Compositional Simulation and Performance Analysis of the Prudhoe Bay Miscible Gas Project
- P.L. McGuire (Arco Alaska Inc.) | A.L. Moritz Jr. (Arco Alaska Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1992
- Document Type
- Journal Paper
- 329 - 334
- 1992. Society of Petroleum Engineers
- 5.4 Enhanced Recovery, 4.3.4 Scale, 3 Production and Well Operations, 3.1 Artificial Lift Systems, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements, 5.1.2 Faults and Fracture Characterisation, 5.2.2 Fluid Modeling, Equations of State, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating, 4.6 Natural Gas, 5.1 Reservoir Characterisation, 4.9 Facilities Operations, 4.3.1 Hydrates, 5.3.2 Multiphase Flow, 5.2 Fluid Characterization, 1.6.9 Coring, Fishing, 5.4.9 Miscible Methods, 5.5 Reservoir Simulation, 5.6.5 Tracers, 2.4.3 Sand/Solids Control, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5.8 History Matching, 5.4.2 Gas Injection Methods, 5.6.4 Drillstem/Well Testing
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A pseudocomponent method was developed to use fully compositional reservoirsimulation results in the interpretation of separator gas samples. Thisinterpretation provided insight into actual EOR performance by quantifyingsolvent breakthrough and production rates. Field examples of various reservoirmechanisms production rates. Field examples of various reservoir mechanismsaffecting the efficiency of Prudhoe Bay EOR are examined.
Compositional analysis of produced fluids from enriched-hydrocarbon misciblefloods to evaluate EOR performance is significantly more complex than that fromCO2 floods. This is particularly true at Prudhoe Bay, where a number offree-gas sources exist in the Prudhoe Bay, where a number of free-gas sourcesexist in the reservoir, solvent composition is not radically different fromsolution-gas composition, and active primary and secondary oil recovery maskstertiary oil production. The Prudhoe Bay Miscible Gas Project (PBMGP) is theworld's largest miscible gasflood, with a solvent injection rate of more than400 MMscf/D at an average water-alternating-gas (WAG) ratio of 2:1. Althoughthe Prudhoe Bay field has been featured in numerous papers, only a few havedealt with EOR operations at Prudhoe. papers, only a few have dealt with EORoperations at Prudhoe. Prudhoe Bay EOR began in late 1982 with an 11-patternpilot Prudhoe Bay EOR began in late 1982 with an 11-pattern pilot projectlocated at Drillsite 13 within the Eastern Peripheral Wedge project located atDrillsite 13 within the Eastern Peripheral Wedge zone. EOR operations wereexpanded in 1987 and now include 67 patterns in four separate areas of thefield (Fig. 1). Dawson et patterns in four separate areas of the field (Fig.1). Dawson et al. described the reservoir properties and anticipated EORperformance in these areas, so they are not repeated here. Instead, thisperformance in these areas, so they are not repeated here. Instead, this paperfocuses on the compositional aspects of monitoring and paper focuses on thecompositional aspects of monitoring and evaluating the enriched-gas miscibleflood. The first part of this paper briefly examines the development of theequation-of-state (EOS) characterization (if the Prudhoe Bay oil/solventsystem, the results of studies made with a compositional reservoir simulator,and the methodology used to group hydrocarbon production from the simulationsinto three pseudocomponent production from the simulations into threepseudocomponent streams. The second part of the paper describes the separatorflash routine and allocation program that uses these three pseudocomponents tointerpret compositional data obtained from pseudocomponents to interpretcompositional data obtained from separator gas samples. This program is used tomonitor EOR performance for individual wells, selected areas of the field, andperformance for individual wells, selected areas of the field, and the entiremiscible flood. Specific examples of a number of reservoir mechanisms affectingthe efficiency of the miscible flood are cited. Finally, EOR performanceobservations for the entire flood are compared with predictions made by patternscale-up forecasting programs to verify their predictive ability.
