Between 1988 and 1991, the Bureau of Economic Geology (at The University of Texas at Austin), Research and Engineering Consultants, and ResTech conducted a study for the Gas Research Institute and U.S. Department of Energy in Seeligson Field of south Texas. Toward the end of the project, a small 3-D seismic survey was acquired. This paper documents the interpretation methods and results that may aid in field rejuvenation or discovery in analogous hydrocarbon reservoirs.

A study was done to characterize deep, prolific Ellenburger gas reservoirs at Lockridge, Waha, West Waha, and Worsham‐Bayer fields in Pecos, Ward, and Reeves counties in West Texas. A major effort of the study was to interpret a 176-mi23-D seismic data volume that spanned these fields. Well control defined the depth of the Ellenburger, the principal interpretation target, to be 17 000–21 000 ft (5200–6400 m) over the image area. Ellenburger reflection signals were weak because of these great target depths. Additionally, the top of the Ellenburger had a gentle, ramp‐like increase in acoustic impedance that did not produce a robust reflection event. A further negative influence on seismic data quality was the fact that a large portion of the 3-D seismic area was covered by a variable surface layer of low‐velocity Tertiary fill that was, in turn, underlain by a varying thickness of high‐velocity salt/anhydrite. These complicated near‐surface conditions attenuated seismic reflection signals and made static corrections of the data difficult. The combination of all these factors has caused many explorationists to consider this region of west Texas a no‐record seismic area for deep drilling targets. Although the 3-D seismic data aquired in this study produced good‐quality images throughout the post‐Mississippian section (down to ∼12 000 ft, or 3700 m), the images of the deep Ellenburger targets (∼20 000 ft, or 6100 m) were limited quality. The challenge was to use this limited‐quality 3-D image to interpret the structural configuration of the deep Ellenburger and the fault systems that traverse the area so that genetic relationship could be established between fault attributes and productive Ellenburger facies. Two techniques were used to produce a reliable structural interpretation of the 3-D seismic data. First, log data recorded in 60-plus wells within the 3-D image space were analyzed to determine where there was evidence of overturned and repeated units caused by thrusting and evidence of missing sections caused by normal faulting. These petrophysical analyses allowed reliable fault patterns and structural configurations to be build across 3-D seismic image zones that were difficult to interpret by conventional methods. Second, cross‐section balancing was done across the more complex structural regimes to determine if each interpreted surface that was used to define the postdeformation structure had a length consistent with the length of that same surface before deformation. The petrophysical analyses thus guided the structural interpretation of the 3-D seismic data by inferring the fault patterns that should be imposed on the limited‐quality image zones; the cross‐section balancing verified where this structural interpretation was reliable and where it needed to be adjusted. This interpretation methodology is offered here to benefit others who are confronted with the problem of interpreting complex structure from limited‐quality 3-D seismic images.

In previous unpublished work, we found that anomalous values of instantaneous frequency (that is, frequency values that are negative or that have positive magnitudes greater than Nyquist limit) are valuable indicators of alterations in reflection waveshape that occur commonly at stratigraphic terminations. Inspection of 3-D seismic data across Nash Draw Field on the northwest slope of the Delaware Basin showed that appreciable wavelet alterations occurred at the boundaries of distinct seismic facies within the targeted Brushy Canyon reservoirs that are being produced in this field. Based on this observation, we used instantaneous frequency as the fundamental database to define the edge positions and areal shapes of individual reservoir facies within this complex, slope‐basin distribution of siltstones and sandstones, commonly thought to be a succession of turbidite depositions. We compared the compartmentalization detail derived from this frequency‐based approach with compartmentalization models provided by an amplitude‐based interpretation and by coherency/continuity cube technology. These comparisons led us to conclude that a properly executed 3-D interpretation of instantaneous frequency behavior can provide a good first guess of the internal compartmented structure of many reservoirs. We offer our work here for peer evaluation by people who support reservoir characterization studies similar to what we describe. We have used instantaneous frequency behavior to successfully detect lateral disruptions in stratigraphic continuity for several years—long before the current concept of a coherency (or continuity) cube was publicized for this same purpose. This study shows that interpreters who do not have ready access to coherency‐cube technology, but who do have Hilbert transform algorithms available to them, can create 3-D volumes of instantaneous frequency that provide valuable indications of reflection discontinuity, much in the same way that continuity/coherency cube technology does.

A study was done at Nash Draw field, Eddy County, New Mexico, to demonstrate how engineering, drilling, geologic, geophysical, and petrophysical technologies should be integrated to improve oil recovery from Brushy Canyon reservoirs at depths of approximately 6600 ft (2000 m) on the northwest slope of the Delaware basin. These thin‐bed reservoirs were deposited in a slope‐basin environment by a mechanism debated by researchers, a common model being turbidite deposition. In this paper, we describe how state‐of‐the‐art 3-D seismic data were acquired, interpreted, integrated with other reservoir data, and then used to improve the sitting of in‐field wells and to provide facies parameters for reservoir simulation across this complex depositional system. The 3-D seismic field program was an onshore subsalt imaging effort because the Ochoan Rustler/Salado, a high‐velocity salt/anhydrite section, extended from the surface to a depth of approximately 3000 ft (900 m) across the entire study area. The primary imaging targets were heterogenous siltstone and fine‐grained sandstone successions approximately 100 ft (30 m) thick and comprised of complex assemblages of thin lobe‐like deposits having individual thickness of 3 to 6 ft (1 to 2 m). The seismic acquisition was complicated further by (1) the presence of active potash mines around and beneath the 3-D grid that were being worked at depths of 500 to 600 ft (150 to 180 m), (2) shallow salt lakes, and (3) numerous archeological sites. We show that by careful presurvey wave testing and attention to detail during data processing, thin‐bed reservoirs in this portion of the Delaware basin can be imaged with a signal bandwidth of 10 to 100 Hz and that siltstone/sandstone successions 100 ft (30 m) thick in the basal Brushy Canyon interval can be individually detected and interpreted. Further, we show that amplitude attributes extracted from these 3-D data are valuable indicators of the amount of net pay and porosity‐feet in the major reservoir successions and of the variations in the fluid transmissivity observed in production wells across the field. Relationships between seismic reflection amplitude and reservoir properties determined at the initial calibration wells have been used to site and drill two production wells. The first well found excellent reservoir conditions; the second well was slightly mispositioned relative to the targeted reflection‐amplitude trend and penetrated reservoir facies typical of that at other producing wells. Relationships between seismic reflection amplitude and critical petrophysical properties of the thin‐bed reservoirs have also allowed a seismic‐driven simulation of reservoir performance to be initiated.

We conducted a study at Stratton Field, a large 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 less than 20 ft (6 m) thick 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 seismic data are carefully calibrated to subsurface stratigraphy 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 study 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.

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.

Roksandic’s discussion is superb! Because so few papers are submitted to Geophysics that deal with seismic interpretation theory, we were concerned that our philosophy of thin‐bed interpretation might not be appreciated by the readership. We encourage Roksandic, and other interpreters who have his ability to explain concepts, to continue to submit interpretation‐based papers to Geophysics.

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.