CO2 Injection Increases Hansford Marmaton Production
- William A. Flanders (Transpetco Engineering of the Southwest) | Wallace A. Stanberry (Stanberry Oil Co.) | Manuel Martinez (Transpetco Engineering of the Southwest)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1990
- Document Type
- Journal Paper
- 68 - 73
- 1990. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 2 Well Completion, 4.1.6 Compressors, Engines and Turbines, 5.6.4 Drillstem/Well Testing, 6.5.2 Water use, produced water discharge and disposal, 3.3 Well & Reservoir Surveillance and Monitoring, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.4 Gas Processing, 5.4.2 Gas Injection Methods, 5.5.7 Streamline Simulation, 7.1.10 Field Economic Analysis, 4.1.2 Separation and Treating, 1.2.3 Rock properties, 4.2.3 Materials and Corrosion, 7.1.9 Project Economic Analysis, 2.4.3 Sand/Solids Control, 5.4 Enhanced Recovery, 5.1.1 Exploration, Development, Structural Geology, 3 Production and Well Operations, 5.2.1 Phase Behavior and PVT Measurements, 5.5 Reservoir Simulation, 7.4.5 Future of energy/oil and gas, 4.3.4 Scale, 4.1.9 Tanks and storage systems
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A full-scale CO2 EOR project initiated in June 1980 at the Hansford Marmatonfield in the Texas Panhandle used CO2 from an anhydrous ammonia plant 46 miles[74 km] away. Unique features of the project include the use of CO2 torepressurize the reservoir after primary depletion and of treated sewer waterto displace the CO2 bank. This paper reviews the performance of the field underCO2 injection and explores operational features of the project, including theuse of sewer water as an additional injectant. Surveillance techniques andproject economics are also presented.
"Production response has been superb since CO2 injection began in June1980. Oil rates have increased from 30 to more than 600 B/D [4.8 to 95.4m3/d]."
The Hansford Marmaton field in Hansford County, TX, is operated by StanberryOil Co. This CO2 EOR project differs from most in that the bottomhole pressure(BHP) was exceptionally low--less than 250 psig [1724 kpa]--when CO2 injectionbegan in June 1980. The field is being repressurized to miscibility pressureprimarily with CO2. The field was nearing its economic limit under primarydepletion when the CO2 project began. The primary recovery mechanisms weresolution-gas drive and limited gas-cap expansion. The original reservoirgas-cap volume was less than 10% of the original reservoir oil volume. Primaryproduction before CO2 injection was 1.64 X 106 bbl [0.26 x 106 m3] of oil, or13% of the original oil in place (OOIP). The reservoir's response to CO2injection has been excellent. Production has increased from 30 to more than 600B/D [4.8 to 95.4 m3/d]. Cumulative EOR is more than 1.14 x 106 bbl [0.18 X 106m3] of oil, which represents 70% of the primary oil recovery. Immiscible CO2displacement accounts for most of the oil response to date. The reservoir iscurrently approaching the minimum miscibility pressure (MMP), with futureproduction expected to be dominated by miscible displacement. Utilization ofpurchased CO2 is expected to be less than 7.0 Mscf/bbl [1.3 x 103 std m3/m3] ofoil produced.
The Hansford Marmaton field is located in the extreme northern part of theTexas Panhandle (Fig. 1). Production is from the Marmaton sandstone located atan average depth of 6,500 ft [1981 m]. Oil and gas accumulations are inisolated stratigraphic sand lenses within the Marmaton formation. The reservoirdips to the east at about 110 ft/mile [20.8 m/km], as indicated by thestructure map (Fig. 2). A small gas cap was initially present in the reservoirwith a gas/oil contact (GOC) at 3,383 ft [1031 m] subsea. The total freegas-cap volume was relatively small, representing only 7% of the HCPV in thereservoir. An oil/water contact (WOC) exists at 3,514 ft [1071 m] subsea and isshown in Fig. 2. The aquifer is very small and had no significant effect onprimary production. The net pay of the Hansford Marmaton reservoir is more than45 ft [13.7 m] at its thickest point in the central portion of the field. Thepay thins uniformly from the center of the reservoir to the edges (Fig. 3). Thenet pay averages 20 ft [6.1 m] for the productive portion of the field.Permeability averages 48 md and the porosity averages 18.1 %. There is a goodcorrelation between porosity and permeability, demonstrated by the crossplot inFig. 4. This relationship was used to estimate permeability when cores were notavailable. The reservoir is extremely heterogeneous. The Dykstra-Parsonsheterogeneity coefficient is 0.92 (Fig. 5). Significant vertical permeabilitybarriers or restrictions exist within the Hansford Marmaton pay. Fig. 6 shows afence diagram of the three stringers within the reservoir. The two shalebarriers substantially reduce overall vertical permeability. The uppermoststringer, with an average thickness of 14.6 ft [4.5 m] and an average porosityof 19.2%, contained 75 % of the OOIP. The middle and lower stringers accountedfor 15% and 10%, respectively, of the OOIP. Permeability decreases from 61 mdfor the upper zone to 7.5 md for the lower stringer. Heterogeneity coefficientsfor the individual stringers are essentially the same as for the entire payinterval. Table 1 summarizes properties of the individual stringers. Thereservoir originally contained 12.54 x 106 STB [1.99 x 106 stock-tank m3] ofoil at a pressure of 2,080 psig [14 341 kPa] and a temperature of 142F [61C].Oil gravity was 38 API [0.835 g/cm3]. The reservoir had an initial GOR of 640scf/bbl [114 std m3/m3]. Table 2 summarizes the reservoir and PVTproperties.
The field was discovered in Dec. 1958 and achieved a peak oil productionrate of 576 B/D [91.6 m3/d] in Aug. 1959. Fig. 7 summarizes the productionhistory of the Hansford Marmaton field.
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