Developing a high capacity axis translation apparatus for gas shale testing

Jinwoo Kim,Alessio Ferrari,Lyesse Laloui,Russ Ewy,R Cardoso,C Jommi,E Romero

doi:10.1051/e3sconf/202019503020

Jinwoo Kim, Alessio Ferrari + Show 5 more

Open Access

https://doi.org/10.1051/e3sconf/202019503020

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Abstract

Gas shales are usually partially saturated due to hydrocarbon generation and often have a low in-situ degree of saturation less than 40 %. During stimulation, substantial fluid imbibition into the formation occurs due to high suction. Recent research on these shales showed that changes in saturation strongly affect the strength and elastic properties, as well as their hysteretic behavior. To date, most experimental methodologies were based on total suction control by the vapor equilibrium technique. We postulate that the more representative in-situ conditions can be reproduced by capillary pressure control using the axis translation technique. The main challenge, however, is that the capillary pressure range is limited and far from sufficient to bring gas shales to partially saturated conditions. This paper introduces our recent progress in developing a high capacity axis translation apparatus for gas shales testing. Four high air entry value (HAEV) filter candidates were tested and evaluated for their performances and suitability

Highlights

Gas shales are usually partially saturated with the pore space filled with brine and hydrocarbon
We introduce our recent progress in developing a high capacity axis translation apparatus for gas shale testing
Matric suction can be decomposed into two components: s = Pc + Pd where Pc is capillary pressure and Pd is disjoining pressure corresponding to the adsorption [16]

Summary

Introduction

Gas shales are usually partially saturated with the pore space filled with brine and hydrocarbon (liquid and/or gas). The presence of immiscible fluids – especially hydrocarbon gas and brine – in the nanometer scale pores generate high capillary pressure [1]. Water adsorption onto the clay surface prevails [3], leading to very high in-situ matric suction. Brines in these shales often have appreciable salinity and osmotic suction [4]. Numerous field evidence supports this idea; more than half of the water injected in the well is not recovered during flowback operations [5,6] Is this uneconomical, but subsequent changes in saturation may cause shale stability problems [7] and reservoir damages [8].

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