Investigation of Rock Properties of the Marcellus Formation – An Experimental Study

Abstract

The Marcellus formation has begun to attract more attention from the oil and gas industry. Despite being the largest shale formation and biggest source of natural gas in the United States, it has been the subject of little research. To fill this gap, this study experimentally examined the rock properties of twenty core samples from the formation. Five tests were performed on the core samples: X-ray computerized tomography (CT) scan, porosity, permeability, ultrasonic velocity, and X-ray diffraction (XRD). CT-scans were performed to identify the presence of any existing fracture(s). Additionally, helium was injected into the core samples at four different pressures (100 psi, 200 psi, 300 psi, and 400 psi) to determine the optimal pressure for porosity measurements. Complex Transient Method was employed to measure the permeabilities of the core samples. Ultrasonic velocity tests were conducted to calculate the dynamic Young's moduli (E) and the Poisson's ratios (ν) of the core samples at various confining pressures (in increments of 750 psi between 750 psi and 4,240 psi). Finally, the mineralogical compositions of the core samples were determined using the XRD test. The results of the CT-scan experiments revealed that seven core samples contained fractures. The porosity tests yielded an optimal pressure of 200 psi for porosity measurement. The measured porosities of the samples were between 6.43% and 13.85%. The permeabilities of the samples were between 5 nD and 153 nD. The results of the ultrasonic velocity tests revealed that at the confining pressure of 750 psi, the compressional velocity (Vp) ranged from 18,411 ft/s to 19,128 ft/s and the average shear velocities (Vs1 and Vs2) ranged from 10,413 ft/s to 11,034 ft/s. At the same confining pressure, the Young's modulus and Poisson's ratio ranged from 9.8 to 10.8 million psi and 0.25 to 0.28, respectively. Increase in the confining pressure resulted in increases in the Vp, Vs, Young's moduli, and Poisson's ratios of the samples. The results of the XRD test revealed that the samples were composed of calcite, quartz, and dolomite. This study is one of the first to characterize core samples obtained from the formation outcrop by performing five tests: CT-scan, porosity, permeability, ultrasonic velocity, and XRD. The results provide detailed insights to researchers working on the formation rock properties.

Effects of Pressurizing Cryogenic Treatments on Physical and Mechanical Properties of Shale Core Samples—An Experimental Study

“…Because the pore throats of shale core samples are very tight, implementing the methods of the conventional porosity measurement might lead to erroneous results. Khalil et al [38] experimentally investigated the effect of injection pressure on porosity measurements of shale core samples using helium at injection pressures of 0.69, 1.38, 2.07, and 2.76 MPa. They claimed that 1.38 MPa is the optimal injection pressure to measure the porosity of shale core samples without damaging the samples, and increasing the pressure above that does not promise significant changes in the porosity measurements.…”

An experimental study to investigate the physical and dynamic elastic properties of Eagle Ford shale rock samples

“…Several studies have investigated the effects of many parameters, such as gas transport and adsorption effect, pyrolysisinduced thermal maturation, water content, the relationship between static and dynamic properties, temperature, anisotropy, and bedding orientation effects using shale samples (Aljamaan et al 2017;Aljamaan et al 2013;Allan et al 2016;Alnoaimi* et al 2014;Guo et al 2013;He et al 2019;Holt et al 2015;Holt et al 2012;Kim et al 2020;Kuila et al 2011;Lai et al 2016;Masri et al 2014;Sone and Zoback 2013a;Sone and Zoback 2013b;Zhai et al 2021). However, few studies have conducted to examine the rock physical and/or dynamic elastic properties of shale formations (Badrouchi et al 2019;Cho et al 2016;He and Ling 2016;Heller et al 2014;Khalil et al 2019;Ramezanian and Emadi 2020;Sun et al 2016). Heller et al (2014) investigated the effects of confining and pore pressures on matrix permeability of gas-shale plugs from Barnett, Eagle Ford, Marcellus, and Montney reservoirs.…”

“…The multi-pulse method results showed that this method could reduce anisotropy and heterogeneity effects. Khalil et al (2019) measured samples' porosity from Marcellus formation at four injection pressures (0.69, 1.38, 2.07, and 2.76 MPa). The results showed a direct relationship between the injection pressure and the measured porosity.…”