Utah FORGE (Frontier Observatory for Research in Geothermal Energy) is a field laboratory for developing, testing, and prototyping technologies that could be adopted for commercializing Enhanced Geothermal Systems (EGS). The principle of developing an EGS is to use multiple hydraulic fracturing stages to interconnect an injection well and a production well – forming the surface area within a large heat exchange system. At the Utah FORGE site, near Milford, Utah, an injection well (65° to the vertical) has been drilled and a three-stage fracturing treatment was carried out at the toe of this well. A production well will be drilled into the stimulated domain determined from microseismic measurements. The objectives of the treatments were to establish if the created fracture networks will form independent flow networks between the injector and the producer, and ultimately to test long-term connectivity between the two wells. In addition, the mechanics of isolating stages and developing fracturing fluid viscosity in a naturally fractured granitic reservoir at 435°F [224°C] were evaluated. Three stages were pumped. Geophones in three offset wells and shallow distributed acoustic sensors (DAS) and surface monitoring devices tracked the fracture evolution. The first stage was slickwater in a barefoot section, pumped at rates up to 50 bpm [7.95 m3/min]. Bridge plugs were used in 7-inch [177.8 mm] casing to isolate the next two stages, which each used a single long perforation cluster (20 ft [6.096 m] long, with six shots per ft at 60° phasing for each of the latter two stages). The second stage was slickwater pumped at rates up to 35 bpm [5.56 m3/min]. The final stage was crosslinked carboxymethyl hydroxypropyl guar (CMHPG) polymer fluid pumped at rates up to 35 bpm [5.56 m3/min] with low concentrations of microproppant. The well was flowed back between each stage to mitigate the potential for stage interference, facilitate running bridge plugs, and reduce the possibility of undesirable microseismicity. Isolation technology had been a significant concern before the treatment. However, bridge plugs successfully functioned at these high temperatures – isolating stages 1 and 2 and stages 2 and 3. Treatment records show a significant morphological difference between pumping in the openhole section (stage 1), and in the two cased and perforated zones (stages 2 and 3). Microseismic data suggest nominally planar growth orthogonal to the wellbore for the two cased and perforated zones – favoring intersection with the soon-to-be-drilled production well. These treatments superficially seem mundane. However, they successfully demonstrated the viability of hydraulic fracture creation in a cased well in hot, low permeability granitic rocks, a prerequisite for EGS development, revealed conditions for limited natural fracture interaction, and this was one of the few high-temperature granitic stimulation treatment programs since Fenton Hill in the 1980s.

It was the first time that single well injection and withdrawal(SWIW) tracer tests were conducted in a low temperature Enhanced Geothermal System (EGS) well in Taiwan in an attempt to identify the tracers that can react well within the fractures of metamorphic rocks. Various tracers including Naphthalene Disulfonates, Safranin O, and Amino Family were first tested in the laboratory and then in the field. In the laboratory, 2,6-nds was found to behave conservatively on slate samples taken from the Yilan geothermal field, whereas Amino G and Amino C were found to adsorb reversibly (R-f = 1.39 and 1.10) at 90 degrees C and could serve as suitable tracers. Three types of breakthrough curves were found, suggesting a significant and extensive in situ groundwater flow exists at a depth of 1500 m.

The Habanero Enhanced Geothermal System (EGS) in central Australia has been under development since 2002, with several deep (more than 4000 m) wells drilled to date into the high-heat-producing granites of the Big Lake Suite. Multiple hydraulic stimulations have been performed to improve the existing fracture permeability in the granite. Stimulation of the newly-drilled Habanero-4 well (H-4) was completed in late 2012, and micro-seismic data indicated an increase in total stimulated reservoir area to approximately 4 km(2). Two well doublets have been tested, initially between Habanero-1 (H-1) and Habanero-3 (H-3), and more recently, between H-1 and H-4. Both doublets effectively operated as closed systems, and excluding short-term flow tests, all production fluids were re-injected into the reservoir at depth. Two inter-well tracer tests have been conducted: the first in 2008, and the most recent one in June 2013, which involved injecting 100 kg of 2,6-naphthalene-disulfonate (NDS) into H-1 to evaluate the hydraulic characteristics of the newly-created H-1/H-4 doublet. After correcting for flow hiatuses and non-steady-state flow conditions, tracer breakthrough in H-4 was observed after 6 days (compared to similar to 4 days for the previous H-1/H-3 doublet), with peak breakthrough occurring after 17 days. Extrapolation of the breakthrough curve to late time indicates that approximately 60% of the tracer mass would eventually be recovered (vs. approximately 80% for the 2008 H-1/H-3 tracer test). This suggests that a large proportion of the tracer may lie trapped in the opposite end of the reservoir from H-4 and/or may have been lost to the far field. The calculated inter-well swept pore volume is approximately 31,000 m(3), which is larger than that calculated for the H-1/H-3 doublet (similar to 20,000 m(3)). A simple 2D TOUGH2 tracer model, with model geometry constructed based on the current conceptual understanding of the Habanero EGS system, demonstrates good agreement with the measured tracer returns in terms of timing of breakthrough in H-4, and observed tracer dispersion in the tail of the breakthrough curve. Crown Copyright (C) 2015 Published by Elsevier Ltd. All rights reserved.

