Two formation damage mechanisms that can cause severe permeability damage in friable micaceous sandstones during flow of neutral salt solutions are described. Laboratory flow studies on cores suggest that damage by these mechanisms is probably quite common and should be considered in all poorly, consolidated micaceous sands.
Permeability damage mechanisms involving clay Permeability damage mechanisms involving clay structural expansion and particle dispersion have been discussed previously. It has been shown that permeability damage by aqueous solutions usually can be permeability damage by aqueous solutions usually can be prevented in even very clayey sands by maintaining some prevented in even very clayey sands by maintaining some minimum amount of dissolved salt in the flowing solution. Gray and Rex showed that even distilled water can be flowed without significant damage if the clays previously are saturated with calcium ions.
Over the years, I have observed that some reservoir sands tend to lose permeability in laboratory flow studies during flow of salt solutions that normally prevent clay damage problems. This usually occurred in relatively recent sediments and most were fairly friable. The layered minerals in these young sediments are predominately mica with lesser amounts of montmorillonite, predominately mica with lesser amounts of montmorillonite, kaolinite and chlorite. Several authors have reported on the mechanism of potassium release by micaceous minerals and the effects of potassium extract on the properties of mica. Based on these reports and recent properties of mica. Based on these reports and recent laboratory studies, I propose two mechanisms to account for at least some of the permeability damage observed in such friable micaceous sands.
The objectives of this paper are to describe the proposed damage mechanisms and to present laboratory and proposed damage mechanisms and to present laboratory and field data supporting them.
Reservoir sandstone samples from several Southern California oil fields were used in the study. The sands were chosen on the basis of their mica content, friability, and observed permeability damage from flowing salt solutions. The mineralogical composition of single samples of reservoir sand from the five oil fields included in the study are shown in Table 1. The compositions as determined by X-ray diffraction are typical for Los Angeles Basin Miocene sands. Small cores about 1/2 in. square and 1 to 2 in. long were cut from full-bore rubbersleeve and conventional cores. The sands were poorly consolidated, which necessitated hand carving the small cores to the desired size and shape.
Fluid flow measurement were made with a permeameter having a constant-rate pump that pumps a permeameter having a constant-rate pump that pumps a driving fluid into a bladder-type accumulator, displacing the test fluid at a constant rate. The test fluid was forced through corns and the differential pressure across each core was measured continuously with a differentialpressure transducer and recorded on a strip-chart recorder. The cores, which had been potted previously in aluminum sleeves with epoxy resin, were confined in a core holder consisting of two end plates secured with through-bolts. All solutions were filtered previously with 0.22-micrometer Millipore filters. Permeabilities were calculated from core dimensions, fluid viscosity, and differential pressure.
Carbonate contents of effluents and sands were determined by titrating with hydrochloric acid. In the case of aqueous effluent solutions, a known volume of solution was titrated with 0.01-normal hydrochloric acid to below pH 7. A glass electrode and pH meter were used to pH 7. A glass electrode and pH meter were used to determine pH values.