52 Oilfield Review A New Horizon in Multiphase Flow Measurement Ian Atkinson Bertrand Theuveny Cambridge, England Michel Berard Moscow, Russia Gilbert Conort Rosharon, Texas, USA Joel Groves Princeton, New Jersey, USA Trey Lowe Houston, Texas Allan McDiarmid Apache Energy Limited West Perth, Western Australia, Australia Parviz Mehdizadeh Consultant Scottsdale, Arizona, USA Patrick Perciot Clamart, France Bruno Pinguet Gerald Smith Bergen, Norway Kerry J. Williamson Shell Exploration and Production Company New Orleans, Louisiana, USA For help in preparation of this article, thanks to Alain Chassagne, Luanda, Angola; Dan Deznan, Apache Energy Limited, Aberdeen, Scotland; Richard Kettle, Ahmadi, Kuwait; Donald Ross, Rosharon, Texas, USA; Jon Svaeren, Framo Engineering AS, Bergen, Norway; Eric Toskey, Bergen, Norway; and Laurent Yvon, Douala, Cameroon. 3-Phase, LiftPRO, NODAL, PhaseTester, PhaseWatcher, Platform Express and Vx are marks of Schlumberger. A quiet revolution has taken place in the technology for measuring three-phase fluids at the surface. Advanced multiphase meters provide production and reservoir specialists with the data required to understand and optimize well performance without separating a flowstream into individual gas, oil and water phases.
Transcript
52 Oilfield Review
A New Horizon in Multiphase Flow Measurement
Ian AtkinsonBertrand TheuvenyCambridge, England
Michel BerardMoscow, Russia
Gilbert ConortRosharon, Texas, USA
Joel GrovesPrinceton, New Jersey, USA
Trey LoweHouston, Texas
Allan McDiarmid Apache Energy LimitedWest Perth, Western Australia, Australia
Parviz MehdizadehConsultantScottsdale, Arizona, USA
Patrick PerciotClamart, France
Bruno PinguetGerald Smith Bergen, Norway
Kerry J. WilliamsonShell Exploration and Production Company New Orleans, Louisiana, USA
For help in preparation of this article, thanks to Alain Chassagne, Luanda, Angola; Dan Deznan, Apache Energy Limited, Aberdeen, Scotland; Richard Kettle, Ahmadi, Kuwait; Donald Ross, Rosharon, Texas, USA; Jon Svaeren, Framo Engineering AS, Bergen, Norway; Eric Toskey, Bergen, Norway; and Laurent Yvon, Douala, Cameroon. 3-Phase, LiftPRO, NODAL, PhaseTester, PhaseWatcher,Platform Express and Vx are marks of Schlumberger.
A quiet revolution has taken place in the technology for measuring three-phase
fluids at the surface. Advanced multiphase meters provide production and reservoir
specialists with the data required to understand and optimize well performance
without separating a flowstream into individual gas, oil and water phases.
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Winter 2004/2005 53
A new surface flowmeter is fundamentallychanging the way we measure complex flow fromproducing wells. This transformation is driven bynew technology that accurately measures rapidvariations in three-phase fluids, including slugflow, foams and stable emulsions that previouslywere difficult to quantify. The capability tometer multiphase fluid in real time increasesoperational efficiency, saving both time and money.
It is now possible to allocate production with-out conventional phase separation and toovercome processing constraints, or bottlenecks,in existing surface facilities. Accurately quantify-ing individual fluid phases in a productionstream allows operators to make more informeddecisions about well performance. Engineers cannow better identify, understand and remediatemultiwell flow problems, optimize artificial liftoperations and build dynamic reservoir models.
This article discusses recent advances in multiphase metering and examines the use ofthis technology for permanent-measurement, artificial lift and mobile well-testing applica-tions, both onshore and offshore. Case histories from Australia, the Gulf of Mexico and Africa highlight the benefits of advanced measurement technology.
Conventional Separation and Well Testing Conventional test separators are scaled-downversions of the large production separators thatsegregate and measure gas, oil and water at
surface processing facilities. In established fieldoperations, test separators are permanent instal-lations. For exploratory and field-delineationwells, companies must deploy modular testseparators. Several test separators in series or parallel are sometimes needed to handlehigh-rate wells, heavy oils or condensate-rich—wet—gas.
Typically, test separators are cylindrical vessels that are deployed horizontally. These vessels vary from 15 to 30 ft [4.6 to 9.1 m] inlength, 8 to 13 ft [2.4 to 4 m] in height andweigh up to 10 tons [9,072 kg]. Separatorsreceive produced effluent from individual wellsand segregate the different fluid phases througha gravity-based process (above).
Two-phase vessels separate gas from liquids,and three-phase vessels further separate the liquids into oil and water. These systems meterthe separate fluid phases individually as theyleave the vessel before commingling and return-ing the fluids to a flowline. Normal operatingconditions for a test separator are limited topressures between 200 and 1,000 psi [1.4 and6.9 MPa] with maximum working pressures up to1,440 psi [9.9 MPa].
Test separators are not designed for specificwells, but instead must handle a wide range offlow rates. At the time of installation, test separators are often intentionally oversized toserve as backup or supplemental production separators and to accommodate future increasesin field output.
Obtaining reliable measurements from a testseparator requires relatively stable conditionswithin the vessel, which can take several hours.Well-test protocols associated with these unitsgenerally emphasize operational efficiency—aone-size-fits-all approach—rather than settingthe measurement instruments and controllingflow rates based on individual well conditions.Time constraints and personnel limitations oftenpreclude optimization of the separation process.
