the future of reservoir management

The Futureof ReservoirManagement

Real-time reservoir management is an emergingconcept in the exploration and production (E&P)industry. However, there are numerous definitions ofreal-time reservoir management, which reflects thefact that there have been many attempts to implementit. In this article, Fikri Kuchuk, Andrew Carnegie, andMahmut Sengul define the scope and processes ofreal-time reservoir management and explore itssignificance to the various disciplines within E&P.

Middle East & Asia Reservoir Review

Smaller teams—biggerresponsibilitiesReorganization during the 1980s and1990s reduced employee numbers inmany oil and gas companies. However,oil and gas consumption has grown byabout 2% per year during the last twodecades, but oilfield employment hasremained almost constant, or has evendecreased slightly during this time.Downsizing, combined with theretirement of those in senior positions,means that today’s upstream industryis lean in terms of an experienced,professional workforce. However,some companies have overcome thischallenge by using new technologiesthat allow them to find and producehydrocarbons at lower cost and withfewer people. Real-time reservoirmanagement has the potential to takethis process a stage further and enablethe industry to maximize efficiencyand increase revenues.

Any system that delivers true, real-time reservoir management and control must combine all therelevant disciplines, encouragegreater cooperation, and increase the efficiency of data utilization andsharing. Continuing improvements in computer processing power andgreater connectivity between remote locations are critical to thedevelopment of modern reservoir-management processes.

Reservoir management is a complexdecision-making process that isinfluenced by technical, logistical,health, safety, environmental, andeconomic issues (Figure 4.2). Planningis probably the most important aspectof reservoir management. Successfulplanning defines the problem anddevelops possible solutions, but it alsoinvolves setting the objectives andlimits, such as production targets andbudgets, that will influence the project.

The first priority for geoscientistsand engineers is to identify andevaluate the factors that control theflow of oil, gas, and water in the porousand, sometimes, fractured and faultedrocks that comprise their reservoirs.This involves understanding thephysical controls and the combinedeffects of capillarity, gravity, and rockheterogeneity, as well as the chemicalreactions and phase changes associatedwith multiphase flow conditions. The

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technical challenges include modelingpore-scale processes, the complexheterogeneities encountered in somereservoirs, and macroscopic flowinstabilities; and conducting large-scalemodeling of enhanced oil recovery.

Once the reservoir has beenreasonably characterized andmodeled, the asset team can begin topredict how possible modifications toproduction or field-developmentstrategies would affect hydrocarbonproduction rates and recovery. Thesepredictions can then be tested againstlogistical and economic constraints.

The team must also determine thesafe design limits for pipelines andother production facilities. This is an important task, particularly whenplanning how to deal with health andsafety hazards, or when designingexpensive one-off facilities such asthose associated with deepwaterdevelopments. The design ofproduction facilities involves beingable to confidently predict and thenhandle unwanted compounds such as asphaltenes, waxes, and hydrogensulfide. More importantly, the designprocess must establish how to handleever increasing levels of waterproduction. Production scenarios areobtained from the reservoir model,which, in turn, must be based upon athorough and accurate understandingof the fluid compositions and the rock chemistry.

Better models—better results

Modern reservoir models provide thefundamental framework for reservoirmanagement and a flexible logisticaltool. But, establishing static (rock-related) and dynamic (flow-related)reservoir properties (Figure 4.3) isonly one stage in a process designed to maximize production and recoveryrates. Once the team of geoscientistshas established the static reservoirdescription, the discipline of reservoirengineering usually assumes the leadresponsibility for the next stage ofmodeling (but it must be noted that all the geoscientific disciplines remainpart of the team). The role of thereservoir engineer involves monitoringchanges in key physical reservoirparameters, assessing how proposeddevelopment and production strategieswill affect the field, and implementing

Figure 4.3: The first step in maximizingproduction and recovery rates is establishingthe static and dynamic reservoir properties.

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Imagine an oil field where a fewmultiskilled geoscientists and

engineers control every aspect ofdevelopment and production from acontrol room or iCenter* immersivevisualization systems. When presentedwith a continuous stream of reservoir,well facilities, and pipeline information,these geoscientists and engineers haveautomated systems to analyze the data,others to help them formulate effectiveresponses to changing surface andsubsurface conditions, and the meansto implement these responses in realtime. The emerging technology allowsthem to respond quickly to economicfactors and increase or reduceproduction rates from individual wellsto reflect changing quotas or marketconditions. And they are doing all of this from offices hundreds orthousands of kilometers from thereservoir (Figure 4.1). A few years ago this might have been just a dream, but recent technological advances and closer cooperation between oilfielddisciplines are near to making it areality. Field optimization will drive thefuture development of oil fields, and

this article focuses on a key part of thisprocess—reservoir optimization.

Effective real-time reservoirmanagement will require developmentin at least five key areas:■ downhole monitoring and

acquisition systems ■ software to manage large and

continuous streams of data. Thiswill help asset teams to identifyvalue-adding opportunities and to optimize asset performance.

