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NASA NTRS1993

Formation and evolution of radial fracture systems on Venus

A survey of approximately 90 percent of the surface of Venus using Magellan data has been carried out to locate all radial fracture systems and to assess their association with other features such as volcanic edifices and coronae. Squyres et al. and Stofan et al. have discussed the association of radial fracture features in relation to coronae features, our approach was to assess the associations of all of the fracture systems. These fracture systems have two broad types of form - some fracture systems are associated with updomed topography, radiate from a point and have relatively uniform fracture lengths while others have a wider range of fracture lengths and radiate from the outer edge of a central caldera. Squyres et al. and Stofan et al. have interpreted both types of feature as reflecting tectonic fracturing resulting from uplift of the surface as a mantle plume impinges upon the crust. While it is true that a number of features are related to uplift and that such uplift will induce stresses consistent with radial fracturing, we explore the possibility that these fractures are not exclusively of tectonic origin. Purely tectonic fracturing will tend to generate a few main fractures/faults along which most of the stresses due to uplift will be accommodated leading to the triple-junction form common for terrestrial updoming. Though this type of feature is observed on Venus (e.g., feature located at 34S86), the majority of radial fracture systems display much more intensive fracturing than this through a full 360 degrees; this is difficult to explain by purely tectonic processes. The association of many of the fractures with radial lava flows leads us to interpret these fractures as reflecting dike emplacement: the form of the fractures being consistent with primarily vertical propagation from the head of a mantle plume. In the case of the second type of fracture system (those radiating from a central caldera), an even stronger case can be made that the fractures are not of tectonic origin. These features are not as commonly associated with updoming of the surface and where they are, the fractures extend out well beyond the edge of the topographic rise - an observation which is not consistent with the fractures being of tectonic uplift origin. Furthermore the fractures have a distribution of lengths (many short, fewer long) which is characteristic of dike swarms, and show direct associations with calderas and lava flows consistent with a volcanic origin. In addition, the longest fractures have a radial pattern only close to the center of the system but bend with distance to align themselves with the regional stress field - this behavior is very difficult to explain on purely tectonic grounds but is a pattern commonly seen for terrestrial dikes. For these reasons, we argue that many, if not the majority, of radial fracture systems found on Venus are the surface reflection of dike swarms, those associated with positive topography reflecting vertical emplacement and those radiating from calderas reflecting lateral propagation.

Parfitt, E. A.↗

DOE OSTI2020

Characterizing natural fractures and sub-seismic faults for well completion of Marcellus shale in the MSEEL Consortium project, West Virginia, USA

The Middle Devonian Marcellus shale play has emerged as a major world-class hydrocarbon accumulation and represents one of the largest and most prolific shale plays in the world. According to many outcrop studies in the region, natural fractures are well developed in the Marcellus Shale. However, evaluating fractures in the subsurface is often a significant challenge due to a lack of sufficient data. Therefore, in the Marcellus Shale Energy and Environment Laboratory (MSEEL) consortium project, significant efforts have been made to acquire high-quality image logs in the Marcellus laterals. The project provided tremendous opportunities to characterize the natural fractures and sub-seismic faults and to evaluate their impact on well stimulation. In this study, about 70,000 ft of acquired high-resolution logging while drilling (LWD) acoustic images from five long laterals located in Monongalia County, West Virginia, were processed and interpreted. In addition, the study used high-quality micro-resistivity images from a pilot well, allowing the evaluation of natural fractures in the entire Marcellus vertical sequence. Based on the available acoustic images, the natural fractures were classified into three basic categories: high-amplitude fractures, low-amplitude fractures, and faults. Further, larger open fractures can also be determined when a low-amplitude fracture is evident on caliper images. The fractures in the Marcellus usually have a medium to high angle dip; however, multiple fracture sets in terms of strike orientation were clearly observed in all the laterals. The fracture set with a strike at NE-SW (or 60-240 deg) seems to be the predominant one in all the wells. A few other sets, including those with N-S, NWW-SEE, and E-W strikes, were also observed. Several sub-seismic faults, with mostly a low dip angle and a NE-SW strike, have also been seen in two of the laterals. The fracture density is variable across all the laterals, ranging from very low (or none) to very high (up to 5 fractures per ft). The average fracture density for all the laterals is about 1 fracture per 10 ft. In the vertical sequence, the natural fracture development showed a clear preference for shale or shaly facies over carbonate-rich or thin limestone layers. The interpreted fracture and fault data were used as input data for the stimulation design with the purpose of better understanding the fractures’ impact on well stimulation. Production data from the laterals were also used to evaluate the natural fractures’ influence on well performance. The quality image database and the consistent interpretation results for the entire project enabled a systematic approach to characterizing fractures and, more importantly, to evaluating the impact of fractures on well stimulation and production.

