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Abstract Assessment of in-situ stresses and hydraulic fracturing stimulation are two critical parameters for successful heat extraction from Enhanced Geothermal Systems (EGS). Fracture injection and injection/flow back tests are two conventional techniques for estimating the minimum horizontal stress in subsurface formations. Because of the heat exchange during the test, ultra-low permeability of the host rock, and natural fractures, the conventional methods yield inaccurate results in geothermal reservoirs. In this paper, we present a new methodology based on the signal processing approach for analyzing DFIT in geothermal reservoirs. The applicability of our technique is demonstrated using several test data from the Utah FORGE project. The main advantage of our methodology is that it does not depend on any assumption regarding fracture geometry and rock properties. Also, unlike most similar studies, we consider the effect of heat exchange between fracturing fluid and the hot rock. In our methodology, the recorded pressure and temperature are treated as signals, and a wavelet transform is applied to separate them to high pass (noise) and low pass (approximation) components. Using the noise energy of the two signals, we then identify different events such as fracture closure. Also, an analytical technique is used to correct the pressure by extracting the effect of fluid compressibility and heat exchange between the rock and injected fluid. We show that the G-Function technique underestimates the minimum horizontal stress in tight formations. After applying the corrections for pressure, the underestimation becomes more apparent. However, our approach gives consistent results before and after the pressure correction. Using the developed technique, we analyzed several injection tests from the Utah FORGE project. Both recorded pressure and temperature have been analyzed. Results show that the energy of the pressure signal noise decreases to a minimum level at the fracture closure. The fracture closure is confirmed by applying the same technique on the recorded temperature. The moment of closure using the proposed methodology is compared to the G-function approach, before and after correction of the pressure for temperature. Unlike physics-based techniques, the proposed method does not have any pre-assumption about the fracture's geometry or type of the well. The method solely relies on the pressure and temperature signals that are recorded during the injection and shut-in periods. Combining several analysis techniques to analyze DFIT (including the analysis of monitored temperature for a geothermal reservoir) is unique and maybe the first of its kind.
Xing, P. (Energy & Geoscience Institute, University of Utah) | Goncharov, A. (University of Utah) | Winkler, D. (Red Rocks, Inc.) | Rickard, B. (Geothermal Resource Group) | Barker, B. (University of Utah) | Finnila, A. (Golder Associates) | Ghassemi, A. (Reservoir Geomechanics and Seismicity Research Group, University of Oklahoma) | Podgorney, R. (Idaho National Laboratory) | Moore, J. (Energy & Geoscience Institute, University of Utah) | McLennan, J. (University of Utah)
ABSTRACT During April and early May 2019, injection testing was carried out in three granitic zones in a vertical well at the FORGE site near Milford Utah. The deepest zone was in an uncased openhole region that had also been treated in September 2017. Two cased and perforated intervals farther uphole were also evaluated. In a number of the injection cycles, flowback was implemented rather than shut-in, with the goal of finding an alternative to prolonged shut-in periods for inferring closure stress and formation permeability (transmissibility). The flowback data from the FORGE program involved a progressive increase in the choke size, or cyclic flowback/shut-in while pressure decreased. The flowback data are presented, and analyses are shown. The predictions are compared with equivalent injections that were strictly shut in. Closure signatures are considered, and after flow evaluations – for permeability (transmissibility) determination – are carried out. Flowback potentially has advantages over shut-in because of the reduced time to closure. 1. INTRODUCTION Enhanced Geothermal Systems (EGS) offer the potential to bring low-cost geothermal energy to locations that lack natural permeability through hydraulic stimulation (Moore et al., 2019). The U.S. Department of Energy selected a location near Milford, Utah, as the site for the Frontier Observatory for Research in Geothermal Energy (FORGE). The goal of the FORGE program is to develop the techniques required for creating, sustaining, and monitoring EGS reservoirs. In Sept 2017, an injection program was carried out in the openhole toe of Well 58-32 at the Utah FORGE site (see, for example, Balamir et al., 2018). Well 58-32 is approximately 7500 feet deep with 147 feet of open hole below the production casing shoe. A follow-on injection program was carried out in this same well in April and May, 2019. One of the aims of the 2019 testing program was to evaluate the repeatability of injection into the barefoot section along with the potential for pumping into cased and perforated zones farther uphole. Post-injection measurements were undertaken under shut-in conditions or while flowing back the well. The flowback measurements assessed using previously proposed technology as a substitute for unreasonably long shut-in periods as part of Diagnostic Fracture Injection Testing (DFIT).
