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Results
Abstract Carbon dioxide injection, either by huff and puff or displacement operations, results in a crude oil viscosity reduction at pressures below the miscibility conditions. Carbon dioxide miscibility occurs in reservoirs at miscible temperature and pressure, but these conditions are not possible in shallow reservoirs. Improved oil recovery in a shallow reservoir depends on the degree of viscosity reduction at the reservoir temperature and pressure. A recovery project's success depends on the interaction between the carbon dioxide and the reservoir system. P. 243
- North America > United States > Wyoming > Powder River Basin > Salt Creek Field (0.99)
- North America > United States > Montana > Cut Bank Field (0.99)
- North America > United States > California > Los Angeles Basin > Wilmington Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
ABSTRACT: The Alkaline-Surfactant-Polymer, ASP, process can significantly enhance waterfloods for appropriate reservoirs using carefully designed, reservoir specific, chemical injection strategies. This ASP technology recovers waterflood residual oil by reducing the capillary forces trapping the oil and improving the overall contact efficiency. The Minnelusa formation in the Powder River Basin was the location of the first field-wide application of this process in the U.S. An assessment of this early project nearing the end of its economic life and of other ongoing ASP projects provides an estimate of the potential of the ASP process to add reserves in other Minnelusa fields. Analysis of approximately 120 Minnelusa oil fields in the Powder River Basin indicates that the total original stock tank oil in place exceeds one billion barrels. The potential incremental oil recovery of the ASP process to these fields approaches 130 million barrels. This process can be applied at an incremental cost of $1.60 - $3.50/bbl. Introduction An Alkaline-Surfactant-Polymer, ASP, design was developed and applied to the West Kiehl Minnelusa Field beginning in 1987. This was the first field-wide application of the ASP process in the U.S., but was applied as a secondary recovery method following primary production. This made the interpretation of the waterflood incremental oil somewhat more speculative, as there was no bases for establishing waterflood recovery by decline analysis. A complication was the field size, configuration and number of wells meant that a significant fraction of the pore volume could not be swept by flooding processes. The first published analysis in 1992 showed an incremental recovery of 0.11 pore volume (340.5 Mbbl) based on project performance and laboratory data. A much more detailed evaluation was performed relying on new laboratory data, numerical simulation, and much more field performance data to assess the effectiveness of the ASP process, and to compare the West Kiehl performance with that of other Minnelusa fields. This paper is a summary of the findings of the detailed evaluation. P. 231
- North America > United States > Wyoming (1.00)
- North America > United States > Montana (0.90)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Kiehl Field (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- North America > United States > Kansas > State Field (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Since the early 1970s, numerous presentations have been made and articles written about pilot tests and field-scale enhanced oil recovery projects using carbon dioxide (CO2) as a solvent. This paper summarizes publicly available data on 30 paper summarizes publicly available data on 30 projects. The use of CO2 has grown significantly projects. The use of CO2 has grown significantly since the early-1980s, especially in the Permian Basin, as reliable supplies of CO2 became more available. Today, even with depressed crude oil markets, the use of CO2 continues to grow. The use of CO2 in the Rocky Mountain region is increasing, primarily among those with prior CO2 flooding primarily among those with prior CO2 flooding experience in the Permian Basin. As the demand for CO2 increases in the Rocky Mountains, so will the supply, and the same growth experienced in the Permian Basin should be seen. As with any major Permian Basin should be seen. As with any major project in the oil industry, the enhanced recovery project in the oil industry, the enhanced recovery of oil requires thorough advance planning to determine the optimum EOR method. This summary of CO2 projects is intended to provide a brief on each project, describe the reservoir parameters, and project, describe the reservoir parameters, and review the conclusions of the individual authors, in addition to providing a quick reference of available papers to which those interested may turn for greater detail. Since the use of CO2 has been successfully tried in a wide range of reservoirs and under a variety of operating conditions, the application of CO2 in Rocky Mountain reservoirs should be every bit as successful as it has been