In addition, operating conditions sometimesprevent complete separation of the fluid phases.Some oil remains in the water, some water in theoil, some gas in the liquids and some liquids inthe gas. These conditions cause errors in separa-tor instruments, which are designed to measurestreams of single-phase gas, oil or water. Testseparators also have difficulty measuring certainanomalous flow regimes because of the need for stable processing conditions and the factthat response to dynamic flow conditions isalways delayed.
Problematic flow regimes include fluid slugs,in which one phase is interrupted by anotherphase; foams, which conventional separatorscannot handle; and stable emulsions thatrequire additional heat or chemical treatment toseparate the one phase that is suspended inanother. In addition, viscous fluids, such asheavy oil, make separation and accurate testmeasurements extremely difficult.
> Conventional separators and fluid measurements. Production separation begins with well flowstreamsentering a vessel horizontally and hitting a series of perpendicular plates. This causes liquids to dropto the bottom of the vessel while gas (red) rises to the top. Gravity separates the liquids into oil(brown) and water (blue). The gas, oil and water phases are metered individually as they exit the unitthrough separate outflow lines. Mechanical meters measure fluids; an orifice meter measures the gas.Both devices require periodic recalibration.
Pressure-reliefvalve
Secondpressure-relief
valveCoalescing
platesFoam breakerbaffle plate
Gas outlet to orifice meter
Mist extractor
Accessdoor
Oil-level controller
Vortex breaker
Vortex breaker
Oil outlet to mechanical meterWeir baffle plate
Water outletto mechanical meter
Water-level controller
Deflectorplates
Additionaloutlet
Effluent inlet
Multiphase MeasurementsUnlike conventional separators, multiphasemeters continuously measure gas, oil and waterflow without physically separating the flow-stream into individual fluid phases. Multiphaseflowmeters accept three-phase fluids directlyfrom a flowline, make measurements and imme-diately return fluids to the flowline (left). Thesemeters yield measurement results within min-utes of being placed in operation.1
Pressure drop across multiphase flowmetersis significantly less than for conventional separa-tors, which allows wells to be tested close toactual producing conditions. In permanentmetering applications, these devices have mini-mal footprints at surface locations or on offshoreplatforms. At this time, there are more than1,300 multiphase meter installations worldwide,reflecting sharp increases during the pastsix years (below left).2
Third-party testing and joint-industry projectshave helped prove multiphase measurement tech-nology. Developers of three-phase flowmetershave also demonstrated the effectiveness of thesesystems through extensive flow-loop testing. Aflow-loop test consists of accurately measuringsingle-phase fluids—gas, oil and water—in acontrolled environment, mixing them to create amultiphase stream and then flowing themthrough a multiphase meter.
Flow-loop measurement results are com-pared with the individual volumes of constituentfluids that formed the test flow.3 These testsassess meter performance over a wide range offluid mixtures and flow conditions. Meterperformance under anticipated field conditionscan be extrapolated from flow-loop test data.
Users conduct extensive testing of multi-phase flowmeters to qualify the systems forspecific field applications. Qualification isfrequently necessary because various meteringsystems react differently to changes in processconditions, such as flow rates, fluid properties,the presence of scale or paraffin, and sand orgas volumes in a flowstream.4
To date, there is no commonly accepted testprocedure. Project partners, government entitiesand other joint-interest owners must agree onappropriate qualification procedures each time ametering system is used to allocate, or apportion,commingled production according to ownership.However, several industry and regulatorybodies—the American Petroleum Institute (API),
54 Oilfield Review
> Multiphase flow measurements. Metering three-phase flow in wellbore tubulars or facility piping(left) requires continuous measurement of changing gas (g), oil (o) and water (w) compositions(Ag, Ao, Aw) and velocities (Vg, Vo, Vw). Advanced multiphase production monitoring units can beintegrated with facility piping (top right) or skid mounted (bottom right).
Ag
Ao
Aw
Vg
Vo
Vw
VgVoVwAgAoAw
======
gas velocityoil velocitywater velocityarea occupied by gasarea occupied by oilarea occupied by water
1,200
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1,000
800
600
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0
Year
Multiphase Meter Installations
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f Ins
talla
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1994 to 1996 1997 to 1998 1999 to 2000 2001 to 2002 2003 to 2004
Subsea
OnshoreOffshore
> The expansion of multiphase meter technology. Although multiphase meterinstallations began in about 1994, the estimated number of installationsincreased dramatically beginning in about 1999 (top). In permanent-measurement applications, these devices take up less space than conventionaltest separators (bottom).
Winter 2004/2005 55
American Society of Mechanical Engineers(ASME), Oil & Gas Conservation Commission(OGCC), International Organization for Stan-dardization (ISO), United Kingdom Departmentof Trade and Industry (DTI) and Norwegian Soci-ety for Oil and Gas Measurement (NSOGM)—aredeveloping guidelines for the application andqualification of multiphase flowmeters.5
In addition to flow-loop tests, testing underfield conditions is another means of qualifyingmultiphase flowmeter systems for specific appli-cations. Flowmeter performance is comparedwith measurements from test separators in afield where fluid composition, line pressure andflow rates closely approximate those of anintended application. Testing under actual fieldconditions often establishes a higher level ofacceptance for multiphase meter performance.6
However, field tests consume more time than typical flow-loop tests and tend to be more costly.It is also essential that operators pay close atten-tion to the calibration and operation of testseparators to ensure high-quality reference data.7
For subsea developments with wellheads, ortrees, and production-control equipment locatedon the seabed, field tests are often impractical.
