New Interpretations of Reservoir Architecture of the Upper Cretaceous Woodbine Group in East Texas Field: Sequence Stratigraphic and Depositional Perspectives
Tucker F. Hentz and William A. Ambrose
East Texas field, located on the west margin of the Sabine Uplift, is the largest oil field in the lower 48 states. Oil reservoirs occur in west-dipping Woodbine Group conglomerates and sandstones that are truncated by a subregional unconformity below the Austin Chalk, which forms the seal throughout the field. From its discovery in 1930 through mid-2007 the field had produced 5.42 billion stock tank barrels (BSTB). Its calculated ultimate recovery of approximately 5.49 BSTB and advanced degree of water encroachment indicate that it is in the waning stages of production. Given these figures, about 70 million stock tank barrels (MMSTB) are still likely producible under current production practices. Recent closer evaluation of the amount of bypassed pay, deeper Woodbine pay, and poorly swept oil, however, indicates that the field has remaining reserves of as much as 550 MMSTB. Because of this large estimated remaining-reserves volume, the abundant wells (>31,200) that exist in the field for potential recompletion and/or deepening, and the currently favorable price of oil, producers are now aggressively targeting recompletions—especially deeper pay zones in the Woodbine section.
Although East Texas field has been producing for more than 75 yr, no modern comprehensive geologic study of the field exists. Our study is the first to integrate core data from the field and adjacent areas using well log analysis. Our main objectives have been to understand the role of sequence stratigraphy in the depositional origin of the producing intervals in the field, document facies distribution in the field, and describe its controls on the potential for additional production. We have achieved these objectives by (1) applying sequence-stratigraphic analysis to the Woodbine Group in the East Texas Basin where the succession is complete and extending it to the truncated Woodbine section on the adjacent Sabine Uplift to identify principal chronostratigraphic boundaries in the field; (2) using these boundaries to map coeval sandstone units, identifying reservoir-facies trends in selected pilot study areas, and interpreting depositional-facies origin and distribution and Woodbine paleogeography; and (3) inferring sequence-stratigraphic and facies controls on incompletely swept reservoir zones, potential bypassed pay, and deeper pay zones by integrating our findings from the large core and log data set with engineering data.
The Woodbine Group represents the dominant episode of coarse-siliciclastic deposition during the Late Cretaceous in the East Texas Basin and comprises mostly on-shelf, fluvial-deltaic deposits. The succession thins gradually from the axis of the basin westward to the Mexia-Talco Fault Zone and eastward to the Sabine Uplift. Regional sequence-stratigraphic an
alysis of ~225 well logs distributed across the central part of the basin indicates that a maximum of 14 fourth-order sequences compose the Woodbine succession, and the number of sequences systematically decreases in both directions away from the basin center. The oldest five sequences, extending to the west flank of the Sabine Uplift, are truncated by the base-of-Austin unconformity, whereas deposition of the upper Woodbine sequences was limited to a zone approximately 35 mi wide centered on the basin axis. Reservoirs in the field occur in the basal three fourth-order sequences (S1–S3).
Analysis of >1,500 ft of 30 whole cores and wireline logs from approximately 500 wells in the north pilot area (NPA) and south pilot area (SPA) of the field indicates that the sandstone-body architecture is more complex than that inferred by previous workers. Moreover, the depositional settings of reservoir facies vary considerably from those of earlier investigations, which inferred stacked meanderbelt sandstones in the north part of the field grading to sandstones of equivalent wave-dominated deltaic and coastal-barrier systems in the south part. Our analysis indicates that throughout the NPA, an S3 conglomeratic lowstand incised-valley fill overlies a sandstone-dominated S1 highstand systems tract, the primary target for recent well deepenings. The entire S2 succession has been removed by valley incision in this area. The Woodbine section in the SPA occurs just east of the approximate depositional limit of the S3 incised-valley-fill system and comprises most or all of the S1 highstand deltaic succession. Sandstone-body heterogeneity in the highstand section is controlled by the fluvial-dominated deltaic depositional architecture, with dip-elongate distributary-channel sandstones pinching out over short distances (typically <500 ft) into delta-plain and interdistributary-bay siltstones and mudstones.
Two main development strategies—well deepening and optimized waterfloods—are options for increasing recovery efficiency in East Texas field. A full understanding of reservoir compartmentalization, fluid flow, and unswept mobile oil in the field should consider the fluvial-dominated deltaic and lowstand valley
-fill sandstone-body architecture. For example, production of oil by deepening of existing wells is primarily from thin sandstones in the S1 highstand deltaic succession inferred to contain limited, untapped reservoir compartments owing to abrupt lateral and vertical changes in facies and thickness of sandstone bodies. Permeability and porosity data, in conjunction with net-sandstone maps, indicate that primary reservoir facies in the S1 highstand deltaic succession in the SPA occur in thick (>25-ft) distributary-channel and channel-mouth-bar sandstones. Waterfloods can be better designed to take advantage of the discontinuous reservoir sandstone geometry. Costs can be reduced by shutting off water-injection wells in shaly areas where there is no appreciable pressure support.
© 2004 Tendenci™ software by Schipul - "The Web Marketing Company" | www.schipul.com
in 1983 from the University of Texas at Austin. Before joining the Bureau of Economic Geology in 1987, he was involved in regional subsurface studies of the Yegua and Vicksburg Formations and the Wilcox Group in the Texas Gulf Coast. Ambrose has worked on a variety of projects at the Bureau, including characterization of Frio fluvial and deltaic reservoirs in South Texas, co-production of gas and hot brine from Oligocene reservoirs in the Texas Gulf Coast, evaluation of coalbed methane reservoirs in Rocky Mountain basins, and reservoir characterization and basin analysis studies in Venezuela and Mexico. He is a past president of the Energy Minerals Division of AAPG. His contact information is — email: