CO2 flooding has become the fastest growing gas injection EOR method, contributing 4.8% of U.S. oil production. An integrated approach was undertaken to evaluate the CO2-EOR feasibility for Marathon's Rocky Mountain (RM) region assets. The RM assets of the Wind River and Big Horn basins were evaluated using detailed geological and compositional reservoir models imposed with multiple development scenarios. The fractured nature of the RM assets posed a challenge for reservoir modeling, which prompted combinations of approaches such as production ranking to facilitate fracture descriptions. Extensive laboratory CO2-oil PVT tests were also conducted to tune a representative equation-of-state fluid model to confidently quantify reservoir fluid behavior. CO2 injection scenarios for two oil fields were evaluated using compositional dual-porosity and dual-permeability reservoir models. Performance evaluation under multiple sensitivities, namely WAG ratio, fluid properties, injection pressures, and fracture characteristics were also investigated to quantify their impact on oil recovery factors. The simulation recovery results were non-dimensionalized to generate distinct type-curves, which were then applied to areas that have similar fracture and geological characteristics. The unique workflows generated during this study were verified and benchmarked by using them to history match the performance of an analogous RM field currently under CO2 injection. This paper describes the integrated approaches applied to maturing RM assets, which in addition to identifying significant IOR potential, have helped enhance the reservoir's characterizations, standardize subsurface workflows, aid facilities design, and scale-up performance data for optimal reservoir management. 1. Improved Oil Recovery In 1978, the United States Congress commissioned the Office of Technology (OTA)(1) to evaluate the state of the art in U.S. oil production. The OTA concluded that the 300 billion barrels of known U.S. oil were economically unproducible by conventional methods in practice at that time. The OTA report also evaluated a range of enhanced oil recovery (EOR) techniques and their potential for improving the prospects of extracting a sizeable fraction of this known resource base. These major political and administrative amendments triggered increased interest in EOR in late 70's and early 80's, most notably in California and the Permian Basin of West Texas. Now, 30 years later, there is again a strong interest in improving domestic oil production(2), which has been on a continuous decline of approximately 3% per year (Figure 1)(3), while the total 'unproducible oil' referred to in the OTA report(1) has increased to a whopping 400 billion barrels(4). The U.S. Geological survey reported(5) that the bulk of the conventional oil yet to be produced in the world resides in already discovered reservoirs, with the ever decreasing possibility of finding newer reserves. The most important conclusion of this report, from an oil self-reliance point of view, is that the EOR techniques have not been tried for most of these reservoirs. Therefore, the potential for EOR applications in the U.S. is very large with a target of approximately 400 billion barrels(6).

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This paper reports on the design and operation of two CO 2 EOR tests conducted in the Rock Creek field in Roane County, WV. The history, fluid properties, and geology of the Rock Creek field are presented first. The test area is then addressed more specifically with an evaluation of the cores and the geophysical logs of the injection, production, and observation wells. Finally, the injection history and the production response are documented.The first test was conducted in two to-acre [4-ha], normal five-spot patterns, with 13,000 scf CO 2 /STB oil [2315 std m 3 / stocktank m 3 ] injected. This test effort recovered 13,078 STB [2079 stock-tank m 3 ] of oil [3 % of the original oil in place (OOIP)] but was terminated after 3 years before all oil capable of being mobilized was recovered. About 15% of an HCPV was injected. The first test was followed by a second, smaller test that, given the same amount of CO 2 to be purchased, would result in an increase in HCPV's of C02 injected and a greater potential for oil recovery. The second test was conducted in a 1.55-acre [0.63-ha], normal four-spot pattern contained within the original test pattern. This test lasted 2 years, with 9,000 scf CO 2 /STB oil [1603 std m 3 /stock-tank m 3 ] injected. Recovery from this test was 3,821 STB [607 stock-tank m 3 ] of oil (11 % of the OOIP). About 48 % of an HCPV was injected. It appears that CO 2 miscible flooding is technically successful in Appalachian reservoirs.

The U.S. DOE Morgantown Energy Technology Center and the Pennzoil E&P Co. predicted the recovery and economic potential of a full-field, CO 2 miscible EOR flood at the Rock Creek field, Roane County, WV. Data used in this evaluation were obtained from two miscible CO 2 Rock Creek field tests: (1) a pilot test consisting of two contiguous normal fivespot patterns, each containing 10 acres [4 hal, and (2) a 1.55-acre [0.63-ha] normal four-spot minitest. Core data from the eight injection wells and three observation wells were used to determine reservoir input parameters, and fluid samples were analyzed to obtain fluid properties. A predictive model was used to calculate oil recovery and project economics. The model's base-case run showed that an oil price of $391bbl [$245/m 3 ] was required to produce a 15 % discounted cash flow rate of return (DCF ROR). A sensitivity study was then conducted on operating parameters [Le., pattern size, water-alternating-gas (WAG) ratio, total HCPV of WAG injected, and injection rate] and economic parameters (e.g., oil price and CO 2 cost) to determine their effect on project performance and project economics.

The accuracy of four-point estimation methods (simple averaging, fifth-degree bicubic spline, inverse weighted distance squared, and kriging) were compared in five reservoir layers using data sets consisting of five different reservoir properties (horizontal permeability, vertical-horizontal permeability ratio, thickness, porosity, and top of structure).This study had four objectives:(1) to determine if kriging could be applied to petroleum-related data sets; (2) to determine the optimum estimation method by layer for each reservoir property and to use that optimum method to assign values to grid blocks for use in a reservoir simulation study;(3) to determine if a correlation could be established between the optimum estimation method and a reservoir property; and ( 4) to determine if criteria could be established for choosing the optimum estimation method through initial evaluation of data set size, distribution, and spatial correlation.Kriging was found to be the optimum estimation method in 10 out of 12 cases for data sets having a normal or lognormal histogram distribution and a stable overall semivariogram.Simple averaging and inverse weighted distance squared were optimum in the other two cases. Fifth-degree bicubic spline proved to be the optimum estimation method for data sets that did not have a normal or lognormal histogram distribution.Simple averaging was found to be the optimum method for data sets that did not have stable overall semivariograms because of limited data set size.These results show that kriging can be applied to petroleum-related problems with a relatively small number of data points as compared to kriging's usual application in the ore industry with much larger data setsi