ioncontent of the produced water. Dramatic changesin the concentrations of scaling ions, such asBa+2 or sulfate [SO4

-2], that coincide with reducedoil production and increased water cut, can sig-nal that injection water has broken through andscale is beginning to form. Inspection of theresponse to previous chemical interventions,such as acid treatments, can give weight to suchinterpretations.

Early warning of scaling conditions would bevaluable to operators, since wells can scale upwithin 24 hours or less. Wells with intelligentcompletions and permanent monitoring systemsare being designed to detect changes in waterchemistry. Downhole scale sensors and perma-nent monitoring applications are areas of activeresearch. For example, BP Amoco initiated anintegrated scale management system that uses adownhole electrochemical sensor sensitive to pHand chloride ion concentrations along with tem-perature, pressure and multiphase flow measure-ments to detect potential carbonate buildup andhelp regulate chemical dosages for scale control.4

Chemical modeling—Chemical models arenow available to predict the nature and extent ofscaling from detailed fluid conditions. Thesemodels predict phase equilibrium using thermo-dynamic principles and geochemical databases.All rely on basic input data such as elemental-concentration analysis, temperature, pressureand gas-phase compositions. These programsare designed to predict the effect of perturba-tions such as incompatible mixing or changes intemperature and pressure.

Water flow

Scale

Oil

>Matrix damage. Scale deposition restricts the flow of fluids through the formation,resulting in a loss of permeability.

Scale damaged zone

Injection water

Injection flow

Perforations

> Injection-well damage. Autoscaling of injectionwater can cause scale buildup and createrestrictions in the tubing. Calcium carbonate canprecipitate as a result of increased temperatureand pressure, leading to deposition and damagenear the wellbore, particularly in HPHT wells.Incompatible mixing of injection water with for-mation water also leads to damage early in theinjection program.

2. Richardson SM and McSween HY: Geochemistry:Pathways and Processes. Englewood Cliffs, New Jersey,USA: Prentice-Hall, Inc., 1989.

3. Bamforth S, Besson C, Stephenson K, Whittaker C,Brown G, Catala G, Rouault G, Théron B, Conort G, Lenn C and Roscoe B: “Revitalizing Production Logging,”Oilfield Review 8, no. 4 (Winter 1996): 44-60.

4. Snieckus D: “Tipping the Scales,” Offshore Engineer(September 1999): 117.

Many scale-prediction programs are nowavailable as public domain software and a lim-ited number of commercial computer programstailored specifically to the simulation of oilfieldbrine chemistry. These programs range fromspreadsheet models to highly developed geo-chemical models designed to simulate fluid andchemical transport in porous formations.5

Such simulators can be used to predict scal-ing problems far into the future, using scenariosof reservoir performance and expected waterbreakthrough. In fact, for new reservoirs thathave no history of scaling problems, chemicalmodels are the only available predictive tools.Still, simulators require highly accurate chemicalcomposition data for virgin reservoir fluids andinjection waters. These are rarely available, butcan be collected to provide more accurate pre-dictions of scale formation.

Common Scaling ScenariosFour common events typically encountered inhydrocarbon production give rise to scale.

Incompatible mixing—Mixing incompatibleinjection and formation waters can cause scaleformation. Seawater is often injected into reser-voirs during secondary and enhanced-recovery

waterflooding operations. Seawaters are typi-cally rich in SO4

-2 anions with concentrationsoften above 2000 mg/L [0.02 ppg], while forma-tion waters contain divalent cations Ca+2 andBa+2. Fluid mixing in the near-wellbore matrixgenerally produces new fluids with combined ion concentrations that are above the solubilitylimits for sulfate minerals. Calcium sulfate[CaSO4] scale forms in limestone formations, andbarium sulfate [BaSO4] and strontium sulfate[SrSO4] scales form in sandstone formations(below). If these scales form in the formation,they are difficult to remove chemically andimpossible to remove mechanically. Incompatiblewater mixing can also occur in tubing, producingscales that are accessible to both chemical andmechanical removal.

Autoscaling—A reservoir fluid experienceschanges in temperature and pressure as it is pro-duced. If such changes take the fluid compositionbeyond the solubility limit for a mineral, it willprecipitate as scale—this phenomenon is calledautoscaling or self-scaling. Sulfate and carbon-ate scales can precipitate as a result of pressurechanges within the wellbore or at any restrictiondownhole. Sodium chloride scale (halite) forms in a similar way from highly saline brines

undergoing large temperature drops. Water cancarry 100 lbm/bbl [218 kg/m3] of halite at 200°C,but only 80 lbm/bbl [174 kg/m3] at surface tem-peratures. Halite can precipitate at the rate of 20lbm for each barrel of water produced, leading tomany tons of scale every day in a single well pro-ducing water at a rate of 1000 B/D [159 m3/d].

Another serious problem occurs when car-bonate scales precipitate from produced fluidscontaining acid gases. Reduction in pressure dur-ing production outgasses the fluid, which raisespH and causes scale deposition. The depositionof carbonate can extend from the near-wellborematrix, along tubing and into surface equipmentas the produced water continuously changes inpressure and temperature.

For carbonate scales, temperature effectsoften work against pressure effects. For example,the pressure drop at the point of entry into thewellbore can lead to matrix scale. As the fluidprogresses up the tubing to surface temperaturesand wellhead pressure, the resulting tempera-ture drop may override the pressure effect, reduc-ing scale formation in the tubing. On the otherhand, subsequent release of pressure from thewellhead to surface can lead to massive depositsof scale in surface equipment and tubing.

Evaporation-induced scale—Scale formationis also associated with the simultaneous pro-duction of hydrocarbon gas and formation brine(wet gas). As the hydrostatic pressure in produc-tion tubulars decreases, the volume of thehydrocarbon gas expands and the still hot brinephase evaporates. This results in dissolved ionsbeing concentrated in excess of mineral solubil-ities in the remaining water. This is a commoncause of halite scaling in high-pressure, high-temperature (HTHP) wells, but other scales mayalso form this way.

Gas flood—Flooding a formation with CO2

gas for secondary recovery can result in scaledeposition. Water containing CO2 becomes acidicand will dissolve calcite in the formation.Subsequent pressure drops in the formation sur-rounding a producing well can cause CO2 tobreak out of solution and cause carbonate scaleto precipitate in the perforations and in formation

34 Oilfield Review

600

Ion species

Sodium

Potassium

Magnesium

Barium

Strontium

Sulfate

Chloride

Calcium

Formation water, ppm

31,275

654

379

269

771

0

60,412

5038

Seawater, ppm

10,890

460

1368

0

0

2960

19,766

428

500

400

300

200

100

00 20 8040 60 100

Seawater, %

SrSO4

BaSO4

Brine Composition of Two Different Waters

Mas

s of

sca

le p

reci

pita

tion,

mg/

L

Scale from incompatible waters.The table (top) shows typical differ-ences in ion concentrations found in formation water and seawater.The graph (bottom) shows theamount of scale that precipitatesfrom different mixtures of seawaterand formation water.

5. Oddo JE and Tomson MB: “Why Scale Forms and How to Predict It,” SPE Production & Facilities 9, no. 1(February 1994): 47-54.

6. Martel AE and Calvin M: Chemistry of Metal ChelateCompounds. New York, New York, USA: Prentice-Hall,Inc., 1952.

7. Kotlar HK, Karlstad S, Jacobsen S, and Vollen E: “An Integrated Approach for Evaluating MatrixStimulation Effectiveness and Improving Future Design in the Gullfaks Field,” paper SPE 50616, presented at the1998 SPE European Petroleum Conference, The Hague,The Netherlands, October 20-22, 1998.

>

Autumn 1999 35

pores near the wellbore. The production of scalein the near-wellbore environment will cause afurther reduction in pressure and even more pre-cipitation (above). Like autoscaling, this self-gen-erating process can completely seal perforationsor create an impermeable wall between theborehole and reservoir within a few days, com-pletely shutting down production.

Scale RemovalScale-removal techniques must be quick, non-damaging to the wellbore, tubing or formationenvironment, and effective at preventing repre-cipitation. Formation matrix stimulation treat-ments frequently employ scale dissolvers toarrest production decline. The best scale-removaltechnique depends on knowing the type andquantity of scale, and its physical composition ortexture. A poor choice of removal method canactually promote the rapid recurrence of scale.

In tubulars, scale strength and texture play sig-nificant roles in the choice of removal technique.Strengths and textures vary from delicate, brittlewhiskers or crystals with high microporosity, torock-like, low-permeability, low-porosity layers.Scale purity affects its resistance to removalmethods. Scale may occur as single-mineralphases, but is more commonly a mixture of similar,compatible compounds. Pure barium sulfate isnormally of low porosity and is extremely impervi-ous to chemical removal, and only slowly remov-able by most established mechanical techniques.Mixtures of barium sulfate, often with strontiumsulfate, calcium sulfate or even calcium carbon-ate, will frequently yield to a variety of removalmethods, both chemical and mechanical.

Chemical techniques—Chemical scaleremoval is often the first, and lowest costapproach, especially when scale is not easilyaccessible or exists where conventional mechan-ical removal methods are ineffective or expen-sive to deploy. For example, carbonate mineralsare highly soluble in hydrochloric acid and there-fore can be easily dissolved. Hard sulfate scale ismore difficult because the scale has a low acidsolubility. In the formation matrix, it can betreated by the use of strong chelating agents,compounds that break up acid-resistant scale byisolating and locking up the scale metallic ionswithin their closed ring-like structure.6

Most chemical treatments are controlled byhow well the reagents gain access to the scale

surface. Consequently, the surface-area-to-vol-ume ratio, or equivalently the surface-area-to-mass ratio, is an important parameter in the speedand efficiency of the removal process. Large reac-tant surface areas, such as porous materials, clay-like particles of extremely thin plates, and hair-likeprojections react quickly, since the acid or reactantvolume surrounding the surface is large. Smallersurface-area-to-volume in thick, nonporous sheetsof scale are slow to react with any but thestrongest chemical reactants. Scale deposits intubing exhibit such a small surface area for a largetotal deposited mass that the reactivity of chemi-cal systems is usually too slow to make chemicaltreatment a practical removal method.