elsewhere. Introduction The use of CO2, both miscibly and immiscibly, has grown dramatically since the start of this decade, spurred by the installation of CO2 pipelines in the Permian Basin in the early-1980s. While many Permian Basin in the early-1980s. While many challenges still face the user of CO2, the increased use of CO2 to recover residual oil evidences the optimism the industry has towards enhanced oil recovery using CO2. The use of CO2 to recover additional crude oil includes immiscible flooding and an individual well stimulation technique known as "huff 'n' puff." This paper summarizes 21 miscible floods, 4 immiscible multi-well floods and 5 immiscible "huff 'n' puff" projects. puff" projects. The original intent of this paper was to present both successful and unsuccessful projects so that comparisons could be made. However, the search of available data banks for papers published on unsuccessful projects was fruitless. It is likely that some of the projects discussed could be considered marginally economic with depressed crude oil prices even though they were technical successes. This paper does not attempt to draw conclusions of the projects reviewed but instead presents, without interpretation, conclusions as presents, without interpretation, conclusions as published in the individual references. The reader published in the individual references. The reader should bear in mind while reviewing this paper that many of the extrapolations of incremental recoveries and other factors are based on performance data from relatively early in a performance data from relatively early in a project's life. project's life. DEFINITIONS Terminology used in this paper is consistent with that used in the EOR arena. The term "incremental oil" refers to the oil production in excess of a base decline curve for continued operations. Gross utilization of CO2 is defined as the total injected volume of CO2, including any recycled volumes, divided by the total incremental recovery. The net utilization is the purchased volume of CO2 divided by the total incremental recovery. Miscible flooding refers to the use of CO2 at a reservoir pressure greater than that necessary for the CO2 to pressure greater than that necessary for the CO2 to mix with the reservoir oil, commonly referred to as the minimum miscibility pressure (MMP). Immiscible flooding or stimulation uses CO2 at pressures less than the MMP and relies more on the reduction of viscosity and interfacial tension, and the swelling of the oil contacted by the CO2. In discussing various CO2 floods, the volume of CO2 injected is commonly referred to in terms of percent of hydrocarbon pore volumes (HCPV). P. 499
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.70)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (45 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract In this paper the design methodology for the Warner Ranch Unit polymerflood is reviewed. The design included field tests which are believed to have underestimated polymer retention. This result in turn adversely affected project performance. The propagation of the polyacrylamide through the rock propagation of the polyacrylamide through the rock was much less than anticipated. Performance of a polymer injection well is compared Performance of a polymer injection well is compared to several J-Sand water injection wells. It is evident that injectivity is greatly reduced with polymer injection; the loss in injectivity polymer injection; the loss in injectivity approximates that which is expected when the mobility ratio is reduced to less than one. Most field projects have demonstrated that the absolute benefits of polymerflooding are difficult to quantify, and the Warner Ranch Unit is not an exception. Two producing wells produced 18,000 bbl of incremental oil attributed to polymer injection. Introduction The Warner Ranch Field Unit is located in Banner County, Nebraska. The area is part of the Denver-Julesburg basin of western Nebraska, northeastern Colorado, and southeastern Wyoming. Production is from the Lower Cretaceous age J-Sand Production is from the Lower Cretaceous age J-Sand at 6150 ft. Like most J-sand reservoirs, Warner Ranch is a small thin sand lens containing undersaturated 37 degrees API sweet crude. The field produced 163,729 bbl of primary oil from the J-1 produced 163,729 bbl of primary oil from the J-1 lens over the sixteen years prior to waterflooding. Pertinent reservoir rock and fluid characteristics Pertinent reservoir rock and fluid characteristics are given in Table 1. Well locations are illustrated on the Fig. 1 isopachous map. Chain Oil, Inc. of Scottsbluff, Nebraska, unitized the six-well field on Nov. 1, 1982. Well D-1 was drilled, and water injection commenced during January, 1983, into Wells D-1 and C-2. By April, 1983, production response at Wells C-1 and C-3 was noted as shown in Fig. 2a. The same data is plotted with cumulative injection as the x-axis rather than as time in Fig. 2b. During May and June, pressure transient tests were performed on