the expanding scope of well testing -...

44 Oilfield Review

The Expanding Scope of Well Testing

Hani Aghar In Salah Gas (Joint venture of Sonatrach, BP and Statoil)Hassi-Messaoud, Algeria

Mark CarieNew Orleans, Louisiana, USA

Hani ElshahawiShell International Exploration and Production Houston, Texas, USA

Jaime Ricardo GomezJawaid SaeediClay YoungHouston, Texas

Bruno PinguetClamart, France

Keith SwainsonChevron CorporationHouston, Texas

Elie TaklaHassi-Messaoud, Algeria

Bertrand TheuvenyCambridge, England

For help in preparation of this article, thanks to Corey Auresand David Polson, Houston, Texas; and David Harrison, SugarLand, Texas.ArchiTest, CFA (Composition Fluid Analyzer), CHDT (CasedHole Dynamics Tester), CleanSep, CleanTest, CQG (CrystalQuartz Gauge), eFire, E-Z Tree, InterACT, IRIS (IntelligentRemote Implementation System), LFA (Live Fluid Analyzer for MDT tool), MDT (Modular Formation Dynamics Tester), MFE (Multiflow Evaluator tool), OFA (Optical Fluid Analyzer), Oilphase-DBR, PCT (Pressure Controlled Tester), PhaseTester,PIPESIM, PLT (Production Logging Tool), PowerFlow, PVT Express, PVT Pro, Quicksilver Probe, SenTREE and UNIGAGE are marks of Schlumberger. PhaseWatcher and Vxare joint marks of Schlumberger and Framo.

Well testing has come a long way since the first drillstem test was run in 1926. From

a simple composite packer and valve run on drillstring, the scope of well testing has

blossomed into a broad array of sophisticated downhole and surface technologies.

Every E&P company wants to know what type offluids its well will produce, what flow rates thewell will deliver, and how long production can be sustained. Given the right planning,technology and implementation, well testing canprovide many answers to these importantquestions. In one form or another, well testinghas been used to determine reservoir pressures,distance to boundaries, areal extent, fluidproperties, permeability, flow rates, drawdownpressures, formation heterogeneities, verticallayering, production capacity, formation damage,productivity index, completion efficiency and more.

By measuring in-situ reservoir conditions andfluids as they flow from the formation, the testingprocess gives E&P companies access to a varietyof dynamic and often unique measurements.Depending on the scale of a test, some param -eters are measured at multiple points along theflow path, allowing engineers to comparedownhole pressures, temperatures and flow ratesagainst surface measurements of the sameparameters (below). Through well testing,operators can extract reservoir fluid samples—both downhole and at the surface—to observechanges in fluid properties and compositionbetween the perforation and the wellhead. This

> Data measurement points. Depending on the scale of the test, a variety ofmeasurements may be obtained downhole, at the surface, and at differentpoints along the flowpath. Besides establishing important flow-rate andpressure relationships, the information derived from these measurementshelps project engineers track changes in cleanup fluids, understand heatflow and hydrate formation conditions in the system and evaluateperformance of system components.

Surface Acquisition

Flowhead Pressure and temperature of tubing and casing

Choke manifold Pressure and temperature

Heater Pressure and temperature

Separator Pressure and temperature; differential pressure across the gas orifice; flow rates of oil, gas and water; oil shrinkage; basic sediment and water; oil and gas gravity; fluid samples

Storage tanks Temperature and shrinkage

Subsea test tree Annulus pressure, temperature

Downhole Acquisition

Downhole recording DST pressure and temperature, fluid samples retrieved when test string is brought to surface

Surface readout Downhole pressure and temperature data retrieved by wireline

Wireline tools Pressure, temperature, flow rates, samples and various other measurements, depending on the suite of tools

Data Measurement Points

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Spring 2007 45

information is vital to predicting the futurebehavior of a reservoir or well completion.

In its most basic form, a well test recordschanges in downhole pressure that follow achange in flow rate. Often, downhole pressuresand temperatures, surface flow rates andsamples of produced fluids are obtained.Variations on this basic theme are carried outwith regularity.

To accommodate different testing needs andstrategies, service companies have developed abroad array of innovative testing tools and

techniques. This article describes advancesacross a range of downhole and surface testingequipment. We also discuss the reasons for welltesting, the strategies applied at different stagesin the life of a reservoir, and the answers that canbe provided by properly planned, prepared andexecuted well tests. Examples from a Middle Eastgas field and a record-breaking operation in theGulf of Mexico demonstrate the versatility andhigh performance provided by today’s well-testing methods.

Why Test?Today, most prospects are explored and thenproduced on the basis of geological and seismicdata, logging data, and then well testing data.Prior to drilling a prospect, seismic data initiallyserve to delineate the depth and breadth of apotential reservoir. During the drilling process,logging data are used to determine staticreservoir parameters such as porosity, lithology,rock type, saturation, and formation depth,thickness and dip. Dynamic reservoir propertiesare measured through well testing. Pressure and


rate perturbations induced by the testing processprovide important clues to the nature of areservoir and its fluids.

Wells are tested to determine reservoirparameters that cannot be adequately measuredthrough other techniques, such as mud logging,coring, electrical logging and seismic surveys.Admittedly, in some cases, we can obtain similarmeasurements through these techniques, but the quality or scope may not be sufficient to meetthe operator’s objectives. Pressure and tempera -ture measurements, flow rates and fluid samplesare keys to understanding and predictingreservoir behavior and production capabilities.Well test data provide inputs for modelingreservoirs, designing well completions, develop -ing field-production strategies and designingproduction facilities.

Well test results are also crucial for reservesestimations. Many countries require flow testing,with fluids produced to surface, for reserves to be classified as proven. In addition to estimatingreserves, these tests provide a means for directly measuring the aggregate response ofreservoirs at large scales and for detectingreservoir boundaries.

One of the more important reservoirparameters is permeability. Understandingpermeability and its directional variability isessential for developing perforating strategies,evaluating fracture or fault connectivity,predicting well performance and modeling thebehavior of the reservoir under primary,secondary or tertiary production. Permeability isa scale-sensitive tensorial property; its valuedepends on the scale and the direction throughwhich it is measured. And like other reservoirproperties, permeability may be heterogeneous.Thus, its characteristics are difficult to scale upfrom core to reservoir scale, and measurementsobtained at one location may not adequatelycharacterize the property at another locationwithin the same reservoir. Well testing, byphysically measuring pressures and flow rates,provides a large-scale aggregate measure ofpermeability. It thereby provides the ultimatemeans for evaluating a reservoir’s ability totransmit fluids.

Testing Objectives and StrategiesWell test objectives change with each stage in thelife of a well and its reservoir. During theexploration and appraisal phase, well testinghelps the E&P company ascertain the size of areservoir, its permeability and fluid charac -teristics. This information, along with pressuresand production rates, is used to assess the

deliverability and commercial viability of aprospect, and is critical for booking reserves.Fluid characteristics are particularly importantduring the early stages of a prospect’s evaluation,when E&P companies need to determine the typeof process equipment they must install to treatand move produced fluids from the wellbore tothe refinery.

During development, the operator’s focusshifts from assessing deliverability and fluid typeto evaluating pressure and flow and ascertainingcompartmentalization within the reservoir. Thisinformation is needed to refine the fielddevelopment plan and optimize placement ofsubsequent wells.

During the production phase, well tests areconducted to evaluate completion efficiency anddiagnose unexpected changes in production. Thesetests assist in determining whether productiondeclines are caused by the reservoir or by thecompletion. Later in the life of the reservoir, theseresults will prove crucial for assessing subsequentsecondary recovery strategies.

