Summary 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. Introduction 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.

Summary Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s), and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery. This paper reviews progress in the application of large-volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. During the period November 1996-November 1997 three large-volume foam-gel treatments were successfully placed into the Rangely reservoir. The first 36?400 bbl treatment, implemented November 1996, increased the pattern oil rate from 260 barrels of oil per day (BOPD) in March 1997 to ±330 BOPD in August 1998; a conservative estimate of incremental oil recovery is ±40?000 bbl by the end of August 1998. The second 43?450 bbl treatment, implemented August-September 1997, increased the pattern oil rate from ±430 BOPD in March 1998 to ±470 BOPD in August 1998; post-treatment, the pattern oil rate data is described by a linear regression with slope, +56 BOPD but it is too early to make a firm estimate of incremental oil recovery. The third 44?700 bbl treatment, implemented October-November 1997, increased the pattern oil rate from ±330 BOPD in May 1998 to ±375 BOPD in July-August 1998; a linear regression of the post-treatment data gives a positive slope but again it is too early to estimate incremental oil recovery. Some general features in the pattern production response given by the three foam-gel treatments were observed. First, each of the treatments induces a stabilization in the pattern oil rate which, for treatments I and II, is accompanied by a decrease in the pattern gas rate. Second, the first positive oil rate response given by each of the treatments is observed 6-8 months after treatment execution and is dominated by the response at producer wells lying to the west/southwest and/or east/southeast of the treated injector well. For a given treatment volume, the cost of a foam-gel treatment at Rangely is 40%-50% below the average cost of polymer gel treatments. As the foam is injected at a higher rate, the total pump time required for a 40?000 bbl foam-gel treatment is similar to a 20?000 bbl polymer gel treatment. Early during pumping treatments II and III, we attempted to increase the CO2 content of the foam from 80 to 85 vol?%; this resulted in a wellhead pressure which was too close to the CO2 pressure limit necessitating a decrease in foam injection rate. Thus, in optimizing foam-gel treatment cost, there is a balance between maximizing the content of the inexpensive CO2 phase and minimizing total pump time. For Treatments II and III, the cost of the liquid phase formulation was reduced by decreasing the concentrations of surfactant and buffer. The implementation and evaluation of three large-volume foam-gel treatments at Rangely indicates that the foam-gel approach provides a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. Introduction A recent survey1 indicated that the proportion of U.S. EOR production recovered by gas injection has increased from 18% to 41% during the period 1986-1996. A major contribution to this trend has been the strong increase in the number of miscible carbon dioxide (CO2) projects which now account for > 70% of the total number of ongoing gas injection projects in the U.S. The Rangely CO2 flood began in 1986; currently, there are 372 active producer wells and 300 active injector wells, 259 of which are injecting CO2 using the water-alternating-gas (WAG) process. In the application of gas injection to heterogeneous reservoirs, oil recovery efficiency can be limited by poor conformance as an increasing proportion of the injected gas flows through higher permeability thief zones and/or fractures. The importance of conformance improvement has long been recognized at Rangely. The main problem being addressed is poor CO2 conformance due to preferential flow through the natural fracture network leading to premature gas breakthrough at the associated producers. This process increases operating costs and reduces oil recovery. The objective of the Rangely Conformance Improvement Team (CIT) is to improve conformance in order to reduce operating costs and increase the oil recovery to >1 billion bbl (>50% OOIP) compared to the current 815 million bbl (43% OOIP). A number of mechanical methods and chemical treatments have been employed to improve conformance at Rangely. While dual injection strings and selective injection equipment (SIE) have been used for improved injection profile control, chemical treatments using polymer gels2 and CO2 foam3 have been used to improve volumetric sweep efficiency and oil recovery. During the period 1994-1997, 49 injector wells were treated by placing a MARCIT™ gel4 into the fracture network.5 While these treatments have improved local sweep efficiency and oil recovery, economics limit the maximum treatment volume per injector well to 15?000-20?000 bbl. Certain regions of the Rangely reservoir require considerably larger treatment volumes to reduce the permeability of a larger volume of the fracture network and improve conformance in a larger volume of the well pattern.

