Mots-clés de l'auteur: Induced seismicity ; stress management ; hydraulic fracturing ; reservoir stimulation ; Enhanced Geothermal Systems ; state of stress ; stress preconditioning ; reservoir depletion ; carbon storage ; fluid injection.

A comprehensive overview of the key geologic, geomechanical and engineering principles that govern the development of unconventional oil and gas reservoirs. Covering hydrocarbon-bearing formations, horizontal drilling, reservoir seismology and environmental impacts, this is an invaluable resource for geologists, geophysicists and reservoir engineers.

In the past several years, some energy technologies that inject or extract fluid from the Earth, such as oil and gas development and geothermal energy development, have been found or suspected to cause seismic events, drawing heightened public attention. Although only a very small fraction of injection and extraction activities among the hundreds of thousands of energy development sites in the United States have induced seismicity at levels noticeable to the public, understanding the potential for inducing felt seismic events and for limiting their occurrence and impacts is desirable for state and federal agencies, industry, and the public at large. To better understand, limit, and respond to induced seismic events, work is needed to build robust prediction models, to assess potential hazards, and to help relevant agencies coordinate to address them. Induced Seismicity Potential in Energy Technologies identifies gaps in knowledge and research needed to advance the understanding of induced seismicity; identify gaps in induced seismic hazard assessment methodologies and the research to close those gaps; and assess options for steps toward best practices with regard to energy development and induced seismicity potential.

The characterisation of fluid transport properties of rocks is one of the most important, yet difficult, challenges of reservoir geophysics, but is essential for optimal development of hydrocarbon and geothermal reservoirs. This book provides a quantitative introduction to the underlying physics, application, interpretation, and hazard aspects of fluid-induced seismicity with a particular focus on its spatio-temporal dynamics. It presents many real data examples of microseismic monitoring of hydraulic fracturing at hydrocarbon fields and of stimulations of enhanced geothermal systems. The author also covers introductory aspects of linear elasticity and poroelasticity theory, as well as elements of seismic rock physics and mechanics of earthquakes, enabling readers to develop a comprehensive understanding of the field. Fluid-Induced Seismicity is a valuable reference for researchers and graduate students working in the fields of geophysics, geology, geomechanics and petrophysics, and a practical guide for petroleum geoscientists and engineers working in the energy industry.

Induced seismicity has become commonplace in the disposal of fluids in the subsurface. Understanding the mechanisms controlling fluid-injection induced/triggered seismicity is necessary to assess the safety and feasibility of industrial injection activities, such as shale reservoir stimulation, wastewater injection, greenhouse gas sequestration, and enhanced geothermal systems. The following reports on experimental studies that explore: (1) frictional and sealing behavior of laboratory faults; (2) assess the role of excess fluid pressures on the slip behavior of laboratory faults; and, furthermore (3) constrain the largest probable moment magnitudes developed during injection-triggered seismicity. Separately, machine learning methods are applied to (4) image the evolution of permeability structure in stimulated reservoirs using microearthquakes and observations from an unusually-well-constrained injection experiment -- the EGS-Collab. These activities and outcomes are described in detail in the following. Chapter 1 introduces a new miniature double direct shear (mini-DDS) apparatus, housed within a standard-triaxial (TEMCO) pressure vessel, capable of concurrently measuring the evolution of frictional strength, stability, healing and along-fault permeability under in situ conditions of stress and temperature. The apparatus accommodates gouge samples (25mmx32 mm) and intact rock samples with confining and shear stresses and pore pressures up to ∼26 MPa. Permeability may be measured with applied flow rates ranging from 1.67x10-11 to 3.6x10-6m3/s to a flow accuracy of 0.5% representing a lower bound of permeability>2.2x10-18m2. Sliding velocities are in the range 0.1 [mu]m/s to 0.67 cm/s with a frame stiffness of 0.067 kN/[mu]m. We describe protocols and procedures for calibration and experiments and note the potential of the apparatus for both rapid and extended-duration measurements of friction-permeability evolution and healing. The apparatus returns measurements of friction and stability of reference materials of F110 quartz consistent with the literature while additionally allowing the concurrent measurement of permeability. Permeability of F110 quartz evolves in slide-hold-slide (SHS) experiments with increases during holds and decreases during subsequent slides. These observations are consistent with grain crushing and resultant wear products that reduce that permeability by clogging during slides with unclogging of the major fluid channels occurring during shearing. Chapter 2 presents concurrent measurements of shear displacement and flow to quantify the evolution of frictional strength, stability, healing and permeability of schist during the full seismic cycle. We complete this via velocity stepping (VS for stability) and slide-hold-slide (SHS for frictional healing) experiments using a miniature single direct shear apparatus contained within a pressurized core holder. Our results demonstrate that increasing pore fluid pressures can stabilize frictional slip under otherwise invariant effective stresses. This implies that elevated pressures favor stable slip as a material characteristic even in the absence of decreasing critical fault stiffness (thereby increasing stability) as a result of decreased effective stress. However, the magnitude of pore pressure does not control permeability evolution during velocity steps as pore pressure does not control aperture dilation/compaction for an invariant effective normal stress. During SHS tests, it is shown that the magnitude of normalized permeability change increases with hold time and that the rate of permeability change generally decreases with the increment of pore fluid pressure, suggesting that high fluid pressures may limit permeability change during interseismic response, although creep response may still dominate over the long term. Chapter 3 introduces a robust method to both define critical antecedent conditions and to thereby constrain anticipated event size. We define maximum event magnitudes resulting from triggering as a function of pre-existing critical stresses and fluid injection volume. Fluid injection experiments on prestressed laboratory faults confirm these estimates of triggered moment magnitudes for varied boundary conditions and injection rates. In addition, observed ratios of shear slip to dilation rates on individual faults signal triggering and may serve as a measurable proxy for impending rupture. This new framework provides a robust method of constraining maximum event size for preloaded faults and unifies prior laboratory and field observations that span sixteen decades in injection volume and four decades in length scale. Chapter 4 introduces a hybrid machine learning (ML) model to visualize 3D in-situ permeability evolution for an intermediate-scale (~10 m) hydraulic stimulation experiments at the Sanford Underground Research Facility (the EGS Collab project). The hybrid model uses ML to predict average reservoir injectivity. The ML model is built based on the XGboost algorithm using the well history of flow rate and wellhead pressure and MEQs data from the first three stimulation episodes (#1-#3) to predict injectivity from the statistical features of the MEQs alone over the final two episodes (#4#5). The ground truth of injectivity (episodes #4#5) calculated directly from the well data compares well with the ML prediction with an MSE 2.9x10-4 and R20.93. We then geometrically convert this history of injectivity into a mean permeability assuming steady flow. This causality between injectivity/permeability and MEQs is then used to develop a physics-based model linking permeability evolution to MEQ magnitude. This relies on the parallel plate analog linking permeability to dilation and then supplemented by laboratory observations scaling dilation to equivalent MEQ magnitude. These data are then scaled to link individual MEQs of known magnitude and location to define incremental changes in permeability in both space and in time. These use MEQ location and moment magnitude data alone. The resulting permeability map defines and quantifies projected flow paths in the reservoir with the averaged permeability comparing favorably with the permeability recovered from the injectivity history of the latter two ground truth episodes (#4#5). Together, such ML and physics-based MEQ methods offer significant potential to characterize the transport and reactive/heat-transfer characteristics of reservoirs where stress exerts significant control.