Frequently high-permeability zones in the for-mation—offering a path of least resistance—divert treatment fluids, and hinder the ability ofscale dissolvers to penetrate the intervals dam-aged by scale. Novel techniques using dissolversand preflushes containing viscoelastic surfactantscan enhance dissolver placement. Viscoelasticsurfactants form high-viscosity gels when mixedwith specific brine compositions, but completelybreak down and become water-like in the pres-ence of oil or hydrocarbon gas. Therefore, theseviscoelastic surfactants help channel the scaledissolvers into productive oil-saturated zones,avoiding nonproductive water-saturated zones.

Although hydrochloric acid is usually the firstchoice for treating calcium carbonate scale, therapid acid reaction may hide a problem: spent acidsolutions of scale by-products are excellent ini-tiators for reformation of scale deposits. For exam-ple, a field study evaluating matrix stimulationwith acid, helped an operator in the North Seainterpret declining production rates (below).7 Bycomparing well production histories in the

Injected seawater

Formation water

Precipitation of Calcium Carbonateproduces further pressure drop,leading to furtherprecipitation.

4 ft skin zone

Scale

Scale

Pressure drop zone

Fluid flow

>Production well damage. Autoscaling can lead to problems in producing wells (right), where scaleforms near the perforation throat (right insert). The pressure drop over the near-wellbore matrix canlead to runaway CaCO3 precipitation. Mixing incompatible injection water and formation water canlead to scale precipitation in the formation matrix (left).

7000

6000

5000

4000

3000

2000

1000

0

250.00

200.00

150.00

100.00

50.00

0Oct92

Flui

d flo

w, m

3 /d

Wel

lhea

d pr

essu

re, b

ar

Jan93

Mar93

Aug93

Nov93

Mar94

Sep94

Oct94

Jan95

Wellhead pressureDate of acid wash

Normalized flow

Oil flow Water flow

>Saw-tooth production profiles. A portion of the production history from one of the prolific wells in theGullfaks field shows cyclic production impairment. The normalized flow (red curve) is a good indicatorof productivity changes due to intervention efforts, because it removes the effects of choked-backproduction caused by surface equipment limitations. The normalized curve shows the large and imme-diate impact of multiple acid treatments (indicated by blue circles) and the subsequent loss in wellproductivity within one to three months afterwards—indicating recurring scale precipitation.

Gullfaks field before and after stimulation, engi-neers used NODAL analysis to determine thechange in formation damage, called skin. Then,the effect of each acid treatment on differenttypes of scale in each well was modeled using acoupled wellbore-reservoir simulator (see“Chemical Placement Simulator,” page 40). Theimpact of scale removal on the skin in each casewas compared with the production-derivedchanges in skin to evaluate the type of scale andits location. The field study confirmed that carbon-ate reprecipitation in the gravel packs was the pri-mary damage mechanism causing recurringproduction losses in the wells.

Chemicals that dissolve and chelate calciumcarbonate can break this reprecipitation cycle.Ethylenediamenetetraacetic acid (EDTA) was anearly candidate to answer the need for improvedchemical removal, and is still used today in manyforms (below). While EDTA treatments are more

expensive and slower than hydrochloric acid,they work well on deposits that require a chemi-cal approach. EDTA and variations on its chemi-cal structure are also effective in noncarbonatescale removal, and show promise for the removalof calcium sulfate and mixtures of calcium-bar-ium sulfate.

Recently, Schlumberger developed an im-proved EDTA-based scale dissolver, called U105,as a cost-effective alternative for carbonatematrix stimulation. This dissolver was designedspecifically for calcium carbonate, but is alsoeffective against iron carbonate and iron oxidescales. It dissolves carbonates more slowly thanhydrochloric acid and has a higher dissolvingcapacity than traditional organic acids, such asformic and acetic acid. Once the scale is dis-solved through chelation, there is no reprecipita-tion. Stable at temperatures up to 250°C [482°F],it is a low-toxicity scale dissolver that is effec-tively noncorrosive on most steels—making thetreatment extremely safe.

Other chelating agents have also been opti-mized especially for barium and strontium sulfatescale. For example, U104 is based on an EDTAdissolver containing chemical activators thatenhance the rate of scale dissolution, and hasproven effective on a wide variety of scalesincluding calcium sulfate, calcium carbonate andmixed scales. In a typical applications these solu-tions are diluted with fresh water with a 6- to 24-hour soak period.

36 Oilfield Review

SO4-2

Ba+2 EDTA

Surface complex

Ba-EDTA solutioncomplex

CH2

CO

O

O

CH2CO

CO

Ba CH2

O

O

CO CH2

CH2

N

N

>EDTA chelate compound. Chelating agents are used to lock up unwanted ionsin solution. An EDTA molecule shares electrons from oxygen and nitrogen atomswith barium ions, forming a barium-EDTA chelate compound (top). The chelatingprocess can help to dissolve solid barium sulfate scale (bottom).

1600

1400

1200

1000

800

600

400

200

0Time, days

147 days

Scale dissolvertreatment

Average 450 bblincremental oilover 147 days

700 bbl

1150 bbl

OilWater

Prod

uced

flui

d, b

bl

>North Sea well production history. High skin damage in a well due to BaSO4 andCaCO3 scaling in the perforations and matrix near the wellbore was successfullytreated, resulting in a 64% increase in oil production for more than 147 days.

Autumn 1999 37

The effectiveness of this new dissolver wasdemonstrated on a North Sea well that had high skin damage due to scaling in the near-wellbore matrix and perforations. The scale typewas identified as mixed barium sulfate and cal-cium carbonate. A U104 treatment was designedto bullhead, or pumped against pressure, into theformation to give an average radial displacementof 3 ft [1 m]. The treatment was overflushed witha tubing displacement of inhibited seawater, andthe well was shut in for a total soak time of 18 hours, after which it was returned to produc-tion (previous page, top). Production increased450 BOPD [72 m3/d] paying out all materials,pumping and lost production costs in 12 days.

Conventional mechanical methods—Mechan-ical solutions to remove scale deposits offer awide array of tools and techniques applicable inwellbore tubulars and at the sandface (below).Like chemical techniques, most mechanicalapproaches have a limited range of applicability,so selecting the correct method depends on the well and the scale deposit. Mechanicalapproaches, though varied, are among the mostsuccessful methods of scale removal in tubulars.

One of the earliest scale-removal methodswas an outgrowth of the use of explosives torattle pipe and break off brittle scale. Explosivesprovided high-energy impact loads that couldremove scale, but often damaged tubulars and

cement. Taming the explosive meant changing thetype of explosive or reducing the amount of explo-sive load. A strand or two of the detonation cord,called a string shot, was found to be adequate.

String shots are still used today, especially asa simple diagnostic tool, when quick wirelineentry and detonation during flow yield cluesabout the type and location of scale. Experienceshows that using a few strands of cord, deto-nated by an electronic cap, and long enough tocover the zone of interest, is effective in remov-ing scale blockages in perforations and thin scalefilms inside tubulars.

Thick scales, especially those in tubulars, areoften too strong for safe explosive removal andhave too little porosity for effective chemicaltreatments in a reasonable time frame. For thesedeposits, removal usually requires techniquesdeveloped for drilling rock and milling steel.Impact bits and milling technology have beendeveloped to run on coiled tubing inside tubularsusing a variety of chipping bits and milling con-figurations. The downhole power source is typi-cally a hydraulic motor or a hammer-type impacttool. Motors are fluid-powered, stator and rotorcombinations that turn the bit. Their powerdepends on fluid supply rate and motor size—smaller motors that remove scale inside tubing,typically 111⁄16-in. to 13⁄4-in. diameter, providetorque from 100 to 130 ft-lbf.

Because scale is rarely deposited evenly onthe tubing wall, milling power requirements varyenormously. When motors cannot supply thepower needed for the bit to cut the scale, themotor stalls and the milling process stops. As aresult, scale-removal rates vary with the type ofscale and application, but generally range fromabout 5 to over 30 linear feet [1.5 to over 9 m] ofscale removed from the tubular per hour ofmilling. The variation in milling speed dependson the match between the type of deposit andthe combination of motor and mill. Experienceshows that small, low-torque motors are gener-ally more effective when run with small-toothmills. Larger tooth mills, though more aggressive,do not spin well on irregular scale surfaces—stalling small motors. Thus, the small-tooth, lessaggressive mills cut faster because they are lessprone to frequent motor stalls.

Positivedisplacementmotor andmill

Fluid-powered ‘Moineau’motor and mill. Millremoves deposits bygrinding.

Yes. Cleanrate may bevery slow.

Positive surface indication of cleaningSmall cuttings make hole cleaning easier

Motor stator and mill are expensive expendables~300°F [150°C] limitNot compatible with scale dissolversMill can damage tubulars

Impacthammer

Fluid poweredpercussion hammer.High shock forcesshatter brittle deposits.

Large cuttings size makes hole cleaning more difficult Not compatible with scale dissolvers

Yes. Cleanrate may bevery slow.

Positive surface indication of cleaning Simple, robust tool

Fixed washtool

Fixed tool with manylarge-diameter nozzles.Normally used only withchemical dissolvers.

Most fluid power lost to circulating friction Low nozzle pressure—cannot remove inert deposits

Yes, ifdeposit issoluble.

Simple, robust tool

Spinning-jetting tool

Rotational torqueprovided by nozzlesoffset from tool axis. No speed control.

Inefficient jetting due to high rpm (>5000)

Simple tool Complete wellbore coverage by rotating jets

Yes, ifdeposit issoluble.

Indexed-jetting tool

Nozzle head rotates~90° when coiled tubing pressureis cycled. Head hasmany small-diameternozzles to improvewellbore coverage.

Requires multiple cleaning runs increasing job time and coiled tubing fatigueNo surface indication of cleaningSmall cleaning radius due to small nozzles

Turbine-poweredjetting tool

Fluid turbine rotatesnozzle with two nozzles.Eddy current brakecontrols rpm.

Abrasives cannot be pumped through turbine Complex tool

Complete wellbore coverage with large cleaning ratios

Sonic tools Used to create high-frequencypressure pulses thatremove deposits byshock waves orcavitation.

Hydrostatic pressure suppresses cavitation Tools not effective in removing hard scales in lab tests

SimpleYes, ifdeposit issoluble.

ScaleBlastingtechnique

Nozzle head rotated bytwo nozzles offset fromtool axis. Viscous brakecontrols rpm.

Complete wellbore coverage with large cleaning radius Positive surface indication of cleaning

BridgeBlastingtechnique

Fluid-powered ‘Moineau’motor and jet/mill head.Radial jets follow pilotmill.

