UPM 17050 SONAR-based Wellhead Surveillance for ……(MPFM) are intrusive and may be costly to...
Transcript of UPM 17050 SONAR-based Wellhead Surveillance for ……(MPFM) are intrusive and may be costly to...
Copyright 2017, Letton Hall Group. This paper was developed for the UPM Forum, 22 – 23 February 2017, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
Abstract
Production optimization and reservoir managementrelyinpartonperiodicsurveillanceofproducedoil,gasandwater flowratesof individualgascondensatewells.Flowmeasurementatthewellheadhasproventobechallengingdue toanumberof factors.Conventional (gravity-based)TestSeparators(CTS)andin-lineMulti-PhaseFlowMeters(MPFM)areintrusiveandmaybecostlytomobilize,nottomentiontheassociatedHSErelatedrisks.Forfieldswhereaccess and logistics pose a challenge, the deployment ofeither CTS or MPFM packages may require a significantamount of time. In some cases, the required well testfrequency may not be reached with the availableequipment or due to the increased number of wells inproduction.
This paper describes a convenient and cost-effective
approach to production surveillance of gas condensatewells using the non-intrusive SONAR-based Surveillancesystem. The system integrates the clamp-on sonar flowmeter(SONAR)withaPVTandmultiphaseflowenginetocalculate the properties of the produced fluids, and theindividual phase flow rates. The SONAR is amultiphase-tolerantvolumetricflowdevicethatprovidesthebulkflowrateofthefluidstreamwithintheflowline.ThePVTenginecalculatestheindividualphasepropertiesoftheproducedfluids, at the pressure and temperature conditionsmeasuredwheretheSONARisclamped-on.Themeasuredflowrateistheninterpretedintermsofoil,gasandwaterratesatboththeactualandstandardconditions.
ExamplesoffieldperformanceofSONAR-basedsystem
forthree-phaseproductionsurveillanceofgascondensatewellsarepresented.ThetestresultsshowthattheSONAR-basedsystemrepresentsareliable,safeandcost-effectivesolution for recurring production surveillance wherereservoirconditionsarerelativelystableovertime.
Introduction
Monitoringproducedoil,gas,andwaterfromindividualwells plays an important role in reservoir management.Acquiringtimelyandaccuratewellheadmeasurementscanbechallengingduetoarangeoffactors.Usingtraditionalwelltestseparatorsprovidesonlyperiodicmeasurements
and may result in deferred production due to pressuredrop.
While measuring dry gas flow measurement is well-
servedbyawiderangeofgasflowmeteringtechnologies,accurateandcost-effectivemeasurementofwetgasflowremainsachallengefortheupstreamoilandgasindustry.The paper provides a method to provide minimallyintrusive, clamp-on production surveillance for wet gasflowmeasurement.
Exprodevelopedaclamp-onnon-intrusiveproduction
monitoring system, Total Production Surveillance (TPS),designed to provide rapid and cost-effective wellheadsurveillance forawide rangeofapplications, suchasgasandgascondensatewells.Expro’sclamp-onSONAR-based(Sonar) flow meters, PassiveSONAR™ or ActiveSONAR™,operate effectively in multiphase conditions typical formost oil and gas applications. Therefore, they can beinstalled close to the wellhead, allowing accurate flowmeasurementonanindividualwellbasiswithoutinstallinganinlinedeviceordivertingproduction.
SONAR-basedFlowMeasurementTechnology
History. Sonar flow measurement technology was
introduced to the oil and gas industry in 2000, usingSONAR-basedpassive-listeningtechniquestoprovideflowrate and compositional information for downholeapplications(fiber-opticmeter).
In 2004, a clamp-on version of a strain-based sonar
meter (PassiveSONAR™)was introducedwithpiezo-strainsensors,providingsimilarfunctionalityastheoriginalfiber-optic-strain sonar technology with reduced cost andcomplexity. PassiveSONAR™hasbeenappliedtoawiderangeof flowmeasurementapplications, including singleandmultiphasemixtures,fromgas/liquidmixturestohighsolidscontentslurries.