Well tests can generally be classified as eitherproductivity or descriptive tests. Productivity testsare carried out to obtain representative samplesof reservoir fluids and to determine fluid-flowcapacity at specific reservoir static and flowingpressures. On the other hand, E&P companiesschedule descriptive tests when they need toestimate a reservoir’s size and flow capacity,analyze horizontal and vertical permeability and determine reservoir boundaries (above).Productivity testing typically seeks to obtainstabilized bottomhole pressures over a range ofdifferent flow rates. Successive rate changes aremade by adjusting choke size, which is not doneuntil continual measurements have determined

that bottomhole pressures and temperatures have stabilized.

Unlike testing to obtain stabilized bottomholemeasurements, descriptive tests require transient-pressure measurements. Pressure transients areinduced by step changes in surface productionrates and can be measured by bottomhole pressuresensors or permanent downhole pressure gauges.The changes in production cause pressureperturbations that propagate from the wellbore tothe surrounding formation. These pressure pulsesare affected by fluids and geological featureswithin the reservoir. While they might travelstraight through a homogeneous formation, thesepulses may be hindered by low-permeability zones,or may vanish entirely when they enter a gas cap.By recording wellbore pressure response overtime, the operator can obtain a pressure curve thatis influenced by the geometry of geologicalfeatures and the particular fluids contained withinthe reservoir.

Well tests can be carried out before or after awell is completed, and at different stages in thelife of reservoir; thus, they come in a variety ofsizes and modes (See “The Testing Spectrum,”page 48). An operator’s objectives dictate themode and scale of the test (next page). Testingmodes range from openhole wireline testing withan MDT Modular Formation Dynamics Tester toolto cased hole testing with a CHDT Cased HoleDynamics Tester tool; or from slicklinebottomhole pressure surveys of producing wellsto simply monitoring shut-in wellhead pressure.1

46 Oilfield Review

1. A slickline is a nonelectric cable used for selectiveplacement and retrieval of tools and flow-controlequipment in a wellbore. This cable passes throughpressure-control equipment mounted on the wellhead,permitting a variety of downhole operations to beconducted safely on live wellbores.

>Well test objectives. The objective determines which type of test will berun, and frequently more than one objective must be achieved.

Productivity Tests

Obtain and analyze representative samples of produced fluids

Measure reservoir pressure and temperature

Determine inflow performance relationship and deliverability

Evaluate completion efficiency

Characterize well damage

Evaluate workover or stimulation treatments

Descriptive Tests

Evaluate reservoir parameters

Characterize reservoir heterogeneities

Assess reservoir extent and geometry

Evaluate hydraulic communication between wells

Well Test Objectives


Spring 2007 47

Although some well test objectives are metthrough extensive tests that run for days orweeks, other test objectives can be accomplishedthrough new techniques in a matter of hours.New developments in technology are radicallychanging the face of well testing, most notably inthe area of flowmetering.

Schlumberger developed its multiphaseflowmetering capability over several years andtested it in flow loops and fields around theworld. One such early test was conducted withthe support of Sonatrach in wells in the Hassi-Messaoud field in Algeria. Results were used tocalibrate and verify flowmeter performancebefore it was commercialized in 2001 asPhaseTester portable multiphase periodic welltesting equipment. In 2002, it was delivered tothe Hassi-Messaoud field, and has since beenutilized in other Sonatrach field operations.

PhaseTester Vx multiphase well testingtechnology was tested extensively at the In SalahGas (ISG) project. A joint development project ofSonatrach, Statoil and BP, the ISG comprises thedevelopment of seven gas fields in south-centralAlgeria and represents one of the largest gasprojects in the country. Well testing services forthe Krechba, Teguentour and Reg fieldscommenced with the following objectives: • well cleanup—reduce the potential for forma -

tion damage between well completion and its connection to the production facility and reduce facility damage normally caused by solids production during the subsequent startup

• flow deliverability—test the productivity ofreentry wells and newly drilled wells

• corrosives—gather information on carbon diox-ide [CO2] and hydrogen sulfide [H2S] content

• well pressure—acquire downhole pressuredata during initial production in each field

• well deliverability—unload the well and conduct a single rate test to determine overall deliverability.

An average flow rate of 50 MMcf/d [1.4 million m3/d] was expected, so for safetyreasons the equipment had to safely handle70 MMcf/d [2 million m3/d]. Besides dry gas, the24-hour production tests were expected to yieldup to 9% CO2, 11 ppm H2S, and varying amountsof gas condensate, oil, mud, sediment and water.In addition, flowback of diesel used to limitdifferential pressure against the test string was expected.

> Test modes and scales. The scale of a test is a function of time. Small-scale tests arecarried out by wireline formation tester in a matter of minutes or hours, obtaining fluidsamples ranging from cubic centimeters to liters in size, and producing small pressureperturbations that investigate a radius of several feet beyond the wellbore. At the otherextreme, extended well tests can last for months, produce several thousand barrels offluid, and create large pressure perturbations that can propagate for thousands of feetbeyond the wellbore.

Sample yield

MacroscaleClosed chamber test

Radius of investigation < 1,000 ft

Reservoir-scaleDrill stem and production testing

Sample yieldRadius of investigation > 1,000 ft

Sample yield

MicroscaleWireline formation tester

pressure test (drawdown and buildup)

Radius of investigation < 10 ft

Sample yield

Micro- to macroscaleLarge volumes withdrawn through probe

or packers using downhole pumps

Radius of investigation < 100 ft

(continued on page 52)

59605schD7R1.qxp:59605schD7R1 5/19/07 9:48 PM 7

48 Oilfield Review

The variety of tools and services that fallunder the well testing umbrella is extensive.A diverse assortment of tools and techniqueshas evolved to meet the well testing needs ofE&P companies. In this evolutionarysequence, the drillstem test (DST) forms acentral trunk from which other testing toolsand techniques have grown. The ensuingproduct sequence followed a naturalprogression from basic to sophisticated, andbranched off to include surface, sampling,slickline and wireline devices.

In 1926, brothers E.C. Johnston and M.O.Johnston ran their first commercial DST. Thisjob used a composite packer and valve run inopen hole to create a temporary completionand control flow. By 1933, Johnston WellTesters had modified their offering to includea pressure gauge to supplement flow-rateinformation with formation pressuremeasurements.1 Since then, the well testingbusiness has expanded through numerousinnovations in equipment and methods.

Testing engineers quickly recognized thatsurface equipment was needed to handleformation fluids produced through the tempo -rary completion established by the DSTstring. As a result, a three-phase testseparator and surge tank became standardequipment in many well testing configurations.The test separator is positioned downstreamfrom the choke manifold, which is used tocontrol flow of produced fluids at the surface.

A separator receives fluids produced from awell and uses gravity and differences in fluiddensity to separate the fluids into water, oiland gas phases (right). Once separated, theindividual phases are metered as they leavethe vessel. The gas phase is routed to aseparate gas line or is flared.2 The liquidphases are commingled and returned to aflowline, or sent to a storage tank. In remotelocations that cannot accommodate storageand transport of produced liquids, the liquidsmay have to be routed to a burner for disposal.

A surge tank, placed downstream of theseparator, provides a vessel into which sepa -rated liquids can flow to neutralize suddenpressure surges. With a decrease in oilpressure at the surge tank, gas will come outof solution, causing a decrease in oil volume.This shrinkage can be measured at the surgetank. Auxiliary equipment may also berequired, such as a steam heat exchanger orindirect-fired heater. The heater is placedupstream of the separator to heat producedfluids and prevent hydrate formation,reduce fluid viscosity and break downemulsions. A burner installed downstream ofthe surge tank disposes of the produced gasand, under certain circumstances, disposesof produced liquids.

