Impact of Solvent Injection Strategy and Reservoir Description on Hydrocarbon Miscible EOR for the Prudhoe Bay Unit, Alaska

Abstract

Abstract A large hydrocarbon miscible flood of the Sadlerochit and Sag River sandstones is now in progress at the Prudhoe Bay Unit. The current miscible flood area includes more than 50 patterns, with the potential for flooding more than 100 patterns. Process design is complicated by a highly variable reservoir description and an uncertain level of vertical communication. A reservoir simulation study was made to determine EOR sensitivity to reservoir description, solvent injection rate, and solvent bank size. Results from this study were used to develop a solvent injection strategy that maximized EOR benefits within the limitations of solvent availability. The simulation study used 11 basic models. Each model was designed to represent a geological subset of the actual EOR patterns. The design sensitivity matrix consisted of two vertical patterns. The design sensitivity matrix consisted of two vertical permeability assumptions, two solvent injection rates, and at permeability assumptions, two solvent injection rates, and at least two solvent bank sizes. Solvent efficiency as a function of solvent bank size was determined for half of the above cases. Miscible EOR was shown to be a strong function of reservoir description and vertical permeability. Permeability distribution within the formation was a key variable in determining the relative performance of a pattern. Less important was the impact of solvent injection rate (WAG ratio) on miscible EOR. A procedure was developed to estimate the optimum solvent bank size for each of the project patterns as a function of the cumulative solvent supply. Introduction At the Prudhoe Bay Field on Alaska's North Slope, the Working Interest Owners have installed a hydrocarbon miscible WAG injection project for enhanced oil recovery. The reasons for selection of this process and the overall project design have been previously described. EOR development has progressed in two stages. In 1983, the Flow Station Three progressed in two stages. In 1983, the Flow Station Three Injection Project was initiated with solvent injection into 11 wells. In 1987, after start up of the world's largest gas plant, the Prudhoe Bay Miscible Gas Project was commenced with solvent injection into 43 additional wells. Future expansion of the project is also under consideration. Reservoir properties such as horizontal permeability stratification, vertical communication, and oil column thickness vary substantially over the current project area and areas available for expansion. Expansion of the project area will depend on performance in the initial areas and the supply of solvent. The solvent supply is expected to increase from its current level of approximately 350 million scf/d because of three major factors. These factors are: the future expansion of field-wide gas handling facilities, the increasing reproduction of solvent, and the decreasing volume of NGL's required for pipeline blending as overall field liquid production rates pipeline blending as overall field liquid production rates decline. (NGL's are blended with produced crude and condensate up to vapor pressure constraints.) The objective of the simulation study was to determine the influence of reservoir description on solvent injection strategy and miscible EOR performance. This study focused on the complex interaction of viscous and gravity forces in heterogeneous reservoirs. Emphasis was placed on determining the vertical conformance of a miscible WAG process where gravity segregation of water and solvent limits process where gravity segregation of water and solvent limits recovery. Compositional effects were addressed in other simulation and laboratory studies and were considered less important in comparing relative performance of different reservoir descriptions. RESERVOIR MODELS The Todd and Longstaff mixing model was selected as the most appropriate model for a large sensitivity study. P. 305