Reservoir Polymer Gel Treatments To Improve Miscible CO2 Flood
- G.P. Hild (Chevron USA Production Co.) | R.K. Wackowski (Chevron USA Production Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 1999
- Document Type
- Journal Paper
- 196 - 204
- 1999. Society of Petroleum Engineers
- 4.6 Natural Gas, 7.1.10 Field Economic Analysis, 6.5.2 Water use, produced water discharge and disposal, 5.7.5 Economic Evaluations, 5.4 Enhanced Recovery, 7.1.9 Project Economic Analysis, 5.4.5 Conformance Improvement, 1.14 Casing and Cementing, 3 Production and Well Operations, 5.1.1 Exploration, Development, Structural Geology, 5.4.2 Gas Injection Methods, 1.6 Drilling Operations, 4.1.9 Tanks and storage systems, 1.10 Drilling Equipment, 5.6.4 Drillstem/Well Testing, 5.4.3 Gas Cycling, 5.4.1 Waterflooding, 4.1.5 Processing Equipment, 1.2.3 Rock properties, 3.3.2 Borehole Imaging and Wellbore Seismic, 4.1.2 Separation and Treating, 4.3.1 Hydrates, 5.5.2 Core Analysis, 2.4.3 Sand/Solids Control, 4.2 Pipelines, Flowlines and Risers, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.2.1 Wellbore integrity
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This paper describes the application of large volume (10,000 bbl) chromic-acetate acrylamide polymer gel treatments to improve sweep in the CO2 flood at Rangely Weber Sand Unit located in northwestern Colorado. Conformance improvement has become the key operating strategy due to the maturing flood's associated natural increase in operating expense and declining oil production. Recent efforts using large volume polymer gel treatments on injection wells have been successful. The key to success has been the pairing of accurate problem characterization with a technology that can effectively impact the deep reservoir problem. The gel system has been effective because it has proven to be resistant to the low pH environment associated with CO2 flooding and has been pumped in significant quantities to improve sweep. Previous application of relatively small volume, near-wellbore treatments were not effective at preventing flow in the high permeability matrix and fracture pathways believed to be responsible for poor sweep. Results from 44 injection well treatments performed through mid-1997 are discussed. Candidate selection, treatment logistics, individual treatment examples, and full project economics are provided. Field modeling and forecasting is discussed to show the significant impact of continued treatments on field performance.
The Rangely Weber Sand Unit is in Rio Blanco County, Colorado, USA. It is the largest field in the Rocky Mountain region in terms of daily and cumulative oil production. Rangely Weber sandstone production was discovered by the California Company in 1933, but was not developed until 1944. Initial development, completed in 1949, was on 40-acre spacing. The field was unitized in 1957 and peripheral water injection began in 1958. Hydrocarbon gas was reinjected until 1969 when fieldwide waterflood pattern injection started. Infill drilling on 20-acre spacing began in 1963 and continued in earnest until the mid-1980's. Most areas of the field are currently being processed on 20-acre spacing. A total of 899 wells have been drilled to the Weber formation. Currently, there are 378 active producers and 280 active injectors, 259 of which are injecting CO2 utilizing the water-alternating-gas (WAG) process. The miscible CO2 flood was initiated in October 1986.
Original oil in place (OOIP) is estimated to be 1.88 billion stock tank barrels. Ultimate primary plus secondary recovery from the Unit is expected to be 798 MMSTBO, or 42.5% OOIP. Approximately 332 MMSTBO, or 17.6% OOIP is attributed to primary recovery. Ultimate cumulative tertiary recovery is expected to be 129 MMSTBO, or 6.8% OOIP. Cumulative production through October 1997 is 814 MMSTBO.
The Pennsylvanian-Permian Weber formation consists of a sequence of interbedded eolian sandstones and mixed fluvial siltstones, shales, and sandstones at depths between 5,500 and 6,500 feet. Six major producing zones have been identified and are separated by five major fluvial shale breaks that are correlative across the field. These fluvial shale breaks will most likely act as effective vertical permeability barriers when they exceed 10 to 20 feet in thickness.
The average gross thickness of the reservoir is 675 feet. The net effective reservoir thickness averages 175 feet, although varying widely. Effective reservoir is defined by porosities greater than 8% and a clean, eolian sand cutoff of 50 API gamma ray units. Average effective porosities are 11%. Permeabilities range from 0.1 to 200 md with an average of 10 md for the effective sands. There is a general trend of increasing permeabilities and net sand thickness from southeast to northwest across the field. The ratio of vertical to horizontal permeability varies from 0.25 to 0.50.
The fieldwide performance of the CO2 project has been very successful, but the mature state of the Rangely CO2 project has made conformance improvement (CI) increasingly important. Since unit operating expense (OPEX) is highly influenced by CO2 purchases and handling, it is imperative to prevent CO2 injection into zones or parts of the reservoir that are no longer yielding incremental oil. As the Rangely CO2 project matures, the normal progression in the WAG process is to increase the ratio of injected water to CO2 over time. This is referred to as tapering, and is triggered by the economic performance of CO2 in each pattern. There were however, a significant number of patterns that were being tapered prematurely in comparison to the field average or adjacent patterns. While the tapering of these patterns was a good economic decision, it represented the potential for bypassed or abandoned CO2 reserves. Further investigation into these patterns revealed poor injectant conformance — poor vertical sweep was evident in the injection profile data, and poor areal sweep was recognized by rapid breakthrough to only one producer in the pattern.
Past efforts at improving conformance had primarily been limited to near-wellbore methods such as dual injection strings, selective injection equipment, straddle packers, cement squeezes, solid plugging materials, and small volume polyvinyl alcohol and chromium (VI) gels. While controlling fluids at the wellbore has improved the water and CO2 flood performance in the past, the current well age and associated poor wellbore integrity has made their utility rather limited.
Controlling fluids in the near-wellbore region may result in a good injection profile but does not insure that the vertical or areal distribution of fluids is maintained out in the reservoir. In order to correct poor vertical and areal sweep in the reservoir the flow of injectants must be diverted from the over-processed pathways to the bypassed regions. This strategy can be realized by placing a diverting agent of significant volume in the interwell area. The rock properties of the Weber sandstone can actually be an advantage for the placement of diverting agents such as polymer gels. The viscosities of the uncrosslinked polymer gel (gelant) are such that it can only be placed into the high permeability pathways and therefore reduces the risk of plugging damage to the 10 md matrix.
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