Penrose Abstracts




ANDERSON, Tom, Energy & Geoscience Institute, University of Utah, Salt Lake City, UT

Currently developed hydrothermal systems are a significant energy source, but these systems have limited geographic extent. EGS has the potential to drill into hot crystalline rock and create fractured reservoirs suitable for water injection and production cycles. However, a challenge to the economics of these systems is the drilling and fracturing cost. “Co-production” of geothermal energy associated with oil operations has been demonstrated successfully at Teapot Dome. However, this approach has yet to be embraced by the oil industry.

A potential new path toward expanded geothermal energy production is to use known porous and permeable reservoir rocks in appropriate sedimentary basins, where those packages of rocks have sufficient temperature, thickness, porosity, and permeability, existing at depths that are not so great that drilling costs make the potential system uneconomic.

For this study, 17 basins in the western U.S. have been examined. Stratigraphic columns were compiled, including unit depths, thicknesses, and thermal profiles. Target reservoir sections at appropriate depths and temperatures have been evaluated with respect to porosity and permeability, primarily from available core data, supplemented with wire-line log analysis. For screening purposes, thresholds of < 4 km depth and > 125 °C temperatures were applied to meet economic targets.

Based on this work, basins meeting the criteria are the Williston, Denver, Great Basin, Fort Worth, Raton, Sacramento, Gulf Coast, and Imperial Valley. However, when considering permeability, based on reservoir data evaluated so far, the potential reservoir rocks in the Raton and the Williston basins don’t exhibit minimum acceptable permeability (approx. 50-100 md). The areal extent of the targets for the Raton, Fort Worth and the Sacramento Basins probably also limit them. The best basins identified for future study and potential pilot projects are the Great Basin, Denver, and Gulf Coast.


AUGUSTINE, Chad, National Renewable Energy Laboratory, Golden, CO 80439,

Parametric analysis of the factors controlling the costs of sedimentary geothermal systems was carried out using a modified version of the Geothermal Electricity Technology Evaluation Model (GETEM). The sedimentary system modeled assumed production from and injection into a single sedimentary formation. The parameters varied in the study were the reservoir temperature (165‑190oC/320-375oF), drilling depth to reservoir (3,000-5,000 km/10,000-16,500 ft), reservoir well productivity index (2-30 L/s/bar / 1,100-16,400 lb/h/psi), and production-to-injection well ratio (1:1 and 2:1). Drilling costs were estimated using the default drilling cost curves in GETEM, and a power plant with 30 MWe net power sales was assumed. As one would expect, preliminary results show that costs increase as depths increase, temperatures decrease, and the productivity index decreases. The production-to-injection well ratio was not found to have a large impact on costs. Still, a large number of scenarios were found to have overnight capital costs estimates below $6,000/kW, even for productivity indices as low as 3.3 L/s/bar or less, with the most-favorable scenarios approaching $4,000/kW. The analysis found that the performance of down hole pumps on the production wells will be key to realizing these systems. When the production well flow rate is unrestricted, the model results show production well flow rates of up to 280 kg/s (5,100 gpm) for production wells. However, limiting production well flow rates to 165 kg/s (3,000 gpm) only moderately increases capital costs and still results in a large number of cases with capital costs below $6,000/kW. The preliminary results will be used to inform reservoir-performance requirements for detailed sedimentary reservoir modeling.

Pre-exploration geothermal resource assessment for the Raton Basin, Colorado — The rest of the story

BOHLEN, Karoline, Colorado School of Mines, Geophysics Department, Golden CO  80401,

Coal bed methane production in the Colorado portion of the Raton Basin results in large quantities of co-produced hot water, suggesting geothermal power production requirements may be met in the basin.  Research for this potential commenced on a study area in Las Animas County bounded on the west by the Culebra Range and on the east by the city of Trinidad. Herein presented are the methodology and results of the research using literature, well, and rock data that suggest 2030 MW heat capacity in a very small (0.25 km3) engineered geothermal system (EGS).  The Sangre de Cristo Formation (SdC Fm) was chosen as a potential geothermal reservoir due to its depth and volume.  Thin-sections reveal very little clay material, suggesting good fracturing potential.  Detailed lithologies of the SdC Fm offer insight to its stratification, possibly offering good directional fluid flows.  In general, water migration and surfacing to the east provides for higher heat flows in the east.  This could possibly be causing the underpressured nature of the basin, even at the depths of the SdC Fm.  To this end, special focus must be on fluid movement for extraction and re-injection.  Further exploration is required to locate the best drilling area(s) for development of an EGS power plant.  Continued research on logistics and public feedback may also lead to consideration of supplemental or standalone direct heat use and development.