■ software that integrates the datainto the subsurface model, so that asset teams can identifydiscrepancies in the model at anearly stage. This opens the way for real-time history-matching.

■ methods for downhole, mostlyrigless, intervention. These mayrequire devices that are preinstalledinto the production system of thefield such as intelligent completions,or advanced and highly compactconveyance systems such as tractors.

■ control systems that allow thereservoir to be more closely linked,perhaps eventually managed, by thedictates of the refinery and other

facilities that process the fluids beingproduced from the reservoir. The development of these

automated systems represents the firststep toward a transformation of theupstream business and the emergenceof autoengineered smart oil fields. Theindustry is beginning to make full andeffective use of the World Wide Weband associated intranets to accessdata, applications, and expertise,wherever they are available throughoutthe world. Once they have made theconnections, each oil company mustfocus these capabilities on the keyopportunities within its asset portfolio.Real-time reservoir management hasalready been implemented, forexample, in some modern deepwaterfields that contain subsea wellheadsproducing from multizone reservoirs,and in which many problems, such as a zone watering out, cannot beeconomically solved by a simpledownhole intervention.

Figure 4.2: Technical, logistical, and economic issues all influence the long, complex decision-making process that is reservoir management.

OilWater

Permanent downhole monitoringSurface monitoring

Prod

uctio

n

Time

Prod

uctio

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Production stops for logging, testing, and

remediation

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Shut down water zone

Locate problem

Continuous oilproduction

Figure 4.1: Asset managers need to respond quickly to changing reservoir or economic conditions so that they can increase or reduce production ratesfrom individual wells to meet their technical and business objectives.

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Figure 4.5: Projecting 3D images of geological structures onto an immersive, panoramic screen has changed the way reservoirs are assessed anddeveloped—ideas can be exchanged, hypotheses tested, and problems solved on a team basis.

continuous data streams to surfacecontrol centers using dedicated fiber-optic links. When linked to advancedcompletion technology, downholesensors can help to optimize thedrainage of multiple reservoir targetsby measuring flow rates and pressureduring production, and can also helpin modifying completion parametersin an effort to maximize recovery,optimize production, and minimizeunwanted gas and water production.

The rise of visualizationBefore the mid 1980s, interest innumerical reservoir modeling waslimited. Engineering teams usednumerical simulation to create models that estimated and predictedreservoir behavior in a simplistic way.This generally involved setting up a4D numerical simulation model andadjusting its parameters by history-matching production pressure andwater-cut data that are normally 2D(1D spatially and 1D temporally). This incompatibility created a longand arduous history-matching processthat was carried out by specialists and often resulted in unrealisticparameter distributions andproduction predictions. A major

problem with this was one ofnonuniqueness—the reservoir modelcreated through history-matchingcould often be one of several plausiblemodels, all of which could satisfy thehistorical performance of the field in the simulator. This presented amajor problem—understanding theuncertainties associated with history-matched models.

Unfortunately, this meant thatpredictions about reservoir behaviorcould be extremely inaccurate. Thisapproach also encouraged thoseresponsible for assets to downgradethe value of the measurements madeat the reservoir. For example, someoperators would question the value ofacquiring core permeabilities becausethese would be changed drasticallyduring the history-matching process.

During the mid 1980s, the conceptof reservoir description was introducedto provide a realistic framework for history-matching. Although field measurements were used toconstrain the simulations, and soreduce the problems associated withnonuniqueness, they did not provide aconsistent methodology or any of thebenefits of modern techniques such as3D reservoir modeling.

A better view

The introduction of large collaborativeand immersive visualization systemshas had a major impact on theupstream industry. Visualization was avital part of E&P activities long beforecomputers became commonplace, butthen it was carried out on paper, withvisualization being achieved using barcharts, graphs, well logs, and seismicsections. Once computer technologyhad been introduced, there was a rapid increase in the use and value ofvisualization. However, it took time todevelop visualization tools (charts,graphs, etc.) for computer applications.At first, everything remained on paperor was presented in a paper-like formaton small computer screens. Over thepast three to five years, computer-generated displays have undergonedramatic improvements in resolution,physical size, and interactivity,particularly since the introduction of3D seismic data. And the upstreamsector is benefiting as a result.

The emergence of virtual-realitysystems has taken the trend evenfurther. Being able to interpret hugevolumes of seismic, drilling, andreservoir data, and then project theresulting 3D images of geologicalstructures onto an immersive,


the necessary changes to optimize fieldperformance. Until recently, thesesteps were conducted intermittentlyand the time between the initial datagathering and the implementation ofthe approved changes was generallymeasured in months.

The various disciplines involved inreservoir characterization were basedin different departments; there waslittle interaction between them; andthey often had slightly differentbusiness objectives. For example,geologists created maps of the assetand passed them to the reservoirdepartment. This was effectively aone-way transfer; the geologists werenever informed of the drastic changesthat reservoir engineers might maketo fit the map to the production data. The drilling department wasoften responsible for the testing of exploration wells, and drillingpriorities or production issuesdetermined how well tests wereperformed and their duration. Thismeant that tests were conducted withlittle consideration of the wider issuesof reservoir characterization such asfault boundaries and aquifers.