Motor strator is an expensive expendable ~300°F limit

Positive surface indication of cleaning

Clean hardbridges

DescriptionTool Clean tubularjewelry

Otheradvantages

Otherdisadvantages

Mechanical cleaning

Chemical cleaning

Jet Blaster tools

>Mechanical scale-removal techniques.

Impact tools, such as the Baker Oil Tools HippTripper tool, are reciprocating tools that workmuch like a small jackhammer with a rotating bit.They impact the scale at 300 to 600 times perminute and rotate about 20 times per minute,typically with a chisel or star-shaped bit. Millscannot be used with such tools because theimpacts cause excessive damage to the millsurface. These tools work best on brittle scale deposits, removing scale as quickly as 10 to100 linear feet [3 to 30 m] per hour.

When fullbore access to scale deposits is par-tially blocked by physical restrictions such asdecreasing tubing diameter and encroaching com-pletion equipment, tools that can change diame-ter are required to remove scale below therestriction. If such equipment is not available,then a small hole—less than full tubing size—can usually be drilled through the scale below therestriction to allow increased flow. Nevertheless,a residual scale surface in the tubing encouragesnew scale growth and makes inhibitor treatments

to block nucleation much more difficult. A clean,bare steel surface is more effective in preventingnew scale growth.

Impact tools like motors and mills usually needfullbore access and seldom clean scale completelyto the steel walls. For such partial access situa-tions, under-reaming mills can increase the effec-tive diameter by moving the milling bladesoutward in response to pump pressure and rate.Under-reaming mills are effective, but removescale only at about half the rate of a typical mill.

Fluid-mechanical jetting methods—Downholefluid-jetting systems, such as Halliburton’sHydroblast and BJ-NOWSCO’s RotoJet system,have been available for many years to removescales in production tubing and perforations. Suchtools use multiple jet orifices or an indexed jettinghead to achieve full wellbore coverage. Thesetools can be used with chemical washes to attacksoluble deposits wherever placement is critical toprevent bullheading reagent losses. Water jettingcan be effective on soft scale, such as halite, anddebris or fill, but experience shows that it is lesseffective on some forms of medium to hard scalesuch as calcite and barium sulfate (left).

38 Oilfield Review

>Removing calcium carbonate scale with waterjetting. The tubing was jetted with a single waterjet at a rate of 2.4 in./min [1 mm/sec]. Althoughcarbonate scale has been removed, a consider-able amount remains in place.

>Removing calcium carbonate scale with abrasivewater jetting. The tubing was jetted with abrasivesand in a single water jet at a rate of 2.4 in./min [1 mm/sec]. During the test the jet was held station-ary for 3 minutes, and the sand jet cut a hole nearly80% through the tubing wall, an unacceptable levelof damage.

Target

Speed timingelectronics

Barrel Gas cylinder

Individual particle impact Speed 200 m/sec Impact angle 30/90°

Sand particles Limestone particles Glass Beads Sterling Beads particles

Particle-impact tester. A particle-impact testerwas built to study and evaluate the abrasivematerial damage mechanism on steel tubing andscale substrate (top). This device can fire individ-ual particles in excess of 450 mph [200 m/sec]that hit the surface at angles between glancingblows of 30° and perpendicular impacts. Thedamage from various particles can be seen in thephotographs (bottom). Angular sand and calciteparticles tend to gouge through the steel, leadingto ductile failure. Round particles bounce off thesteel surface. Glass beads create large, deepimpact craters that eventually erode through thesteel tubing. Sterling Beads particles shatter onimpact with steel, creating only small pits thatleave the steel undamaged.

>

Autumn 1999 39

At surface pressure, water jetting removesscale by cavitation, whereby small bubbles formin the fluid jet stream. These bubbles are createdby the large pressure release as fluid passesthrough the jet nozzle. The bubbles collapse on impact with scale, causing a forceful—almost explosive—erosive effect. Research atSchlumberger Cambridge Research, England,shows that this cavitation process is highlysuppressed downhole under hydrostatic bore-hole pressure. Cutting rates are typically reducedby a factor of four or more. Surface pumping-pressure limitations using coiled tubing-conveyed jetting tools prevent increasing fluidpressure high enough to overcome the differen-tial loss at the bottom.

Abrasive slurries—Adding a small concentra-tion of solids, 1% to 5% by weight, to a water jetcan drastically improve its ability to cut throughscale. Water jets using abrasive sand are widelyused in the construction and demolition indus-tries for cutting reinforced concrete, and even indemilitarization for cutting live ammunitionswithout generating heat or an ignition source.This technique also shows superior cuttingperformance in calcium carbonate scale overwater jetting alone (previous page, top right).Unfortunately, using abrasives such as sand candamage steel tubulars. When scale is completelyremoved from tubing, the abrasive jet erodes thesteel as efficiently as it does the scale. Shouldthe jetting tool stall, there is a significant risk ofthe abrasive jet perforating the steel tubing.

An abrasive jet that cuts scale without dam-aging tubing must exploit the difference in hard-ness between wellbore scale and the underlyingsteel. One of the key differences between well-bore scale and tubular steel is that while scale isbrittle, steel is prone to ductile failure (previouspage, bottom). A sharp sand particle will erodethe surface of ductile material by a cutting andplowing action. On the other hand, a hard roundparticle will bounce off the surface, removingonly a small volume of steel and leaving animpact crater. Scale exhibits brittle failure, so theimpact of a hard particle fractures the scale andultimately causes substrate disintegration. Scalebreakdown is independent of particle shape.

Choosing round rather than sharp, angularparticles promotes scale erosion while reducingdamage to steel tubulars. For example, AdamsCoiled Tubing provides a glass-bead abrasive-jetting system. The jetting tool has eight station-ary nozzles allowing complete radial coverageand downward pointing jets. The system iscompatible with foaming fluids and effective onall types of scale. On the other hand, the cratersformed by repeated impacts with glass particlescan eventually lead to fatigue and failure of thesteel surface (above).

Sterling Beads abrasives—Glass beads aresignificantly harder than the steel tubing andcause excessive tubing erosion. Reducing thehardness of the abrasive particles too much,however, renders them ineffective. Thus, thedesired hardness is a compromise between min-imizing damage to the steel while maximizing thescale-cutting performance. Other parameters,such as abrasive material friability, are alsoimportant. Although many spherical particles ofcorrect hardness are available, they tend to havelow durability and shatter on impact—impartinginsufficient destructive energy to the substrate toremove the scale.

Based on experimental and theoretical studyof the physical interactions between abrasiveparticles and typical tubing materials atSchlumberger Cambridge Research, a new abra-sive material called Sterling Beads abrasive wasproposed.8 This material matches the erosive per-formance of sand on hard, brittle scale materials,while being 20 times less erosive of steel, andwill not damage the well if prolonged jettingoccurs in one spot (above). The abrasive particleshave a spherical shape, a high fracture tough-ness and low friability (below). The beads aresoluble in acid and have no known toxicity,making cleanup operations simple.

>Tubing cleaned with glass-bead abrasive. Thetubing was jetted with glass beads in a singlewater jet at a rate of 2.4 in./min [1 mm/sec].Carbonate scale has been removed. During thetest the jet was held stationary for 3 minutes, and the glass beads cut a hole nearly 30% intothe tubing wall.

>Tubing scale removed with the Sterling Beadsabrasive. The tubing was jetted with SterlingBeads abrasive in a single water jet at a rate of2.4 in./min [1 mm/sec], to remove carbonate.During the test, the jet was held stationary for 3 minutes, and less than 2% of the steel wasremoved from the tubing wall.

0.75 mm

>Microscopic view of Sterling Beads abrasive.

8. Johnson A, Eslinger D and Larsen H: “An Abrasive jettingRemoval System,” paper SPE 46026, presented at the1998 SPE/IcoTA Coiled Tubing Roundtable, Houston,Texas, USA, April 15-16, 1998.

Coiled tubinghead connector,

check valves and disconnect

Dual-actuatedcirculating

valve

Filter module

Swivel “Moineau” PDM

Motormodule

Drift ring

Headmodule

Radial jet head

Scale Blastingtechnique

Jet drillinghead

Radial jethead

and pilot mill

Bridge Blastingtechnique

Nozzle head Drift ring

< Jet Blaster tool. Photograph (top) shows thetoolbox containing the abrasive jetting system asdelivered to the wellsite. The Jet Blaster down-hole tool (middle left) includes coiled tubing con-nections, check valves and disconnect equip-ment; dual-acting circulation unit; and a filterthat prevents unexpected debris in the jettingfluid from clogging the jetting nozzles. The toolconverts fluid power to a continuous speedrotation with a viscous shearing-fluid speed-controlled swivel for removing scale along theinside of tubular walls (insert middle right).Reaction forces from the two offset jet nozzlesprovide about 5 ft-lbf torque to rotate the swivelhead at speeds less than 200 rpm. The jettinghead consists of a nozzle carrier and a drift ring.In the Jet Blasting and Scale Blasting tech-niques, the nozzle carrier is assembled with twoopposing tangential jets (bottom left). The offsetjetting nozzles maximize hydrodynamic energytransport to the wellbore. The drift ring allowsweight to be set down on the tool so that the tool will advance only after the entire minimumbore diameter is cleaned. In the Bridge Blastingtechnique, a positive displacement “Moineau”style motor (bottom center and right) can beused to drill scale bridges across tubing forBridge Blasting applications. This motor candeliver 150 ft-lbf torque to the head module at 300 rpm.

A simulator can help design an effective chemi-cal treatment. For example, StimCADE softwareis a coupled wellbore and reservoir stimulationprogram that includes a wellbore model, areservoir model and a chemical reaction modelfor scale prediction. Input parameters include a comprehensive list of wellbore, formation,fluids and chemical treatment descriptions. The wellbore model solves convection-diffusionequations for fluid flow down the treatment string

Universal scale-removal system—Engineersat the Schlumberger Reservoir CompletionsCenter in Rosharon, Texas, USA, developed a vis-cous fluid-controlled rotating head jetting toolcalled the Jet Blaster tool, that has jet-nozzlecharacteristics optimized for use with SterlingBeads abrasives (right). This new rotating jetting-head-based tool, combined with the SterlingBeads abrasives, forms the basis of a new sys-tem of coiled tubing-conveyed intervention ser-vices designed to remove scale in downholetubulars. The Blaster Services system featuresthree scale-removal techniques that can beapplied to a wide range of scale problems:• The Scale Blasting technique combines the use

of Sterling Beads abrasive with the new jettingtool for hard-scale removal.

