SPE 136932 Pressure Transient Analysis: Characterizing the Reservoir and Much More BadrM.Al-Harbi,SPE,SaudA.BinAkresh,SPE,AbdulazizA.Al-Ajaji,SPE,andEdgarJ.PinillaForero,SPE, Saudi Aramco Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the 2010 SPE/DGS Annual Technical Symposium and Exhibition held in Al-Khobar, Saudi Arabia, 0407 April 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society ofPetroleum Engineers, itsofficers,ormembers. Paperspresentedat the SPE meetings are subject topublicationreviewbyEditorialCommitteeofSocietyofPetroleum Engineers. Electronicreproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not morethan300words;illustrationsmaynotbecopied.Theabstractmustcontainconspicuousacknowledgmentofwhereandwhomthepaperwaspresented.WriteLibrarian,SPE,P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract The development stage of any new field requires careful and full integration of all available data to ensure the robustness and flexibility of the development plans. One major source of information that adds a wealth of knowledge and reduces the number ofuncertainvariablesinanyfielddevelopmentisPressureTransientAnalysis(PTA).Whenusedproperly,thistoolcan provideaccurateinformationaboutreservoirheterogeneitiesandwellparameterssuchaspermeabilitythickness,reservoir features, skin, and productivity indices.This paper presents a comprehensive study where pressure transient analysis played a key role in detecting various reservoir featuresattheearlyphaseofafielddevelopment.Itfurthersharescaseswherepressuretransientanalysisconfirmedgood pressure communication across a layer that was thought of as a very tight layer. Also, the study participated in building a new realization of faults existence in the field. Many faults were removed from the field geological model based on insights from PTAandsomeotherdynamicdata.SomeothercasestudiesareincludedshowingthefullpowerofPressureTransient Analysis which added significant value to reservoir properties definition. Furthermore, this paper will shed light on the use of pressure transient analysis for fluid characterization proposes.Thestudiedreservoirhasaverycomplexnatureintermsofrockandfluidproperties.Both,therockandfluidvaryinthe lateral and vertical direction making rock and fluid characterization a very challenging task to be completed.Analysis of vintage and newly acquired well test data of this field played an important role in understanding the reservoir and helped fine-tune the development strategy. Integration of different data proved to be, yet again, a best practice to understand reservoirs and act accordingly Field History and Geological Background ThefieldisanoffshorefieldlocatedintheKingdomeofSaudiArabiacontainingsixArabianheavy-oilbearingreservoirs, whichareanonymouslyidentifiedinthisstudyasA,B,C,D,EandFreservoirs.Thefieldwasdiscoveredin 1957andproductionbeganwhenCReservoircameonstreamin1964.Itwasnotuntil1974whenBReservoirwas brought on production.Thestructureofthefieldisanorthwest-southeasttrendingasymmetricalanticlinewithslightlysteeperdiponthenortheast flankthanonthesouthwestflank.BandCarethetwomajorreservoirsinthefield.BothBandCreservoirswere deposited in a shallow marine environment and capped by regressive tight limestone and algal boundstone facies.TheBreservoirislocatedwithinaporouscarbonatememberontopoftheSulaiyformationofCretaceousage.Itis separated from the older C member by dense carbonates. The B reservoir averages about 250 ft in thickness. The lithology iscalcarenite,occasionallydolomitic.Rockpropertiesaregenerallyquitegood, the porosityinthe netrockaveragingabout 22-23%.The field is situated in a northwest-southeast trending anticlinal structure. During the geological past, in times of C and B and A this area geographically lay over on an extended Rimthan Arch between the separated major basins-Gotnia basin to the north and Arabia basic to the south. This arch served as an ideal platform for the high to