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All sourcesNASA NTRSDOE OSTI
DOE OSTI2018

Cryogenic Fracturing of Wellbores Under True Triaxial-Confining Stresses: Experimental Investigation

A laboratory study of cryogenic fracturing was performed to test its ability to improve oil/gas recovery from low-permeability reservoirs. Our aim is to develop well-stimulation technologies using cryogenic fluids [e.g., liquid nitrogen (LN)] to increase permeability in a large reservoir volume surrounding wells. The new technology has the potential to reduce formation damage caused by current stimulation methods and minimize or eliminate water usage. The concept of cryogenic fracturing is that a sharp thermal gradient (thermal shock) created at the surfaces of formation rocks by applying cryogenic fluid can cause strong local tensile stress and start fractures. We created a laboratory system for cryogenic fracturing under true-triaxial loading, with LN-delivery/control and -measurement systems. The loading system simulates confining stresses by independently loading each axis up to approximately 5,000 psi on 888-in. cubes. Temperature in boreholes and at block surfaces and fluid pressure in boreholes were continuously monitored. Acoustic and pressure-decay measurements were obtained before and at various stages of stimulations. Cubic blocks (8 88-in.) of Niobrara shale, concrete, and sandstones were tested, and stress levels and anisotropies varied. Three schemes were considered: Gas fracturing without cryo-stimulation, gas fracturing after low-pressure cryogen flow-through, and gas fracturing after high-pressure cryogen flow-through. Findings from pressure-decay tests show that LN stimulation clearly increases permeability, and repeated stimulations further increase the permeability. Acoustic velocities and amplitudes decreased significantly after cryo-stimulation, indicating fracture creation. In the gas fracturing without the stimulation, breakdown (complete fracturing) occurs suddenly without any initial leaking, and major fracture planes form along the plane containing principal-stress and intermediate-stress directions, as expected theoretically. However, in the gas fracturing after cryogenic stimulations, breakdown occurred gradually and with massive leaking because of thermal fractures created during stimulation. In addition, the major fracture direction does not necessarily follow the plane containing the principal-stress direction, especially at low confining-stress levels. In tests, we observed that cryogenic stimulation seems to disrupt the internal stress field. The increase in borehole temperature after stimulation affects the permeability of the specimen. When a stimulated specimen is still cold, it maintains high permeability because fractures remain open and local thermal tension is maintained near the borehole. When the rock warms back, fractures close and permeability decreases. In these tests, we have not used proppants. Overall, fractures are clearly generated by low- and high-pressure thermal shocks. The added pressure of the high-pressure thermal shocks helps to further propagate cryogenic fractures generated by thermal shock. Breakdown pressure is significantly lowered by LN stimulation, with observed breakdown-pressure reductions up to approximately 40%.

42 ENGINEERING↗
DOE OSTI2019

Characterization of laboratory-scale hydraulic fracturing for EGS

To investigate the impact of reservoir stimulation by hydraulic fracturing, a series of advanced lab-scale block tests were conducted with multiple measurement methods to characterize the fracture and to assess the operation and the performance of an enhanced or engineered geothermal system (EGS). The stimulation test samples were 330-mm cubic blocks of Sierra White granite with one injection well and four producers drilled into it. Acoustic emissions generated during the fracture initiation and propagation were monitored with twenty AE sensors mounted on all sides of the block to help characterize the fracture initiation and propagation process. The recorded AE signals were analyzed to obtain the event location and the failure mechanism. The localized AE events shows that due to the low viscosity of the fracturing fluid (water), the fracture propagated rapidly and took only about 1.4 s to reach near the block surface. During the fracturing phase, about 47 percent of the events were determined to be shear/mixed mode failure events, 28 percent tensile failure events, and 25 percent compressional failure events. Just after the simulation, a step-rate (constant flowrate) injection test was carried out to investigate the reservoir injectivity enhancement. During this phase additional compressional failure events were observed and the percentages of tensile failure and shear/mixed mode failure decreased. The dramatic increase of the injection rate with small increments of the injection pressure demonstrates the nonlinear response of the fracture to effective normal stress variation with much higher fracture opening increase during the low effective normal stress interval. Hydraulic fracturing tests under different stress levels show that more AE hits/events are recorded when the rock block is under higher applied stress. The reconstructed 3D fracture geometry shows good agreement with the AE monitoring results. After fracturing, a tracer test was carried out and the fracture aperture was estimated to be around 139 μm. The tracer recovery curve shows two linear portions of the tracer tail on a semi-log plot similar to that observed in some field data and predicted by numerical modeling. Laser scanning of the fracture surfaces indicates that the induced fracture has a rough surface with a joint roughness coefficient (JRC) of 12.98 and tortuosity of 1.10, both of which are slightly larger than that from the Brazilian test fracture on the same rock. The thin section and SEM observations show that the fracture follows the weak boundaries between the Quartz and Albite grains or the weak beddings in the grains.