Downhole, pressure and temperaturemeasure ments can be acquired by slickline. In the past, slickline surveys used mechanicalchart recorders to measure downholepressures, while a maximum-readingthermometer measured bottomholetemperature (BHT). With the advent ofcrystal-sensor technology, downhole pressureand temperature gauges have grownincreasingly reliable and accurate. Even thistechnology has evolved. A single crystal nowmeasures temperature and pressure at thesame point, eliminating temperature lags orother discrepancies seen formerly, when asecond crystal was used for thermalcorrections. Sensors, such as the CQG CrystalQuartz Gauge sensor and UNIGAGE pressure

The Testing Spectrum

> Test separator. A portable three-phase separator (top) is enclosed in a structuralframework for protection and lifting support. The cutaway view (bottom) shows deflectorsand baffles used to separate produced fluids. These fluids enter from the inlet and hit aseries of plates, causing liquids to drop out of the flowstream, where they are separatedby gravitation based on density contrast.

Pressure-reliefvalve

Secondpressure-relief

valveCoalescing

platesFoam breakerbaffle plate

Gas outlet to orifice meter

Mist extractor

Access door

Oil-level controller

Vortex breaker

Vortex breaker

Oil outlet to mechanical meterWeir baffle plate

Water outletto mechanical meter

Water-level controller

Deflector plates

Additionaloutlet

Effluent inlet


Spring 2007 49

gauge system, are highly versatile and canrecord downhole pressure in slickline, DSTand tubing-conveyed perforating (TCP)applications. On DST and TCP jobs,measurements are made from either above orbelow the packer, and gauges can be placedinside or outside the test string. The data areeither recorded downhole or trans mitted tosurface for real-time readout.

Tester valves, which form the heart of thewell test string, have evolved too. From thesimple but effective valve of the originalJohnston Formation Tester, test tool designprogressed to the MFE Multiflow Evaluatorreciprocating multicycle tool in 1961. ThisMFE test tool was utilized on thousands ofopenhole DSTs and is still in use in traditionalDST applications in certain hard-rock areas.

In the 1970s, offshore exploration increaseddramatically and with it arose the need for atest valve more suited for cased-hole testing,in much deeper wells and higher pressuresand in operations conducted from floatingrigs. The PCT Pressure Controlled Testervalve estab lished its niche in this arena,eliminating the need to move the pipe up anddown to manually operate the valve—apotential concern when testing from floatingrigs. Instead, the PCT tool was operated byapplying pressure to the test string-casingannulus. High-rate wells prompteddevelopment of the fullbore PCT tool in 1981.

In 1989, the first of a new generation of“smart” test tools was introduced with thedevelopment of the IRIS Intelligent RemoteImplementation System. This dual-valvesystem combines the test valve andcirculating valve into a single tool. Integralsensors and microprocessors make the toolprogrammable, providing flexibility in testingoperations. The mechanical power to openand close both the test and circulating valvesis contained within the tool rather than beingsupplied from surface through manipulationof the pipe or annular pressure.

Now, coded pressure pulses sent fromsurface provide commands to the tooldownhole. These low-intensity pressure pulsesare transmitted along the annulus anddetected downhole by the tool’s intelligentcontroller. The microprocessor analyzes eachpulse to differentiate commands from otherpressure events during the job. Pulses

recognized as IRIS commands areimplemented using hydrostatic pressure avail -able downhole to open or close theappropriate valve, or even execute sequencedvalve opera tions. For example, the testervalve can be set to close if annulusoverpressure occurs, and can be reopenedonce the problem has been remedied. Themicroprocessor stores a pressure-data file andlists all executed commands for postjobanalysis of the operation.

Deepwater prospects are drilled andcompleted by drillships or semisubmersiblerigs; well tests conducted from such floatingvessels require an additional measure of wellcontrol beyond that provided by the drilling

blowout preventer (BOP). This requirementspawned the development of the Johnston-Schlumberger E-Z Tree retrievable wellcontrol system in 1975. In 1997, anothersystem was developed to provide greatersecurity during urgent situations, allowingclosure of pipe and shear rams with the testtree in place. The SenTREE subsea wellcontrol system provides hydraulic controlfrom the surface to a dual fail-safe ball andflapper valve module (above). The SenTREE

> Subsea test tree. The SenTREE test tree was designed to enhance well control duringwell tests conducted from drillships and semisubmersibles. It is landed inside the BOPstack at the seafloor.

Riser

Drilling vessel

Mud line

Spanner joint

Retainer valve

Shear sub

Latch assembly

Valve assembly

Slick joint

Adjustablefluted hanger

Bleedoff valve

Shear rams

Blind rams

Pipe rams

BOP stack

Pipe rams

Annular BOP

Mud line

1. Johnston Well Testers was acquired by Schlumberger in 1956.

2. Atkinson I, Theuveny B, Berard M, Connort G, Lowe T,McDiarmid A, Mehdizadeh P, Pinguet B, Smith G andWilliamson KJ: “A New Horizon in Multiphase Flow Measurement,” Oilfield Review 16, no.4 (Winter 2004/2005): 52–63.


system also serves as a disconnect point forthe test string in the event that the rigposition moves out of tolerance, forcing therig to move off the subsea BOP.

At the surface, a new approach tomultiphase measurement has taken place.PhaseTester portable multiphase periodicwell testing equipment was developed toaccurately measure flow rates of oil, gas andwater phases without the need to separatethe flowstream into individual phases. Thedevice can accurately measure each phase inslug flows, foams and stable emulsions.3 Thisflowmeter is typically installed immediatelydownstream of the wellhead and upstream ofthe surface separator during DSTs (above).

Using Vx multiphase well testing technologydeveloped by Framo Engineering AS andSchlumberger, the PhaseTester unit combinesa venturi with a dual-energy-gamma ray, high-speed detection system. Pressure is measuredas the fluid enters the constriction in theventuri throat. A small radioactive chemicalsource on one side of the venturi emitsgamma rays across a discrete range of energylevels, and the attenuation of gamma rayscaused by the fluid is measured at twodifferent levels. Across from the source, a

scintillation detector combined with aphotomultiplier detects gamma rays that havenot been absorbed by the fluid mixture as itflows through the venturi. Taking thesemeasurements 45 times per second ensuresaccurate measurements regardless ofturbulence in flow regimes.

The low-energy gamma ray count rate isrelated to the composition of the fluid—thereby responding to the water/liquid ratio.The high-energy count rate is primarilyrelated to the density of the mixture. A flowcomputer deter mines relative fractions ofeach phase present in the pipe. Thecombination of mixture density and pressuredifferential across the venturi delivers arobust and high-resolution total mass flowrate. The flow computer combines PVTvolumetric properties of the fluid with thefractions and the mass rate to deliver instan -taneous volumetric rates of oil, gas and waterevery 10 seconds.

A special Vx interpretation program hasalso been developed for measuring flow in gaswells with gas volume fractions (GVF) rangingfrom 90% to 100%. The Vx gas-modeinterpretation program enables thePhaseTester flowmeter to measure gas flowrates across the full spectrum of gases, from

dry gas to extremely wet gas and gas rich incondensate. With GVF flows as high as 98%,the Vx gas-mode program can also achieveaccurate measurement of water flow rates.

Some of the concepts described above havebeen integrated into a compact, lightweightwell testing package for acquiring accurateflow-rate data while processing large volumesof well effluent produced during testing. TheCleanTest well testing service uses amultiphase flow meter, a specially designedsurface separator, a water treatment unitplaced downstream of the separator, and ifneeded, a high-efficiency burner for smoke-free disposal of effluent (next page).

The PhaseTester Vx flowmeter, located onthe surface between the wellhead and thesepara tor, continuously monitors producedfluids during the well test, eliminatingdependency on the separation process forflow measurements. This is especiallyimportant during the cleanup period, whenthe well is initially opened up to flow and theinvaded zone of the formation unloads mudfiltrates, brines and other fluids pumpeddownhole during drilling or completionprocesses. Using the multiphase flowmeter to monitor flow rates at the surface, theoperator can immediately determine theinstant that the well has cleaned up.

