Feasibility of Gas Drive in Fang-48 Fault Block Oil Reservoir

2007ScienceVol 4 No. 3Feasibility of Gas Drive in Fang-48 Fault Block Oil ReservoirCui Lining",, Hou Jirui, 2 and Yin Xiangwen,2(1. Key Laboratory of Petroleum Engineering under Ministry of Education, China University of Petroleum, Bejing 102249, China)( Enhanced Oil Recovery Center China University of Petroleum, Beifing 102249, China)Abstract: The Fang48 fault block oil reservoir is an extremely low permeability reservoir and it is difficult to producesuch a reservoir by waterflooding Laboratory analysis of reservoir oil shows that the minimum miscibility pressure foro2 drive in Fang-48 fault block oil reservoir is 29 MPa, lower than the formation fracture pressure of 34 MPa, so thedisplacement mechanism is miscible drive. The threshold pressure gradient for gas injection is less than that forwaterflooding, and the recovery by gas drive is higher than waterflooding. Furthermore, the threshold pressure gradientfor carbon dioxide injection is smaller than that for hydrocarbon gas, and the oil recovery by carbon dioxide drive ishigher than that by hydrocarbon gas displacement, so carbon dioxide drive is recommended for the development of theFang- 48 fault bleKey words: Low permeability reservoir, gas drive, feasibility, laboratory analysis, numerical simulation1 Introduction2.1 Separator test and swelling testFang-48 fault block oil reservoir is located inA GF-731 high pressure/high temperature apparatussoutheastern part of the Songfangtun reservoir, andis capable of measuring physical properties of crudein the Zhaozhou structural nose Sanzhao Sag in the oil natural gas systems, including viscosity, density, oilformation volume factor and vapor/liquid ratios undernorthern part of the Songliao Basin. The parameters reservoir conditions, then the swelling capacity andof this block are summarized as follows: Initialformation pressure 22.64 MPa, formation fracture gas-dissolving capacity of oil could be determined. Themajor components of GF-731 PVT apparatus include apressure 34 MPa, formation oil density 0.8030 g/c, phase behavior cell, high pressure dosing pump,formation oil viscosity 3.3 mPaS, porosity 14.5%, thermostatic control system, pressure display andand permeability 1.4x10-umFang 48 fault block oil reservoir is an extremelymeasuring system, high-pressure ballViscometer,permeability reservoir, and it is difficult to producecapillary viscometer and electronic balancea reservoir by waterflooding, Gas drive is a matureSeparator test 1) Simulated formation oil wasprepared in the PVT cell. 2) Some oil was separatedmethod for enhancing oil recovery and field tests in some from the PVt cell under reservoir conditions intooilfields in China demonstrated that it is worthwhile toimplement gas injection to improve the recovery of low multistage gas/oil separator system to perfpermeability reservoirs. Accurate laboratory analysis of separator test Separator test data are shown in Tareservoir oil and numerical simulation were made in this2 and 3work to study the feasibility of gas drive in the Fang-48Table 2 Oil properties datfault block oil reservoirPressure. Mmation volume factor Density, g/cm2. Laboratory analysis of reservoir oil22.64105660.7657Oil samples used in all tests were taken from Well0.7648184-124 in the Songfangtun Oilfield and its viscosi0.7638was adjusted to 3. 