moderate to low energy sediments to be deposited in super-tidal, fore beach and open lagoon environments. Some of the facies in the cored wells indicate that the cyclicity of sedimentation and pertain to shallower platform, inter-tidal and sub-tidal zones as well. Dominant reservoir rocks have been used to decipher the depositional environment. The regional setting allowed the oolitic grainstone to be deposited as the dominant reservoir facies during the C and B times, whereas during A times beach rock, detrital skeletal limestones 2SPE 136932 facies are common in cyclicity. The reservoir rocks are interrupted by wacke limestone cycles intermittently, providing some regional and localized markers for stratigraphic analysis. Bands of algal boundstones, cycles of onolitic grainstones and onolite with algal dominance, thin cycles of stramatoporoids do contribute towards reservoir porosities.The reservoir of interest in this study is B Reservoir. B Reservoir indicates a thickness of 220 ft in the southeast and 242 ft inthenortheast.Theooliticshoals ofthisreservoirareprobablydepositedinashallowmarineenvironment.Overthetime, suchfacieshavegonethroughaslow,transgressiveperiodthatallowsmuddysedimentstoformlocallywithindominantly high-energy and clean depositional environments. Discussion Data Availability and Quality:Welltestsdataof21wellswereavailableandthemajorityofthewellswereselectivelytestedmorethanonetime acrossdifferentreservoirintervals.Nearlyalloftheavailabletestsdataweresufficienttobeanalyzed.Tenofthe wellshadbuild-uptests,ninehadfallofftestsandtheremainingtwowellshadbothbuild-upandfall-offtests. Figure-1 shows the distribution of the tested wells. The distribution of the tested wells provided good coverage of the field which in turn helped attaining good full-field reservoir characterization. The pressure recording of most of the testswereattainedthroughmechanicalstraingaugeswithverylowsamplingfrequencyasshownin Figure-2.The lowsamplingfrequencyoftheusedgaugesresultedinmissingearlytimedatawhererapidpressurechangestook place. In general, matching drawdown periods with actual data add confidence in the simulated data. In this study, the datadoesnotincludethedrawdownperiodwithonlyasinglepressurepointrepresentingbottomholeflowing pressure.Finally,thebuild-updurationswererelativelyshort.However,alloftheselimitationswereovercomevia integration of other available data such as drilling and completion history, formation analysis log (FAL), production history and geology of the area. All of the conducted tests were performed while the wells were dry, for that, all the resultedpermeabilityfigureswererepresentativeofaverageeffectivepermeabilityforeachwell.Thesinglephase flow eased the permeability calculation keeping it away from the complication of relative permeability that is usually associated with multiphase flow. Transmissibility (Kh/) Distribution: PressureTransientAnalysiswasusedtogeneratethetransmissibilitydistributionmapforthefieldasshownin Figure-3.Thesizesofthebubblesrepresentthetransmissibilityvalues.Thefigureclearlydemonstrateshigher transmissibility values in the center side of the field and low transmissibility in the flanks. Reservoir Characterization i.The Tight Layer Slicing the B Reservoir, Does it Act As A Flow Barrier: The B reservoir contains a tight layer separating two good layers. This tight layer was thought of as a layer thatpossiblypreventspressurecommunicationbetweenthetwogoodlayers.Thistightlayerisextensive and can be mapped across the entire filed. However, the degree of its vertical tightness is not well identified.Pressure transient analysis has proved good pressure communication across this tight layer in the crest of the field.Figure-4&5showhowthistightlayerisidentifiedfromlogs.Itissimplyidentifiedbyhavinga uniform distribution of porosity while having a significant reduction in core permeability values. Figure-4 is for a well in the west while Figure-5 represents a well