BRADFORD, Jacob, MCLENNAB, John, Department of Chemical Engineering, University of Utah, Department of Chemical Engineering, 50 S. Central Campus Dr. Rm 3290, Salt Lake City, UT 84112, USA, , MOORE, Joseph, Energy & Geoscience Institute at the University of Utah, Energy & Geoscience Institute, 423 Wakara Way Suite 300, Salt Lake City, UT 84108, USA

The Raft River geothermal field, located in Cassia County, in southwestern Idaho is the site of a Department of Energy Enhanced Geothermal System project. Well RRG-9 ST1 is the target well for this project and is currently undergoing a thermal stimulation program with a hydraulic stimulation to come later this fall. In an effort to better understand how thermal stimulations affect an enhanced geothermal reservoir Idaho National Laboratory’s finite element modeling software FALCON is being modified to model the injection operations. Substantial data have been collected from wireline logging, borehole imaging, and injection testing at RRG-9 ST1. These measurements facilitate estimating rock material properties and prescribing feasible locations and orientations of naturally occurring fractures around the wellbore. Using information gained from borehole imaging a discrete fracture network, DFN, consisting of 73 fractures was generated using Golder Associates Inc. program FracMan. This DFN covers an area roughly 92,903 m2 and 91 m in height around the RRG-9 ST1 wellbore. Instead of meshing each fracture individually the fractures are treated as material properties in the mesh – an equivalent continuum approach. This approach has several advantages. First, adaptive meshing can be used so that only areas of interest are finely meshed. This enables efficient use of computing resources. Second, using an equivalent medium allows fractures to propagate during the simulation without having to make fundamental changes to the mesh. As the thermal stimulation of Raft River continues the resulting data are also being analyzed using conventional produced water injection methods, including a modified Hall’s technique which highlights how each stage of the cold water injection is affecting the injectivity. These analyses allow numerical simulations to be interactively used to assess the effectiveness of injection and to delineate potential improved techniques.


BUURSINK, Marc L., U.S. Geological Survey, National Center MS-956, 12201 Sunrise Valley Dr., Reston, VA  20192,

The U.S. Geological Survey (USGS) recently completed a geologic basin-scale assessment of technically accessible storage resource (TASR) for carbon dioxide (CO2) in onshore and State waters area of the United States.  In part, TASR is limited by the geothermal and pressure gradient, and by the distribution of deep formation water (e.g. brine) in the basin being assessed.  The current USGS methodology defines a storage assessment unit (SAU) as a mappable volume of rock that consists of a porous reservoir and a bounding regional sealing formation. Reservoirs assessed are at least 3,000 feet (914 meters) below ground surface because below this depth temperatures and pressures typically maintain stored CO2 in a supercritical state, and maximize storage resource per unit volume (i.e. density).  Using published equations of state, subsurface CO2 density in SAUs may be computed using geothermal and pressure gradients in deep sedimentary basins.  A geothermal gradient expresses the change of reservoir temperature, which typically increases with depth, but which can vary considerably both within and between basins.  In sedimentary rocks, pressure commonly increases along the hydrostatic gradient because the pore space is mostly filled with water and may be connected along a complex path to the surface.  Nevertheless, in many basins pressure may be greater than the hydrostatic gradient prediction resulting in overpressure of the SAU.  The opposite condition, underpressure, may also exist, either as a result of fluid withdrawals, geologic structure, outcrop locations or surface topography.  However, the required large-scale of this current USGS assessment necessitated estimation of gross basin-averaged gradients that do not necessarily account for local variations in temperature and pressure.  Furthermore, previous studies suggest that temperature affects CO2 density more than pressure; and therefore in overall cool basins the optimum pressure and temperature regime for supercritical CO2 storage occurs shallower than in warm basins.

Aside from subsurface temperature and pressure limits, U.S. Environmental Protection Agency regulations for injection prohibit CO2 storage in potential sources of drinking water with a total dissolved solids (TDS) concentration less than 10,000 mg/L.  In the current USGS methodology, the SAU boundary is limited, independent of depth, by the distribution of formation water with TDS concentrations below this limit.  In practice, defining the low-TDS zone for exclusion from the SAU is complicated.  For example at the basin-scale, water-quality data (when available and reliable) may indicate that some formations, and therefore SAUs, contain highly variable TDS concentrations.  To improve the next round of TASR estimates, more information is needed on temperature, pressure, and formation water prediction.  The USGS is also investigating the resource linkage between CO2 storage and EOR (enhanced oil recovery), and potential geothermal energy generation.


CORBEL, S.1,2, SCHILLING, O.3 , HOROWITZ, F.G.1,5,*, REID, L.B.1,2,5, SHELDON, H.A.1,2, TIMMS, N.E.1,4, WILKES, P.1,2

1. Western Australian Geothermal Centre of Excellence, Kensington WA 6151, Australia

2. CSIRO Earth Sciences and Resource Engineering, PO Box 1130, Bentley WA 6102, Australia

3. Institute of Environmental Engineering, Swiss Federal Institute of Technology Zurich (ETH), Wolfgang-Pauli- Str. 15, CH-8093 Zürich, Switzerland

4. Department of Applied Geology, Curtin University, Bentley WA 6102 Australia

5. University of Western Australia, Crawley WA 6009, Australia

Faults are important for understanding geothermal systems due to their influence on the stratigraphic structure, and how that structure influences fluid flow. A new workflow has been developed by the Western Australian Geothermal Centre of Excellence (WAGCoE) to identify a fault network in urban areas and generate a 3D model of subsurface geology. The approach involves testing inferred fault models against progressively more complex data types.