The delays and lost productionassociated with these methods led to the emergence of an asset-teamapproach, where specialists fromdifferent departments work in closeassociation on a particular field asset.

Asset teams have investigated newtechnology and new ways to useexisting technology. This has greatlyreduced the time between datagathering and intervention (Figure 4.4). The world’s leading oil companies now organize theirexperts into multidisciplinary teams.Interaction between the variousdisciplines is well established but,until recently, this was generallyachieved without a formal frameworkfor data sharing.

Over the past decade, the industryhas focused its research anddevelopment efforts on the issuessurrounding the static aspects ofreservoir characterization. Theintroduction of 3D seismic surveyshas helped companies to makesignificant progress in 3D reservoirmodeling, but merging the static anddynamic features of a reservoir—toprovide the vital link between earthscience and production engineering—is not yet well established.

Measuring dynamic properties

The modern E&P industry combinestime-lapse surface and boreholeseismic monitoring, directionaldrilling, permanent downholemonitoring, advanced wellcompletions, fiber-optic sensortechnology, data management,

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Internet technology, and shared earthmodels to extract and share detailsabout the structure, fluid content, andproduction capacity of oil and gas fields.

Time-lapse seismic methods can beused to monitor injected fluid fronts;locate bypassed oil; map pressurecompartmentalization and pressurechanges; and establish the sealingproperties of faults. High-resolution,time-lapse seismic monitoring hasbeen conducted in the borehole, inboth vertical seismic profile and cross-well geometries. Multicomponentseismic receivers can be installed forlittle more cost than acoustic sensors.The additional information gainedfrom the shear wave-data obtainedcould help the reservoir engineer tomonitor pressure fronts, in-situ stress,and fracturing.

Similarly, newly emerging deepresistivity measurements, acquiredusing tools available fromSchlumberger and run on wirelineinto a wellbore, can now monitorwater fronts several hundreds ofmeters into the reservoir.

Downhole instrumentation andborehole technology have developedrapidly over the past few years.Downhole sensors can now measurekey reservoir variables such aspressure, temperature, and oilsaturation. When permanentlyinstalled, these sensors can deliver

Data gathering

Data processing

Data analysis

Intervention planning

InterventionTraditional

Time

Modern

Time

Figure 4.4: Continuous monitoring of key physical reservoir parameters and assessment of proposed development and production strategies reduce thetime between data gathering and intervention, and help to prevent the delays and lost production associated with conventional methods.

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necessarily provide a unique solution,but the level of uncertainty can bereduced by increasing the amountand range of information incorporatedinto the model and by verifying thatthe selected model is consistent withall the available data.

Reservoir characterization is acontinuous process that must beupdated as new information is gatheredfrom the asset. For simplicity, it may beconsidered to be divided into threemajor consecutive steps: 1. Generate data interpretations for

each technical discipline.2. Integrate these interpretations into a

model of the reservoir.3. History-match this model. Generally, the models in steps 2 and 3are grid based, i.e., the reservoir(structure, rock fabric, and fluids) isrepresented by a set of cells.

The models created as part of step 2are called geocellular models and donot generally have the capability tosimulate fluid flow. This takes place aspart of step 3—the geocellular modelsof step 2 are transformed into the flow

Figure 4.7: The DecisionPoint* personalized E&P Web workflow solution enhances collaboration and provides access to validated information usingproven Internet technology. This aids production of the accurate model of the reservoir system and prediction of the consequences of implementingpossible, alternative strategies that are required for reservoir management.

simulation models in step 3. The cellsin geocellular models are generally ata finer scale (i.e., smaller) than thosein the equivalent flow simulationmodel. Hence, a process known asupscaling is required to convert theproperties from geocellular modelsinto those in simulation models. Theprocess involves two consecutivesteps: generating data interpretationsfor each technical discipline andintegrating these interpretations intothe reservoir model.

Combining data

Asset team members may generatetheir own data interpretations, butthey usually use in-house experts,consultants, and/or service companies.The interpretation process may differdrastically from one company toanother and may depend on theimportance of the field. In any case,these data will typically include static data (geology, geophysics,geochemistry, and petrophysics) that correspond to a description of the

reservoir’s shape and structure, anddynamic data (fluids, geomechanics,tracers, production logs, well tests,and production) that relate toreservoir behavior.

Data interpretations use widelyvarying scales and resolutions (surfaceseismic interpretations are measuredin meters, while core samples aremeasured in millimeters) and revealdifferent aspects of the formation and the reservoir and its behavior.Geophysical data modeling, forexample, reveals acoustic impedancecontrasts, whereas pressure transientdata at different scales (from wirelineformation testing to conventionalbuildup testing) primarily identifymobility and storativity contrasts.Understanding the significance of suchdiverse information and measurementsrequires cooperation across the assetteam as well as the involvement ofmany other professionals.