03 NATURAL GAS↗

DOE OSTI2024

Experimental and numerical investigation of fracture conductivity between non-smooth rock surfaces with and without proppant

The enhancement of fracture conductivity is vital for the efficient recovery of subsurface resources, such as geothermal energy and petroleum hydrocarbons. Proppants, granular materials injected into hydraulic fractures to maintain their conductivity, have been studied primarily in the context of smooth fractures (i.e., fractures between smooth rock surfaces). However, non-smooth fractures (i.e., fractures between rough rock surfaces) are common in geoenergy reservoirs and thus require further investigations. In this study, we conducted laboratory measurements of fracture conductivity on shale slabs with non-smooth surfaces and carried out numerical simulation using the lattice Boltzmann (LB) method, which aimed to investigate the conductivity of non-smooth fractures with and without proppants placement. When ceramic proppant with an areal concentration of 2 lb/ft 2 was placed in the fracture, the conductivity was enhanced by roughly 3-8 times compared to fractures without proppant. In fractures with proppant, gas-measured conductivity was higher than that measured with water due to proppant embedment caused by water. The experiments demonstrate the advantages of using proppant in fractures, even if the rock surface roughness can provide certain fracture conductivity via the self-propping mechanism. For fractures without proppants, high rock surface roughness is not necessarily favorable for enhancing fracture conductivity because the self-propping mechanism requires shear slip along the fracture surface. If there is no shear slip, high rock surface roughness can cause a detrimental effect on the fracture conductivity due to the interlocking effect. Utilizing advanced experimental equipment and LB modeling, this research explores the interplays between proppant placement, fracture geometry, and stress conditions to develop a comprehensive understanding of the productivity in non-smooth fractures. Further, the outcomes of this investigation indicate the importance of creating fractures with surface roughness during hydraulic fracturing and will contribute to the development of more efficient stimulation techniques for subsurface energy extraction.

15 GEOTHERMAL ENERGY↗

DOE OSTI2022

Effect of Initial Water Saturation on The Performance of Fracturing Fluids With and Without Polyallylamine under Simulated EGS Conditions

Objectives/Scope: StimuFrac (US Patents 9,873,828 B2 and 9,447,315 B2), a CO2-reactive polymer aqueous solution [polyallylamine (PAA) 1wt% in water] combined with CO2, can be used as a less water-intensive fracturing fluid for enhanced geothermal systems (EGS). Our previous results show that in hot dry rock (HDR), PAA/CO2 fracturing fluids outperformed other fluids such as water, CO2, and CO2/water in generating large fractures with less fluid consumed. The objective of this work is to study the effect of initial water saturation of rock on the performance of StimuFrac fluid in ½ foot cubic rock samples and under representative EGS pressure/temperature conditions using cyclic and constant flow rate injection strategies. The fracturing results are compared with results using different fracturing fluids in terms of controlling fracture propagation rates, fracture hydraulic conductivity, breakdown pressures and volumes of fluids required. Methods/Procedures/Process: In all tests, water was initially injected into the rock to increase the water saturation before the fracturing processes to simulate actual geothermal reservoir conditions. For the cyclic injection, one complete cycle consisted of (1) a PAA slug (or water slug) injection followed by (2) CO2 injection to initiate the fracture. In the second step of the first cycle, the pressure of CO2 is increased until a maximum pressure is reached (fracture is initiated at this moment), and then the injection of CO2 is allowed for another 30 seconds to propagate the fracture. Then, the two-step cycle of PAA followed by CO2 injection (up to 2-4 mL/min) was continued. For the constant flow rate injection strategies, the initial water saturation was increased by injecting water at 1000 psi and 200°C for three days. After that, an initial slug of water, CO2, or PAA was injected and then fracturing was initiated and propagated by injecting CO2 at a constant flow rate. Applications/Significance/Novelty: The results of this study suggest that water saturation, especially near the wellbore region, will significantly affect the fracturing fluid transmission into the rock porous media by changing the relative permeability of CO2 or water, thus affecting the fracture initiation and propagation. In this study, fracturing with cyclic injection or constant flow rate injection methods were performed using three different kinds of fluids systems. These fluids are water, CO2, or CO2 with PAA. Splitting the rock samples in half after fracturing reveals that the fracture propagation is significantly limited under these high water saturated conditions compared to dry initial conditions: The fractures propagate less than 1/3 length of the distance from the wellbore to rock surface, and in some cases no fracture is generated. This may be caused by the fact that leak-off is dominating the fracturing process and the injected fluid flow rate is not high enough to overcome the leak-off even under high flow rate injection conditions. Additionally, CO2 could be leaking off into the wellbore annulus and this may be making it more difficult to generate pressure gradients away from the near-wellbore region.