in the east. Three cases are discussed below, two for wells in the crest and one for a well in flank. Two cases of the three show how the pressure communication was proved in the crest of the field whereas the third case discusses the tight layer in the flank.Case 1: Well-A:Well-Aisaverticalwelllocatedinthecenterofthefield.Figure-6showstheFALofthewell whichincludesthreeperforationintervalsasthewellwastestedinthreedifferentperforations. Each perforation is across a particular sub-zone of the reservoir. The tight layer is located between themiddleandtopperforation.Thetestswereconductedbasedonatestdesigninwhicha downholeshut-intoolwasutilized.Thewellwasfirstacidizedandtestedacrossthelower perforation.Figure-7showsthelog-logplotofthistest.Thederivativecurvestartedwitha stabilization whichrepresentsthe flowcapacityacrosstheperforatedinterval.Thenthederivative experiencedadown-trendingslopethatlastedfortwologcycles.Afterthat,thelog-logcurve exhibit another stabilization representing the flow capacity of all B reservoir intervals. The lower perforationwasisolatedandthemiddleintervalwasperforated,acidizedandtested.Figure-8 displays the log-log plot of the build-up test across the middle interval. The log-log curve shape is identical with the shape of the log-log plot of the test conducted across the lower interval. It has two stabilizationswithonetransitionzoneinbetween.Thefirststabilizationisassociatedtotheflow capacity of the perforated interval and the second stabilization is associated to the flow capacity of theentireBreservoir.Again,thistestconfirmedverygoodhydrauliccommunicationbetween different zones of B reservoir. The third test is the most important one in terms of confirming the SPE 1369323 pressurecommunicationacrossthetightlayer.Themiddleperforationwasisolatedandthetop intervalwasperforated,acidizedandtested.Figure-9demonstratesthelog-logplotofthetest across the top interval. It is clear that it behaved just like the previous two tests which proves that thetightpermeabilitylayerisallowingpressurecommunicationacrossit.Figure-10gathersthe log-log curves of the three tests in one plot. It is crystal-clear that the derivative curves of bottom andmiddletestsareidenticalwhereasthethirdtesthadthesamebehaviorbutwithalittle difference in the speed of pressure communication. In other words, the third test took longer time to see the rest of B reservoir zones which concludes that the tight permeability layer does not act as a pressure barrier. Case 2: Well-B:Well-Bislocatedinthecrestofthefieldinanareawithveryhightransmissibility.Figure-11 showstheFALlogofthewellwhichclearlyindicatesverygoodporosityalongthewhole reservoir.Thewellwastestedacrossatwentyfeetperforationabovethetightpermeabilitylayer. Figure-12 presents the log-log curve of the test. A partial penetration effect is very apparent with a down-trending slope that represents spherical flow regime. This kind of flow regimes is observed in wells with limited entry completions. If the tight layer was indeed a flow barrier, then the spherical flow regime would not have developed on the derivative plot. Since this flow regime was actually observed,itconfirmedthatthereisgoodcommunicationwiththerestofthezonesbelowthe perforation.Case 3: Well-C:Well-C is located in the middle-west side of the field toward the flank. The FAL of this well is shown in figure-13.Thiswellwastestedtwiceabovethetightlayer.First,abuild-uptestwasconductedit followed by an acid wash job then a fall-off test. The discussion of these tests requires mentioning the factthatbothtestswereconductedabovetheoil-heavyoil-contactwhichbringsmorecomplicationto the analysis of the two tests. Figure-14 shows the log-log plot of the build-up test. It is dominated by a clear radial flow regime which represents an infinite acting homogenous reservoir. Unlike previous case (case-2), no partial penetration effect was observed from the pressure derivative which suggests sealing barrier from the tight