We apply this methodology to create a series of new geological models of the Perth Metropolitan Area (PMA). One model involves significant flexure of the stratigraphic layers adjacent to the faults, and the other model involves stiffer stratigraphic layers and consequently larger fault displacements. Each model is consistent with the constraints from well data and gravity data, geologically plausible, and yet produces slightly different aquifer geometries.

The new faulted model is applied to calculate temperature and fluid flux in a three-dimensional hydrothermal model of the Perth Metropolitan Area. Fault locations, offsets, and properties greatly influence hydrogeologic recharge areas and the pattern of hydrothermal convection cells.

Application of Radar Interferometry to the detection of surface deformation

ENEVA, Mariana and ADAMS, David, Imageair Inc, 600 Greensburg Circle, Reno, NV 89509, U.SA., and FALORNI, Giacomo and MORGAN, Jessica, TRE Canada Inc., Suite #410 475 W. Georgia St., Vancouver, BC V6B 4M9, Canada

Interferometric synthetic aperture radar (InSAR) applied to satellite data can be used to detect and measure surface deformation. Examples are shown from a project with the California Energy Commission (CEC), in which we use 2003-2010 Envisat data collected over Imperial Valley in southern California. The study area is characterized by ongoing regional extension due to the relative movement of the Pacific and North American plates, localized tectonic deformation associated with fault networks, Colorado River-derived sediments, high heat flow, significant earthquakes and seismic swarms, and aseismic slip. A technique developed at TRE Italy, SqueeSARTM, makes use of permanent and distributed sctatterers to identify surface displacements amidst the agricultural fields of the region, where conventional InSAR techniques do not work. Displacement is first identified in the line-of-sight (LOS) toward or away from the satellite. The availability of data from two orbital geometries, where the satellite moves north to south (descending) and south to north (ascending), makes it possible to combine the two LOS sets and decompose them into vertical and east horizontal movements. Surface deformation is detected within all current geothermal fields – Salton Sea, Heber, North Brawley and East Mesa. Ground-based annual leveling measurements available for the Salton Sea and Heber fields agree well with the SqueeSAR measurements. Differential movements on both sides of faults associated with ongoing fault movements (Superstition Hills, San Andres, and Imperial) are also observed. In addition, triggering effects on the Superstition Hills fault are detected from a nearby April 2010 M7.2 earthquake and from an October 2006 local aseismic event. The SqueeSAR technique is also effective elsewhere, for monitoring of oil fields, underground gas storage, and CO2 sequestration – examples from TRE will be shown.


FOX, Don, School of Chemical and Biomolecular Engineering, Cornell University, Ithaca, NY 14853,

An analysis of the U.S. thermal energy demand shows large opportunities for the expansion of geothermal energy for direct use applications less than 260C. The greater implementation of geothermal energy will have to rely on engineered discretely fractured reservoirs. Because these reservoirs are conduction dominated, prolonged use will locally deplete the reservoir and put a burden on the surface installation. A heat farming strategy can be carried out in which a fresh reservoir is used while the original reservoir is allowed to thermally recover. To better maintain and manage these geothermal reservoirs, it is imperative to model the thermal hydraulics during both extraction and recovery phases. A simple reservoir model was used to derive analytical equations for multiple extraction and recovery phases. The equations show that recovery is initially fast, but the deviation from the initial rock temperature eventually falls as one over the square root of time. Thus, future extraction operations will still retain the signature of the extracted heat from previous operational phases.

A numerical model was constructed that is capable of handling a varying aperture field, changes in thermophysical properties, buoyancy, multiple intersecting fractures, etc. Simulations show that fracture roughness will more likely result in adverse rather than beneficial flow channeling. The constructed numerical model will be used as a platform for modeling conservative and reactive tracers to identify reservoir characteristics like flow channeling and the distribution of thermally depleted regions. Information from tracer tests will be valuable in running and maintaining a geothermal reservoir.


GAN, Quan, ELSWORTH, Derek, Department of Energy and Mineral Engineering, EMS Energy Institute and G3 Center, Pennsylvania State University, University Park, Pennsylvania, 16801,

We explore the issue of fault reactivation induced in Enhanced Geothermal Systems (EGS) reservoirs by fluid injection. Specifically we investigate the role of late stage activation by thermal drawdown. We use a THM (Thermal-Hydrological-Mechanical) simulator that incorporates elastic-plastic behavior on the fault and uses a ubiquitous joint model. We apply this new THM model to systematically simulate the seismic slip of a critically-stressed strike-slip fault embedded within the reservoir. We examine the effects of both pore pressure perturbation and thermal shrinkage stress on the magnitude of the resulting events and their timing. We analyze the sensitivity of event magnitude and timing to changes in the permeability of the fault and fractured host, fracture spacing, injection temperature, and fault stress obliquity. From this we determine that: (1) the fault permeability does not affect the timing of the events nor their size, since fluid transmission and cooling rate is controlled by the permeability of the host formation. (2) When the fractured medium permeability is reduced (e.g. from 10-13 to 10-16 m2), the timing of the event is proportionately delayed (by a corresponding three orders of magnitude), although the magnitude of the seismic event is not impacted by the change in permeability. (3) Injection temperature has little influence on either the timing or size of the early hydro-mechanically induced events, but it does influence the magnitude but not the timing of the secondary thermal event. The larger the temperature differences between that of the injected fluid and the ambient rock, the larger the magnitude of the secondary slip event. (4) For equivalent permeabilities, changing the fracture spacing (10m-50m-100m) primarily influences the rate of heat energy transfer and thermal drawdown within the reservoir. Smaller spacing between fractures results in more rapid thermal recovery but does not significantly influence the timing of the secondary thermal rupture.


