To characterize production from and to provide reserve estimates for low-permeability gas reservoirs in the Travis Peak Formation, East Texas Basin, reservoir parameters, such as permeability, porosity, water/gas saturation, and formation pressure, were calculated and analyzed. Production characteristics, such as absolute open flow potential, maximum production rate, decline rate, and gas/condensate production ratio, were examined. In addition to the results from completed studies of six gas producing fields, some data from incomplete field studies and from public records were also included in the regional interpretations. The study area lies within the central and eastern parts of the East Texas Basin and includes the western flank of the Sabine Uplift.
Thickness-weighted average permeabilities and median permeabilities, which both represent the upper limits of gas permeability in the study area, are less than 0.1 md. Thickness-weighted field-average permeability ranges from 0.006 md in the southeastern part of the study area to 0.1 md in the northern part, with the exception of one field in the central part of the study area, which measured 2 md. About 57 percent of wells that have been completed in the six selected fields have permeabilities of less than 0.1 md. Field-average porosity ranges from 8 percent to 11 percent, with the exception of a field in the central part of the study area, which measured 14 percent. Water saturation varies from 24 percent to 43 percent and decreases from the northeastern part to the southwestern part of the study area.
Gas fields in the northern and central parts of the study area are characterized by relatively high productivity and a weak water drive production mechanism, which contrasts with low productivity and a gas expansion production mechanism only in the southern and southeastern parts. Production decline curves from Travis Peak gas fields may be empirically characterized as having two linear sections with different slopes. The first linear section, which represents early production (a period of 3 to 5 years), is followed by a linear section of lesser slope representing later production. For the early years of production, the average production decline rate of the first linear section in the northern part of the study area (0.46 cycle/year) is lower than that of the southern part (1.28 cycle/year). A production decline rate of 0.3 cycle/year characterizes the central part of the study area. Maximum production rate decreases from 82,300 Mcf/month in the northern part of the study area to 11,700 Mcf/month in the southern part with the exception of a rate of 40,890 Mcf/month for a field in the southeastern part. About one-third of the gas wells in the northern area and more than one-half of the gas wells in the southern and western areas initially produced wet gas (gas to condensate ratio between 5 to 100 Mcf/bbl). In the study area, specific gravity of produced gas ranges from 0.62 to 0.66 (air = 1), and API gravity of produced condensate ranges from 50° to 60°. Formation temperature ranges from 200° F to 245° F. Some wells in gas fields in the northern and central parts of the study area produce oil.
Potential fluid migration in the study area in the Travis Peak Formation may be from the southwest toward the northwest, in part because initial average formation pressure decreases from 4,540 psi in the southwestern parts of the study area to 3,076 psi in the northeastern parts.