Chemical tracers have been utilized to effectively monitor injected fluid movement in two vertical hydrocarbon miscible floods in the Rainbow Field, Alberta. By placing small slugs of chemical tracers, consisting of sulphur hexafluoride (SF6) and chlorinated fluorocarbons (CFC) or halocarbons within the injectants, the spreading and development of chase gas and solvent banks were monitored, and in some cases, reservoir flow channels identified. In addition, geological units were confirmed and well workover planning improved, resulting in increased cost effectiveness in operating the miscible floods. The chemical tracer program commenced with the first field application conducted in the Rainbow Keg River "A" (R.K.R.A.) Pool secondary miscible flood on January 31, 1991, where chase gas injection into two wells was traced. Subsequently a program of tracing chase gas and solvent was initiated at one well location in November, 1991 in the Rainbow 1 Keg River "B" (R.K.R.B.) Pool tertiary miscible flood, and later at six additional chase gas and solvent co-injection wells. This paper presents the design of the tracer programs, the significance to the operation of the miscible oil recovery schemes and alternative tracers considered for the future. Introduction Husky Oil operates seven mature secondary and three tertiary miscible flood enhanced oil recovery projects in the Rainbow Field of northwest Alberta (Figure 1). Cost effective operation of these floods requires that solvent and chase gas sweep a significant extent of the reservoir without being produced at high rates. If miscible solvent bypasses large portions of the reservoir due to channeling, recovery efficiency will be lower than expected. Maintaining cost effective operation of hydrocarbon miscible flooding has required the development of extensive tracer programs designed to track and optimize solvent distribution in the reservoir as well as detect breakthrough at the very early stages. Previously, Husky had used radioactive tracers to monitor solvent bank placement in the R.K.R.B. Pool(1). Following the successful conclusion of this program and others in Rainbow Lake, other tracers were researched with the expectation that more of the analysis could be conducted on site and with reduced cost. More recently, Husky has used several Freon" haIocarbons and SF6 as chemical tracers to monitor chase gas and solvent injection in both the R.K.R.A and B Pools. FIGURE 1: Field location map. Illustrations available in full paper. Tracing injected chase gas and miscible solvent is used to identify the distribution of these fluids, both regionally and vertically, in the miscible floods. This enabled identification of the source of early solvent and chase gas breakthrough due to reservoir channeling, and allowed for early remedial action. Tracers less expensive than radioactive tracers, both from an initial cost and a per sample analysis cost basis were sought. They had to be detectable and accurately measurable at extremely low concentrations in the field lab and be readily handled by the field operations group. Finally, they could not be native to the oil reservoirs or have adverse rock or fluid adsorption or partitioning characteristics.
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.
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.
Since 1989, Husky Oil has drilled 12 horizontal wells in six mature hydrocarbon vertical miscible flood pools. To date, these horizontal wells have been very successful in reducing gas coning and improving oil productivity(1) as originally intended. Furthermore, actual field performance indicates that, in some cases, horizontal wells have considerably improved productivities of adjacent vertical wells. The drilling of a horizontal well in the Rainbow Keg River E Pool resulted in a 10 –15% increase in oil production and a cessation in the rising gas-oil ratio in the offset vertical wells. Such unexpected benefits are attributed to improved drainage to the vertical wells induced by the drilling of the horizontal well, along with the healing and/or reduction of the gas cone at the vertical wellbores. These hypothesized causes for the unexpected benefits were qualitatively confirmed with a 3-D numerical simulation model. It is concluded that drilling of horizontal wells can improve the productivities of offset vertical wells. The fear of drawing gas over to a horizontal well that is drilled close to gas coning vertical well(s) may be unfounded under most situations. After drilling a horizontal well into a target area, the lateral section can be extended to cover areas near offset vertical well(s) to improve drainage and reduce some of the gas coning tendencies around the offset vertical wellbore(s). Introduction Since 1989, Husky Oil has drilled 12 horizontal wells in six mature hydrocarbon vertical miscible flood pools (Figure 1). The original intent of the horizontal drilling technology in these reservoirs is two-fold:to minimize coning and channeling of gas and water,to attain larger drainage area, resulting in incremental oil sandwich recovery and improved oil productivity(1–3). To date, all of these horizontal wells have been extremely successful in reducing gas coning and in improving oil productivity(1). On average, initial capital investment is paid out within one year. The length of the lateral sections has increased from 178 m in the first well to as long as 720 m with each subsequent well drilled into a progressively riskier target(1). More importantly, actual field performance now indicates that, in some cases, horizontal wells can also considerably improve the productivities of adjacent vertical wells. This paper presents one case history (Rainbow Keg River E Pool) showing the additional benefits of horizontal wells, the results of a conceptual numerical simulation model that was used to rationalize and substantiate the reasons for such unexpected benefits, and finally a discussion on a new application of horizontal well technology in further enhancing oil recovery in mature, vertical miscible floods. Field Performance Observations Rainbow Keg River E Pool Pool Description The Rainbow Keg River E Pool (Figure 1) is one of the carbonate reefs of Middle Devonian age discovered in the mid-sixties in northwestern Alberta. Using both material balance and volumetric calculations, the original oil-in-place (OOIP) was determined to be 4.2 × 106 m3.
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