Meeting the Challenge to Extend Success at the Pikes Peak Steam Project to Areas with Bottom Water

Abstract

This paper provides a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation (CSS) and steam drive in non-bottom water. To test development over relatively thin bottom water (less than 5 meters), various steam processes were field trialed. Field pilot results from vertical well CSS, dual horizontal well gravity drainage, and a combination of vertical injectors-horizontal well producer are presented for comparison. Based on field experience and numerical simulation input, CSS has been successfully conducted with economic steam-oil ratios (SOR) in areas with up to 4 meters of bottom water by injecting significantly larger steam slugs in what is termed a drive, block and drain process. In thicker bottom water, the ability to operate at constant pressure to prevent bottom water influx confers an advantage to the horizontal well approach. Followup field scale developments of some bottom water areas are described. Numerical simulation results indicate that pressuring up of a depleted steamflooded zone to be an optimum strategy for maximizing offset flank recovery. This is being implemented in the field by re-injecting produced vent gases. Introduction 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 an average depth and thickness of 500 and 15 m respectively. The oil is a heavy 12.4 °API crude with a solution GOR of 14.5 m3/m3 and a dead oil viscosity of 25000 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 utilized with subsequent conversion to pattern steam drive to target development of the Waseca structural highs with no bottom water (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 bottom water 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. Geological Setting 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 bottom water and tends to have thicker basal homogeneous sand with over 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 bottom water. A typical log for this area is shown in Fig. 4. A discussion of the reservoir geology was published by van Hulten1. Development History 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 has been published outlining the Pikes Peak performance and progress.

Enhanced Oil Recovery of Heavy Oil in Reservoirs With Bottom Aquifer

“…Wong and co-workers (Wong, et al 2001) discuss the Pikes Peak cyclic steam (CSS) and steamflood project in Canada operated by Husky Oil where CSS was tested over bottom water with vertical wells. Dead oil viscosity is 25, 000 cp.…”

Can SAGD Be Exported? Potential Challenges

“…The main reason for this belief is that Lloydminster-area reservoirs tend to be relatively thin compared with Athabasca reservoirs, so the oil rate generated by SAGD in the Lloydminster region will tend to be lower and the heat losses higher than in the Athabasca region. Another critical issue in many Lloydminster SAGD pilots is the presence of bottom water 6,7,8 .…”