Mining Heat

Oilfield Review Winter 2009/2010: 21, no. 4. Copyright © 2010 Schlumberger. For help in preparation of this article, thanks to Mo Cordes, Houston; and Stephen Hallinan, Milan, Italy. GeoFrame and TerraTek are marks of Schlumberger. The mechanics of harvesting the Earth’s natural subsurface heat seem to be familiar petroleum engineering tasks: drill and complete wells and produce fluids from wells landed in targeted formations beneath the surface. But the prize in geothermal energy production is not fluids. It is heat. So while there is considerable potential for technology transfer from the oil and gas upstream business—drilling rigs, bits, pressure control and other basic practices and technologies—the specifics of hydrocarbon and geothermal energy production diverge. For example, ultrahigh temperature represents an obvious problem in bringing oil industry technology to bear on geothermal exploration and production: It renders useless the sophisticated tools and sensors that are dependent on pressuretight seals and electronics. The industry, however, is continually overcoming temperature limitations. In reality, the accurate characterization of geothermal reservoirs is a more fundamental obstacle to realizing the full energy potential from the Earth’s heat. Constructing geothermal reservoir models and simulations using seismic surveys and logging data will require more innovation than adaptation such as increases in hardware temperature tolerances. Still, the comparison between heat and hydrocarbon exploitation remains compelling. Many of the geothermal wells currently feeding power plants have been constructed by oilfield workers using essentially traditional drilling and completion equipment and techniques. Today, those efforts have resulted in geothermal or, more accurately, hydrothermal fields that feed power plants producing about 10,000 megawatts (MW) of electricity in 24 countries (below).

The mechanics of harvesting the Earth's natural subsurface heat seem to be familiar petroleum engineering tasks: drill and complete wells and produce fluids from wells landed in targeted formations beneath the surface.But the prize in geothermal energy production is not fluids.It is heat.So while there is considerable potential for technology transfer from the oil and gas upstream business-drilling rigs, bits, pressure control and other basic practices and technologies-the specifics of hydrocarbon and geothermal energy production diverge.
For example, ultrahigh temperature represents an obvious problem in bringing oil industry technology to bear on geothermal exploration and production: It renders useless the sophisticated tools and sensors that are dependent on pressuretight seals and electronics.The industry, however, is continually overcoming temperature limitations.In reality, the accurate characterization of geothermal reservoirs is a more fundamental obstacle to realizing the full energy potential from the Earth's heat.Constructing geothermal reservoir models and simulations using seismic surveys and logging data will require more innovation than adaptation such as increases in hardware temperature tolerances.
Still, the comparison between heat and hydrocarbon exploitation remains compelling.Many of the geothermal wells currently feeding power plants have been constructed by oilfield workers using essentially traditional drilling and completion equipment and techniques.Today, those efforts have resulted in geothermal or, more accurately, hydrothermal fields that feed power plants producing about 10,000 megawatts (MW) of electricity in 24 countries (below).> Potential hydrothermal resources.The first major hydrothermal developments were located in areas with high tectonic activity marked by volcanoes, geysers, hot springs and large hot-water reservoirs.These resources are relatively shallow and often flow to the surface naturally.A large portion of potential resources, given here in megawatts, is made up of enhanced geothermal systems (EGS) and is contingent on technological development.
Hydrothermal energy is a specific form of geothermal resource.Characterized by high temperature, high permeability and rock that contains large volumes of water, it is often found at relatively shallow depths.Without stimulus, or aided only by high-temperature electrical submersible pumps, these formations can deliver superheated water or steam to the surface through large-diameter production wells.The steam, or hot water flashed into steam at the surface, is funneled to drive turbines that generate electricity.Such formations exist in relatively few places around the world.Hydrothermal reservoirs are found predominantly in areas of high tectonic activity where hot-water reservoirs are abundant and pressured, such as in the area of the Pacific Ocean known as the "Ring of Fire." Most formations around the world that have the requisite water and permeability do not have sufficient heat to be considered geothermal energy sources.But there are others with deep, hightemperature zones that lack only sufficient water or permeability, and it is these that may hold the most promise as future sources of geothermal energy.The solution to tapping such widely available heat resources is through enhanced, or engineered, geothermal systems (EGS).
Put simply, EGS projects create or sustain geothermal reservoirs.In cases of low permeability, the formation may be hydraulically fractured.Formations with little or no liquid or without a sufficient recharge source may be supplied with water through injection wells.Today, engineers and geophysicists are bringing techniques for EGS to high-temperature dry reservoirs at depths of 3 to 10 km [10,000 to 33,000 ft] below the surface.At these depths, the rock is hot enough to convert water to superheated steam.
These hot dry rock (HDR) systems are a unique type of EGS, characterized by very hot basement formations with extremely low permeability.They require hydraulic fracturing to connect waterinjection wells to water-production wells.
Other prospective formations contain permeability and water but are not hot enough for geothermal applications.To exploit these resources, less ambitious concepts are being advanced through binary power plants.These plants use water that is below the boiling point to heat a second fluid with a boiling point that is below that of water.The vaporized second fluid is funneled to turbines to generate electricity (left). 2 This article focuses on hydrothermal and HDR technology.The state of EGS technology is discussed through preparations for an EGS-expansion project in Nevada, USA, a case history from > Geothermal power plants.Dry-steam power plants are the most basic style of geothermal power plants (top).Steam piped from a hydrothermal reservoir directly enters turbines to generate electricity.As the steam cools and condenses, the water is gathered and injected back into the reservoir where it is reheated as it travels through the formation to the production well.Flash-steam plants (middle) use hot water that is below the boiling point while at reservoir pressure but that flashes to steam at lower surface pressures.Binary power plants (bottom) use a closed system to exploit even cooler reservoirs whose water temperatures are less than 150°C [302°F].Water flows or is pumped to the surface and enters a heat exchanger where it brings a second fluid, in this case isobutane, to its boiling point, which must be below that of water.The second fluid expands into a gaseous vapor that then powers electricity-generating turbines.This fluid may be circulated through the heat exchanger for reuse rather than being disposed of and, because the water does not come into contact with the power generator, maintenance costs are usually lower than with dry-steam or flash-steam hydrothermal plants.