In addition, flow-loop procedures may not becapable of replicating the extreme pressuresand temperatures prevalent in some projects,such as deepwater and ultradeepwater develop-ments. Often, the best option in these cases is to compare data from an accelerated program ofpostinstallation monitoring with conventionalsingle-phase process-stream data at exportpoints during monthly production testing.8
A New Flowmeter DesignBecause of the limitations inherent in conven-tional test separators, Schlumberger and FramoEngineering AS developed the Vx multiphasewell testing technology through the joint-venture company 3-Phase Measurements AS.This multiphase flowmeter system is applicablefor permanent installations, mobile testing andartificial lift optimization.9 Vx technology hasbeen qualified in more than 1,500 flow-loop testsconducted by third parties at five independentfacilities that generated about 5,000 flow-regimetest points.
The principal components of the Vx multi-phase flowmeter are a venturi meter equippedwith absolute- and differential-pressure sensors,and a dual-energy spectral gamma ray detectorpaired with a single, low-strength, radioactivechemical source to measure total mass flow rateand the holdups, or fractions, of gas, oil andwater (left).
Vx technology functions without the need foran upstream flow-mixing device, which mini-mizes the size and weight of the unit.10 Thesesystems have no moving parts and are essen-tially maintenance-free. In-line flow passesthrough an inlet into a short, straight length ofhorizontal pipe leading to an inverted tee with one horizontal end closed. This blind teepreconditions and directs the flow upwardthrough a venturi section in the Vx meter. Pressure is measured just before fluids enter theventuri and as the flowstream passes throughthe narrow venturi throat.
1. Letton W, Svaeren J and Conort G: “Topside and SubseaExperience with the Multiphase Flow Meter,” paper SPE 38783, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 5–8, 1997.
2. Mehdizadeh P: “Qualifying Wet Gas and MultiphaseMetering for Deep Water Well Allocations,” presented at the Deep Offshore Technology International Conference and Exhibition, New Orleans, November 30–December 2, 2004.
3. Mehdizadeh, reference 2.4. Mehdizadeh, reference 2. 5. State of the Art Multiphase Flow Metering, API
Publication 2566, First Edition. Washington, DC: American Petroleum Institute, 2004. Use of Subsea Wet-Gas Flowmeters in Allocation Measurement Systems, API Recommended Practice RP 85, API Upstream Committee, Subsea Equipment Subcommittee, Upstream Measurement Technical Advisory Group. Washington, DC: American PetroleumInstitute, 2004. Allocation of Gas and Condensate in the Upstream Area,draft version, Technical Report ISO/TC193/SC3/WG1.Delft, The Netherlands: Nederlands Normalisatie-Instituut (NEN), 2002. Amdal J, Danielsen H, Dykesteen E, Flølo D, Grendstad J,Hide HO, Moestue H and Torkildsen BH: Handbook ofMultiphase Metering. Oslo, Norway: The NorwegianSociety for Oil and Gas Measurement, 1995. Guidance Notes for Petroleum Measurement Under thePetroleum (Production) Regulations, Issue 7-Final Draft.London, England: Department of Trade and Industry,Licensing and Consents Unit, 2003.
6. Mehdizadeh, reference 2. 7. Hasebe B, Hall A, Smith B, Brady J and Mehdizadeh P:
“Field Qualification of Four Multiphase Flowmeters onNorth Slope, Alaska,” paper SPE 90037, presented at the SPE Annual Technical Conference and Exhibition,Houston, September 26–29, 2004.
8. Mehdizadeh, reference 2. 9. Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T,
Cosad C, Fitzgerald J, Navarro J, Gabb A, Ingham J, Kimminau S, Smith J and Stephenson K: “Advances inWell and Reservoir Surveillance,” Oilfield Review 14,no. 4 (Winter 2002/2003): 14–35.
10. Atkinson I, Berard M, Hanssen B-V and Segeral G: “New Generation Multiphase Flowmeters from Schlumberger and Framo Engineering AS,” presented at the International North Sea Flow Measurement Workshop, Oslo, Norway, October 25–28, 1999.
> Vx multiphase well testing technology. The venturi shape is based on theindustry standard. Absolute- and differential-pressure measurements aremade at the same location in the venturi throat. Nuclear-transparentwindows in the venturi allow gamma rays to pass from source to detectorwith negligible loss caused by the hardware, enhancing measurementaccuracy. The nuclear source is barium-133 with a half-life of about 10.5years. A flow computer provides sensor processing and flow-rate data plusmore than 30 other parameters at standard and line conditions. It storesmore than 200 well profiles that include well-specific fluid characteristics,enabling multiple wells to be flowed through the same meter.
Nuclear detector
Flow computer
Nuclear source
Differential-pressure
transmitter
Flow
Venturi
Pressuretransmitter
The dual-energy spectral gamma ray detectoris mounted on one side of the venturi section,directly across from a barium source, which emitsgamma rays at various energy levels—approxi-mately 32, 81 and 356 keV. The detector measuresradioactive count rates, which are related togamma ray attenuation through the fluid mixtureat the 32- and 81-keV energy levels.11 The higherenergy level chiefly measures mixture density,which is affected by the gas/liquid ratio; the
lower energy level corresponds to fluid composi-tion, which is influenced by the water/liquidratio (below left).
Because total mass flow rate and holdup aremeasured at the same time and same place—the venturi throat—the dual-measurementsystems in Vx meters evaluate the same flow.This configuration and stringent equations for the fluid dynamics associated with flow conditioned by a venturi throat provide a robust
measurement capability unaffected by upstreamflow regimes.12
The detector makes complete calculations ofgas, oil and water fractions every 22 millisec-onds, or slightly more than 45 measurements of fluid-mixture density and three-phase holdup per second.
