Common Attributes of Jurassic Tight Gas Sand Reservoirs, Greater Gulf Coast Basin

Steve J. Blanke
Anadarko Petroleum Corporation, The Woodlands, Texas

Multiple TCF tight-gas sand reserves have been recently discovered in the Upper Jurassic (Kimmeridgian-Tithonian) “Bossier” play in two discrete regions within the greater Gulf Coast basin. In both the western margin of the East Texas basin and the Vernon field area of the North Louisiana salt basin, active exploration and development drilling programs indicate the potential of a much larger undiscovered gas resource over at least a 200 mile long fairway that has previously been unrecognized or undervalued in the upper Gulf Coast basin. Regional geological studies and knowledge gained from field development in east Texas and north Louisiana have revealed a number of common play attributes:

• Both areas are characterized by low to moderate sand/shale ratios within distal deltaic and outer shelf deposits. Thick shale units provide vertical and lateral seals that aid both in maintaining pressure compartmentalization, and induced fracture containment during completion. In some areas, transgressive limestones provide important regional pressure topseals.
• Though little has been published on the source bed potential of Kimmeridgian and Tithonian shales within these basins, new geochemical data and basin modeling studies show that over most of the play area, the encasing Bossier shales exhibit adequate organic content (up to 15% TOC) and thermal maturity (greater than 1.2 %Ro) to be considered potential source beds. This precludes the necessity of long-distance secondary migration within these rather laterally discontinuous sandstone deposits.
• Both plays demonstrate some degree of overpressuring, ranging from 0.65—0.95 psi/ft., with the higher values generally coincident with greater present-day burial depths. Thermal cracking of original oil accumulations appears to be a significant contributor to overpressuring, as thin section photomicrographs from gas reservoirs commonly show evidence of pyrobitumen. Basin modeling studies indicate a minimum burial depth of 11,000 feet is necessary to have initiated thermal cracking of oil, a depth that is coincident with observed geopressure trends in these basins. Late-stage faulting and salt diaprism have resulted in localized breaching of the pressure seals in some areas.
• At the depths necessary for adequate thermal maturity and overpressuring, diagenesis, most notably quartz overgrowths, can dramatically reduce reservoir quality. Without a mechanism present for retarding this diagenesis, these reservoirs usually flow non-economic rates of gas. However, reservoirs demonstrating structural or stratigraphic traps at the time of peak hydrocarbon generation and migration are those in which the majority of economic reserves have been found.
• Taken as a whole, these reservoirs exhibit a great deal of heterogeneity. Though intervals exhibiting permeability as low as 0.001 millidarcies provide the bulk of a well’s reserves over its lifetime, thin zones of enhanced permeability up to 0.2 millidarcies are responsible for the bulk of a well’s post-fracture high deliverability.

Initially both the East Texas and North Louisiana Bossier field areas appeared to represent classic basin-centered gas characteristics, i.e., wide spread, low-permeability, over-pressured gas reservoirs with little or no down dip water production. However, new insights gained from full scale field development have shown that reservoir quality is highly dependent upon many of the same conditions governing more conventional gas plays. A full understanding of the reservoir, including depositional environment, timing of trap development, hydrocarbon maturation and tectonic history is necessary to maximize the full potential of the Bossier tight gas sand play.