Jian, Guoqing↗

DOE OSTI2022

Foam Fracturing Study for Stimulation Development of Enhanced Geothermal Systems

This is a final technical report for the project: Foam Fracturing Study for Stimulation Development of Enhanced Geothermal Systems (EGS). The goal is to demonstrate the feasibility of foam fracturing in EGS applications. The project, led by Oak Ridge National Laboratory (ORNL), was conducted in collaboration with Temple University. The report describes the research activities with Task 1 at ORNL: foam fracturing testing system development and experimental study on foam fracturing, and Task 2 at Temple University: foam testing and foam characterization. Main findings are: 1. A foam fracturing test system has been developed at ORNL, which can be used to perform foam fracturing under pressure up to 6,000 psi. The system monitors foam density during fracturing online and is capable of testing materials in both monotonic and cyclic (up to 50 Hz) injections. 2. Foam fracturing tests were carried out on Charcoal black granite specimens with a blind borehole to the middle length. Two diameters of blind borehole were tested; G2 series: 9.53 mm and G3 series: 4.76 mm. N2-in-water foam was used with AOS as a surfactant. 3. There was a hole-size effect on fracture initiation pressure. The effect is smaller in the case of foam, which was influenced by the high penetrability of gas in foam. Breakdown pressure showed a behavior just as that of fracture pressure; namely an increased value for small hole samples, while the effect in water fracture was more impressive than in foam fracture. 4. Water mass was reduced in foam fracturing within similar range of breakdown pressures. In G2 series, it was decreased from 10.44 g for water fracturing to 5.17 g, representing more than 50% water reduction. Therefore, there is the potential to reduce water use in EGS stimulation through foam fracturing. 5. Use of cyclic injection has the potential to reduce the breakdown pressure and seismicity in EGS application. Experiments using 4-s cycle period found that specimens can be fractured with a low number of cycles. The fatigue pressure was approximately 64 - 77% of monotonic breakdown pressure for water fracturing and 58 - 94% of the breakdown pressure for foam fracturing. 6. A foam stability testing system has been developed that can test foam at 220 Deg C to 2,000 psi. Tested components of candidate foams included two gases: N2 and CO2; 4 surfactants: AOS, SDS, NP-40 and CTAC; 5 stabilizing agents: guar, bentonite clay, borate salt, silica NPs, and GO. 7. N2 and AOS provided the most stable performance over the tested ranges. Furthermore, the AOS foam with stabilizing agents of guar and borate salt (crosslinker) offered the highest half-life of 20 minutes at 200 Deg C and 1,000 psi. 8. Arrhenius equation and modified power law have been demonstrated to fit well the half-time vs. temperature and pressure data, respectively. These relations can be useful to provide the suggestion for future foam stability study. This submission contains the supporting data developed during the project: 1) A final technical report 2) Granite fracturing data in monotonic and cyclic injections with water and N2 foam Foam performance data in various temperatures and pressures, including half-time, is submitted separately.

15 GEOTHERMAL ENERGY↗

DOE OSTI2016

Evaluating the effect of internal aperture variability on transport in kilometer scale discrete fracture networks

The apertures of natural fractures in fractured rock are highly heterogeneous. However, in-fracture aperture variability is often neglected in flow and transport modeling and individual fractures are assumed to have uniform aperture distribution. The relative importance of in-fracture variability in flow and transport modeling within kilometer18 scale field–scale fracture networks has been under a matter of debate for a long time because the flow in each single fracture is controlled not only by in-fracture variability but also by boundary conditions. Computational limitations have previously prohibited researchers from investigating the relative importance of in-fracture variability in flow and transport modeling within large-scale fracture networks. We address this question by incorporating internal heterogeneity of individual fractures into 23 flow simulations within kilometer scale three-dimensional fracture networks, where fracture intensity, P32 (ratio between total fracture area and domain volume) is between 0.027 and 0.031 [1/m]. A recently developed discrete fracture network (DFN) simulation capability, dfnWorks, is used to generate DFNs that include in-fracture aperture variability represented by a stationary log-normal stochastic field with various correlation lengths and variances. The Lagrangian transport parameters, non-reacting travel time and cumulative retention, are calculated along particles streamlines. It is observed that due to local flow channeling early particle travel times are more sensitive to in-fracture variability than the tails of travel time distributions, where no significant effect of the in-fracture transmissivity variations and spatial correlation length is observed.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2023