58 GEOSCIENCES↗
DOE OSTI2017

The Application of Radon for Mapping Open Fracture Networks in a Thin Vadose Zone

The use of naturally occurring tracers to elucidate subsurface flow and transport of water and gasses through fractured vadose zones represents a powerful and inexpensive methodology for understanding geologic systems. Our study was conducted at Sheply’s Hill, a highly fractured granite highland at the old Fort Devens military base. This study evaluates the applicability of using cheap, readily available passive radon detectors to identify conductive structures (e.g., fractures and fracture networks) in fracture-dominated vadose zones. Radon data from this study provides strong evidence that, even within an intensively fractured system, a relatively smaller subset of the fractures is responsible for the majority of the vertical migration of gas and water that recharges contaminated groundwater sites. Our study found that zones of high recharge potential associated with open fracture networks could be identified based on the 222 Rn flux within the highly fractured Shepley’s Hill. Based on the results of this study, 222 Rn is an environmental tracer capable of efficiently detecting major bedrock fracture sets in the vadose zone responsible for water infiltration into contaminated aquifers. Results from the Shepley’s Hill study show a clear spatial correlation of elevated 222 Rn concentrations emanating from fracture zones previously identified by independent geologic studies. At Shepley’s Hill, the 222 Rn concentrations measured from detector locations directly above the major bedrock fractures, located within the Disc Golf Fracture Zone (DGFZ) and the Nona-Shep Fracture Zone (NSFZ), were almost exclusively the highest values measured in the study. Conversely, probes located above areas of less-fractured bedrock, although highly fractured, showed relatively low 222 Rn concentrations. Furthermore, these two observations provide strong supporting evidence that not all fractures are equal when it comes to their ability to transmit gas or water into and out of the subsurface.

58 GEOSCIENCES↗
DOE OSTI2014

Scale-Dependent Fracture-Matrix Interactions And Their Impact on Radionuclide Transport - Final Report

Matrix diffusion and adsorption within a rock matrix are widely regarded as important mechanisms for retarding the transport of radionuclides and other solutes in fractured rock (e.g., Neretnieks, 1980; Tang et al., 1981; Maloszewski and Zuber, 1985; Novakowski and Lapcevic, 1994; Jardine et al., 1999; Zhou and Xie, 2003; Reimus et al., 2003a,b). When remediation options are being evaluated for old sources of contamination, where a large fraction of contaminants reside within the rock matrix, slow diffusion out of the matrix greatly increases the difficulty and timeframe of remediation. Estimating the rates of solute exchange between fractures and the adjacent rock matrix is a critical factor in quantifying immobilization and/or remobilization of DOE-relevant contaminants within the subsurface. In principle, the most rigorous approach to modeling solute transport with fracture-matrix interaction would be based on local-scale coupled advection-diffusion/dispersion equations for the rock matrix and in discrete fractures that comprise the fracture network (Discrete Fracture Network and Matrix approach, hereinafter referred to as DFNM approach), fully resolving aperture variability in fractures and matrix property heterogeneity. However, such approaches are computationally demanding, and thus, many predictive models rely upon simplified models. These models typically idealize fracture rock masses as a single fracture or system of parallel fractures interacting with slabs of porous matrix or as a mobile-immobile or multi-rate mass transfer system. These idealizations provide tractable approaches for interpreting tracer tests and predicting contaminant mobility, but rely upon a fitted effective matrix diffusivity or mass-transfer coefficients. However, because these fitted parameters are based upon simplified conceptual models, their effectiveness at predicting long-term transport processes remains uncertain. Evidence of scale dependence of effective matrix diffusion coefficients obtained from tracer tests highlights this point and suggests that the underlying mechanisms and relationship between rock and fracture properties are not fully understood in large complex fracture networks. In this project, we developed a high-resolution DFN model of solute transport in fracture networks to explore and quantify the mechanisms that control transport in complex fracture networks and how these may give rise to observed scale-dependent matrix diffusion coefficients. Results demonstrate that small scale heterogeneity in the flow field caused by local aperture variability within individual fractures can lead to long-tailed breakthrough curves indicative of matrix diffusion, even in the absence of interactions with the fracture matrix. Furthermore, the temporal and spatial scale dependence of these processes highlights the inability of short-term tracer tests to estimate transport parameters that will control long-term fate and transport of contaminants in fractured aquifers.

58 GEOSCIENCES↗
DOE OSTI2025

Diagenesis is key to unlocking outcrop fracture data suitable for quantitative extrapolation to geothermal targets

