The South Swan Hills Unit, located in north-western Alberta, is a carbonate reef with an original-oil-in-place (OOIP) of approximately 850 MM bbl. Waterflooding was begun in the field during the 1960s, and a staged hydrocarbon miscible flood was begun during the 1970s. Chase gas injection was terminated in the mid-1990s. In 1994, however, miscible flooding was reinitiated in the reef margin area of the field using horizontal injectors and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. They have both recovered between 800 M bbl and 900 M bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas which were part of the original miscible flood.

This paper will detail the past history of the pool under miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The factors that have made this redevelopment successful, and their impact on field production, will also be discussed. Finally, plans for future development of this mature field will also be discussed.


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 (usually C1 to C5). 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 portion of the unit. This area was still in 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 using vertical wells. Early performance, and an evaluation of the performance of the tertiary miscible flood were documented by Griffith and Cyca.2

A common problem with miscible flooding is gravity override of the solvent due to its much lighter density at reservoir conditions than the in-situ oil and water. This was identified as a concern during the design of the original miscible flood, and was observed in the field. One area particularly prone to override was the reef margin, with its thick, continuous, stacked pay.

One means of increasing recovery in miscible flood projects is to use horizontal injectors. Taber and Sereight noted several benefits that might be realized through the use of horizontal injectors including improved sweep, improved displacement efficiency, faster reservoir processing, and the minimum miscibility pressure maintained over a larger portion of the reservoir.3

The concept of horizontal injectors applied to SSHU (and some of the other geologically similar reservoirs in the area) is illustrated in Figure 1. The horizontal well is placed low in the pay section to sweep reservoir that was missed due to gravity override during injection into vertical wells. Chugh et al describe a model study and consequent field implementation of such a miscible injector in the Virginia Hills field (a sister reservoir to SSHU) in 1997.4

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