The rapid sampling and measurement speedallow the flowmeter to derive the velocity of liquid and gas phases in a flowstream and tocompensate for high-frequency instabilities inthe venturi throat. As a result, the Vx meter canmeasure flow conditions caused by downholeconditions and surface piping, including slugflow, foams and emulsions (next page, top).13
The PhaseWatcher fixed multiphase well production monitoring service is the main permanent monitoring application of Vx tech-nology. This system is available with venturithroat sizes of 29 mm [1.1 in.], 52 mm [2 in.]and 88 mm [3.5 in.], depending on flow rate.14
For mobile well-testing applications, thePhaseTester portable multiphase periodic well testing equipment is available in 29-mm or52-mm throats. This compact system weighsabout 3,750 lbm [1,700 kg] and can be trans-ported easily on a truck, trailer or modular skid (next page, bottom). A gas-testing modulealso is available for permanent-monitoring andmobile-testing applications.15
Continuous Measurement Opportunities Multiphase flow measurements help allocateproduction among working- and royalty-interestowners or record volumes for custodial transferat pipeline stations or port terminals. This infor-mation is essential for project partners and alsofor governments, which have testing require-ments for accurate computation of taxes androyalty payments. For example, measurementsmight be made on a given well during a one-week period so the results can be extrapolatedto allocate production over a longer time.
56 Oilfield Review
> Gamma ray attenuation. Different fluids attenuate gamma rays to varyingdegrees. The high-speed detector produces a signature count rate over thehigher and lower energy bands that are a function of the measured medium(top). These count rates permit a triangular solution of phase holdup (bottom).For each phase, the ratio of high-energy count rate versus source strength,or empty pipe count rate, is plotted against the ratio of low-energy countrate versus source strength on an x-y chart. These points become theapexes of a triangle. Phase holdup is determined by the intersection of twolines inside the triangle. The first line represents the gas/liquid ratio (green);the second connects the 100% gas point to the oil/water ratio point (red).
Coun
ts
Low-energy peaks
High-energy peaks
Gas
40%
Oil
60%Water
High
-ene
rgy
peak
cou
nt ra
te
Low-energy peak count rate
17,500
15,000
10,000
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7,500
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032 KeV 81 KeV
Gas
OilDistilled water5% saline water10% saline water15% saline water
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11. Al-Asimi et al, reference 9. 12. Atkinson et al, reference 10. 13. Williamson J and Mehdizadeh P: “Alaska Regulatory
Guidelines for Qualification of Multiphase Metering Systems for Well Testing” paper SPE 94279, prepared for presentation at the 2005 SPE Western Regional Meeting, Irvine, California, USA, March 30–April 1, 2005.
15. Atkinson DI, Reksten Ø, Smith G and Moe H: “High-Accuracy Wet-Gas Multiphase Well Testing and Production Metering,” paper SPE 90992, presented at the SPE Annual Technical Conference and Exhibition,Houston, September 26–29, 2004.
> Multiphase flowmeter and separator data comparison. Continuous measurement data from amultiphase meter clearly identify the presence of periodic slug flows in the well. The data pointsfrom the test separator show that the separator may or may not detect these slugs, depending onthe frequency of data capture.
Gas
and
liqui
d fl
ow ra
tes
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er c
ut, %
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0
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100Multiphase meter
Gas, Mcf/D
Liquid, B/D
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Conventionalseparator
Gas, Mcf/D
Water cut
Liquid, B/D
> Periodic well testing. The PhaseTester portable multiphase periodic well testing system can beskid-mounted for transport to onshore wellsites on the back of a small truck or as a modular packagefor crane lifts onto offshore platforms. The PhaseTester unit is significantly smaller and more compactthan temporary conventional test separators.
Test-separator data also provide a basis forproduction optimization strategies. However, asfield developments progress and more wells goon stream, test-separator capacity often becomesinadequate, and production has to be deferred toperform well tests (above). These limitations area disincentive to test wells more often than commercially or legally required.
A similar situation arises when new productionis added, such as completing previously bypassedzones or performing remedial treatments in exist-ing wells, or when implementing pressure-maintenance and enhanced recovery methods. Inthese cases, bottlenecks at test separators limitfield evaluation and production optimization.
Adding separation capacity is one option, buta single separator costs up to US$500,000. Installation of a multiphase flowmeter costsabout 40% of that amount. Multiphase meteringsystems do not store, separate or treat flow-streams, but instead measure fluids under in-lineconditions and return them immediately to aflowline. This eliminates process bottlenecks.
In some cases, multiphase meters allowoperators to convert test separators for use asproduction separators. This added capacityincreases field production rates and enhancesoperational flexibility. Positioning multiphaseflowmeters next to a flowline and operatingthem with a minimal pressure loss allow meter-ing at conditions that are close to the actualfunctioning point or production setting of eachwell. Another application for multiphase flowmeasurements is the subsea environment.
The PhaseWatcher subsea systems providesubstantial cost savings through down-scaling orelimination of surface well-testing facilities andsubsea test lines (next page, top). Since test sep-arators cannot be deployed in this setting, surfacemeasurement of production from subsea wellsrequires the installation of expensive subsea testlines. In addition, platform-based facilities oftenhave insufficient capacity for subsea wells to betied into existing topside test separators thatwere initially designed to accommodate only theproduction from platform wellheads.
Platform facility expansions may not be anoption because of space or economic limitations.Furthermore, long subsea test lines increase separator stabilization times, hampering the abil-ity to track dynamic producing conditions fromthe surface and reduce well-testing frequency.Commingled production from several subseawells obscures individual well performance.
If commingling occurs through a subsea pro-duction manifold with no test line, measuringindividual well performance requires “testing bydifference.” This means periodically shutting in one of the wells while measuring the othersand eventually deriving individual well data by inference. Deferred production and pooraccuracy inevitably result.
