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Results
Abstract Field testing results are reported for a new conformance-improvement-treatment (CIT) gel technology, where acrylamide polymers are crosslinked with a chromium(III) [CrIII] crosslinking agent. Results are reported for nine field tests performed in Wyoming's Big Horn Basin during 1985 and 1986. All nine treatments were designed to reduce conformance problems encountered in naturally fractured reservoirs. Seven were injection-well treatments, and two were production-well treatments. All nine field tests were operational and technical successes. Significant amounts of incremental oil production were obtained following five of the seven injection-well field tests and at both production-well field tests. Peak incremental-oil-production rates resulting from the injection-well gel CITs ranged from 38 to 380 bbl/D [6.0 to 60 m3/d). The first production-well field test, in a carbonate reservoir, generated 7500 bbl [1190 m3 of incremental oil (beyond 4400 bbl [700 m3 of projected base oil production). The second production-well field test, in a sandstone formation, required a smaller than expected gel volume. The second treatment has generated over 14,000 bbl [2200 m3) of incremental oil and did pay out in five months. Overall, the economics of the field testing program are encouraging. For the seven field tests which stimulated incremental production, incremental stock-tank oil production through May 1987 was 450,000 bbl [71,500 m3; and the production wells affected by these seven gel CITs were still producing at a combined incremental-oil-production rate of 780 bbl/D [124 m3/d] above pretreatment decline rates. Cost of the seven field tests (including well workover, gel, and gel injection costs) totaled $438,000, yielding a cost for incremental stock-tank oil production through May 1987 of $0.97/bbl [$6.10/m3). The field testing program has shown that the new gel CIT technology can generate significant amounts of incremental oil production profitably, even during times of depressed oil prices, and can be used to significantly reduce water/oil ratios (WORs). Field testing has also shown that the gel technology is operationally attractive. At all nine field tests, quality CrIII gel was made consistently and injected without encountering any significant operational, safety, or environmental problems. Little, or no, chromium was detected in associated produced fluids. As intended, significant reductions in injectivity occurred during all the injection-well field tests. The field tests demonstrated that large volumes of gel can be injected into the cited fractured Big Horn Basin reservoirs. Introduction This paper, the second in a series, reports on field testing of a new and patented, Del conformance-improvement-treatment (CIT) technology. The aqueous gels are formed by crosslinking acrylamide polymers (polyacrylamide or partially hydrolyzed polyacrylamide) with a chromium(III) (CrIII) crosslinking agent. The first paper reported on laboratory testing and evaluation of the new gel technology, and presented a brief description of the chemistry of the new gel technology. In this paper, results relating to the new gel technology are reported for the first nine field tests that were carried out as a joint effort between the Rocky fountain Region Production and the Exploration and Production Technology Organizations of Marathon Oil Company. The nine field tests were performed in Wyoming's Big Horn Basin in 1985 and 1986; and all involved fracture conformance problems. P. 699^
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- North America > United States > Wyoming > Bighorn Basin (0.99)
- North America > United States > Montana > Bighorn Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 152 > Marathon Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > 153 > Marathon Field (0.99)
Summary Oil displacement experiments are reported which were performed in stratified rectilinear systems consisting of two lower permeability sandstone slabs, enclosing a central high permeability layer made of unconsolidated glass ballotini. The adjacent layers were in good flow communication, except for a very small region close to the outlet. This arrangement allows the crossflow mechanisms that occur when the viscosity of the displacing brine is increased by adding a water soluble polymer. These mechanisms cannot be assessed by performing experiments in one-dimensional cores or packs. Results of oil displacement experiments are presented for different mobility driving fluids, in which glycerol is used to viscosify the aqueous phase. carbon-I 4 and chlorine are used as radioactive tracers in the experiments. The effluent fluids from each layer were collected and analysed to produce data on the cumulative oil recovery, watercuts, flow rates in each layer, viscosities and concentrations of radioactive tracers. The results of these oil displacement experiments were modelled using computer simulation, and a very good match to the experiments was obtained. This simulation work confirms the flow mechanisms involved when water soluble polymers are used to increase the oil production from stratified reservoirs. Introduction In stratified