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Different gel systems have been extensively used to reduce unwanted water production and improve overall hydrocarbon productivity in many reservoirs. The main target for gel placement is to reduce channeling through fractures or highpermeability zones, while redirecting flow to less permeable unswept zones (1) . It is a common fact that many water based gels feature disproportionate permeability reduction (DPR) effect, resulting in significantly higher reduction in permeability to water compared to that of oil. This phenomenon has been widely investigated in sandstone porous media; however there is a lack of information available on gel performance in carbonate porous media. The main objective of this study is to verify the presence and extent of DPR effect when placing gels in carbonate porous medium. High molecular weight polyacrylamide and two crosslinkers, chromium(III)-acetate and chromium(III)-chloride, were used as main components of gel system. A series of brine and oil injections were performed to examine performance of gel, its stability and its contribution to DPR in carbonate porous medium. The effect of residual oil saturation was also studied by conducting experiments with and without residual oil present prior to gel placement. Gel stability study was carried out by subjecting gel to different pressure gradients under applied range of flow rates. The obtained results clearly indicate effectiveness of water based gel application to significantly reduce permeability to water in carbonate rock, as well as verifying DPR phenomenon in carbonate porous medium.

Petroleum reservoirs demonstrate a very complex behavior that changes with time in a non-linear manner. Application of neural networks for field-wise analysis of waterflooding projects is very appropriate because a structural model between injection and production does not need to be specified in order to predict performance. The neural network approach recognizes that individual well behavior may depend on the well history and the injection/production conditions of surrounding wells. The outcome of this neural network analysis could determine injection and production policies that would lead to determining the minimum injection water leading to maximum oil recovery.

For waterflooding in argillaceous reservoirs, the injection water needs to be carefully designed to avoid formation damage by clay swelling and migration. Common methods of achieving this are compatibility tests of injection water with formation water and rocks and injectivity tests. However, such tests are often not practical nor even possible due to the limited availability and prohibitive cost of obtaining actual reservoir cores. The objective of this work was to develop a cost-effective method to evaluate injectivity that does not require the use of reservoir core. In this study, a novel coreless injectivity method was developed and validated. The method utilizes field-produced drill cuttings to make synthetic core plugs, which are universally available during well drilling and commonly considered as waste. A specially designed cleaning process was performed for the drill cuttings. They were then wet compressed with a high-pressure hydraulic press and dried in a constant-humidity oven to make core plugs with standard dimensions. Drill cutting plugs prepared in this way can then be used for injectivity tests as an alternative to actual reservoir core plugs. The routine core analysis revealed that, although sedimentary structures were lost, the drill cutting plugs preserved the mineralogy and maintained comparable porosity and permeability to the reservoir plugs. To validate the representativeness of the formation damage tendencies of the drill cutting plugs, water injectivity tests were carried out on both preserved reservoir cores and compressed drill cutting cores, using simulated injection water with successively lower salinities. The results showed that injectivity loss as indicated by increasing pressure drop was consistent with both types of cores. The "coreless injectivity evaluation" technique can be applied for argillaceous reservoirs with formation damage concerns. It is a cost-effective and viable technique for evaluating water injectivity when reservoir cores are unavailable.

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