layer beneath the perforation interval or low mobility effect from the heavy oil or both. Figure-15 shows the log-log plot of the fall-off test. It started with an up-trending slope that lasted for3logcycles.Thenitstabilizedatthesameflowcapacitylevelofthebuild-uptest.Figure-16 contains the overlay of both tests. This example explains very visibly the difficulties associated to tight layer identification in the flank of the field. The above shared cases established very well confirmation of the connectivity of different layers within the B reservoir in the crest of the field. Such information isvery vital to be known in the early phase of the field development in order to optimize the well placement and production scheme. ii.Low Transmissibility in Wells Tested Across the Heavy Oil Zone: Twowellsweretestedacrosstheheavy oilzone.Thetestsshowedverylowtransmissibilityandverylow injectivity/productivy indices. The tests are discussed in details below: Case 4: Well-C:Well-Cisdiscussedincase-3.Thewellwasperforatedintheheavyoilzone(20ftperforations). Figure-17showstheFALofthewell.Thequalityofthefallofftestdatawasnotgoodascanbe seeninFigure-18.Withthatinmind,theresultedtransmissibility(404md.ft/cp)wassolow comparingtooffsetwells.Themainreasonisthatthewellisinjectingwaterinsidetheheavyoil zonewhereastheothersareinjectingwaterinwaterzonesorlighteroilzones.Thislow transmissibility was reflected on the poor well injectivity (0.6 bpd/psi).Case 5: Well-D:Well-D is located in the middle-west side of the field, south east of the previous mentioned Well-C. Figure-19showstheFALofthewellandtheexactlocationoftheheavyoilzone.Onemajor challenge in this build-up test is the fact that the well could not sustain flow to surface. For that, the ratewasestimatedutilizingtherecoveryofthetubingvolumeduringtheflowingperiod.The quality of the data was poor as can be seen in Figure-20. The analysis revealed a transmissibility of 344 md.ft/cp and a very low productivity index of 0.38 bpd/psi.Case-3 and 4 show that there is some transmissibility across the heavy oil zone which in turn, adds up to the field and reservoir understanding as a whole.

iii.Mobility Effect on Wells Tested for Injection Above Oil-Heavy Oil-Contact Inthissection,adiscussionofthemobilityeffectonthewellsthatwereInjectivitytestedabovetheoil-heavy oil contact will be carried out. As mentioned earlier, each reservoir feature is identified by a distinct pressure derivative curve that distinguishes reservoir features from each other. The same can be said about 4SPE 136932 fluidcharacterization.Thebelowcasewillelaborateonthisissueandwouldshowclearlytheeffectof having two fluids with different properties inside the reservoir. Case 6: Well-E:Well-Eislocatedinthesouthwestpartofthefield.Figure-21showstheFALofthiswellandit contains the heavy-oil-oil contact. A fall-off test was conducted across the shown perforations. Figure-22 shows the derivative curve of the well and it contains an up-trending slope that dominated the entire log-logplotwithstabilizationattheend.Inthiswell,thewaterwasinjectedintheoilcolumnwhich makes two fluids with different properties available. The derivative plot represents the movement of the pressure transient from the injected water bank to the oil bank. A clear degrade in the fluid mobility is observed onthelog-logcurveasthepressuretransientgetsmoreintotheoilbankuntilitgotentirely into the oil bank when the pressure derivative curve exhibits stabilization. One of Well-Es offset wells was fall-off tested across the aquifer and did not show the mobility effect observed in Well-E derivative plot. The offset well is discussed in an upcoming case. This analysis does not rule out the possibility of having an actual degrade in rock quality away from wellbore. iv.Physical Sealing Boundary Inthisstudy, onlyonewellinBreservoirwasanalyzedasawellthatissittingnearapossiblephysical