Thirty-six thousand four hundred barrels of CO 2 gelled foam were successfully placed via an injector well into the Rangely Weber Sand Unit in Colorado. The treatment objectives were ͑1͒ to improve volumetric conformance in this CO 2 flood by reducing excessive CO 2 breakthrough through fractures, and ͑2͒ to increase oil recovery from the associated producers. Local reservoir characteristics indicate the need for a large-volume treatment to achieve these goals. The required treatment volume is beyond the economic limits of standard gel systems. Foam gel technology is one way to economically achieve in-depth conformance improvement at Rangely by replacing 60 to 80% of the liquid phase by the less expensive CO 2 phase. A gelled foam system was specifically designed for application to Rangely conformance problems. The field-tested surfactant/gel system was designed according to the following criteria: ͑1͒ to produce strong and robust gelled foams under the harsh pH conditions of a CO 2 flood, ͑2͒ to provide enough gelation delay to achieve the injection of a large foam volume with manageable injectivity reduction, and ͑3͒ to considerably reduce the unit cost of the treatment fluid relative to standard non-foamed gel systems. This paper describes the methodology used to design and test the optimum gelled foam system for Rangely. Laboratory results are presented to support the chemicals system selection, including gelation kinetics experiments, surfactant selection, and corefloods with supercritical CO 2 at field conditions. The candidate well selection process is described, including injection profile surveys, offset well response, and bypassed reserves calculation. Data taken during the injection phase of the program, including injectivity history and on-site quality control monitoring of the chemical system behavior, are given. Finally a preliminary assessment of the impact of the treatment on CO 2 cycling rates and incremental oil production is presented.

F. Friedmann, Chevron Petroleum Technology Company, T.L. Hughes, Schlumberger Cambridge Research, M.E. Smith, Chevron Petroleum Technology Company, G.P. Hild, Chevron USA Production Company, A. Wilson and S.N. Davies, Schlumberger Cambridge Research Abstract Thirty six thousand four hundred barrels of CO2 gel led foam were successfully placed via an injector well into the Rangely Weber Sand Unit in Colorado. The treatment objectives were 1) to improve volumetric conformance in this CO2 flood by reducing excessive CO2 breakthrough through fractures and 2) to increase oil recovery from the associated producers. Local reservoir characteristics indicate the need for a large-volume treatment to achieve these goals. The required treatment volume is beyond the economic limits of standard gel systems. Foam-gel technology is one way to economically achieve in- depth conformance improvement at Rangely by replacing 60% to 80% of the liquid phase by the less expensive CO2 phase. A new gelled foam system was specifically designed for application to Rangely conformance problems. The field-tested surfactant/gel system was designed according to the following criteria:to produce strong and robust gel led foams under the harsh pH conditions of a CO2 flood,to provide enough gelation delay to achieve the injection of a large foam volume with manageable injectivity reduction andto considerably reduce the unit cost of the treatment fluid relative to standard non-foamed gel systems. This paper describes the methodology used to design and test the optimum gel led foam system for Rangely. Laboratory results are presented to support the chemicals system selection, including gelation kinetics experiments, surfactant selection and core floods with supercritical CO2 at field conditions. The candidate well selection process is described, including injection profile surveys, offset well response and bypassed reserves calculation. Data taken during the injection phase of the program, including injectivity history and on-site quality control monitoring of the chemical system behavior are given. Finally, a preliminary assessment of the impact of the treatment on CO2 cycling rates and incremental oil production is presented. Introduction Oil recovery efficiency in CO2 floods can be substantially reduced if premature CO2 breakthrough occurs at offset producers through fractures. Injector polymer gel treatments have successfully improved volumetric sweep in some CO2 field projects. CO2 diversion from the fracture network to the adjacent matrix rock resulted in the recovery of additional oil reserves. However, the volume of injector polymer gel treatments can be limited by cost which in turn limits the potential impact on reservoir sweep. If there is significant crossflow between the thief zone and the remainder of the reservoir, larger treatment volumes impact sweep over a large volume of the reservoir thereby, improving incremental oil recovery. Gelled foam technology is one way to economically increase the treatment volume when reservoir characteristics dictate the need for in-depth conformance improvement. Fluid costs can be substantially reduced if 60% to 80% of the expensive aqueous phase can be replaced by a cheap readily available phase such as CO2. P. 883^

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