Enhancement of In-Situ Combustion by Steam Stimulation of Production Wells
- C.M.F. Galas (BP Resources Canada Ltd.) | G.C. Ejlogu (BP Resources Canada Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1993
- Document Type
- Journal Paper
- 270 - 274
- 1993. Society of Petroleum Engineers
- 6.5.2 Water use, produced water discharge and disposal, 1.14 Casing and Cementing, 1.6 Drilling Operations, 5.3.2 Multiphase Flow, 5.4 Enhanced Recovery, 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 1.2.3 Rock properties, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.10 Drilling Equipment, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.4.6 Thermal Methods
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Steam stimulation of individual wells was used to improve the performance of an in-situ combustion project operated by BP Resources Canada Ltd. in the Cold Lake oil-sand deposits of northeastern Alberta. In addition, steam was used to protect production wells that were threatened by the combustion front or had experienced oxygen breakthrough. The effectiveness of these steam uses varied. This paper describes the strategy developed for the use of steam injection and case histories and draws conclusions on how to use steam injection for maximum effect.
BP Canada's Oxygen Wolf Lake (OWL) project in the Cold Lake region of east central Alberta (Fig. 1) uses the patented pressureup/blowdown combustion process where the reservoir is pressured up by oxygen in cycles.1,2 After each injection phase, the production wells are operated without restriction.
The project is unique because cyclic steam stimulation is used as a precursor to in-situ combustion. As a consequence, steam injection facilities were in place during the combustion phase and individual production wells could have steam injected into them at any time.
A major difficulty in thermal flooding processes is that the production wells do not receive the benefit of the heat entering the reservoir at the injection wells immediately, especially in reservoirs where the oil is immobile when cold. However, the process may be enhanced by selective thermal stimulation of the production wells as an adjunct to the flooding process. The flooding process itself has no chance of success if effective communication does not exist between the injectors and the producers. Stimulation of the producers also may enhance this communication. Steam injection also can be used to protect production wells and to divert the flood front in a desired direction. This paper discusses these benefits and provides field case histories that illustrate some of these effects.
The bitumen-bearing reservoirs in the Cold Lake region are in the early Cretaceous Age Mannville group. The target reservoir in Project OWL is the 450-m-deep Clearwater formation. Its gross thickness at the pilot site is 35 m, and its net thickness is 23 m. The original reservoir pressure was 2700 kPa, and the temperature was 16°C.
The Clearwater formation is interpreted as a marine deltaic sequence. The formation is divided into three stacked sands, C1, C2, and C3. Each sand consists of a thin basal shale and interlaminated silt grading upward through interbedded and partially bioturbated sands, silts, and shales coarsening upward into thick, relatively massive sands. The sands are classified as poorly sorted, very-fine-grained unconsolidated sandstone. Visser3 gives a detailed description of the geology.
Fig. 2 shows the formation log response and illustrates the division. Sand C3 is the thickest and most laterally consistent of the three zones; indications from the observation wells are that combustion is largely confined to this sand. The porosity is 33%, and the average water saturation is 35 %. The horizontal permeability is high, 1 to 3 µm2, but the vertical permeability is low because of the presence of frequent clay laminae and up to three calcite-cemented streaks.
The bitumen has a density of 986 kg/m3 and a viscosity of ˜1.0×105 mPa·s at the reservoir temperature and 100 mPa·s at 100°C.
From the start of the project in 1978, the aim of the pilot was to test and to develop a combination process of cyclic steam followed by wet in-situ combustion. Evaluations indicated that such a combination would result in higher economic recoveries of the bitumen than cyclic steam alone.
The original project partnership included BP Resources Canada Ltd., Alberta Oil Sands Technology & Research Authority (AOSTRA), Hudson's Bay Oil & Gas Ltd., and PanCanadian Petroleum Ltd. The third combustion cycle was conducted by BP Canada and PetroCanada Inc.
The original pilot consisted of a main pattern of four five-spot patterns, with 2-ha/well spacing. These wells were Wells EX 1 through EX 13. In addition, several special test wells, Wells T2 through T4, on a smaller spacing were used to obtain early operating experience with in-situ combustion.
The cyclic steam stimulation test showed that the steam had to be injected at above fracture pressure to obtain adequate injectivity and that the fractures were preferentially oriented in the northeast-southwest direction. These fractures led to interwell communication through heated channels. To cope with this communication, the pressure-up/blowdown process was developed in the test area.1,2 In addition, an engineering study indicated that injection of oxygen instead of air would be technically and economically beneficial.
When the main pattern was put on in-situ combustion, infill drilling had been done and there were 23 wells with ˜1-ha/well spacing. The operating plan called for use of oxygen instead of air and the pressure-up/blowdown process. Fig. 3 shows the heated channels that are believed to exist between the wells after the cyclic steam operations and that determined the principal communication paths.
Hallam and Donnelly2 described the pressure-up/blowdown process in detail. Briefly, the process consists of injecting air, oxygen, and water, usually in several slugs, until either the target oxygen volume is injected or the target pressure is reached. Then, the injection is stopped (a trickle of water is continued into the injection wells for safety purposes), and the production wells are operated to depressurize the reservoir. When the reservoir has been depleted, the next injection cycle is started. Although the principles behind the process are simple, many process variables and detailed strategies needed to be optimized.
Various injection wells were used at different times; changes most often are dictated by the mechanical state of the wells. In the second cycle, the injectors were Wells EX 4, EX 5, EX 7, EX 9, and EX 10; in the third cycle, the injectors were Wells EX 4, EX 7 and EX 10. Fig. 4 shows the well configuration and dominant communication channels at the start of the third combustion cycle.
Galas et al.4 presented fluid and heat movement details of the pilot performance, Nzekwu et al.5 discussed temperature response, and McGee et al.6 described pressure response. Mehra7 developed a theoretical model of the process.
Steam Injection Strategy
In the first two combustion cycles in the pilot main pattern, steam was used to protect wells and at other times as necessary. In the third combustion cycle, a clearer strategy for steam use, based on experience gained in the first two cycles, was developed. Steam injection into the production wells would be used in three ways.
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