sealingboundary.Suchreservoirheterogeneitieshaveuniqueshapesonthepressurederivativecurve. Nevertheless,insomesituations,thepresenceofsomelimitationsaddstotheuncertaintyoftheanalysis. The previous statement is a general statement that may or may not fit the analyzed case.Case 7: Well-F: Well-F is located in the crest of the field right in the center. The well was tested three times across three differentperforationsasshowninfigure-23.Thewellwasfirsttestedacrossthelowerzonealone.In thesecondtest,thewellwastestedacrossthelowerandmiddlezonetogether.Inthethirdtest,the upper interval was added and the well was tested across the three perforations together. The three tests reveal the same pressure derivative behavior at the late time (Figures-24, 25 and 26).Figure-27 has an overlay of the three tests. The behavior is an up-trending slope at the late time of the pressure build up. This shape could be attributed to many reservoir/fluid features, two of which are presence of a physical sealing boundary or degrade in fluid mobility. The fact that the three tests were build-up tests has ruled out the possibility of having degradation in fluid mobility simply because it is not well justified. To have degradation in fluid mobility; presence of fluids of different mobility is a must. In this case, the well was flowing oilfromanoilcolumn.Certainly,oilcanhave differentmobilityvaluesinthesamereservoir whichmightopenagainthepossibilityofmobilitydegradation.Yet,noenoughjustificationsare present.Conversely,theotherpossibilitywhichisapresenceofaphysicalsealingboundaryawayfromthe wellbore seems to be more acceptable. From literature, if the well is sitting near a sealing fault, then it is expected to have an infinite acting reservoir behavior at the early time followed by a hemi-radial flow regime(adoublingofslope).TheactualdataforWell-Frepresentsalmostthesameflowregimes mentionedintheliterature.Inaddition,thewellwasdrilledbesideaninterpretedpredeterminedfault. TheanalysesofWell-FderivativeplotsofthethreetestsconfirmthepresenceofthisfaultinWell-F vicinity.Theupcomingsectionofthepapershowshowthestudyparticipatedinconfirmingthenon-presenceofthisfaultinsomeotherareas.Inotherwords,pressuretransientanalysissuggeststhatthe fault does exist, but its extension is very limited across the field. Figure-28 shows how close Well-F is to the fault. v.Mobility Effect Versus Physical Sealing Boundary Continuingwhatwasstartedintheprevioussection,mobilityeffectandphysicalsealingboundarycould have the same behavior on the pressure derivative curve. Without integration of all the available data of the well and surrounding area, no reliable analysis would be attained. In this study, there were some cases where the shape of the pressure derivative curve was not enough to determine the right model. In the approaching lines,twoexamplesaresharedforcaseswherethepressurederivativecurvecouldsuggestmorethanone solution.Theexamplesarefortwowellsoriginallycompletedbesidepredeterminedfaults.Furthermore, thesetwowellswerefallofftestedinwhichthewaterwasinjectedacrosstheoilcolumn.Thesetwofacts have complicated the analyses of both tests. Both cases are discussed in details below: Case 8: Well-G: Well-G is located in the west side of the field toward the south. The FAL of the well is shown in figure-29, and it indicates a perforation interval of 20 ft above the heavy oil-oil contact. The derivative plot of thetest(Figure-30)showsstabilizationattheearlytimefollowedbyatransitionperiodtoanother stabilization plateau. This shape leaves two possibilities, either the well is affected by the fluid mobility where the early part represents the water bank and the outer part is representing the oil bank. Or the well SPE 1369325 issittingnearaphysicalsealingboundary.Infact,bothoptionsarefairlypossible.Thefirstoption (mobility effect) is supported by the fact that water was injected inside the oil which makes two fluids available (Injected Water and Reservoir Oil). The second option is supported by the presence of fault in the geological