Miscible Displacement Studios
To undertake meaningful compositional studies, it was first necessary tounderstand the relevant miscible displacement mechanisms and to develop anaccurate EOS description of the Prudhoe Bay oil/solvent system. This was donewith an extensive series of slim-tube, coreflood, multiple-contact, andnear-critical swell experiments. Two distinct fluid characterizations are usedin Prudhoe Bay evaluations. Both characterizations are based on thePeng-Robinson EOS and incorporate the volumetric shift parameter Peng-RobinsonEOS and incorporate the volumetric shift parameter developed by Jhaveri andYoungren. A 12-component characterization was specifically calibrated to thenear-critical range found in the Prudhoe Bay oil/solvent system and was used inall reservoir, coreflood, and slim-tube simulation studies. A 19-componentcharacterization with a more detailed breakdown of solvent-range components wasused in all flash calculations to interpret the compositional data obtainedfrom separator gas samples. Table 1 lists the pseudocomponents.
During a detailed analysis of the laboratory experiments, it was determinedthat the classic industry understanding of the condensing-gas-drive mechanismdid not apply to either the PBMGP or to the pilot. Rather, miscibility wasdeveloped by the condensing/vaporizing mechanism, in which light intermediatecomponents from the solvent condensed into the liquid phase and middleintermediate components from the oil vaporized into the gas phase. Fig. 2 showsoil recoveries from some Prudhoe Bay phase. Fig. 2 shows oil recoveries fromsome Prudhoe Bay slim-tube experiments. None of the displacements shown werecalculated to be "thermodynamically miscible" in the classic sense offorming a single hydrocarbon phase. The displacement was "effectivelymiscible, " with a lean-gas bank leading the near-critical displacementfront and a zone of very heavy oil at low saturations remaining behind thefront. The size of the lean-gas bank was a function of how close the solventwas to the minimum miscibility pressure (MMP), which was defined by thebreakover point in the slim-tube recovery plot. This highly efficientcondensing/vaporizing displacement mechanism typically yielded residual oilsaturations of 2% to 6% in both the slim-tube and coreflood experiments. Thetertiary displacement process during a simultaneous WAG coreflood isillustrated in the pseudoternary diagram of Fig. 3 and in the saturationprofile of pseudoternary diagram of Fig. 3 and in the saturation profile ofFig. 4. It is important to note that numerical dispersion in the simulator cansignificantly affect these results and should be considered during evaluationsof either pseudoternary diagrams of saturation profiles. The solventcomposition at Prudhoe Bay is designed to maximize EOR for the limited volumeof enriching fluids available from the Prudhoe Bay central gas facility. Table2 shows average compositions Prudhoe Bay central gas facility. Table 2 showsaverage compositions of the current solvent and the pilot solvent (which wasinjected in 11 pilot patterns during 1983-86). The current solvent has acalculated MMP that is about 400 psi lower than the average reservoir pressure.The lower MMP is necessary because reservoir pressure has been declining atabout 30 psi/yr. This lower MMP provides a safety factor to ensure thateffective miscibility is maintained despite the declining reservoir pressureand the potential dilution of the solvent by evolved solution gas. The currentsolvent, however, will not attain thermodynamic miscibility. If the solvent hadbeen enriched sufficiently to suppress the development of the lean-gas bank, assuggested in a recent paper, 10 solvent availability would have beenconsiderably reduced, with a commensurate loss in EOR reserves.
Numerous 2D reservoir simulations were made to evaluate the effects ofsolvent slug size, WAG ratio, and reservoir description on Prudhoe Bay EOR.This effort was similar in many respects to the studies reported by Dawson etal. 5 but had the advantage of providing compositional information and oil andwater production. providing compositional information and oil and waterproduction. Fig. 5 shows waterflood and WAG flood production rates for atypical case, and Fig. 6 shows the C1, C3, and C8 through C 10 production forthe WAG flood case. Fig. 6 shows the production of production for the WAG floodcase. Fig. 6 shows the production of a lean-gas bank ahead of the EOR oil bank,with the C1 /C3 ratio gradually decreasing as injected solvent is produced.This behavior is very similar to that seen in the ID simulation studies oftertiary WAG displacement of saturated oil.
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