Three-Dimensional Data Improve Reservoir Mapping
- Piet A. Ruijtenberg (Shell Intl. Petroleum Mij.) | Ray Buchanan (Shell Intl. Petroleum Mij.) | Paul Marke (Shell Intl. Petroleum Mij.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1990
- Document Type
- Journal Paper
- 22 - 61
- 1990. Society of Petroleum Engineers
- 5.1.7 Seismic Processing and Interpretation, 5.1.2 Faults and Fracture Characterisation, 6.5.2 Water use, produced water discharge and disposal, 5.7 Reserves Evaluation, 4.3.4 Scale, 5.1.9 Four-Dimensional and Four-Component Seismic, 1.2.3 Rock properties, 4.1.2 Separation and Treating, 2.4.3 Sand/Solids Control
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The use of 3D seismic data results in a clearer and more precise subsurface picture than obtainable with 2D data. Thus, 3D data can have a major impact on the volume of estimated reserves. Examples demonstrate that 3D data also provide the basis for detecting subtle changes in reservoir development, fluid contacts, and minor faults.
". . changes In reserve levels... can make the difference between an economic venture and a financial disaster."
Over the last 25 years, seismic data have increasingly influenced hydrocarbon field development. Analog data before the 1960's had relatively poor resolution and, although often sufficient for exploration and appraisal siting, was generally too coarse and inaccurate to affect development planning significantly. The succeeding digital seismic acquisition allowed for increasingly sophisticated processing and signal enhancement. Further technological improvements in the early 1970's enabled us to recognize a reservoir directly from preserved relative amplitudes and, in favorable cases, to identify reservoir contents. At this time, 2D seismic data became important in field development. With increased use, however, the limitations of 2D seismic, caused by inadequate areal coverage and inaccurate reflector positioning, became more apparent. Although seismic wave propagation through the earth is a 3D phenomenon, all processing and seismic displays assume it to be 2D, only acting along the axis of the line of acquisition. While this has only a small effect in relatively flat, unfaulted geological settings, this is not the case in most hydrocarbon fields where out-of-plane energy from adjacent structural elements can cause seismic reflections to be superpositioned and blurred. These weaknesses were recognized in the mid-1970's and led to the first attempts at 3D surveys. Today, 3D seismic surveys are an accepted part of the early data-acquisition process, leading to optimized appraisal sites, refined reserve estimates, and more firmly based development plans. This method provides better control over structural shape (particularly fault orientation and interrelationships) and improves the ability to map stratigraphic variations in detail. The detailed coverage and use of consistent acquisition parameters also make 3D surveys a powerful tool for investigating seismic amplitude changes. Interactive workstations facilitate rapid display of horizon amplitude maps, and color displays allow subtle amplitude changes to be differentiated. Amplitude changes may be caused by variations in acoustic contrast at top- or intra-reservoir levels that reflect features such as increasing/decreasing porosity and net reservoir development. Changes in pore content may also affect the amplitude and, in some cases, can be used to map hydrocarbon extent or, in the best circumstances, to indicate swept zones from zones of water injection or depletion around producing wans. Minor faults or fractures that are too subtle to note on individual lines often are displayed as linear-amplitude features. Using horizon amplitude maps allows the geologist/seismologist to inject a new level of detail into understanding the field. Future developments in seismic technology will allow an increasing sophistication in our ability to "see" at the intrareservoir level.
Growth of 3D Surveys
Fig. 1 shows the growth of 3D surveys for the Shell Group of companies. Initial growth was slowed by technical problems and by the need to justify economically the use of the more expensive 3D data acquisition and processing methods. Many of the early surveys were acquired in hostile offshore areas, such as the North Sea, where it was easier to demonstrate that significant savings could be made by avoiding dry-hole locations, thereby reducing (1) the number of appraisal wells needed and (2) the risk in siting development locations that optimized drainage areas. The greatest impact, however, was the ability to match platform size, number of well slots, and production facilities to the more accurately determined field reserves. These results led to rapid expansion in the use of 3D surveys from 1981 onward. By 1987, the total number of surveys conducted was about 100. Acquisition of additional areal coverage in 1988 doubled that of 1987. Most of the 1988 surveys were conducted over hydrocarbon fields to provide a better appreciation of reserves and to guide development-well siting. When this can be achieved at a reasonable cost, there is an increasing tendency to include adjacent exploration prospects within the 3D survey area. Virtually all these surveys are considered to justify the additional acquisition costs.
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