The Lower Cretaceous Travis Peak Formation contains an estimated 6.4 trillion cubic feet (Tcf) of gas in place in East Texas and North Louisiana. Advanced technology will be needed to maximize recovery from this low-permeability ("tight") gas sandstone. This report focuses on the contribution of geology to understanding and efficiently developing the complex gas reservoirs in the Travis Peak Formation in East Texas. Geologic characterization of the Travis Peak Formation included three major areas of study: (1) interpretation of stratigraphy and depositional systems, (2) evaluation of reservoir sandstone diagenesis, and (3) analysis of the structural history and current structural setting.Depositional systems of the Travis Peak Formation in this region include (1) a braided to meandering fluvial system that composes most of the section, (2) a deltaic system that is interbedded with and encases the distal part of the fluvial system, (3) a paralic system that overlies and interfingers with the deltaic and fluvial systems near the top of the Travis Peak, and (4) a shelf system that is present at the downdip extent of the Travis Peak. Reservoir geometry and quality in the systems vary because of differences in depositional processes that controlled sediment lithology, texture, and stratification, in addition to the degree of diagenesis. Thin sandstones separated by mudstones in the upper part of the formation were deposited in paralic and meandering fluvial environments. Best quality reservoirs in the upper Travis Peak occur in tidal-channel, tidal-flat, and meandering fluvial channel sandstones. In most of the lower part of the Travis Peak, sandstones are dominantly braided fluvial. Best quality reservoirs in the braided fluvial deposits exist in wide channel belts oriented parallel to depositional dip. Reservoir quality decreases at channel margins (levees), at channel tops (abandoned-channel deposits), and in interchannel areas where sediments are poorly sorted.Petrographic studies indicate that the Travis Peak Formation contains mainly fine- to very fine grained sandstone, muddy sandstone, silty sandstone, and sandy mudstone. True claystones that could provide stress barriers to hydraulic fracture growth are rare. The sandstones are mineralogically mature, consisting of quartzarenites and subarkoses. Well-sorted sandstones had high porosity and permeability at the time of deposition, but their reservoir quality has been reduced by compaction and cementation. Cementation by quartz, dolomite, ankerite, illite, and chlorite and introduction of reservoir bitumen by deasphalting have reduced porosity to less than 8 percent and permeability to less than 0.1 md in much of the formation. Structurally deeper Travis Peak sandstones are more intensely quartz cemented than are shallower sandstones. This variability in cementation results in differences in mechanical properties, porosity, and permeability between upper and lower parts of the Travis Peak. Furthermore, differences in grain size and cementation history of fluvial and paralic sandstones have resulted in fluvial sandstones having an order of magnitude higher permeability than paralic sandstones at all depths.Because a correspondence exists between extensive quartz cementation and fracture occurrence, abundant, open natural fractures should be expected in highly cemented sandstones. Natural fractures may contribute to production in lower Travis Peak sandstones that have very low matrix permeability. Predicting the propagation direction of hydraulically induced fractures is a key part of completion strategy, and geologic studies of core showed that borehole breakouts and drilling-induced fractures in core can be used as inexpensive and reliable methods of predicting horizontal stress directions and the direction of hydraulic fracture propagation. Hydraulic fractures propagate in directions subparallel to the east-northeast strike of the natural fractures. Thus, hydraulically induced fractures may not intersect many natural fractures. Among the effects that natural fractures can have on well treatments are increased leakoff, fracture branching, and curvature. Branching could cause high treatment pressures and detrimentally affect treatment results if not accounted for in treatment design. Geologic models indicate that natural fractures are not likely to be common in the upper Travis Peak sandstones and that special precautions for treating naturally fractured rock are not required in the upper zone. In the lower Travis Peak, however, natural fractures are common and locally are extensively developed.
Dutton, S. P., Laubach, S. E., Tye, R. S., Baumgardner, R. W., Jr., and Herrington, K. L., 1991, Geologic Characterization of Low-Permeability Gas Reservoirs, Travis Peak Formation, East Texas: The University of Texas at Austin, Bureau of Economic Geology, Report of Investigations No. 204, 84 p.