Abstract Fracturing fluid formulations, testing methodology and equipment has evolved, as have industry-accepted standards for testing. These standards have undergone a number of revisions over the years, and were published first as a recommended practice under the American Petroleum Institute (API-RP39) and subsequently under the International Standards Organization as ISO-13503-1. These standards define the geometry, shear rate, temperature control and other test parameters to measure the fluid performance under in-situ reservoir conditions. Little focus was given to the pressure applied to the fluid, other to ensure that it would not be allowed to boil under the test conditions. This lack of emphasis on pressure is completely understandable, as condensed matter (solids and liquids) typically have a limited response to the pressures experienced in the wellbore or during fracturing operations. And a typical expectation for compressible fluids, oils for example, is to experience an increase in viscosity with increased pressure.
It has been found that pressures (hydrostatic and pressure applied during pumping operations) encountered during hydraulic fracturing can materially reduce the viscosity of a borate crosslinked fluid. The loss in viscosity, depending on fluid formulation, temperature and pressure, can range from negligible to catastrophic. This phenomenon has been studied using high pressure rheometry and high pressure nuclear magnetic resonance (NMR), and has only recently been published in the scientific literature.
This paper will present results from testing a variety of fracturing fluids, including polymeric and viscoelastic surfactant-based, under in-situ conditions. It will detail the results of these tests for borate crosslinked fracturing fluids, and analogues not employed in the industry.
Based on these data, it will be clear that fracture geometry and proppant placement will be influenced. This is particularly true for deepwater treatments where the in-situ pressures are very high.
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