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Many of TIORCO’s technologies were initially developed in the oil basins of Wyoming. The geologic diversity of the region along with low original oil recovery rates contributed to an early interest in IOR technologies among the operators.
Wind River Basin | Powder River Basin | Big Horn Basin
Polymer Gels in the Wind River Basin of Wyoming
The Maverick Springs and Circle Ridge oil fields in the Wind River Basin of Wyoming are both anticlines and shallow fields that produce at an average depth of 1,000 feet with extremely prolific natural water-drives. The oil produced from the fields is sour and has an average gravity of 24 degrees API. Total dissolved solids in the produced water is approximately 1000 mg/l and the bottom hole temperature is 80 degrees Fahrenheit.
The two major formations in both fields are the Embar and Tensleep. The Embar Reservoir is a Permian age dolomite. The Tensleep, which typically occurs 200 feet below the Embar, is Pennsylvanian age eolian sandstone with thin beds of densely sandy dolomite occurring periodically. Both formations are highly fractured, evident from core reports and the extremely high productivity of many of the wells.
Maverick Springs was discovered in 1918 but had become a marginal field. Over the years, a number of zones were abandoned due to high water production. From November 1993 to December 1994, 12 workovers using polymer gel were performed in Maverick Springs, resulting in a substantial reduction in water production as well as increasing oil production.
While most of the workovers included additional well work, such as recompletions, reactivations and pumping equipment upsizes, two wells received only gel treatments and production increases can be related directly to the treatments. Estimated reserves developed as a result of these treatments were 19,000 and 20,000 barrels of oil. At the first well, oil production increased by 67 BOPD while water production dropped by 672 BWPD, resulting in a drop in WOR from an average of 75 to 17. At the second well, oil production increased 43 BOPD and water production decreased 848 BWPD; a reduction in producing WOR from 247 to 38.
In early 1995, three Maverick Springs wells were selected for additional treatments, but results were not very encouraging.
The overthrust portion of Circle Ridge was waterflooded in the late 1980s, but the waterflood was shut-in after about five years due to a total absence of response. Gel designs resulting from successful application at Maverick Springs were begun in April of 1995 along with workover of the wells. Water oil ratios were consistently reduced and incremental oil achieved.
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Comparing Two Chemical Enhanced Waterflood Methods in the Powder River Basin
The Triangle “U” Unit is located in Campbell County, Wyoming, in the Powder River Basin. The field produces mainly from Sussex A sandstone, with completions and limited production from the Sussex B. The field produced 12.8% OOIP on primary before initiation of a waterflood.
Waterflooding was expected to recover an additional 13.8% OOIP, but there were two basic challenges. First was the concern that the clays would limit injectivity over time. Sussex A is relatively tight, with an average permeability of 15 and porosity of 13.5%. The rock contains swelling and migrating clays and the initial injection water source was fresh, adding to concerns about long-term injectivity. The rock also exhibited a permeability variation of 0.65, which could lead to bypassing of recoverable oil as water tended to establish channels through more permeable rock.
The long narrow shape of the reservoir also made development of an efficient waterflood pattern challenging.
Two different chemical processes were used to treat the injection wells to stabilize clays near the wellbore, allowing the highest possible injectivity. The first four injection wells were treated with a KCI solution followed by cationic polymer. The purpose of the KCI was to stabilize clays near the wellbore and the cationic polymer was to coat the clays, preventing contact with fresh water when injection began.
As technology to permanently stabilize clays became available, the rest of the injection wells added over the next 15 years were treated with a new process using KOH to permanently stabilize the clays near the wellbore. This process involved injecting a presoak of KCI to flush divalent cations out of the near-wellbore region, followed by exposure to KOH. This one-time KOH process only affects rock near the wellbore. To encourage injection water to contact as much formation rock as possible out beyond the near-wellbore, an imbibition process was implemented following clay stabilization treatments. This process involved a wettability agent combined with a small quantity of polyacrylamide, injected continuously at a low concentration.
Contrasting the two technologies over time, the KOH treated wells have generally shown better, more consistent injectivity. Cumulative oil recovery exceeded 36% of OOIP at a WOR of 0.71, compared to the original projection of 26.6% OOIP. Injection wells treated with KOH averaged 83% more water injection than the control wells and additional water was injected 1.4 years faster in the wells treated with KOH.
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Crosslinked Polymer Conformance Treatments in the Big Horn Basin Area, Wyoming
Gel conformance treatments performed on producing wells in the Big Horn Basin in the Madison formation have yielded promising results by reducing water rates an average of more than 2000 BWPD, increasing oil rates by 50 BOPD, reducing WOR to less than one-third of pre-gel treatment ratios and lower producing fluid levels by over 1,100 feet.
The Madison is a Mississippian age carbonate formation with 28 oil/water productive subzones over approximately 1,000 feet of gross interval with diversely charactered zones including vugular and naturally fractured dolomites. Bottomhole temperatures range from 130 to 150 degrees Fahrenheit and the area has an extremely prolific natural water drive. The formation has a history of success with cement water shut-off treatments, however, these treatments were expensive due to the numerous attempts often required to get fluid reduction.
Initially it was believed that gel conformance treatments were not a viable solution, however, due to the large upside potential, they were attempted. The initial Madison production well gel conformance treatments were high concentration, two-stage treatments. They consisted of pumping equal volumes of the total treatment volume at 5,000 ppm and 7,500 ppm and at 10,000 ppm crosslinked gels followed by water overdisplacement. After a two day shut-in, the same treatment design was repeated with an uncrosslinked polymer and lease oil flush.
Results were complicated by other simulations performed at or near the same time, however, in retrospect the two-stage treatments may have caused near total shut-off. Incremental reserve development was minimal although the economic limits of the wells were reduced substantially.
The second gel treatment design consisted of equal volumes of the total treatment volume at 5,000, 7,500 and 10,000 ppm crosslinked polymer solution. Madison “D” zones responded well to the treatment, however, Madison “B” zone treatments were not successful.
The third and final MARCITSM design was a low-concentration, single-stage design that consisted of pumping approximately 80% of the total treatment volume at 5,000 ppm, 10% at 6,000 ppm and 10% at 8,000 ppm crosslinked gels followed by an uncrosslinked polymer and water flush. This optimized treatment design has been pumped on wells in the Madison “B”, “D” and “F” zones with excellent incremental oil and water reduction results.
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