Reducing bottlenecks is not always the majorjustification for installing permanent multiphaseflowmeters. Sometimes the problem is acces-sibility. This is true of unmanned offshoreplatforms and certain remote onshore wells.Wells located far from the nearest productionbattery with a test separator may be tied directlyinto a flowline and commingled with productionfrom other wells, especially if the wells are notmajor producers.
The only way to measure multiphase flowfrom these wells is testing by difference. As apractical matter, some wells may never betested. However, planning, designing and bring-ing new wells on line with permanentmultiphase monitoring offer new possibilities forobtaining additional data about gas, oil andwater flow from development wells, includingthose in remote locations.
Multiphase metering systems increase well-testing frequency, but also enhance measurement quality. Flow from some wells is sounstable that it cannot be measured accuratelywith a conventional test separator. Multiphaseflowmeters are more accurate than conventionaltest separators and are less affected by complexflow regimes (next page, bottom).
Multiphase measurements also identify phaseconditions that might not be detectable by theexclusively volumetric measurements of conven-tional test separators. Furthermore, unlike testseparators, multiphase flowmeters have no moving parts and associated maintenancerequirements to maintain measurement accuracy.
Multiphase flowmeters enhance operationalsafety by eliminating the need for high-pressurevalves and relief lines. Also avoided is storage ofsubstantial volumes of hydrocarbons under potentially unstable conditions in test separa-tors. This is an important issue if well testingtakes place in environmentally sensitive areas.
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> Undersized test separators. As operators increase well flow rates with larger choke sizes (red),there are significant differences between the liquid flow rates measured by a multiphase flowmeter(green) and a conventional test separator (blue). At high rates, test separators that are too small oftenfail to achieve complete separation. A large amount of liquid remains in the gas and is no longermetered with the liquids. Separator operation can even become unstable and have to be bypassed,resulting in short periods of zero flow. Correlation between liquid rates measured by the multiphaseflowmeter and choke settings provides confidence in the quality of flow-rate measurements.
Moreover, there are no fluid-disposal problemsassociated with multiphase flowmeters, whichenhances safety and environmental protection.
Multiphase flowmeters not only eliminateobstacles to greater measurement consistency,reliability and quality, but the measurement process itself essentially becomes a continuousmonitoring function. Even when wells are notmetered all the time, measurements are typically more frequent and conducted overlonger time periods.
Because of this, operators are now obtainingdynamic multiphase flow data. This ability toobserve in-line multiphase flows over anextended period in real time affords a step-change improvement in the quantity and qualityof data available for production-optimizationdecisions. The PhaseWatcher unit can interfacesecurely with the Internet to allow monitoringand remote decision-making about well and fieldoperations from anywhere in the world.
Multiphase flowmeter data allow operators todetermine whether wells are flowing as expectedand whether to schedule remedial workoversbased on individual gas, oil and water productionrates. If field production is limited by bottle-necks in surface gas- and water-handlingfacilities, multiphase flowmeters help identifywhich wells to optimize and which to choke back.
Another significant optimization opportunityinvolves artificial lift operations, typically whereelectrical submersible pump (ESP) or gas-injection systems lift fluids to the surface. TheSchlumberger LiftPRO service for improvingunderperforming artificially lifted wells addressesthis need, with applications for both permanentmeasurement and periodic mobile testing. Individual wells can be monitored with multi-phase flowmeters, while pump or gas-injectionrates are separately monitored by differentinstrumentation to identify optimal levels.
Optimizing Artificial Lift OperationsApache Energy Limited used the PhaseWatcher system to optimize artificial lift operations while developing offshore fields in Australia. TheVx system achieved several important objectives,including reduced capital and operating expen-ditures, and improved production allocation andfield management.
> Subsea flowmeter. The PhaseWatcher subsea monitoring unit is lowered to seafloor for installationon a wet production tree or in a manifold (right). This system significantly reduces field-developmentcosts by eliminating surface testing facilities and subsea test-line installation (left).
Venturi
Nuclearsource
Nucleardetector
> Testing the untestable. Multiphase flowmeters can test wells that previouslywere difficult or, for practical purposes, impossible to test. Data from a typicalwell with slug flow show the oil rate abruptly rising from 1,000 B/D [159 m3/d]to more than 6,000 B/D [953 m3/d], conditions that conventional separatorscannot accurately measure because response time is too slow. In addition toslug flows such as these, multiphase flowmeters can measure flows consistingof foams and emulsions that also pose essentially untestable conditions forconventional separators.
7,000
6,000
Oil slugs
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00
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Tota
l oil
rate
, B/D
Time, hours4 6 8 10 12
A key element of these development effortswas the installation of five unmanned platformswith minimal facilities with no processingcapacity, and therefore no topside separation(below). Production from each platform wascommingled into a single production flowline,which required accurate measurement of
each component fluid in the flowstream. Wells in each field are produced using a common gaslift system.
Web-enabled PhaseWatcher metering at eachwellhead allowed Apache to quickly optimize gaslift and production systems, and make immedi-ate operational adjustments in response tochanges in choke settings or well productivity.
This eliminated the waiting period for inventorytank flows to stabilize, which is necessary with atest separator.
The optimization process began during wellcleanup, so the Vx systems provided continuousproduction monitoring. Wells reached their target rates within hours of startup. Multiphasemonitoring also helped eliminate productioninterruptions by immediately identifying risingwater cuts and slug flows, which enhanced theability to maintain a stable production process.Rapid identification of dynamic flow factors by the PhaseWatcher meters improved well diagnostics on a continuing basis.
