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With the advent of advanced information technology and related tools in late 1990s, the scope, nature, and avenues of the business opportunities and its financial perspectives changed. Stabilization and equating of the demand and supply for the sources of inflows and outflows of funds remained the challenges across the industry. The struggling players during this time remained MSMEs due to their limited scale and more importantly limited cushioning capacity to absorb the shocks of financial downs. The micro, small, and medium enterprise (MSME) sector has emerged as a highly vibrant and dynamic sector of the Indian economy over the last five decades. It contributes significantly to the economic and social development of the country by fostering entrepreneurship and generating many employment opportunities at comparatively lower capital cost, next only to agriculture. MSMEs are complementary to large industries as ancillary units, and this sector contributes significantly to the inclusive industrial development of the country.

A diverse suite of numerical simulators is currently being applied to predict or understand the performance of enhanced geothermal systems (EGS). To build confidence and identify critical development needs for these analytical tools, the United States Department of Energy, Geothermal Technologies Office sponsored a Code Comparison Study (GTO-CCS), with participants from universities, industry, and national laboratories. A principal objective for the study was to create a community forum for improvement and verification of numerical simulators for EGS modeling. Teams participating in the study were those representing U.S. national laboratories, universities, and industries, and each team brought unique numerical simulation capabilities to bear on the problems. Two classes of problems were developed during the study, benchmark problems and challenge problems. The benchmark problems were structured to test the ability of the collection of numerical simulators to solve various combinations of coupled thermal, hydrologic, geomechanical, and geochemical processes. This class of problems was strictly defined in terms of properties, driving forces, initial conditions, and boundary conditions. The challenge problems were based on the enhanced geothermal systems research conducted at Fenton Hill, near Los Alamos, New Mexico, between 1974 and 1995. The problems involved two phases of research, stimulation, development, and circulation in two separate reservoirs. The challenge problems had specific questions to be answered via numerical simulation in three topical areas: (1) reservoir creation/stimulation, (2) reactive and passive transport, and (3) thermal recovery. Whereas the benchmark class of problems were designed to test capabilities for modeling coupled processes under strictly specified conditions, the stated objective for the challenge class of problems was to demonstrate what new understanding of the Fenton Hill experiments could be realized via the application of modern numerical simulation tools by recognized expert practitioners. We present the suite of benchmark and challenge problems developed for the GTO-CCS, providing problem descriptions and sample solutions.

Hot water extraction and cold water injection into an underground geothermal reservoir cause mechanical deformation of rock matrix and rock joints/fractures. That leads to alteration of hydraulic transmissivity. To study the evolution of reservoir transmissivity we performed coupled Thermo-Hydro-Mechanical (THM) simulations using a robust code called Finite Element for Heat and Mass Transfer (FEHM) for a 3-D domain with a single fracture connecting the injection and production wells. Rock fracture was modeled as a thin equivalent porous medium. We established dynamic relations between the properties of the equivalent porous medium and fracture aperture. In this paper we discuss the alteration of fracture aperture due to heat extraction. The channeling of flow between injection and production wells by THM effects causes faster temperature drawdown and reduces energy production. The model also predicted fracture opening near injection well and closure at far field locations. We also simulated the aperture alteration for different joint stiffness, thermal expansion coefficients and rock matrix permeabilities. Increase in rock matrix permeability not only causes the leakage of injected water but also increases matrix contraction due to cooling and therefore the aperture growth. Additionally we reported the effect of thermo-poro-elastic deformation on the expansion and contraction of the formation for different reservoir properties. We established that in the early-stages the compaction/expansion of the formation was controlled by pore pressure change but in the late-stage it was controlled by thermal contraction.

The aim of the study was to analyse the financial performance of telecom companies in Oman.Annual reports of two telecom companies were collected for seven years (2010-2016) and the financial statement data was analysed using Z score model. The results of the analysis shows that the performance of Omantel was better than Ooredoo. The present study is a fundamental analysis of telecom companies in Sultanate of Oman. The study can provide an idea for the investors in which company they can make investments to earn more returns. The parameters selected for analysis proves to be useful to an investor for his basic analysis of selecting portfolio of investment.