On the CleanTest platform, a CleanSepadjustable well test separator is placeddownstream of the flowmeter to manageeffluents. By installing the highly accuratePhaseTester flowmeter upstream, theseparator is relieved of instrumentationnormally used to measure phase fractions atthe surface. This allows the separator to beput on line the moment the well is opened up for flowback; the flowstream is no longerrerouted to bypass the separator during thecleanup period to avoid damaging theinstrumentation. This approach saves rig timeon testing programs that typically require twoto three days of progressive chokeadjustments before cleanup is sufficient topermit produced fluids to be routed through the separator.

50 Oilfield Review

> Portable flowmeter. The PhaseTester multiphase flowmeter is housed in a modular framework(left). At 3,750 lbm [1,705 kg], the PhaseTester flowmeter is compact enough to be transported bya mid-sized truck (right).

3. Atkinson et al, reference 2.


Spring 2007 51

The separator uses a remotely controlledweir that moves up or down with fluctuationsin oil- and water-phase fractions. Inside theseparator, gas, oil and water phases of theproduction stream are split into theirrespective fractions before being discharged.

Water exiting the separator is sent to amobile water treatment unit. This unitcombines coalescing and gravity separation

techniques to reduce oil-in-water concentra-tions. For instance, water that enters the unitwith 20,000 ppm of dispersed oil will containless than 20 ppm of oil at the outlet, evenwith dense, low API-gravity oils. The oil-in-water content is confirmed when samplestaken at the unit are run through an onsiteanalyzer. By removing oil from the water, theunit assists in compliance with strict

environmental discharge regulations that allowwater disposal directly into the sea. Suchcompliance provides the operator with a cost-effective alternative to water storage, transportand disposal. The oil is gathered into anatmospheric oil recovery chamber, and a built-in pump is provided to export the recovered oilto a storage tank or to the burner.

> Flowstream schematic. Reservoir fluids are handled by the CleanTest platform. Fluids producedto surface are metered through the PhaseTester multiphase flowmeter before being sentdownstream to a specially designed separator. By monitoring the flowmeter, the operator canfine-tune flow and heat adjustments at the separator, thereby optimizing fluid-handlingperformance. Water exiting the separator passes through a treatment unit to remove remainingoil prior to discharge. High-efficiency burners dispose of any fluids that the operator is notequipped to store or transport.

Separator

Flowmeter

Wellhead or flowhead Flare stack

Oil storage tank

Water treater


Originally, the project relied on conventionaltechnology such as horizontal gravity separators,surge tanks, manifolds, transfer pumps andburners. In 2004, Schlumberger introduced thePhaseTester Vx gas-mode interpretation model.The multiphase capabilities of the gas-modeinterpretation model extended the full range offlow measurements to wet- or dry-gas conditions.The PhaseTester multiphase flowmeter alsoprovided accurate readings of gas flow rate atstandard conditions, and obtained liquid rateand water-cut values.

The PhaseTester flowmeter dramaticallysimplified the field setup because phaseseparation was no longer needed and samplingwas not a critical objective (above). This newlayout proved inherently safer than previous well

tests. Rig-up and rig-down times were also fasterby an average of 11.5 days. The need forpersonnel, trucks and support vehicles wasgreatly reduced, resulting in an estimated costsavings of 28% compared with previous well tests.

In another well test, the operator wasconcerned about the ability to resolveuncertainties in liquid-phase production. Duringthe Krechba field campaign in 2005, thePhaseTester Vx system was able to clearlydelineate the gas and liquid flow rates (nextpage, top right). These rates were subsequentlyconfirmed using the PLT Production LoggingTool. Using the PhaseTester Vx technology, theoperator obtained high-quality data whileincreasing safety and reducing cost related tologistics, personnel and operating time.

Fluid Sampling Beyond pressure, temperature and flow rate, theoperator also needs to know the precise nature ofthe fluids produced by the reservoir. The future ofa prospect hinges on the operator’s understandingof the fluids contained within a reservoir (nextpage, bottom right). Important economicconsiderations such as reservoir recovery factor,reserves estimates and production forecasts areaffected by fluid properties. In addition toobtaining information about chemical compo -sition, density, viscosity and gas/oil ratio (GOR) ofthe fluid, operators are especially interested indetermining the conditions under which theproduced fluids will form waxes, hydrates andasphaltenes. Knowledge of fluid properties istherefore essential to evaluating the profitabilityof a well or prospect.

52 Oilfield Review

> Simplified layout. A comparison of the original test setup (top) and a later well test layout (bottom)shows a dramatic reduction in piping and complexity obtained by including the PhaseTester multiphaseflowmeter.

Wellhead

Wellhead

Bypass manifold PhaseTester flowmeter

Isolation valve

Choke manifold

Air-driven pumpOil manifold

To mud pit

Flame arrestor

Choke

Pump unitIsolation valve

SeparatorVertical

separator

To water pit

Dieselrecovery

tank

Chokemanifold

Heater

Burner

Surgetank

Gaugetank

Flare pit

Air compressor

Relief line

Flare pit

Transfer pump

Flame arrestor

Gaugetank

Surgetank


Spring 2007 53

Well testing offers a prime opportunity tocollect representative reservoir-fluid samples.Samples are considered representative of fluidsin the reservoir when they are single-phase, and have been collected at saturation-pressureand critical-temperature conditions above which organic solids would precipitate from the sample. The pressure-temperature crite-ria must be strictly observed for samples to be representative.

Analyses of representative samples are vitalinputs for the design and simulation of productionprocesses that take place between the sandfaceand the sales pipelines. These simulations rely on pressure-volume-temperature (PVT) analysisdata, and start with the assumption that areservoir is performing under initial conditions,before the reservoir is produced. Once produced,its fluid properties inevitably change as pressuresdecrease over the life of a reservoir.

It is not always possible to obtain a represen-tative sample of the original reservoir fluid.When reservoir pressure drops below thebubblepoint pressure of the oil, lighter fractionsof the oil will vaporize into a separate gas phase.2

The opposite effect is seen when pressure in agas condensate reservoir drops below thedewpoint pressure.3 Liquid will form as the gascondenses. The compositions of these reservoirfluids will then be altered by the correspondingloss of light or heavy fractions.

Timing is critical in obtaining a represen-tative sample of the original reservoir fluid.Samples should be taken as early as possible in a reservoir's producing life to avoid the two-phase condition caused by pressure drawdown asthe well is produced. For this reason, discoverywells are often sampled extensively, usingwireline formation testers after an interval is drilled, and again during the drillstem test (DST).

In addition to pressure, an operator mustconsider how representative a sample can be if itis drawn from a reservoir of large areal extent.That is, a single sample from a given position maynot account for variations or compartmental -ization within an expansive reservoir. Neitherwould a single sample account for fluidgradations that are seen between the top andbottom of massive pay sections. Therefore,reservoir fluids are often sampled as other wellsare drilled across a reservoir. Samples are also

taken from different depths in the reservoir,typically using a wireline formation tester.

Fluids sampled at the surface can differgreatly from fluids sampled downhole.Asphaltenes may precipitate out of reservoirfluids with the drop in pressure that occurs asfluids are produced from the perforation to thesurface. Waxes can also precipitate out ofsolution with a drop in temperature thataccompanies fluids as they are produced to thesurface. The difference between downhole andsurface fluid properties is of keen interest to anoperator, and a variety of techniques has beendeveloped to capture each type of sample.

