Some of the Middle East fields are approaching their final stage of primary production. Most of these fields are highly fractured and carbonate in nature. One major problem is the creation of gas and water invaded zones during the history of production form such fields. Hence, the implementation of proper EOR process requires an extensive laboratory work and simulation studies. A mature field with more than six decades of production has been considered in this study to explore all possible EOR methods. Several EOR processes such as continuous gas injection (GI), WAG (water alternative gas flooding), SWAG (simultaneous WAG), FAWAG (Foam Assisted WAG), and GAGD (Gas Assisted Gravity Drainage) process were studied in laboratory scale and simulation work. The Gas injection and GAGD were found to be unfeasible due the high fracture frequency and early gas breakthrough even with low rate of injection. However, the WAG, SWAG and FWAG were found to be more feasible. This is possibly due to mobility modification by water phase. During SWAG method all pores displaced at the same time, so that a higher ultimate recovery factor achieved sooner in comparison with WAG process. In order to have better recovery for the residual oil, FAWAG method was applied to control the injectivity of injected gas and reduce the interfacial tension (IFT) between residual oil and rock. Surfactant was chosen in different concentration of 5000, 2000, 1000, and 500 ppm. All experiments were carried out under reservoir condition. The FAWAG process was found to be more suitable process for such reservoirs due to its high recovery. Finally the simulation study was conducted with different patterns of injection and production for all the mentioned EOR scenarios. It was found that the fractures density had an important role in the selection of the optimum pattern.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPrecise and accurate characterization of a reservoir fluid is a very important factor in reservoir simulation studies. PVT experiments are usually expensive and performed in limited conditions. Therefore Computer EOS based PVT packages are used widely for the prediction and evaluation of fluid properties at reservoir, well and surface conditions over a wide range of temperature, pressure and composition 1,2,3,4 . In this work different PVT packages that are available in National Iranian Oil Company (NIOC) have been used to complete fluid analysis and experiment simulation of an Iranian oil reservoir and PVT model preparation for the reservoir simulators. This reservoir is a medium size, highly fractured carbonate reservoir located in southwest of Iran. The carbonate formation has dense matrix with improved permeability by presence of fracture network. This reservoir was initially highly undersaturated and after 5 years of oil production the oil pressure reached to the saturation pressure and gas injection was started into the reservoir 5 .In this work different equation of states, different regression methods and correlations were analyzed for the prediction of fluid properties. Considering the results of this work in general good agreement was obtained for the experimental and calculated data for used packages. However, the method used for tuning the equation of states is critical in getting good agreement.
CO 2 injection and storage in deepwater sediments under water depths greater than 9,000 feet (≈2,750 meters) where high pressures and low temperatures result in the CO 2 being denser than seawater and therefore being buoyantly trapped in the sediments pore-fluid, could provide an attractive sequestration option for countries and regions densely populated and emitting large quantities of anthropogenic CO 2 such as East and West Coasts of the United States of America, Japan, the East Coast of China and Western Europe. In these places, public opinion, government regulatory agencies, a lack of space for CO 2 injection sites and few depleted oil and gas fields available necessitate the application of alternative technologies to sequester CO 2 in order to mitigate a significant part of the 30 billion tons of CO 2 annually released in the Earth's atmosphere. This paper presents the results of multiple reservoir simulations and parametric studies for different types of deepwater sediments located in various regions of the globe (Pacific Ocean, Atlantic Ocean, Japan Sea and Gulf of Mexico). Since not all regions and sediments deposited below 9,000 feet of ocean waters seem to be viable to permanently store CO 2 , this study focuses on the critical parameters that need to be considered to successfully inject and permanently store liquid CO 2 in deepwater sub-seabed sediments.In fact, when injecting liquid CO 2 through an ultra-deepwater conduit (injection pressurized riser) within the first few hundreds of sediments, several uncertain variables such as temperature, sediment type, sediment thickness, permeability, porosity and CO 2 injectability greatly influence the overall integrity of the buoyant trap. Very long-time reservoir simulations (e.g. 250 years) have been used to assess the effects of different decision and uncertain variables on the behavior and the evolution of the CO 2 plume within the sediments. Also, experimental design and response surface methodologies have been used to quantify the risk associated with each of the critical parameters and to determine the optimal conditions for deepwater sediments CO 2 storage. Finally, the essential findings of the paper provide the offshore and carbon sequestration industries with a high-level mapping of the world's oceans and deep seas best candidates for CO 2 storage in deepwater sediments.
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