Interest in geothermal energy production has grown rapidly in recent years due to the increasing demand for clean, renewable, domestic energy. Recent publications have suggested that geothermal energy from Enhanced Geothermal Systems could satisfy a large portion of the energy needs in the U.S. if the technology were implemented on a large scale. Pertinent to this goal are many of the lessons learned from the pioneering Hot Dry Rock project aimed at producing usable energy form the heat of the earth, conducted from 1970 to 1995 at Fenton Hill, New Mexico, USA. During this project, the Los Alamos National Laboratory created and tested two reservoirs at depths in the range of 2.8–3.5 km in crystalline rock formations underlying the Fenton Hill site. Thermal energies in the range of 3–10 MWt were produced demonstrating the technical feasibility of the concept. Many important lessons were learned regarding the creation, engineering and operation of such subsurface systems—these lessons will prove valuable as the geothermal community moves towards the goal of realizing the immense potential of this ubiquitous renewable energy resource. The purpose of this paper is to provide a brief, easy to read overview of this pioneering project.

Flow of undersaturated water in limestone aquifer can cause continuous permeability growth due to dissolution. We have simulated the evolution of permeability field of a 3-D porous limestone aquifer subjected to geothermal temperature gradient and vertical through-flow. The upward flow through porous limestone results in dissolution since calcite is a retrograde soluble mineral. In addition to permeability growth by promoting more dissolution, through-flow also inhibits Rayleigh Benard convection. To understand the temporal evolution of permeability and flow fields, we have performed several simulations with various combinations of initial permeability and through-flow magnitude. Since our computational domain is different in size and boundary conditions from past studies related to buoyant convection in porous medium, we have carried out simulations without reactive alteration to distinguish the hydrothermal systems as stable or unstable. The permeability growth is insignificant in the central part of the reservoir as the temperature gradient vanishes due to forced convection. Permeability growth is more near the edges, where temperature gradients are significant due to conductive heat transfer from the boundaries. For small magnitudes of through-flow, convection rolls are formed near the corners. However, the growth is very localized and rolls never form when magnitude of through-flow is large.

Creation of an Enhanced Geothermal System relies on stimulation of fracture permeability through self-propping shear failure that creates a complex fracture network with high surface area for efficient heat transfer. In 2010, shear stimulation was carried out in well 27-15 at Desert Peak geothermal field, Nevada, by injecting cold water at pressure less than the minimum principal stress. An order-of-magnitude improvement in well injectivity was recorded. Here, we describe a numerical model that accounts for injection-induced stress changes and permeability enhancement during this stimulation. We use the coupled thermo-hydrological–mechanical simulator FEHM to (i) construct a wellbore model for non-steady bottom-hole temperature and pressure conditions during the injection, and (ii) apply these pressures and temperatures as a source term in a numerical model of the stimulation. A Mohr–Coulomb failure criterion and empirical fracture permeability is developed to describe permeability evolution of the fractured rock. The numerical model is calibrated using laboratory measurements of material properties on representative core samples and wellhead records of injection pressure and mass flow during the shear stimulation. The model captures both the absence of stimulation at low wellhead pressure (WHP ≤1.7 and ≤2.4 MPa) as well as the timing and magnitude of injectivity rise at medium WHP (3.1 MPa). Results indicate that thermoelastic effects near the wellbore and the associated non-local stresses further from the well combine to propagate a failure front away from the injection well. Elevated WHP promotes failure, increases the injection rate, and cools the wellbore; however, as the overpressure drops off with distance, thermal and non-local stresses play an ongoing role in promoting shear failure at increasing distance from the well.