model of the field. Choosing the right model to fit the available pressure derivative curve requireslookingatotherwells.Theotherwellswerelookedatasdiscussedincase-9andthechosen option for Well-G is the mobility effect option.Case 9: Well-H: Well-H is located in the south east part of the field. Its FAL is shown in figure-31 and it demonstrates a perforationinterval of 50 ft abovethe heavyoil-oilcontact.Afall-off testwasconductedonthis well and the derivative plot is shown in figure-32.The derivative shape is identical with Well-G derivative shape.Thegeologicalmodelhasafaultsittingneartothiswellasshowninfigure-33.Again,two possible solutions are available to match the test data. The first solution is that the well is sitting near a sealingfault.Thesecondsolutionisthatthewellissensingfluidmobilitydegradationawayfrom wellbore. Like Well-G, the analysis of Well-H fall-off test requires looking at the data of other wells.Two wells were looked at to come up with a reliable analysis of Well-G and Well-H fall-off tests. The first well is Well-I which was briefly discussed in case 6. Well-I is completed in a water zone and then wasfall-offtested.Theshapeofitspressurederivative(Figure-34)showadominationoftheradial flow regime which support that what Well-G and Well-H are observing in their derivative plots is only a mobilityeffect.ThesecondwellthatwasutilizedtosupporttheanalysisofthetestsofWell-Gand Well-H is Well-J. This well is located north of Well-H close enough to the fault (Figure-33). The well has high water saturation (Figure-35). The shape of the pressure derivative does not indicate any sealing boundary or mobility effect (Figure-36) meaning that the well did not sense the sealing fault although the geological model indicates the fault presence.This will rule out the possibility of Well-H to sense the fault as the fault does not actually exist. Moreover, the only difference between Well-J and Well-H is the high water saturation in Well-J. This means that the behavior observed in Well-H at the late time of the pressure derivative is due to mobility effect. By applying the same concept on Well-G, the fault near to Well-G will be considered as none-existing.Thegeologicalmodelwasrevisedbasedonmanydatasuchasseismicanddrillingandmostofthefaults were actually removed from the new geological model. Pressure Transient Analysis indicated the absence of these fault prior their actual removal of the geological model. vi.Excellent Reservoir Quality at the Middle of the Field. Pressure transient analysis identified the best reservoir quality to be within the crest of the field toward the south.Threeoffsetwellsshowedthesameflowcapacityvalue.Thethreewellsareshowninfigure-37. Figure-38 shows an overlay of the three offset wells displaying the flow capacity line of the three wells. Conclusions The tight permeability layer at the top of B reservoir does not act as a barrier in the crest of the field.The tests that were performed across the heavy oil zone revealed very low transmissibility. Very good reservoir quality is observed in the middle of the field. Mobility effect was detected in many of the wells that are completed just above the heavy oil-oil contact. No mobility effect in the wells that are completed in the water zone below the heavy oil. The wells that are completed away from the heavy-oil oil contact reveal very good reservoir quality. One well was analyzed as a well sitting near a sealing boundary. Manyfaultswereremovedfromthegeologicalmodelbasedondynamicdata(oneofwhichisPressureTransient Analysis). 6SPE 136932 Acknowledgment The authors wish to extend their gratefulness to Saudi Aramco for granting the authorization to publish this work. Nomenclature Kh: Flow Capacity, md*ft II: Injectivity Index, bpd/psi Abbreviation PTA: Pressure Transient Analysis FAL: Formation Analysis Log References1.BadrM.Al-HarbiandSaudA.BinAkreshASuccessfulFull-FieldReservoirCharacterizationStoryUtilizing PressureTransientAnalysis,paperSPE120724presentedatthe2009SPEMiddleEastOil&GasShowand Conference held in Bahrain International Exhibition Centre, Kingdome of Bahrain, 15-18 March 2009. 