Transferring data into the


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panoramic screen has changed theway reservoirs are assessed anddeveloped. The continued growth ofcomputing power has helped to turnthe concept of a shared earth modelinto reality. Now, many teams haveaccess to modern visualizationtechnology that helps them toexchange ideas, test hypotheses, andinvestigate different scenarios on ateam basis (Figure 4.5).

iCenter immersive visualizationsystems from Schlumberger offermini-theater-sized, curved screensand powerful image-handlingtechnologies. These systems presentthe subsurface environment in a waythat allows users to view, manipulate,walk, and even fly through reservoirsin their quest for solutions to drillingand production challenges. Usingthese systems, asset teams caninspect an entire field or just a smallcorner of it, thus allowing them toagree on the most efficient and cost-effective strategies for reservoirdevelopment. Schlumberger has anInside Reality* ‚ 3D visualizationiCenter system in all the major oil andgas provinces; the Abu Dhabi facilityopened in 2002.

Time-lapse monitoring

A 4D seismic monitoring projectinvolves repeating 3D seismic surveysfor a field, or its subsection, after agiven period. The results from thesesurveys help the asset team to monitorfluid movement over time. The imagesproduced by 4D seismic monitoringhelp to identify fluid flow and revealspatial and temporal variations in fluidsaturation and possible pressure andtemperature changes. The mostimportant applications includemapping bypassed oil; monitoringinjected reservoir fluids such as water,steam, gas, and carbon dioxide;studying the effect that productionand/or injection has upon pressurethroughout the field; estimating thefluid-flow variations related to pressurecompartmentalization; and assessingthe hydraulic properties of faults andfractures (Figure 4.6).

Monitoring fluid flow with 4Dseismic techniques requires closecollaboration between the disciplinesof structural and stratigraphicgeology, fluid-flow simulation, rockphysics, and seismology. Seismicreservoir monitoring can significantlyhelp to understand recovery in newand existing fields by helping theasset team to monitor and predict the

1985

0 1HC indicator

1996 Changes

No change Significantchange

Figure 4.6: 4D seismic images help to identify heterogeneous fluid flow and reveal both spatial and temporal variations in fluid saturation, pressure, andtemperature. They are very useful for mapping bypassed oil; monitoring injected reservoir fluids; estimating fluid-flow heterogeneity related to pressurecompartmentalization; and assessing the hydraulic properties of faults and fractures.

interwell positions and the movementof reservoir fluids. Fluid monitoringhelps the team to locate bypassed oil,avoid premature water breakthrough,optimize infill well locations, andevaluate enhanced-oil-recovery pilotsbefore full-field implementation.

Modeling for management

Reservoir management is based on a series of decisions that enables oiland gas companies to meet theirtechnical and business objectives(Figure 4.7). The process requires an accurate model of the reservoirsystem and the ability to predict the consequences of implementingpossible, alternative strategies.

Reservoir characterization, a vitalpart of the model creation process,involves generating an editable,mathematical subsurface model. Themodel is calibrated to reproduce thepast, observed dynamic performanceof the reservoir, and is expected to be able to predict future performance.Since the objective in makingpredictions is to optimize production,it may be necessary to take surfaceprocessing facilities into account. The calibration process does not

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Gamma ray

Cementbond

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Casing resistivity

(ohm-m)

CHFR resistivity

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AIT 90

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(p.u.)0.45 -0.15

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Openhole neutron porosity

(p.u.)0.45 -0.15

DSI delta-t compressional

(µs/m)300 100

Cased hole neuton porosity

(p.u.)0.45 -0.15

Figure 4.11: Modern logging can deliver precise information on fluid content and movement, and the latest sampling methods can retrieve formation fluidsamples from behind casing.

to evaluate production behavior add a further complication to reservoirmanagement. The grids applied innumerical simulators are coarser than those in the reservoir model.Consequently, the asset team mustupscale the model data before it canexamine model behavior (Figure 4.9).Though essential, the upscalingprocess introduces errors that affectmodel verification.

Measure to manageSurface monitoring of wells has been routine since the oil and gasindustries were in their infancy. Forcommercial and material balancereasons, oil companies have alwaysneeded to know the volumes ofproduced fluids. Through the earlydecades of the twentieth century,engineers and geoscientists came to

gathering could only be conducted indiscrete testing and logging periods.Unless performed in a well that wasdedicated to reservoir monitoring (an observation well) this processinterrupted production, wasconsidered expensive, and wasconducted at infrequent intervals with months or years between eachassessment. Moreover, in someregions, wells were only logged whenthe operator wanted to diagnoseproduction problems or look atinjection profiles.

realize how complex the subsurfaceenvironment could be and began toextract information about reservoirrocks and fluids in situ.

Downhole data gathering startedwith electrical coring to characterizeproducing formations (Figure 4.10).Service companies emerged toconduct these specialized tasks and,over the years, have improved andextended their technology, thusproviding the operating companieswith better information about theirvital hydrocarbon assets (Figure 4.11).For example, the CHDT* Cased HoleDynamics Tester drills through casingand cement, and into the formation;measures reservoir pressure and fluidresistivity; collects fluid samples; andplugs the hole with a bidirectional seal that can withstand pressures ofup to 10,000 psi.

