Performance Monitoring And Reservoir Management Of A Tertiary Miscible Flood In The Fenn - Big Valley South Lobe D-2A Pool

Abstract

Abstract In February 1983, a hydrocarbon miscible flood (HCMF) was Implemented in the South Lobe D-2A Pool, Fenn – Big Valley field in central Alberta. The pool had effectively watered out under the primary drive mechanism and its performance indicated a primary recovery of 48.8% of OOIP. Initial estimates suggested an incremental recovery factor of 15% by the tertiary flood. This paper presents the performance evaluation of the HCMF and shows how the derived information helped in a better management of the reservoir. Several techniques including analyses of radioactive tracers, and various logs aided in performance evaluation. Nine tracers were injected early in the life of the project to trace the movement of both injected solvent and water. To match the tracer response a computer model based on the work of Yuen et. al.(1) was utilized. The results provided useful clues about interwell reservoir characteristics, relative fluid velocity and reservoir sweep efficiency. In addition, important information about gravity override was provided by various production logs. The results of this evaluation indicated problems with early solvent breakthrough, and poor sweep efficiencies. Based on the results of different studies, the miscible displacement front is now being more closely managed by production adjustments to improve the areal sweep efficiency. Recompletions of injectors and producers improved vertical sweep efficiency and delayed solvent breakthrough. Introduction The Fenn – Big Valley South Lobe Nisku D-2A Pool is located approximately 160 km northeast of Calgary, as shown in Figure 1. The pool boundary and well locations are depicted in Figure 2. Development was carried out on a 16.0 hectare (ha) spacing with the drilling of 60 wells, 36 of which remained capable of production. Geological Description A detailed geological study of the pool was carried out in 1979. The study revealed that the pool consists of stratified porous dolomite ranging in thickness from about 19 m to 34 m. The reservoir is fairly heterogeneous in nature with significant variations in both porosity and permeability. Vertical continuity is blocked in some places by the presence of the Medial Dense or Duhamel Shale zones, which effectively separate the reservoir into two or three units. Within each unit, horizontal continuity is maintained by intergranular, moldic, and fracture porosity (short randomly oriented breccia fractures). All units are above the original oil-water interface over the structurally high culmination of the pool. The pool was formed by closure created by a growth-type structural high, and by buildup of porous strata over the paleotopographic high produced by this structure during an early stage of development. The underlying Leduc reef contributed to the relief of the paleotopographic high. Carbonate sand banks accumulated on the high, accompanied by a fauna rich in snails and corals. Through dolomitization and solution, both fine pores (intergranular and intercrystalline) and larger pores (moldic vugs) developed. Continued structural uplift and warping produced open breccia fractures and may have been responsible for the accumulation of oil. A typical structural-stratigraphic cross section illustrating the lithostratigraphic units, reservoir units and original oil-water interface is shown in Figure 3. The structural configuration is attributed to uplift, as well as to differential compaction.