Abstract The Headlee Devonian field in West Texas produces a rich (325 bbl/MMcf) gas condensate from a depth of 11,900 ft. Over 50,000,000 bbl of hydrocarbon liquids have been recovered during 8 years of cycling operations. The average core properties are 5.8 percent porosity and 0.11 to 0.30 md permeability. The dewpoint pressure of 4,375 psia is only 881 psi below, the average reservoir pressure. This high dewpoint pressure and the low formation permeability result in flowing BHP's below the dewpoint pressure. A method for calculating the volume of retrograde liquid around the producing wellbore and its effect on producting rates is presented. Also presented is a prediction technique combining areal sweep behavior and a stratification analysis that matches past performance, indicating a recovery of 3.5 times that expected under primary pressure depletion. Introduction The Headlee Devonian field was unitized in Dec., 1957, for the purpose of conducting cycling operations. Gas injection began on the effective date of the unit. Flowing BHP's below dewpoint pressure are experienced because of low formation permeability and a high dewpoint pressure. A retrograde liquid saturation of 45 percent occurs within 50 psi of the dewpoint pressure. It was, therefore, desirable to derive a method of calculating the volume of this retrograde liquid around the producing wellbore and its influence on producing rates. It was also desirable to compare actual injected gas production with a prediction of sweep efficiency and injected gas production. History The Headlee Devonian field was discovered in Aug., 1953. It is encountered at a depth of approximately 11,900 ft. The field is located in Ector and Midland counties immediately east of the city of Odessa, Tex. Fig. 1 is a structure map contoured on the top of the Devonian formation. Although the field is limited on the east by decreasing permeability and water and on the west by water, no evidence of water influx has been noted. it contains 14,000 productive acres. Formation stimulation with large volume fracture treatments was required to establish commercial production rates. Generally, 300 gal of brine per foot of net pay with 2 lb/gal of sand as propping agent were used in the treatments. The operators in the field were aware that a great loss in liquid recovery would occur if cycling operations were not put into effect before the reservoir pressure declined below the single-phase pressure. At the operators' request, production from the reservoir was restricted to six producing days on Nov. 1, 1956, by the Texas Railroad Commission. At that time there were 15 statewide producing days. The field was unitized in Dec., 1957, for the purpose of conducting cycling operations. Gas injection, using a nine-spot pattern with wells on 80-acre spacing, began on the effective date of the unit. Less than 2 percent of the ultimate recovery was produced prior to unitization. A production-injection balance was attained at the end of 1959 and the field was restored to statewide producing days in Jan., 1960. Data obtained prior to unitization indicated that the reservoir fluid existed in a single phase; however, it was inconclusive as to whether a bubble point or a dew point was encountered on isothermal pressure reduction at reservoir temperature. The field was classified as an oil reservoir. Subsequent to unitization, sufficient additional reservoir fluid data were obtained to establish conclusively that the reservoir fluid encountered a dew point. The field was reclassified as a non-associated gas field effective July 1, 1962. On Jan. 1, 1966, there were 163 wells (111 producers, 39 injectors, 13 shut-in) in the unit. Cumulative unit liquid production at that time was 52,800,000 bbl (Fig. 2). The reservoir fluid was initially produced through conventional separation facilities to atmospheric storage tanks. Since Dec., 1961, absorption and stabilization facilities have been used. The well effluent is now separated in the field at either 1,200 or 750 psi for ease of measurement and movement to additional facilities. The separator liquid yield is in the order of 300 to 350 bbl/MMcf of full well stream. JPT P. 41ˆ
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Jun 1, 1975
Yong-Wu Kim + 1
Open Access