In2009,ExproMetersintroducedtheActiveSONAR™,
based on the pulsed-array sonar technology, usingexternally generated acoustic pulses to “illuminate” thevortical coherent structures. The pulsed-array sonartechnologyallows themeasurementof lower flowrates
UPM 17050
SONAR-based Wellhead Surveillance for Gas Condensate Fields Gabriel Dragnea, Expro Meters Inc., Siddesh Sridhar, Expro Meters Inc.
Copyright 2017, Letton Hall Group. This paper was developed for the UPM Forum, 22 – 23 February 2017, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
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thanstrain-basedsonarflowmeters.TheActiveSONAR™meteriswellsuitedforGasandGasCondensatewellsinheavyschedulepipes.ExproMetersutilizesbothtypesofClamp-on SONAR flow measurement technologies toaddressawiderangeofflowlineconditions.
SONAR-basedFlowMeasurement.Sonar-basedflow
measurementsutilizeanarrayofsensors,alignedaxiallyalong the pipe, to characterize the speed at whichnaturallyoccurring,coherentflowstructuresconvectpastthesensorarrayusingsonarprocessingtechniques.Sinceboth single andmultiphase flows typically exhibit thesecoherent structures, the methodology is suitable for awiderangeofapplications.
Figure1showsthenaturallyoccurring,self-generated,
coherent structures characteristic for turbulent flow ofNewtonianfluids.Theturbulenteddiesaresuperimposedover the time-averagedvelocityprofiles andare carriedalongwiththemeanflow.Theseeddiesremaincoherentfor several pipe diameters and convect at, or near, theaverageflowrateinthepipe.
Figure 1: Sonar-based Flow Meters with Coherent
StructuresSonar flow meters use the convection velocity of
coherentstructures(eddies)todeterminevolumetricflowrate.Thesonar-basedalgorithmsdeterminethespeedofthesestructuresbycharacterizingboththetemporalandspatial frequencycharacteristicsof the flow field. Foraseriesofcoherenteddiesconvectingpastafixedarrayofsensors, the temporal and spatial frequency content ofpressure fluctuations are related through a dispersionrelationship,expressedasfollows:
k
Vconvectw
= (1)
Where, Vconvect is the convection velocity of the
disturbance,ωthetemporalfrequency(rad/sec),kisthe
wave number (defined as k=2π/λ) and λ is the spatialwavelength.
In sonar array processing, the spatial/temporalfrequencycontentofsoundfieldsaredisplayedusing“k-ω" plots in which the power of the sound field isdecomposed into bins corresponding to specific spatialwavenumbersandtemporalfrequencies(Figure2).Onak-ωplot, thepowerassociatedwithcoherentstructuresconvecting with the flow is distributed along “theconvective ridge”. The slope of the convective ridgerepresents the speed of the turbulent eddies, which isthenconvertedtovolumetricflow.
Figure2:k-ωplotwithconvectiveridgeSonarWetGasOver-readingCorrelation.Whenusing
the Sonar forwet gas flowmeasurement, the reportedflow rate is higher than the actual flow rate of the gasphaseofthemixture,similartothedP-basedflowmeters(Venturi,orifice,etc.).ThemagnitudeoftheSonarover-reaadingistypicallylessthanthatofthedP-basedmeters.
The over-reading of a sonarmeter is defined as the
ratiobetweenthereported flowvelocity (Vsonar)andthegassuperficialvelocity(Vsg):
sg
sonar VsonarORV
= (2)
Thefollowingempiricalcorrelationwasdevelopedto
characterize the over reading of pulsed-array sonarmeters for wet gas streams flowing in fully developed,horizontalflowlines:
DK
Dw
Slope– 11.57fps
Copyright 2017, Letton Hall Group. This paper was developed for the UPM Forum, 22 – 23 February 2017, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
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2
111 ÷÷
ø
öççè
æ
++÷÷ø
öççè
æ
++= mmsonar Fr
LVFFrLVFOR jb (3)
Where,LVF is the liquid volume fraction (LVF) and Fr
is the gas densimetric Froude number (Fr); β andϕ arecalibrationconstantsand
îíì
³<<-
=5.1 ,1
5.10.5 ,5.0
r
rr
FFF
m (4)
Total Production Surveillance System (TPS). The
system integrates the Sonar flowmeasurementwith anEquation of State (EoS) model for the Pressure,Temperature and Volumetric (PVT) properties of theproducedfluidsingascondensatewellsasshowninFigure3.