reservoirs with high permeability contrasts between layers, early water breakthrough can occur during a waterflood, causing low vertical sweep efficiencies. The use of water soluble polymers to increase the water viscosity has been shown to be an effective way of improving the sweep efficiency and hence increasing the oil recovery. Earlier theoretical work has shown that the mechanism of increasing the recovery of oil in this way involves the crossflow of fluids between the various layers, as well as increasing the velocities in the lower permeability layers adjacent to the high viscosity polymer solution). A large number of papers have been published which investigate oil displacement using polymer solution in one-dimensional cores. Some experiments have also been performed in two-dimensional systems, but most of these used multiple radial or linear cores in parallel, with no contact between the cores except at the inlet. In the early literature, waterflooding experiments in communicating layered systems were reported, generally from the viewpoint of investigating scaling laws, or recovery mechanisms. More recently, polymer displacement experiments have been performed in stratified systems, with crossflow between layers. Whilst these have provided valuable information on the displacement processes, they have not provided sufficient data to allow a theoretical analysis of the flow mechanisms. In our laboratory, we are performing experiments which provide detailed information on the oil recovery, watercuts, flow rates and tracer concentrations produced from individual layers. The results of these experiments are being analysed using numerical simulation, in order to reproduce the flow mechanisms quantitatively. Earlier work performed at Winfrith used a heterogeneous core made from a sandstone cylinder with the centre removed and replaced with a pack of glass ballotini. This work has recently been extended using a rectilinear core assembly, and the results of these later studies are discussed in this paper. P. 823^
Abstract The Weeks Island S sand Reservoir B (S RB) gravity-stable CO2 field test is almost complete. Injection started in October 1978 and production began in January 1981 in this high-permeability, steeply dipping sandstone reservoir. Through 1987, about 261,000 barrels of oil or about 64 percent of the starting volume has been recovered. A 24-percent pore-volume slug of CO2 mixed with about six mole percent of natural gas (mostly methane) was injected at the start of the pilot. During 1983, when gas production rates started to increase, CO2 containing produced gas was reinjected. Through 1987, CO2 usage statistics are 7.90 MCF/BO with recycle and 3.26 MCF/BO based on purchased CO2. This report is a review of early pilot history and a more detailed account of the post-June 1981 results. A reservoir-simulation history match of pilot performance plus core and log data from a 1983 swept-zone evaluation well are included. Introduction The Weeks Island field is located in New Iberia Parish, Louisiana. The structural features of the Weeks Island reservoirs are typical of many piercement salt-dome fields in the Gulf Coast. Sand quality and continuity in most reservoirs in the field are exceptionally good. Oil recoveries are typically 60 to 70 percent of original oil in place, and water-displacement sweep efficiencies are very high in these strong water-drive reservoirs. Residual oil volumes remaining in the larger reservoirs represent sizeable enhanced oil recovery (EOR) targets. The reservoirs at Weeks Island are deep and hot, e.g., 13,000 feet and 225F in the pilot. The dip in the S RB is about 26 degrees and permeability is high. Under these reservoir conditions, gravity-stable CO2 flooding is the selected EOR process. The implementation and about half of the operational life of the pilot were a joint effort with the U.S. Department of Energy. Reports by Perry and others document pilot design, implementation and early results for the 1977 to June 1981 time period. RESERVOIR DESCRIPTION The S sand Reservoir B was chosen for the pilot because it has properties similar to the largest EOR candidate reservoir at Weeks Island and because it is relatively small and well confined by faulting. The S RB originally contained about three million STB of oil underlying a 38-BCF gas cap. The oil column was first produced by gas-cap expansion and later by water injection. The one oil production well was completed near the gas-oil contact. Figure 1 is a structure map of the pilot portion of the S RB illustrating the relative position of the pilot wells. The gas cap extends along the face of the dome to the right in this figure. Table 1 shows key reservoir parameters plus production and injection volumes prior to the start of CO2 injection. The original oil-water contact was not logged in this reservoir; therefore, the original oil in place is uncertain. The prepilot oil-column production history ended in July 1978 in preparation of CO2 injection. P. 317^
- North America > United States > Louisiana > Iberia Parish (0.25)
- North America > United States > Oklahoma > Osage County (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
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