Many technical, regulatory and public perception challenges remain to be addressed before large-scale deployment of CO 2 geologic storage becomes a reality. Two major risks associated with injection of CO 2 into the subsurface are the possibility of induced earthquakes compromising long-term seal integrity, and the displacement of saline brines resulting in contamination of shallow groundwater. Both induced seismicity and brine migration are caused by elevated pressures in the storage formation owing to the relative incompressibility of water. Here, we describe a strategy, termed passive injection that can be used to inject large amounts of CO 2 in a storage formation with no increase, temporary or long-term, in reservoir pressure. Passive injection relies on the strategic placement of brine production wells to create negative pressure gradients that result in CO 2 entering the formation at ambient pressure. Injection occurs at the intersection of pressure-depth profiles for a surface-pressurized, low-density CO 2 column and a hydrostatic column of formation fluid. A multi-stage, square-ring well configuration is envisaged, in which brine production wells are repurposed for CO 2 injection upon CO 2 breakthrough, and the next concentric ring of production wells installed at a greater distance. Numerical simulations of passive injection are presented using the coupled thermo-hydro-mechanical (THM), multi-fluid, multi-phase numerical simulator FEHM. We consider CO 2 injection into a 3 km-deep, closed reservoir over a period of 50 years, with up to four stages of injection and production depending on well-spacing and production pressures. Storage rates as high as 4 Mt yr −1 at 70% utilization of the reservoir pore volume are achieved under optimum conditions. Long-term mass production of brine is approximately 1.7 times that of CO 2 sequestered. Geomechanical effects due to reservoir drawdown, cooling near injection wells, and surface subsidence are modeled. The risk of induced seismicity is quantified in terms of the Coulomb Failure Stress (CFS) for an optimally oriented fault in an extensional tectonic regime. Injection and production-induced changes in pressure and CFS confirm that, both during and at the conclusion of injection, (i) reservoir pressure is everywhere less than or equal to its initial value; and (ii) the risk of induced seismicity is everywhere reduced or unchanged. Thus, the primary risks of brine migration outside the primary reservoir and induced seismicity compromising seal integrity are neutralized. Passive injection produces large quantities of brine, the treatment and disposal of which represents an additional economic burden to CO 2 geologic storage operations. Unless additional revenue streams or economies of scale can be leveraged, these costs are likely to limit the viability of the proposed scheme to only the most economically favorable sites.

We present the description of a fully coupled simulator FEHM for modeling coupled thermo-hydro-mechanical (THM) processes in geomedia. The coupled equations for fluid flow and energy transport are implemented using finite volume whereas Galerkin finite element method is used for mechanical force balance. The simulator is designed to address spatial scales on the order of tens of centimeters to tens of kilometers, and time scales on the order of hours to tens of years. The governing coupled nonlinear equations are solved using a Newton–Rapshon scheme with analytically or numerically computed Jacobians. A suite of models is available for coupling flow and mechanical deformation via permeability–deformation relationships. The coupled simulator is verified by comparing with several analytical solutions developed for this purpose. A subset of the simulator capabilities is benchmarked against commercially available simulators. We also demonstrate a good match with data from Desert Peak geothermal field in Nevada, USA. This validation required the use of a shear failure model with non-linear permeability–stress relationship. In addition, we present another application involving fluid injection into an inclined fault zone using a non-orthogonal grid with stress-dependent Young׳s modulus and permeability.

Heat extraction by cold water circulation disturbs the thermo-chemical equilibrium of a geothermal reservoir, activating the dissolution/precipitation of minerals in the fractures. Calcite being a more reactive mineral than other rock minerals composing the earth curst, we investigate the permeability alteration during geothermal heat production from carbonate reservoirs. In this study the simulations are performed using the code FEHM with coupled thermo-hydro-chemical (THC) capabilities for a three dimensional domain. The computational domain consists of a single fracture connecting the injection and production wells. For reactive alteration of aperture, the model considers that the kinetics of dissolution/precipitation is coupled to the equilibrium interactions among the aqueous species/ions. The reaction rate predominantly depends on the temperature dependent solubility and advective-dispersive solute transport in the fracture. Due to the nonuniform flow fields resulting from injection and production, the coupled thermo-hydro-chemical processes initiate significant variation of the aperture alteration rate over the fracture. We have considered different operating conditions such as different mass injection rate, injection temperature and concentration of minerals. Our simulations show that dissolution and precipitation can occur simultaneously at different locations in fracture. Furthermore the reaction rate varies with time and the reaction rate can also switch between dissolution and precipitation. To illustrate this interesting behavior, the variations of shape and size of zero reaction rate contours with time are shown. An interesting outcome is a non-monotonic evolution of the overall transmissivity between the wells. The alteration of overall transmissivity largely depends on the concentration of mineral in the injected water with respect to the solubility at the initial fracture temperature. For both dissolution and precipitation controlled cases, the rapid changes in transmissivity provide challenges for maintaining circulation of water at constant mass flow rate. � 2013 Elsevier Ltd.