Exceptionally large, well-exposed sandstone outcrops in New York provide insights into folds, deformation bands, and fractures that could influence permeability, heat exchange, and stimulation outcomes of geothermal reservoir targets. Cambrian Potsdam Sandstone with <5% porosity contains decimeter-scale open, angular-limbed monoclines <0.5 km apart with associated low-porosity mm-wide cataclastic deformation bands. Crossing and abutting relationships among sub-vertical opening-mode fractures show four chronological Sets A–D, striking NNW, NE, NW, and ENE, respectively. Fracture lengths and heights range from millimeters to tens of meters. Sets A and C macro-fractures, and possibly B and D, contain quartz deposits. All sets have abundant associated quartz cemented microfractures that also record set orientations and crosscutting relations. Quartz cement deposits—evidence of diagenesis—are the key to identifying attributes of outcrop fractures suitable for extrapolation to geothermal targets in sandstones because they show which fractures formed in the subsurface. Set A fluid inclusion homogenization temperatures (120°C–129°C) are compatible with fracture at >3 km depth. Fractures are stiff and those ≥0.05 mm (Set C) and ≥0.1 mm (Set A) are open and potentially conducive to flow. Sets A and D are abundant in outcrops with close fracture spacing—0.18 m and 0.68 m, respectively—and define a rectangular connectivity network dominated by crossing and abutting X and Y nodes. Set A aperture distributions follow a power law with slope –0.8 up to 0.15 mm; other sets have lognormal distributions. Set A and D microfractures are weakly clustered, while macro-fractures commonly have 1D anticlustered (regular or periodic) arrangements at shorter length scales (<0.2 m). Sub-horizontal fractures are barren and may have formed near the surface. Fracture heights, lengths, and spatial arrangements show good trace connectivity but low open connectivity. For geothermal applications, outcrop results predict low initial well-test permeabilities owing to quartz disconnecting open fractures, but stimulation of closely spaced microfractures and partly open macro-fractures could yield high surface area for heat exchange. Quantitative extrapolation of key fracture attributes like abundance, orientation, spatial arrangement, length, and open fracture connectivity is possible from outcrops to fractured reservoirs if differing thermal histories and diagenesis are accounted for.

02 PETROLEUM↗
DOE OSTI2016

Waterless fracturing technologies for unconventional reservoirs-opportunities for liquid nitrogen

During the past two decades, hydraulic fracturing has significantly improved oil and gas production from shale and tight sandstone reservoirs in the United States and elsewhere. Considering formation damage, water consumption, and environmental impacts associated with water-based fracturing fluids, efforts have been devoted to developing waterless fracturing technologies because of their potential to alleviate these issues. Herein, key theories and features of waterless fracturing technologies, including Oil-based and CO 2 energized oil fracturing, explosive and propellant fracturing, gelled LPG and alcohol fracturing, gas fracturing, CO 2 fracturing, and cryogenic fracturing, are reviewed. We then experimentally elaborate on the efficacy of liquid nitrogen in enhancing fracture initiation and propagation in concrete samples, and shale and sandstone reservoir rocks. In our laboratory study, cryogenic fractures generated were qualitatively and quantitatively characterized by pressure decay tests, acoustic measurements, gas fracturing, and CT scans. The capacity and applicability of cryogenic fracturing using liquid nitrogen are demonstrated and examined. Furthermore, by properly formulating the technical procedures for field implementation, cryogenic fracturing using liquid nitrogen could be an advantageous option for fracturing unconventional reservoirs.

03 NATURAL GAS↗
DOE OSTI2017

Optimizing for Large Planar Fractures in Multistage Horizontal Wells in Enhanced Geothermal Systems Using a Coupled Fluid and Geomechanics Simulator

Enhanced Geothermal Systems (EGS) could potentially use technological advancements in coupled implementation of horizontal drilling and multistage hydraulic fracturing techniques in tight oil and shale gas reservoirs along with improvements in reservoir simulation techniques to design and create EGS reservoirs. In this study, a commercial hydraulic fracture simulation package, Mangrove by Schlumberger, was used in an EGS model with largely distributed pre-existing natural fractures to model fracture propagation during the creation of a complex fracture network. The main goal of this study is to investigate optimum treatment parameters in creating multiple large, planar fractures to hydraulically connect a horizontal injection well and a horizontal production well that are 10,000 ft. deep and spaced 500 ft. apart from each other. A matrix of simulations for this study was carried out to determine the influence of reservoir and treatment parameters on preventing (or aiding) the creation of large planar fractures. The reservoir parameters investigated during the matrix simulations include the in-situ stress state and properties of the natural fracture set such as the primary and secondary fracture orientation, average fracture length, and average fracture spacing. The treatment parameters investigated during the simulations were fluid viscosity, proppant concentration, pump rate, and pump volume. A final simulation with optimized design parameters was performed. The optimized design simulation indicated that high fluid viscosity, high proppant concentration, large pump volume and pump rate tend to minimize the complexity of the created fracture network. Additionally, a reservoir with 'friendly' formation characteristics such as large stress anisotropy, natural fractures set parallel to the maximum horizontal principal stress (SHmax), and large natural fracture spacing also promote the creation of large planar fractures while minimizing fracture complexity.