3 mPa- s, the initial reservoir oilviscosity. The gases added were CO2, N2 and natura0.7628Table 1 lists the natural1.062007618Table 1 Composition of natural gas11.82106350.7608ComponentCH4 C2H6 CaHg C,Ho Total中国煤化工CNMHGfraction0414392l3581.93041100.75856551.06730.7580Petroleum ScienceTable 3 Variation in oil properties in the process ofviscosity, limited expandability and limitedmultistage separationcompressibility and the gas liberated from oil ischaracterized by low densityPressure ViscosityFormationvolumeMPaGOR DSwelling test 1) The pressure in the PVT cell wasfactorincreased above the bubble point pressure, and then gas3.3140.80510538was injected into the Pvt cell. 2)After gas injection,8590.78410818the pressure in the PVt cell was increased to the3.5010665formation pressure and then the physical properties ofthe gas-containing oil were measured; 3)Injection was1.703.2111.0486continued and the above processes were repeated0.1034630.83310383After injecting the gas produced from WellFangshen-6, Well Shengqi-1-4 and carbon dioxide, theTable 2 shows that the oil from the Fuyu Formation is phase behavior data of oilgas system are shown inheavy oil with a small formation volume factor. Oil Table 4. Experimental data indicate that the injectedformation volume factor varies slightly with pressure, in a gases had evident influence on the physical propertiesrange of 1.0566-1.0673. This indicates that there is limited of oils. The bubble point pressure, gas/oil ratio,energy of volumetric expansion in the Fang 48 fault block formation volume factor and swell factor increased withoil reservoir, thus elastic drive is not suitable.increasing injection of gas, while the density andMultistage separator tests(Table 3)indicate that the viscosity of oil gas system decreased. This is helpful inviscosity and density of crude oil incrcase with enhancing oil recovery. However, the physicaldecreasing pressure, while the gas/oil ratio(GOR)and properties of oil cannot be changed by waterflooding, sooil formation volume factor decrease (Table 3), gas drive is better than waterflooding in lowindicating that the oil has moderate density, higher permeability reservoirsTable 4 lnfluence of gas injected on oil physical propertiesviscosity, mPasInjection gas如P12105Density Oil formation volume factor GORvcllactor40 MPaPb 40 MPa00401.138101252.50Gas from0.1233.36Fangshen-6 0 2451.2071.1371.07580.782812521.1704608080881.0550.1021.142101782453.40Gas from0.187079961.1621,121103572.273.10WellSheng-1-40.7910078721.16158276701.05621.872461.07691.892.280.377078091.232109801802.00080881.081l.0551.05472860167080561.1581.112826080211.2031.15432353.110.361080711.3561.3321121.3317201and MMP, the displacement pattern and ultimateThe slim-tube displacement experimental apparatus Coy2.2 Slim-tube displacement testH中国煤化工 gas driveT- n-tube experiment Iscan be used to conduct miscibility experiments and shoCNMHG2 m long, 6 mm inidentify minimum miscibility pressures(MMP). By outside diameter and 1 mm in wall thickness, is packedcomparison between the reservoir pressure with 160-200 mesh fine sandVoL 4 No.3Feasibility Drive in Fang-48Fault Block Oil ReservoirThe experimental procedure was as follows: 1)The During displacement, the volume of oil and gassand-packed slim-tube was saturated with oil. 2)Gas displaced and the readings of the pump were monitoredinjection. The Ruska pump was turned on and gas regularly. The injection volume of gas, the cumulativepressure in the gas injection cell was raised to a pressure, volume of outlet oil and the cumulative volume of1-3 MPa lower than the designed displacement pressure. outlet gas were recorded when gas breakthroughThe hand pump was adjusted to raise the backpressure occurred. 4) The pump was turned off when theto the designed displacement pressure. The exit valve of cumulative injection volume of gas was more than 1.2temperature, atmospheric pressure, and the initial and the above-mentioned procedure was repeated atreadings of gas flowmeter and Ruska pump were another designed displacement pressure(Li, et al., 2001;recorded. Displacement began at a given pump rate. 3) Liu, et al., 2002; Yang, et al., 2004; Hao, et al., 2005)21-Pressure gauge, 2-Digital displayer, 3-Back pressure controller, 4-Gas cylinde, 5-Intermediate container,6-Forward displacement device, 7-Gas flowmeter, 8-Separator, 9-Ruska pump, 10-Capillary sight glassll-Gas injection cel, 12-Sand packed slim tube, 13-High pressure PVI analyzerThe plot of percentagerecovery versusdisplacement pressure for CO2 drive is shown in Fig. 2As the pressure increased, the oil recovery when thecumulative injection volume of gas was 1.2 PVincreased and reached a plateau above 29 MPa. ThusmmP for this oil was about 29 MPa for cO,displacement, which was less than those correspondingto hydrocarbon gas displacement (37 MPa)andnitrogen gas displacement (44 MPa). Since the中国煤化工035formation fracture pressure is 34 MPa,thedisplacement mechanism is miscible drive in thisCNMHFig. 