We measured argon gas permeability in three intact and one partially fractured Eagle Ford Shale samples documenting the stress dependence of horizontal (bedding parallel) in situ permeability of intact samples which varies between 1 and 10 nD (1 nD = 0.9869233 × 10−21 m2), while the permeability of partially fractured sample varies between 18 and 37 nD. For all samples, permeability decreases by up to an order of magnitude while cycling the confining pressure (PC) between 27.7 and 55.2 MPa at a constant pore pressure (PP) of 14.4 MPa. Most of the permeability decrease is within the first loading and unloading cycle. During this first cycle, we also observe less than 2% decline in permeability over ~ 10 days when we held the PC constant at 51.6–55.2 MPa, respectively. This suggests that the ongoing creep plays a relatively minor role. The subsequent PC cycles result in a small decrease in permeability (~ 6 to 26% variation between the start and the end of each cycle). We interpret that the initial permeability loss is due to the closing of micro-fractures—which we infer are caused by stress relief and gas expansion during sample retrieval and/or preparation. We interpret that the higher permeability of the partially fractured sample is mainly due to incomplete closure of a preexisting fracture, which extends nearly two-third the sample length. We document this dual-permeability structure from the observation of a dual-timescale pressure response behavior during the experiments at lower PC–PP. We find permeability decreases with increasing PC–PP; stress dependency of permeability follows an exponential relationship with a stress-sensitive gradient of 0.019–0.040 MPa−1. A better understanding of permeability variation with stress will help to reliably estimate in situ permeability and to better understand production evolution from unconventional shale reservoirs.
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This research project is funded by Shell under the Shell-UT Unconventional Research (SUTUR) program. We thank Shell for providing the two samples from SW3 well. We thank the Mudrock System Research Laboratory (MSRL) and its sponsors for providing access to the two samples from K2 well. We also thank Lucy T. Ko for the SEM images of the samples from K2 well, Patrick Smith for taking the SEM images of the samples from SW3 well and Dr. Jessica Maisano for taking the microscale X-ray computed tomography images of the test core plugs. We are grateful to Drs. Robert Dombrowski, Mikhail Geilikman, Robert Loucks and Stephen Ruppel for guidance and fruitful discussions.
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Bhandari, A.R., Flemings, P.B., Hofmann, R. et al. Stress-Dependent In Situ Gas Permeability in the Eagle Ford Shale. Transp Porous Med 123, 1–20 (2018). https://doi.org/10.1007/s11242-018-1021-6
- Pulse-decay permeability
- In situ permeability
- Inter-particle pores