Tertiary Application of a Hydrocarbon Miscible Flood: Rainbow Keg River "B" Pool
- Raymond G. Nagel (Canterra Energy Ltd.) | Brian E. Hunter (Canterra Energy Ltd.) | Jonathan K. Peggs (Canterra Energy Ltd.) | David K. Fong (Canterra Energy Ltd.) | Enrico Mazzocchi (Canterra Energy Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1990
- Document Type
- Journal Paper
- 301 - 308
- 1990. Society of Petroleum Engineers
- 1.14 Casing and Cementing, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics, 2.2.2 Perforating, 1.8 Formation Damage, 4.1.2 Separation and Treating, 4.1.9 Tanks and storage systems, 5.6.1 Open hole/cased hole log analysis, 5.5.8 History Matching, 5.5 Reservoir Simulation, 4.6 Natural Gas, 4.2 Pipelines, Flowlines and Risers, 5.3.2 Multiphase Flow, 1.6.9 Coring, Fishing, 5.4.9 Miscible Methods, 5.7.5 Economic Evaluations, 2 Well Completion, 5.7.2 Recovery Factors, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements, 1.6 Drilling Operations, 3 Production and Well Operations, 4.3.3 Aspaltenes, 5.6.5 Tracers, 6.5.2 Water use, produced water discharge and disposal
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The Rainbow Keg River "B" pool EOR scheme calls for placement of a 12% (net after recycle) -original-HCPV miscible bank in the crestal region of the pool. This bank will be chased vertically downward with more than 1 PV of dry gas. The injected solvent and chase gas will push the oil/water contact (OWC) downward as the previously injected water is produced. A tertiary oil bank will be formed in the region previously occupied by the water. This paper reports tertiary flood performance, results of the 1987 reservoir simulation study, and the operational strategy and problems encountered in monitoring the flood. The well-completion technique implemented to operate the flood is described, and the scheme economics is reviewed. Performance of the tertiary flood to date is encouraging.
The pool contained 270 x 106 STB [43 X 106 stock-tank M3] original oil in place (OOIP) and was greatly undersaturated at discovery. Its original pressure was 2,490 psia [17.2 MPa], or 930 psia. [6.4 MPa] above the oil's bubblepoint pressure. Primary oil production by fluid expansion began in Nov. 1965 (Fig. 1) and continued, without any significant aquifer influence, for some 2 1/2 years. During this depletion phase, the reservoir pressure decreased to 1,970 psia [13.6 MPa] (still well above the bubblepoint), and cumulative oil production amounted to 4,260 x 103 STB [677.3 x 103 stock-tank m3] or 1.6% OOIP. In March 1968, a pressure-maintenance scheme was instituted with water injection into the "B" pool aquifer displacing the oil vertically upward. As a result of water breakthrough, a decline in oil production was recorded from mid-1977 through 1978. This decline was significantly reduced by infill drilling. Fig. 1 presents the waterflood production performance, 1 and Fig. 2 shows the pressure history. A waterflood simulation study showed that the ultimate recovery factor would be 46.4% OOIP. A first-contact hydrocarbon miscible scheme was implemented in the North Lobe of "B" pool in March 1982 to maximize the oil recovery above the OWC. At that stage, the OWC had risen above the saddle, resulting in physical separation of the oil zones of the North and South Lobes (Fig. 3). The miscible process began with solvent injection, in this case straight natural gas liquid (NGL), while the South Lobe continued to produce under waterflood. Comprehensive technical and economic studies demonstrated the feasibility of implementing a vertical tertiary hydrocarbon miscible scheme in the North and South Lobes of the "B" pool, where the major EOR target was represented by the 120 X 106 STB [19 X 106 stock-tank m3] of residual oil left unswept in the waterflooded zone. On June 22, 1984, solvent injection began in the South Lobe to start the tertiary scheme.
The "B" pool is one of the largest reefs discovered in the prolific northeast/southwest-trending evaporite Rainbow basin. The reef mass is about 3.5 miles [5.6 km] long and 1.3 miles [2.1 km] wide at its widest point. The productive horizon is the reefal Rainbow member of the Middle Devonian Keg River (Pine Point) formation of the Elk Point group. The pool isopach, reef top to original OWC, in Fig. 4 illustrates the reef's geometry as inferred from 3D seismic data and well information. Pool bulk volume for the oil column is about 569,900 acre-ft [703 x 106 m3], 76% of which is located in the South Lobe. Study and analysis of the large volume of core, wireline log, 3D seismic, reservoir, and production data indicated that the reefal Keg River formation above the original OWC shows limited petrophysical reservoir zonation in both horizontal and vertical dimensions. The proposed reservoir model contains three horizontal zones within the original oil column arranged in a more-or-less "layercake" fashion (Fig. 5). The uppermost thin Zone A is largely limestone. Underlying the capping Zone A is Zone B, which is all dolomite. Generally, increased vugginess in the pool coincides with the top of Zone B. Zone B is also recognized by the absence of the ubiquitous pyrobitumen, which characterizes the basal Zone C. Indicated fracturing appears to be somewhat more prevalent in Zone C. Both the dolomite and the pyrobitumen extend to and below the pool's original OWC. The pool has a total vertical relief of the oil-bearing formation of about 350 ft [107 m] above the initial OWat 4,350 ft [1326 m] subsea.
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