The objective of this project was to develop and demonstrate a new class of tracers that offer great promise for use in characterizing fracture networks in EGS reservoirs. From laboratory synthesis and testing through numerical modeling and field demonstrations, we have demonstrated the amazing versatility and applicability of quantum dot tracers. This report summarizes the results of four years of research into the design, synthesis, and characterization of semiconductor nanocrystals (quantum dots) for use as geothermal tracers.

A combination of optical absorption and scattering is used to detect tracer species in a strongly scattering medium. An optical setup was developed, consisting of a dual-beam scattering detection scheme in which sample scattering beam overlaps with the characteristic absorption feature of quantum dot tracer species, while the reference scattering beam is outside any absorption features of the tracer. This scheme was successfully tested in engineered breakthrough tests typical of wastewater and subsurface fluid analysis, as well as in batch analysis of oil and gas reservoir fluids and biological samples. Tracers were detected even under highly scattering conditions, conditions in which conventional absorption or fluorescence methods failed.

A series of column transport experiments ranging from 25 degrees C to 275 degrees C, as well as batch sorption experiments at 25 degrees C, were conducted to estimate cation exchange parameters for lithium and cesium at the Newberry Crater Enhanced Geothermal System demonstration site. The experiments were designed to facilitate interpretation of single-well field tracer tests to interrogate fracture surface area. Lithium column transport from 125 degrees C to 275 degrees C showed a strong temperature dependence, with much greater cation exchange at higher temperatures than in 25 degrees C experiments. Cesium column transport at 225 degrees C indicated a weaker temperature dependence, and unlike Li+, its exchange decreased at higher temperatures. Published by Elsevier Ltd.

Starting in 2008, a 4-year tracer study was conducted to evaluate ambient changes in groundwater concentrations of a 1,3,6-naphthalene trisulfonate tracer that was added to drill water. Samples were collected under open borehole conditions and after installing a multilevel groundwater monitoring system completed with 11 discrete monitoring zones within dense and fractured basalt and sediment layers in the eastern Snake River aquifer. The study was done in cooperation with the U.S. Department of Energy to test whether ambient fracture flow conditions were sufficient to remove the effects of injected drill water prior to sample collection. Results from thief samples indicated that the tracer was present in minor concentrations 28 days after coring, but was not present 6 months after coring or 7 days after reaming the borehole. Results from sampling the multilevel monitoring system indicated that small concentrations of the tracer remained in 5 of 10 zones during some period after installation. All concentrations were several orders of magnitude lower than the initial concentrations in the drill water. The ports that had remnant concentrations of the tracer were either located near sediment layers or were located in dense basalt, which suggests limited groundwater flow near these ports. The ports completed in well-fractured and vesicular basalt had no detectable concentrations.

Geochemical tracers have been used for many years to improve the understanding of reservoir dynamics in geothermal systems. Tracers can be classified as either conservative or reactive, and can be used in liquid-phase, vapour-phase or two-phase reservoirs at temperatures up to and above 300°C. They are commonly used to map flow pathways between injection and production wells in a geothermal field, to monitor the effects of reinjection and identify wells that might experience premature thermal breakthrough if left unmanaged. Tracer tests also provide information about reservoir fluid residence time, fluid recharge location or direction, swept pore volumes, interwell connectivity, temperatures, fracture surface area, flowstorage capacity relationships and volumetric fluid sweep efficiencies. In addition, tracer data can be used with numerical transport codes to help validate 2D or 3D reservoir models. Thus, tracer tests can provide powerful insight into geothermal reservoir characteristics, and they can be performed at many stages of project development, from small-scale demonstration projects (e.g. an injectionproduction well doublet) through to large-scale commercial fields (e.g. Wairakei, New Zealand). New ‘smart’ tracers have the potential to be used with a single well to evaluate changes in fracture surface area following reservoir stimulation, and thus have applications to both conventional and unconventional (engineered) geothermal projects.

