TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractReservoir simulation has become the industry standard for reservoir management. It is now used in all phases of field development in the oil and gas industry. The full field reservoir models that have become the major source of information and prediction for decision making are continuously updated and major fields now have several versions of their model with each new version being a major improvement over the previous one. The newer versions have the latest information (geologic, geophysical and petrophysical measurements, interpretations and calculations based on new logs, seismic data, injection and productions, etc.) incorporated in them along with adjustments that usually are the result of single-well or multi-well history matching. A typical reservoir model consists of hundreds of thousands and in many cases millions of grid blocks. As the size of the reservoir models grow the time required for each run increases. Schemes such as grid computing and parallel processing helps to a certain degree but cannot close the gap that exists between simulation runs and real-time processing. On the other hand with the new push for smart fields (a.k.a. ifields) in the industry that is a natural growth of smart completions and smart wells, the need for being able to process information in real time becomes more pronounced. Surrogate Reservoir Models (SRMs) are the natural solution to address this necessity. SRMs are prototypes of the full field models that can run in fractions of a second rather than in hours or days. They mimic the capabilities of a full field model with high accuracy. These models can be developed regularly (as new versions of the full field models become available) off-line and can be put online for automatic history matching and real-time processing that can guide important decisions. SRMs can efficiently be used for real-time optimization, real-time decision making as well as analysis under uncertain conditions. This paper presents a unified approach for development of SRMs using the state-of-the-art in intelligent systems techniques. An example for developing an SRM for a giant oil field in the Middle East is presented and the results of the analysis using the SRM for this field is discussed. In this example application SRM is used in order to analyze the impact of the uncertainties associated with several input parameters into the full field model.

TX 75083-3836, U.S.A., fax 01-972-952-9435.

Time-lapse or ‘4D’ seismic has been used to directly monitor the fluid movements in some oil- and gas-reservoirs. This technique allows one to verify and where necessary to update the reservoir flow models, e.g. to incorporate ‘geological surprises’ like unexpected flow barriers or conduits. The method is based on the change of the acoustic properties (velocity, density) of the reservoir when the initial reservoir fluid in place (oil, gas, brine) is replaced by others while the reservoir is produced. Under favourable conditions this change in properties leads to a detectable change in the seismic reflection. Successes of 4D seismic have been reported, mostly from clastic reservoirs located offshore and onshore heavy-oil/tar sands reservoirs. In such reservoirs the change in seismic response with changes in reservoir fluid is relatively large. Direct hydrocarbon indicators, AVO and bright spots often work well in these reservoir types. Furthermore the good quality of modern 3D marine seismic data allows one to reliably detect these changes in many offshore cases. For the large onshore oil fields produced by ADCO, the situation is more challenging. The main reservoirs are formed by fairly hard carbonates; they are reasonably deep and consist of several thin zones with quite different flow properties due to variable porosity, permeability and fracturing. The surface is covered by sand dunes, which severely hamper the recording of high quality recorded seismic data. Some oil fields have been producing for more than 30 years and have been penetrated by several hundreds of wells, including infill horizontal drilling. However, the reservoir behaviour is still not fully predictable and sometimes wells do not perform as expected. With extensive use of water-injection for production support and gas-injection programs scheduled, a further calibration and refinement of the reservoir models would be quite welcome. The recent improvements in the quality of 3D seismic data seen in Abu Dhabi could enable the successful application of 4D seismic (and its associated benefits) for these fields. For this reason ADCO and its shareholders have carried out a feasibility study into the possibility of using 4D seismic for the seismic monitoring of several production scenarios for one of their main fields. Over this field a high-spec 96-fold 3D seismic survey was acquired during 1997 and 1998 for structural mapping. If the feasibility study were sufficiently encouraging, this survey would act as a base case for future follow-up 4D surveys at appropriate times covering areas of specific interest. The feasibility study followed a phased approach integrating several disciplines, with the results of one part being used for the other.seismic properties as a function of reservoir rock properties and fluid content were derived from well logs and models;reservoir simulations were run for several production scenarios, to compute in detail the expected fluid distribution profiles over time;from these fluid profiles and the static model rock properties, synthetic seismic response histories were computed representing sequential 4D's;a seismic noise analysis and a 3D seismic repeatability test were carried out to estimate the real-life seismic noise levels;finally these results were integrated to find out which production effects would be detectable with the measured noise. These cases should be detectable by a future time-lapse survey.

Summary Secondary- and tertiary-recovery processes based on gas injection can extend the life of waterflooded reservoirs by maximizing the oil recovery. However, the injection strategy needs to be studied carefully to optimize the overall sweep efficiency. In particular, the impact of possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection, and a simultaneous water-alternating-gas (SWAG) injection. The experiments were carried out on composite cores consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were monitored continually during the hydrocarbon recovery, including the chromatographic analysis of the produced gas. The final oil recovery resulting from the three types of experiments was very good [approximately 90% original oil in place (OOIP) at surface conditions after 6 pore-volume (PV) injection] and quite similar within the expected experimental error, regardless of the sequence of gas injection. The low remaining oil saturation (ROS) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Because of the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by mobility control of the water phase. This enhances the sweep efficiency by viscous drive. A water-blocking effect was found to be negligible because it could be anticipated due to wettability consideration. The influence of the fluid description (equation of state, or EOS) and the three-phase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained with both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with seven pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model (either "geometrical construction" or Stone1) on the results was found to be small. Introduction For enhanced oil recovery (EOR) purposes, miscible or immiscible hydrocarbon gas injections have been applied successfully in many oil reservoirs throughout the world (Thomas et al. 1994; Lee et al. 1988). Compared to water injection, gas injection is associated with higher microscopic displacement efficiency due to the low value of the interfacial tension (IFT) between the oil and gas phases. IFT tends toward zero when miscibility is reached, which means that the oil recovery can be total in the swept area. Even when miscibility is not reached, the mass-transfer mechanisms that occur between oil and gas phases lead to low IFT values when compared to waterflooding. Even under those conditions, regarding remaining oil-saturation values, gas injection appears to be an interesting recovery process.