2 Oil recovery versus displacement pressureblock reservoir(gas injection volume 1.2 PV007the proportion of CO2 in the The compositions of the displacing agents are listed indisplacing agent on oil recovery was also investigated. Table 5Table 5 Compositions of displacing agentsMol%Displacing agentTotalGas from Well Sheng-1-40.023.3594.711.6002100.040007Gas from well Fang-612.461.1083581.150.240003000.84Hydrocarbon gas41.321.3456.360.830.15Hydrocarbon gasⅡ53421.1844.550.7201300Ire cOt fig. snows that oil recovery increased with was prepared with the crude oil from Well 184-124 increasing CO2 proportion and the recovery by pure the Songfangtun Oilfield, and its viscosity was adjusteCO2 displacement was 69.35%.to 3.3 mPas(formation oil viscosity). The simulatedformation water was prepared according to the salinityof formation water(7, 158 mg/L). The gases used in thecore tests were pure COz and natural gas (itsposition is shown in Table 1 ).Theused were natural cores obtained from WellFang-188-138, except 2-1, 6-1, ll-I and 15-1 whichwere from other oilfields, and their physical parametersare listed in Table 6Table 6 Characteristics of cores used20406080Length Diameter Permeability PorosityCO2 proportion,2.520.38Fig3 Relationship between oil recovery and Co2 proportion2.524.12(gas injection volume 1. 2PV)4.362.3 Core displacement test6-11342Core displacement tests were performed to measure 10-1 7.40 2.52 0.396.1the threshold pressure and the threshold pressure10-27.44gradient (Huang, 1998), so as to determine the11-16.7625218fcasibility of gas injection. The schematic diagram ofcore displacement test is shown in Fig. 4l2-17852.5212-27.672.525016.582.521.24124812.6816.6815-27332.5215.74I)The core sample was saturated with simulatedformation water. 2) The water in core was displaced byoil till there was no water flowing out of the exit of coreensuring that the oil and water saturations on coresamples were similar to those under reservoir conditionsFig. 4 Schematic diagram of core displacement tests3)Gapplied to the core1-Micro pump, 2-1ntermediate container, 3-Pressure gauge, 4-Valve,entran中国煤化工 ually increaser5-Core bolder, 6-Ruska pump, 7-Container, 8-Gas cylinder, 9-ThermostatusingCNMHGpressurization,thedisplacement pressure was recorded until the first dropThe oil sample used in all core displacement tests of oil flowed out of the core exit. This pressure wasVol, 4 No.3Feasibility of Gas Drive in Fang-48 Fault Block Oil Reservoirconsidered the threshold pressure.waterflooding in the Fang-48 fault block oil reservoir.The core displacement results(Table 7)indicate that Moreover, injecting the mixture of COz and gaseousthe average threshold pressure gradients were 0.728 hydrocarbon is easier than injecting natural gas, andMPa/m for CO2 displacement, 1. 150 MPa/m for natural CO2 injection is the easiest In a word, it is feasible togas displacement, and 2.384 MPa/m for waterflooding. implement gas displacement, especially CO,Hence, it is easier to implement gas displacement than displacement in Fang-48 fault block oil reservoirTable 7 Core displacement test dataWaterfloodingCore Permeability Threshold Threshold Threshold Threshold pressureThresholdThreshold pressuredientpressureMPaMPa/mMPa/mMPa/m0.215100.1503.8410-20.552.0600014-11.2430.0620890.0500.720.15515-23.7360.0390530.095l-24.1150.01504402000802.322-24.3640.720.03204800I11.641225,018001904300150.20004012-15252064004011-100120.18001101600340502-172790.190.010004815-112.68100080.110.10035134190.00600050.0140.19and