Until relatively recently, data


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cellular reservoir modelThe asset team can incorporate directand interpreted data into the reservoirmodel using deterministic or stochasticmethods. A stochastic approach allowsthe team to integrate knowledge fromdifferent data interpretations (aprocess known as conditioning) whiletaking into account the different levelsof reliability (uncertainty) associatedwith each interpretation. Stochasticmodeling provides multiple,equiprobable 3D realizations of thereservoir model that can then be usedto explore, and perhaps even quantify,the effects of the uncertainty aboutvarious aspects of the reservoircharacterization on the predictedperformance of the field (Figure 4.8).

Stochastic techniques are mostuseful where data are sparse, typicallyduring the early stages of fielddevelopment, and/or when significantheterogeneities such as thin, high-permeability streaks are at a smallerscale than those of the availablemeasurements. Deterministictechniques are more appropriate forfields with high data density—thosewith lots of wells and years ofproduction information (thoughstochastic modeling is still useful forevaluating the level of uncertainty inan established reservoir model).

Validation, history-matching,flow simulationOnce the team has completed itsreservoir description, it must ensureconsistency with all the availableinformation and data interpretations.This process is known as validation.The model must honor all of the datathat were used in the characterizationprocess—seismic, log, and well- andproduction-test data if available. If the reservoir model is consistent with the available information and the data interpretations, the correlationbetween the field data and the modelresponses is normally good and,therefore, relatively simple to improveby adjusting the reservoir modelparameters within the limits imposedby available knowledge. This ishistory-matching.

The numerical simulators used

Figure 4.9: Model data must be upscaledbefore an asset team can examine modelbehavior, as the grids applied in numericalsimulators are coarser than those used in thereservoir model.

Figure 4.10: Electrical coring to characterizeproducing formations was the start ofdownhole operations.

? ?

Figure 4.8: Stochastic modeling providesmultiple, equiprobable 3D realizations of thereservoir model and quantifies theassociated uncertainties. In this simplifiedexample, available well data allow severalpossible interpretations or realizations ofinterwell structure.

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Reliable? You can depend on itWhen a permanently installeddownhole gauge stops working,reservoir engineers lose their windowon the reservoir. It is vital, therefore,that gauges remain operationalthroughout their planned working life.Over the past decade, Schlumbergerhas focused on improvements inengineering and testing processes,system design, risk analysis, training,and installation procedures toenhance the reliability of itspermanent monitoring systems.

The development of a permanentgauge system follows a sequence of engineering operations, withdependability being paramount duringeach stage. The engineering sequencebegins with a careful description of the technical concept that sets outpossible applications for the gauge.This serves as a framework and definesthe role of each component and theenvironmental conditions that it willencounter during its expected lifetime.

System components are generallytested and qualified to withstand theexpected conditions. Accelerateddestructive tests subject thecomponents to conditions that aremore extreme than those expected in service, such as greater mechanicalshocks and vibrations, and higher-than-downhole temperatures andpressures. This type of testing helpsto determine the causes and modes of failure. Long-term testing of thesystem enables engineers to validatereliability models and quantifymeasurement stability. Feedback fromfield engineers is a vital input to alllaboratory-testing methods.

Innovation in actionTechnical innovation has been the keyto recent improvements in reservoirmanagement. The Schlumbergerportfolio of products geared toachieving optimum run life andreservoir production has expandeddramatically in recent years; forexample, WellWatcher*, FloWatcher,and PumpWatcher* monitoringsystems are operating successfully insome of the world’s most demandingreservoirs (Figure 4.16).

Saturation monitoring is a crucialpart of reservoir management. In

Figure 4.15:Engineers candetermine flow ratesfrom individual wellintervals by closingall the other intervalsand measuring flowat the surface usingdownhole electricallyor hydraulicallyactuated controlvalves.

Figure 4.14: Downhole production logging using thePS Platform services platform in combination withPhaseTester multiphase well testing equipment at thesurface offers multiphase flow characterization andproduction testing.


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1975 First pressure and temperaturetransmitter on a single wireline cable

1978 First subsea installations in theNorth Sea and West Africa

1983 First subsea installation with acoustic data transmission to surface

1986 Fully welded,metal-tubing-encasedpermanent downhole cable

1990 Fully supported copper conductor in permanent downhole cable

1993 New generation of quartz and sapphire crystal permanent gauges

1994 Permanent quartz gauge performance substantiated by gauge accreditation program at BP. Start of long-term laboratory testing

1986 Introductionof quartz crystalpermanent pressure gauges in subsea wells

1994 FloWatcher* integrated permanent production monitor installed for mass flow-rate measurement

1970

s19

80s

1990

s1973 First permanent downhole gaugeinstallation in West Africa using wireline logging cable and equipment

Figure 4.12: The first permanent downholegauges were installed in the 1970s.

A permanent solution

The first permanent downhole gaugeswere installed during the 1970s(Figure 4.12). These early systemswere often hindered by poor reliability,but the benefits of continuousmonitoring encouraged the pioneers to overcome these problems.