15 GEOTHERMAL ENERGY↗
DOE OSTI2018

Discontinuities in effective permeability due to fracture percolation

Motivated by a triaxial coreflood experiment with a sample of Utica shale where an abrupt jump in permeability was observed, possibly due to the creation of a percolating fracture network through the sample, we perform numerical simulations based on the experiment to characterize how the effective permeability of otherwise low-permeability porous media depends on fracture formation, connectivity, and the contrast between the fracture and matrix permeabilities. While a change in effective permeability due to fracture formation is expected, the dependence of its magnitude upon the contrast between the matrix permeability and fracture permeability and the fracture network structure is poorly characterized. We use two different high-fidelity fracture network models to characterize how effective permeability changes as percolation occurs. The first is a dynamic two-dimensional fracture propagation model designed to mimic the laboratory settings of the experiment. The second is a static three-dimensional discrete fracture network (DFN) model, whose fracture and network statistics are based on the fractured sample of Utica shale. Once the network connects the inflow and outflow boundaries, the effective permeability increases non-linearly with network density. In most networks considered, a jump in the effective permeability was observed when the embedded fracture network percolated. We characterize how the magnitude of the jump, should it occur, depends on the contrast between the fracture and matrix permeabilities. For small contrasts between the matrix and fracture permeabilities the change is insignificant. However, for larger contrasts, there is a substantial jump whose magnitude depends non-linearly on the difference between matrix and fracture permeabilities. A power-law relationship between the size of the jump and the difference between the matrix and fracture permeabilities is observed. In conclusion, the presented results underscore the importance of fracture network topology on the upscaled properties of the porous medium in which it is embedded.

36 MATERIALS SCIENCE↗
DOE OSTI2019

Multiscale Modeling of CO 2 Migration and Trapping in Fractured Reservoirs with Validation by Model Comparison and Real-Site Applications (Final Technical Report)

This report documents the accomplishments achieved during the project titled “Multiscale Modeling of CO 2 Migration and Trapping in Fractured Reservoirs with Validation by Model Comparison and Real-Site Applications” funded by the US Department of Energy, Office of Fossil Energy. The objectives of the project were to develop modeling capabilities for predicting CO 2 and brine migration in fractured reservoirs during geologic carbon storage and to investigate the feasibility of carbon storage in fractured reservoirs using the newly developed modeling capabilities. To achieve these objectives new mass transfer functions were developed to adapt existing dual-continuum approaches – a commonly used approach in hydrocarbon reservoir modeling – to the CO 2 -brine system. In the dual-continuum approach the undisturbed rock matrix and the fractures are modeled as two separate continua, which are coupled through mass exchange of CO 2 and brine between the two continua. Mass transfer functions represent the mass exchange between fractures and the rock matrix, without requiring highly resolved numerical grids of individual fractures, thus allowing large modeling domains relevant to geologic carbon storage questions (tens of meters to hundreds of kilometers). Mass transfer functions for the exchange of both free-phase CO 2 and brine between fractures and rock matrix were developed for both the injection phase and the post-injection phase. During the injection phase the fractures are filled with CO 2 , while the rock matrix is initially filled with brine. Therefore, a mass transfer function was developed that is based on vertical displacement of brine by CO 2 in the rock matrix due to gravitational forces. Once CO 2 injection ceases and CO 2 migrates away from the direct vicinity of the injection site, the fractures will begin to re-fill with brine, while the rock matrix will have high CO 2 saturations. For these conditions a mass transfer functions was developed that is based on spontaneous imbibition, as the pore spaces in the rock matrix are much smaller than in the fractures. For formations with low permeability or high capillary entry pressure of the rock matrix, free-phase CO 2 may not be able to enter the rock matrix. However, free-phase CO 2 at the interface between fractures and rock matrix can dissolve into brine resident in the rock matrix. Therefore, additional mass transfer functions were developed based on aqueous-phase diffusion of CO 2 through the rock matrix. These mass transfer functions are based on existing solutions for diffusion and were expanded to be applicable to a variety of block shapes relevant to dual-continuum modeling. Implementations of the newly developed mass transfer functions showed that they give accurate results when compared to highly resolved models. In addition to developing new transfer functions, a new vertically-integrated dual-continuum modeling framework was developed. This development takes advantage of fast vertical segregation of CO 2 and brine in the fractures due to the density difference between CO 2 and brine and the high permeability of the fractures. Therefore, a vertically-integrated vertical equilibrium model for the fractures is coupled with a vertically-distributed model for the rock matrix. The newly developed approach significantly reduces the computational effort, but is only accurate for fracture permeabilities of 100 mD or higher. Finally, the newly developed models were applied to real and hypothetical geologic carbon storage sites to investigate the feasibility of using fractured reservoirs for carbon storage. The general results were, that storage of CO 2 – both as free-phase and dissolved – is feasible, but that storage capacities are likely lower than in unfractured systems. While the high permeability of the fractures reduces the injection pressure (or permits higher injection rates), fast migration of CO 2 may limit the overall storage volume, because CO 2 may escape laterally with not enough of the rock matrix being swept for effective storage.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2017

Study of hydraulic fracturing processes in shale formations with complex geological settings