Figure 3: Schematic Total Production Surveillance
MethodologyWell bore composition is input by specifying
molecularcompositionofthewellborefluid.TheEoSPVTmodelcalculatesthepropertiesofthewellborefluidatthe location of the sonar meter using the measuredpressure and temperature. The model also calculatesmixture properties such as liquid volume fraction (LVF)andgasFroudenumber(Fr).Thoseparametersareusedinconjunctionwiththeempiricalcorrelationfortheover-reading of the sonar meter to correct the sonar flowvelocityof themixture in termsof actual gas flow rate.Oncethegasflowrateisdeterminedatactualconditions,theoilandwaterratesarethendeterminedfromthePVTmodel. The total mixture is flashed to standardconditions,andgas,oil(condensate)andwaterratesarereportedatstandardconditions.
AschematicofthethetypicalembodimentoftheTPS
systematthewellheadisshowninFigure4:
Figure 4: Schematic Total Production Surveillance
MethodologyTheover-readingcorrectionenablestheActiveSONAR
metertoreportgasratestowithin+/-3%for0<LVF<0.106and0.5<Fr<5.78.Figure5 illustratestheresultsfora4inSonartestedinthewetgasloopatCEESI,CO.
Figure5:Wetgasover-readingcorrection(4inSonar)
TPSSensitivitywithCompositionalParameters.SincedefiningthewellborecompositionisequivalenttospecifyingtheCGR(condensategasratio)andWGR(watergasratio)ofthegascondensatestream,theaccuracyofthecompositionalinformationwouldhaveadirectimpactontheindividualphaseflowratesinferredbytheTPSsystem.
Typically, the sonar-based surveillance relies on the
knowledge of the well bore composition from eitherhistorical well tests or/and fluid sampling. Therefore, abriefsensitivityanalysiswouldbebeneficialtoquantifythemagnitude of flow errors due to errors in compositionalparameters.
MultiphaseFlow&Compositional
Models
P,T
CompostionalInformation
Qoil
Qgas
Qwater
(ClientProvided)
VSONAR
Input
Measurements
Output
TPS1000SystemDiagram
©CopyrightExpro2011ExproMetersWELLFLOWMANAGEMENT
Copyright 2017, Letton Hall Group. This paper was developed for the UPM Forum, 22 – 23 February 2017, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
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Forsimplicity,theflowconditionsfromoneofthetrialspresentedhereinwereused(Table1).TherearetwoCGRvalues used for the analysis, 30STB/mmscf and70STB/mmscf, which are varied by ±20% each, whilekeepingthewatercut(WC)constant,at5%.Theneteffectof±20%changeinCGRisthatboththeoilandwaterflowratesshiftby±20%.
If the CGR is held constant (30STB/mmscf and
70STB/mmscf), andWC is varied by ±2% (absolute), thewater flowratechangesby±40%,which is similar to therelativechangeinWC.
Table1:TPSsensitivitywithwellcomposition
Theanalysisshowstheimportanceofhavingaccurate
compositional inputs in The TPS system in order for theinferred phase rates to be accurate. Therefore, thecompositional information shouldbeupdatedevery timethereisasignificantchangeinthewetgasparameters.
Fieldperformance
Inmanyplacesaroundtheworld,the localregulatorybodyrequiresthewellstobetestedatacertainfrequency,buttheexistinginfrastructuremaynotallowtheoperatorsto comply easily with those requirements. In mostinstances, it could lead to a significant increase of theoperatingcosts,especiallyfortheoffshoreandremotelandfieldswherephysicalaccessposeschallenges.
Oftentimes,thefieldpipinglayoutdoesnotincludethe
means(testseparators)totesteachindividualwellandtheproduction allocation becomes a serious issue for bothfinancialandtechnicalreasons.