Ingraham, M. D. (Sandia National Laboratories) | Schwering, P. C. (Sandia National Laboratories) | Burghardt, J. (Pacific Northwest National Laboratory) | Ulrich, C. (Lawrence Berkeley National Laboratory) | Doe, T. (Tdoegeo) | Roggenthen, W. M. (South Dakota School of Mines & Technology) | Reimers, C. (South Dakota School of Mines & Technology)
ABSTRACT A series of hydrofractures were performed on the 4100 ft. level of the Sanford Underground Research Facility (SURF) to quantify the minimum principal stress and stress orientation. The motivation for this work was to determine the suitability of the site as a second testbed for the EGS Collab project and to inform the testbed design. EGS Collab is a meso-scale project where experiments are being performed to increase permeability in low-permeability rock and improve our understanding of appropriate techniques and models required for developing enhanced geothermal systems. In order to design the second testbed, a ∼50 m vertical HQ (96 mm) pilot borehole was drilled in June, 2019, to perform a series of mini-frac tests to determine the rock stress state. Utilizing an elastic model based on the ISIP (Instantaneous Shut In Pressure), testing indicates that the minimum principal stress is 20.4 MPa oriented NNE (24°) and plunges at an angle of approximately 28°. 1. INTRODUCTION As part of determining a location for Experiment 2 of the EGS Collab project (Kneafsey et al. 2018), a 50 m vertical HQ (96 mm) borehole was drilled on the 4100 level of the Sanford Underground Research Facility (SURF), the borehole is located in an alcove near the Yates shaft (Heise, 2015). This borehole was to be used for a series of tests to determine the feasibility of the location for shear fracture stimulation as part of the Experiment 2 test protocol. As part of the testing, a series of hydraulic fractures were performed throughout the length of the borehole. These were used to determine the minimum principal stress and infer stress direction from the comparison of pre- and post-test borehole logs. 2. ROCK STRUCTURE The rock in question is part of the Yates unit, a heavily folded and metamorphosized amphibolite (Caddey et al., 1991, Hart et al., 2014). This is contrary to the rock type which was used for Experiment one which was the Poorman formation (Oldenburg et al., 2017, Vigilante et al., 2017, Wang et al., 2017), a layer of schist which overlays and the Yates amphibolite. Both formations are steeply dipping, so that even though the tests described here occur at a shallower depth than Experiment one, they are in an underlying formation.
The near-tip behavior of a hydraulic fracture determines the local dynamics of the fracture front, and therefore affects the global fracture geometry. Several physical mechanisms may compete to determine the near-tip behavior. In this paper, we consider the simultaneous interplay of fracture toughness, fluid viscosity, and leak-off, which together cause the solution to vary at multiple scales in the near-tip region. In order to avoid having a mesh size that is able to resolve the finest length scale, an Implicit Level Set Algorithm (ILSA), which uses a suitable asymptotic solution for the tip element to locate a fracture front, is employed. The latter asymptotic solution comes from the analysis of a semi-infinite fracture propagating steadily under plane strain elastic conditions. Equipped with an accurate closed-form approximation for this asymptotic solution, which resolves the effects of the fracture toughness, fluid viscosity, and leak-off at all length scales, we analyze the problem of the simultaneous propagation of multiple parallel hydraulic fractures.
Hydraulic fracturing is a process, in which a pressurized fluid is injected into a rock formation to induce crack propagation. This technology is used primarily to stimulate oil and gas wells , but, in addition, is used for waste disposal , rock mining , as well as for CO2 sequestration and geothermal energy extraction . To increase the efficiency of operation in petroleum applications, multiple hydraulic fractures from different perforations are often generated simultaneously from one well-bore. In this situation, outer fractures induce an additional compressive stresses on inner fractures and cause non-uniform fracture growth. This phenomenon is called stress shadowing and has been addressed in numerous studies [5, 6, 7, 8, 9, 10, 11, 12, 13, 14] to name a few. It can significantly affect the fracture geometry and the associated production rate. For this reason, it is important to develop numerical models that are able to predict simultaneous growth of multiple hydraulic fractures and that can be used to design more efficient hydraulic fracture stimulations.
Summary Reservoir stimulation is commonly used to increase well-production rates and enable economic oil and gas recovery from conventional and unconventional reservoirs. One potential stimulation method that has been laboratory tested as a means to increase well injectivity after conventional hydraulic fracturing is mechanical-impulse hydraulic fracturing (MIHF). MIHF is a high-strain-rate stimulation method that uses a mechanical-energy source as an alternative to rapid gas expansion. Field-scale viability of MIHF was evaluated by use of elastic mechanics and thermodynamics. Results from laboratory tests are presented in which associated flow data indicated significant increases to well injectivity after MIHF stimulation. Tests were performed in two granite specimens with dimensions of 300×300×240 mm and 300×300×300 mm, respectively. The first specimen was unconfined at room-temperature conditions, whereas the second was subjected to heating and true-triaxial confinement. Stimulated well injectivity was evaluated with a series of step-constant-pressure and step-constant-flow injection tests.