Surface samples are collected at the wellheador at the separator. Separator samples requireindividual samples of the oil and gas phases to betaken, along with accurate measurements oftheir respective flow rates, pressures andtemperatures. The oil and gas samples are latercombined in a laboratory to form a repre -sentative sample. These samples are taken whenspecial analysis requires volumes that exceed thecapacity of conventional sampling tools or whenit is not possible to collect reservoir fluid samplesdownhole. Such volumes may be required foranalyses used in refinery studies or enhanced oilrecovery studies.

2. The bubblepoint is the temperature and pressure atwhich part of a liquid begins to convert to gas. Thus, if a constant volume of liquid is held at a constanttemperature while pressure is decreased, the point atwhich gas begins to form is the bubblepoint.

3. The dewpoint is the temperature and pressure at whicha gas begins to condense. If a constant pressure is heldon a given volume of gas while the temperature isgradually reduced, the point at which droplets of liquidbegin to form is the dewpoint of the gas at that pressure.

> Fluid determination during well test cleanup. This Krechba field well was monitored by the PhaseTesterflowmeter over a 24-hour cleanup period. Following each increase in choke size prescribed by thecleanup program, wellhead pressure, liquid and gas rates were measured. PhaseTester results showdistinctive plateaus for each phase, corresponding to adjustments in choke size.

2,500

2,000

1,500

1,000

500

0

Wat

er ra

te, b

bl/d

Wel

lhea

d pr

essu

re, p

si

Date/time

Gas rate

Water rate

Wellhead pressure

08/24/05–12:00 08/24/05–18:00 08/25/05–0:00 08/25/05–6:00 08/25/05–12:00 08/25/05–18:00

50

40

30

20

10

0

Gas

rate

, MM

cf/d

> Demand for produced fluid samples.Representative fluid samples and their analysesare required upstream and downstream of the wellhead.

Completion and Production Engineers

Geologists

Reservoir Engineers

Facilities Engineers

Completion designs

Material specifications

Artificial lift calculations

Production log interpretations

Production forecasts

Flow assurance mitigation

Separation and treatment of produced fluids

Metering options

Transport strategies

Well test interpretations

Reserves estimations

Material balance calculations

Natural drive mechanism analysis

Reservoir simulations

Reservoir correlations

Geochemical studies

Hydrocarbon source studies

Who Needs Fluid Samples?


Downhole samples, commonly referred to asbottomhole samples, are the most representativeof the original formation fluid, because they arecollected as close to reservoir pressure andtemperature as wellbore conditions permit.Bottomhole samples are taken from devicesdeployed on wireline or slickline, or as anintegral part of the DST toolstring. They are usedwhen the flowing bottomhole pressure is greaterthan the reservoir oil-saturation pressure.Bottomhole samples are essential for PVTanalysis and for evaluating potential flow-assurance problems, such as the precipitationand deposition of asphaltenes and waxes.

Several factors influence the choice ofsampling technique: reservoir properties, thevolume of sample required, the type of reservoirfluid to be sampled, the degree of reservoirdepletion, and the type of surface and subsurfaceequipment required. Each sampling moderequires its own special equipment, thoughcertain components are common to most. Therange of sampling modes can be loosely groupedinto five basic techniques:• Wellhead sampling: A purpose-built wellhead

sampling manifold is used to collect samplesat the surface (above). These samples can becollected only when the flowing wellheadpressure and temperature are above thereservoir fluid-saturation pressure, such thatthe fluid is a single phase at the wellhead.Such conditions are not typical, but aresometimes present; for example, in certainsubsea wells where produced fluids mayremain in single phase all the way to thesurface choke manifold.

• DST surface sampling: Samples of oil and gasare often acquired at the test separator. Withaccurate measurements of oil and gas flowrates, pressures and temperatures, thesesamples can be recombined in a laboratory toapproximate the composition of a representa -tive fluid at depth. Such samples require stableflow conditions inside the separator. Surfacesamples should always be collected as a precaution against unforeseen problems that could prevent successful retrieval of downhole samples.

• DST downhole sampling: Representative fluidsamples are taken downhole at the end of theDST main flow period. Commands from surfaceare transmitted to open a sample chamber,such as a single-phase reservoir sampler(SRS), which is incorporated into a specialdrill collar on the DST string. (right). Using aSCAR downhole carrier, up to eight SRS single-phase samples can be obtained. The SCARsampling tool is activated by rupture disk or bymud-pulse telemetry to an IRIS trigger. DSTbottomhole sampling takes place at reservoirpressure and temperature, such that single-phase fluid is recovered if reservoir pressure isabove the bubblepoint.

• Slickline sampling: Typically run in producingwells, SRS sample devices can be suspended ona slickline and lowered through the productiontubing to the top of perforations. A timer onthe SRS allows the sample chamber to openand admit fluids after sufficient time haspassed for the tool to reach the desired depth.

• Wireline formation tester sampling: Wirelinetools such as the MDT tool are routinely run inopen hole to measure reservoir pressures, andfrequently measure pressures at several depthsspanning the reservoir to obtain a reservoirpressure gradient, in addition to collectingreservoir fluid samples. The multisamplingcapability of the MDT tool means that it cancollect samples from various depths across areservoir to delineate complex gradations inthe fluid column. Wireline formation testerresults are often used to guide subsequentdrillstem testing.

Inside the MDT tool, sample quality ismonitored by an OFA Optical Fluid Analyzer, LFALive Fluid Analyzer or CFA Composition FluidAnalyzer modules. These modules can determineif a fluid has passed through its saturationpressure—as when an oil sample drops below itsbubblepoint, or a gas sample drops below itsdewpoint. They also verify that the sampled fluidis sufficiently low in filtrate contamination.4

Samples acquired by MDT tool are stored in asingle-phase multisample chamber (SPMC) toensure that the fluids are maintained atformation pressure as they are brought tosurface. In exploration wells, openhole MDTsamples often serve as a preliminary indicator ofreservoir fluid type before the cased-hole welltest is conducted. In some wells, MDT pressuremeasurements and sampling are run in lieu ofthe DST.

54 Oilfield Review

> Downhole fluid sampler. The single-phasereservoir sampler (SRS) uses a nitrogen-chargedpiston to exert pressure on the 600-cm3 fluid-sample chamber, thereby keeping the fluid aboveits saturation pressure and in single phase whenthe sample chamber is brought to surface.Maintaining high pressure also prevents the fluidfrom precipitating asphaltenes, which can makesamples unrepresentative.

Timing device

Air chamber

Regulator valve

Closure device

Floating piston

Sampling ports

Fixed piston

Spool valve

>Wellhead sampling manifold. This easilytransportable unit provides sampling cylinders,valves and necessary gauges for capturingproduced fluids at the wellhead.


Spring 2007 55

For oil-base muds (OBM), a special focusedsampling system has been developed to reducecontamination of the hydrocarbon fluid sampleby miscible oil-base drilling fluid filtrate. TheQuicksilver Probe wireline sampling tool usestwo distinct flow areas to focus clean formationfluid into the MDT tool.5 A perimeter, or “guard”ring around the outside of the probe capturesfiltrate, while a central ring draws in cleanreservoir fluid from the center of the cone offlow. This tool is not restricted to OBM though;the same guard probe provides faster, cleanersampling in wells drilled with any type of mud.

Downhole sampling can also be performed incased hole, using the CHDT tool, a variant on theMDT tool. This tester drills a 0.28-in. diameterhole through casing, cement and formation, theninserts a probe to take pressure measurementsand samples. After the probe is withdrawn, a 10,000-psi [69-MPa] bidirectional seal is insertedto plug the casing hole.6

Fluid AnalysisPressure-volume-temperature (PVT) relation -ships and composition of produced fluids are ofgreat interest to E&P companies, and areessential for evaluating the profitability of a wellor prospect. The composition and physicalproperties of produced fluids impact criticalcompletion designs, and those of the flowline,separation and pumping stations, and evenprocessing and refining plants—especially whenCO2, H2S or other corrosives are produced.Compositional analysis provides key input forreservoir simulation.

