Re-Evaluation of the Miscible WAG Flood in the Caroline Field, Alberta
- Gary S. Birarda (Petro-Canada Inc.) | Chris W. Dilger (Petro-Canada Inc.) | Ian McIntosh (Petro-Canada Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1990
- Document Type
- Journal Paper
- 453 - 458
- 1990. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 1.6.9 Coring, Fishing, 5.7.5 Economic Evaluations, 2.4.3 Sand/Solids Control, 5.1.5 Geologic Modeling, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2.2 Fluid Modeling, Equations of State, 5.5.8 History Matching, 4.1.2 Separation and Treating, 5.5.2 Core Analysis, 5.3.4 Reduction of Residual Oil Saturation, 5.6.9 Production Forecasting, 5.1 Reservoir Characterisation, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements, 5.7.2 Recovery Factors, 5.2 Reservoir Fluid Dynamics, 5.4.9 Miscible Methods, 1.6 Drilling Operations, 5.5 Reservoir Simulation, 5.1.1 Exploration, Development, Structural Geology, 5.4 Enhanced Recovery, 4.1.5 Processing Equipment
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Premature water breakthrough led to reassessment of a miscible water-alternating-gas (WAG) injection scheme. The reassessment involved detailed geological modeling and a reservoir simulation study. A matching of the complex reservoir history was achieved, and the economic benefits of the scheme were reaffirmed.
A miscible WAG scheme was implemented in the Caroline Cardium formation in southern Alberta in 1984. An earlier feasibility study to predict the WAG scheme performance was considered to have modeled the water and gas displacement adequately, so early water breakthrough was unexpected. The lower oil production that resulted from the water production and lower-than-expected oil prices caused serious doubts about the economic feasibility of the scheme and resulted in a review of the pool performance modeling. Preliminary simulation sensitivities indicated that a more detailed reservoir description needed to be incorporated in the reservoir modeling to forecast pool behavior accurately.
The complex production history (primary depletion, produced-gas reinjection, and WAG injection) made simulation of the pool performance difficult. A model was produced, however, that allowed performance difficult. A model was produced, however, that allowed the pool history to be matched and future depletion to be predicted.
Pool Description Pool Description The Caroline Cardium "E" pool is a low-permeability Upper Cretaceous reservoir in the northern half of an elongated northwest/ southeast Cardium "B" sandstone trend. The reservoir sand becomes cleaner upward and probably was deposited in an offshore shelf setting. The pool is 12.5 miles [20 km] long and 1.5 miles [2-4 km] wide and presently contains 42 wells, 12 of which are injectors. Located at a depth of 8,200 ft [2,500 m], the reservoir has an average net pay of 6 ft [2 m] and consists of interbedded sandstones, siltstones, and mudstones that are capped by a conglomeratic facies. Overlying and lateral mudstones provide the stratigraphic trap for oil accumulation.
The field, discovered in 1974, is about 78 miles [125 kml north-west of Calgary (Fig. 1) and was delineated in 1975 and 1976. The southern half of the field is a separate project currently being water-flooded by another operator. The reservoir contains a sweet 4 degree API [0.82-g/CM] oil with an initial GOR of 1,700 scf/bbl [300 M/M]. No gas cap or active aquifer exists in the "E" pool.
Pool History Pool History The "E" pool was initially drilled on 320-acre [130-ha] spacing with a resulting well allowable of 56 BOPD [9 M 3 /d oil]. In Aug. 1978, reinjection of produced gas commenced. This partial pressure-maintenance scheme was continued until 1980 when full voidage pressure-maintenance scheme was continued until 1980 when full voidage replacement by gas injection began. Flores and Pawelek discussed the merits of a high-pressure miscible dry-gas injection scheme for the pool.
By 1983, reservoir pressure had declined from an initial average of 4,190 to - 3,480 psi [28.9 to - 24 MPa]. Because this was below the 3,960-psi [27.3-MPa] saturation pressure, GOR's increased from 1,700 to (is greater than) 5,600 scf/bbl [300 to (is greater than) 1000 M 3 /M 3 ] on average. Dry-gas breakthrough also contributed to the high producing GOR'S. As a result of the increasing GOR's and declining oil producing GOR'S. As a result of the increasing GOR's and declining oil rates, a field simulation study was undertaken in 1982 to examine depletion alternatives. Continued dry-gas injection was expected to recover only around 19% of the original oil in place (OOIP) at a 3,480-psi [24-MPa] operating pressure. Waterflooding was anticipated to result in a 31 % recovery, and miscible WAG injection recoveries were estimated at 35 %. An economic evaluation favored the WAG scheme because of low repressuring costs, high recoveries, and government royalty incentives. Injection began in 1984 on a 2:1 water/gas ratio. In 1986, although there was no evidence of solvent (enriched-solution-gas) breakthrough and GOR's had declined as expected, water breakthrough occurred 3 years prematurely and oil rates were below what was predicted (Fig. 2).
Before the WAG scheme was implemented, 3.0 million bbl [475 x 10 M] of the 34.6 million bbl [5,500 x 10 M] OOEP had been produced (8.7 % recovery). By the end of 1987, 4.8 million bbl [770 x 10 M ] had been recovered (14 %). With current oil rates of about 1,320 B/D [210 M /d], 33% 0011) ultimately should be recovered.
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