Meeting the Challenge To Extend Success at the Pikes Peak Steam Project to Areas With Bottomwater
- Frank Y. Wong (Husky Energy Inc.) | Don B. Anderson (Husky Energy Inc.) | J. Cameron O'Rourke (Husky Energy Inc.) | Harley Q. Rea (Husky Energy Inc.) | Keith A. Scheidt (Husky Energy Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2003
- Document Type
- Journal Paper
- 157 - 167
- 2003. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 5.3.9 Steam Assisted Gravity Drainage, 1.6 Drilling Operations, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.2.2 Perforating, 5.4.2 Gas Injection Methods, 4.1.5 Processing Equipment, 1.14 Casing and Cementing, 5.5.8 History Matching, 5.1.1 Exploration, Development, Structural Geology, 5.4.6 Thermal Methods, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.2 Reservoir Fluid Dynamics, 1.6.6 Directional Drilling, 4.6 Natural Gas, 3.1.1 Beam and related pumping techniques, 2.4.3 Sand/Solids Control
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This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steamdrive in non-bottomwater. To test development over relatively thin bottomwater (less than 5 m), various steam processes were given field trials. Field pilot results from vertical-well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors/horizontal well producers are presented for comparison.
Based on field experience and numerical simulation input, CSS has been conducted successfully with economic steam/oil ratios (SORs) in areas with up to 4 m of bottomwater by injecting significantly larger steam slugs in what is termed a drive, block, and drain process. In thicker bottomwater, the ability to operate at constant pressure to prevent bottomwater influx confers an advantage on the horizontal well approach. Follow-up field-scale developments of some bottomwater areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone is an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by reinjecting produced vent gases.
A very successful steam project is being operated at Pikes Peak, located in the Lloydminster heavy-oil block straddling the provinces of Alberta and Saskatchewan (Fig. 1). The producing formation is a Waseca channel sand at average depth and thickness of 500 and 15 m, respectively. The oil is a heavy 12.4°API crude with a solution gas/oil ratio (GOR) of 14.5 m3/m3 and a dead-oil viscosity of 25 000 mPa·s. A summary of reservoir rock and fluid properties is listed in Table 1.
From the initial steam pilot in 1981, CSS has been used with subsequent conversion to pattern steamdrive to target development of the Waseca structural highs with no bottomwater (Fig. 2). The result has been highly successful, with current oil recoveries reaching 70% in the more mature steamflooded areas.
A remaining challenge for the project is the development of thinner oil pay underlain by bottomwater in the structural lows flanking the steamflooded pattern areas. The flanks are also at a higher pressure than the adjoining heated areas, which are pressure depleted at a mature stage of steamflooding.
The Pikes Peak steam project produces heavy oil from the Waseca formation of the Lower Cretaceous Mannville group. The project is located on an east/west structural high within an incised valley fill channel complex that trends north/south (Fig. 3). It consists of a generally fining upward sequence with clean homogeneous unconsolidated quartzose sand at the base and sand/shale interbeds on top. Locally, there are calcite-cemented tight streaks in the interval. Oil saturation in the best part of the reservoir exceeds 90%. Porosity is usually in the mid- to high thirties, and permeability is in the 5 µm2 range.
The structurally high central portion has the best reservoir. It has no bottomwater and tends to have thicker basal homogeneous sand with more than 20 m of pay. Development has now gone beyond the central portion and into the edge area. The reservoir in this area usually has thinner homogeneous sand and a thicker interbedded zone with some bottomwater. A typical log for this area is shown in Fig. 4. A discussion of the reservoir geology was published by van Hulten.1
The Pikes Peak steam project is located in the western Canadian Heavy Oil Basin approximately 42 km east of the city of Lloydminster (Fig. 1). Since the field's discovery in 1970 and the initiation of steam injection in 1981, a number of papers2-5 outlining the Pikes Peak performance and progress have been published.
The field was first developed on 16.2-ha spacing for primary production from the General Petroleum formation using reciprocating rod pumps. Attempts were made to produce the Waseca channel; however, the results were unsuccessful because of high operating costs associated with the large volumes of sand produced.
In 1981, the Pikes Peak steam pilot was implemented. Following encouraging results from CSS tests completed on the existing thermally completed wells, additional wells suitable for CSS were drilled on 1-ha spacing.
Steam was injected into the wellbore to heat the reservoir. The heated fluids are produced to surface with a reciprocating rod pump until the oil-production rate drops below an economic optimum. At that time, another steam-injection cycle is initiated. After 2 to 4 injection and production cycles, interwell communication was observed.3 Steam injection at one well would affect production at an offsetting location. Over time, the process was optimized, and the project was expanded continuously with directionally drilled vertical wells.6
In 1984, a steamflood process was initiated as a follow-up process to CSS in an area in which interwell communication existed between several wells.4 The excellent results led to the establishment of 3-ha inverted 7-spot patterns throughout the project (see Fig. 2).
By mid-2001, the Pikes Peak steam project had grown to 219 active, 10 observation, and 8 saltwater disposal wells. The current project covers 352 ha and has exploited the best part of the Waseca channel (greater than 10 m of continuous oil pay and no bottomwater). The success of the Pikes Peak steam project is depicted in Fig. 5. Through the end of July 2001, a cumulative total of 17.85 × 106 m3 cold water equivalent (CWE) of steam has been injected into the project, resulting in a total oil recovery of 6.56 × 106 m3. The good thermal efficacy of this project is reflected in the cumulative SOR of 2.72 m3/m3 and current oil recoveries of up to 70% in the more mature steamflooded areas.
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