Since the early 1990s, permanentreservoir-monitoring systems (mainlypressure gauges) have been installed in a number of reservoirs around theworld. The principal aims of permanentmonitoring are to improve assetmanagement and optimize productionthrough the acquisition, management,and interpretation of a continuousstream of real-time data. The keyrequirements for a successful downholemonitoring system are good reliabilityand durability, and the design flexibilityto meet the operator’s requirements.

Downhole monitoring sensors aredeployed in extremely hostile anddemanding environments. Thechallenges include high temperatureand pressure, and harsh chemical andphysical conditions (Figure 4.13).Consequently, reliable transducertechnology is essential. Conventionalelectronic gauge technology has beendeployed successfully in a range ofdownhole monitoring applications,predominantly in wireline-retrievablesystems, but also, more recently, forpermanent reservoir monitoring.Unfortunately, electronic systemshave inherent limitations that renderdownhole applications particularlychallenging, for example, electronic

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Shearwater Thomasville

Eugene Island

FranklinElgin

TrecatePuffin

Malossa

Villa/TrecateErskine

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Figure 4.13: Downhole monitoring sensors have to meet challenges that include extremes oftemperature and pressure, and harsh chemical conditions.

systems are less reliable at hightemperatures.

Today, fiber-optic technology isbecoming an important part of thereservoir-monitoring toolbox. Theadvanced sensor systems developedby companies such as Sensa haveapplications across the oil and gasindustries where, through downholemonitoring, they are helping tochange the way reservoirs aredeveloped and managed.

Downhole fluid measurements

Flow-rate and multiphase meters fordownhole use will be vital elements of the real-time reservoir-managementstrategy, but are still in the earlystages of development.

Useful information on downhole flow rates and fluid compositions can be inferred from downholetemperature and pressuremeasurements in combination withsurface measurements. For example,downhole production logging using the PS Platform* new-generationproduction services platform incombination with PhaseTester*multiphase well testing equipment atthe surface has proved effective formultiphase flow characterization and production testing (Figure 4.14).Downhole electrically or hydraulicallyactuated control valves allow engineersto determine flow rates from individualwell intervals by closing all otherintervals and measuring flow at thesurface (Figure 4.15).

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Producer (fractured)

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Figure 4.18: Electromagnetic imagingmethods (top) are emerging as key tools forreservoir monitoring. The technology hasproven its potential value in a number of pilotstudies such as the Lost Hills survey, inCalifornia, USA, (middle) where it has beenused to track changing resistivity values forextended periods (bottom).

for more than a decade to developdeep-reading, electromagneticborehole sensors that can produce 3Dresistivity images on a reservoir scale.At present, there are two options,both are conveyed using conventionalelectric wireline and can becustomized to suit specificrequirements. The first systeminvestigates large rock volumes arounda single wellbore. This single-welllogging tool can investigate rock fortens of meters around the borehole.

The second system images formationbetween adjacent wells. The verticalresolution of this cross-well system isapproximately 5% of the well spacing.The volume of rock measured is muchgreater than can be achieved withconventional wireline technology. Cross-well electromagnetic technologycan provide an interwell resistivitydistribution and so map watersaturation and reservoir structurebetween wells. By mapping resistivity,engineers can identify faults andfractures; locate bypassed hydrocarbonzones; and monitor water, steam, andpolymer flooding operations. Thiswealth of subsurface information allowsasset teams to make better decisionsabout their reservoirs.

The cross-well technique has beenused for more than five years to imagethermal oil-recovery operations(steamfloods) and, more recently, for reservoir waterflood monitoring.The resistivity contrast between thezones flooded with saline water andthe hydrocarbon-filled pay zonesusually provides an excellentelectromagnetic signal.


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Hourly average fiscal rateFlow rate derived from venturi

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Figure 4.16: Because Strathspey field wells in the North Sea are produced commingled, productionallocation was a key reservoir-management issue. Two high-precision PressureWatch* quartz gaugeswere installed across a venturi at 9000 ft to monitor pressure, temperature, and flow rate. A third PressureWatch gauge was installed at 8000 ft to provide water holdup data. Measurementsfrom all three gauges were transmitted in real time through the subsea control module.

the past, engineers relied on pulsedneutron methods—such as thatimplemented with the RST* ReservoirSaturation Tool—to assess fluid type(oil, water, or gas) and its associatedsaturation through casing. Therelatively shallow readings achievedwith the RST tool mean that near-wellbore effects such as poor cementand residual acid from stimulationjobs may severely affect the reading.However, the CHFR* Cased HoleFormation Resistivity tool readsdeeper into the formation and is little affected by the near-wellboreenvironment. Its measurements areoften much closer to those obtainedfrom openhole logging (Figure 4.17).

Despite increasing interest in thenew gauges, very few of the world’s oil and gas wells have continuousdownhole monitoring. Many wells havebeen allowed to produce for yearswithout checking how production has modified the reservoir around thewell—this is all right while the well is producing at a reasonable rate with a low water cut. But it can bevery difficult to establish the causeand even harder to select the mostappropriate remedial action when aproblem occurs.