By equipping each flowline with a multi-phase meter, Apache eliminated the need for atest separator in the field production systems. Atabout 815 lbm [370 kg], the PhaseWatcher systems represented nearly a 90% weight savingscompared with the alternative of conventionaltest separators that weigh about 3.5 tons[3,175 kg] each, excluding structural supportand utility components.16
This weight reduction helped minimize capital expenditures, which were further reducedby limiting the size of platform structures and theextent of piping. Still other capital savings inlogistics resulted from this structure minimiza-tion. The reduced size, weight and complexity ofthe topsides for each platform allowed transportto the loadout site by road in a single trip.
Elimination of test separators and minimalmultiphase flowmeter maintenance also reduceoperating costs. Remote operating capabilitiesachieved by integrating metering and telemetrysystems further minimized the need for intrusivemaintenance and personnel visits. Installationof multiphase meter systems played an impor-tant role in optimizing gas lift operations andreducing capital and operating expenses, criticalobjectives in the development of these fields.
Improving the Allocation ProcessRegulatory and petroleum industry bodies, includ-ing the United States Minerals ManagementService (MMS), API, ASME, Norwegian PetroleumDirectorate (NPD) and United Kingdom DTI, recognize the role of high-quality data frommultiphase meters for well testing and are devel-oping standards for this equipment. As a result,multiphase flowmeter technology is increasinglyused for allocating oil and gas production.
New deepwater projects increasingly reflectdevelopment strategies with a processing hubthat receives production from one or more satellite reservoirs with subsea completions. Thenumber of outlying fields often increases as newdiscoveries are developed and tied directly orindirectly into the host facility (left).
60 Oilfield Review
> Optimized gas lift. These unmanned miniplatforms were among several such facilities offshore Australia where Apache Energy Limited installed thePhaseWatcher multiphase metering system. PhaseWatcher technologyallowed Apache to optimize gas lift operations, while saving capital andoperating expense.
> Deepwater satellite development strategy. A production hub, or host, facility receives additionalproduction directly or indirectly through subsea manifolds from one or more satellite fields withsubsea wells. As this scenario evolves, bottlenecks in test-separation capacity result in less frequentwell testing and lower quality measurements as flow distances increase. Multiphase flowmetersystems eliminate these bottlenecks, which improves measurement quality and allows wells to betested as often as needed. These factors improve production allocation and increase opportunitiesto optimize production.
Satellite field subsea wells
Satellite field subsea wells
Subsea manifolds
Production hub
Winter 2004/2005 61
For these types of developments, allocationis often more complex because ownership maybe different for each field or reservoir. The useof hub-based test separation for multiphase flowmeasurements can become increasingly prob-lematic. First, there is the issue of test separatorsize and weight, which affects host-facility costand operating parameters, such as number ofplatform wellhead slots and operational safety.
In addition, expansion of production throughsatellite tie-ins can cause well-testing demandsto exceed test-separator capacity and availability,resulting in less frequent testing of individualwells. Adding separation capacity at a hub isoften impractical or impossible. Furthermore, asdistance from the wells to a hub increases,metering and measurements with test separatorsbecome more difficult.
Stabilization time for test separatorsincreases when test lines are longer. Long sub-sea test lines can mask well-flow dynamics andcontribute to slug flow as water accumulates inlow points along their path. As the availabilityand effectiveness of test-separation facilitiesdecline, so does the quality of data obtained for allocation and production optimization.17
By contrast, multiphase flowmeter systems eliminate concerns about measurement qualityand well-test frequency.
The number of multiphase flowmeters currently deployed in deepwater developmentsis small, but their effectiveness for improvingproduction allocation creates potential deep-water applications. Multiphase meters can beeconomically designed into new productionfacilities as satellite fields are developed. Inlight of these factors, Vx technology becomes apractical necessity in many offshore develop-ments and essentially an enabling technology forsome deepwater projects.18
Allocation Measurements at Offshore HubsShell installed the PhaseWatcher system at theGulf of Mexico Auger complex to overcome test-separation bottlenecks and related alloca-tion difficulties resulting from productiongrowth. Several subsea fields in the area had been tied into the Auger complex for production processing.
The Auger field produces from a tension-leg platform (TLP) that began operation in 1994with the capacity to process 50,000 B/D[7,950 m3/d] of oil and 140 MMcf/D [39.6 million m3/d] of gas from direct-vertical-access (DVA) wells. As development activitiesprogressed, production soon exceeded expectations. The Auger TLP facilities wereupgraded and expanded.
In addition, the development of severalnearby subsea fields led to a series of tiebacks atthe Auger platform in 2000, 2001 and 2004. Thistransformed the Auger facilities into a productionprocessing and export hub that today handlesproduction from six different fields (above).
Through the various tiebacks and expansions,processing capacity more than doubled, and thefacilities network became more complex.Because of limited test-separator capacity andthe complexity of measurement and allocationneeds, well testing began to require productiondeferment and downtime on some wells. This further increased susceptibility to a system shutdown. With platform space at a premium,adding separation capacity was both difficult and expensive.
By installing four multiphase flowmeters,Shell reduced both flow interruptions and theneed to divert and defer production because ofwell testing. Utilizing Vx technology in a continu-ous producing environment provided a simplerconcept for new subsea production wells. Shellinstalled six additional PhaseWatcher meteringdevices on incoming production flowline tiebacksand the DVA production manifold. This allowscontinuous flow-rate monitoring of subsea flow-lines without the need for individual separators.
The use of multiphase flowmeter technologyat the Auger complex led to MMS approval ofthis technology in combination with NODAL production system analysis for measurementand allocation applications.19 Multiphase meter-ing solved important problems at the Augerplatform and established an economic means ofmeasuring future production at this hub facility.
Improving Onshore Development Planning In North Africa, surface facilities for five satelliteoilfields are located on 12 onshore well padsspread throughout the development area. Pro-duction is allocated among various partnersbased on the ownership and royalty percentagesof each company.
The operator faced difficulties planning forfuture development because of increasing com-plications associated with integrating new wellsinto the existing test-separation system and thehigh costs of expanding that system. Test-separa-tor operation periodically caused significant pressure losses in the surface gathering systemthat required the use of field compressors tocompensate for these losses. Gas flaring wasoccasionally necessary to control the resultingpressure increases.
16. The weight figure applies to a Vx metering system withan 88-mm [3.5-in.] diameter venturi throat. A smallerdiameter version of the system was also used in some of the applications.
17. Mehdizadeh, reference 2. 18. Mehdizadeh, reference 2. 19. An analytical tool for forecasting the performance at
various points, or nodes, in a production system, NODALanalysis is used to optimize well-completion and surfacefacility designs, maximize well performance and reservoir deliverability, identify restrictions or limitationsin the system and improve operating efficiency.
> Subsea field-development strategies. Higher-than-anticipated production at the Shell Augerplatform in the Gulf of Mexico led to facility expansions, followed by a series of tiebacks from nearbysubsea fields that required additional facilities. This transformed the Auger facility into a high-volumeprocessing and export hub. Multiphase flowmeters helped eliminate costly bottlenecks at the Auger hub, enabling Shell to economically meet complex measurement and allocation needs.
Pink sand development,
1995
Facility expansions,1995, 1997 and 2000
Peak production, 1998 to 2000
Macaroni field,first subsea tieback, 2000
Satellite field exploration
Cardamon fielddiscovery, 1996
Auger field production
Time
The Auger Transition to a Subsea Host
Serrano and Oregano fieldtiebacks, 2001
Auger hub processing
Habanero and Llano field
tiebacks, 2004
Firstproduction,
1994
The operator installed a series of 12 PhaseWatcher multiphase metering systems,including 52- and 88-mm meter sizes, throughoutthe field. Seven of the meters were dedicated tofiscal allocation and five to well testing for reser-voir management. Key specifications for the newmeters included internal data storage, directlinkage to a service computer and compatibilitywith the existing supervisory control and dataacquisition (SCADA) systems. The operatorimplemented the Vx Fluid ID module with a set of field-specific fluid property data loadedinto the meter setup parameters. The deploy-ment of Vx meters simplified field developmentplans considerably.
The first four PhaseWatcher systems weredelivered and commissioned in October 2004.The site-acceptance process incorporated sev-eral field tests to evaluate meter performance.To date, the Vx systems have proved highly accurate with demonstrated measurementrepeatability. By using these meters, the opera-tor avoids production pumping and flaring.Delivery and commissioning of the remaining Vx multiphase flowmeter systems were slated for the end of 2004 and early 2005.
Streamlining Field InfrastructureAt another North Africa location, several partnershold working interests in three satellite fields,which are being developed and tied back to a cen-tralized host production facility. Installation ofPhaseWatcher 52-mm multiphase well productionmonitoring systems achieved considerable costsavings by eliminating the need for remote sepa-ration and metering stations (above).
To address a growing need to improve multi-phase flow measurement for production andfiscal allocation, and for field optimization, Theoperating company commissioned the firstPhaseWatcher metering system in August 2003.This meter initially allocated productionbetween the partners in Well 1 during develop-ment of the first field. Six months later, theoperator brought Well 2 on stream through thesame meter. The two wells are about 7.5 miles[12 km] from the main gathering station.
The PhaseWatcher monitoring system savedan estimated US$10 million by eliminating theneed for an intermediate field station. Numerousfield tests compared meter performance againstconventional measurements made by three third-party test separators and associated gauge tanks.Results indicated a maximum difference of lessthan 1.7% with daily oil production rates thatranged from 4,500 to 6,000 B/D [715 to 954 m3/d].
Based on this record, a second, identicalPhaseWatcher device was installed in January2004 to meter two wells in the second field. Per-formance has been comparable to the initialsystem. A third PhaseWatcher 52-mm flowmeterwas commissioned in November 2004 to monitor production from the third field. Data from thismetering system facilitate operation of a wellequipped with an intelligent completion thatincorporates four downhole flow-control valves.The second well in this field is scheduled tocome on stream in 2005 and flow through thesame meter.
Mobile Testing OpportunitiesMultiphase flowmeters have transformed perma-nent flow measurement and are also creatingnew opportunites in mobile and periodic welltesting. In many instances, it is uneconomic toretrofit existing production wells with perma-nent multiphase flowmeters. The PhaseTestermobile system acquires the same high-quality,dynamic data as the permanent PhaseWatchersystem. Measurements can be obtained relatively frequently, which is an ideal solutionin locations where multiphase flow data were previously obtained infrequently or not at all.
For the first time, there is no overridinglogistical or technical obstacle to testing anyproduction well an operator needs to evaluate. Production wells can be tested at any time, but apotentially advantageous time for mobile testingis during the cleanup stage just after drilling. Inthis way, testing can be integrated into thelarger package of well services to establish optimized production from the very beginning.
Additionally, by combining a full complementof downhole production-logging measurementswith the surface measurements of a multiphaseflowmeter, it is possible for the first time toobtain a complete well diagnosis. The mobilePhaseTester flowmeter plays an essential role indiagnosing the source of water encroachment incommingled producing wells.
62 Oilfield Review
>Minimal multiphase meter installation. The PhaseWatcher 52-mm production-monitoring system was installed in a North Africa field to streamline thesurface infrastructure for measuring and allocating production.
