SPE Members Abstract The gravity drainage mechanism in the Prudhoe Bay Field has been evaluated by means of repeat Compensated Neutron Log (CNL) data, centrifugal gas/oil displacements in small preserved cores, and by an analytical stochastic approach. From the repeat CNL data, in-situ displacement efficiencies as observed above the advancing gas-oil contact in 50 gravity drainage wells have been estimated. A Monte Carlo-type error analysis is presented to give the range of uncertainty associated presented to give the range of uncertainty associated with the results. Gas/oil centrifuge displacements in small preserved cores were performed in order to validate the CNL results, and to investigate the time dependency of recovery in gassed out zones which is otherwise beyond CNL resolution. Conventional scaling theory was subsequently used to find homologous times for the reservoir and laboratory models, thus making comparisons (between CNL and centrifuge data) possible. In addition, relative permeability to oil (to be possible. In addition, relative permeability to oil (to be used in the analytical study) was computed from the centrifuge data. Finally, an approximate analytical description of the gravity drainage process was formulated and a Monte Carlo analysis performed to cover the wide range of values the input parameters in the equations may take on. This analysis yields a statistical distribution in displacement efficiencies at each point in time. The "average" behavior may be compared to the CNL and centrifuge data. The results demonstrate that the gravity drainage mechanism in Prudhoe Bay is very time-effective and yields high quantifiable displacement efficiencies. The consistency obtained among the various evaluation techniques gives confidence in the results. Introduction The Prudhoe Bay Field is the largest, most prolific and also one of the most complex combination drive reservoirs in the U.S. (1-6) The main objective for development is to maximize economic recovery while maintaining a high and stable rate of oil production. To achieve this, reservoir engineers have had to consider all classical drive mechanisms. gas and water injection programs, and finally EOR processes to be implemented programs, and finally EOR processes to be implemented at a later stage. Efficient reservoir management is dependent upon accurate knowledge of residual oil saturations, displacement efficiencies, and the time dependency of recovery associated with the various drives. P. 567
Methods previously presented in the literature for determining permeabilities from RFT* pretests were applied to an extensive amount of data recorded in 14 cored wells in the Prudhoe Bay Field. Arithmetically averaged core permeabilities in the zones of interest were validated by comparison with pressure build-up data. The foot by foot core data was then used to achieve an adequate vertical resolution for meaningful comparisons with RFT results. Comparisons indicate that corrected RFT data are consistently lower than corresponding core data. RFT- and core-derived permeabilities agree more closely when data is obtained from low-permeability sands. Trends between the two types of derived permeabilities exist for a few wells. However, these trends are different from well to well, and it is not possible to develop a usable field-wide correlation between RFT and core permeabilities. The study cites reasons for the differences between RFT- and core-derived permeabilities. These differences are attributed to relative permeability effects, uncertainties in fluid saturations, well-specific skin damage, reservoir anisotropy, and uncertainties in drawdown fluid flow equations for the RFT measurements. In conclusion, RFT permeabilities cannot be used to determine true reservoir permeabilities.
Accurate reservoir description significantly enhances the ability to assess reservoir performance and to predict future performance from simulation and analytical techniques. These predictions impact infill drilling, waterflood area selection and operation, production offtake strategies, well completions, and workover philosophy. An integrated approach that uses available production and surveillance data has been employed to refine reservoir description. The available data includes: open and cased hole log data, reservoir pressure and transient analysis interpretations, RFT pressure data, and individual well production histories. Downdip production from beneath continuous shale complexes has resulted in lateral movement of gas from the original gas cap at Prudhoe Bay. This and other physical evidence of barriers to vertical flow have been used to calibrate and enhance confidence in geologic shale maps based on well to well correlations. In areas where vertical gas cap expansion has occurred, tracking reservoir fluid movements has provided a method to identify the occurrence and observe the drainage of oil lenses from discontinuous shales. In addition, the data has allowed the computation of volumetric sweep efficiencies to improve reserve estimates, and delineate areas where recoveries can be increased by adjustments to offtake strategy, or application of future improved oil recovery techniques.
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