Hydraulic fracturing has been applied to extract gas from shale-gas reservoirs. Complicated geological settings, such as spatial variability of the rock mass properties, local heterogeneities, complex in situ stress field, and pre-existing bedding planes and faults, could make hydraulic fracturing a challenging task. In order to effectively and economically recover gas from such reservoirs, it is crucial to explore how hydraulic fracturing performs in such complex geological settings. For this purpose, numerical modelling plays an important role because such conditions cannot be reproduced by laboratory experiments. This study focuses on the analysis of the influence of confining formations and pre-existing bedding planes and faults on the hydraulically-induced propagation of a vertical fracture, which will be called injection fracture, in a shale-gas reservoir. An elastic-brittle model based on material property degradation was implemented in a 2D finite-difference scheme and used for rock elements subjected to tension and shear failure. A base case is considered, in which the ratio SR between the magnitudes of the horizontal and vertical stresses, the permeability k c of the confining formations, the elastic modulus E p and initial permeability k p of the bedding plane and the initial fault permeability k F are fixed at reasonable values. In addition, the influence of multiple bedding planes, is investigated. Changes in pore pressure and permeability due to high pressure injection lasting 2 h were analysed. Results show that in our case during the injection period the fracture reaches the confining formations and if the permeability of those layers is significantly larger than that of the shale, the pore pressure at the extended fracture tip decreases and fracture propagation becomes slower. After shut-in, the pore pressure decreases more and the fracture does not propagate any more. For bedding planes oriented perpendicular to the maximum principal stress direction and with the same elastic properties as the shale formation, results were found not to be influenced by their presence. In such a scenario, the impact of multiple bedding planes on fracture propagation is negligible. On the other hand, a bedding plane softer than the surrounding shale formation leads to a fracture propagation asymmetrical vertically with respect to the centre of the injection fracture with a more limited upward fracture propagation. A pre-existing fault leads to a decrease in fracture propagation because of fault reactivation with shear failure. This results in a smaller increase in injection fracture permeability and a slight higher injection pressure than that observed without the fault. Results of a sensitivity analysis show that fracture propagation is influenced by the stress ratio SR, the permeability k c of the confining formations and the initial permeability k p of the bedding plane more than the other major parameters.

58 GEOSCIENCES↗
DOE OSTI2023

Final Report DE-FE0031785 Mohsen Ahmadian, Ph.D. Demonstration of Proof of Concept of a Multiphysics Approach for Real-Time Remote Monitoring of Dynamic Changes in Pressure and Salinity in Hydraulically Fractured Networks

Hydraulic fracturing has evolved into a multistep process with varying flow rates, carrier fluids (e.g., gel or slickwater), proppant loadings, and proppant grain sizes. As a result, primary recovery from a hydraulically fractured tight-oil reservoir is often a tiny fraction of the original oil in place, ranging between 5 and 10%. As stated in the FOA1990, “part of this problem is due to the inability of current well completion processes to effectively stimulate the entire reservoir volume in contact with the wellbore. Innovative technologies are needed that can help improve the effectiveness of reservoir completion methods, maximize stimulated reservoir volumes, and optimize recovery over the entire producing life span of a well”. We first need to enhance the current fracture diagnostic techniques to improve a well-completion design. However, detecting and delineating a subsurface hydraulic fracture is extremely difficult because the induced fracture network is only fractionally propped, and these propped fractures are generally very thin. Microseismic and tiltmeter monitoring techniques can provide information on the fracture extent but provide little or no information on the movement and final distribution of proppant or production fluids. On the other hand, electromagnetic (EM) imaging has shown the capability to monitor proppant distribution throughout the fracture area, especially in the presence of Electrically Active Proppants (EAPs). A previous EM survey of hydraulic fracturing at the Devine Fracture Pilot Site (DFPS) and subsequent EM code developments demonstrated this survey as a robust technique to remotely interrogate the extent of the EAP-filled hydraulic fracture during its propagation. The objectives of the project were threefold: (1) to capitalize on the material properties of an EAP to demonstrate remote monitoring of relative changes in pressure, pressure, and flow that are commonly encountered during production from a hydraulically fractured reservoir; (2) to evaluate EM imaging tools, to achieve Objective 1 in near real-time; and (3) to develop a multi-physics joint inversion approach to precisely predict flow patterns and physiochemical changes within an EAP-filled fracture network. This research project was built upon our previous work at the Devine Test Site managed by the Bureau of Economic Geology (BEG) at The University of Texas at Austin (UT-Austin). It also leveraged a significant investment from the Advanced Energy Consortium (AEC) to address the DOE's interest in subsurface flow, containment, and characterization by multiple signals. This three-year and three-month project succeeded in demonstrating the feasibility of a real-time dynamic fluid flow mapping technique at Technology Readiness Level 5 (TRL5) by utilizing a commercially available surface-based Controlled-Source Electromagnetic (CSEM) method (Objectives 1, 2). We demonstrated that injections into an EAP-filled fracture could be successfully coupled with real-time electric field measurements on the surface, leading to remote monitoring of dynamic changes within the EAP-filled fracture. Furthermore, the observed electric field in our study is influenced by bottomhole pressure, flow rate, and salinity, which is demonstrated by comparing these parameters with the electrical field potentials. EM simulations solely based on assumptions of fracture conductivity changes during injection did not reproduce the whole measured electric field magnitudes. Preliminary estimates showed that including Streaming Potential (SP) in our geophysical model is likely needed to reduce the simulation misfit.