Fluorescent nanocrystals are promising candidates for a range of applications, ranging from biomedical imaging and sensing to solar energy conversion and lighting. Recently, these nanometer-sized semiconductor crystals (also referred to as “quantum dots”) have shown potential to be used as novel geothermal reservoir tracer particles. Quantum dots have size-dependent, tunable electronic and optical properties that make them promising candidates for use as tracers in geothermal fields. In this study, organic molecules were investigated as quantum-dotsurface-stabilizing ligands in order to create watersoluble nanocrystals that behave as conservative tracers in geothermal media. More extensive modification of the surface chemistry of nanocrystals could also make them attractive materials for reactive tracers. The thermal stability of organic-ligandstabilized core/shell quantum dots under simulated geothermal conditions was studied through autoclave experiments at temperatures exceeding 150 oC. These tests looked for degradation, agglomeration, and solubility, all of which would alter the optical properties of the tracers. Quantum dot behavior and response was also tested in flow-through reactors packed with geothermal media using in-line fluorometers, and compared to conventional tracers.

This report describes a 10-year DOE-funded project to design, characterize and create an Engineered Geothermal System (EGS) through a combination of hydraulic, thermal and chemical stimulation techniques. Volume 1 describes a four-year Phase 1 campaign, which focused on the east compartment of the Coso geothermal field. It includes a description of the geomechanical, geophysical, hydraulic, and geochemical studies that were conducted to characterize the reservoir in anticipation of the hydraulic stimulation experiment. Phase 1 ended prematurely when the drill bit intersected a very permeable fault zone during the redrilling of target stimulation well 34-9RD2. A hydraulic stimulation was inadvertently achieved, however, since the flow of drill mud from the well into the formation created an earthquake swarm near the wellbore that was recorded, located, analyzed and interpreted by project seismologists. Upon completion of Phase 1, the project shifted focus to a new target well, which was located within the southwest compartment of the Coso geothermal field. Volume 2 describes the Phase 2 studies on the geomechanical, geophysical, hydraulic, and geochemical aspects of the reservoir in and around target-stimulation well 46A-19RD, which is the deepest and hottest well ever drilled at Coso. Its total measured depth exceeding 12,000 ft. It spite of its great depth, this well is largely impermeable below a depth of about 9,000 ft, thus providing an excellent target for stimulation. In order to prepare 46A-19RD for stimulation, however, it was necessary to pull the slotted liner. This proved to be unachievable under the budget allocated by the Coso Operating Company partners, and this aspect of the project was abandoned, ending the program at Coso. The program then shifted to the EGS project at Desert Peak, which had a goal similar to the one at Coso of creating an EGS on the periphery of an existing geothermal reservoir. Volume 3 describes the activities that the Coso team contributed to the Desert Peak project, focusing largely on a geomechanical investigation of the Desert Peak reservoir, tracer testing between injectors 21-2 and 22-22 and the field's main producers, and the chemical stimulation of target well 27-15.

Fractures are important conduits for fluids in geothermal systems, and achieving and maintaining fracture permeability is a fundamental aspect of EGS (Engineered Geothermal System) development. Hydraulic or chemical stimulation techniques are often employed to achieve this. In the case of chemical stimulation, an understanding of the minerals present in the fractures themselves is desirable to better design a stimulation effort (i.e. which chemical to use and how much). Borehole televiewer surveys provide important information about regional and local stress regimes and fracture characteristics (e.g. aperture), and XRD is useful for examining bulk rock mineralogy, but neither technique is able to quantify the distribution of these minerals in fractures. QEMSCAN ® is a fully-automated micro-analysis system that enables quantitative chemical analysis of materials and generation of high-resolution mineral maps and images as well as porosity structure. Initial applications of QEMSCAN ® technology were predominantly in the minerals industry and application to geothermal problems has remained limited to date. In this pilot study, the application of QEMSCAN ® technology to fracture characterization in geothermal systems was evaluated using samples from Newberry Volcano (Oregon) and Brady‟s geothermal field (Nevada). QEMSCAN ® results

A new simple one-step method based on a biphasic solution route has been developed for encapsulating quantum dots (QDs) within a silica shell and transferring them into water. Our method keeps the photoluminescence properties (color and brightness) of core/shell CdSe/ZnS QDs intact as well as their UV-visible absorption characteristics. The effectiveness of ODs transfer into water was found to be strongly dependent on the silica precursor conditions. After silica-coating, QDs exhibited increased robustness to high pressure and temperature conditions tested by a hydrothermal treatment. This work provides a new approach to coat QDs with silica, which is simpler than current methods.