The few wells that do havemonitoring systems generate a wealthof data. Changing pressure–volume–temperature conditions and flow ratescan be measured every few hours,minutes, or seconds, depending on the needs of the reservoirmanagement. Special softwarepackages have been developed to manage the flow of data fromdownhole gauges and to pass thesedata around the world using secureInternet and intranet connections.Once the data have been distributed,the asset team can get to work on thecritical decision-making process.

Cross-well electromagnetictechnologyCross-well electromagnetictechnology is an emerging methodthat promises to revolutionize theindustry’s understanding of what goes on between wells (Figure 4.18).Scientists and engineers atElectromagnetic Instruments Inc., a Schlumberger company based inCalifornia, USA, have been working

Figure 4.17: The data from the CHFR tool are much closer to those obtained from openhole logging, asthe tool reads deeper into the formation and is unaffected by mud filtrate.

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because of its expense and technicaldifficulty. New data sets such as welllogs are not easily incorporated intothe knowledge base. Consequently,the reservoir model is updatedinfrequently, and an asset team has to make decisions based on old orinadequate information. Opportunitiesto accelerate or increase productionand continuously improve operationalefficiency are, therefore, either lost or delayed, with consequent loss ofincome and value.

Efficient oil and gas production and recovery require continuousmonitoring, prediction, andreevaluation of interpreted behavior.The most sophisticated approach uses reservoir simulators that predictperformance by modeling thereservoir as a mesh of grid blocks.

Similarly, performance monitoringuses production logging of wells toidentify vertical variation in reservoirbehavior. Often, however, engineersuse more traditional analyticalinterpretation methods.

Engineers who are managinghydrocarbon recovery will map fluidfronts by comparing predicted

performance with simulated behavior.They do this by generating cross-sectional and areal views of thereservoir. This approach is highlyinterpretative because information is only obtained at the wells and its reliability is reduced by theheterogeneous and anisotropic natureof most formations. The ability tovisualize fluids between wells wouldclearly make it easier to locatebypassed hydrocarbon areas withinthe reservoir and reduce the risks indrilling and completing the wellsdesigned to drain them.

Bringing it all togetherThe drive toward real-time reservoirmanagement is a major opportunityfor the industry—a chance to changethe emphasis in oil and gas from arace to extract natural resources to a controlled process industry whereproduction can be monitored andoptimized. Oil companies that seizethis opportunity will be transformingone of their core competencies—assetmanagement. This, in turn, will helpthem generate additional growth,

Intervention—making the changesToday, production and reservoirengineers have an extensive range ofproduction and drilling technologies,all designed to maximize productionrates and boost recovery. Theseinclude gas-lift methods, electricalsubmersible pumps, horizontal drilling,and multilateral and intelligentcompletions. These solutions oftencreate a complicated network ofvertical, deviated, and horizontal wellsthat produce varying proportions ofoil, water, and gas from multiplereservoir zones (Figure 4.21).

Modern technology allows assetteams to control fluid flow in theborehole, for example, by shutting offsections of a well when a particularzone is watered out, and increasing or reducing production on demand. Infields where this technology is appliedin several wells, asset teams can setproduction rates and squeeze more oil and gas from the reservoir whilemaintaining low water cuts.

At present, monitoring of reservoirconditions is extremely sparse


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Waterflood monitoring in Oman

In 1998, Shell and Schlumbergerlaunched a joint project to prove the feasibility and value of dynamicreservoir-drainage imaging (DRDI).The aim was to develop time-lapsemonitoring of water saturation thatwould allow engineers to evaluatedrainage efficiency in reservoirs. The method selected was resistivitymonitoring. The development teamapplied this technique by cementing inan array of electrodes at reservoir levelto provide continuous measurement offormation resistivity.

In 1999, a field test was set up with Petroleum Development Omanto demonstrate the technology and toevaluate the value of data gathered atFahud field, Oman.

The DRDI installation for the testprogram was located at the center of a waterflooding cell between dualhorizontal injectors and producers(Figure 4.19). Two resistivity arrayswere deployed behind casing andacross the reservoir zone. Themonitoring period was estimated ataround 18 months. Readings weretaken at regular intervals from late1999 until early 2000 to indicate thewater-saturation variations at several

depths (Figure 4.20). These datashowed that the reservoir was beingunevenly swept and that waterbreakthrough times were reduced. Thefindings were confirmed by productiondata, which indicated a rising watercut, and by a logging campaign, whichindicated localized saturation increases.

Turning data into decisionsThe production process involves aseries of decisions on how to drain thereservoir efficiently. Efforts are usuallyfocused on cash flow and maximizingrevenues. Eventually, as the assetmatures, production priorities changeand, in the latter stages of field life,the team aims to maximize ultimaterecovery and minimize operatingexpenditure.

Many oil companies are changing the way they develop and managereservoirs. Identifying and implementingbest practice helps a company tooptimize initial field development so thatplateau production is maintained for aslong as possible and the challenge ofefficient production from a mature assetbase is met. This is not a particularlynew approach. For example, in someMiddle East countries, where thereservoirs are large and owned by the

national oil companies, the overridingreservoir-management priority hasalways been to implement best practiceto maximize the long-term recovery ofthe fields.

