|dc.description.abstract||The main concern in the monitoring of gas injection, exsolution and dissolution is the exact spatial distribution of the gas volumes in the subsurface. In principle, this concern is addressed by the use of 4D seismic data. However, it is recognised that the seismic response still largely provides a qualitative estimate of the moved subsurface fluids; exact quantitative evaluation of fluid distributions and associated saturations remains a challenge still to be solved. It is widely believed that a few percent of gas makes the pore fluid mixture very compressible, so that it cannot be distinguished from a more complete gas saturation using seismic techniques. However, because of the fact that a gas distribution viewed at the reservoir scale is distinctly different from that observed at the laboratory scale, conclusions from laboratory measurements may not, in fact, be wholly applicable. Indeed, it is found in this study that the main factor controlling the seismic response is gas thickness, whilst gas saturation per se remains approximately constant. Modelling studies show that, for thin reservoirs (less than tuning thickness), both timeshift and amplitude change attributes have a linear trend with gas volume. In theory, this conclusion does not apply to thick reservoirs, as the amplitude change then becomes non-linear. However, because thick reservoirs are normally combinations of intra reservoir sand and shale, it is anticipated that a linear amplitude response can still be expected in most reservoirs. Reservoir heterogeneity is observed to affect these results by less than 2%. In the modeling, a spurious deviation from linearity is evident with increasing simulation model cell size (especially the vertical dimension). The understanding above is applied to both timeshift and amplitude change attributes in a North Sea gas injection field. Here, seismic scale calibration coefficients are obtained by a volumetric method which aims to calculate gas volume maps using the 4D seismic attributes. The work reveals that the results from the two mapped attributes appear reasonably close but still have regions of disparity. Synthetic data based on the reservoir model and further analysis of the observed data have been able to replicate some of these differences and identify them as due to inter-layer wave interferences and 4D noise.
Similar findings to the above also apply to gas exsolution, in which gas migrates after arriving at the critical gas saturation, and establishes two specific gas saturations in the
reservoir: maximum gas saturation within the gas cap and critical or minimum gas saturation within the oil leg. On the other hand, for the reverse process, in which reservoir pressure builds up, it is noted that it is not only the fluid type that impacts the gas when it goes back into solution, but also other reservoir properties such as relative permeability curves, transmissibility, Kv/Kh, and the injection/production plan. The laboratory-proposed equations for calculation of solution gas oil ratio (Rs) and pressure dependency of the fluid and rock are found to be not directly valid in cases in which the reservoir pressure drops below the bubble point pressure. In this situation, gas evolves, migrates and alters the pressure dependency of the saturated rock and solution gas oil ratio. A compositional change of the gas and oil is found to occur with pressure drop. However, it is observed to have a negligible impact on the seismic domain. Finally, importance is drawn to the role of engineering principles when interpreting dynamic reservoir changes from 4D seismic data. In particular, it is found that, in clastic reservoirs, the principal parameters controlling mapped 4D signatures are not the pressure and saturation changes per se, but these changes scaled by the corresponding thickness (or pore volume) of the reservoir volume that these effects occupy. This understanding is validated both with numerical modelling and analytic calculation. This provides a basis for a linear equation that can readily and accurately be used to invert for pressure and saturation changes. The observed seismic data are then inverted for pressure and saturation changes using the principles above. The results show that the simulator does appear to predict the inverted seismic observations fairly accurately. However, there are also some noticeable differences which require some specific updates to the transmissibility multipliers (and hence barriers) and the net-to-gross distribution in the simulation model. This project reveals the ability of 4D seismic to quantitatively monitor the gas injection and exsolution, and highlights the fact that laboratory measures are not directly applicable at the reservoir scale. It can be concluded that the impact of the reservoir scale phenomena needs to be taken into account during time-lapse seismic interpretations.||en_US