Performance of a Miscible Flood in the Bear Lake Cardium Unit, Pembina Field, Alberta, Canada

Abstract

Field data and interpretation of project performance are given on a rich gas-drive miscible flood project that has been in progress for more than 5 years. Production has been good, but early solvent breakthrough occurred at two wells. In developing explanations for the breakthrough, computer models were used to analyze field data and the displacement mechanism. Introduction In Feb. 1968, a secondary recovery project was begun in the Pembina Bear Lake Cardium Unit 1 in Alberta, Canada. The major part of the secondary scheme was a rich gas-drive miscible flood conducted in the central region of the unit. The miscible process was used because of its potential for recovering oil unrecoverable by conventional waterflooding. This potential results from displacement efficiencies approaching 100 percent in the region of the reservoir swept by the solvent. Presented here is a general description of the reservoir, followed by a discussion of the miscible project scheme. The performance of the project is reported and analyzed. Information derived from reservoir simulation studies is also presented. The paper is a summary of several engineering studies and progress reports that are on file as public documents with the Energy Resources Conservation public documents with the Energy Resources Conservation Board of Alberta. These documents contain detailed reservoir data not reported in this paper. General Description of the Reservoir Reservoir Location and Layout The Pembina Bear Lake Cardium Unit 1 is located in the northwest portion of the Pembina field in Alberta, Canada, as shown in Fig. 1. The unit boundary and well locations are indicated in Fig. 2. Originally, the wells were developed on 160-acre spacing, but in the last 2 years some infill wells have been added. Currently, there are 29 wells in the unit; three are used as injectors, 25 are producers, and one well has been shut in. producers, and one well has been shut in. Formation Description The Cardium oil reservoir occurs at an average depth of 4,857 ft (-2,054 ft subsea). The oil accumulation is found in a sand bar development about 1 1/2 miles wide and 6 miles long. The Cretaceous sand was deposited under a deltaic condition and then was deeply eroded over most of the unit area. A highly permeable conglomerate-type chert was deposited over the eroded area. Fig. 3 is a cross-section of the reservoir showing the geometry of the sand and conglomerate layers. Maximum thickness of the conglomerate along the major axis of the bar is 41 ft. The underlying sand varies in thickness from 0 to 35 ft. The conglomerate layer is thickest in the northwest, and thins down and disappears in the southeast. It is important to note the vertical scale exaggeration on Fig. 3. The reservoir is actually extremely thin compared with its areal extent. Fig. 4 shows the depth to the top of the pay zone. The crest of the structure follows close to the major axis and dips downward from southeast to northwest. The amount of relief is small compared with the areal extent. Typical or average characteristics for the formation are included in Table 1. In the conglomerate layer, the average horizontal permeability is about 700 md. Permeability in the sand averages only about 20 md. The Permeability in the sand averages only about 20 md. The porosity is about 11 percent in both the conglomerate and porosity is about 11 percent in both the conglomerate and the sand. Permeability data taken from tests on core samples indicate that horizontal permeability of the conglomerate is generally 10 to 20 times greater than the vertical permeability. Geological analysis of core samples indicates that this difference results from the presence of essentially horizontal lithologic zones (beds) of relatively low permeability. In most cases, these zones consist of permeability. In most cases, these zones consist of conglomerate containing abundant sandstone matrix. JPT P. 672