Using Specific Exploration and Completion Techniques in the Fort Worth Basin for the Separate Tectophases of Sediment Development
The Fort Worth Basin developed in three separate “tectophases” as a foreland basin in front of the advancing Quachita foldbelt. The first phase is the deep marine black shales; the second is the flysch sediments (basin centered tight gas sands); and finally are the more shallow marine related sediment systems. Due to the present competitive leasing situation in the Fort Worth Basin, acreage needs a complete economic hydrocarbon evaluation to not only determine what the value of the reserves are today using present technology, but to also determine what the future value could be using expected advances in technology. A different and distinctive geologic and engineering technology is needed for each tectophase to produce the maximum volume of hydrocarbons for the least cost in the Fort Worth Basin, which is the fundamental purpose of both petroleum geology and engineering in any basin.
The tectonics of the advancing Quachita foldbelt create the dynamics for a predictable foreland basin sediment system model. There are variations in sediments from basin to basin but all generally follow the three tectophases of development. The Fort Worth Basin had deep marine black shale development during the Mississippian and to a less extent again in the Lower Atoka after deposition of Bend age shallow marine sediments. The basin was as much as 600 feet deep during the Barnett but became shallower during Marble Falls limestone development and later cyclic Bend shallow marine clastic and limestone deposition. Tectonics intensified at this time as the basin down warped along with extensive faulting as the Quachita foldbelt continued to advance westward. Lower Atokan black marine shales developed during this down warping followed by a more predictive coarsening upward of sediments from very fine-grained flysch sediments of the Lower Atoka to the deltaic clastic and limestone systems of the Upper Atoka and Strawn. A later southeastern uplift gives the Fort Worth Basin it’s present structural dip.
The Mississippian Barnett deep marine black shales were deposited over Ordovician Ellenburger karst dolomites as the basin deepened. The Barnett Shale reservoir quality varies greatly across the basin in the composition of hydrocarbons and in the rock characteristics. The rock characterization data from the geologist is necessary for any engineering completion model to effectively determine optimal completion techniques. An understanding of what rock characteristics produce the highest productivity index from wells drilled and completed in these shales is needed by the geologist to stake better drilling locations. Black shales are in an unconventional resource class by themselves and must be mapped and evaluated using black shale models.
The Atoka basin-centered tight gas sands were deposited in what is described as flysch sediments. These sediments have been misidentified most of the time in the past by either grouping the sediments into underlying Bend sediments or overlying Strawn sediments. The Atoka basin-centered tight gas sands were deposited in central Parker County and continue to the south and southwest. These very fine-grained, thinly-laminated sediments have no distinctive water contact, are located in the center of the basin, and are under-pressured. The sediment thickness is in the hundreds of feet and contains extremely large reserves of gas-in-place. The basin centered gas sands are presently not being produced but will be a resource for the future with proper exploration and completion technologies.
The most explored for and produced sediments are the shallow marine sediments of the northwest to southwest parts of the Fort Worth Basin. These sediments were deposited during the Bend and again in the Lower Atoka to Strawn. For the most part, these western sediments are now classed as mature hydrocarbon resources. New reservoirs will be discovered as we drill deeper for the Barnett Shale, but most of the shallow marine deposits will be depleted or partially depleted and need secondary recovery technologies to recover the hydrocarbons. Again, a combination of petroleum geology and engineering is needed for successful future exploration and completion of hydrocarbons in the mature sediments of the Fort Worth Basin.
Much of the acreage in the Fort Worth Basin contains the sediment systems of all three tectophases in basin development. Three distinctive petroleum geologic and engineering technologies must work together to effectively drill, evaluate and produce hydrocarbons in the basin as available leases disappear or become more expensive in the future. The Fort Worth Basin will continue to move into the “gas farming” phase of development that George Mitchell envisioned decades earlier.
AAPG Search and Discover Article #90065©2007 AAPG Southwest Section Meeting, Wichita Falls, Texas