• The Bridge Blasting technique uses a poweredmilling head and abrasive jetting, when scalecompletely plugs the tubular.

• The Jet Blasting technique uses the new jet-ting tool with nonabrasive fluids for soft-scale-removal applications.

The scale-removal system also includes ascale-removal design program, called Jet Advisorsoftware, that enables an operator to optimize thejetting-tool configuration and nozzle size based onwell conditions to maximize jetting power andhead penetration rate. It also helps with the selec-tion of either abrasive or nonabrasive—fluidonly—scale-removal techniques. The Jet Advisorprogram alerts the operator to the risk of tubulardamage due to headstalls—using steel damageand coiled tubing stick-slip analysis.

(production tubing, coiled tubing or the casing)to estimate friction pressure during pumping.

In estimating the invasion of treatment fluidsinto the formation surrounding the wellbore,the reservoir model tracks the location of differ-ent fluid fronts in the reservoir. The chemicalreaction model estimates the rate of mineraldissolution following kinetic rate laws for thesolvents used and mineral species present inthe formation lithology section. The net mineral

dissolution is translated into a skin reductionfor each acid treatment.

Additional features include the ability tomodel wellbore deviation, predict effects ofdiverting agents on fluid-invasion profiles in thereservoir, and simulate flow of two fluids simul-taneously into the well—one down tubing orcoiled tubing, and one down the annulus. Thesefeatures help predict the efficiency of varioustreatment placements.

Chemical Placement Simulator

40 Oilfield Review

Autumn 1999 41

Removing hard scale—For hard scales likeiron, strontium and barium sulfate, nonabrasivefluid jetting and chemical treatments are inade-quate. The controlled-erosive action of theSterling Beads abrasive has been successful inremoving every type of scale in tubing, includingthe most difficult barium sulfate scales, at ratesup to 100 ft/hr [30 m/hr] or more. The ScaleBlasting technique is a particularly good optionwhen the scale encountered in the well is insol-uble, unknown or of variable hardness. The sys-tem also provides a safe method to remove scalefrom downhole completion equipment. Rate ofpenetration (ROP) is controlled using a drift ringthat ensures full tubing-diameter cleaning withminimum damage to the steel surface.

The Scale Blasting technique was used in theNorth Sea to remove hard barium sulfate depositson two gas-lift valves, identified by multifingercaliper logs, in a multiple-mandrel gas-lift comple-tion well (right).9 Well flowing pressure decreasedas water was injected, and there was a possibilitythat the available gas pressure would be inade-quate to reach the only remaining active valve in aside-pocket mandrel. Failure to remove andchange a second damaged valve would haveresulted in the well dying as water cut increasedand led to a costly workover. Solvents were inef-fective in removing enough scale to allow kickovertools to engage and latch onto the valves.10

The new coiled tubing-conveyed abrasive-jetting technology was used in this well for thefirst time in the North Sea. Jet Advisor softwareprovided the optimal drift ring size, nozzle and noz-zle-head size to efficiently clean the hard scale.The software also provided the optimal abrasiveconcentration and predicted scale-removal rates.

First, the damaged side-pocket mandrel wascleaned at a rate of 100 ft/hr [0.5 m/min]. Then,the other operating side-pocket mandrel wascleaned with the same procedures. The entireoperation was evaluated by running the kickovertool and checking the possibility of changing thegas-lift valves in the cleaned side-pocket man-drels. A gamma ray log was also run to evaluatethe remaining scale deposit in the completion(right). The damaged valve was successfully

retrieved and replaced. Abrasive jetting efficientlycleaned the scale without damaging the mandrel.

In another example, up to 0.38-in. [1-cm] thickbarium sulfate deposits prevented an operator inGabon, West Africa, from accessing and chang-ing five gas-lift mandrels in a well with a taperedproduction-tubing completion. The well had notproduced since 1994. Gauge cutter runs showedscale buildup bridged the tubing, blocking accessto the lower section of the well. The workoverobjectives were to clean the tubing scale, changeout gas-lift mandrels, and gain access to the wellbelow the tubing.

Early attempts at conventional scale-removalmethods, including several positive displacementmotors (PDM) and milling runs, an impact hammerand another jetting system following dissolvertreatments, were unsuccessful. The ability toremove hard barium sulfate scale under a widerange of conditions made the Scale Blasting tech-nique an attractive alternative. Because of thetapered completion, several sizes of gauge ringsand nozzle heads were required. The jetting fluidwas formulated with standard concentrations ofpolymer and Sterling Beads abrasives to achieveoptimum well cleanup and rate of penetration.

Nominal tubing diameter

Diameter April 1996

Diameter April 1997

Diameter August 1997

Dept

h, ft

X526

X527

X528

X529

X530

4.0 in. 6.0 in.

>Scale buildup between April 1996 and August 1997. Multi-arm caliper logs show scaleaccumulation (shaded) in the upper side-pocket mandrel.

9. Tailby RJ, Amor CB and McDonough A: “Scale Removalfrom the Recesses of Side-Pocket Mandrels,” paper SPE54477, presented at the 1999 SPE/IcoTA Coiled TubingRoundtable, Houston, Texas, USA, May 25-26, 1999.

10. For a discussion of the use of kickover tools to removeretrievable gas-lift valves located in side-pocket mandrels: Fleshman R, Harryson and Lekic O: “ArtificialLift for High-Volume Production,” Oilfield Review 11, no. 1 (Spring 1999): 49-63.

900

X870 X880Depth, m

May 1998

Region of scale removal

April 1997

X890 X900X860

800

700

600

500

GR, A

PI

400

300

200

100

0

>Confirming scale cleaning. Gamma ray logs can be used to indicate the amount of scaleremoved over the 22-m [84-ft] cleaned interval centered at the side-pocket mandrel loca-tion. The 1997 gamma ray log shows the relative scale buildup on the lower side-pocketmandrel one year before treatment. The 1998 log was measured after scale was removedfrom the zone between X872 m to X894 m.

42 Oilfield Review

1.5

1

13

4

2.5

7

2

1.5

Scale Blasting technique

Scale Blasting technique

Bridge Blasting technique

Scale Blasting technique

Scale Blasting technique

Bridge Blasting technique

Scale Blasting technique

Scale Blasting technique

Blaster Services Length of scaleremoved, m

Treatmenttime, hr

Tool driftO.D., mm

Well 1

Well 2

Well 3

Well 4

Well 5

Well 6

Well 7

Well 8

1023

45

162

1108

28

270

511

20

54

46.7

46.7

46.7

54

54/45

54

46.7

>Beaverhill Lake scale-removal results.

Jet Advisor software optimized the rotatingjetting-head torque and abrasive cutting effi-ciency with rate, pressure and viscosity as vari-ables in the 56°-deviated wellbore. The mosteffective pump rates and surface pressures weredetermined by the CoilCADE software, while theCoilLIMIT program was used to determine thesafe working limits of the coiled tubing.

The treatment resulted in 6500 ft [1981 m] of tubing cleaned in a total jetting time of 25.5 hours. Average penetration rates were 600 to 900 ft/hr [3 to 5 m/min] in 31⁄2-in. tubing,and 40 to 100 ft/hr [0.2 to 0.5 m/min] across the gas-lift mandrels and in the 27⁄8-in. tubing.Successful treatments allowed the operator toreplace the gas-lift mandrels, and the well nowproduces 2000 B/D [320 m3/d]. The removed gas-lift mandrels had been cleaned in all areasexposed to the wellbore and the valves were not damaged.

Removing scale bridges from tubulars—Scale deposits that completely bridge tubularscan be removed with a special adaptation of theJet Blaster abrasive jetting tool using the BridgeBlasting technique. The Bridge Blasting tech-nique incorporates a 1.69-in. diameter PDM spe-cially modified to prevent Sterling Beads abrasivefrom clogging the motor’s high-pressure labyrinthshaft seal. The PDM drives a combination jettingand milling head that uses a Reed-Hycalog dia-mond mill to make a small pilot hole in thedeposit (above right). Radial jets complete thecleaning. Since the mill removes only a fractionof the total bridged deposit volume, the cleaningrate and overall mill and motor reliability aremuch higher than with conventional PDM-milling-cleaning methods.

A drift ring centers the tool and prevents milldamage to the tubulars—frequently a problemwith conventional milling techniques. In hard,bridged deposits, a different jet-drilling head isused if the pilot mill does not achieve acceptablecleaning rates. The jet-drilling head uses four crit-ically oriented jetting nozzles to drill through thescale bridge using a Sterling Beads slurry. A sub-sequent run with the Jet Blaster swivel withSterling Beads abrasive is usually required to com-plete cleaning to the full diameter of the tubulars.

Iron sulfide [FeS2] scale is a special problemfor BP Amoco throughout the Kaybob south fieldin the Beaverhill Lake formation in Canada. Theiron sulfate crystallites form directly on steeltubing, attaching firmly, and promote eitherbimetallic or crevice corrosion beneath the crys-tallites. These sour gas [H2S] condensate wellsdeposit high molecular-weight compounds, suchas asphaltene, on the iron sulfide crystallitesinside tubing.11

This unusual scale cannot be removed byhydrochloric acid, surfactants or chelating agentsbecause asphaltene protects the scale from scaledissolvers. The scale can be removed only bymechanical techniques or by first chemicallyremoving the asphaltene layers. Past experiencewith conventional methods for scale removal—including foamed acid, acid jetting combined withorganic solvents such as xylene, and drilling,milling and tubing shakers—were inconsistent.

New abrasive jetting techniques using theSterling Beads abrasive were evaluated in eightwells. Gelled water containing a xantham bipoly-mer additive was used for friction reduction andimproved cuttings transport. The Sterling Beads

weight concentration used in these wells was2.5%. Treatment times varied from 1 to 4 hoursfor six wells treated with the Scale Blastingtechnique, and up to 13 hours in one of the twowells containing scale bridges treated with theBridge Blasting technique (below). Rates of pen-etration vary depending on tool drift, nature ofthe deposits, occurrence of bridges when usingthe Scale Blasting technique, and wellborerestrictions. Overall, 10,400 ft [3170 m] of scalewere successfully removed from the eight wellsin 32.5 hours cumulative jetting time.

