Waterflood and CO2 Flood of the Fractured Midale Field (includes associated paper 22947 )
- Dennis Beliveau (Shell Canada Ltd.) | David A. Payne (Shell Canada Ltd.) | Martin Mundry (Gardiner Oil and Gas Ltd.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1993
- Document Type
- Journal Paper
- 881 - 817
- 1993. Society of Petroleum Engineers
- 4.3.4 Scale, 5.6.4 Drillstem/Well Testing, 5.6.1 Open hole/cased hole log analysis, 5.2.1 Phase Behavior and PVT Measurements, 5.4.9 Miscible Methods, 5.1.1 Exploration, Development, Structural Geology, 5.4.1 Waterflooding, 5.5 Reservoir Simulation, 5.4.2 Gas Injection Methods, 1.6 Drilling Operations, 3 Production and Well Operations, 5.5.8 History Matching, 1.6.9 Coring, Fishing, 1.6.6 Directional Drilling, 1.8 Formation Damage, 5.4 Enhanced Recovery, 5.8.6 Naturally Fractured Reservoir, 5.6.5 Tracers, 4.3.3 Aspaltenes, 5.1 Reservoir Characterisation
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The considerable remaining oil target in the naturally fractured Midale field prompted a major reservoir and recovery mechanism study in the mid-1980's. Included in the study were the detailed evaluation of 20+ years of waterflood history and the implementation and analysis of a tertiary miscible CO2-flood pilot. The study showed that tertiary miscible flooding should not necessarily be precluded for naturally fractured reservoirs.
The 500-million-bbl Midale oil field is part of a trend of large Mississippian oil accumulations located in southeastern Saskatchewan along the northern margin of the Williston basin. The field was discovered in 1953 and developed on 80-acre spacing. In 1962, Midale was unitized for waterflooding, with eighty-three 320-acre inverted nine-spot patterns (Fig. 1).
The reservoir section in Midale consists of a heavily fractured vuggy limestone overlain by a less fractured chalky dolomite. Waterflood performance is dominated by these oriented vertical fractures, which typically are spaced 1 to 4 ft apart. Production wells located "on-trend" from injectors(aligned with the fractures) showed sharp early response to waterflood. In contrast, response of "off-trend" producers was smooth and delayed. Oil produced to date represents recovery of 20% of the original oil in place(OOIP); ultimate waterflood recovery is predicted to be only 24% OOIP. The current water cut in the mature operation is about 80% (Fig. 2). Although the reservoir is fractured, well productivities are modest, with average production rates of 75 to 100 STB/D-well.
Typical EOR screening criteria suggest that naturally fractured reservoirs are poor candidates for miscible CO2 flooding. Despite this rule of thumb, the favorable reservoir geology combined with the substantial EOR target at Midale persuaded the field owners to study implementation of CO2-flood technology.
A 4.4-acre tertiary miscible CO2-flood pilot was conducted during 1984-89. Field-scale waterflood and pilot-scale CO2-flood results were history matched with a dual-porosity reservoir simulator. Field-scale CO2-flood recoveries are predicted to be an incremental 20% OOIP. The high CO2-flood recovery results from the favorable interaction of the different layers within the reservoir. The bulk of the large tertiary target is trapped in the chalky dolomites in the upper reservoir section. Although most of the CO2 is injected into the underlying heavily fractured limestones, gravity forces cause the CO2 to rise and come in contact with the oil in the dolomites. Based on pilot results and simulation studies, a $40-million commercial-scale CO2 flood began in Feb. 1992 in 10% of the unit.
The 4,600-ft-deep, gently dipping productive carbonates are overlain and underlain by impervious anhydrite beds.1The productive interval typically consists of a limestone (the Vuggy) overlain by a dolomite (the Marly), as shown in the type log in Fig. 3. The Marly zone has a layered geometry with good lateral continuity between wells. The Vuggy is less layered and more laterally discontinuous.
The average gross thicknesses for the Vuggy and Marly zones are 40 and 30 ft, respectively; reservoir development is 20 ft in the Vuggy and 10 ft in the Marly. The reservoir is quite consistent in total thickness, varying from 60 to 80 ft across the majority of the unit. Internally, however, the Vuggy/Marly thickness ratio does vary considerably.
The Vuggy zone contains two distinct rock types, intershoal and shoal. The intershoal Vuggy is present over the entire unit, while shoals have limited areal extent. Indeed, the majority of the unit is devoid of shoal Vuggy. However, where shoal Vuggy does exist, it dominates performance because of its high permeability. Intershoal Vuggy consists primarily of peloidal and bioclastic packstones containing mostly interparticle porosity. The shoal Vuggy consists of peloidal grainstones that display visually dramatic vugular and interparticle porosity. Despite these large pores, porosity values in the shoal and intershoal are very similar, ranging from 10% to 15%. Typical intershoal permeabilities are 1 to 10 md, with shoal permeabilities an order of magnitude higher.
The Marly zone consists primarily of dolomitic wackestones and mudstones, with the mudstones forming the best reservoir rock. Porosity, which ranges from 20% to 35%, is predominantly intercrystalline with secondary amounts of pinpoint vuggy porosity. Marly permeability ranges from 1 to 10 md.
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