Effect of initial water saturation on the performance of fracturing fluids with and without polyallylamine under simulated EGS conditions

Objectives/Scope: StimuFrac (US Patents 9,873,828 B2 and 9,447,315 B2), a CO 2 - reactive polymer aqueous solution [polyallylamine (PAA) 1wt% in water] combined with CO 2 , can be used as a potentially less water-intensive fracturing fluid for enhanced geothermal systems (EGS). Our previous results show that in hot dry rock (HDR), PAA/CO 2 fracturing fluids outperformed other fluids such as water, CO 2 , and CO 2 /water in generating large fractures with less fluid consumed. The objective of this work is to investigate the effect of initial water saturation on the performance of StimuFrac by conducting hydraulic fracturing tests with ½ foot cubic rock samples held under representative EGS stress/temperature conditions and by using cyclic injection strategies (under constant injection rate). The resulting fracture hydraulic conductivities, breakdown pressures, and volumes of fluids required are compared. Methods/Procedures/Process: To simulate geothermal reservoir conditions, in all tests, the rock sample was held under triaxial confinement and at 200 °C, and different volumes of water were initially injected into the rock sample before any fracturing processes were initiated. For the single-cycle PAA (or water) alternating CO 2 (PAG or WAG) injection fracturing experiments, one complete cycle consisted of two steps: (1) injecting a PAA slug (or water slug) followed by (2) injecting CO 2 to initiate and propagate the fracture. For experiments involving multiple injection cycles, the CO 2 injection pressure is increased until it peaks and begins to decline (indicating fracture initiation at this moment), and then continued being injected for another 30 seconds to propagate the fracture. Then, these two-step cycles [injection of PAA (or water) followed by CO 2 injection (up to 2-4 mL/min)] are repeated. Applications/Significance/Novelty: The results of this study suggest that water saturation significantly affects the fracturing fluid transmission into the rock pore space, thus affecting the fracture initiation and propagation. In this study, fracturing tests via a single injection cycle or multiple injection cycles were performed. Splitting the rock samples in half after testing reveals that fracture propagation is significantly limited under high water saturation conditions (three-day initial water injection) compared to stimulation experiments performed in hot dry rock. The fractures propagate less than 1/3 of the distance from the wellbore to the outer rock surface, and in some cases, no fracture is generated. This may be caused by leak-off dominating the fracturing process and the fluid injection rate is insufficient to overcome leak-off, even under high injection rate conditions. Additionally, CO 2 could be leaking off into the wellbore annulus and this may be making it more difficult to generate sufficiently high-pressure gradients away from the near-wellbore region. Under low water saturation conditions (dry rock or after 1-day initial water injection), PAA/CO 2 consistently generated significantly larger fractures compared with the other fluids. CO 2 generated large fractures only in the hot dry rock and only when using high injection rates, though data variability is high.

58 GEOSCIENCES↗

DOE OSTI2021

Development and Field Testing Novel Natural Gas Surface Process Equipment for Replacement of Water as Primary Hydraulic Fracturing Fluid (Final Report)