2.E.J.Pinilla,L.MWarlick,Y.M.Al-Shobaili,M.N.Aftab,A.KhanandN.M.ARahmanImprovingReservoir CharacterizationUsingAccurateFlow-RateHistory,paperSPE116003presentedatthe2008SPEAnnual Technical Conference and Exhibition held in Denver, Colorado, USA, 21-24 September 2008. SPE 1369327 34503550365037500 20 40 60 80 100 120 140 160 180 20006251250History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr]) BU (10 Wells)FO (9 Wells)FO+ BU (2 Wells)CJAEGHFDBKLIFigure-1: Distribution of the Tested WellsFigure-2: Example of the Test Data Figure-3: Transmissibility Distribution Map Figure-4: The Tight Layer Identification (West Flank) ReductioninCorePermeabilityTightLayerCore K 8SPE 136932 Figure-5: The Tight Layer Identification (East Flank) ReductioninCorePermeabilityTightLayerCore K Figure-6: Well-A (FAL) Figure-7: Well-A (Log-Log Plot of Lower Zone) Figure-8: Well-A (Log-Log Plot of Middle Zone) SPE 1369329 Figure-9: Well-A (Log-Log Plot of Upper Zone) Figure-10: Well-A (Overlay of All Tests) B Reservoir PerforationFigure-11: Well-B (FAL) Figure-12: Well-B (Log-Log Plot of Test Data) 10SPE 136932 Heavy Oil Water OilBridge Plug PerforationFigure-13: Well-C (FAL) Figure-14: Well-C (Log-Log Plot of Build-Up Test) Figure-15: Well-C (Log-Log Plot of fall-off Test)Figure-16: Well-C (Overlay of BU and FO Tests) SPE 13693211 Heavy Oil Heavy Oil-Oil ContactHeavy Oil-Water Contact PerforationFigure-17: Well-C (FAL) Figure-18: Well-C (Log-Log Plot of Test Data) Heavy Oil-Oil Contact Figure-19: Well-D (FAL) Figure-20: Well-D (Log-Log Plot of Test Data) 12SPE 136932 Heavy Oil-Oil Contact PerforationFigure-21: Well-E (FAL) Figure-22: Well-E (Log-Log Plot of test data) PerforationFigure-23: Well-F (FAL) Figure-24: Well-F (Log-Log Plot Lower Interval) SPE 13693213 BU (10 Wells)FO (9 Wells)FO+ BU (2 Wells)CJAEGHFDBKLI1E-3 0.01 0.1 1 10 100110100MNIF34b5261982revised.ks3-Analysis3MNIF34a5221982revised.ks3-Analysis2(ref)MNIF34c5281982.ks3-Analysis4Compare files: Log-Log plot (dp and dp' normalized [psi] vs dt)LowerLower+MiddleAllIntervals Figure-25: Well-F (Log-Log Plot Middle Interval) Figure-26: Well-F (Log-Log Plot Upper Interval) Figure-27: Well-F (Overlay of the three tests) Figure-28: Well-F (Well and Fault Location Map) Figure-26: Well-F (Log-Log Plot Upper Interval) 14SPE 136932 1E-4 1E-3 0.01 0.1 1101001000Log-Log plot: p-p@dt=0 and derivative [psi] vs dt [hr]Damage Skin= 0II=2.96 bpd/psiKH/ = 2304 md*ft/cp= 4.6 cp KH= 10,600 md*ftMobility and/or boundary effect1E-4 1E-3 0.01 0.1 1101001000Log-Log plot: p-p@dt=0 and derivative [psi] vs dt [hr]Damage Skin= 2.6II= 3.34 bpd/psiKH/ = 5522 md*ft/cp= 4.6 cp KH= 25,400 md*ftMobility and/or boundary effect Heavy Oil-Oil Contact Cement Plug Figure-29: Well-G (FAL) Figure-30: Well-G (Log-Log Plot of Test Data) Heavy Oil-Oil Contact Figure-31: Well-H (FAL) Figure-32: Well-H (Log-Log Plot of Test Data) SPE 13693215 BU (10 Wells)FO (9 Wells)FO+ BU (2 Wells)CJAEGHFDBKLI1E-3 0.01 0.1 1 10110100Log-Log plot: p-p@dt=0 and derivative [psi] vs dt [hr]Damage Skin= -5.9II= 137.21 bpd/psiKH/ 54,545md*ft= 0.5 cp KH= 27,272 md*ft1E-3 0.01 0.1 1 10101001000Log-Log plot: p-p@dt=0 and derivative [psi] vs dt [hr]Damage Skin= 14.7II= 11.5 bpd/psiKH/= 39,158 md*ft/cp=0.5 cp KH= 19,579 md*ft Figure-33: Well-H (Well and Fault Location Map) Figure-34: Well-I (Log-Log Plot of Test Data) Figure-35: Well-J (FAL) Figure-36: Well-J (Log-Log Plot of Test Data) 16SPE 136932 BU (10 Wells)FO (9 Wells)FO+ BU (2 Wells)CJAEGHFDBKLI1E-6 1E-5 1E-4 1E-3 0.01 0.1 1 10 1000.11101001000MNIF-72LowerRatawi.ks3-Build-up2FinalMNIF-5(LWRT)testedMay29,2007fixrates2.ks3-FinalMNIF-32C.ks3-Analysis1(ref)Compare files: Log-Log plot (dp and dp' normalized [psi] vs dt)Well-MWell-LWell-C Figure-37: Excellent Reservoir Quality Figure-38: Overlay of Well-B, K and L