The High Cost of Deep Heat
The upside potential of geothermal energy may be enormous.In 2008, world electricity consumption was 2 terawatt years.The heat flux continuously flowing from the Earth's core is equivalent to about 44 terawatt years. 3These numbers are astronomical of course, but if only a small percentage of this potential were to be tapped, it would easily supply most of the world's energy demands.Most geothermal resources are also truly renewable in that the same fluids can be reheated, produced, injected and recycled throughout the life of the reservoir.
Besides the technological questions are financial ones that persist in the face of otherwise positive investment factors (above right).Geothermal projects, with few exceptions, require a significantly higher initial capital outlay than do oil and gas, solar, wind and biomass projects.The risk is also higher, and the current experience with return on investment in geothermal installations is discouraging.For example, a 50-MW hydrothermal project is estimated to yield an initial rate of return of less than 11% and a profit-to-investment (P/I) ratio of 0.8.By comparison, a large oil and gas project typically yields an initial rate of return of nearly 16% and a P/I of 1.5. 4hese poor financial results are partially a reflection of geography.Areas with favorable hydrothermal conditions tend to be sparsely populated and far from large electricity markets.Financial results are also hampered by the difficulty inherent in drilling and developing these formations.Geothermal resources are found in much harder and hotter rock than those for which petroleum and mining industry bits are designed, so drilling is slower and more costly.To be economic, geothermal wells must accommodate relatively large flow volumes, and therefore wellbore diameters must be greater than those of most oil and gas wells.This adds considerably to well construction costs.The extreme temperature of geothermal environments forces operators to choose high-priced premium products for such things as cements, drilling fluids and tubulars.
While in recent decades the oil industry has greatly refined drilling and reservoir management efficiencies-consequently reducing costs-it has often done so through such electronics-based innovations as logging while drilling and subsurface monitoring.These tools are currently restricted to temperatures below about 175°C [350°F] and are not available for use in high-temperature geothermal wells.

