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Two seismic surveys acquired over South Timbalier Block 295 field (offshore Louisiana) record significant differences in amplitude that are correlated to hydrocarbon production at multiple reservoir levels. The K8 sand, a solution‐gas‐drive reservoir, shows increases in seismic amplitude associated with gas exsolution. The K40 sand, a water‐drive reservoir, shows decreases in seismic amplitude associated with increases in water saturation. A methodology is presented to optimize the correlation between two seismic surveys after they have been individually processed (poststack) This methodology includes rebinning, crosscorrelation, band‐pass filtering, and cross‐equalization. A statistical approach is developed to characterize the correlation between the seismic surveys. This statistical analysis is used to discriminate seismic amplitude differences that record change in rock and fluid properties from those that could be the result of miscorrelation of the seismic data. Time‐lapse seismic analysis provides an important new approach to imaging hydrocarbon production; it may be used to improve reservoir characterization and guide production decisions.

Abstract Time-lapse seismic analysis has been applied to two 3-D seismic surveys acquired over the Central North Sea Fulmar Field -- a pre-production survey shot in 1977, reprocessed in 1987, and a 1992 survey. The Upper Jurassic reservoirs in the field have been under production since 1982. Water is the main drive mechanism, supported by flank injection. Although the field is currently at over 80% water cut, there are infill opportunities. Petrophysical analyses for Fulmar indicate that water replacing oil will result in an increase in seismic impedance. In addition, a pressure decline of about 1000 psi during the time between the two seismic surveys will result in a further impedance increase. These impedance changes are observed between the two seismic surveys. In order to overcome inherent differences in the seismic data due to acquisition and processing differences, the data are equalized and then inverted to obtain impedance which is then averaged between the top of the reservoir and the position of the original oil-water contact. Differences in averaged impedance between the 1977 and 1992 surveys clearly show the effects of water influx and pressure decline. The changes observed in the seismic data are overall consistent with predictions obtained from a full-field, history-matched flow simulation. Differences in details may suggest areas of bypassed oil. However, data quality is not sufficient to serve as the sole basis for drilling decisions. Introduction In the later phases of a field's life, reservoir surveillance is a key to meeting goals of reduced operating costs and maximized recovery. Differences between actual and predicted performance are typically used to update the geological model of the reservoir and to revise the depletion strategy. The changes in reservoir fluid saturation, pressure, and temperature that occur during production also induce changes in the reservoir acoustic properties of rocks that may be detected by seismic methods under favorable conditions. The key to seismic surveillance is the concept of differential imaging using time-lapse measurements. While one seismic image of a reservoir may not show any obvious production- related effects, differences in repeated surveys may be able to detect even subtle changes in reservoir properties. Acquisition of a seismic survey before production or intervention establishes the baseline conditions of the reservoir. Subsequent monitor surveys are differenced from the base survey. The result is a seismic difference volume which, when integrated with reservoir characterization and flow simulation, may be used to track the movement of fluid in a reservoir between well control. However, the difference between two seismic surveys is not only sensitive to changes in reservoir rock properties but is also sensitive to differences in acquisition and processing, and errors in navigation. As a result, the repeatability of seismic data is a key issue. For legacy seismic data, differencing the horizon-keyed average of attributes such as impedance is more robust in the presence of noise and data artifacts. The Fulmar Field The Fulmar Field lies in the Central North Sea approximately 270 km southeast of Aberdeen. The field was discovered in 1975 and is between 9900 and 11000 feet TVSS. It consists of an eroded triangular anticline (Figure 1) with a relatively small areal extent.

Abstract We have imaged 4D seismic amplitude and impedance differences between 3D seismic surveys conducted in 1988, prior to production, and in 1994, when about half of the recoverable hydrocarbons had been produced, to attempt to quantify the variations in fluid saturations with time within turbidite reservoirs in a Gulf of Mexico oil field. The mission of this 4D seismic monitoring project was to develop the software tools and interpretation techniques 1) to isolate and interpret seismicchanges that have occurred in the field over time in terms of oil/gas/water changes in order to better understand the drainage of the field, and 2) to identify and locate bypassed pay. Two turbidite reservoirs of the South Timbalier 295 field, offshore Louisiana, Gulf of Mexico, provide contrasts in acoustic response that point to important lessons for 4D monitoring in other fields of the Gulf of Mexico. In the K-40reservoir, a "classic" updip water sweep pattern in the oil/water contact with time was deduced from the observation of the dimming of seismic amplitudes over time in this vigorous water-drive reservoir. A "finger" of dimmed seismic amplitudes that breaks updip of even the structurally highest perforations was observed between two of the producing wells. This finger may be related to sand quality and permeability pathways and/or to acoustic shadowing from brightening that occurred within the K-8/16 reservoir directly above. The K-40 sand is two-lobed, and our region growing analysis of 4D seismic changes suggests that water had migrated farther updip in the lower than in the upper lobe by 1994. In the K-8 reservoir sequence, complex depositional channeling appears to have isolated the sand from the regional aquifer system to produce a gas depletion drive reservoir. Volumetric region-growing about high seismic amplitude "seed" pointsproved very successful in mapping the turbidite fairways, but not in isolating the K-8 from the immediately underlying K-16 sand. Seismic differences between 1988 and 1994 indicate brightening over time occurred in the K-8 sand fairways, which is thought to be associated with increased exsolution of gas. A marked increase in GOR was observed between the times of the two seismic surveys in producing wells from the K-8 reservoir. Introduction The interpretation of drainage patterns and the tracking of the migration of oil, gas and water fronts in 4D, that is volumetrically with time, are valuable optimization tools for the economic development of producing oil and gas fields1. However, current production technology is predominantly 2D. Even when a 3D seismic survey is used, 2D map-based, interpretation "horizons" are derived and used by geologists, geophysicistsand, reservoir engineers, to plan and execute production decisions in virtually all currently active oil and gas fields. This process relies upon the accumulated experience-base of these integrated teams that use seismic, logging, pressure monitoring, and production histories to determine how oil, gas, and water move within reservoirs as production proceeds.

Reservoir and production characteristics of the K40 sand (South Timbalier Block 295, offshore Louisiana) are used to track the oil-water contact as it moved vertically 80 m between 1988 and 1994. This zone of water sweep is associated with a strong decrease in seismic amplitudes observed from comparison of 3-D (three-dimensional) seismic curves acquired before hydrocarbon production (1988) and during production (1994). The Pliocene K40 sand is an overpressured (0.80 psi/ft) turbidite reservoir deposited in a slope minibasin. Wireline and seismic data are used to develop a geologic model for this reservoir. This analysis, combined with production history and log data, indicates that relatively uniform water sweep was effectively imaged by time-lapse (4-D) seismic over most of the reservoir. The lack of seismic dimming in some parts of the reservoir is attributed to poor drainage of low-permeability lithofacies. In addition, it may not be possible to image drainage of reservoir zones with less than 10 m of original net pay with these data. These results illustrate the potential of time-lapse seismic analysis for illuminating the dynamic behavior of producing reservoirs and indicate that preproduction seismic surveys, not originally intended for use in time-lapse (4-D) seismic analysis, have value as baselines for seismic monitoring studies.