Today, geostatistical reservoir characterization from 3D seismic volumes provides most static descriptions for reservoir models. These models can be improved by integrating the dynamic data in the reservoir description process. 3-D time-lapse seismic surveys have been proposed to relate time dependent-changes in seismic attributes to the flow processes in the reservoir. This paper presents a new approach to reservoir characterization by integrating time-lapse seismic and production data. The issues involved in the integration will be examined. A case study was conducted over a turbidite sheet sand reservoir in the Gulf of Mexico. Seismic data from the base survey were combined with log and production data to build an initial reservoir model which was run forward to the time of a second monitor seismic survey. Dynamic history matching by a simulated annealing type of optimization further improved the model. The output from this simulation was then converted to a synthetic monitor seismic survey using Gassmann's equations and a simple convolutional approach. A quantitative combined seismic and production history-matching methodology was then tested. It constrains the modeling process to match the production history and simultaneously minimize the differences between the synthetic and real 3-D seismic time-lapse data. This new systematic approach provides us with a quantitative time-lapse seismic analysis and reservoir characterization tool which has the potential to improve reservoir management. Introduction Once an oil reservoir has been found and is being produced, it is important to understand the movement of the fluid which is related to the flow mechanism and the reservoir heterogeneity. Recently, 3D seismic data have been used successfully to improve reservoir characterization by extraction of reservoir parameters using inversion, geostatistics and petrophysics to understand the coupling of seismic and rock properties. More than 10 years ago, laboratory work demonstrated that different fluid substitutions can cause acoustic changes, and time-lapse seismic was proposed to capture the changes in reservoir properties with time. These mostly qualitative studies showed that time-lapse seismic even on legacy data resulted in a better understanding of the production behavior of the reservoir. Time-lapse seismic data are mainly used for monitoring of the fluid movement in the reservoir. By integrating other data, they can provide another avenue for reservoir characterization not only including the fluid movement but also other reservoir properties. The following sections document a case study on a turbidite sheet sand reservoir in the Gulf of Mexico where 3-D time-lapse seismic data were integrated with production data from three wells over five years to characterize the reservoir by optimization, and time lapse seismic data were used to validate a seismic history matching methodology. Background This study uses two volumes of "off-the-shelf" data for timelapse seismic analysis. The base 3D seismic volume was acquired in 1988 before the production of the reservoir, while the monitor 3D seismic volume was acquired in 1994 after more than 5 years of production. The difference in orientation of the two surveys was small. The acquisition parameters were different for the two volumes. The base survey was reprocessed to improve the imaging part of the processing sequence to match the 1994 processing sequence more closely. Both volumes were processed through deterministic and adaptive deconvolution, 3-D dip move out and one-pass 3-D migration. The monitor volume was interpolated to smaller bins before migration. The limitations in using "off-the-shelf" data are well known and were recently discussed by Beasley et al., 1996. Since the focus of the present study is to demonstrate an improved seismic history matching methodology, it was decided to use legacy data rather than data reprocessed from field tapes to minimize differences. The accuracy of the results is expected to improve when using carefully reprocessed data sets. The case study was conducted over a sheet sand reservoir in the Gulf of Mexico, offshore Lousiana. The sand is of Pliocene age and pinches out onto a salt-related structural high that controlled its deposition. The average porosity is about 31 % and its permeability is about 500 md. P. 439^

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Seven hundred thirty-nine workers at Merck's Stonewall plant in Elkton, Virginia, have a safer and healthier workplace because four of them were enthusiastic about health and safety training they received from the union's training center in Cincinnati, Ohio. What emerged was not only that all 739 plant employees received OSHA 10-hour General Industry training, but that it was delivered by “OSHA-authorized” members of the International Chemical Workers Union Council who worked at the plant. Merck created a new fulltime position in its Learning and Development Department and hired one of the four workers who had received the initial training. Strong plant leadership promoted discussions both during the training, in evaluation, and in newly energized joint labor-management meetings following the training. These discussions identified safety and health issues needing attention. Then, in a new spirit of trust and collaboration, major improvements occurred.

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In general only a single 3D seismic data set is used for the characterization of the static properties of a reservoir, even though these static properties could be integrated with dynamic properties. But sometimes, more than one 3D seismic data volume has been acquired over the same field after the production starts. We propose to use these additional data not only to understand the dynamic properties of the reservoir using a time-lapse seismic analysis as presented last year, but to improve the accuracy of the initial reservoir description and study its sensitivity to the input data during the optimization process. Using two 3D seismic data sets acquired over a field in the Gulf of Mexico, this paper demonstrates a method to improve the porosity map obtained from the geostatistical characterization of the base 3D seismic data set by an analysis of the second 3D data volume. It is not possible using just the base data to differentiate factors such as fluid content and pressure from the geostatistical porosity characterization. But by using the flow information from the wells and the second 3D seismic data which was acquired after the production started, it is possible to decouple the porosity, fluid contents and even pressure. Consequently, it provides a more representative porosity characterization compared to using a single 3D seismic data set. The relative permeability curves are optimized by comparing actual time-lapse seismic and production data to synthetic ones generated with a Gassmann rock physics model. P. 527