Horizontal Injectors Rejuvenate Mature Miscible Flood - South Swan Hills Field
- K.A. Edwards (Conoco Canada Resources Ltd.) | B. Anderson (Conoco Canada Resources Ltd.) | B. Reavie (Conoco Canada Resources Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2002
- Document Type
- Journal Paper
- 174 - 182
- 2002. Society of Petroleum Engineers
- 5.5 Reservoir Simulation, 3.3.1 Production Logging, 5.3.2 Multiphase Flow, 5.8.7 Carbonate Reservoir, 3 Production and Well Operations, 5.4.9 Miscible Methods, 6.5.2 Water use, produced water discharge and disposal, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 4.3.4 Scale, 5.6.5 Tracers, 2.2.2 Perforating, 5.4 Enhanced Recovery, 1.14.4 Cement and Bond Evaluation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5.8 History Matching, 1.10 Drilling Equipment, 1.14 Casing and Cementing, 5.4.1 Waterflooding, 3.2.4 Acidising, 5.1 Reservoir Characterisation, 5.7.2 Recovery Factors, 1.6 Drilling Operations
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The South Swan Hills pool, located in northwest Alberta, Canada, is a carbonate reef with an original oil in place (OOIP) of approximately 850 million bbl. Waterflooding began in 1963, and a staged hydrocarbon miscible flood covering most of the field began in 1973. Solvent injection in the main miscible flood was terminated in 1989, and chase gas injection ceased in 1998. In 1994, however, solvent injection was reinitiated into a single pattern in the reef margin area of the field using a horizontal injector and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. The horizontal injector was placed at the base of the reef margin to minimize the effects of gravity override and to maximize sweep efficiency. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. Both patterns are projected to recover almost 1 million bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas that were part of the original miscibleflood project.
This paper covers the development of the original miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The geological and performance factors that made this redevelopment successful, and their impact on field production, are discussed. Finally, plans for future development of this mature field are presented.
Hydrocarbon miscible flooding has long been a preferred means of enhanced oil recovery (EOR) in Alberta. It is similar to CO2 flooding, with the exception that the solvent is composed of a mixture of hydrocarbon components. The current solvent composition, for example, is composed of 28% C1, 57% C2, 7%C3, 3%C4, and 2% C5+, with the remainder in other components. This composition is first-contact miscible at current operating conditions. The solvent is usually displaced with cheaper chase gas, composed primarily of methane.
An abundance of natural gas liquids (NGLs) in the 1960s and 1970s and the opportunity to incorporate a more efficient displacement process prompted the operator of the South Swan Hills Unit (SSHU) to consider a hydrocarbon miscible flood as a means to increase oil recovery.1 An injection pilot of pure NGLs was carried out from 1970 to 1972, and the field-scale project started in 1973. Initial design called for 21 patterns to be put on injection in the central and northern portions of the unit. This area was still in the early stages of waterflooding and was termed a secondary miscible flood. The western part of the unit was put on miscible injection in 1982. This area had a relatively mature waterflood and was thus termed a tertiary miscible flood. Both areas were developed exclusively with vertical wells. Early performance of the secondary miscible flood, and an evaluation of its performance, were documented by Griffith and Cyca.2
A common problem with miscible flooding is the gravity override of the solvent owing to the density at reservoir conditions, which is much lighter than that of the in-situ oil and water. This was identified as a concern during the design of the original miscible flood, and it was observed in the field. One area particularly prone to override was the reef margin, with its thick, continuous, stacked pay.
Horizontal wells have long been considered for application in miscible floods because of problems such as gravity override, and they have been the subject of many studies.3-8 In the case of the South Cowden field in Texas, the goal was to centralize facilities and lower capital costs by accessing larger amounts of reservoir using fewer wells drilled from central locations.6 In the case of the Ratherford Unit in Utah, the goal was to increase the processing rate and sweep efficiency in a low-permeability reservoir.7 These and other benefits (such as improved displacement efficiency, the largest improvement in areal sweep efficiency at the most adverse mobility ratios, and the minimum miscibility pressure maintained over a larger portion of the reservoir) were noted by Chen and Olynyk3 and by Taber and Seright.4
Actual case histories of horizontal injectors in miscible flood applications are relatively rare, however. Two horizontal CO2 injection wells were drilled at South Cowden in 1996,9 but no performance has been published. Horizontal injectors are being used in the Prudhoe Bay field in what is termed a lateral MIST application. 10 There, bulbs of miscible injectant are placed at regular intervals along a horizontal injector. The solvent bulbs mobilize residual oil toward vertical producers. Horizontal injectors are being used in the Weyburn CO2 flood in Saskatchewan, Canada, but no performance has been published to date. Finally, Chugh et al. describe a model study and subsequent field implementation of a horizontal miscible injection project in the Virginia Hills field (a sister reservoir to South Swan Hills) in 1997.11 The concept of horizontal injectors applied to SSHU is the same as that in the Virginia Hills field and is similar to the process used in Prudhoe Bay. It is illustrated in Fig. 1. The horizontal well is placed low in the pay section to sweep reservoir that was missed because of gravity override during injection into vertical wells.
To date, four patterns using horizontal injectors have been implemented at SSHU. The first pattern went on injection in 1994 and has since finished chase gas injection. The second pattern went on injection in 1997; it has since completed solvent injection and is currently on chase waterflood. The final two patterns began injection during 2000. The geology that makes these patterns possible, their response, and an analysis of performance are discussed in detail next.
The South Swan Hills pool is located in northwest Alberta, as shown in Fig. 2. It covers an area of almost 37,000 acres, of which more than 35,000 acres have been unitized into SSHU. The pool is a carbonate reef with an OOIP of ??850 million bbl. To date, almost 300 wells have been drilled into the unit, mainly on 160-acre spacing. Fig. 3 shows the unit outline, well locations, and horizontal miscible-pattern locations.
The South Swan Hills pool is one of a number of large atoll reef buildups that are part of an extensive reef complex developed in Upper Devonian time. It produces light oil from original limestone porosity of the Devonian Swan Hills formation. The reef has features typical of these complex heterogeneous reservoirs, including a platform, a reef interior characterized by tidal flats and lagoonal mud areas with varying degrees of restriction, and a reef margin.
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