Recent experiences with large-scale injection of fluids into geological formations within the Oil & Gas, Geothermal and Waste Disposal industries have demonstrated a risk of induced seismicity. In the case of geological sequestration of CO2, reactivation of faults may result in leakage pathways for the buoyant plume and thus compromise the integrity of seal formations. In this study, we investigate the potential for an overpressured reservoir formation to cause deformation and mechanical failure in an overlying, low-permeability caprock, thereby compromising seal integrity. In particular, we show that uplift and associated extensional strain in the caprock lead to a reduction in the minimum horizontal principal stress that reinforces the ambient extensional tectonic stress. Changes in the Coulomb failure stress (ΔCFS) characterize the tendency for fault failure. We use normalized and ΔCFS-weighted frequency distributions as an integrated measure of the 3-D distribution of ΔCFS. These measures quantify the magnitude and nature of the risk of induced seismicity. Using the example of the Springerville-St. Johns CO2 reservoir as an analogue site, we explore the sensitivity of the induced seismic risk to caprock stiffness, reservoir overpressure and well configuration. Over a range of these parameters, we calculate the geomechanical response of a large reservoir over a ten-year period of injection. The magnitude of induced stresses within the caprock is approximately 1–2 MPa for typical overpressures of 5–10 MPa, even in regions where the low-permeability caprock prevents appreciable increases in pore pressure. These stresses would be sufficient to cause reactivation of an undetected, well-oriented, critically stressed structure present above or near the injection location. Importantly, we show that this occurs outside a sphere of influence delineated by sub-surface pressure increase.

Assessment of potential CO 2 and brine leakage from wellbores is central to any consideration of the viability of geological CO 2 sequestration. Depleted oil and gas reservoirs are some of the potential candidates for consideration as sequestration sites. The sequestration sites are expected to cover laterally extensive areas to be of practical interest. Hence there is a high likelihood that such sites will contain many pre-existing abandoned wells. Most existing work on wellbore integrity has focused on field and laboratory studies of chemical reactivity. Very little work has been done on the impacts of mechanical stresses on wellbore performance. This study focuses on the potential enhancement of fluid flow pathways in the near-wellbore environment due to modifications in the geomechanical stress field resulting from the CO 2 injection operations. The majority of the operational scenarios for CO 2 sequestration lead to significant rise in the formation pore pressure. This is expected to lead to an expansion of the reservoir rock and build-up of shear stresses near wellbores where the existence of cement and casing are expected to constrain the expansion. If the stress buildup is large enough, this can lead to failure with attendant permeability enhancement that can potentially provide leakage pathways to shallower aquifers and the surface. In this study, we use a numerical model to simulate key features of a wellbore (casing, annulus and cement) embedded in a system that includes the upper aquifer, caprock, and storage aquifer. We present the sensitivity of damage initiation and propagation to various operational and formation parameters. We consider Mohr-Coulomb shear-failure models; tensile failure is also likely to occur but will require higher stress changes and will be preceded by shear failure. The modeling is performed using the numerical simulator FEHM developed at LANL that models coupled THM processes during multi-phase fluid flow and deformation in fractured porous media. FEHM has been developed extensively under projects on conventional/unconventional energy extraction

We present a preliminary model of geomechanical failure in wellbore systems induced by elevated pore- pressure following injection of CO 2 . The model is a coupled flow and geomechanics and operates on 2-D and 3- D detailed representations of the wellbore environment. We find that failure occurs at over-pressures of 6-7 MPa and that subsequent flow of water and/or CO 2 relieves pressure in the injection reservoir.

The trend toward unstructured grids in subsurface flow modeling has prompted interest in the issue of streamline or pathline tracing on unstructured grids. Streamline tracing on unstructured grids is problematic because a continuous velocity field is required for the calculation, while numerical solutions to the groundwater flow equations provide velocity in discretized form only. A method for calculating flow streamlines or pathlines from a finite-volume flow solution is presented. The method uses an unconstrained least squares method on interior cells and a constrained least squares method on boundary cells to approximate cell-centered velocities, which can then be continuously interpolated to any point in the domain of interest. Two-dimensional tests demonstrate that the method correctly reproduces uniform and corner-to-corner flow on fully unstructured grids. In three dimensions using regular hexahedral grids, the method agrees well with established semianalytical methods. Tests also demonstrate that the method produces physically realistic results on fully unstructured three-dimensional grids.

This report is being prepared under the FY14 activity FT-14LA0818069, Mechanical and Hydrological Behavior of the Near-Field Host Rock Surrounding Excavations, and fulfills the Los Alamos National Laboratory deliverable M4FT-14LA08180610, which in PICS:NE is titled “Draft report, Test Plan for Mechanical and Hydrological Behavior of the Near-field Host Rock Surrounding Excavations.” Since the report is an intermediate deliverable intended as input to the eventual test plan for this test, rather than being an actual test plan, the activity title is used as the title of this document to avoid confusion as to the contents in the report. This report summarizes efforts to simulate mechanical processes occurring within a hypothetical high-level waste (HLW) repository in bedded salt. The report summarizes work completed since the last project deliverable, “Coupled model for heat and water transport in a high level waste repository in salt “, a Level 2 milestone submitted to DOE in September 2013 (Stauffer et al., 2013).

