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A multidisciplinary team, composed of stratigraphers, petrophysicists, reservoir engineers, and geophysicists, studied a portion of Boonsville gas field in the Fort Worth Basin of north‐central Texas to determine how modern geophysical, geological, and engineering techniques can be combined to understand the mechanisms by which fluvio‐deltaic depositional processes create reservoir compartmentalization in a low‐ to moderate‐accommodation basin. An extensive database involving well logs, cores, production, and pressure data from more than 200 wells, [Formula: see text] [Formula: see text] of 3-D seismic data, vertical seismic profiles (VSPs), and checkshots was assembled to support this investigation. We found the most important geologic influence on stratigraphy and reservoir compartmentalization in this basin to be the existence of numerous karst collapse chimneys over the [Formula: see text] [Formula: see text] area covered by the 3-D seismic grid. These near‐vertical karst collapses originated in, or near, the deep Ordovician‐age Ellenburger carbonate section and created vertical chimneys extending as high as 2500 ft (610 m) above their point of origin, causing significant disruptions in the overlying clastic strata. These karst disruptions tend to be circular in map view, having diameters ranging from approximately 500 ft (150 m) to as much as 3000 ft (915 m) in some cases. Within our study area, these karst features were spaced 2000 ft (610 m) to 6000 ft (1830 m) apart, on average. The tallest karst collapse zones reached into the Middle Pennsylvanian Strawn section, which is some 2500 ft (760 m) above the Ellenburger carbonate where the karst generation began. We used 3-D seismic imaging to show how these karst features affected the strata above the Ellenburger and how they have created a well‐documented reservoir compartment in the Upper Caddo, an upper Atoka valley‐fill sandstone that typically occurs 2000 ft (610 m) above the Ellenburger. By correlating these 3-D seismic images with outcrops of Ellenburger karst collapses, we document that the physical dimensions (height, diameter, cross‐sectional area) of the seismic disruptions observed in the 3-D data equate to the karst dimensions seen in outcrops. We also document that this Ellenburger carbonate dissolution phenomenon extends over at least 500 mi (800 km), and by inference we suggest karst models like we describe here may occur in any basin that has a deep, relatively thick section of Paleozoic carbonates that underlie major unconformities.

The locally converted shear wave is often neglected in ray‐trace modeling when reproduction of the AVO response of potential hydrocarbon reservoirs is attempted. Primaries‐only ray‐trace modeling in which the Zoeppritz equations describe the reflection amplitudes is most common. The locally converted shear waves, however, often have a first‐order effect on the seismic response. This fact does not appear to be widely recognized, or else the implications are not well understood. Primaries‐only Zoeppritz modeling can be very misleading. Interference between the converted waves and the primary reflections from the base of the layers becomes increasingly important as layer thicknesses decrease. This interference often produces a seismogram that is very different from one produced under the primaries‐only Zoeppritz assumption. For primaries‐only modeling of thin layers, synthetic seismograms obtained by use of a linearized approximation to the Zoeppritz equations to describe the reflection coefficients are more accurate than those obtained by use of the exact Zoeppritz reflection coefficients. A real‐data example consisting of an assemblage of very thin layers has recently been discussed in the literature. Inferences as to the true earth properties based on the predicted amplitude variation with offset are in error because the primaries‐only assumption is invalid. For one of the models, primaries‐only modeling predicts an amplitude increase of approximately a factor of three from the near trace to the far trace. Reflectivity modeling predicts an amplitude decrease with offset. The O’Doherty‐Anstey effect suggests that transmission loss for primary reflections should not be included in normal‐incidence synthetic seismograms if the short‐period reverberations are not also included. The same principle holds for prestack modeling. Similarly, the Zoeppritz equations should not be used for synthetic seismograms without including the locally converted shear wave.

We conducted a study at Stratton Field, a large Frio gas‐producing property in Kleberg and Nueces Counties in South Texas, to determine how to best integrate geophysics, geology, and reservoir engineering technologies to detect thin‐bed compartmented reservoirs in a fluvially deposited reservoir system. This study documents that narrow, meandering, channel‐fill reservoirs as thin as 10 ft (3 m) and as narrow as 200 ft (61 m) can be detected with 3-D seismic imaging at depths exceeding 6000 ft (1800 m) if the 3-D data are carefully calibrated using vertical seismic profile (VSP) control. Even though the 3-D seismic images show considerable stratigraphic detail in the interwell spaces and indicate where numerous thin‐bed compartment boundaries could exist, the seismic images cannot by themselves specify which stratigraphic features are the flow barriers that create the reservoir compartmentalization. However, when well production histories, reservoir pressure histories, and pressure interference tests are incorporated into the 3-D seismic interpretation, a compartmentalized model of the reservoir system can be constructed that allows improved development drilling and reservoir management to be implemented. This case history illustrates how realistic, thin‐bed, compartmented reservoir models result when geologists, engineers, and geophysicists work together to develop a unified model of a stratigraphically complex reservoir system.