Production surveillance and monitoring of individual
wellsusingtheclamp-onSONAR-basedTPSsystem,allowsoperators tomeasure the production of eachwellmorefrequentlyandwithoutdeferringproduction.Also,duetothe clamp-on design, the well production is measuredunder normal operating conditions, helping to identifyunderperformingwellsortheneedforworkover.
The test data from two gas condensate field trials ispresentedherein,oneoffshoreandtheotheronland.
OffshoreTrial.Theoffshoretrialwasconductedinagas
condensate field with two satellite platforms and oneproductionplatform.Thesatelliteplatformsareequippedwithproductionseparators,butnotestseparators.
The client was experiencing significant production
losseswhendivertingwellsthroughthetestseparatordueto backpressure effects. Additionally, the client waslooking to obtain production surveillance data at normalwell flowconditions,unaffectedby the limitationsof thetest separators. The client wanted to increase both thefrequency and efficiency of productiontesting/surveillance.
ElevenwellsweretestedonplatformsAandB:A1,A2,
A3,A4,A5,B1,B2,B3,B4,B5andB6,overa7dayperiod.
Figure6:Sonarflowmeter(6in)The flow data recorded by the flow meter was post
processed using Expro Meters' proprietary TPS1000software,alongwithwellheadpressureandtemperature(provided by client), a well stream compositionreconstructedwithCGRandWGR(watergasratio)valuesdeterminedfromtheApril2014welltestreport,toreportgas,oilandwaterratesatstandardconditions.
Well A5was tested before and after a facility layout
modification,aspartofanoptimizationscheme.Reviewofthe data for both tests (Pre- and Post- Modification)indicated that the flow measurement increased by 2.4MMscfdinthepost-testflowdata.
Well CGR Water Cut WGR Qgas Qoil Qw ater Qgas Error Qoil Error Qw ater ErrorSTB/MMscf STB/MMscf MMscfd STB/D STB/D % % %
U 30 5% 1.58 79.00 2370.0 124.824 5% 1.26 78.79 1891.4 99.3 -0.27% -20.19% -20.43%36 5% 1.89 79.17 2850.0 149.6 0.22% 20.25% 19.87%
V 70 5% 3.68 80.11 5607.7 294.856 5% 2.94 79.73 4464.6 234.4 -0.47% -20.38% -20.49%84 5% 4.42 80.50 6762.1 354.2 0.49% 20.59% 20.15%
W 30 5% 1.58 79.00 2370.0 124.830 3% 0.92 79.02 2370.6 72.7 0.03% 0.03% -41.75%30 7% 2.26 78.98 2369.4 178.5 -0.03% -0.03% 43.03%
X 70 5% 3.68 80.11 5607.7 294.870 3% 2.16 80.15 5610.6 173.1 0.05% 0.05% -41.28%70 7% 5.26 80.07 5604.7 421.1 -0.05% -0.05% 42.84%
Vsonar 75 ft/sPressure 1400 psig
Temperature 200 degFPipe Size 6in Sch 160
Sonar Wet Gas Sensitivity
Copyright 2017, Letton Hall Group. This paper was developed for the UPM Forum, 22 – 23 February 2017, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
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Figure7:SonarflowmeterresultsPlatformA
Figure8:SonarflowmeterresultsPlatformB.
The total3-phase flowrates for theAandBwells,as
reported by Expro Meters, have been compared to theproductionseparatorA(platformA),B1andB2(platformB)flowrates.ExproreportedgasratesfortheAwellswerewithin 3% of the A platform production separator rates.ThereportedgasratesfortheBwellswerewithin-3%ofthe B1 and B2 platform production separator rates. Thecondensaterateswerewithin4.5%,whilethewaterrateswithin12%forSeparatorB,whichmaybeindicativeofanincorrectWGR.
As a result of the trial, the client decided to employ
Exprotoperformthewellsurveillanceonaquarterlybasisandexpandthescopetotheentirefield.
Land Trial. The land trialwas conducted in a remote
highpressuregascondensatefield;thepressuresrecordeddownstream of the choke were between 1700psig and2150psig. The client was looking to increase well testfrequencyduetothelocalregulationsandpossiblyreducethecost.
Attherequestoftheclient,ExproMetersperformeda
wellhead surveillance trial on twowells: C1 and C2. TheTPS1000 softwarewas then used to provide single pointvolumetricflowrates(oil,gasandwater)onsite,basedonaveragevelocitymesurements.
