Numerical Evaluation of Single-Slug, WAG, and Hybrid CO2 Injection Processes, Dollarhide Devonian Unit, Andrews County, Texas
- E.C. Lin (Unocal Corp.) | E.S. Poole (Unocal Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1991
- Document Type
- Journal Paper
- 415 - 420
- 1991. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 1.6 Drilling Operations, 4.3.4 Scale, 1.6.9 Coring, Fishing, 5.4.9 Miscible Methods, 7.1.9 Project Economic Analysis, 5.5.8 History Matching, 1.2.3 Rock properties, 5.4.2 Gas Injection Methods, 5.4.1 Waterflooding, 5.3.1 Flow in Porous Media, 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 1.8 Formation Damage, 5.3.4 Reduction of Residual Oil Saturation, 7.1.10 Field Economic Analysis, 5.7.5 Economic Evaluations, 5.6.9 Production Forecasting, 5.5.2 Core Analysis, 5.4 Enhanced Recovery, 5.6.2 Core Analysis, 5.3.2 Multiphase Flow, 4.2 Pipelines, Flowlines and Risers, 5.5 Reservoir Simulation
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This paper summarizes a numerical evaluation of the effectiveness ofapplying the conventional single-slug and water-alternating-gas (WAG) CO2injection processes and an innovative hybrid process at the Dollarhide DevonianUnit, Andrews County, TX. The hybrid process consists of the injection of aninitial slug of CO2 followed by WAG CO2 and water injection. The study showsthat a properly designed hybrid injection process may have the potential toimprove CO2 flood oil recovery. process may have the potential to improve CO2flood oil recovery. Introduction
Injection of CO2 for EOR has been successful in many west Texas oil fields.Generally, a predetermined CO2 volume is injected as either a single slug or inseveral WAG cycles at various WAG ratios and then followed by water injection.The WAG injection process is used primarily to improve the mobility ratiobetween the injected fluid and the oil bank in front of it. During WAGinjection, however, water-blocking effects in water-wet reservoirs can besubstantial and can severely hinder oil recovery in a WAG process.
The main objective of this study was to investigate the relativeeffectiveness of conventional single-slug and WAG CO2 injection processes andan innovative hybrid process for the Dollarhide field. processes and aninnovative hybrid process for the Dollarhide field. Field ProductionHistory
The Dollarhide Devonian field in Andrews County, TX, was discovered in 1945.There are two productive zones, designated the upper and lower Devonian, whichare separated by a limestone barrier ranging from 70 to 150 ft thick. The lowerzone is the primary productive interval, containing 75% of the original oil inplace productive interval, containing 75% of the original oil in place (OOIP).The entire field is divided into three major fault blocks. OOIP is estimated tobe 138.3 X 10) bbl. Of this amount, about 42 X 106 bbl is located in the southfault block, 72 X 106 bbl in the north fault block, and 24.3 X 106 bbl in themiddle fault block.
The Dollarhide Devonian field was developed on 40-acre spacing from 1945through 1950 and recovered primary production from both upper and lowerDevonian zones until the early 1960's. In late 1961, half the wells wereconverted to water injection, forming 80-acre, five-spot patterns, and floodingof the lower Devonian began. Oil production increased from less than 1,000 BOPDto more than 9,000 BOPD in 1969. Significant waterflood breakthrough did notoccur for 7 years, and it took 14 years to reach a 50% water cut. In 1972,water injection began in the upper Devonian, resulting in an increased oilproduction from 6,500 to 7,800 BOPD in 1974. Infill drilling began in early1984. Through Dec. 1986, cumulative oil production for the entire unit wasabout 57.7 X 106 bbl, or 42% OOIP.
The Dollarhide Devonian waterflood has been very successful compared withmost west Texas waterfloods. Ultimate primary and secondary recovery (excludinginfill drilling) is estimated to be 59.5 X 106 bbl, or 43.1% OOIP. Uniquegeological characteristics of the Devonian reservoir at Dollarhide were asignificant contributing factor to the prolific waterflood response. Thereservoir exhibits a relatively high degree of continuity between wells andlimited heterogeneities compared with other west Texas reservoirs. Waterchanneling has not been a problem during waterflooding because no apparenthigh-permeability streaks are present. On the basis of the success of thewaterflood and a significant amount of remaining oil (about 78.8 X 106 bbl),Dollarhide Devonian was considered to be an excellent target for CO2 injection.Basic engineering analysis and a simplified modeling study were conducted inthe early 1980's. As a result, a field-scale CO2 injection project wasinitiated for the Dollarhide field.
On May 29, 1985, trucked-in CO2 was first injected into Wells 47-4-D,53-1-D, 55-2-D, and 55-3-D, located in the southeast portion of the south faultblock. After completion of major CO2 portion of the south fault block. Aftercompletion of major CO2 pipeline facilities in Jan. 1986, the CO2 injectionprogram was pipeline facilities in Jan. 1986, the CO2 injection program wasexpanded into the majority of the south fault block, known as the Phase I CO2injection area. Through Dec. 1986, the original Phase I CO2 injection area.Through Dec. 1986, the original trucked-in CO2 injection area had receivedabout 5% HCPV of CO2. At that time, only one of the surrounding producers hadexperienced CO2 breakthrough, and that breakthrough was minimal (50 Mcf/D inWell 47-9-D). Detailed discussion of field CO2 flood performance is coveredelsewhere. performance is covered elsewhere.
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