Fluid analysis is carried out in PVTlaboratories, some of which can be brought to thewellsite. The PVT Express onsite well fluidanalysis service delivers a dedicated PVT analysislaboratory to the wellsite (above right). Expertsfrom Oilphase-DBR fluid sampling and analysisservice conduct PVT analyses as soon as thesamples are collected. In their self-containedlaboratory, PVT analysts measure saturationpressure, bubblepoint and dewpoint, GOR, gascomposition to C12 and liquid composition to C36,atmospheric liquid density and viscosity.7

Customized fluid analysis results are delivered tothe client within hours, enabling critical testingand completion decisions to be made.

In a recent offshore well test, PVT Expressspecialists analyzed reservoir fluid samplescollected at the wellhead, along with separatorgas and liquid samples. The Oilphase-DBRengineer measured the wellhead fluid samplesaturation pressure at the sampling temperature

and at reservoir fluid temperature, and the fluidgas/oil ratio, and composition. This informationwas transferred to the InterAct real-timemonitoring and data delivery system andtransmitted to the Oilphase-DBR Houston FluidAnalysis Center, where data quality checks werecarried out. The results were then loaded intoPVT Pro equation-of-state simulation softwarefor further modeling. The resulting pressure-temperature matrix was sent back to the rig,where it was downloaded into a PhaseTester datafile. The data enabled test engineers to create acustomized fluid identification for optimizingPhaseTester flowmeter measurements obtainedduring the well test.

Well Test PlanningWith the advent of computerized planningapplications, well testing by generalized ruleshas gone the way of the nomogram. Well testsrequire clearly defined objectives and carefulplanning. Most well tests are designed aroundobjectives such as taking fluid samples forlaboratory analyses, measuring reservoir pressureand temperature, determining well productivity,evaluating completion efficiency or determiningreservoir size, boundaries and other parameters.To achieve these objectives, the test engineermust devise a dynamic measurement sequenceand select the right hardware to do the job.

4. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC, Rylander Eand Van Dusen A: “Quantifying Contamination UsingColor of Crude and Condensate,” Oilfield Review 13, no. 3(Autumn 2001): 24–43.For more on the CFA Composition Fluid Analyzer module:Betancourt S, Fujisawa G, Mullins OC, Carnegie A,Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo ARand Terabayashi H: “Analyzing Hydrocarbons in theBorehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.

5. For more on the Quicksilver Probe sampling tool:Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B,Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M,Tarvin J, Weinheber P, Williams S and Zeybek M:“Focusing on Downhole Fluid Sampling and Analysis,”Oilfield Review 18, no.4 (Winter 2006/2007): 4–19.

6. Burgess K, Fields T, Harrigan E, Golich GM, MacDougall T, Reeves R, Smith S, Thornsberry K,Ritchie B, Rivero R and Siegfried R: “Formation Testingand Sampling Through Casing,” Oilfield Review 14, no. 1(Spring 2002): 46–57.

7. Oilphase-DBR is the fluid-sampling and analysis divisionof Schlumberger. Oilphase was founded in Aberdeen in1989 with the launch of the industry’s first single-phase,cased-hole, bottomhole sampling tool. Oilphase wasacquired by Schlumberger in 1996. DBR was founded in1980 in Edmonton, Alberta, Canada, by Donald BakerRobinson, the coauthor of the Peng-Robinson equation ofstate. DBR designed and manufactured mercury-freePVT and flow assurance laboratory equipment, equation-of-state software, and heavy-oil fluid analysis services.In 2002, DBR was acquired by Schlumberger and mergedwith Oilphase.

> Portable fluid analysis laboratory. The PVT Express mobile analysis service can provide informationabout the physical characteristics, composition and behavior of reservoir fluids. By bringing thelaboratory to the wellsite, the operator can quickly obtain a detailed analysis of fluid composition,bubblepoint or dewpoint pressures, compressibility, viscosity and other important parameters.


Whatever the operator’s objectives, all well teststoday are designed with safety and environ -mental protection as top priorities.

The first step in effective test design involvesa detailed understanding of the proposed welltest objectives. All decisions about rate handling,test period durations, pressure gauge samplingfrequency, and fluid sampling protocol require afirm understanding of what the test is expectedto prove. In some cases, sample collection is a priority; some require maximum rate ordrawdown; and others seek to evaluatecompletion efficiency or investigate reservoirboundaries. For each objective, a careful anddeliberate analysis of costs versus benefits mustbe carried out.

Test objectives are developed after a detailedanalysis of geophysical, petrophysical anddrilling information. These objectives shouldthen be prioritized to aid subsequent decision-making when economic and operational factorsmust be considered. From this analysis,geologists and engineers will determine whichzones to test, the type of test data they need toacquire to satisfy the stated objectives, andhence the type of well test they need to run.

To determine the range of objectives that canbe met by a well test, test engineers model thereservoir’s response to changes in productionrate during the test. Computerized simulationsallow well test designers to weigh the effects of awide range of pressures and flow rates on thereservoir and the testing system. Simulation alsohelps identify the types of systems capable ofmeasuring the expected pressure, temperatureand rate ranges as well as the downhole andsurface test equipment that will be required tophysically execute the well test program.

Simulation results are reviewed to determinewhen key pressure-transient features will appear,such as the end of wellbore storage orcompletions effects, or the start and duration ofinfinite-acting radial flow.8 These results also lettest personnel anticipate the emergence ofouter-boundary effects caused by faults orpressure boundaries. Sensitivity analysesdetermine the effects of potential reservoirparameters on the duration of flow and shut-inperiods. At this point, a review of the prioritizedwell test objectives may be necessary. It is notuncommon to find that the flow or shut-in timerequired to achieve a particular objective isprohibitive in light of the associated cost. Suchtrade-offs are a very real part of the well testplanning process.

With testing parameters in hand, well testengineers can select data-acquisition systemsand well test equipment appropriate to the job.Important considerations include the following:• ensuring that required well test data will be

sufficient to validate the test • requiring surface readouts to display pressure

and temperature data measurements for real-time decision-making versus downhole recorders

• using high-resolution gauges when test objec-tives call for detailed reservoir description

• ensuring redundancy of measurements • requiring redundancy of downhole tools through -

out operations in offshore wells to ensure posi tivewell control downhole and at the seafloor

• selecting surface equipment to safely and efficiently handle expected rates and pressures

• disposing of produced fluids in an environmen-tally sound manner.

The design and specification of surface flowequipment are quite involved. To safely producefluids to surface, well test engineers must designa system that can withstand and control high-rate flows of liquids and gases from the flowheadto the separator to the storage tanks, or onthrough to the flare stack. To prevent potentiallydisastrous erosion of piping, bends andequipment, they must factor in fluid velocity,drag and pressure drops from one component tothe next.

An important planning tool is the equipmentlayout diagram. This schematic shows the testingequipment to be used, the general piping layout,and the specific location of each piece ofequipment at the wellsite. With expected flowrates and wellhead pressures in mind, well testdesigners can determine the size and pressureratings for the piping, flowhead, choke manifold,heater and test separator. Correct piping size, inparticular, is important in preventing excessivefluid velocities, large pressure losses andoverpressurization of equipment.

High flow rates are a particular concern withrespect to the surface test separator. Too muchfluid can quickly overwhelm the equipment,causing liquid carryover into the separator gasline, or formation of foam in its oil line. Bydesigning a system with retention times andpressure profiles in mind, well test engineers canavoid such problems.9 Their test design must alsoensure maintenance of a temperature andpressure regime that will prevent the formationof hydrates, or else they must plan to inject glycolor methanol upstream of the choke manifold.