Removing sand plugs—When wellboredeposits are soft, acid soluble or chemically reac-tive, the nonabrasive Jet Blasting technique is themost cost-effective and efficient. The increasedfluid-jet efficiency from the optimized jetting headmaximizes cleaning ability on soft scale, freshcement and filter cake. Other drilling damage andinsoluble deposits benefit greatly from a com-bined chemical and jet-cleaning treatment.

An operator in south Texas was having diffi-culty removing sand plugs in a well with threefracture-stimulated zones that were isolated bysand plugs. Each sand plug was topped with a cap

>Bridge Blaster milling head. The Bridge Blaster system can be configured with aradial jetting head, drift ring and a Reed-Hycalog mill (left), or with downward-facingabrasive jetting nozzles (right) that drill a hole through scale bridges that cannot becut with tungsten carbide mills.

11. Crombie A, Halford F, Hashem M, McNeil R, Thomas EC, Melbourne G and Mullins O: “Innovations in Wireline Fluid Sampling,” Oilfield Review 10, no. 3(Autumn 1998): 26-41.

12. Wigg H and Fletcher M: “Establishing the True Cost of Downhole Scale Control,” paper presented at theInternational Conference on Solving Oilfield Scaling,Aberdeen, Scotland, November 20-21, 1995.

13. Rosenstein L: “Process of Treating Water,” U.S. PatentNo. 2,038,316 (April 21, 1936). This 1936 US patent is one of the earliest references to threshold inhibitors.

14. Nancollas GH, Kazmierczak TF and Schuttringer E: “A Controlled Composition Study of Calcium CarbonateGrowth: The Influence of Scale Inhibitors,” Corrosion-NACE 37, no. 2 (1981): 76-81.

Autumn 1999 43

of silica flour to provide a better pressure seal. Adrill motor with a mill was used to try to clean outthe sand plugs. The first plug was cleaned out suc-cessfully, but the mill was completely worn downafter cleaning 2 ft [0.6 m] of the second plug. Asecond mill managed to drill out only an additional5 ft [1.5 m] in the plug before it was completelyworn (above). The plug with silica flour on top hadbeen crushed and packed tightly due to fracturingpressure from above, forming a hard fill.

Jet Advisor software was used to select theproper nozzle size for the Jet Blasting techniquebased on well conditions. Head components andsizes were based on well completion and fill mate-rial. The jetting fluid was a 2% potassium chloride[KCl] water with friction reducer, foaming agentand nitrogen [N2]. Treatment resulted in a cleanoutrate of 420 to 600 ft/hr [2 to 3 m/min]. The plugsand silica flour were removed from the well in lessthan one day, saving the operator the cost of theworkover rig and five days in lost production.

Preventing ScaleThe direct cost of removing scale from one wellcan be as high as $2.5M, and the cost of deferredproduction even higher.12 Just as prevention isbetter than cure in medical practice, keepingproducing wells healthy is ultimately the mostefficient way to produce hydrocarbons. In mostcases, scale prevention through chemical inhi-bition is the preferred method of maintainingwell productivity. Inhibition techniques can rangefrom basic dilution methods, to the mostadvanced and cost-effective methods of thresh-old scale inhibitors.

Dilution is commonly employed for control-ling halite precipitation in high-salinity wells.Dilution reduces saturation in the wellbore by continuously delivering fresh water to thesandface, and is the simplest technique toprevent scale formation in production tubing. It requires installation of what is called amacaroni string through the production tubing

(above). The macaroni string is typically small-diameter tubing—less than 11⁄2-in.

In addition to dilution, there are literally thou-sands of scale inhibitors for diverse applicationsranging from heating boilers to oil wells. Most ofthese chemicals block the growth of the scaleparticles by “poisoning” the growth of scalenuclei. A few chemicals chelate or tie up the reac-tants in a soluble form. Both approaches can beeffective, but each requires careful application astreatments show little tolerance for change in theproducing system. Chelating inhibitors block pre-cipitation or scale growth only for a certain lim-ited level of oversaturation. Equilibrium upsetsoccur, even in protected systems, allowing scaleto precipitate. Because chelating agents con-sume scale ions in stoichiometric ratios, the effi-ciency and cost-effectiveness of chelants asscale inhibitors are poor.

In contrast, threshold scale inhibitors interactchemically with crystal nucleation sites and sub-stantially reduce crystal growth rates. Thresholdscale inhibitors effectively inhibit formation ofmineral scales at concentrations on the order of1000 times less than a balanced stoichiometricratio.13 This considerably reduces the treatmentcost. Most scale inhibitors are phosphate com-pounds: inorganic polyphosphates, organic phos-phate esters, organic phosphonates, organicaminophosphates and organic polymers. Thesechemicals minimize scale deposition through acombination of crystal dispersion and scale sta-bilization (left).14

>Mill worn by silica flour.

Macaroni string

B

A

Chemical squeeze

Salineproduction

Freshwater

>Macaroni string. The small-diameter macaronistring, also called a spaghetti string, or capillarystring, delivers fluids and chemicals into produc-tion wells. It delivers chemicals close to the interval, as shown at A, that is producing the fluid needing treatment. A periodic inhibitorsqueeze into the formation is shown at B.

Dispersion Stabilization

Inhibitor absorbed onto the active sites of the growing crystals—preventing further growth

Crystal nuclei are stericallystabilized—preventing further growth

>Dispersion and stabilization. Dispersion (left) prevents small seed crystals of scale from adhering totubing walls and other crystal particles. Stabilization chemicals modify the deposited scale structure,preventing additional crystal attachment.

44 Oilfield Review

Fluid inflow through adsorbed zone

Phase-inverted inhibitor in proppant orimpregnated proppants in proppant

> Fracture stimulation with inhibitor placement. High-efficiency scale-inhibitor placement isachieved by pumping the inhibitor into the fracturing fluid during fracture stimulation. The inhibitoris retained by adsorption on the formation in the leakoff zone, or by precipitation on the proppant.As formation water passes through the inhibitor-absorbed zone, it dissolves enough inhibitor toprevent the water from precipitating in the fractures and wellbore.

Inhibitor lifetime—Scale inhibitors areretained in the formation by either adsorbing tothe pore walls or precipitating in the pore space.Adsorption is most effective in sandstone forma-tions (above). Treatment lifetimes depend primar-ily on the surface chemistry, the temperature, andthe pH of the liquid contacting the formation, andare occasionally unusually short (3 to 6 months)because the adsorption capacity of reservoir rocksunder reservoir conditions is limited.15 Under spe-cial conditions, such as high adsorption-capacityformations and low water-production rates, up totwo-year lifetimes can occur.

Normally, treatment lifetimes exceed one yearfor properly designed treatments in which precipi-tation is the inhibitor retention mechanism—evenwhen high water-production rates are encoun-tered.16 For example, phosphates and phosphino-carboxylic acid inhibitors are among those knownto prevent calcium carbonate scale. Calcium ionsare often liberated when the inhibitors are placedin carbonate formations, and precipitation is thedominant long-term retention mechanism in car-bonate formations. A calcium chloride brine over-flush is often pumped to induce scale inhibitorprecipitation and extend the treatment lifetime inreservoirs that do not naturally contain enoughsoluble calcium to precipitate the inhibitor.17

Long inhibitor lifetime can be also beachieved by pumping large volumes of inhibitordeep into the formation, such that the inhibitor isexposed to and absorbed to a large surface area.This is not always successful because squeezingwater-based inhibitors into oil zones can lead toa temporary change in formation wettability. Thisresults in unacceptably long production-recoverytimes. Alternative oil-soluble inhibitors that donot cause the formation rock to become waterwet are needed. New fluids based on criticalpoint wetting of rock are being tested for inhibitor

enhancement. These make the reservoir rock“super wet,” allowing a higher degree of inhibitorretention and a longer protection lifetime.

Commercial software, such as the Squeeze-Vprogram that was developed at Heriot-WattUniversity, Edinburgh, Scotland, models theretention and release of scale inhibitors byadsorption or precipitation. This program is usedto optimize inhibitor concentrations, treatmentand overflush volumes to maximize inhibitor life-time. It can also be used to match histories ofprevious treatments as part of an overall strategyof continual improvement in scale management.

Improving inhibitor placement—Ultimately,treatment performance is based on scale preven-tion, not on the duration of the inhibitor. Properinhibitor placement is a key factor in the perfor-mance of an inhibitor squeeze treatment.Bullheading the inhibitor into a formation canlead to overtreatment of low-pressure and high-permeability zones, and undertreatment of

high-pressure and low-permeability zones. Thus,it is considered good practice to place scaleinhibitors in heterogeneous formations using thesame placement techniques employed to controlacid placement. In fact, there are significantadvantages to combining the acid and scale-inhibitor treatments to ensure that the scaleinhibitor is controlled along with the acid. Caremust be taken to insure that the acid pH does notexceed that required for inhibitor precipitation.18

Integrating scale inhibitor with fracturestimulation—Protection of propped fracturesagainst mineral scale fouling is critically depen-dent upon proper inhibitor placement. Portions ofthe fracture that are left untreated by theinhibitor might be irreversibly damaged becauseof the ineffectiveness of contacting mineralscales in proppant packs with scale solvents. Asa result, there have been efforts to pump scaleinhibitors in fracturing fluid, thereby guarantee-ing proppant-pack coverage.19

Phase-trappedinhibitor

Adsorbed inhibitorClay or othercharged surface

Inhibitor Adsorption Inhibitor Precipitation with Phase Separation

Phase-separated inhibitor

Clay or othercharged surface

Dissolved inhibitor

>Adsorption and precipitation. Scale inhibitors yield the best treatment lifetimes when they are retained in the formation eitherby adsorption to the pore walls (left), or by precipitating in the pore space (right).

Autumn 1999 45

An alternative inhibitor delivery system,implemented by Schlumberger, called theScaleFRAC system combines a scale-inhibitortreatment and fracture treatment into a single-step process by using a new liquid inhibitor com-patible with fracturing fluids. The scale inhibitoris effectively placed everywhere in the proppedfracture by pumping the scale inhibitor during thepad and sand-laden stages of the fracturingtreatment (previous page, bottom). The newprocess eliminates a scale squeeze treatmentimmediately following a fracture stimulationtreatment, and also circumvents the problem ofslow oil-production recovery caused by wettabil-ity changes produced by conventional scale-squeeze treatments.

