In some hydrocarbon reservoirs, severe compaction of the reservoir rocks is observed. This compaction is caused by production, and it is often associated with changes in the overburden. Time‐lapse (or 4D) seismic data are used to monitor this compaction process. Since the compaction causes changes in both layer thickness and seismic velocities, it is crucial to distinguish between the two effects. Two new seismic methods for monitoring compacting reservoirs are introduced, one based on measured seismic prestack traveltime changes, and the other based on poststack traveltime and amplitude changes. In contrast to earlier methods, these methods do not require additional empirical relationships, such as, for instance, a velocity‐porosity relationship. The uncertainties in estimates for compaction and velocity change are expressed in terms of errors in the traveltime and amplitude measurements. These errors are directly related to the quality and repeatability of time‐lapse seismic data. For a reservoir at 3000‐m depth with 9 m of compaction, and assuming a 4D timeshift error of 0.5 ms at near offset and 2 ms at far offset, we find relative uncertainty in the compaction estimate of approximately 50–60% using traveltime information only.

Time-lapse (4D) seismic monitoring of pressure-induced changes in depleting gas fields reveals that detectable differences in seismic arrival times are observed above the reservoir interval. Geomechanical models of depleting reservoirs predict that as a result of reservoir compaction due to pressure depletion, changes in the long-wavelength stress and strain fields occur in the rocks bounding the reservoir. Models incorporating the geomechanical stress and strain field changes predict changes in the two-way arrival times that are compared with actual time-shift observations at a depleting gas field in the North Sea. The geomechanical-based predictions are in good agreement with the observations. Detecting geomechanical changes in the over-and underburden rocks opens up new ways of using 4D data, especially in places where the signal from the reservoir rocks is small.

A B S T R A C TIn the Southern Gas Basin (SGB) of the North Sea there are many mature gas fields where time-lapse monitoring could be very beneficial in extending production life. However, the conditions are not immediately attractive for time-lapse seismic assessment. This is primarily because the main production effect to be assessed is a pore pressure reduction and frame stiffening because of gas production in tight sandstone reservoirs that also have no real seismic direct hydrocarbon indicators. Modelling, based on laboratory measurements, has shown that such an effect would be small and difficult to detect in seismic data. This paper makes two main contributions. Firstly, this is, to our knowledge, the first time-lapse study in the SGB and involves a real-data assessment of the viability for detecting production in such an environment. Secondly, the feasibility of using markedly different legacies of data in such a study is addressed, including an assessment of the factors influencing the crossmatching. From the latter, it is found that significant, spatially varying time shifts need to be, and are successfully, resolved through 3-D warping. After the warping, the primary factors limiting the crossmatching appear to be residual local phase variations, possibly induced by the differing migration strategies, structure, reverberations and different coherencies of the volumes, caused by differences in acquisition-structure azimuth and acquisition fold. Despite these differences, a time-lapse amplitude signature is observed that is attributable to production. The character of the 4-D amplitude anomalies may also indicate variations in stress sensitivity, e.g. because of zones of fracturing. Additionally, warping-derived time attributes have been highlighted as a potential additional avenue for detection of pressure depletion in such reservoirs. Although the effects are subtle, they may indicate changes in stress/pressure in and around the reservoir because of production. However, to fully resolve the subtle time-lapse effects in such a reservoir, the data differences need to be better addressed, which may be possible by full re-processing and pre-stack analysis, but more likely dedicated 4-D acquisition would be required.

Standards for 4D seismic feasibility estimation and interpretation aim to simplify the 4D seismic interpretation process, facilitate understanding of results, and accelerate learning between projects and between disciplines. Standards encode those best practices that have proved to have a more or less universal relevance in the subject area and provide a convenient starting point for individuals and teams new to 4D interpretation. Standards are about casting a result into a familiar format. The main result is a quality improvement of the integration process between different disciplines; a side effect is the efficiency improvement and time saving from increased skill levels within each discipline. There are currently accepted 4D standards in the fields of F = 4D feasibility (fluid effects) P = poststack processing I = seismic inversion and 4D A = 4D interpretation and attributes S = simulator-to-seismic The primary user group is subsurface professionals in asset teams, in particular reservoir engineers, geologists, and geophysicists. Although 4D seismic is seen as a tool originating in the geophysical domain, the fact that it is about observing reservoir dynamics makes it of primary interest to reservoir engineers and geologists alike.