We present thermo-hydro-chemical simulations of silicic geothermal reservoirs over 20 year durations. For injection of undersaturated or oversaturated water with respect to the solubility of amorphous silica, the highest rates of reactive alteration occur at some distance away from the injection well. This is largely because the temperature dependence of the reaction rate plays a much greater role than temperature dependent solubility. For oversaturated injection, precipitation occurs in a band, confining the flow system to smaller areas. For undersaturated injection, dissolution causes permeability growth far from the injection well, resulting in longer flowpaths that prevent short-circuits, which implies favorable conditions for sustained energy production. Initial permeability heterogeneity influences reservoir response significantly only when the correlation lengths are of the order of 1/10th of the fracture size or more. � 2015 Elsevier Ltd.

Using an analogy to the classical Stefan problem, we construct evolution equations for the fluid pore pressure on both sides of a propagating stress-induced damage front. Closed form expressions are derived for the position of the damage front as a function of time for the cases of thermally-induced damage as well as damage induced by over-pressure. We derive expressions for the flow rate during constant pressure fluid injection from the surface corresponding to a spherically shaped subsurface damage front. Finally, our model results suggest an interpretation of field data obtained during constant pressure fluid injection over the course of 16 days at an injection site near Desert Peak, NV., Comment: 30 pages, 5 figures

This paper presents a study of solute transport through ground water in the saturated zone and the resulting breakthrough curves (BTCs), using a field-scale numerical model that incorporates the processes of advection, dispersion, matrix diffusion in fractured volcanic formations, sorption, and colloid-facilitated transport. Such BTCs at compliance boundaries are often used as performance measures for a site. The example considered here is that of the saturated zone study prepared for the Yucca Mountain license application. The saturated zone at this site occurs partly in volcanic, fractured rock formations and partly in alluvial formations. This paper presents a description of the site and the ground water flow model, the development of the conceptual model of transport, model uncertainties, model validation, and the influence of uncertainty in input parameters on the downstream BTCs at the Yucca Mountain site.

Results of drilling, logging, and testing of three exploration core holes, combined with results of geologic and hydrogeochemical investigations, have been used to present a reservoir model of the Platanares geothermal system, Honduras. Geothermal fluids circulate at depths ≥ 1.5 km in a region of active tectonism devoid of Quaternary volcanism. Large, artesian water entries of 160 to 165°C geothermal fluid in two core holes at 625 to 644 m and 460 to 635 m depth have maximum flow rates of roughly 355 and 560 l/min, respectively, which are equivalent to power outputs of about 3.1 and 5.1 MW(thermal). Dilute, alkali-chloride reservoir fluids (TDS ≤ 1200 mg/kg) are produced from fractured Miocene andesite and Cretaceous to Eocene redbeds that are hydrothermally altered. Fracture permeabillity in producing horizons is locally greater than 1500 and bulk porosity is ≤ 6%. A simple, fracture-dominated, volume-impedance model assuming turbulent flow indicates that the calculated reservoir storage capacity of each flowing hole is approximately 9.7 × 106 l/(kg cm−2), Tritium data indicate a mean residence time of 450 yr for water in the reservoir. Multiplying the natural fluid discharge rate by the mean residence time gives an estimated water volume of the Platanares system of ≥ 0.78 km3. Downward continuation of a 139°C/km “conductive” gradient at a depth of 400 m in a third core hole implies that the depth to a 225°C source reservoir (predicted from chemical geothermometers) is at least 1.5 km. Uranium-thorium disequilibrium ages on calcite veins at the surface and in the core holes indicate that the present Platanares hydrothermal system has been active for the last 0.25 m.y.

This paper presents a literature survey of the occurrences of radionuclide plumes in saturated, fractured rocks. Three sites, Idaho National laboratory, Hanford, and Oak Ridge are discussed in detail. Results of a modeling study are also presented showing that the length to width ratio of a plume starting within the repository footprint at the Yucca Mountain Project site, decreases from about 20:1 for the base case to about 4:1 for a higher value of transverse dispersivity, indicating enhanced lateral spreading of the plume. Due to the definition of regulatory requirements, this lateral spreading does not directly impact breakthrough curves at the 18 km compliance boundary, however it increases the potential that a plume will encounter reducing conditions, thus significantly retarding the transport of sorbing radionuclides.

