Mark W. McClure

The Importance of Slow Slip on Faults During Hydraulic Fracturing Stimulation of Shale Gas Reservoirs

We utilize several lines of evidence to argue that slow slip on pre-existing fractures and faults is an important deformation mechanism contributing to the effectiveness of slick-water hydraulic fracturing for stimulating production in extremely low permeability shale gas reservoirs. First, we carried out rate and state friction experiments in the laboratory using shale samples from three different formations with a large range of clay content. These experiements indicated that slip on faults in shales comprised of less than about 30% clay is expected to propagate unstably, thus generating conventional microseismic events. In contrast, in formations containing more than about 30% clay are expected to slip slowly. Second, we illustrate through modeling that slip induced by high fluid pressure on faults that are poorly oriented for slip in the current stress field is expected to be slow, principally because slip cannot occur faster than fluid pressure propagates along the fault plane. Because slow fault slip does not generate high frequency seismic waves, conventional microseismic monitoring does not routinely detect what appears to be a critical process during stimulation. Thus, microseismic events are expected to give only a generalized picture of where pressurization is occurring in a shale gas reservoir during stimulation which helps explain why microseismicity does not appear to correlate with relative productivity. We review observations of long-period-longduration seismic events that appear to be generated by slow slip on mis-oriented fault planes during stimulation of the Barnett shale. Prediction of how pre-existing faults and fractures shear in response to hydraulic stimulation can help optimize field operations and improve recovery. Introduction Multi-stage hydraulic fracturing with slick-water in horizontal wells is an effective completion strategy for producing commercial quantities of natural gas from organic-rich shale gas formations. That said, the physical mechanisms responsible for reservoir stimulation are poorly understood. The prevalent paradigm is that diffusion of water out of the hydraulic fracture stimulates shear failure on multiple small, pre-existing fractures and faults in the shale. This shear slip creates a network of relatively permeable flow paths and thus enhances productivity from the extremely low permeability shale formations. Microseismic events recorded during hydraulic fracturing are evidence of this shear slip and the ‘clouds’ of microseismic events associated with multiple hydraulic fracturing stages in a well are generally assumed to define the stimulated rock volume (SRV) from which the gas is being produced (Warpinki et al., 2012). While this paradigm is generally useful, a simple mass balance calculation illustrates that the cumulative deformation associated with the microseismic events can account for only a small fraction of the production. In a single well, it has been shown that the number of microseismic events does not correlate with production from successive hydraulic fracturing stages (Moos et al., 2011). Production from five wells in the Barnett shale studied by Vermylen and Zoback (2011) does not correlate the number of microseismic events generated by hydraulic fracturing in each well even though the wells were stimulated in a similar manner. In this paper we argue that slow slip on numerous fault planes is occurring in shale gas reservoirs during stimulation. In fact, we believe this is likely to be the dominant deformation mechanism during hydraulic stimulation. The shear deformation associated with the slowly slipping faults is expected to create a network of multiple permeable planes surrounding the induced hydraulic fractures. In the sections below, we first review evidence of

An embedded fracture modeling framework for simulation of hydraulic fracturing and shear stimulation

A numerical modeling framework is described that is able to calculate the coupled processes of fluid flow, geomechanics, and rock failure for application to general engineering problems related to reservoir stimulation, including hydraulic fracturing and shear stimulation. The numerical formulation employs the use of an embedded fracture modeling approach, which provides several advantages over more traditional methods in terms of computational complexity and efficiency. Specifically, the embedded fracture modeling strategy avoids the usual requirement that the discretization of the fracture domain conforms to the discretization of the rock volume surrounding the fractures. As fluid is exchanged between the two domains, conservation of mass is guaranteed through a coupling term that appears as a simple source term in the governing mass balance equations. In this manner, as new tensile fractures nucleate and propagate subject to mechanical effects, numerical complexities associated with the introduction of new fracture control volumes are largely negated. In addition, the ability to discretize the fractures and surrounding rock volume independently provides the freedom to choose an acceptable level of discretization for each domain separately. Three numerical examples were performed to demonstrate the utility of the embedded fracture model for application to problems involving fluid flow, mechanical deformation, and rock failure. The results of the numerical examples confirm that the embedded fracture model was able to capture accurately the complex and nonlinear evolution of reservoir permeability as new fractures propagate through the reservoir and as fractures fail in shear.

