Techniques such as horizontal drilling and hydraulic fracturing have helped in exploitation of unconventional shale reservoirs. However, a drawback of hydraulic fracturing is that it results in forced imbibition of frac-water into the pore system of the organic shale matrix. This can potentially result in lower productivity emanating from water blockage of oil-wet and oil-bearing nano-pore networks. This paper introduces a laboratory setup to investigate and quantify the damage to oil permeability caused by invasion of fracturing fluids in shales. The proposed process also allows for testing the impact of altering completions fluids chemistry (fresh versus produced water, surfactants, friction reducers, etc) on oil productivity.

The technique starts with carrying out micro-CT and NMR scans on as-received shale plug samples to evaluate sample condition and fluid saturations. These samples are then humidified and then saturated with either produced crude, after which a subsequent NMR scan is done to track oil and water saturation. For the permeability measurement, the samples are then loaded in an overburden cell, some of which are made of non-ferrous material and can be loaded in the NMR spectrometer. The sample is brought to reservoir stress conditions by increasing overburden stress and pore pressure gradually. The initial steady state permeability measurement is measured by injecting produced crude or hydrocarbon gases at a constant flow rate using a pump and monitoring pore pressures for stability. The downstream pressure is controlled by a back-pressure regulator.

Once steady state flow is established and the baseline effective hydrocarbon permeability is measured, a brine or a fracturing fluid solution is injected into the sample from the downstream for a specified time period. The completion fluid injection pressure is typically about 1000 psi to 2000 psi higher than the upstream oil pressure to simulate hydraulic fracturing induced imbibition of water. Then, to mimic shut-in that follows hydraulic fracturing of a stage, the upstream and downstream valves are closed for about 12 to 24 hours. Finally, hydrocarbon permeability is measured again as was done initially, to quantify degradation of deliverability due to water imbibition. Saturations of hydrocarbon fluid and brine in the sample are calculated using NMR T2 and T1T2 scans either during the test or right after the test is complete. In some instances, the saturation front of the hydrocarbon fluid or injected brine is examined using 2D and 3D gradient NMR scans.

These tests can be conducted at high pressure and temperature, while the setup that involves continuous NMR scanning of the plug during the core flooding process is rated to 10,000 psi for overburden pressure, 9000 psi for reservoir pressure and 100 C for reservoir temperature [Mathur et al. 2020]. Permeabilities as lows as 5 nano-Darcies can be measured. Varying completions fluids chemistries (salinity alteration, KCl, surfactants, FRs, etc) can also be used in the setup to evaluate the benefit or lack thereof in minimizing permeability damage.

On average, a decrease of 70% in hydrocarbon productivity is observed on comparing initial permeability and final permeability after water damage. As a validation of the water block phenomenon, samples have also been injected with decane and diesel from the bottom and little to no damage in hydrocarbon productivity is observed. Some scenarios of adding surfactant mixtures to the frac water, as well as cyclic gas injection have shown initial positive results; and are active areas of study.

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