GEISER, Peter, Global Microseismic Services, 1625 Broadway, Denver, CO 80202, LEARY, Peter, Institute of Earth Science & Engineering, University of Auckland, 58 Symonds St, Auckland 1142, New Zealand MALIN, Peter, Institute of Earth Science & Engineering, University of Auckland, 58 Symonds St, Auckland 1142, New Zealand

TFI is a proven method for direct 4D mapping of transmissive fracture/fault networks with over 50 successful projects completed for the Oil and Gas industry. TFI uses SET to capture the weak but spatially and temporally coherent seismic emissions of transmissive fracture/fault damage zones. TFI works by utilizing two phenomena of the Earth’s brittle crust.

1. The near critical state where stress drops ≤ 0.01 bar are associated with failure.

2. Fluid pressure (Pf) waves created by changes in Pf that propagate through transmissive networks for distances that can be at the kilometer scale and at velocities of 10s of meters/second.

TFI differs from hypo-central techniques in two ways:

1. It can extract objective images of the actual fracture/fault surfaces themselves thus eliminating the need for the highly subjective interpretation of hypo-central clouds.

2. It uses high sampling rates (1ms) and stacking rather than standard hypo-central location techniques. Stacking from seconds to hours allows the signal of the weak seismicity of the fracture damage zones to emerge.

TFI has proven X,Y accuracy of as much as +/- 5m. In all cases (>20) where independent evidence for the location of transmissive fracture/faults existed, TFI results were confirmed. As an example of TFI we show a movie sequence of 1 minute intervals during which a Pf wave induced by a frac moved along a natural transmissive fairway to intersect a 2nd well over 700 m from the treatment well. The Pf wave preceded the arrival of the fluid in the well intersected by the fairway by 2 stages.


HENRY, Stephen, School of geology, West Virginia University, 98 Beechurst Ave Morgantown, WV 26506; SHARMA, Shikha, School of Geology, West Virginia University, 98 Beechurst Ave Morgantown, WV 26506; CRANDALL, Dustin, National Energy Technology Laboratory, 3610 Collins Ferry Rd Morgantown, WV 26507; and HAKALA, Alexandra, National Energy Technology Laboratory, 626 Cochrans Mill Road Pittsburgh, PA 15236

The use of carbon and oxygen isotopes is an effective way to monitor water-rock interactions in complex geothermal environments.  This study focuses on the use of carbon and oxygen isotopes in identifying geochemical reactions in a series of core flow-through experiments within an emulated geothermal environment.  Cores taken from depths of 4457’ to 4787.5’ have been obtained by the National Energy Research Technology Laboratory (NETL) from well BCH #3 in Brady’s Hot Springs, Churchill County, Nevada.  High resolution carbon and oxygen isotopic analysis of individual cores was carried out at the Stable Isotope laboratory at West Virginia University. Preliminary carbon and oxygen isotope mapping of fracture fills and groundmass in individual cores prior to flow-through experiments indicates that the cores are isotopically heterogeneous.  Hence, we propose to utilize distilled water isotopically enriched in 18O for the first set of flow-through experiments to understand if artificially enriched water can serve as an effective tracer for monitoring fluid rock interactions.  This research is part of a larger collaborative research effort between National Energy Technology Laboratory, Penn State, University of Pittsburgh, and West Virginia University. Our aim is to utilize reactive transport modeling, CT imaging, mineralogy, geochemistry, stable isotopes and non-traditional heavy isotopes to determine relative changes in the heat transfer rate and fracture transmissivity of the rock. Understanding these changes can provide insight into reservoir performance and longevity as well as demonstrating the application of specific isotopes as tracers in Enhanced Geothermal Systems at the field scale.



HUANG, Hai, PLUMMER, Mitch, and PODGORNEY, Robert, Idaho National Laboratory, PO Box 1625, MS2107, Idaho Falls, ID83415,

We have developed a physics-based rock deformation and fracture propagation simulator by using a quasi-static discrete element model  (DEM) to model rock mechanical deformations and fracture propagations induced by thermal stress and fluid pressure changes. We also developed a network model to simulate fluid flow and heat transport both fractures and porous rock. In this talk, the DEM model and network flow & heat transport model are coupled together to provide more physics-based simulations of the changes of apertures and permeability of fractures and fracture networks induced by thermal cooling and fluid pressures changes within fractures. Various important processes, such as Stokes flow and convective heat transport in the apertures, heat exchanges between fluid in fractures and solid rock across fracture surfaces, heat conductions through nonpermeable solid and associated mechanical deformations are all incorporated into the coupled model. The effects of the confining stress, magnitude of thermal stress, and injection pressure on the permeability evolution of fracture and fracture networks are investigated systematically. The potential of thermal fracturing and fracturing patterns will also be discussed.