A computer code is described which can simulate non-isothermal multiphase multicomponent flow in porous media. It is applicable to natural-state studies of geothermal systems and ground-water flow. The equations of heat and mass transfer for multiphase flow in porous and permeable media are solved using the finite element method. The permeability and porosity of the medium are allowed to depend on pressure and temperature. The code also has provisions for movable air and water phases and noncoupled tracers; that is, tracer solutions that do not affect the heat and mass transfer solutions. The tracers can be passive or reactive. The code can simulate two-dimensional, two-dimensional radial, or three-dimensional geometries. A summary of the equations in the model and the numerical solution procedure are provided in this report. A user`s guide and sample problems are also included. The main use of FEHMN will be to assist in the understanding of flow fields in the saturated zone below the proposed Yucca Mountain Repository. 33 refs., 27 figs., 12 tabs.

[1] A general form of the dispersion tensor is derived for axisymmetric porous media involving four dispersivity coefficients corresponding to longitudinal and transverse dispersion in horizontal and vertical directions, defined as perpendicular and parallel to the axis of symmetry, respectively. The general form of the dispersion tensor provides for distinct vertical and horizontal longitudinal dispersivity values. Transverse dispersion is isotropic for flow parallel to the symmetry axis and anisotropic for flow perpendicular to the symmetry axis with distinct horizontal and vertical transverse dispersivities. The new form of the dispersion tensor is applied to several examples involving axisymmetric media utilizing particle tracking techniques and compared to the tensor proposed by Burnett and Frind [1987]. It is demonstrated that for the case of spatially variable flow the drift term ∇ · (ϕD)/ϕ must generally be included in the particle tracking algorithm to obtain accurate results.

At the Fenton Hill Hot Dry Rock Geothermal Project in the United States, more than ten hydraulic fracturing experiments have been conducted to stimulate a hot dry rock reservoir. Two hydraulic fracturing attempts, Exp. 2059 and Exp. 2062, successfully established a large fracture system connecting an injection well, EE-3A and a production well, EE-2. The fracture systems created by the two experiments showed different fracture extension pressures. In order to understand the combined behavior of fractures, thecomputer code FEHM was used to simulate the two layered fracture system. As in part 1 of this series of papers, an exponential relation between fracture aperture and fracture pressure was used. Parameters in the modelwere fitted to simulate specificexperiments.In this paper, the parameters were chosen to fit the data obtained from each experiment described above. The extension of each fracture was then estimated using these parameters at a constant flow rate, 0.8m3/min. Next, the fracture extension is simulated when water is pumped into the combined two-layer fracture system. From the computer simulation, the following results are obtained.1. When two fractures with different characteristics obtained by experiments 2059 and 2062 extend at the same time by pumping water at a fixed flow rate of 0.8m3/min, the higher permeability fracture (Exp. 2059: upper fracture) extends almost at the single fracture rate, while thefracture of Exp. 2062 (lower fracture) which has lower permeability extends at half the single fracture rate. The wellhead fracture extension pressure is only 0.5MPa less than that when upper fracture extends alone.2. By doubling the flow rate and keeping other parameters constant, both fractures extended faster and the lower fracture showed a marked increase in fracture extension rate. The results suggest that if we try to make multiple fractures along openhole section in an effort to create a large artificial reservoir, it is advisable to use the largest flow rate allowable under the given conditions.

A 30-day closed-loop circulation test of the Phase II Hot Dry Rock reservoir at Fenton Hill, New Mexico, was conducted to determine the thermal, hydraulic, chemical, and seismic characteristics of the reservoir in preparation for a long-term energy-extraction test. The Phase II heat-extraction loop was successfully tested with the injection of 37,000 m/sup 3/ of cold water and production of 23,300 m/sup 3/ of hot water. Up to 10 MW/sub t/ was extracted when the production flow rate reached 0.0139 m/sup 3//s at 192/degree/C. By the end of the test, the water-loss rate had decreased to 26% and a significant portion of the injected water was recovered; 66% during the test and an additional 20% during subsequent venting. Analysis of thermal, hydraulic, geochemical, tracer, and seismic data suggests the fractured volume of the reservoir was growing throughout the test. 19 refs., 64 figs., 19 tabs.