02 PETROLEUM↗
DOE OSTI2021

Effect of Shear Displacement and Stress Changes on Fracture Hydraulic Aperture and Flow Anisotropy

Fluid flow in fractures has the potential to drastically change the economic, environmental, and safety risks associated with a subsurface operation. This work focuses on the analysis of experimental shear fracturing and subsequent shear displacement of a shale specimen that contains multiple pre-existing natural fractures. A triaxial direct shear apparatus with concurrent µCT imaging allowed continuous monitoring of sample permeability and changes in fracture geometry during fracture creation, displacement, and changes in stress. Steady-state, low Reynolds number fluid flow simulations were used to determine the changes of each individual fracture’s hydraulic aperture due to displacement and effective stress. The development of anisotropy in the hydraulic aperture of a generated shear fracture was determined for shear displacements of 0.38, 0.74, and 2.04 mm. At high confining stress (30 MPa), shear displacement significantly reduced the hydraulic aperture of the shear fracture to below flow detectable limits and X-ray imaging resolution (23 × 23 × 23 µm 3 ). The shear generated fracture was found to be more sensitive to changes in effective stress compared to the pre-existing natural fractures. Existing models derived from fluid flow equations accounting for stochastic fracture roughness were able to partially fit the simulated flow properties of the pre-existing fractures, but no model was found to fit the flow properties of the newly formed shear fracture. These results are the first report of simultaneous changes in the geometry and flow properties of surrounding, parallel natural fractures as a shear fracture is generated with varying stress and shear displacement conditions.

58 GEOSCIENCES↗
DOE OSTI2013

Method development for determining the hydraulic conductivity of fractured porous media

Plausible, but unvalidated, theoretical model constructs for unsaturated hydraulic conductivity of fractured porous media are currently used in Performance Assessment (PA) modeling for cracked saltstone and concrete (Flach 2011). The Nuclear Regulatory Commission (NRC) has expressed concern about the lack of model support for these assumed Moisture Characteristic Curves (MCC) data, as noted in Requests for Additional Information (RAIs) PA-8 and SP-4 (Savannah River Remediation, LLC, 2011). The objective of this task was to advance PA model support by developing an experimental method for determining the hydraulic conductivity of fractured cementitious materials under unsaturated conditions, and to demonstrate the technique on fractured saltstone samples. The task was requested through Task Technical Request (TTR) HLW-SSF-TTR-2012-0016 and conducted in accordance with Task Technical & Quality Assurance Plan (TTQAP) SRNL-TR-2012-00090. Preliminary method development previously conducted by Kohn et al. (2012) identified transient outflow extraction as the most promising method for characterizing the unsaturated properties of fractured porous media. While the research conducted by Kohn et al. (2012) focused on fractured media analogs such as stacked glass slides, the current task focused directly on fractured saltstone. For this task, four sample types with differing fracture geometries were considered: 1) intact saltstone, 2) intact saltstone with a single saw cut, smooth surface fracture, 3) micro-fractured saltstone (induced by oven drying), and 4) micro-fractured saltstone with a single, fully-penetrating, rough-surface fracture. Each sample type was tested initially for saturated hydraulic conductivity following method ASTM D 5084 using a flexible wall permeameter. Samples were subsequently tested using the transient outflow extraction method to determine cumulative outflow as a function of time and applied pressure. Of the four sample types tested, two yielded datasets suitable for analysis (sample types 3 and 4). The intact saltstone sample (sample type 1) did not yield any measureable outflow over the pressure range of the outflow test (0-1000 cm H 2 O). This was expected because the estimated air entry pressure for intact saltstone is on the order of 100,000 cm H 2 O (Dixon et al., 2009). The intact saltstone sample with a single saw cut smooth surface fracture (sample type 2) did not produce useable data because the fracture completely drained at less than 10 cm H 2 O applied pressure. The cumulative outflow data from sample types 3 and 4 were analyzed using an inverse solution of the Richard’s equation for water flow in variably saturated porous media. This technique was implemented using the computer code Hydrus-1D (Šimunek et al., 2008) and the resulting output included the van Genuchten-Mualem water retention and relative permeability parameters and predicted saturated hydraulic conductivity (Van Genuchten, 1980; Van Genuchten et al., 1991). Estimations of relative permeability and saturated conductivity are possible because the transient response of the sample to pressure changes is recorded during the multi-step outflow extraction test. Characteristic curves were developed for sample types 3 and 4 based on the results of the transient outflow method and compared to that of intact saltstone previously reported by Dixon et al. (2009). The overall results of this study indicate that the outflow extraction method is suitable for measuring the hydraulic properties of micro-fractured porous media. The resulting cumulative outflow data can be analyzed using the computer code Hydrus-1D to generate the van Genuchten curve fitting parameters that adequately describe fracture drainage. The resulting characteristic curves are consistent with blended characteristic curves that combine the behaviors of low pressure drainage associated with fracture flow with high pressure drainage from the bulk saltstone matrix.

