Production from hydrocarbon reservoirs is strongly dependent on the permeability of the formation. For decades, the permeability of conventional reservoirs, which are typically in milli-Darcy range, has been measured by the steady-state laboratory technique which provides accurate and fast results. In contrast, unsteady state techniques such as GRI or pulse decay have been used to measure the permeability of unconventional formations such as shales due to their ultra-low permeability. GRI technique is carried on crushed samples and is considered a fast technique for matrix permeability measurement. However, recent studies have found that reported GRI measurements results by different commercial laboratories are often inconsistent. This may be related to the sample crushing method. Moreover, GRI technique cannot measure the permeability of the sample under reservoir stress conditions. Pulse decay is a different technique for measuring permeability of the core plugs. Pulse decay measurement results are also found often to be inconsistent.

This paper introduces a new, fast and robust technique that measures permeability of shale plug samples under steady-state condition. A laboratory set-up was designed and assembled which has a resolution of one millionth standard cubic centimeters per second for gas flow rate and one hundredth cubic centimeters for pore volume measurement. Extremely accurate differential transducers are used to measure the flow of gas passing through the core samples under in-situ conditions. The in-situ conditions are achieved by maintaining isothermal conditions and the application of the confining stress on the core sample. The laboratory set-up is fully automated to eliminate any human error and more importantly maintains the temperature stable within the enclosed unit. In this technique, the permeability is determined under wide range of pore and confining pressure. Klinkenberg and modified Klinkenberg methods can be then applied to evaluate the absolute permeability. When adsorbent gases such as CO 2 and CH 4 are used, this technique can provide the permeability hysteresis for adsorption and desorption processes. Finally, the laboratory set-up can be used to measure porosity, based on Boyle's law, formation compressibility and the sorption parameters. In this study, the laboratory set-up was used to measure permeability and porosity of Marcellus Shale core samples under wide range of pore and confining pressures using Helium as a non-adsorbent and Nitrogen and Carbon Dioxide as adsorbent gases. Both Klinkenberg and modified Klinkenberg techniques were applied to the gas permeability measurement results to obtain the absolute permeability. The permeability and porosity of the samples were found to be significantly impacted by the net stress. In contrast to porosity, the permeability exhibited hysteresis with respect to net stress.

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This paper introduces a robust and accurate technique for the steady-state permeability and porosity measurements in ultra-low permeability shale core samples. A laboratory set-up was designed and assembled which has a resolution of one nano-darcy for the permeability and one-hundredth cubic centimeters for pore volume measurements. Extremely accurate differential-pressure transducers are used to measure the flow of gas passing through the core sample under in-situ conditions. The in-situ conditions are achieved by maintaining isothermal conditions and the application of the confining stress on the core sample. The laboratory set-up is fully automated to eliminate any human error and more importantly maintains the temperature stable within the enclosed unit.A series of measurements were performed on a Marcellus Shale core sample under wide range of pore and confining pressures using Helium (He) as a non-adsorbent and Nitrogen (N 2 ) and Carbon Dioxide (CO 2 ) as adsorbent gases. The measured gas permeability under steady-state condition is generally higher than the absolute permeability due to gas slippage (Klinkenberg 1941). Recent experimental and numerical studies indicate that permeability values for organic rich shale obtained by using different gases are much larger than the absolute permeability predicted by Klinkenberg the slippage theory. In ultra-tight formations such as organic rich shale, the measured "apparent" permeability is not a linear function of reciprocal of pressure as predicted by Klinkenberg. Thus, a new method based on the double gas slippage theory in nano-capillaries has been proposed for reliable estimation of the shale absolute permeability.In this study both Klinkenberg and double slippage corrections were applied to the steady-state permeability measurements. The results indicated that application of Klinkenberg to the permeability measurements lead to negative absolute permeability for shale samples. However, the double-slippage correction resulted in physically plausible values for absolute permeability of shale samples. Finally, the measurement results with adsorbent gases indicated that the adsorbed gas layer thickness can significantly impact the gas transport and storage in organic rich shale reservoirs and needs to be considered for hydrocarbon in place calculation and production predictions.

The advances in hydraulic fracturing and horizontal well technology have unlocked considerable reserves of hydrocarbon contained in shale formations. However, quantification of the key shale petrophysical properties remain challenging. It is not practical to measure the permeability of the unconventional formations such as shales by standard steady state techniques because shales typically have permeability values in nano-Darcy range. Therefore, unsteady state methods have been extensively used to estimate permeability of the shale samples. However, the measured permeability values by these techniques suffer from large margin of uncertainty and reproducibility problems. These problems are attributed to the lack of consistent experimental protocols and the interpretations of the transient data. Another limitation of the unsteady-state measurements is that the experiments cannot be performed under the reservoir stress and temperature conditions. This paper provides the results of the porosity and permeability measurements on Marcellus shale core plugs which were performed using a fully automated laboratory set-up for evaluation of the ultra-low permeability petrophysical properties under the confining pressure. The permeability of the core plug were first measured under different gas pressures at constant net stress. The absolute permeability was then determined by applying the gas double-slippage correction. The porosity and the permeability of the core plug were then measured under a wide range of net stress. The measured porosity and permeability values were found to be sensitive to stress. Two distinctive behaviors with net stress, for both porosity and permeability, were observed that can be related to the natural fracture and matrix properties. The experimental results were then utilized to determine the natural fracture closure pressure. The permeability measurements with carbon dioxide revealed that permeability is impacted by adsorption. The results of the measurements with were carbon dioxide also provided information for determination of the sorption characteristics that were found to be in agreement with the published values.