At Los Alamos National Laboratory, more than ten hydraulic fracturing experiments have been conducted to stimulate a hot dry rock reservoir. Two hydraulic fracturing attempts, Exp. 2059 and Exp. 2062, successfully established a large fracture system connecting an injection well, EE-3A, and a production well, EE-2. The initial closed loop flow test (ICFT) is planned (from May through June, 1986) to get information on volume impedance and temperature of the reservoir. The fracture systems created by the two experiments show characteristics that are different from each other.

The deepest EE-3A interval stimulated during Expt. 2061 did not connect to EE-2, but rather extended a fractured region downwards some 300 m below the bottom of EE-3A. Therefore, the decision has been made to abandon for now the bottom 600 feet of EE-3A, and to stimulate the three flowing fractures between 12,050 ft and 12,200 ft identified by temperature logging prior to Expt. 2059 (our successful Memorial Day reservoir connection experiment).

Abstract In cooperation with Tiffany Gas Company, Terra Tek cored the Fruitland Formation coal, lying at approximately 3100 feet, in the Glover Well #1 drilled in the southeast quarter of Section 2, T32N, R6W, Archuleta County, Colorado, within the northern portion of the San Juan Basin. The coal was fully water saturated. Laboratory tests were performed on the recovered cores and reservoir engineering tests within the coal before and after underreaming. Production data indicates the need to treat the coal with a deeply penetrating fracture to achieve acceptable gas production. penetrating fracture to achieve acceptable gas production. However, coal fines migration is a serious problem to maintaining high production. Introduction In-place methane in excess of 186 trillion cubic feet (tcf) is estimated to exist within unmineable coalbeds (depths greater than 3,000 feet) in the forty-eight lower states. Over ninety percent of the coal in this category is found in the five western states of Colorado, Wyoming, New Mexico, Utah and Washington. A large fraction of the gas is adsorbed on internal coal surfaces and pressure must be reduced for it to desorb. For water saturated coal, water must be produced to lower pressure and thereby to initiate produced to lower pressure and thereby to initiate desorption. Production of methane from coal for the gas industry is in its infancy; information regarding reservoir characteristics to assist in the establishment of well completion techniques, well spacing, and evaluation of coalbed methane production economics is totally unavailable. production economics is totally unavailable. Under the Gas Research Institute (GRI) funding, Terra Tek in cooperation with Tiffany Gas Company performed a field test program in the Fruitland performed a field test program in the Fruitland Formation coal to provide specific knowledge on resource potential and characteristics at a selected site and to identify a well completion technique. The paper summarizes the experience gained in the performance of this project. Tiffany Gas Company, a company formed to recover gas from coal, was planning to drill a well to the Cretaceous, Fruitland Formation coals, in the northern San Juan Basin and agreed to provide Terra Tek access to their well. Teaming provide Terra Tek access to their well. Teaming with Tiffany Gas provided the added benefit of working with a company whose purpose was to commercially produce gas from coal. This allowed for production history data to be obtained beyond the production history data to be obtained beyond the immediate duration of the research program. The well, Glover Well #1, is located in the southeast quadrant of Section 2, T32N, R6W, Archuleta County, Colorado, in a region considered to be a prime target area for recovery of occluded gas; see Figure 11. The site location is immediately north of the small community of Allison, Colorado, and a few miles outside the present limits of proven natural gas production from the Cretaceous sandstones. The target was a medium volatile bituminous coal at a depth of approximately 3100 feet with a net thickness of 25 feet. Reservoir pressure was 1500 psi and the temperature 120 deg. F. SITE EXPLORATION The Pictured Cliffs sandstone, underlying the Fruitland Coal Formation (see Figure 2), was deposited during the final retreat of the Upper Cretaceous Sea from the San Juan Basin. Immediately shoreward of these sands, widespread coastal swamps paralleled the shoreline and accumulated thick sequences of vegatal material with inter-bedded clastics. The still-stands of the sea are now represented by thick units of Pictured Cliffs sand and thick Fruitland Formation coals in the northeast part of the San Juan Basin. Contours for the top of the Pictured Cliffs sandstone, as deduced from geophysical logs in the vicinity of the Glover Well #I, are shown in Figure 3. Note that the well is anticipated to be at the base of a shallow syncline. The expected gross thickness of coal within the lower 100 feet of the Fruitland Formation is shown in Figure 4. P. 417