Characterizing hydraulic fracturing with a tendency-for-shear-stimulation test

The classical concept of hydraulic fracturing is that a single, planar, opening mode fracture forms. In recent years, there has been a growing consensus that in many formations, natural fractures play an important role during stimulation. There is not universal agreement on the mechanisms by which natural fractures affect stimulation, and these mechanisms vary depending on formation properties. One potentially important mechanism is shear stimulation, where an increase in fluid pressure induces slip and permeability enhancement on preexisting fractures. We propose a Tendency for Shear Stimulation (TSS) test as a direct, relatively unambiguous method for determining the degree to which shear stimulation contributes to stimulation in a particular formation. In the TSS test, fluid is injected at a bottomhole pressure that is intentionally maintained below the minimum principal stress, ideally at a constant pressure. Under these conditions, shear stimulation is the only possible mechanism for permeability enhancement (except perhaps thermally induced tensile fracturing). Standard pressure transient tests could be performed before and after the TSS test to estimate formation permeability. The flow rate rate transient during injection may also be interpreted to identify shear stimulation. Numerical simulations of shear stimulation were performed with a discrete fracture network model that couples fluid flow with the stresses induced by fracture deformation. These simulations were used to qualitatively investigate how shear stimulation and fracture connectivity affect the results of a TSS test. The simulations neglected matrix flow and were two-dimensional, which made it impossible to forward simulate the transients that would be expected in practical application. Modeling improvements will make this possible in future work. Two specific field projects are discussed as examples of a TSS test, the Enhanced Geothermal System (EGS) projects at Desert Peak and Soultz-sous-Forêts. At Soultz, the formation had a high TSS, and at Desert Peak, formation TSS was minimal. Introduction Classically, hydraulic fracturing has been conceptualized as creating a single, planar, opening mode tensile fracture. But in low matrix permeability applications such as oil or gas production from shale or geothermal production from granite, the process of hydraulic stimulation has been conceptualized as creating a complex network of newly forming fractures and/or natural fractures that slip and open in response to injection (Fisher et al., 2004; Bowker, 2007; Gale et al., 2007; Cipolla et al., 2008; King, 2010; Pine and Batchelor, 1984; Murphy and Fehler, 1986; Brown, 1989; Ito, 2003; Ito and Hayashi, 2003; Evans, Moriya, et al., 2005; Ledésert et al., 2010). The precise geometry of these networks is a major uncertainty. The networks cannot easily be observed directly in the subsurface; it is difficult to know how laboratory experiments relate to the reservoir scale, and microseismic interpretations with respect to network geometry are nonunique. In shale, it is widely believed that new fractures form and propagate through the formation, but apparently there is disagreement about the role of preexisting fractures and how they contribute to production. One potentially important process is termination of propagating natural fractures against preexisting fractures. This has been observed in laboratory experiments (Blanton, 1982; Renshaw and Pollard, 1995; Zhou et al., 2008; Gu et al., 2011), mine-back experiments (Warpinski and Teufel, 1987; Warpinski et al., 1993; Mahrer, 1999; Jeffrey et al., 2009), and computational investigations (Dahi-Taleghani and Olson, 2009; Gu and Weng, 2010; Fu et al., 2012). If termination occurs, then it may be difficult for a single, continuous, large fracture to propagate across the formation, and pathways for flow through the reservoir may occur through both new and preexisting fractures (a process we refer to as Mixed-Mechanism Stimulation, MMS). This process could play an important role in generating stimulated fracture surface area and therefore increasing recovery. MMS

Generation of large postinjection‐induced seismic events by backflow from dead‐end faults and fractures

Induced seismicity is common during hydraulic stimulation in fractured crystalline rock. Fluid injection pressurizes preexisting fractures, triggering slip and seismicity. Often, the largest induced events occur after the end of injection, which complicates efforts to manage seismic risk. In this study, a three-dimensional discrete fracture network simulator that couples fluid flow with earthquake simulation was used to investigate a novel hypothesis for why large postinjection seismic events occur. Fractures that form dead-end pathways differentially pressurize during injection. After injection is stopped, fluid backflows through the well from the dead-end fractures into larger fractures, inducing additional seismicity and potentially causing events larger than occurred during injection. Our simulations indicate that flowing fluid back to the surface immediately after injection could mitigate this effect and reduce postinjection seismicity.

Identifying potentially induced seismicity and assessing statistical significance in Oklahoma and California

We develop a statistical method for identifying induced seismicity from large datasets and apply the method to decades of wastewater disposal and seismicity data in California and Oklahoma. The study regions are divided into gridblocks. We use a longitudinal study design, seeking associations between seismicity and wastewater injection volume along time-series within each gridblock. In each gridblock, we find the maximum likelihood estimate for a model parameter that relates induced seismicity hazard to total volume of wastewater injected each year. To assess significance, we compute likelihood ratio test statistics in each gridblock and each state, California and Oklahoma. Resampling with permutation and random temporal offset of injection data is used to estimate p-values from the likelihood ratio statistics. We focus on assessing whether observed associations between injection and seismicity occur more often than would be expected by chance; we do not attempt to quantify the overall incidence of induced seismicity. The study is designed so that, under reasonable assumptions, the associations can be formally interpreted as demonstrating causality. Wastewater disposal is associated with other activities that can induce seismicity, such as reservoir depletion. Therefore, our results should be interpreted as finding seismicity induced by wastewater disposal and all other associated activities. In Oklahoma, the analysis finds with extremely high confidence that seismicity associated with wastewater disposal has occurred. In California, the analysis finds moderate evidence that seismicity associated with wastewater disposal has occurred, but the result is not strong enough to be conclusive.

Insights from pressure transients at observation wells near hydraulically fractured wells in a domestic shale play

AbstractWe integrate microseismic data and pressure measurements at far-field observation wells to characterize the relationship between deformation and fluid flow during hydraulic fracturing and production in four horizontal wells in an unconventional shale play. The microseismicity qualitatively delineated, where injection fluid traveled during stimulation. However, there was one clear example of the Kaiser effect, in which a strong pressure signal propagated aseismically over hundreds of feet through fractures that had recently been stimulated around a neighboring well. Analysis suggested that poroelastic pressure changes caused by fracture deformation were minimal because of the high compressibility of the volatile oil formation fluid. Therefore, the pressure changes at the observations wells were likely caused by flow of the injection fluid. Based on this hypothesis, the pressure signals in the observation wells were roughly categorized based on whether the pressure response exceeded the magnitude of...