The new inhibitor delivery system has beenused extensively on the North Slope in Alaska,and has found applications in the North Sea andthe Permian Basin. For example, results in thePermian Basin show that inhibitor concentrationsin produced water remain above threshold valuesnecessary to prevent scale deposition signifi-cantly longer than conventional treatments(above right). The new integrated inhibitor-frac-ture treatment provides sustained fracture pro-ductivity due to better inhibitor placement. It alsosimplifies wellsite logistics, due to combining thesqueeze and inhibitor treatments; and the wellreturns to production faster because there is noshut-in to allow the inhibitor to adsorb or precip-itate in the formation.

Recently, AEA Technology in England devel-oped a new porous ceramic proppant that isimpregnated by the scale inhibitor for use duringhydraulic fracturing.20 The novel feature of the AEA scale inhibitor is that the salt of a

commonly used oilfield scale inhibitor is pre-cipitated such that it fills the porosity of alightweight ceramic proppant. The filled ceramicproppant can then be substituted for a fraction ofthe original proppant in the fracture-treatmentdesign. Upon production, any water flowing overthe surface of the impregnated proppant willcause dissolution of the scale inhibitor—protect-ing the well against scale depositing from thewater. The inhibitor-release mechanism is disso-lution of the inhibitor from the interstitial poresof individual proppant grains. This avoids wastedinhibitor by phase trapping. After all the inhibitoris dissolved, the ceramic substrate remains andcontinues to serve as a propping agent.

ConclusionThere have been many significant advances inscale control and remediation in recent years.Today, operators have access to a portfolio ofchemical and mechanical products designed toremove scale and prevent its buildup. Theimprovements in placement technology, reservoirchemistry and intelligent fluids furnish more cost-effective options for chemical scale inhibition andremoval in the formation. Developments in scale-removal services incorporating new abrasivematerials are providing fast, reliable ways toremove scale inside tubulars without risk to thesteel tubing.

Each new technology improves one aspect ofscale control in a wellbore. Combined, these newtechnologies become part of a scale-managementprocess in which one can apply surveillancemethods to identify the onset of scaling condi-tions and develop the optimum strategy for reduc-ing scaling-related production losses andremedial expenses. The strategy may include ele-ments of scale prevention and periodic removal.Engineers working in scale-prone reservoirs aregrateful for every improvement in the technologyused to combat their scale problems. —RCH

50,000 100,000 150,000 200,0000.1

1

10

100

Scal

e-In

hibi

tor c

once

ntra

tion,

ppm

Cumulative water tested, bbl

ScaleFRAC Well AScaleFRAC Well BConventional treatment

Minimum inhibitor range

> Inhibitor retention. Inhibitor elution data measured in two wells treated with theScaleFRAC system show that inhibitor concentrations in the produced waterremained above the threshold value—typically 1 to 5 ppm—to prevent scaledeposition and growth. Wells A and B treated with the new inhibitor-placementtechnique produced scale-free water significantly longer than those with conven-tional treatments.

15. Browning FH and Fogler HS: “Precipitation andDissolution of Calcium Phosphonates for theEnhancement of Squeeze Lifetimes,” SPE Production & Facilities 10, no. 3 (August 1995): 144-150. Meyers KO, Skillman HL and Herring GD: “Control ofFormation Damage at Prudhoe Bay, Alaska, by InhibitorSqueeze Treatment,” paper SPE 12472, presented at theFormation Design Control Symposium, Bakersfield,California, USA, February 13-14, 1984.

16. Martins JP, Kelly R, Lane RH, Olson JB and Brannon HD:“Scale Inhibition of Hydraulic Fractures in Prudhoe Bay,”paper SPE 23809, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 26-27, 1992.

17. See Meyers et al, reference 15.18. Crowe C, McConnell SB, Hinkel JJ and Chapman K:

“Scale Inhibition in Wellbores,” paper SPE 27996, presented at the University of Tulsa CentennialPetroleum Engineering Symposium, Tulsa, Oklahoma,USA, August 29-31, 1994.

19. Powell RJ, Fischer AR, Gdanski RD, McCabe MA andPelley SD: “Encapsulated Scale Inhibitor for Use inFracturing Treatments,” paper SPE 30700, presented atthe SPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 22-25, 1995. See alsoMartins et al, reference 16.

20. Webb P, Nistad TA, Knapstad B, Ravenscroft PD andCollins IR: “Economic and Technical Features of aRevolutionary Chemical Scale Inhibitor Delivery Methodfor Fractured and Gravel Packed Wells: ComparativeAnalysis of Onshore and Offshore Subsea Applications,”paper SPE 39451, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 18-19, 1998.

46 Oilfield Review

Nick SwinsteadGatwick, England

For help in preparation of this article, thanks to Geoff Dicksand Tim Lloyd, Gatwick, England; Tor Eilertsen and ArildViddal, Asker, Norway; Carel Hooykaas and MickRichardson, Houston, Texas, USA; and Andrew Muddimerand Mark Williamson, Sugar Land, Texas.Monowing, Nessie, TRILOGY and TRINAV are marks ofSchlumberger. Cyberbase is a mark of Hitec. ProEngineer is a mark of Parametrics Corporation. Sun is a mark of Sun Microsystems.

A Better Way to Work

Autumn 1999 47

In any enterprise in which people do the work,efficiency and productivity depend on human fac-tors. Health and safety of workers and protectionof the environment are cornerstones of most mod-ern business policies. By establishing and com-plying with health, safety and environment (HSE)principles, companies can attract qualified person-nel, fulfill government requirements, assure busi-ness longevity and ultimately be more productive.

But to excel in an industry, meeting minimumHSE standards is not enough. While HSE programsstill come first, high-performance companies arelearning that taking standards of employee andenvironmental well-being to a higher level yieldseven higher levels of performance.

The key to this achievement is the applicationof principles of ergonomics to the daily tasks thatworkers face. Derived from the Greek words“ergon” for work and “nomos” for natural laws,ergonomics is the study of the efficiency of peo-ple in their working environment. The main tenetof this field of study is that the working environ-ment should be adapted to the worker’s needs.

Applying this theory to the oil and gas indus-try potentially means addressing a wide range ofactivities, from handling heavy equipment to sit-ting down and picking up the telephone.Conditions can span arctic cold, desert heat,heavy seas and choking dust, and include situa-tions that are tense, dangerous, physicallydemanding, repetitive and dull. Clearly, not allaspects of the work environment can be modifiedto suit the individual. However, approaching eachtask with the view to optimizing it for the workerbuilds efficiency into every operation.

This article explains the basic principles ofergonomics and shows how their applicationincreases safety and productivity. Following thatis a practical illustration of these techniques in aproject to optimize aspects of marine seismicacquisition, vessel design and training simulationfor the new vessel, Geco Eagle.

Optimizing Work EnvironmentsOne of the fundamental fallacies of the world of work is that people can adapt to anything. Toa point, people can adapt to a new way of think-ing, an unaccustomed activity or an uncomfort-able posture. The degree to which the adaptationsucceeds depends on many factors, such as theability of the person, the effort involved, theduration, and the level of discomfort, difficulty ordanger in the new activity.

Some common working conditions are notregarded as dangerous enough to warrant safetyprecautions, but are still important to consider,such as noise levels, lighting, vibrations, temper-ature, boredom, work posture and repetitiveactions. These can potentially result in perma-nent hearing loss, eye strain, fatigue, loss of con-centration and mistakes. In addition tocontributing to lower productivity, the latter twoespecially—work posture and repetitiveactions—are now recognized as responsible formore enduring bodily harm.

The quality of working environments determines how well a task is performed. Here, we

examine how improving workplaces encountered in the oil and gas industry—and seismic

survey vessels in particular—contributes to increased safety, productivity and efficiency.

Repetitive actions and poor posture havebeen identified as the causes of repetitive straininjury, or RSI, in the medical field. The simpleactions of standing, sitting or moving improperlycan lead to permanent muscular and skeletaldamage (below).

Application of ergonomic principles can helpin the design of work environments that preventharmful posture and actions. For office work,properly designed chairs, desks, computer key-boards and office spaces reduce strain and pro-duce improved health and satisfaction for staffand customers, less discomfort and increasedproductivity and performance. These in turn leadto fewer accidents, less sick leave, lower staffturnover and less retraining for replacementstaff. And suitably formulated equipment for fieldwork delivers similar benefits.

Along with ergonomic considerations, equip-ment requirements in most work environmentsbenefit from attention to technical efficiency andsafety, manufacturability and disposal. The opti-mal product-design process reconciles thesethrough a series of five steps:

Review—The human and technical factors that will influence the success of the final projectare investigated.

Observe—Human-factors issues areobserved in a working context with existingequipment and documented to identify opportu-nities for innovation.

Visualize—A future direction is conceivedwith creative design concepts through brain-storming, sketches and mock-ups.

Evaluate—The feasibility of various solu-tions is tested to converge on an optimal direc-tion using computer-aided design (CAD)visualization, solids modeling and sometimesfull-size test setups.

Implement—The engineering group respon-sible for manufacture is assisted to ensure thatthe most critical design aspects are preserved.

In addition to considering ergonomic aspectsin the design of a product, the discipline of indus-trial design brings a balance of functionality andaesthetics. Other industries, such as the automo-tive industry, have long benefited from the recog-nition that customers want a combination ofoptimal mechanical performance, high reliability,personal comfort, good value and attractiveappearance. The successful industrial designprocess blends function, ergonomics and a posi-tive perceived image to yield a product differen-tiated from that of the competition.

Such a process for improving equipment andwork environments and optimizing design hasbeen developed by the Schlumberger IndustrialDesign group—a multidisciplinary team of grad-uate industrial designers, ergonomists andhuman factors specialists—working in Gatwick,England and Sugar Land, Texas, USA.1

Originally a design resource for SchlumbergerResource Management Services, the teamexpanded its repertoire to offer industrial designand ergonomic resources to Oilfield Servicesstarting in 1988. The Industrial Design group hasworked with dedicated product-design teams ona wide range of products including automatedtest equipment, pay telephones, gasoline dis-pensers, utilities metering systems, controlrooms on semisubmersible rigs, oilfield vehicles,hand-held and back-packable portable equip-ment, hardware and coiled tubing units.2

48 Oilfield Review

> The Geco Eagle en route to her first operations offshore Brazil.

