Excessive water production is an enduring problem in the oil industry that has always been an unbearable burden on the environment and a great damage to the ultimate oil recovery. Gel treatment has been routinely used for decreasing water production. Disproportionate permeability reduction (DPR) is a natural phenomenon in some polymer gels that can reduce the permeability to water more than to oil. The conformance improvement treatments with DPR can effectively reduce the water cut without substantially reducing the oil productivity in fractured reservoirs. At present, there are no widely accepted mechanisms of oil-phase permeability development and DPR. In this paper, nuclear magnetic resonance is applied to study the mechanisms of oil-phase permeability development, DPR, and permeability influence by scanning different core samples treated with Cr­(III)–acetate–hydrolyzed polyacrylamide polymer gels. Results show that the permeability difference leads to a certain alteration in NMR T2 curves, but final conclusions for the mechanisms are consistent. For the mechanism of oil-phase permeability development, initially, gel displacement in large pores accounts for the oil permeability development, after which the gel dehydration becomes the main mechanism. The mechanisms for DPR include the blocking of flow channels by gel rehydration and residual oil and the low permeability of gel relative to water. The results can be used to optimize the utility of polymer gels with a DPR property.

Spontaneous imbibition is a critical mechanism for the development of water-wet fractured reservoirs. In order to improve the ultimate oil recovery, it is important to understand the change of in situ oil saturation during the spontaneous imbibition process. In this study, spontaneous imbibition experiments of two ends open (TEO) are conducted using unconsolidated sand packs. The sand packs are filled with quartz sands of three different particle sizes respectively and are fully oil-saturated. Nuclear magnetic resonance (NMR) T2 is used to monitor the saturation development behind spontaneous imbibition front. For porous media of the same lithology, the imbibition speed and final oil recovery decline with the reduction of average pore size. As the imbibition front constantly moves forward, the change of oil saturation behind the imbibition front does exist, and the major decrease of oil saturation happens in the large pore space. In terms of a particular region behind the spontaneous imbibition front, with the progression of the front, the oil saturation gradient in the area declines. Specifically, the dramatic gradient descent occurs when the spontaneous imbibition front just passes by. The smaller the average pore size is (the larger the mesh of sand is), the more rapid the saturation changes behind imbibition front. For porous media of small pore size, even when the imbibition front has moved far away, oil saturation still changes a lot.

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