ICENHOWER, Jonathan, Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA 94720,, JUNG, Yoojin, Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA 94720, PETRO, Miro, Palo Alto Research Center, 3333 Coyote Hill Road, Palo Alto, CA 94304, DOBSON, Patrick, and XU, Tianfu, Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA 94720.

Because of its low viscosity and lack of reactivity, supercritical carbon dioxide is a viable candidate for a heat exchange medium in geothermal reservoirs. As geothermal brine is displaced by supercritical CO2, mixing between the two fluids results in an acidified solution that causes faster dissolution rates of minerals common in subsurface formations. We investigated, through experiments and modeling, the dissolution behavior of kaolinite, chlorite and amphibole. Experiments were conducted using column-type reactors at a total (He) pressure of 1200 psi over a variety of CO2 partial pressures (49 to 1000 psi) and temperatures (90 to 180°C). An automated High-Pressure Liquid Chromatography system, connected to the reactor system on-line, was used to quantify the release of Na, K, Mg and Ca from the test minerals to the solution. A scanning electron microscope was used to evaluate changes in grain textures and to determine if new mineral phases precipitated.  Dissolution rates determined experimentally were compared against modeling results obtained using the TOUGHREACT ECO2h simulator and published thermodynamic and kinetic data. The simulations were used to estimate mineral reactive surface areas – these were typically different from those determined through BET measurements. In addition, these simulations were used to model the in-situ pH and to ascertain the saturation state of the solution with respect to carbonate phases. Kaolinite dissolves faster with increasing temperature for every experimental condition, as expected, but rates are inversely correlated with pCO2. In contrast, chlorite and amphibole dissolve faster with both increasing temperature and pCO2. The kaolinite results are likely influenced by the saturation state of the solution and underscore the need for experimental geochemistry to unravel complex and unexpected results.


KELLEY, Shari A., New Mexico Bureau of Geology and Mineral Resources, New Mexico Tech, Socorro, NM 87801,

Geothermal prospects in the Raton Basin (RB) and the San Juan Basin (SJB) are evaluated using equilibrium (ET), bottom hole (BHT), and wireline (WT) temperature data that were compiled and digitized during the construction of New Mexico’s contribution to the National Geothermal Database System.   ET logs are generally from shallow wells (<600 m in the RB; <2150 m in the SJB); interval geothermal gradients generally correspond to lithology, which is indicative of conductive heat flow. Interval geothermal gradients are 40-60°C/km in Cenozoic and Mesozoic shales and are 20-30°C/km in sandy units. BHT data constrain the deeper thermal structure of the basins.  High BHTs were measured in the Stubblefield Canyon gas field in the RB near the Colorado border; the maximum uncorrected BHT is 135 °C at a depth of 2160 m and associated geothermal gradients are 50-80°C/km.  BHTs in the Las Vegas Basin (LVB) located to the south of the RB are lower (85°C at 3091 m) compared to those in the RB at similar depths. The difference in temperature between the RB and the LVB is attributed to (1) elevated heat flow associated with low velocity mantle beneath the RB, and (2) erosion of low thermal conductivity Cretaceous shales from the LVB.  Overall, the SJB is also cooler than the RB; the maximum BHT is 160°C at a depth of 4400 m in the SJB and the background geothermal gradient is 23-35°C/km.  Spatial trends in temperature at a given depth are not obvious in the BHT or WT data from the SJB, but the ETs increase toward the north.


KING, Dan, AAAS Science and Technology Policy Fellow/Geothermal Technologies Office, U.S. Department of Energy, Washington, DC 20585, and STILLMAN, Greg, Geothermal Technologies Office, U.S. Department of Energy, Washington, DC 20585

The National Geothermal Data System (NGDS) is a distributed data system providing access to information resources related to geothermal energy from a network of data providers. Data are contributed by academic researchers, private industry, and state and federal agencies. Data housed within the NGDS can be shared among these stakeholder communities, enabling geothermal analysis and widespread public use in an effort to reduce the risk of geothermal energy development. The U.S. DOE’s Geothermal Technologies Office (GTO) utilizes the NGDS to share data and project results among researchers and the greater community. To accomplish this goal of data interoperability among the entire geothermal community, a meaningful Data Content Model, the vehicle by which data is collected and disseminated, needs to be developed. The GTO is seeking input and contributions from the SedHeat Penrose Conference attendees in the development of a Data Content Model for sedimentary hosted geothermal systems. Your inputs and feedback will lead to a well-documented community data structure that enables widespread exchange of subsurface information.  Additionally, the NGDS Data Content Model will have a role in the GTO’s emerging play fairway analysis activities. One of the first steps in the play fairway analysis will be the compilation of relevant geologic and geophysical data. This compilation phase should utilize the NGDS. Feedback is sought for how to logically organize various classes of data (i.e. geophysical vs. geochemical) and how to incorporate multiple scales of field observation.