1. For information on the Schlumberger Industrial Designgroup: http://www.slb.com/qhse/design/

2. Brown SF: ”How Great Machines are Born,“ Fortune 139,no. 4 (March 1, 1999): 164-165.

Action or Posture Resulting Injury

Feet and legs,varicose veins

Strained extensormuscles of the back

Strained knees, calves and feet

Strained neck and shoulders

Damage to lumbar region,intervertebral discs

Shoulder and upper arm,periarthritis

Neck, deterioration ofintervertebral discs

Forearm, deteriorationof tendons

Standing in one place

Sitting erect withoutback support

Seat too high

Seat too low

Trunk curved forwardwhen sitting or standing

Arm outstretchedsideways, forwardsor upwards

Head excessively inclinedbackwards or forwards

Unnatural grasp ofhand grip or tools

> Relationship between inappropriate posture ormotion (left) and resulting physical problem (right).

Autumn 1999 49

The team has acquired considerable knowl-edge of general field operations through extendedvisits to both land and offshore locations. Thisknowledge base helps ensure that new projectsare undertaken with a solid understanding of theworking environment. The Industrial Design groupsometimes tackles a problem without detailedprior knowledge of the specific product or service,unaware of standard practice. This can be a greatadvantage: by coming in with a fresh perspectiveand applying a structured approach, the group canopen up creative design possibilities and delivernovel solutions that are unhindered by currentpractice and that promote efficiency, safety andquality. It was in this manner that the groupentered upon its most recent project—optimizingthe designs of the Geco Eagle back deck andinstrument room for improved marine seismicdata-acquisition efficiency (previous page, top).

Towing Until the early 1980s, seismic vessels towed onlyone streamer. Since then, the number of stream-ers has gradually increased and now 6- or 8-streamer configurations are common, with somevessels achieving 10. Total spread, or distancebetween outermost streamers, has grown to 900 m [2950 ft], and typical streamer lengthshave more than doubled from 3000 to 8000 m[9840 to 26,250 ft]. Anticipating continuedgrowth in the marine seismic industry,Schlumberger projected a future demand forvessels that could tow up to 20 streamers.

Towing this larger mass of cable requiresmore powerful vessels with more room to storereeled streamers and extremely wide decks tofacilitate streamer deployment. In the past,smaller, purpose-built seismic vessels wereupgraded and fishing trawlers were converted to

accommodate the added space and powerrequirements. However, neither of these propos-als represents a cost-effective solution becausethey do not offer the new capacity sought—asurvey footprint, or streamer length × spread, ofmore than 16 km2 [6 sq miles], by the beginningof the 21st century.

Also, as vessels become larger and the num-ber and separation of streamers grow, crews arechallenged to deploy and operate more complexacquisition arrays involving large amounts ofcostly in-sea equipment. The potential hazardshave never been greater.

These constraints led Schlumberger to opt fora new purpose-built vessel, and in doing so, toreevaluate the requirements of a new seismicacquisition platform equipped with state-of-the-art technology. The Geco Eagle would representa leap not only in terms of her size—the world’slargest seismic acquisition vessel—but also inother fundamental aspects of design.

The back deck and the instrument room, themain centers of acquisition operations, were twoareas targeted for ergonomic optimization. Toidentify problems, members of the IndustrialDesign group conducted a full study of currentpractice by visiting existing Schlumberger seis-mic vessels and observing operations. All activi-ties and equipment were documented andphotographed. This phase identified numerousopportunities for improvement.

Working BackOn the back deck, the main challenge is to deploysafely and efficiently the increased number ofstreamers called for in the new vessel design(left). On existing vessels, each streamer isreeled out and directed by hand-operatedhydraulic controls located near the reel or byhand-held radio control. This requires an operatoron the back deck for every streamer manipula-tion. It would be safer and more efficient if thestreamers could be controlled remotely by oneperson from one central location.

Attaching equipment to each streamer canrequire stretching and leaning over the stern. Thetowpoint, or point where the streamer departsfrom the vessel and slopes toward the water, maybe high overhead, and the connection maneuvercan require significant upper body strength.

> Back deck of the Geco Eagle.

50 Oilfield Review

> Back-deck crew handling streamer equipment at the stern of the vessel. Lifelines are an HSE requirement in this dangerous work environment.

> Lost-time injuries in the marine seismic business. According to this 1998 study performed by the UK Offshore Operators Association (UKOOA), themajority of lost-time injuries occurs on the back deck. The study collated HSE statistics from all marine seismic contractors for all seismic vesselsworldwide for the years 1993 though 1997.

BackDeck(51%)

Open Deck(19%)

Galley(6%)

Workshop(7%)

Small Boat(5%)

Accommodation(4%)

Ashore(2%)

Chaseboat(2%)

Engine Room(2%)

Compressor(1%)

Other(1%)

Lost-Time Injuries (LTI) by Work Area (1993-1997)

Autumn 1999 51

The field studies identified several opportuni-ties to improve back-deck working conditions thatwould lead to higher productivity and quality, andaddress particular safety concerns. Many lost-time injuries in the marine seismic business stemfrom inappropriate handling of equipment, andmost occur on the back deck (previous page, top).Reducing the number of workers exposed to riskand the high level of exertion on the back deckwill produce a more comfortable and productivework environment.

Not only is the work physically demanding,uncomfortable, wet and tiring, but it is also poten-tially dangerous. On some vessels, the back deckslopes down or drops off abruptly without anywall or guardrail. To control hazards in theseworking environments, workers are required towear life vests and safety harnesses, or lifelines(previous page, bottom). However, lifelines canrestrict movement to the point that they need tobe unclipped to access out-of-reach equipment,and the crew may forget to reattach them. Theredesign should address these issues, and allowthe crew to work safely away from the back edgeof the vessel with equipment at an appropriatelevel relative to body height.

Making practical design changes required anal-ysis of all the tasks performed onboard. Followinga one-week study on an operating vessel, taskanalysis techniques were used to document andanalyze standard operating procedures on the backdeck and to highlight areas of design opportunity(above). The task analysis also helped definedesign details and provided design-goal specifica-tions for the streamer-control systems.

Next, a conceptual design phase waslaunched to explore design opportunities. Early inthe design program, three-dimensional solidsProEngineer CAD visualization techniques were

> Task analysis for the Geco Eagle. The full analysis was captured on a chart measuring 6 ft [2 m] in length. Pictured with the chart aremembers of the Industrial Design team: Andrew Muddimer (left), Nick Swinstead (center), and Mark Williamson (right).

used to evaluate design concepts. Of particularbenefit was the use of fly-through techniques tolet the design team virtually move around a modelof the back deck on screen, to check lines of sight,achieve optimum equipment positioning and toidentify and assess safety issues (above).

The design team established that many back-deck problems were centered around the manip-ulation of streamers and the lack of clear workingspace arising from the large number of streamerscrossing the work area. These problems stemmedfrom the way streamers were being handledbetween the storage reels deep within the vesseland the towpoint where they were deployed intothe sea. A creative design program was initiated

to see if it would be possible to redesign thestreamer towpoints. Many solutions were exam-ined through CAD solids modeling, leading to aninnovative design that featured a traveling tow-point mounted on a rear pivoting beam (nextpage, top).3

This allows the streamer to be above head-height while being towed during acquisitionactivities, but also permits it to be lowered andbacked to a position nearly two meters [6.5 ft]away from the stern of the vessel, creating asafer work area (next page, bottom). The newdesign requires less upper-body strength andawkward strain to operate, letting female work-ers contribute more in areas previously thedomain of their male colleagues.

In addition to providing a completely clearback deck when all streamers are deployed, thenew design obviates the need for lifelines or har-nesses. These are no longer specified as part ofthe HSE policy on the Geco Eagle streamer deck,making it more comfortable for workers to handlestreamers as well as Monowing deflectors,buoys and other equipment.4

52 Oilfield Review

3. Williamson M: ”Streamer Handling Apparatus,“International Patent Application PCT/GB99/01760 (June 12, 1998).

4. The Monowing deflector applies aircraft-wing conceptsto deflect streamers apart, thereby achieving widestreamer spreads without the assistance of additionalvessels. The Monowing technique creates 40% less drag than traditional deflectors and currently enablesstreamer separations of up to 1400 m [4590 ft].

> A computer-aided design (CAD) rendering of the newvessel. The CAD simulations also allowed fly-throughs,or virtual travel, through the back deck, to test the workspace and assess visibility.

Autumn 1999 53

A crew member worksin a safer area and acomfortable position.Hydraulically powered bars extend and contract to bring the towpointwithin easy reach.

CAD modeling leadingto new traveling towpointdesign. In this rendition, a crew member in blue is standing near thestreamer that has beenbrought down to the work area.

>>

Other aspects of back-deck work were alsotransformed. In a sweeping change from tradi-tional practice, Schlumberger proposed transfer-ring streamer control from manual hydraulicfunctions at the individual reels to computer con-trols in a centrally located control room. Thestreamer-control station would house the controlposition, various control panels and monitors,and closed-circuit televisions (CCTV) (right).

CAD simulations helped position thestreamer-control station itself and define its inte-rior design and equipment configuration toensure clear line-of-sight from the operator’sseated position to all critical areas of the backdeck (below). Unobstructed lines of sight werevalidated by flying through the CAD model of thedeck. Based on the fly-through tests, some of thecolumns supporting the upper deck were reposi-tioned in the vessel design to improve visibilityfrom the streamer-control operator’s viewpoint.

Task analysis of back-deck activities helpedidentify control requirements for all in-sea equip-ment, streamer reels and conveyors. Conceptswere produced for controls, panel layouts and

54 Oilfield Review

> A CAD-simulated view from the streamer-control room. These simulations helped position the room and its componentsto ensure primary visibility to the entire back deck and camera exposure to streamer winches behind the control room.

> Conceptual design of the streamer-control station. The climate-regulated room would housea seat with joy-stick controls, monitors, closed-circuit televisions (CCTV) and alarm lights.

Autumn 1999 55

on-screen user interfaces. CAD simulations alsohelped evaluate placement of CCTV cameras thatwould monitor reel and streamer operations fordisplay in the streamer-control station CCTV sys-tem. Emergency controls and alarm indicatorswere positioned close at hand in the primary fieldof vision.

The streamer-control station incorporates aHitec Cyberbase chair—an ergonomically pro-portioned chair with joy-stick control grips tocommand streamer deployment (right). From herethe streamer operator has the ability to controlall in-sea equipment, streamer reels, conveyancesystems and Monowing deflectors from one cen-tral point. Streamers can be deployed and recov-ered, controlled and tested.