The value of real-time dataprovided by sensors installed within the well is becoming widelyrecognized. Downhole pressure,temperature, and flowmeters can be distributed within the well toprovide the required resolution.These distributed measurementsenable, for example, location ofspecific regions of high waterproduction in a horizontal well. Thisability to determine when and whereintervention is needed is of criticalimportance. In addition to directproduction monitoring, the tracking of distributed pressure, temperature,and multiphase flow measurementswithin a reservoir over time providesvaluable input to the reservoir model.By increasing the fidelity of reservoircharacterization, modern systemsenable more effective management of the hydrocarbon reservoir.

Observation, evaluation, andplanning are vital steps, but once the asset team has selected the beststrategy it must be implementedacross the field.

Figure 4.19: TheDRDI installation forthe test program waslocated at the centerof a waterfloodingcell between dualhorizontal injectorsand producers.

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Better performance through thelife of the field There are generally four key stages in the development of an oil field:1. exploration—reservoir structure

and contents are being investigated,but are not well defined

2. delineation—the size and extent ofthe reservoir is being assessed

3. development—the reservoir is fairlywell understood and production isrising toward peak level

4. maturity—the reservoir is wellunderstood and its contents arechanging as it is depleted.Every asset team faces several

fundamental challenges at each stageof field development: accelerating cashflow, achieving a greater return oninvestment, and extending the usefullife of the reservoir (Figure 4.23).

These objectives are the mainreasons for real-time reservoirmanagement. Real-time technologiescan be applied when the first well is drilled in a field. High-resolution 3D seismic surveys help to delineatethe detailed structure of the field and provide the baseline for futuremonitoring of fluid movement.

team will use advanced softwaresystems to integrate all the tasks of reservoir management in atransparent manner. This system will handle a continuous feed ofautomatically acquired data. Thereservoir team will then be able toanalyze these data, update thereservoir model, make predictions and recommendations, and implementthe recommendations, subject tomanagement approval.

Once the field has started toproduce oil and gas, real-timereservoir management helps tomaximize production, minimizeoperating expenditure, maximizerecovery, and extend the productivelife of the reservoir. These benefitsrely, to a large extent, on the assetteam’s ability to collect, process, andanalyze large volumes of data and,crucially, to translate these analysesinto corrective actions.

Systems built on dynamic databaseswill upgrade the reservoir modelcontinuously and provide the assetmanager with the best and latestinformation for optimizing theeconomic model that the companyhas chosen for the field. Sophisticatedreservoir simulators may be used on a daily basis and become an integralpart of the decision-making process.These advances will allow theindustry to improve its financialreturns and to respond faster andmore effectively to changing oilfieldand market conditions.

A major consequence of thesetrends will be that, in the future, asmall team could handle the entirereservoir-management process. The

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Figure 4.23: Business objectives and economic conditions change through the lifetime of an oil field. For modern developments, the aim isusually to start production quickly at a relatively low cost and then maintain high levels of oil production until it drops below economic levels.


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establish important businessadvantages, and position themselvesas technological leaders within the oiland gas sectors.

In establishing systems that willdeliver real-time management,operating companies will have to relyon tested technology to create newasset-management team structures.These new asset teams will helpcompanies reduce developmentcapital needs, generate operating costadvantages, and improve recoveryrates and yield.

Speed is of the essenceReal-time reservoir management willallow asset teams to identify quickly,and then capitalize on, opportunities to improve field productivity andefficiency. The new approach reducescycle time, which allows the asset teamto identify and rectify problems rapidlywith less disruption to production. This approach also promotes rapidassessment of data that will modify the reservoir model, thus enabling the earth scientists to reach a betterunderstanding of asset structure andreservoir engineers to make better-informed development decisions.

Achieving this will require theintegration and modification of diversetechnologies that give the asset teamimproved understanding of the day-by-day performance of the field and themeans to assimilate this informationand transform it into good businessdecisions. A cooperative approach,where operators work with keyresearch and development companies,vendors and, even, other oil companies,will help to ensure that the technologyis developed quickly and efficiently,and at a reasonable cost.

The result could be asset-management systems that link datafrom the reservoir, well, and facilitiesmonitoring and sensing devices directlyto the subsurface model (Figure 4.22).This approach would support assetteam decisions and help to capture and retain each individual’s knowledgeof the asset more effectively. Thechallenge is to integrate existing andemerging technologies and to modifywork processes to take full advantageof these opportunities. In some parts ofthe industry, these changes are alreadytaking place.

Figure 4.21: The extensive range of sophisticated production and drilling technologies designedto maximize production rates and boost recovery often create a complicated network of vertical,deviated, and horizontal wells, producing varying proportions of oil, water, and gas from multiplereservoir zones.

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Figure 4.22: Cooperation could result in asset-management systems that link data from thereservoir, well, and facilities monitoring and sensing devices directly to the subsurface model.

the future of reservoir management

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