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2024

Predicting Fracture Porosity Evolution in Sandstone (Final Report)

To better understand porosity, strength, chemical reactivity, and patterns of fractures, we developed methods using mineral deposits to unravel how fracture growth and diagenesis interact to create and destroy fracture porosity. Quartz and dolomite cement textures and associated fluid inclusion assemblage sequences and thermal histories provided data to infer the duration and rates at which fractures open. We developed and tested a model that accounts for how fracture porosity and rock properties change as a function of thermal exposure and how fracture size and arrangement evolve. Effects of cement deposits on growth were investigated with new geomechanical models and new methods to quantify fracture spatial arrangement. We tested these concepts in a wide range of rock types using outcrop and core-based datasets. We documented opening histories of fractures and fracture arrays in contrasting tectonic and thermal regimes. Our methods set a new standard for fracture characterization and our diagenetic-geomechanical model accurately predicts fluid flow characteristics of fractured rocks based on coupled effects of diagenesis and deformation. Results represent a significant advance in fundamental understanding of fractures in the Earth and have application to improving subsurface engineering operations in a wide range of contexts including geothermal and sequestration applications. The breakthrough of successfully reconstructing the timing and opening rates of parts of single fractures and portions of fracture arrays to document the growth and linkage of fracture arrays was an accomplishment of this grant that is being followed up in our current BES grant DE-SC0022968, ‘Reconstructing and Predicting Fracture Pattern Evolution‘

58 GEOSCIENCES↗
DOE OSTI2015

A New Physics-Based Modeling of Multiple Non-Planar Hydraulic Fractures Propagation

Because of the low permeability in shale plays, closely spaced hydraulic fractures and multilateral horizontal wells are generally required to improve production. Therefore, understanding the potential fracture interaction and stress evolution is critical in optimizing fracture/well design and completion strategy in multi-stage horizontal wells. In this paper, a novel fully coupled reservoir flow and geomechanics model based on the dual-lattice system is developed to simulate multiple non-planar fractures propagation. The numerical model from Discrete Element Method (DEM) is used to simulate the mechanics of fracture propagations and interactions, while a conjugate irregular lattice network is generated to represent fluid flow in both fractures and formation. The fluid flow in the formation is controlled by Darcy’s law, but within fractures it is simulated by using cubic law for laminar flow through parallel plates. Initiation, growth and coalescence of the microcracks will lead to the generation of macroscopic fractures, which is explicitly mimicked by failure and removal of bonds between particles from the discrete element network. We investigate the fracture propagation path in both homogeneous and heterogeneous reservoirs using the simulator developed. Stress shadow caused by the transverse fracture will change the orientation of principal stress in the fracture neighborhood, which may inhibit or alter the growth direction of nearby fracture clusters. However, the initial in-situ stress anisotropy often helps overcome this phenomenon. Under large in-situ stress anisotropy, the hydraulic fractures are more likely to propagate in a direction that is perpendicular to the minimum horizontal stress. Under small in-situ stress anisotropy, there is a greater chance for fractures from nearby clusters to merge with each other. Then, we examine the differences in fracture geometry caused by fracturing in cemented or uncemented wellbore. Moreover, the impact of intrinsic reservoir heterogeneity caused by the rock fabric and mineralogy on fracture nucleation and propagation paths is examined through a three-layered reservoir. Finally, we apply the method to a realistic heterogeneous dataset.

02 PETROLEUM↗
DOE OSTI2020

Interpretation of Hydraulic Fractures Based on Microseismic Response in the Marcellus Shale, Monongalia County, West Virginia, USA: Implications for Shale Gas Production

Summary Hydraulic fracturing is critical for extracting shale gas in the subsurface. The treatment technique of multistage hydraulic fracturing is widely used to maximize production. In multistage hydraulic fracturing, not all pumping stages make the same contribution for production, although the designed stimulation process is almost same in every pumping stage. In this study, we characterize the microseismic responses of hydraulic fracturing. Significant variations of microseismic characteristics are observed among the different pumping stages. Pre-existing natural fractures are examined along the horizontal well in selected stages. Combined with the Mohr’s circle analysis, results of the fracture study show that induced hydraulic fractures can be captured by pre-existing natural fractures. Induced hydraulic fractures are simulated by the unconventional fracture model (UFM), and the result reveals that the stress-shadow effect diverts the direction of hydraulic fractures. The diverted hydraulic fracture affects the development of the hydraulic fracture network, which has influence on production. The treatment of two-step pumping is investigated by application of hydraulic diffusivity. Hydraulic fracturing performance and production could be optimized by the treatment of two-step pumping in a single stage. The second pumping creates new fractures and fills the fractures with additional proppants to maintain production for a long duration.

