4D seismic reservoir monitoring (timelapse seismic) has the potential to significantly increase recovery in existing and new fields. Changes in fluid saturation, pressure, and temperature that occur during production induce changes in the reservoir's density and compressibility that may be detected by differencing repeated seismic data. As a result, seismic data can be used to help monitor and predict the inter-well position and movement of reservoir fluids, locating bypassed oil, avoiding premature breakthrough, optimizing infill well locations, and evaluating EOR pilots prior to full field implementation.

However, most published seismic reservoir monitoring examples have been demonstration projects and the impact of the technology on reservoir profitability has not been well established. The cost of reservoir monitoring must be recovered through increased production rate, added reserves, and/or reduced operating costs. Locating fluid saturation fronts allows optimization of the recovery process. Better placement of infill and development wells, elimination of dry holes, balancing injection and production rates, and more accurate workovers can decrease costs and increase recovery. Although studies suggest that the potential economic impact is great, the acceptance of 4D seismic data in our industry remains limited - similar to the situation with 3D seismic data 10 to 15 years ago.

Indeed, there are many issues associated with the application of timelapse seismic data. Two of the most significant technical issues are the repeatability of the seismic data in the non-reservoir portion of the data volume and the robustness and credibility of the seismic difference within the reservoir. In principle, estimates of dynamic reservoir properties, obtained over the entire field area from 4D seismic data, can be used to optimize reservoir management. However, because of non-uniqueness, the process of inferring dynamic reservoir properties from seismic data is hardly trivial. What then, is the likelihood that action will be taken based on seismic monitoring data that will result in an increase in the economic value of a field?

These issues are examined using several case studies. Seismic monitoring has become an integral part of the enhanced oil recovery technology at Imperial Oil's Cyclic Steam Stimulation Cold Lake Field in Canada. Seismic monitoring surveys provide definitive images of the fluid saturation fronts in the reservoir, where about 50% of the oil has been bypassed. These images were used to drill 46 deviated steam injection wells, three horizontal wells (which serve as injectors and producers), as well as to model and monitor new pilot processes. Early oil production data from the infiIl pilots indicate a significant improvement in oil rate. New reservoir technologies are being developed to attempt to capture the bypassed oil as identified by the seismic data.

An example from the Gulf of Mexico Lena Field looks at the application of 40 seismic data in a mature setting. The legacy seismic data over the field were not acquired or originally processed to maximize repeatability. Sequentially increasing the level of sophistication in the seismic re-processing effort, quantifying and reporting the results at each step establishes the costs and benefits in achieving a robust seismic difference. However, the acquisition of the repeat survey was not necessarily timed to optimally map reservoir changes or impact development decisions. While the interpretation of the seismic difference has yielded infill drilling opportunities, rig availability and other operations constraints may limit action.

New field developments allow planning of time-lapse acquisition to have the greatest impact on field economics. In one such example, seismic modeling based on reservoir flow simulation illustrates that significant seismic differences associated with fluid saturation changes should be observed even within a few years after first oil. An engineering study of the impact of early field-wide production data afforded by 40 seismic shows the potential to improve reservoir description by identification of by-passed oil volumes. This can result in improved reservoir simulation models and performance prediction, reduced probability of dry holes, and reduced operating cost through more efficient injection/production strategies.

Seismic monitoring is a maturing technology and its impact on reservoir management is far from proven. As with the development of 3D seismic technology, industry experience through case studies will establish the costs and benefits of 40 seismic technology.



About the Author(s)

David H. Johnston is a Senior Research Specialist for the Exxon Production Research Company (EPR) in Houston, Texas. He received a BS degree in Earth Sciences from the Massachusetts Institute of Technology in 1973 and a PhD. in Geophysics in 1978, also from MIT. He joined EPR in 1979 and has held assignments in rock physics research and seismic reservoir characterization. He is currently group leader for time-lapse seismic research and is responsible for the development and worldwide application of the technology.

Dr. Johnston is active within the Society of Exploration Geophysicists (SEG) and the Society of Petroleum Engineers (SPE). He was Secretary/Treasurer of the SEG in 1990, Chairman of the Development and Production Geophysics Committee from 1987 to 1988, and Chairman of the Interpretation Committee from 1991 to 1992. He has served on SEG, SPE, and OTC technical program committees.

In addition to a number of published papers in Geophysics and other technical journals, Dr. Johnston was co-editor of the book Reservoir Geophysics, published by the SEG in 1992 and co-editor of the SEG Reprint Series volume on Seismic Wave Attenuation published in 1981. He has presented numerous papers on rock physics and reservoir geophysics including keynote addresses at several conferences. Dr. Johnston was awarded the Best Presentation by the SEG in 1993 and was an SPE Distinguished Lecturer from 1992 to 1993.



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