Reservoir Pore Space Research Articles

Response of North Cowden and Goldsmith Crudes to Carbon Dioxide Slugs Pushed by Nitrogen

Fischer, Daniel D.; Texas A and M U. Bilhartz, Dale; Texas A and M U. Holt, Charles; SPE, Texas A and M U. Johnson, Michelle; SPE, Texas A and M U. Breeze, B.J.; SPE, Texas A and M U. Aud, William W.; SPE, Texas A and M U. Crawford, Paul B.; SPE, Texas A and M U. Texas Petroleum Research Committee Summary Laboratory studies have been conducted to determine oil recovery of the North Cowden-Grayburg and Goldsmith 5,600-ft [1700-m] Clearfork crudes of west Texas when pushed by CO2 at various pressures. Studies were made at reservoir temperatures of 100 and 111 degrees F [38 and 44 degrees C] for the North Cowden and Goldsmith 5,600-ft [1700-m] crudes, respectively. At these temperatures, it was found that the oil recovery ranged from 57 to 99% as the CO2 pressure increased from 700 psi to 1,800 psi [4.8 to 12.4 MPa]. Normally the North Cowden crude gave a higher oil recovery throughout the pressure range. In recognition that CO2, may be in short supply, studies were made of the possibility of using a slug of CO2 pushed by nitrogen. For the slug tests the CO2 slugs ranged from 2.5% to 25% HCPV. All CO2 slugs were pushed by nitrogen. The oil recovery ranged from approximately 60 to 99% over this slug size. The data were obtained in slim-tube equipment ranging from 40 to 100 ft [12 to 30 m] in length. The miscible bank formed between the CO2 and the body of the crude oil was observed to be a clear strawcolored liquid. The analyses of the clear liquid and crude oil conclusively demonstratethat the crude oil undergoes a continuous fractionation process when miscibly displaced by CO2,the need for tong flow tests, andthe inability to interpret most PVT cell data in terms of miscibility. Introduction Most U.S. reservoirs have been substantially depleted by primary production and many of these reservoirs are now in the terminal stages of waterflooding. If abandoned, these oil reservoirs may still leave more oil underground than they have produced. Tertiary oil recovery methods are being developed to recover a large fraction of the original oil in place. One of the enhanced recovery methods receiving consideration is a process whereby a slug of CO2 is injected to achieve miscibility with the crude oil and the CO2 slug is displaced with nitrogen. This method reduces the amount of CO2 required, stretches the CO2 supply, and usually reduces the cost. This would permit a wider application of the CO2 miscible recovery process and, we hope, recover additional oil from our reservoirs. Nitrogen may cost approximately one half as much per thousand cubic feet (Mcf) [28 m 3] as CO2. For many oil reservoirs, 1 Mcf 129 m3] of nitrogen may occupy about three times as much reservoir pore space as the same amount of CO2. Most of the known CO2 reserves are located in Colorado, New Mexico, Utah. and Mississippi. Much of the CO2 target oil is in the Permian Basin of west Texas and New Mexico. A pipeline will be required to transport CO2 to the prospective oil reservoirs. Several companies are moving forward with line construction. The hypothesized CO2 flood potential for west Texas alone has been estimated at 3 to 4 billion bbl [0.48 ⨯ 10(9) to 0.76 ⨯ 10(9) m3] of oil. This will require a lot of CO2. For a very thorough review of CO2 flooding, see Ref. 1, which cites more than 60 references. Whereas CO2 for miscible displacement is in short supply, nitrogen is plentiful. The nitrogen would be obtained from the air by a cryogenic process. In this process, air is compressed and subsequently cooled to approximately –300 degrees F [–184 degrees C]. At this temperature the air liquefies and permits fractionation and purification. The pure nitrogen is taken from the top of the fractionating column and warmed to a gaseous state near atmospheric temperature. The warm gaseous nitrogen is compressed for injection into the oil reservoir. JPT P. 96^

CO2 Flooding Strategy in a Communicating Layered Reservoir

Abstract A computer simulation study of the effects of crossflow between sublayers of a single major zone of a San Andres dolomite reservoir during injection of a CO2 slug followed by a waterflood shows that the crossflow causes a substantial reduction in oil recovery. This loss can be reduced by use of alternate injection of small increments of CO2 and water during the CO2 slug injection. Introduction The subject of this investigation is the Southeast Seminole San Andres Unit (SESSAU), which is operated by Belco Petroleum Corp. Properties of this reservoir are listed in Table 1. The Southeast Seminole field was discovered in Feb. 1964. Primary recovery through June 1979 was about 10.8% OOIP. It is estimated that ultimate primary recovery would be about 15%. However, a unit was formed in Feb. 1978 and waterflooding was begun in May 1979. Waterflood response has now occurred in most of the producing wells. CO2 flooding could be initiated soon or at a much later date after most of the secondary oil recovery has occurred. The purpose of this study was to determine the approximate range of enhanced oil recovery that might be expected from CO2 flooding, based on a five-spot symmetry element. It was recognized that this information could not be extrapolated directly to estimate such recovery for the entire unit, but it would serve as a basis for determining whether to pursue the possibility. In addition, guidance could be obtained as to the preferred strategy of operation in CO2 flooding based on reservoir and oil characteristics and the extent of waterflooding at the start of CO2 flooding. In this feasibility study, the following factors were investigated: 1. extent of previous oil recovery at the start of CO2 flooding, 2. amount of residual oil saturation left by CO2 flooding, 3. extent of viscous fingering of CO2 through the mobile oil phase, 4. extent of availability of waterflood-trapped oil for reconnection by CO2, 5. permeability reduction for the nonaqueous phase resulting from an asphaltic precipitate reported to occur in CO2 flooding, 6. CO2 slug size (always followed by waterflooding to an economic limit), 7. continuous injection of the CO2 slug vs. alternating injection of small increments of water and CO2 (WAG or WACO2), 8. permeability and porosity variation by layers, and 9. degree of crossflow between layers. The reservoir simulation program used in this study was developed by Todd, Dietrich and Chase Inc. to simulate either compositional mass-transfer processes during a displacement or miscible viscous fingering during a displacement, but not both at the same time. It is a finite-difference simulator, and thus uses a reservoir model in which the composition is considered uniform within each of the discrete grid blocks that comprise the reservoir pore space. Phase equilibrium can be calculated for the composition in each grid block. However, if viscous fingering occurs, then either the fineness of the grid must be smaller than the size of the fingers or a method such as the mixing-parameter method must be used to simulate in a coarser grid the effect of viscous fingering on the mobility of the fingering fluid and of the fluid through which the fingers are penetrating. If the compositional transition zone in which phase separations and mass transfer occur between phases in CO2 flooding is to be represented, the grid system must be even finer than that required to delineate viscous fingers, since this transition zone lies along the side surfaces and at the tips of the viscous fingers. The thickness of the transition zone is about 4 to 8 ft (1.22 to 2.44 m), and 50 grid blocks are required to represent phase equilibrium changes accurately through this zone.