gas displacement respectively at different injection3. Numerical simulationpressures and volumes. Table 8 lists variousECLIPS software and CMG software were used to development schemes with a simulation end time ofpredict the main development indices of waterfloodingDec.31,2020.Table 8 Development schemesSchemeDescriptionMaximum Number of Number ofElastic drive1 Maintaining the present well patten0BHFP in production well: 5.3 MPaBHFP in production well: 5.3 MPa2 One additional water injectorShut in when individual well water cut>95%One additional gas injectorBHFP in production well: 5.3 MPaas injected; gas from Well1- 4 Shut in when individual well G/o> 1000 m'im'ne additional gas injectorBHFP in production wcll: 5.3 MPa1as injected: gas from Well Fangshen-6 Shut in when individual well G/O> 1000me additional gaBHFP in production well: 5.3 MPaas injected: 41%CO2+hydrocarbon Shut in when individual well G/O>1000 m/m2One additional gas injectorBHFP in production well: 5.3 MPsGas injected: 53%CO]+hydrocarbon Shut in when individual well C中国煤化工One additional gas injectorCNMHG4as injected: 100%CO2Shut in when individual well G/o>1000 m/mNotes: BHFP-bottom hole flowing pressurePetroleum Science2007The physical parameters of oil used in this5)Laboratory analysis and numerical simulationere obtained from the above-mentioned experiindicate that a higher oil recovery can be achieved byThe simulation results (Table 9)illustrate that a higher gas displacement than by waterflooding, and carbonoil recovery can be obtained by gas displacement. The dioxide displacement can obtain a higher oil recoveryaverage oil recovery by gas displacement is 10% higher than hydrocarbon gas displacement. Carbon dioxidethan that by waterflooding. Furthermore, carbon dioxide displacement is recommended for the development ofdisplacement is better than hydrocarbon gas the Fang-48 fault block oil reservoirdisplacement, with a 15. 32% improved recoveryReferencesTable 9 Results of numerical sinulationSchemeMaximumIncremental Increment versHao Y M, Chen Y M. and Yu H. L(2005) Determination andrecovery, recovery, waterflooding,prediction of minimum miscibility pressure in COz floodingPetroleum Geology and Recovery Eficiency, 12(6), 64-66(in1187926Huang Y Z(1998)Fluid Flow Mechanism in Low-Permeabiliry19.791718792Reservoir. Beijing: Petroleum Industry Press, 59-99(in1001Chinese)24.0212.15Li S. L, Zhang Z. Q. and Ran Q. Q.(2001) Gas injectionTechnique for EOR. Chengdu: Technology Press of Sichuan,24.8422-24 (in Chinese)27.1924581532Liu B. G, Zhu P, Yong Z Q and Lu L. H(2002)Pilot test onmiscible CO flooding in Jiangsu Oilfield. Acta Petroleica, 23(4), 56-60 (in Chinese)4. ConclusionsYang XF, Guo P, Du Z M. and Chen J. L(2004)Influencefactors appraisal of shim-tube simulation to determine the1)The injection of both hydrocarbon gas and carbminimum miscibility pressure. Joumal of Southwestdioxide can lead to an increase in oil formation volumPetroleum institute, 26(3), 4-44(in Chinese)factor and a decrease in density and viscosity, as well asan increase in saturation pressure. Moreover, the About the first authorinjection of carbon dioxide can lead to a much higCui Lining was bom in 1982 andincrcase in oil formation volume factorreceived her bachelor degree from2)Carbon dioxide has a lower MMP and higherDaqing Petroleum Institute in 2004displacement efficiency.Now she is studying for her3) The MMP of Co2 displacement is lower than themaster's degree in China Universityformation fractureus CO2 displacemenmechanism in the Fang-48 block is miscible drivemain interests in EOR engineering4)Core displacement tests show that the thresholdand oilfield chemistrypressure gradient of gas injection in the Fang-48 faultE-mail:clnyydd@126.comblock oil reservoir is lower than that of waterfloodingSo, it is easier to implement gas displacement than(Received July 24, 2006)waterflooding(Edited by Sun Yanhu中国煤化工CNMHG