LARKING, A., BALLESTEROS, M., Green Rock Energy Ltd., OPPERMANN, R., OPPtimal Exploration and Development Pty Ltd., MEYER, G., MCDAIRIMID, J., Green Rock Energy Ltd.,

Green Rock Energy Limited is targeting natural fracture permeability in sediments in the North Perth Basin (NPB) in Western Australia for geothermal energy production for power generation. The Company holds eight geothermal exploration Permit areas (the Mid-West Geothermal Project) occupying over 2,000km2 in the north Perth Basin which the Company considers contain geothermal resource potential for electrical power generation.  The NPB is a sedimentary succession up to 6 kilometres deep located at the northern end of the Perth Basin, a north-south trending 1,000 km long rift basin which formed during the Permian to Early Cretaceous.  These Permits areas are located near oil and gas fields, close to power infrastructure in a region with rapid growth of power demand where there is an extensive power distribution network.

The NPB displays the necessary ingredients of a geothermal system for the successful development of a hot sedimentary aquifer (HSA) geothermal power development based on both matrix and fracture permeability type plays.  The NPB is an active oil and gas exploration and production province with extensive 2D and 3D seismic surveys there and over 250 petroleum wells.  Petroleum well data proves that temperatures in excess of 150°C can be reached at depths less than 3500m.  The most significant risk is identifying a zone with sufficient transmissivity to allow geothermal waters to be produced at commercially viable flow rates.

Work completed to date shows naturally occurring open fractures provide the best opportunity for intersecting a reservoir with the required transmissivity.  Fault and fracture orientations most likely to be critically stressed and open and permeable have been modelled based on the local stress regime in the NPB.  Interpretation of borehole image logs provides data on the orientation of resistive and conductive fractures observed in the area.

This information is being utilised to focus the seismic interpretation of 3D seismic data in order to identify a low risk drilling target.  The application of new structural volume interpretation techniques in the NPB indicates that fault and fracture networks can be delineated at high resolution from seismic data.  The integration of these seismic fracture networks with well and other data allows identification of areas with favourable fault orientations and densities that will significantly increase the chances of intersecting a suitable conduit for geothermal fluid production and ensure the potential for a successful HSA geothermal project.


MAYHEW, Brett, FAULDS, James E., Mackay School of Earth Sciences and Engineering, University of Nevada, Reno, NV, 89557,

The Astor Pass geothermal system resides in the northwestern part of the Pyramid Lake Paiute Reservation, on the margins of the Basin and Range and Walker Lane tectonic provinces in northwestern Nevada. Seismic reflection interpretation, detailed analysis of well cuttings, stress field analysis, and construction of a 3D geologic model have been used in the characterization of the stratigraphic and structural framework of the geothermal area. The area is primarily comprised of middle Miocene Pyramid sequence volcanic and sedimentary rocks, nonconformably overlying Mesozoic metamorphic and granitic rocks. Wells drilled at Astor Pass show a ~1 km thick section of highly transmissive Miocene volcanic reservoir with temperatures of ~95°C. Seismic reflection interpretation confirms a high fault density in the geothermal area, with many possible fluid pathways penetrating into the relatively impermeable Mesozoic basement. Stress field analysis using borehole breakout data reveals a complex transtensional faulting regime with a regionally consistent west-northwest-trending least principal stress direction. Considering possible strike-slip and normal stress regimes, the stress data were utilized in a slip and dilation tendency analysis of the fault model, which suggests two promising fault areas controlling upwelling geothermal fluids. Both of these fault intersection areas show positive attributes for controlling geothermal fluids, but hydrologic tests show the ~1 km thick volcanic section is highly transmissive.  Thus, focused upwellings along discrete fault conduits may be confined to the Mesozoic basement before fluids diffuse into the Miocene volcanic reservoir above. This large diffuse reservoir in the faulted Miocene volcanic rocks is capable of sustaining high pump rates. Understanding this type of system may be helpful in examining large, permeable reservoirs in deep sedimentary basins of the eastern Basin and Range and the highly fractured volcanic geothermal reservoirs in the Snake River Plain.


