The selection process of hydraulic fracturing fluids for oil and gas well stimulation applications largely ignores interactions of the stimulation filtrate and the broken stimulation fluid with formation minerals. Fluid interactions with formation minerals may have a significant influence on formation permeability and subsequent well production. Laboratory formation core regain permeability studies, subsequent to the injection of both low and high pH fluids, were conducted to measure fluid effect on core permeability. Results of these tests indicate that both the rock mineralogy and the pore system morphology are affected by contact of the rock with filtrate from the injection of an unbroken stimulation system into the formation. Formation permeability after treatment with stimulation fluid can be significantly influenced by formation - injection fluid interactions. Studies have demonstrated that, depending on the specific formation mineralogy, post-injection permeability may be increased by low pH systems only, by high pH systems only, or by either low or high pH systems.
The focus of this paper is to identify specific formation minerals which may potentially be affected by contact with fracturing fluid filtrate and broke, fracturing fluid and to relate increases in formation permeability to resultant fluid-rock interactions. Mechanisms of fluid-formation interactions and chemical reactions are presented.
Considerable attention has been given to damage to formation permeability which is induced by the leakoff and/or injection of drilling and stimulation fluids to the formation.
Over the past several years during routine laboratory fracturing fluid loss and regain permeability testing on core plugs, the filtrate from certain fracturing systems has been found to stimulate certain formations, yielding regain permeabilities in excess of 100%. Results of several of these tests are compiled in Table 1. Further investigation revealed that under certain circumstances, anticipated increases in regain permeability did not occur. Instances of both formation stimulation and formation non-stimulation are presented and discussed.
A appropriate fracturing fluid must have certain physical ana chemical properties. The fluid must be compatible with the formation and its indigenous or connate fluids. The fluid should exhibit low friction pressure as it is injected through well tubulars and should exhibit low fluid loss to the formation. The fluid should be capable of suspending and transporting proppant material deep into the fractured formation. It should have appropriate rheological properties to develop the desired fracture geometry and proppant placement and should retain its viscosity throughout the treatment. Fracturing fluids discussed in this paper are prepared using guar and guar derivative polymers which are crosslinked with borate or transition metal chelates.