Pressure Maintenance Operations-Fort Chadbourne Field Odom Lime Reservoir

Publication Rights Reserved Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper. A single accumulation of high-gravity, low-viscosity, saturated oil, stratigraphically trapped in a low-relief, low-porosity Pennsylvanian limestone less than 50 feet thick, constitutes the Fort Chadbourne field in north central Texas. What even now would be classed by many as normal development and depletion practice would have returned marginal profits to its many diverse lease and royalty owners. Early recognition of this fact prompted unitization, which resulted in wider well spacing, pressure maintenance with peripheral injection, and consolidation of facilities. Owners' profits, tax revenues, and the commercial crude oil reserve all were increased by the resulting operation. Introduction The Fort Chadbourne field underlies 18,000 acres in Coke and Runnels Counties, Texas, about 40 miles southwest of the city of Abilene. Figure 1 shows it to be the largest in areal extent of the major known fields in its vicinity. Its one producing reservoir is an early Pennsylvanian age shelf limestone deposit subsequently tilted westward and trapped by permeability barriers. Laboratory analyses of subsurface fluid samples, collected shortly after discovery 13 years ago, indicated a relatively high potential oil yield from dissolved gas drive; however, a planned porosity-permeability evaluation program with fairly complete areal coverage, plus pressure communication testing to furnish data for well spacing, also indicated a good displacement potential. When, after only 12 percent pressure depletion, the operators were satisfied that natural water and/or gas encroachment would be negligible, a casinghead gas return program was adopted. Virtually the entire field was unitized to implement this program before the reservoir limits were even defined. After the field's areal extent was established, its full pressure maintenance potential was estimated in time to stabilize pressure at two-thirds of original, by voluntarily reducing production and supplementing gas with water injection. The casing-head gas reserve now is being sold, but full pressure maintenance with water injection continues. The financial outlays, voluntary production cutbacks, and degree of surveillance that have characterized the exploitation of Fort Chadbourne have been justified largely on the results of applied engineering. The field's response to these actions, notably the establishment of modified peripheral injection, employing fluids compatible with those in the reservoir and equipment capable of sustained operation, together with production of gas and water in minimum quantity, has been as expected. DEVELOPMENT HISTORY Humble's Sallie Odom 1, the June 1949 Fort Chadbourne discovery well, encountered the 5,400-foot deep basal Strawn limestone midway in its 235-foot field oil column. Development by eleven operators (representing 55 owners) over a 5-year period defined the reservoir as a monoclinal, stratigraphic, elipsoid-shaped trap with only one degree dip, whose long axis paralleled original gas-oil and water-oil contacts. Reduced permeability resulted in very low potentials for the few wells drilled in the small gas cap, and only two near the gas-oil contact were completed. Fairly uniform gross Odom thickness in the 16,000-acre oil-productive area averaged 42 feet. Extensive coring and logging showed stratification with a high degree of continuity, as can be seen on the correlated isometric cross-section shown in Figure 2. Reservoir rock and fluid properties are shown in Table 1.Original field rules provided 40-acre spacing and a Texas Railroad Commission yardstick allowable of 102 barrels per day per well. These were changed during development, at the operators' request, to permit 80-acre spacing and to restrict allowables to 80 and 140 barrels per day for 40- and 80-acre wells, respectively. As a result, only 316 commercial wells were drilled and the primary depletion rate was retarded to allow study of the feasibility of pressure maintenance.