This study examines the results of laboratory work to establish rock strength data, acid solubility, fracture fluid selection and mineral identification of a fractured tight gas carbonate reservoir. Basic to a successful acid fracture design are acid etching and rotating disc tests which show for a given acid system, conductivity at a given stress (etched width or how much rock is eaten away) and parameters necessary to determine acid reaction rate, reaction order, rate constant and energy of activation at a given temperature. These tests address the measurement of mass transfer and diffusion with or without leak off in carbonates, and also enable the prediction of reactivity versus temperature for various acid strengths.
Dynamic fluid losses are measured experimentally and laboratory data are converted to an estimate of in-situ leak off. The leak off profile and wall building coefficients enable a consideration of fluid loss additives for fracturing fluids to build up pressure for fracture opening.
In the fracture conductivity tests, closure stress is applied across a test unit for sufficient time to allow the proppant bed to reach a semi-steady state condition while test fluid is forced through the bed. At each stress level, pack width, differential pressure, and average flow rates are measured as fluid is forced through the proppant bed. The proppant pack permeability and conductivity are then evaluated and compared.
A discussion of dominant considerations for effective hydraulic fracturing in naturally fractured tight gas carbonates is presented along with the results of laboratory work to establish rock mechanical properties data, acid solubility, fracture fluid selection and mineral identification for a selected naturally fractured tight gas carbonate reservoir.1
The carbonates under consideration are located in the Western Canadian Sedimentary Basin (WCSB) in what is usually known as the "Deep Basin" of Alberta (Figure 1). The core samples studied come from the Savannah Creek field (Figures 2) and correspond to the Rundle group Mississippian Mount Head and Livingston carbonates (Figure 3). These carbonates were deposited in a shallow marine ramp setting. These are upward-shallowing cycles ranging from crinoid / bryozoan shoals to lagoonal mud facies.
The reservoirs comprise dolomudstones and wackstones with an average pay of approximately 35 m. Reservoir zones can be discontinuous due to lateral facies changes and minor faulting.
The presence of natural fractures in the tight formations considered in this research is corroborated by cores and thin sections. Notice the presence of calcite cemented fractures in the whole core and plugs displayed in Figure 4. The thin section shown on Figure 5 presents calcite-filled fractures (pink strip running from upper left to lower right) that have been re-fractured (thin blue streak). The thin section work corroborates that it possible to re-fracture existing healed fractures.
There are many mechanisms that contribute to the final created geometry (fracture height, fracture width, hydraulic or created fracture length or effective fracture length)2–8 and its evolution in naturally fractured tight gas carbonates. Pump rate, volume injected, fluid viscosity, fluid loss and proppant scheduling combine with static and dynamic rock properties.