The test design considers safety from one endof the system to the other. All surface testingequipment must be grounded. Piping, flowlines

and vent lines are color-coded to identify theworking pressure of the pipe, and each must beanchored. The layout is also designed toaccommodate or counter the effects of noise andheat. Noise measurements obtained during welltests show a corresponding rise in decibels at theseparator and gas line as flow rates increase.Heat is a concern for personnel and equipment,so the equipment layout plan must provide forappropriate isolation distances between variouspieces of equipment, such as the wellhead, steamexchanger, separator or flare stack. Thesedistances are dictated by industry standardclassifications assigned to each component toreduce the likelihood of accidental combustion.

Well test design software can be useful forspecifying surface equipment and mapping itslayout. ArchiTest well test design softwareworks with PIPESIM production systemanalysis software to carry out a nodal analysisof the surface system, creating a realisticsteady-state simulation of surface processes.This application accounts for the surfaceinventory of well testing equipment—fromchoke to separator to burner (next page). Withinputs such as wellhead flow pressure,temperature, flow rate, fluid composition, APIgravity of oil, and specific gravity of gas, thissoftware can model fluids as they are producedthrough the surface equipment—beginningwith drilling or completion fluids andtransitioning to reservoir fluids.

The output predicts pressures and flow rates over time and highlights equipment that is not rated for anticipated conditions. Thesystem can then be used to determine systemsensitivity to changes in variables ranging fromseparator pressure to surface choke or flowlinesize. This software is also used to determineerosion at different velocities and to calculateretention times required to process fluidsthrough the separator.

If the well is not connected to productionfacilities and the client requires disposal ofproduced fluids, ArchiTest software can predictthe noise and heat radiation patterns emanatingfrom the flare. The software can also anticipatehydrate, emulsion or foaming risks.

56 Oilfield Review

8. As a pressure transient diffuses into a formation, it is nolonger affected by wellbore and near-wellbore effects,and becomes more indicative of formation properties.This period is often called the infinite-acting radial-flowregime because the transient is unaffected by externalboundaries and thus acts as if it is infinite in areal extent.

9. The rate at which a fluid passes through a component isa function of its retention time.


Spring 2007 57

Well test planning, high-performance equip -ment and attention to safety and environ mentalrequirements are put to their most challengingtest in the deepwater environment. A recent welltest highlights some of the complexities involvedin planning and imple menting an extended well test.

Deepwater Extended TestIn the Gulf of Mexico (GOM), 99% of proven oilreserves are produced from rock of Miocene ageor younger. In recent years, potential reservoirshave been discovered in older formations,prompting new trends in exploration andopening wider swaths of the GOM to drilling. AsE&P companies venture into deeper waters insearch of these reservoirs, new technologiesmust be developed, and old technologies must be

modified to adapt to the challenges of this harshoperating environment.

Exploration forays into deep and ultradeepwaters highlight the importance of well testing.To acquire meaningful results, the planning ofthese complex, extended well tests can takemany months, and the tests themselves can runfor several weeks. The flow, pressure and fluid-property data obtained through well testing areessential for developing further drilling, comple -tion and production strategies. These data maydictate whether the operator sets pipe orabandons a prospect. If the operator elects tocomplete the well, the test data will guide thesize and type of equipment required to processproduced fluids.

To be successful in these deepwater frontierareas, exploration companies must employ avariety of sophisticated technologies that helpthem ascertain the nature of their prospects—which may lie beneath some 5,000 ft [1,500 m] ormore of ocean, and perhaps 20,000 ft [6,100 m]or more beneath the seafloor. Initially, waves ofpressure in the form of seismic energy penetratethe depths to define the prospect as clearly aspossible. Once a well is drilled, however, anentirely different wave of pressure is used toascertain its contents.

Chevron Corporation, along with partnersDevon Energy and Statoil ASA, has beenprospecting in the deeper Eocene formations ofthe Gulf of Mexico. In the process, Chevron’sJack 2 well, drilled at Walker Ridge Block 758, seta number of records while attaining the deepest

> Automated layout schematic. The ArchiTest program assists in designing the layout for surface test equipment. Length, diameter and working pressuresof each component in the layout are checked against calculated flow rates, pressure drops and erosion rates to ensure that the equipment is capable ofhandling produced fluids. Surface test components that are insufficiently rated for the job are highlighted in red for easy identification.

File Edit View

Properties

Name SURF-SEP

Length 12.50 ftDiameter 48.00 inWeir type PlateWeir distance 9.84 ft

Minimum working -4.00 degFMaximum working 212.00 degF

Pan & Zoom

Working pressure 1,345.00 psiMaximum gas flow 90.00 MMSCF/dMaximum liquid flo 16,500.00 bbl/d

Lcv oil Control Valve 2 ANS

Pcv gas Control Valve Type 2

A: Database

Simulation Tools Help

B: Geometry

C: Safety

D: Valve

Name Control Valve 2

Name Control Valve

Valve diameter 2.00 in

Valve diameter 4.00 in

Flow character Equal percentage

Flow character Linear

Cv Max 59.7

Cv Max 224

NameEnter name

Minimum work 32.00 degFMaximum work 300.00 degFWorking press 1,440.00 psi

Chemical injection

Flowhead

Surface safety valve

Choke

Cyclone sand controlHeater

SeparatorPhase tester

Tank

Pump

Pressure safetyvalve skid

Pressurecontrol valve

Oil manifold

Gas manifold

Burner


successful test of a well in the GOM. The well is located 175 miles [280 km] offshore, about 270 miles [435 km] southwest of New Orleans, in6,965 ft [2,123 m] of water. Targeting sands of theWilcox trend, the Jack 2 well was drilled to atotal depth of 28,175 ft [8,588 m] (right).

Initially proposed on the basis of seismicdata, this subsalt reservoir had to be thoroughlylogged and tested to ascertain the extent andquality of hydrocarbons contained within. TheChevron openhole formation evaluation programfor the Jack 2 well included an LWD suiteconsisting of gamma ray, resistivity, pressure anddirectional services. Chevron also called for acomprehensive suite of wireline tools, includinginduction, density, neutron, elemental capturespectroscopy, natural gamma ray spectroscopy,sonic imager, magnetic resonance, seismicimager, formation tester and a rotary sidewallcoring tool.

Although logging would aid in answeringquestions about depth, porosity, and gross andnet feet of pay in the reservoir, productionengineers were particularly concerned about theWilcox potential for low permeability, low oilgravity, low-GOR oil and the impact of thesefactors on the deliverability or commercialpotential of this prospect. Because of theseconcerns, this Wilcox reservoir was slated for along-duration flow test to thoroughly define thedeliverability of the reservoir.

Chevron assembled a project team withresponsibility for planning and conducting thewell test. Obtaining meaningful test results of asubsalt reservoir located some 20,000 ft beneaththe seafloor required 14 months of extensiveplanning and coordination between Chevron,Schlumberger and other technical serviceproviders. The core of Chevron’s project teamconsisted of reservoir, operations and completionengineers, plus a completion advisor and a welltest advisor, who reported to the Chevron Jackwell test superintendent.

To coordinate the efforts of eight individualSchlumberger services and the services of othertesting contractors, the Schlumberger Testingand Completion Project Support Group wascontracted. The Schlumberger project managerwas colocated with the Chevron well test team inHouston, and served as the single point ofcontact for all Schlumberger testing services. Atthe Schlumberger testing base in Houma,Louisiana, a senior operations coordinatorhandled logistics and oversaw the preparation,testing and qualification of massive amounts ofequipment bound for the Jack well. This same

operations coordinator would serve as theSchlumberger wellsite supervisor during theexecution phase of the Jack well test,coordinating the team efforts of 25 Schlumbergerand 10 third-party service personnel.