Southwest Research Institute® (SwRI ® ), Schlumberger Technology Corporation (SLB), and Chevron Corporation ® (Chevron) developed a novel, optimized, and lightweight process for natural gas (NG) to replace water as a low-cost fracturing medium with a low environmental impact. Hydraulic fracturing is used to increase oil and NG production by injecting high-pressure fluid, primarily water, into a rock formation, which fractures the rock and releases trapped oil and NG. This method was developed to increase yield and make feasible production areas that would not otherwise be viable for large-scale oil and NG extraction using traditional drilling technologies. Since the fracturing fluid is composed of approximately 90% water, one of the principal drawbacks to hydraulic fracturing is its excessive water use and associated large environmental footprint. According to recent data collected at fracture sites within the United States, fracturing applications in North America can consume as much as 9 million gallons of water per well. During the fracturing process, some of the fracturing fluid is permanently lost and the portion that is recovered is contaminated by both fracturing chemicals and dissolved solids from the formation. The recovered water or flow-back represents a significant environmental challenge, as it must be treated before it can be reintroduced into the natural water system. Although there is some recycling for future fracturing, the majority of the flow-back water is hauled from the well site to a treatment facility or to an injection well for permanent underground disposal. To mitigate these issues, an optimized, lightweight and modular surface process using NG to replace a majority of the water was developed as a cost-effective and environmentally clean fracturing fluid. Using NG will result in significantly less consumption since the gas that is injected as a fracturing fluid will be mixed with the formation gas and extracted as if it were from the formation itself. This process will minimize the collection, waste, and treatment of large amounts of water and will reduce the environmental impact of transporting and storing the fracturing fluid. There are two major steps involved in utilizing NG as the primary fracturing medium: (1) increasing the supply pressure of NG to wellhead pressures suitable for fracturing and (2) mixing the required chemicals and proppant needed for the fracturing process at these elevated pressures. The second step (NG-proppant mixing at elevated pressures) still requires demonstration; but very similar processes have been demonstrated in the field with other gases such as nitrogen (N 2 ) and carbon dioxide (CO 2 ). However, the first step (a compact, on-site unit for generating high-pressure NG at costs feasible for fracturing) has not been developed and is currently not commercially available. Due to the inherent compressibility of NG, more energy is required to compress the gas than what is required to pump water (or other incompressible liquids) to the very high pressure required for downhole injection. This project aimed to develop a novel, hybrid method to overcome this challenge. The project accomplishments and findings are discussed in this report. Ultimately, the research and development efforts described herein demonstrate that fracturing with NG foam is a feasible alternative to using water.

02 PETROLEUM↗

DOE OSTI2016

Closure of Fracture Due to Cover Stress Re-establishment After Coal Mining

In situ measurements of deformations, stresses, and closure of fractures, affecting water inflow following coal mining, are challenging due to the inaccessibility of fractured rock. Here, the authors studied the closure process of the fractured rock mass with the cover stress re-establishment based on a theoretical analysis and a scale model testing. A quantitative analysis is used to study the fracture distribution in the fractured zone. A function to describe a fracture aperture distribution in the fractured zone is proposed, which takes into account the curvature and thickness of the fractured rock. The theoretical analysis and a scale model testing both indicate that the cover stress re-establishment with mining distance increasing and the relationship between the fracture closure and cover stress re-establishment both satisfy a logarithmic function. The scale model test also shows the following features: (1) the fracture ratio (which is the fracture area divided by the total area of fracture and intact rock with a unit width in the vertical or horizontal direction) in the lower part of the fractured rock mass is greater than that in the upper part; (2) the initially fast decreased of fracture ratios is then followed by a slower decrease during the cover stress re-establishment process; (3) in the upper part of the rock mass, the vertical directional fractures with small apertures are being closed with cover stress re-establishment, which indicates an increase in the water resistance reducing the seepage from these parts of the fractured zone. This study improves the general understanding of the fracture closure process and cover stress re-establishment in the fractured rock mass after coal mining ceased, and provides a theoretical basis for water resource protection in case of underground coal mining.

58 GEOSCIENCES↗

DOE OSTI2026

Stochastic fracture generation and thermo-hydro-mechanical modeling in an equivalent continuum framework for enhanced geothermal systems

Enhanced geothermal systems (EGS) involve fracturing low permeability material to establish well connectivity and then injecting and circulating fluid into the fractured subsurface for geothermal power production. Changes in fracture aperture from contraction of the cooling matrix rock may alter network connectivity and risk thermal short-circuiting. Thermo-hydro-mechanical (THM) models are a useful tool to study these processes. However, as fracture networks are complex, and data may be limited, fracture networks in THM models are often stochastically generated. Given reliance on stochastic fracture networks and THM modeling to represent the subsurface and assess productivity of EGS, increased understanding of the influence of such statistically derived fracture networks on flow and heat transport in THM models is needed. Here, a new fracture process model is developed in the reactive transport code PFLOTRAN to stochastically generate fracture families and simulate changes in fracture aperture over time due to temperature changes of the rock matrix. Sixty-four different fracture networks ranging from well to poorly-connected, are modeled in PFLOTRAN with and without mechanical processes (THM vs TH). Results indicate that for well-connected fracture networks, thermal short-circuiting is less of a concern due to the abundance of available alternative flowpaths. For poorly-connected fracture networks, inclusion of mechanical processes showed steep thermal drawdown coincident with increase in fracture aperture along developing colder flowpaths, demonstrating the risk of thermal short-circuiting. Simulations with additional, larger fractures engineered to establish connectivity in a poorly-fractured subsurface, indicate that while stochastic variation of fracture orientation of the background network had limited influence, such variation in the engineered fractures significantly affected flow and heat transport.

Discrete fracture networks (DFN)↗

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↗