20. Mus EA, Toskey ED, Bascoul SJF and Barber EC: “Development Well Testing Enhancement Using a Multiphase Flowmeter,” paper SPE 77769, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, September 29–October 2, 2002. Mus EA, Toskey ED, Bascoul SJF and Norris RJ: “AddedValue of a Multiphase Flow Meter in Exploration WellTesting,” paper OTC 13146, presented at the OffshoreTechnology Conference, Houston, April 30–May 3, 2001.
21. A floating production, storage and offloading (FPSO) system is an offshore facility, typically ship-shaped, thatstores crude oil in tanks located within the vessel hull.The oil is periodically offloaded to shuttle tankers orocean-going barges for transport to receiving and processing facilities. An FPSO can be used to developand produce marginal reservoirs and fields in deep wateror remote from existing pipelines.
Winter 2004/2005 63
Cleanup Well TestingTotal used the PhaseTester system to performcleanup tests on subsea development wells in the deepwater Girassol field, Angola. The Vx system obtained complete flow data coveragethat was more accurate than with a conventionalseparator (right). Data obtained by multiphasemetering were instrumental in helping the oper-ator bring these wells on stream economically atplanned levels of production.
This approach ensured that the wells wouldflow as projected on a sustained basis, enhancedoperational efficiency, safety and environmentalprotection in well-testing operations, and avoidedthe need for a conventional test separator. Inaddition, multiphase flow data established a valu-able foundation for ongoing field and reservoirmanagement decisions.20
All wells had to reach optimal production levels as they came on stream to ensure that theprojected plateau for field production could beattained with the number of planned wells. Addi-tionally, flow-assurance considerations imposedelaborate startup procedures for these wells.
Each well needed to reach an immediate oil production level of 10,000 to 15,000 B/D[1,590 to 2,385 m3/d] to create a slug-free, stabilized flow in the subsea flowlines. At thesame time, it was necessary to maintain sand-control integrity through a graduated startupthat was not possible from the floating produc-tion, storage and offloading (FPSO) systembecause of equipment constraints and flowline-stability concerns.21
To perform these startups without risk to thewells required execution from the drilling rig.That meant setting strict limits on budgeted rigtime to control this considerable expense andidentifying any additional rig interventionsquickly. After the first two wells were thoroughlytested, all subsequent wells were allotted minimal cleanup time, and performance evaluations had to be completed during thecleanup stage.
The mobile PhaseTester system providedcontinuous flow-measurement data during wellcleanup that were unobtainable with conven-tional measurements. Dynamic flow-rate dataallowed the operator to optimize the cleanupperiod and avoid unnecessary rig time. The multiphase data confirmed the precise point atwhich fluids and debris were completelyremoved and unimpeded production was flowingfrom all wells.
The multiphase meter data formed the basisfor pressure-buildup interpretations that wouldnot have been possible with only test-separator
data. These interpretations led to key analyses ofwell and completion performance. Permeabilityand skin measurements derived from these pressure-transient data confirmed the selectionof sand-control completion designs in a numberof wells and facilitated the choice of tool-running procedures.
The data were also valuable for formation-evaluation and dynamic reservoir modeling,which, in turn, increased confidence in well-behavior predictions. In one case, using dynamicmultiphase flow measurements to track the estimated transient productivity index (PI) of ahorizontal well led to a timely decision to sus-pend and reenter the well, which had respondedpoorly to cleanup. After the intervention, the PIimproved dramatically to meet expectations,
>Mobile well testing. Total connected thePhaseTester system to a downstream choke and bypass valve during the cleanup phase afterdrilling and completing development wells indeep water offshore Angola, West Africa (top).The productivity index (PI) derived frommultiphase measurements on eight wells wasvalidated by subsequent PI calculations duringthe production phase (bottom).
Prod
uctiv
ity in
dex
(PI)
durin
g pr
oduc
tion
PI during well cleanup
and production logging confirmed that theentire horizontal section was producing.
Complete coverage of cleanup rates made animportant contribution to interference testingconducted prior to first oil in key areas of thefield. Monitoring production from one well during cleanup of a nearby offset well providedvaluable data about pressure and fluid trans-missibility through formation layers and geologicfaults (see “Reducing Uncertainty with Fault-Seal Analysis,” page 38).
These data led Total to revise the drillingpattern and eliminate one of the proposed devel-opment wells. Data from a multiphase flowmeterand downhole gauges also expedited decision-making that led to slickline and coiled-tubingintervention on another well, which opened apartially closed completion valve and allowedthe well to flow normally.
The multiphase flowmeter system improvedpersonnel safety by eliminating the test separa-tor with its safety valves and relief lines. Inaddition, multiphase metering reduced cleanupflow periods and hydrocarbon flaring, whichhelped protect the environment.
Future Multiphase Technology As utilization increases, multiphase flowmeterswill replace conventional separators in manywell-testing applications and eliminate the needfor costly, space-consuming facilities at someproduction sites. Future demand for conven-tional test separators will increasingly be drivenby fluid-sampling requirements. Some sampling,however, particularly for pressure-volume-temperature (PVT) analysis, will be performedwith multiphase flowmeters.
Technological innovations are likely to pushmultiphase flowmeters into higher pressure and temperature environments. This could significantly expand subsea applications for Vx technology, while spawning additional appli-cations onshore in heavy-oil thermal recoveryand in natural gas markets.
Another possibility for future growth is intelligent multiphase flowmeter systems that,in addition to providing flow-rate information,diagnose meter health and measurement quality. In all, growing demand and new insightsinto potential applications for multiphaseflowmeters are virtually certain to spur continu-ing, competitive innovations and enhancementsto meet new challenges. —JP/MET