This comprehensive planning processidentified several areas of concern, especiallywith regard to the high bottomhole pressuresencountered at such great depths. Schlumbergermade several modifications to its completion andtest equipment to permit extended operation athigh pressures. Until this time, most of thedownhole equipment was rated to 15,000 psi[103 MPa]. Among the downhole equipmentdeployed on the Jack well were IRIS downholetest tools and high-resolution pressure andtemperature memory gauges. A specially modi -fied 7-inch PowerFlow slug-free big hole tubing-conveyed perfo rating gun system complementedan eFire electronic firing head system that wasdesigned for this job. All of this equipment wasupgraded to withstand 25,000-psi [172-MPa]working pressures. On the well test, these toolswould be spaced out beneath a SenTREE high-pressure subsea well control test tree that wasprecisely landed in the seafloor BOP stack. At the surface, a Vx multiphase flowmeter and PVT Express onsite fluid sampling and analysisservices were provided to augment thetraditional separator-based well testing suite.

The well was drilled to TD, cased andperforated using tubing-conveyed perforating(TCP) techniques. An upgraded eFire firingsequence was utilized to ensure that no misfiresoccurred because of pressure fluctuations in theannulus while tools were run in hole. The wellwas completed using a frac pack. Later, the welltest string was run in the hole. During the firstweek of the test, a Schlumberger reservoirengineer was on site to integrate data streamsand identify communication issues betweenservice lines of tools supplied by Schlumberger,Halliburton, ClampOn AS and iicorr Ltd.

The 33-day well test involved two flow periodstotaling 23 days, and two shut-in periods totaling10 days. During the test, Oilphase-DBR personnelcollected high-pressure, single-phase samplesupstream of the choke, and low-pressureseparator samples. The PVT Express analysisservice performed real-time fluid analysis onthese samples, and the results of this analysiswere used on site to improve the fluidcorrelations of the Vx flowmeter. Aided by inputfrom PVT Express fluid analysis, the Vx multi-phase flowmeter provided precise and discreterate measurements that were vital to several keyreal-time analyses performed by the Chevronengineering staff.

58 Oilfield Review

> Preparing to test. The Jack 2 well, originally drilled by the Discoverer Deep Seas drillship, wascased and suspended before moving in the Cajun Express semisubmersible rig for the extended welltest. Barges were brought in beforehand to collect fluids produced by the test.


Spring 2007 59

The Jack well test was no normal well test.Under normal well test conditions, real-timepressure measurement and analysis areadvantageous, but with daily costs exceedingUS$ 750,000 for the Jack well, they wereindispensable. Critical decisions associated withtiming and forward planning were regularlyaddressed, based on input from the surfacereadout of bottomhole pressures. Without thisreal-time data, conservative approaches wouldhave been employed, resulting in considerablymore days on location.

An important unknown for the Jack well wasmaximum safe drawdown pressure. Throughpreliminary studies, an aggressive target was set,and this target was predicated on actual well testbehavior derived from bottomhole pressurereadings. Without such pressure readings, real-time plotting of diagnostics could not havebeen carried out. Lacking these readings would have forced a more conservative testingprogram, resulting in lower tested rates andlonger test periods.

A near-constant stream of bottomholepressures also allowed for real-time pressure-transient analysis. This analysis was critical, notonly during buildup portions of the test, but alsoduring flowing periods. With real-timebottomhole pressures and instantaneous flow-rate data from the Vx multiphase flowmeter,Chevron engineers were able to correlate ratechanges with pressure readings and performaccurate type-curve analysis on flowing datausing superposition. When observing pressure-transient signatures associated with the well'scompletion, it was helpful to see these trendsdevelop during flow periods as precursors to thecleaner real-time buildups. Chevron estimatesthat buildup durations were reduced by as muchas 27 days through access to real-timebottomhole pressure data.

Though Chevron tested only 40% of theestimated 350 ft [107 m] of pay, the well flowed ata rate of 6,000 barrels [954 m3] per day. The 33-day test was the longest drillstem test everconducted under these severe conditions withtest equipment at depth. In fact, more than ahalf-dozen world records for test equipmentpressure, depth and duration in deep water wereset during the Jack well test. For example, theperforating guns were fired at world-recorddepths and pressures. Additionally, the subsea

test tree and other DST tools set world records,helping Chevron and co-owners conduct thedeepest extended DST in deepwater Gulf ofMexico history while opening greater possibilitiesfor new finds in the deepwater arena.

Data Integration and InterpretationThe behavior of reservoir fluids and theirinteractions with reservoir rock, and completionand production systems must be thoroughlycharac terized to produce a reservoir efficiently.This characterization is accomplished throughreser voir modeling, and well test data provide adriving force for running model simulations.

Reservoir models are developed on aframework of geophysical, geological andpetrophysical data. Dynamic well test data areintegrated into this static framework to simulateand predict reservoir behavior. Data fromdescriptive well tests are particularly useful indetecting heterogeneities, permeability barriers,structural boundaries, fractures, fluid contactsand gradients that can be incorporated into the model.

Once a reservoir model is built, it is cali -brated by comparing results of a test simulationagainst measured data to check its parameters.To achieve a good match between real andmodeled data, the operator may need to fine-tune certain assumptions in the modelconcerning the well and its reservoir, such aspermeability or distance to a fault, or other such parameters.

Production histories from wells in this fieldare then entered into the model. Anothersimulation is carried out to model pressures atthe wellbore and across the reservoir. Simulation-derived fluid ratios and wellbore pressures arerun through a history-matching process forcomparison with measured production ratios andpressures. It is not unusual for initial results todisagree, in which case the model parameters areagain changed. This iterative procedure contin -ues until a good match is obtained between actualand simulated results. The reservoir model canthen be used in predicting future production, welllocation and completion scenarios.

Well test pressures, flow rates and fluidcompositions are also important criteria for nodalanalysis. These data can help the operator analyzefluid movement from the outer boundary ofproduction to the reservoir sandface, acrossperforations and up the tubing string, past thechoke and out to the separator. Using nodalanalysis, an operator can evaluate flow rate versuspressure drop along each node in the system and

determine whether well production is constrainedby its reservoir, downhole completion or surfaceproduction system.

But perhaps one of the most useful applica -tions of well test data is achieved throughpressure-transient analysis. By generating a log-log plot of measured pressure over time, whenplotted along with the derivative of changingpressure, analysts are able to study pressurechanges in great detail. The derivative of thepressure change provides a characteristicsignature of reservoir pressure response to welltesting that can be interpreted in terms of flowregimes, boundaries, permeability, formationdamage, heterogeneities and reservoir volumes.

Well test data, when integrated into these and other advanced interpretation techniqueshelp production teams understand theirreservoirs and achieve their engineering andbusiness objectives.10

Shaping the futureThe field of well testing has changed dramati-cally since its earliest days in the 1920s, and workcontinues apace in new sampling andmeasurement techniques.

With the advent of highly accurate Vxmultiphase well testing technology, introducedin the PhaseTester portable flowmeter and thepermanently installed PhaseWatcher fixedmultiphase well production monitoring device,the face of dynamic reservoir evaluation isbeginning to change. And these changes areaffecting the bottom line in well testing, throughreduced cleanup periods and improvedseparation and effluent processing. Vxtechnology will undoubtedly increase the rangeof applications for multiphase flowmeters. Thiswill open the way to different testing sequencesand interpretation software to fully exploit thedataset acquired through the new technology.

The shape and scope of well testing willcontinue to evolve as technology strives to fulfillnew testing objectives. — MV

10. For more on well testing and interpretation of test data:Schlumberger: Fundamentals of Formation Testing.Sugar Land, Texas: Schlumberger MarketingCommunications, 2006.


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