Tests have been run on cores from a number of California oil-producing formations, which are potential candidates for Enhanced Oil Recovery (EOR) operations, to evaluate the effects of disturbing fluid/rock equilibrium by injecting EOR fluids. The fluid-flow capacity of reservoir rocks may be severely affected by introduction of foreign fluids. In addition, loss of injected chemicals to the rock by adsorption, ion exchange, and mineral dissolution and by reactions with formation brines, may minimize the effectiveness of the EOR fluid injection.

Many of the cores tested did show serious reduction in fluid-flow capacity upon changing the ionic content and/or concentration of the injected fluid. This reduction is attributed to mobilization of and subsequent plugging by formation fines. Ultra-fine mineral particles have been noted in the effluent from fluid-flow tests. Some cores from two Southern San Joaquin Valley fields (Kern Front and Midway-Sunset), showed anomalous behavior in this regard. These cores showed a reduction of the effluent pH to as low as 4.0 when neutral NaCl solution was injected. This pH reduction which lasts for many pore volumes (PV) of injection, is attributed to H+/Na+ exchange, releasing H+ into the flowing fluid. These cores, although mineralogically similar to other cores from the same formation and, in one case, from the same well, show no reduction in permeability regardless of the nature of the injected fluid.

Screening tests have been developed to identify those cores which do not show permeability reduction to fresh-water injection. Similar tests have also been developed to demonstrate the effectiveness of stabilizing agents (dilute AlCl3 solution in this work) in reducing the susceptibility of cores to permeability reduction.

You can access this article if you purchase or spend a download.