The Ford Geraldine Unit CO2 Flood- Update 1990
- K.R. Pittaway (Conoco Inc.) | R.J. Rosato (Conoco Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1991
- Document Type
- Journal Paper
- 410 - 414
- 1991. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.5 Processing Equipment, 5.4.9 Miscible Methods, 4.1.3 Dehydration, 1.2.3 Rock properties, 4.2 Pipelines, Flowlines and Risers, 2.4.3 Sand/Solids Control, 5.4.1 Waterflooding, 3.1 Artificial Lift Systems, 4.2.3 Materials and Corrosion, 4.6 Natural Gas, 4.1.6 Compressors, Engines and Turbines, 3.1.1 Beam and related pumping techniques, 5.5.8 History Matching, 5.1.5 Geologic Modeling, 1.6 Drilling Operations, 5.4 Enhanced Recovery, 5.4.2 Gas Injection Methods, 5.6.4 Drillstem/Well Testing, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 4.3.4 Scale
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This paper updates the operating history of the tertiary CO2 flood in theRamsey (Delaware sand) formation of the Ford Geraldine Unit (FGU). Thediscussion focuses on injection and production history, operationalconsiderations, data collection and monitoring techniques, and plans for theflood.
The FGU CO2 flood is 130 miles west of Midland, TX. The miscible flood is acontinuous-slug CO2 injection process, currently calling for a 30% total PVslug size followed by a brine postflush.
CO2 injection started in Feb. 1981, when the oil production rate from astaged waterflood had decreased to about 300 B/D. Production has increased to1,700 B/D since that time and is expected Production has increased to 1,700 B/Dsince that time and is expected to reach 2,000 B/D in 1991. This paperdiscusses the reservoir, the history of the flood, the collection and use ofdata, and the reservoir modeling that is a part of the FGU CO2 flood.GeneralInformation
The flood is in the Geraldine Ford field in the Delaware basin (the westernportion of the Permian Basin) in west Texas. The Geraldine Ford field is theterminal portion of a submarine fan channel that became structurally high byeastward tilting during the late Permian Age and again in the late CretaceousAge. The Ramsey and Permian Age and again in the late Cretaceous Age. TheRamsey and Olds sandstones were unitized in the heart of the Geraldine Fordfield as the FGU. Only the Ramsey sand is being CO2 flooded because the Oldszone is discontinuous and contains only about 5 % of the total PV.
The Ramsey sand is the uppermost sandstone of the Bell Canyon formation. TheBell Canyon, with alternating siltstone and fine-grained sandstones, formsimportant shallow oil reservoirs in the Delaware basin. (Table 1 lists thereservoir data.)
The Ramsey sand is at a depth of 2,680 ft, and average net pay is 25 ft.Average porosity is 23%, and average permeability is 60 md. Oil gravity is 40degrees API. Reservoir temperature is 83 degrees F, and the originalbubblepoint was 1,383 psig. The FGU covers 8,400 acres in Reeves and Culbersoncounties. Most of the productive pay is in the south-central portion of thefield and trends northeast/southwest from there.
The field, discovered in 1956, was fully developed by 1965. Water saturationat discovery was 47.7%, well above the irreducible water saturation of 35%.Most wells produced some water at discovery. Fig. 1 shows the field's declinecurve. Primary recovery was 18% of original oil in place (OOIP) by solution-gasdrive, probably with some water encroachment. The FGU (Fig. 2) was probablywith some water encroachment. The FGU (Fig. 2) was formed in Nov. 1968. Awaterflood pilot began in June 1969 and was expanded to the entire unit between1972 and 1980. The high initial water saturation, combined with good primaryperformance, led to a poor secondary recovery of about 4.5% OOIP. The FGU has40-acre five-spot patterns.
CO2 Flood History
Development. By the late 1970's, the waterflood was nearing its economiclimit. CO2 flooding appeared to he a possible EOR technique. An injectivitytest showed adequate CO2 injectivity. Slim-tube tests showed a minimummiscibility pressure (MMP) of 900 psig for pure CO2 and 1,100 psig for CO2contaminated with 5% psig for pure CO2 and 1,100 psig for CO2 contaminated with5% methane. Reservoir pressure was near 1,600 psig, so CO2 flooding appeared tobe possible.
Enron's Twofreds CO2 flood, also in a Delaware sand, was in operation atthat time. Twofreds was history matched and used as a basis for performancepredictions for Ford Geraldine. Economics based on those predictions werefavorable, and flood development started.
Several different sources of CO2 have been used for the flood. By productCO2 from a Fort Stockton gas plant was the initial CO2 supply. The FGU andothers built a 6- and 8-in. pipeline to transport the CO2. Injection into allof the unit except tide Stage V area (Fig. 2) began in March 1981. Owing toreduced natural gas sales, byproduct CO2 supply decreased within a short timeto below adequate rates for the large area. Injection was gradually moved tojust the center of the unit. Two CO2 supply wells, drilled in 1983 and 1984,were plugged and abandoned because of low production.
An 8-year CO2 contract was finally signed with a major supplier during 1985.Injection from that supply began in Dec. 1985. By that time, reservoir pressurewas down to about 1,100 psig, so injection was concentrated into only threeheader house (HH) areas (HH 1 through 3) to increase pressure. The HH 10 areawas activated in July 1987. The flood was expanded again in April 1988, addingthe HH 4 area.
The next expansion, in early 1990, added the southern half of the HH 5 and 6areas. The remaining portions of the unit will be flooded as recycle CO2volumes allow, probably after the first stage is placed on brine postflushinjection.
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