MORGAN, Paul, Colorado Geological Survey, 1500 Illinois St., Golden, CO 80401,

To extract maximum heat from a reservoir with minimum temperature drawdown, fluid should flow through as much rock as possible as slowly as practicable.  These conditions are in conflict with the need to have sufficient flow at the surface to produce electricity economically.  In simplistic terms the fluid-flow rate is described by Darcy’s Law: Q = –KA∂h/∂l: Q is fluid flow, K is hydraulic conductivity, A is cross-sectional area, and ∂h/∂l is hydraulic gradient.  Hydraulic conductivity is a rock parameter and cannot be changed, but sedimentary strata may be selected that often have a high K, such as sandstone, limestone and dolomite.  Hydraulic gradient is a function of pumping rate.  Cross-sectional area varies along flow path, but in general is smallest close to the well bore.  In traditional EGS systems where the production and injection wells are connected by a limited number of fractures, or in strata with a high hydraulic conductivity, A may be relatively small:  The flow may be economically acceptable, but as the fluid contacts only a limited volume of rock, temperature drawdown may be rapid.  Flow through relatively low hydraulic conductivity strata, such as fine-grain sandstones, may be unacceptably low primarily because of high resistance to flow close to the wellbore.  However, using near wellbore stimulation this resistance may be reduced, as in traditional hydrocarbon well stimulation.  The area in Darcy’s Law may be increased to an economically acceptable level for both the production and injection wells.  Flow between wells would be through a large volume of low hydraulic conductivity rock with low K balanced in Darcy’s Law by the large area A.


NEWELL, Dennis L.,, Department of Geology, Utah State University, Logan UT, 84322 J., CAREY, William, and BACKHAUS, Scott, Los Alamos National Laboratory, Los Alamos, NM 87545.

CO2 injection into deep aquifers for sequestration or resource extraction will result in buoyant bodies of supercritical (sc) CO2 trapped beneath cap-rock seals. The potential for CO2 leakage along wellbore defects or fracture zones greatly increases the risk to shallow groundwater quality. Ionic trapping of scCO2 due to dissolution greatly reduces this risk. However, based on diffusion alone, this process is extremely slow. Density-driven mixing is postulated to greatly accelerate the scCO2 mass transfer. This has been the subject of many computational studies but very few experimental studies.

Here the scCO2-water system was studied using a modified autoclave filled with porous media. Experiments were conducted at 40-90oC. Combinations of temperature and water column height were used to simulate reservoirs with Rayleigh numbers from 5,500 – 11,300, similar to many deep saline aquifers. High-pressure liquid CO2 was injected rapidly in the top of the vessel until the desired pressure (20 MPa) was reached. This process simulated placement of a CO2 plume at the top of an aquifer. As CO2 dissolved into the water, the system volume decreased, and to maintain constant pressure, water was injected at the bottom, providing a measure of CO2 mass transfer. Results showed early rapid dissolution (diffusion plus organization of convective fingers), followed by a period of constant flux (convection) that transitioned to a period of slowing dissolution until system saturation (convection slowing as fingers reach base of the vessel). During the convective period, the mass transfer of CO2 was 20–75 times faster than diffusion alone.


LISA PASQUINELLI, Technical University of Denmark DTU spaceDept of Mathemethical  Geoscience and MOSEGAARD, Klaus, Technical University of Denmark DTU space Dept of Mathemethical  Geoscience

In this project we will develop new technology to improve planning of energy storage in geothermal reservoirs through high-quality experiments and modeling. Geothermal reservoirs have high temperature, so energy may be stored in these geological layers with minimal heat loss.  The focus will be on Danish geothermal reservoirs, because heat storage is likely to be the missing link in planning sustainable energy production in Denmark, where several sources of energy should interplay.  By storing energy at low heat loss in hot aquifers we obtain an effective interplay between different sources of energy, so that the degree of coverage with sustainable energy can increase at an acceptable cost.  How the reservoirs will react to the introduction of water with a higher temperature than the natural?  How will the reservoir rock react chemically and mechanically, how will the heat and fluid distribute in the reservoir, what is the energy loss related to this storage method?  The goal of the PhD project is to develop new mathematical and numerical methods to analyze geophysical data and well production data with the aim of investigating flow, heat transport and heat conduction in geothermal reservoirs and make a new mathematical model of the reservoir.  Structure and properties of geothermal reservoirs can be investigated by means of two different methods:  The first method is seismic inversion, where seismic waves generated by near-surface explosions or in boreholes, and reflected from geological structure in the reservoir, are analyzed. From these data, structure and mechanical/elastic properties of the reservoir can be calculated.  The second method is to combine all the geological and geophysical data to create models with the help of mathematical modeling ( algorithms, optimization, numerical calculations). From these models we can calculate all the properties of rocks which we are interested in.


PAN, Feng, Energy & Geosciences Institute, University of Utah, Salt Lake City, UT 84108,;  MCPHERSON, Brian, Department of Civil and Environmental Engineering, University of Utah, Salt Lake City, UT and KASZUBA, John, Geology & Geophysics, University of Wyoming, Laramie, WY.