The joy-stick user interface and multifunc-tional displays provide the means to interact withthe massive spread of the Geco Eagle (below).This display from the TRINAV application, theonboard navigation processing software, showsouter streamers fully deployed and a few innerstreamers unreeling. The joy-stick controls per-mit prompt response for quick adjustments tostreamer position.

Creation of the streamer-control stationmeant that for the first time, rather than beingexposed to the elements, the streamer operatorcould work in the comfort of a heated or air-con-ditioned room, making work safer and more effi-cient. The members of the crew were polled fortheir feedback on the new design features, and

indicated that they wouldn’t want to go back toreeling streamers the old-fashioned way, withoutthe control room.

Overall, the new back-deck design generatedan enthusiastic response from the crew. Theyfind the work safer, more comfortable and moreefficient. According to Mick Richardson, vessel

manager, the efficiency gained in easier andfaster operations produces measurable savings.Time saved changing out used streamer sections,deploying and recovering tail-buoys and avoidingequipment tangles during streamer maintenanceby smoothly controlling streamers, sums to 16hours—the equivalent of $110,000—per month.

> Concept for a TRINAV display from the streamer-control station. Streamer spools (left) can be monitored as streamers are deployed. The streamer-spreaddisplay (right) shows the vessel in the center of the screen and the full streamer spread towed behind. Some of the streamers in the center of the spreadare not fully deployed. Tail-buoys are identified with individual colors.

> Streamer controller driving winches with joy-stick controls.

Up FrontThe instrument room also required modificationto improve acquisition and onboard processingefficiency. The instrument room is where geo-physicists monitor and quality-control data acqui-sition, navigators plan and monitor the vessel’sprogress and observers watch operations. Inaddition to these standard operations, the GecoEagle supports on-line onboard data processingactivity. In the instrument room, many activitiesare performed concurrently, and clear communi-cations are required for rapid decision-making.

The Industrial Design group had already pro-duced a design of vessel instrument rooms forthe Geco Gem-series of vessels, launched in themid 1990s. The Geco Eagle benefitted from theexperience of that exercise and adopted innova-tions tailored to her greater capacity.

In the earlier project, the problem-identifica-tion phase turned up areas for improvement. Eachinstrument room visited was a one-of-a-kindunstructured conglomeration of computers, moni-tors, instrument panels and controls (left).Equipment was not ergonomically positioned,communication between work posts was some-times possible only by telephone, equipment was

56 Oilfield Review

> A vessel instrument room before redesign. Little thought was given to the arrangement of computers,monitors, instrument panels and controls.

Videomonitors

Phoneintercom

Navigation monitor

Gyrorepeat

Datastorage

Echoprinter

Gravityprinter

MagnetometerprinterScreen dump

printer(b&w)Nessie

monitorSource-controlmonitorVisualdisplay

OYOplotter(hard)

Screendumpprinter(color)

Statusprinter

Secondaryview

Tertiaryview

Sunplotter

LoggingPC

Secondary

view

Tertiary

view

Prim

ary

view

Primary

view

Equipment racks

Recording

Processing

Seismic

Reach limit

Visual limit

Reach

limit

Visua

l limi

t

Operational Analysis: Navigation Monitoring

Acousticcompassmonitor

3Dmonitor

Sun Sun

FaxAn operational analysis diagram supporting anobjective approach to instrument room redesign.Ergonomic component positioning is based onusage, reach and field of vision. The position ofthe user is the center of the circle, with distanceincreasing outward. In this example analyzingnavigation monitoring, the user requires a Sunworkstation within reach and primary (head-on)view. Video monitors can be beyond reach,within secondary view. Seismic acquisition andprocessing monitors and printers can be evenfarther from central reach and view.

>

Autumn 1999 57

needlessly duplicated, and the working environ-ment was cramped, uncomfortable and noisy. To avisitor’s eye, it lacked professionalism and fore-thought. A visiting client might question the valueof entrusting a multimillion-dollar proprietary sur-vey to workers in such surroundings.

Previous instrument room layouts developedin an evolutionary manner, referring back towhat had been done before and using personalopinion to decide what might be improved.Modifications to room setups had been done bytrial and error, experimenting with seating andequipment placement.

The new design approached the project froman analytical standpoint, from a basis of studiedresearch and fact rather than opinion. For eachwork station, an operational analysis was under-taken that documented each operator’s equipmentand assigned it a level in a positioning hierarchy(previous page, bottom). Levels were based on fre-quency of use, importance in routine and emer-gency operations, and relation to the user’s primaryand secondary fields of vision, physical reach andcommunications with other work stations.

The preferred new design would make possi-ble, for the first time, eye contact and verbalcommunication between crew members in twokey roles—on-line navigation and on-line seis-mic acquisition. Eye contact is particularly impor-tant in times of high activity or stress; with eyecontact it is easy to judge the level of anxiety orcalm in a coworker, so crucial situations can behandled more efficiently. In theory, the newarrangement seemed good, but such a radicaldesign required further evaluation before com-mitting to construction.

A full-size mock-up was built, and a numberof vessel crews participated in an evaluation pro-gram (above). This brought up-to-date field expe-rience to the evaluation, encouraged crews tosupport the project and provided the design teamwith an opportunity to review new ideas. Theconcept was fine-tuned and construction wasundertaken with the confidence that the designwas right the first time. Operator comfort wasconsidered; high-quality furniture and chairswere specified and careful attention was given tolighting levels (left). A double-glazed wall sepa-rated work stations from computer systems tominimize noise levels. This had the added bene-fit of allowing separate air-conditioning systemsfor computers and operators—a problem identi-fied on previous vessels where temperatures hadto be kept uncomfortably low to maximize com-puter reliability.

> New instrument room pioneered on the Geco Gem-series vessels. Instrument positions and workenvironment are optimized for user comfort and productivity.

> Full-size, whiteboard instrument room model for crew evaluation.

58 Oilfield Review

The first vessel with the new instrument roomdesign was the Geco Emerald and all subsequentGem-series vessels repeated the same design.

For the Geco Eagle, the same general planwas followed, with the addition of more computerworkstations for onboard processing, conferencerooms and a dedicated office for clients (top).

The design added storage space for back-up com-puters and equipment, so that spares are kept ina controlled, accessible environment. A separateroom contains network and telecommunicationcables. In a further improvement, all seats in theinstrument room were positioned to face forwardfor increased comfort in rough seas.

In their feedback, the crew commends the newdesign, especially the good visual communicationand the large amount of workspace (left). Placingthe observers at the same desk as the“Trilogist”—the operator of the SchlumbergerTRILOGY quality-control system for sources andstreamers—greatly facilitates teamwork. Initialskepticism toward the instrument room layout,specifically regarding the forward-facing aspect ofall work areas, has been overcome. The ergonomicdesign has improved communication between thenavigation, onboard processing and acquisitiondepartments and proved to be a winner. The over-all improvement in operational efficiency quicklypaid for the time and effort that went into theredesign project, recouping costs by early in thesecond month of operation.

> The fully operational Geco Eagle instrument room.

> CAD model of Geco Eagle instrument room,with more workstations and workspace. Thereare also extra rooms for meetings, clients andcomputer storage.

Autumn 1999 59

Real (Virtual) TrainingSchlumberger places a strong emphasis on train-ing for operations personnel. A modular trainingprogram gives vessel crews high exposure to awide range of on-line, classroom, practical andself-tutorial instruction. However, the unprece-dented levels of new technology carried onboardthe Geco Eagle led the project team to seek addi-tional training capability prior to the vessel’slaunch. With much of the new technology man-aged from the streamer-control station, trainingin its use was critical to a smooth start-up for thenew vessel.

At the Schlumberger training center in Asker,Norway, a training simulator was constructed tofamiliarize crews with the new technology beforethey even set foot on the vessel. A projectionsystem and 150° curved display screen are usedto create a virtual version of the Geco Eagle backdeck (right).

The CAD simulations devised for theredesign study form the foundations of the train-ing simulator. The system is similar in principleto a flight simulator, replicating the onboardenvironment including the Cyberbase chair, userinterfaces, alarm panels and the closed-circuittelevision system. The renditions are realisticenough to include crew members working on theback deck (right).

Crews were first trained on back-deck proce-dures and best practices during normal streamerdeployment and recovery operations. The simula-tor also provides experience in less common situ-ations. For example, the simulator can test atrainee’s reactions to conditions that stray outsidethe parameters of safe towing. Turning the vessel,other ships crossing the streamers, drilling rigs,fishing nets, shallow water, changes in wind orcurrents and man overboard can all be simulated.Equipment problems such as malfunctioningstreamer depth control, Monowing angle control,global positioning systems in the tail-buoys andwinch controls can be reproduced for training pur-poses. Using the full suite of cases available inthe simulator, the crew can be trained in allaspects of survey management. The training ses-sions are recorded and can be played back toreview and improve how situations are handled.

> Training simulator screen and streamer-control center. The control monitors and Cyberbase chairin the foreground are real, while the back-deck floor, streamers, crew, sea and sky are simulatedprojections in the background.

> Preparing the Asker, Norway training center screen for simulator projection.

Before Geco Eagle was launched, the simula-tor gave her future crew experience that couldnot have been found on any existing seismic ves-sel. It enhanced operational awareness andallowed them to build controls around clearlyidentified high-risk operations, reducing the pos-sibility of error or accident.

After attending more than 40 training courses,the Geco Eagle crew was ready to take her towork offshore Brazil. The vessel had a smoothstart-up and achieved high levels of daily produc-

tion with 10 streamers right from the beginning.There were no operational problems with any ofthe equipment covered by the training programs.

The training simulator will continue to play animportant role, not just for the Geco Eagle butalso for other vessels that will be deploying largespreads in challenging operational environments.The software element is fully portable, enablingsimulation to be used on board vessels to givefurther training as necessary (above). Since thetowed equipment is common to the wholeSchlumberger fleet, there are also plans for

crews of other vessels to take operational semi-nars using the simulator. In the meantime, thesimulator is being used to develop and build thestreamer configuration and train the crew of theGeco Eagle for the first 12-streamer job, scheduledfor Autumn 1999. The combination of the latesttechnology and the added safety, comfort andefficiency built into the new design ensures thatthe Geco Eagle will be influential in shaping thefuture of seismic acquisition methods. —LS

60 Oilfield Review

The portable simulation model of the back deck in demonstration at the 1998 SEG meeting. Pictured are Mick Richardson, Geco Eaglevessel manager (left), Tor Eilertsen,simulation project manager (center)and Arild Viddal, marine technical manager (right).

>