Gas transport, sorption and fracturing in shale.

摘要

Shale gas has become an increasingly important source of natural gas (CH4) in the United States over the last decade. As an unconventional resource, various stimulation techniques including hydraulic fracturing and enhanced gas recovery have been proposed to maximize production. This study examines some of these techniques combining experiments and models. Part I of this dissertation (Chapter 1) examines the use of CO 2 for enhanced shale gas recovery (CO2-ESGR) using a dual porosity dual permeability model to better understand its feasibility and effectiveness. Part II (Chapter 2) explores the use of gas stimulants for hydraulic fracturing to assess the form and behavior of fractures in shale driven by different gas compositions and states. Part III (Chapter 3) examines the evolution of permeability in artificially propped fractures in Green River Shale for native CH4 contrasted against sorbing CO2, slightly sorbing N2 and non- sorbing He, specifically to examine the deleterious influence of proppant embedment. Together, the findings of these experiments and analyses aid in the understanding of proppant embedment and fracture diagenesis in shales. Finally, part IV (Chapter 4) examines the role of stress reorienation in aiding productivity increases in the refracturing of previoslu fractured wells in shales to determine the optimal timing of refracturing as well as in quantifying its potential improvement.;Chapter 1 explores the roles of important coupled phenomena activated during gas substitution especially vigorous feedbacks between sorptive behavior and permeability evolution. Permeability and porosity evolution models developed for sorptive fractured coal are adapted to the component characteristics of gas shales.;In Chapter 2, fracturing is completed on cylindrical samples containing a single blind axial borehole under simple triaxial conditions with confining pressure ranging from 10~25MPa and axial stress ranging from 0-35MPa (sigma1>sigma2 = sigma3). Results show that: 1) under the same stress conditions, CO2 returns the highest breakdown pressure, followed by N2, and with H2O exhibiting the lowest breakdown pressure; 2) CO2 fracturing, compared to other fracturing fluids, creates nominally the most complex fracturing patterns as well as the roughest fracture surface and with the greatest apparent local damage followed by H2O and then N2; 3) under conditions of constant injection rate, the CO2 pressure build-up record exhibits condensation between ~5-7MPa and transits from gas to liquid through a mixed-phase region rather than directly to liquid as for H2O and N2 which do not; 4) there is a positive correlation between minimum principal stress and breakdown pressure for failure both by transverse fracturing (□ 3axial) and by longitudinal fracturing (□ 3radial) for each fracturing fluid with CO 2 having the highest correlation coefficient/slope and lowest for H2O . We explain these results in terms of a mechanistic understanding of breakdown, and through correlations with the specific properties of the stimulating fluids.;In Chapter 3, experiments are conducted on 1inch diameter, 2-inch-long split cylindrical samples sandwiched with proppant at a constant confining stress of 20 MPa and with varied pore pressure -- increases in pore pressure represent concomitant decreases in effective stress. Permeability and sorption characteristics are measured by pulse transient methods. To explore the effect of swelling and embedment on fracture surface geometry, we measure the evolution of transport characteristics for different proppant geometries (single layer vs. multi-layer), gas saturation, and sample variance. In order to simulate both production and enhanced gas recovery saturation, and sample variance. In order to simulate both production and enhanced gas recovery.