Synergism of 3-D seismic data, wavelet processing, colour display and interactive interpretation has been exploited in the study of a Gulf of Mexico gas reservoir. Seismic amplitude has been used as a measure of the proportion of a sand/shale reservoir capable of producing gas. This has led to the mapping of net producible thickness of gas sand. The tuning phenomena resulting from geometric effects alone were studied in detail, and tuning curves of various levels of sophistication were used as the basis for amplitude editing. Statistical tuning curves were derived by interactive cross-plotting and deterministic curves by wavelet extraction. Multiple wavelet side lobes cause multiple maxima in the tuning curve. Depositional effects and intrareservoir communication have also been studied by interactive cross-plotting.
In the Garden Banks area of offshore Louisiana several gas sands have been drilled and found productive. However, the sands are laterally variable in thickness and effectiveness. An improved understanding of the spatial distribution of net producible gas sand is highly desirable for reservoir management. The bright reflections from the top and the base of each sand were tracked automatically on an interactive interpretation system. This yielded time structure maps and hence isochron maps for each gross sand interval. The horizon Seiscrop™ sections diplaying amplitudes over the sand interfaces were then summed, adjusted for tuning effects, and smoothed to yield estimates of net gas/gross sand ratio over the area under study. By combining these with the corresponding isochron maps and an appropriate gas sand interval velocity, we obtained net gas sand isopach maps which tie acceptably with well data. Integration of these provided total reservoir volumes. ™Trademark of Geophysical Service Inc.
Modern reservoir characterization workflows attempt to integrate all available, reliable, and appropriate sources of data into 3D geocellular or numerical earth model(s). These models provide various properties such as lithofacies, porosity, permeability, hydrocarbon/water saturation at each grid cell. Reservoir simulation is then performed on the geocellular model to predict reservoir performance and production history. Geocellular models allow geoscientists to integrate various data from many different sources to calculate oil and gas volumetrics, perform efficient well planning, forecast reservoir performance, and optimize reservoir depletion schemes. In addition, within the same model, the stochastic simulation process can generate multiple equiprobable realizations, all of which honor the input data. The differences among these realizations provide a quantitative envelope of the uncertainty due to the limited reservoir information and data for the subsurface.In reservoir or geocellular modeling, different types of data are used, including geologic, geophysical, petrophysical, and engineering data. Some input data may be highly conceptual and not necessarily limited to a specific reservoir; for example, geologic knowledge can describe the reservoir at all possible scales. There are also various types of measured data specific to the reservoir, such as conventional core, well logs, 3D seismic, well testing, and hydrocarbon production. These data measure the reservoir at different scales. For example, well log data can provide centimeter-to-meter scale resolution, while seismic data are at comparatively lower resolution and provide larger-scale stratigraphic and structural information. These different data types need to be incorporated into the geocellular model at their correct scales. We propose a workflow integrating various types of data including geologic, geophysical, well/petrophysical, and associated knowledge at their respective scales. For this case study, the workflow is applied to a fluvial reservoir that experienced a complex structural history that today is located in an offshore marine setting.Geologic background. The reservoir is Tertiary age, siliciclastic, and was deposited in a rapidly subsiding basin formed in part by wrench and extensional tectonism. The gross reservoir section is approximately 150 m thick with an average of 25% net-to-gross and 20 m of net pay. The sandstone and shale were deposited in a fluvial-dominated setting, which included both meander belts and braided streams. Individual channels are approximately 10-40 m in thickness and 20-800 m in width, and can be filled with either sandstone or shale. These sand and shale-filled channels characteristically have similar shapes and sizes. The fluvial channels have a complex connectivity that affects fluid flow. Fluid and pressure data suggest that some channels are isolated features while other channels are highly connected in labyrinth geometries. In addition, some cross-cutting shalefilled channels can act as local barriers th...
The economic consequence of exploitation in areas with an unspecified risk of abnormal pressure profiles range from increased drilling costs to unrealised prospect potential. Optimised planning practices will impact on not only the costs of drilling but also on the quality of the reservoir evaluation and productivity assessment.Numerous exploratory wells in the Carnarvon Basin have encountered unprognosed high pore pressures in the past, resulting in increased concerns about well control and safety, and as a consequence higher drilling costs. High pressures encountered at Parker–1ST1, Forrest–1AST1, Venture–1ST1, and Venture–2ST1, in particular, caused a high level of concern for moderately deep drilling targets. As a result of the diversity of potential overpressure mechanisms, there is a variety of opinion on the risk of encountering abnormal pressure in particular areas, and no standard way to capture and incorporate this information into planning and drilling decisions.At the end of 1999 a project was defined to evaluate the risk of overpressure of a prospect in this area. This project had the primary focus of evaluating the risk of encountering high pore pressures when drilling an exploratory well. This risk assessment was directed towards a decision point for well design, which had cost implications in anticipation of drillingIn the process of technical assessment of abnormal pressure in this prospect, it was important to include all of the necessary data and technical practices, which could contribute to an understanding of the prediction. The application of a cooperative multi-functional team and a software infrastructure (Juniper) was instrumental in allowing this process to take place. A visual decision tree with risk assessment allowed for input from all contributors and for the inter-relationship of the inputs. This comprised the methodology for assessment.The methodology highlighted, explicitly, areas of high uncertainty where evidence neither for nor against overpressure was available. These areas became the focus of technical work, as they had potential for significant impact on the risk assessment. A sub-team extensively reviewed the pressure tests, sonic logs, borehole influxes and mud weights of nearby wells. The results of the well study had a bearing on the choice of analogue, the geological model, and pressure prediction. A geological modelling sub-process was carried out to test the significance of compaction disequilibrium, organic maturation and permeability on overpressure generation. A geophysical sub-process was initiated to complement the pressure modelling risk element. Surface seismic data was depth processed to relate velocities to trends obtained from the well study.The methodology was found to be a highly effective technique for recording the decision processes and as a tool for interdisciplinary communication in a cooperative and non-threatening environment. The outcome of the study was to highlight reduced risk of overpressure in the prospect as perceived by all parties (geoscientists, drilling engineers, management and joint venture parties). The common view on risk prompted a reassessment of the risk profiles on all the related wells in the program and allowed revision of the drilling programs and significant cost savings relative to the original forecasts for the program.
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