TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNew methods have been developed to initialise a compositional model for a giant Middle East reservoir where the initial H 2 S mol% varies laterally from close to 0 to around 20 and vertically from close to 0 to around 20, being highest at the lower parts of the reservoir.Conventional initialisation methods assume equilibrium, assigning the same composition to any grid block at a given depth. Two different new method, triangulation and surface-fit, are used to capture observed lateral nonequilibrium variations. Vertical variations in fluid composition are simulated using a gravity segregation model as in the conventional method. The nonequilibrium methods use data on the variation in fluid composition and pressure derived from 18 representative fluid samples collected from wells early in the field history.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNew methods have been developed to initialise a compositional model for a giant Middle East reservoir where the initial H 2 S mol% varies laterally from close to 0 to around 20 and vertically from close to 0 to around 20, being highest at the lower parts of the reservoir.Conventional initialisation methods assume equilibrium, assigning the same composition to any grid block at a given depth. Two different new method, triangulation and surface-fit, are used to capture observed lateral nonequilibrium variations. Vertical variations in fluid composition are simulated using a gravity segregation model as in the conventional method. The nonequilibrium methods use data on the variation in fluid composition and pressure derived from 18 representative fluid samples collected from wells early in the field history.

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Laboratory studies have been performed to evaluate the impact of acid gas (80% H2S, 20% CO2) and CO2 injection on the carbonate matrix properties at reservoir conditions. Injectivity abnormalities have been reported in the literature in several WAG projects involving CO2 and loss of injectivity has been crucial factor in many of these projects. However, literature data shows that some reservoirs loose injectivity and others increase injectivity after the first CO2 slug is injected. Change in rock properties due to fluid/rock interaction can account for some of the injectivity loss. In this paper we will report on recent laboratory study that was conducted using limestone and dolomite reservoir core samples from a carbonate reservoir in Abu Dhabi. The laboratory program used core plugs, or plug composites, that had been aged with reservoir oil at a representative initial water saturation prior to the gas displacement. The displacements were performed with three fluids: Vapor phase CO2Acid gas (80% H2S, 20% CO2)Brine saturated with CO2 The vapor phase CO2 and acid gas displacements were considered to be typical of those found near a gas injector, whereas the brine saturated with CO2 displacement was more representative of the reservoir away from the well bore or found during a WAG process. The displacements were conducted at a series of increasing rates. After 75 pore volumes the plug was left to soak for 48 hours in the displacing fluid. Two further displacements were then performed. Following the displacement tests, an assessment of damage to the core plug was made by measuring the porosity, permeability, SEM, XRD, MICP and taking thin sections of the core plug. This paper also presents laboratory work to study CO2 solubility in different brine salinities up to 250 K ppm at different reservoir temperatures up to 149 C and pressures up to 400 bar. A CO2 solubility model is proposed to calculate solubilities at representative salinity and previlent pressures and temperatures. The preliminary results show that in most of the experiments no significant change in permeability was observed. However, in some experiments both enhancement and decrease in permeability was reported. The results of this ongoing study will strongly impact the planning of EOR development options. Injection of CO2 or acid gas will be significantly hampered if the gas injection results in matrix plugging or core damage, and needs to be appropriately evaluated for the reservoir under consideration.

The presence of natural fracturing in the Thamama Reservoir was postulated following its discovery in 1958. The performance of this reservoir was poorly understood being based on information gathered from a small number of well tests executed during the 1960’s and 70’s. An up to date assessment of this reservoir was sought utilising the latest reservoir monitoring technology. The objective was to confirm the existence, magnitude and orientation of any fracturing in the Thamama reservoir. A further objective was to evaluate their distribution within the zones of the Thamama reservoir. The surveillance programme included multi-well interference testing, pressure build-up testing, production logging and water saturation monitoring. It was concluded from this study that there were many small vertical fractures, predominantly located in the dense limestone intervals, which gave rise to a strongly anisotropic reservoir transmissibility.