Supercritical CO2 has been suggested as a heat transmission fluid in enhanced geothermal system (EGS) instead of water due to its favorable fluid dynamics properties. It is indispensable to understand the geochemical processes of CO2-fluid-rock interactions at high temperature and pressure in EGS reservoirs. The objectives of this work are: (1) to calibrate the reactive surface area of the minerals based on the batch experiments; (2) to evaluate the effects of geochemical processes of fluid-rock reactions on the energy extraction rate, carbon sequestration and mineral alteration. The batch simulations are conducted to mimic the laboratory experiments of CO2-water-grainite geochemical reactions conducted by LoRé et al. (2012) using TOUGHREACT code. The parameter estimation and calibration tool (iTOUGH2-PEST) is coupled with TOUGHREACT code to calibrate the reactive surface area of the minerals against the experiment data of major ion concentrations. A 3-D numerical model is setup to simulate the CO2-fluid-rock geochemical interactions in EGS reservoirs. We also evaluate the it effects on the energy extraction rate, geological CO2 sequestration, and mineral alteration with CO2 as a working fluid for EGS reservoirs. The calibrated reactive surface area of the minerals could be few orders of magnitude different from the measured ones by the BET method. The 3-D simulation results shows the net heat extraction rates with CO2 as a working fluid are much larger compared to water, indicating CO2 as a working fluid could enhance energy extraction. The geochemical processes of CO2-rock interaction have significant effects on mineral dissolution and precipitation but limited effects on the enhance of energy extraction. Precipitation of carbonate minerals demonstrates the favorable for CO2 geological storage.

Hydrothermal reservoir characteristics of Calcalpine carbonates based on lithofacial and rock fracture Properties

WEGERER, Eva, Department Applied Geological Sciences and Geophysics, Chair of Petroleum Geology, University of Leoben, Peter-Tunner-Strasse 5, 8700 Leoben, Austria, Europe,

Middle- and Upper Triassic Calcalpine platform carbonates, building up the basement of the Vienna Basin (Austria), reveal hydrothermal reservoir potential due to petrophysical and thermophysical properties, lateral and horizontal continuity as well as the depth of the layers. The regarded basin represents a Tertiary pull-apart basin along a step-over of a sinistral fault system at the transition zone between the Eastern Alps and the Western Carpathians. Synsedimentary tectonics formed a large fault system, separating an elevated zone with a rather hydrodynamic system from a depression zone showing largely hydrostatic conditions. The complex fault networks are associated with tectonical processes from Eocene to Quaternary. Concerning the thermophysical properties (e.g. thermal conductivity, thermal diffusivity, heat capacity) and geomechanical properties (e.g. the response to uniaxiale compressive strength) the different types of carbonates showed variability dependent on lithofacial characteristics, rock fabrics, mineralogical composition, fracture porosity and the distribution of interparticle porosity. A central issue for the estimation of the hydraulic conductivity was the identification, characterization and location of fractures providing special fluid pathways by outcrop-, core- and log-analyses, laboratory measurements of permeability and the evaluation of pumping tests. In terms of the geometry of the void space a conclusion was drawn to a possible flow and transport behaviour of the fractures. The analyses resulted in a calculation of the transmissivity of detected hydrothermal aquifers based on structural and hydraulic parameters and in the attempt to build up a correlation between fault networks and tectonical processes.

Using subsurface thermal data, isotopic tracers, SALINITY and earthquake hypocenters to MATHEMATICALLY MODEL deep regional flow systems within the Albuquerque Basin and underlying crystalline basement in the Rio Grande rift, New Mexico

WOOLSEY, Emily E.1, PERSON, Mark A.1, PHILLIPS, Fred M.1, KELLEY, Shari A.1, CROSSEY, Laura J.2, KARLSTROM, Karl E.2, (1) Earth & Environmental Science, New Mexico Tech, 810 Leroy Place, Socorro, NM 87801,, (2) Earth and Planetary Science, University of New Mexico, Albuquerque, NM 87131

The Albuquerque Basin is one of the largest and deepest sedimentary basins within the Rio Grande rift (RGR).  Anomalously high temperatures (29.5°C at ~60 m depth), river salinity (>700 mg/L) and mantle helium (3He/4He = 0.256-0.800 RA) have been observed at the southern terminus of the Albuquerque Basin, which overlies the Socorro magma body (SMB) at 19 km depth, suggesting mixing of deeply sourced fluids with the shallow groundwater system.

We developed a 19 km deep basin-scale, cross-sectional model that simulates subsurface fluid flow including heat, solute and helium isotope transport.  The model includes a conduit to evaluate the relative importance of conduit-controlled fluid flow versus topographically driven flow at forcing deep fluids to the surface. We use the model to constrain crustal permeability and fluid circulation patterns within the basin and through the crystalline basement. We also use the distribution of earthquake hypocenters to constrain hydraulic interactions between the conduit and basement in the highly seismogenic crust above the SMB.

The model results illustrate the importance of deeply penetrating, moderately permeable conduits (10-13 to 10-15 m2) in advective transport of heat, 3He/4He, and solutes to match observed spring values.  Basement permeability must range between 10-17 to 10-18 m2 for sufficient permeability contrast relative to the conduit.  Published surface uplift estimates (~2 mm/yr) above the SMB are comparable with our simulated uplift rates on a time scale of ~2.5 ka.  However, an order of magnitude longer transport time is required (~25-30 ka) to obtain observed temperature, salinity, 3He/4He and pressure conditions, supporting the hypothesis that the SMB is the most recent intrusion of a long-lived magmatic system.  The use of multiple tracers to model subsurface flow systems within sedimentary basins is of great practical relevance for assessing the vast geothermal resource potential of New Mexico.