Three-Phase Gas/Oil/Brine Relative Permeabilities Measured Under CO2 Flooding Conditions
- D.E. Dria (U. of Texas) | G.A. Pope (U. of Texas) | Kamy Sepehrnoori (U. of Texas)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- May 1993
- Document Type
- Journal Paper
- 143 - 150
- 1993. Society of Petroleum Engineers
- 2.7.1 Completion Fluids, 5.1 Reservoir Characterisation, 5.5 Reservoir Simulation, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 5.6.5 Tracers, 4.1.5 Processing Equipment, 5.3.4 Reduction of Residual Oil Saturation, 1.2.3 Rock properties, 5.3.2 Multiphase Flow, 5.3.1 Flow in Porous Media, 4.3.4 Scale, 1.6.9 Coring, Fishing, 5.4 Enhanced Recovery, 4.1.2 Separation and Treating
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Steady-state three-phase gas/oil/brine relative permeabilities were measuredin a carbonate core under CO2 flooding permeabilities were measured in acarbonate core under CO2 flooding conditions. Results show that the relativepermeability of each phase depends only on the saturation of that phase insteadof on phase depends only on the saturation of that phase instead of on twosaturations, as many previous studies have concluded. All previously reportedgas/oil/brine relative permeability studies previously reported gas/oil/brinerelative permeability studies have been conducted with low-pressure N2 gas orair. In this work, CO2 gas, oil, and brine were injected into a carbonate coreat 71 degrees C and 9.65 MPa so that the phase behavior and flow would besimilar to reservoir conditions. Results show that significant differencesexist between the three-phase gas/oil/brine relative permeabilities measuredwhen the gas is CO2 and those measured permeabilities measured when the gas isCO2 and those measured when the gas was N2.
Three-phase relative permeability relations are needed for the design of CO2field projects; for accurate prediction, through numerical reservoirsimulation, of CO2 flood performance; and for modeling of production andinjection problems. The literature contains empirical, mechanistic, andpore-level models used to predict the relative permeability relationships whentwo phases are predict the relative permeability relationships when two phasesare flowing simultaneously in a porous, permeable medium. Because of thelimited amount of consistent experimental data available to determine the modelparameters accurately, only the simpler models are usually considered. Thetypical description given when one extends one of these models to three-phasegas/oil/brine flow assumes that one liquid phase strongly wets the rock matrix,the gas phase is "totally nonwetting," and the second liquid phase isof "intermediate wettability." In these cases, one also assumes thatthe relative permeability of the wetting and totally nonwetting phases dependsonly on their respective saturations. One then applies the respective two-phaserelative permeability relation as the three-phase relation for these two phasesand need only derive an expression for the relative permeability of theintermediate-wetting phase (kro for a strongly water-wet medium in three-phasegas/oil/brine phase (kro for a strongly water-wet medium in three-phasegas/oil/brine flow). The models for kro most frequently applied include theCorey et al., Naar and Wygal, Land, and Stone models. More recent models orsignificant model modifications include work by Parmeswar and Maerefat, Fayers,Parker et al., Aleman and Slattery, Baker, and Delshad and Pope. Manjnath andHonarpour and Parmeswar and Maerefat reviewed the models, and Baker and Delshadand Pope recently provided detailed comparisons. Experimental studies ofthree-phase relative permeability (water/oil/gas) were reported as early as1941 and have continued to trickle into the literature. Oak et al. and Maloneyet al. reviewed these experimental studies in detail. Oak et al, presented avery well-documented experimental study resulting from presented a verywell-documented experimental study resulting from painstaking attention toprocedural detail; their results, along painstaking attention to proceduraldetail; their results, along with those of Schneider and Owens, are analyzed inmore detail below. Maloney et al. (with preliminary work reported by Parmeswaret al.) presented what they described as viscosity Parmeswar et al.) presentedwhat they described as viscosity effects on three-phase relative permeabilitybut, while acknowledging the obvious importance of saturation history, made nomention of it with regard to their own experiments. Maini et al. 18 reportedthree-phase relative permeabilities measured at 100 degrees C and 3.45 MPa forN2/mineral oil/distilled water in Ottawa sandpacks. Although a modest number ofstudies have been done in which three-phase relative permeability data havebeen reported, there is no universally accepted conclusion as to the shape ofthe isoperms when the data are plotted on a saturation ternary; in fact, oiland gas isoperms are reported as concave, linear, and convex toward therespective apex on the saturation ternary, and brine isoperms are given asconcave and linear. In addition, a significant number of the experiments wereperformed under unsteady-state flow conditions. The interested researchershould evaluate these results with regard to saturation hysteresis, viscousinstability, and experimental methods used. What separates our three-phaserelative permeability study from previous studies is our use of CO2 gas insteadof air or N2, resulting in phase properties consistent with those observed in afield CO2 flood. The experiments were performed under steady-state conditions,minimizing instability phenomena and allowing for control of saturationhistory. Saturations were determined by tracer injection.
A single 5 x 45-cm dolomite core was used for these experiments. The corewas cut from a block of outcrop dolomite quarried from the Guelph formation inSandusky County, OH. Commonly called Baker dolomite, the Guelph is a primary,sedimentary grainstone dolomite with intergranular porosity described in somedetail by Meister. Its granular matrix gives it a somewhat homogeneousappearance, although there are zones of varying permeability throughout thecore, which are evident by detailed visual inspection as well as by X-raycomputed-tomography scanner analysis. Permeability measurements of 2.54-cm coreplugs showed that permeability varied by as much as a factor of two along thecore length. The core PV was found to be 168.4 cm3 at 10.3-MPa overburden,3.45-MPa core pressure (24 degrees C), yielding a porosity of 0.202. Theoverall brine permeability measured over the total core length (Sw = 1) was 24md. Three fluids were pumped through the core: 0.020-kg/kg CaCl2 brine,n-decane, and CO2. Phase properties were estimated with phase-behavior dataaccording to Dria's methods. From these, the phase-behavior data according toDria's methods. From these, the viscosities, flow rates, and fractional flowswere calculated at the mean core pressure. The equipment used in thisexperimental investigations was arranged to achieve steady-state,nonrecirculating three-phase water/oil/gas flow through the core at atemperature of 71 degrees C and average core pressures of about 9.65 MPa. Theonce-through flow design was necessary for continuous collection and analysisof effluent needed for determination of tracer response. Flows through the corewere controlled through constant injection rate coupled with downstreampressure control. Saturations in this study were attained through steady-stateinjection of brine, decane, and CO2 into the core until constant pressure dropsover each core section (measured through four pressure drops over each coresection (measured through four internal pressure ports), constant pressure dropmeasured between the inlet and outlet core faces, and constant effluent flowrates were observed. Steady-state overall pressure drops for the variousexperiments ranged from 35 to 480 kPa, with most between 205 and 345 kPa. Thethree-phase flow rates were designed to maintain total fluxes, u=q/A, of about0.12 m/d.
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