Energy & Fuels↗
DOE OSTI2016

Intermediate-Scale Hydraulic Fracturing in a Deep Mine - kISMET Project Summary 2016

In support of the U.S. DOE SubTER Crosscut initiative, we established a field test facility in a deep mine and designed and carried out in situ hydraulic fracturing experiments in the crystalline rock at the site to characterize the stress field, understand the effects of rock fabric on fracturing, and gain experience in monitoring using geophysical methods. The project also included pre- and post-fracturing simulation and analysis, laboratory measurements and experiments, and we conducted an extended analysis of the local stress state using previously collected data. Some of these activities are still ongoing. The kISMET (permeability (k) and Induced Seismicity Management for Energy Technologies) experiments meet objectives in SubTER’s “stress” pillar and the “new subsurface signals” pillar. The kISMET site was established in the West Access Drift of SURF 4850 ft (1478 m) below ground (on the 4850L) in phyllite of the Precambrian Poorman Formation. We drilled and cored five near-vertical boreholes in a line on 3 m spacing, deviating the two outermost boreholes slightly to create a five-spot pattern around the test borehole centered in the test volume at ~1528 m (5013 ft). Laboratory measurements of core from the center test borehole showed P-wave velocity heterogeneity along each core indicating strong, fine-scale (~1 cm or smaller) changes in the mechanical properties of the rock. The load-displacement record on the core suggests that the elastic stiffness is anisotropic. Tensile strength ranges between 3-7.5 MPa and 5-12 MPa. Permeability measurements are planned, as are two types of laboratory miniature hydraulic fracturing experiments to investigate the importance of rock fabric (anisotropy and heterogeneity) on near-borehole hydraulic fracture generation. Pre-fracturing numerical simulations with INL’s FALCON discrete element code predicted a fracture radius of 1.2 m for a corresponding injection volume of 1.2 L for the planned fractures, and negligible microseismicity. Field measurements of the stress field by hydraulic fracturing showed that the minimum horizontal stress at the kISMET site averages 21.7 MPa (3146 psi) pointing approximately N-S (356 degrees azimuth) and plunging slightly NNW at 12°. The vertical and horizontal maximum stress are similar in magnitude at 42-44 MPa (6090-6380 psi) for the depths of testing which averaged approximately 1530 m (5030 ft). Hydraulic fractures were remarkably uniform suggesting core-scale and larger rock fabric did not play a role in controlling fracture orientation. Monitoring using ERT and CASSM in the four monitoring boreholes, and passive seismic accelerometer-based measurements in the West Access Drift, was carried out during the generation of a larger fracture (so-called stimulation test) at a depth of 40 m below the invert. ERT was not able to detect the fracture created, nor were the accelerometers in the drift, but microseismicity was detected for first (deepest) hydraulic-fracturing stress measurement. The CASSM data have not yet been analyzed. Analytical solutions suggest fracture radius of the large fracture (stimulation test) was more than 6 m, depending on the unknown amount of leak-off. The kISMET results for stress state are consistent with large-scale mid-continent estimates of stress. Currently we are using the orientation of the stress field we determined to interpret a large number of borehole breakouts recorded in nearby boreholes at SURF to generate a more complete picture of the stress field and its variations at SURF. The efforts on the project have prompted a host of additional follow-on studies that we recommend be carried out at the kISMET site.

02 PETROLEUM↗
DOE OSTI2018

Fracture mechanics of shales under chemically reactive conditions

Fracture growth processes under subsurface conditions are known to be affected by fluid chemical environment. Chemical effects on fracture growth are likely to be relevant during host rock and organic matter diagenesis and catagenesis, hydraulic fracturing, in systems undergoing enhanced oil recovery, in geothermal systems, and in CO 2 sequestration reservoirs. To address the chemical effects on opening-mode fracture growth under a wide range in fluid chemical conditions and for different rock types we conducted double-torsion fracture mechanics tests to determine mode-I fracture toughness (KIC), subcritical index (SCI), and the stress-intensity factor vs fracture velocity (K-V) behavior. We tested sandstones, shales and, altered crystalline rocks. Samples were tested in aqueous conditions with variable salinity, solution pH, and at temperatures of up to 70 °C. Fracture growth in shales is highly sensitive to the environmental conditions, with a reduction of KIC of up to 47% from ambient air to water-saturated conditions. The primary interactions between shales and reactive solutions are clay-water and carbonate dissolution. For clay-rich Woodford and Mancos shales, solutions with higher salinity reduce subcritical fracture growth, while acidic conditions favor fracture growth in carbonate-rich Marcellus shale. Increasing the solution temperature promotes fracture growth. In sandstone, chemical effects on fracture parameters are most pronounced for clay- and carbonate-rich samples. Both KIC and SCI are lower in water than in air for nearly all sandstone lithologies tested. SCI is further reduced in chlorite-cemented Tuscaloosa Sandstone in acidic solutions. Mount Simon Sandstone is also sensitive to pH, most significantly in diagenetically bleached samples. Compositionally mature Aztec Sandstone is affected by water saturation, but shows little sensitivity to chemical environment. Silicified gabbro shows a slight reduction in KIC but a >60% reduction in SCI in aqueous environments compared to ambient conditions. The reduction in SCI is most pronounced in alkaline and saline solutions, suggesting silica dissolution and cation exchange at the fracture tip facilitate subcritical fracture growth. Limited reduction in KIC is attributed to low permeability. Overall, our results demonstrate that fracture properties depend strongly on water saturation, on fluid composition and pH, and on temperature, with an increase in temperature lowering fracture resistance.

58 GEOSCIENCES↗