The marginal or questionably productive nature of some hydrocarbon-bearing zones can be due to clays distributed within rock pores in a manner adversely affecting fluid flow. This research involves laboratory measurement of several clay rheological properties that are not commonly used in evaluating hydrocarbon-bearing reservoirs. Liquid, plastic, and shrinkage limits and plasticity indexes of a kaolinite, bentonite, and an illite are being determined using fresh water, salt water, methanol, xylene, and a non-ionic wetting compound as the moisture components.

Conclusions about the relative merits of each liquid as an oil-recovery enhancer may be drawn directly from the results of their effects on the plastic behavior, or indirectly when these results are applied in conjunction with other data concerning the rate of flow of reservoir fluids in the intergranular environment. When the liquid limit of attached clay particles is exceeded by the introduction of a stimulation fluid, they presumably become transient and change into a blocking phase. An attached clay can be induced to deform into new configurations that alter tortuosity if its plastic limit is exceeded. Differing ranges for the plasticity index would be expected to indicate preferential hydrofracture or stimulation fluids for certain reservoirs depending on type, position, and atta hment status of the associated clays.

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