Wells C-2 and C-1 in order to define those reservoir parameters required for forecasting waterflood performance. This forecast was used in conjunction with a polymerflood feasibility study. polymerflood feasibility study. The C-1 buildup test illustrated in Fig. 3 was used to determine oil mobility, while the C-2 falloff test, Fig. 4, was used to determine water mobility. The polymer falloff tests included in Fig. 4 will be discussed later. These mobilities were used to construct the relative permeability curves depicted in Fig. 5. The procedure used to develop the relative permeability curves and the special polymer field tests are discussed in detail in reference 2. It is interesting to note that the relative permeability curves suggest that this J-Sand permeability curves suggest that this J-Sand reservoir is intermediate to slightly oil-wet, information which is supported by the contact angle work done by Leachs and Emery twenty years ago. Presented in Fig. 6 are waterflood and polymerflood Presented in Fig. 6 are waterflood and polymerflood forecasts developed from the relative permeability data, the fluid characteristics given in Table 1, and various presumed in-situ polymer viscosities. Published area and vertical sweep efficiency Published area and vertical sweep efficiency correlations based on fluid mobility considerations were used along with fractional flow theory to produce the forecasts. The forecasts are produce the forecasts. The forecasts are illustrated as oilcut versus cumulative oil produced because of problems with predicting the injection rate. The actual performance is included for comparison. P. 465
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The success of a CO2 flood largely depends on the quality of its injection wells. The wells must confine injection to the desired pay intervals and withstand the corrosive nature of CO2 for the life of the flood. These are difficult goals to achieve considering the primary candidates for CO2 flooding are mature waterfloods where the wells may have been in service for forty years or more. Casing and cementing practices of the past were often inadequate for a long waterflood life, and are certainly unacceptable for a long term tertiary recovery project. This paper describes innovative techniques employed in the MCA Unit, located in southeast New Mexico, for converting old waterflood injection wells into state-of-the-art CO2 injection wells. The solutions developed for the MCA CO2 Project have considerable application to other CO2 projects and can be profitably employed to improve projects and can be profitably employed to improve waterflood recovery as well. Introduction A CO2 project is currently being installed in the MCA (Maljamar Cooperative Agreement) Unit near Maljamar in southeast New Mexico (see Figures 1 and 2). Development is occurring in stages, and when fully implemented, the project will cover 3920 acres of the 8040 acre unit. The MCA Unit occupies a large part of the Maljamar Grayburg-San Andres Pool. The Pool was discovered in 1926, and the Pool. The Pool was discovered in 1926, and the majority of the development occurred in the early 1940's. Water injection was initiated across the field between 1965 and 1969. There are five dolomitic Grayburg-San Andres pay zones (with average depths ranging from 3800' to 4100') under waterflood in the Unit. Many of the problems common to old waterflood injection wells are prevalent at the MCA Unit. These problems include:–Open-hole completions with multiple nitroglycerin shot sections, –Inadequate injection distribution, –Small diameter casing (4-1/2"), –Deteriorated casing, –Significant water loss to non-pay intervals, and –Regional pressure charging, causing the wells to "backflow" for extended periods of time. The majority of the injection wells within the planned CO2 flood boundaries had small diameter planned CO2 flood boundaries had small diameter casing, multiple "shot" sections, and were losing 20% of the injected water out of zone. Prior to the fall of oil prices in February, 1986, we planned to plug and abandon these wells and planned to plug and abandon these wells and redrill. The oil price collapse made it necessary to reduce capital expenditures and operating costs to maintain project economics. The development of technology to convert old waterflood injectors into state-of-the-art CO2 injectors eliminated the need to redrill injection wells. The injection well recompletion system now in use provides solutions to all the problems prevalent provides solutions to all the problems prevalent at the MCA Unit. The system is effective in eliminating waterloss, improves vertical distribution of injected fluids, uses injection equipment that is CO2, resistive and allows the use of selective injection equipment. We have also developed a wellhead that eliminates the need to backflow wells. This paper presents an overview of how the system solves common injection well problems and how the system is implemented. P. 491
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)