ForwellC1,theSONARmeterwasinstalledonthiswell
forsixdays. Theflowdatawaspostprocessedusinglinepressure and temperature readings along with a
wellstream composition (CGR - 33.84 STB/MMSCF andWGR-0.94STB/MMSCF)providedby theclient.Thegasand condensate rates were within 4% of the separatorrates,whilethewaterwithin10%.
The SONARmeterwas installed onwell C2 for three
days.Theflowdatawaspostprocessedusinglinepressureand temperature readings along with a wellstreamcomposition (CGR - 47.1 STB/MMSCF and WGR - 8.715STB/MMSCF) provided by the client. The reported flowrates (gas, condensate water) were all within 3% of thereference.
Figure9:Sonarflowmeter(10in)wellC1.
Figure10:SonarflowmeterresultswellsC1andC2.Theclientiscurrentlylookingintowhatrequirements
need to be met in order to qualify the Sonar-basedSurveillance forgascondensatewell testingby the localregulatorybody.
Conclusions
Aclamp-onproductionsurveillancesystemdesignedtomonitorgascondensatewellswaspresented.Thesystememploysaclamp-onsonarflowmeterastheflowmeteringelement,integratedwithanEquationofStatePVTmodel.Intheapproachdescribedherein,producedoilandwater
Copyright 2017, Letton Hall Group. This paper was developed for the UPM Forum, 22 – 23 February 2017, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the paper may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.
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ratesareinferredfromthemeasuredgasrateusingauser-definedwellborecomposition.
Whencombinedwithaccuratewellborecomposition
data, the clamp-on production surveillance systemprovides a practical, cost-effective, real-time surveillanceofgascondensatewells.
Two field cases are presented illustrating the
applicationofthissystemtogascondensatewells.Thetwocases utilized historical well bore compositional data toprovide three-phase surveillance on a periodic or surveybasis.TheresultsforbothtrialsprovedthatSonar-basedsurveillance(TPS)isaviablealternativeforgascondensatewellheadsurveillance.
While the system measures variations of produced
liquids due to variations in gas production, it will notmeasure variations in CGR and/or WC. To account forchanges in CGR or/and WC, an updated well-borecompositionmustbeenteredintothesystem.
Traditional well testing approaches, such as CTS and
MPFM may require a significant amount of time to bedeployed in the field. The Sonar clamp-on approachrequires a shorter amount of time (about 90min) forinstallationandcommissioningwhichallowsthepossibilitytoperformmulti-ratetestingofthewellsormultiplewelltesting in one day. Therefore, the sonar clamp-onmethodology offers the opportunity to increase thewelltestfrequencyatafield-widelevelthusallowingabetterfield/productionmanagement.
The Sonar-based Surveillance is not to replace
traditional well testing methodologies, but to augmentthembyofferingaquick,reliableandcosteffectivesolutionfor applications requiring recurring productionsurveillance, especially where reservoir conditions arerelativelystableovertime.
AcknowledgementsTheauthorsgratefullyacknowledgeExproGroupforpermissiontopublishthisworkandacknowledgetheeffortsofourcolleagueswhohavecontributedtothispaper.Nomenclature
P CTS = Conventional Test Separator V MPFM = Multiphase Flow Meter T TPS = Total Production Surveillance V Vconvect = Convection velocity of turbulent eddies T ω = Temporal Frequency MPFM = Multiphase Flow Meter
T TPS = Total Production Surveillance V Vconvect = Convection velocity of turbulent eddies T ω = Temporal Frequency k = Wave Number λ = Wave Length T ORsonar= Sonar Wet Gas Over-reading V Vsonar = Sonar Velocity T Vsg = Superficial Gas Velocity T LVF = Liquid Volume Fraction Fr = Gas Froude Number β = Sonar Wet Gas Correction Constant T φ = Sonar Wet Gas Correction Constant V m = Sonar Wet GasCorrection Coefficient T EoS = Equation of State CGR = Condensate Gas Ratio T WGR = Water Gas Ratio WGR WC = Water Cut
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