Finding and Defining
With the exception of some "blind" deep, hightemperature systems, the search for hydrothermal formations is made relatively easy by hot springs and fumaroles that are visible at the surface. 5Additionally, many hydrothermal fields are in deep sedimentary basins where oil and gas drilling and, more importantly, data collection have already occurred.
The geologic setting for hydrothermal reservoirs varies.The reservoirs in the largest fields contain a wide range of rocks, including quartzite, shale, volcanic rock and granite.Most of these reservoirs are identified not by lithology but by heat flow.They are convection systems in which hot water rises from depth and is trapped in reservoirs whose caprocks have been formed by the mixing of upwelling geothermal fluids with local groundwaters and by precipitation of carbonate and clay minerals.
Therefore, the search for a commercial nearsurface hydrothermal reservoir is based on identifying tectonic activity, heat source, heat flow, water recharge and outflow of deep fluids to the surface.Permeability is typically characterized by a network of fractures or active faults held open by local in situ stresses.
The hunt for a hydrothermal reservoir begins with an assessment of available regional data on heat flow, seismic activity, thermal springs and characteristic surficial elemental signatures from remote sensing and imaging.Geophysical, geologic and geochemical techniques that can provide information on the size, depth and shape of deep geological structures are then put into effect.
Subsurface temperature measurements are the most direct method for ascertaining the existence of a hydrothermal system.Thermalgradient holes can be as shallow as a few meters, but to exclude surface-temperature effects the preference is for a depth of more than 100 m [330 ft].Temperature surveys can delimit areas of enhanced thermal gradients-a basic requirement for geothermal systems.In volcanic terrains, high-temperature rocks may occur at relatively shallow depths, and it is likely that a heat source is present.In systems of deep circulation, high temperatures indicate thin continental crust, high rates of heat flow and deep permeable faults that transmit mantle heat close to the surface.
Hydrothermal reservoirs require high temperatures and effective permeability, which is offered by coherent rocks capable of supporting open fracture systems.These rocks have a relatively resistive signature.The associated clay-rich caprocks, however, have low resistivity.The resistivity contrast at the base of the caprock, which can be determined through magnetotelluric (MT) measurements, can provide an indication of geothermal prospectivity. 6MT has become a standard method for mapping the caprock geometry constraining geothermal reservoirs.
If wells have been drilled in an area, many of the parameters measured indirectly from the surface can be obtained directly from well log data.These logs can highlight regions of porosity, saline fluid saturation and temperature variations, which may indicate the presence of hydrothermal reservoirs.
Since these resources may be found in fractured, tectonically stressed areas, their presence is often marked by microseismic events that also serve as a guide to drilling into the fractured rocks once other favorable geothermal conditions are established.By recording a relatively large number of these events over weeks or months and calculating their epicenters, seismologists can determine the location and orientation of fractures.
Seismic reflection and seismic refraction surveys have been used only sparingly in geothermal exploration.Although obtaining refraction profiles requires a considerable effort at depths of 5 to 10 km [16,400 to 33,000 ft], standard seismic reflection surveys often yield useful results in these areas.During geothermal exploration, gravity surveys are used to define lateral density variations associated with a magmatic heat source in volcanic-hosted systems or with fault blocks buried beneath sedimentary cover in systems of deep circulation.But their main value is in defining changes in groundwater level and in monitoring of subsidence and injection, which are directly related to the resource's ability to recharge itself.By correlating the surveys and weather, it may be possible to define the relationship between data from a gravity survey and the precipitation that produces changes in shallow groundwater levels.When corrected for this effect, gravity changes show how much of the water mass discharged to the atmosphere is replaced by natural inflow. 7

The Concept
The most common approaches to geothermal exploration include anomaly hunting, anomaly stacking and conceptual modeling.Mathematical velocity models are routinely used to predict the depth to a formation of interest, and physical models can be used to simulate rock layers.Conceptual models are hypothetical, bringing together observed and inferred information to identify geothermal targets and predict reservoir capacity.Such models are often combined with geostatistical and classical technologies such as those employed for reservoir characterization.
Hydrothermal conceptual models combine observed and inferred information to illustrate reservoir fluid and rock properties and often include data captured through cation and gas geochemistry.They also take into account MT resistivity interpreted in the context of basic geology and hydrology and through mapping of surficial hydrothermal alteration. 8he most important element of a hydrothermal conceptual model is a predicted naturalstate isotherm pattern-solid lines drawn to indicate temperature and depth across a subsurface section.Though difficult to arrive at during the exploration stage, case histories indicate it can be done based on interpretation of the geothermometry-a technique that allows the determination of subsurface temperature using a combination of methods including the chemistry of hot-springs fluids and distribution of hydrothermal alteration minerals at the surface.Patterns of geophysical anomalies and resistivities and a general knowledge of the local geology, hydrology and faulting or structural history may also be used.
Hot water circulating in the Earth's crust may dissolve some of the rock through which it flows.The amounts and proportions of these solutes in the water are a direct function of temperature.If the water rises quickly from the geothermal reservoir to the surface, its chemical composition does not change significantly and it retains an imprint of the subsurface temperature.Subsurface temperatures calculated from hotsprings chemistry have been confirmed by direct measurements made at the base of holes drilled into hydrothermal systems. 9eothermometry uses ionic and stable isotope ratios in the water to determine the maximum subsurface temperature (above left).Geochemical and isotopic geothermometers developed over the past two decades assume that two species or compounds coexist within the geothermal reservoir and that temperature is the main control on their ratio. 10They also assume that no change in that ratio has occurred during the water's rise to the surface.
Gas ratio geothermometers can also be used to determine subsurface reservoir conditions.By integrating these geochemical data with information from temperature-gradient wells and structural mapping, engineers can build conceptual models that display fluid-flow patterns within a hydrothermal reservoir as geological cross sections and maps (right).An upward flow of water creates an upward isotherm pattern and indicates permeable rocks.When reservoir flow is vertical, temperatures increase significantly with depth.In an outflow zone the flow is horizontal and temperatures decrease with depth. 11Permeable zones have smaller temperature gradients with depth than do impermeable ones and generally display a convective isotherm pattern.In very low-permeability formations, the temperature gradient is steep and is easily seen in a cross section as closely spaced isotherms that reveal a conductive thermal regime.The gradient helps determine the location of permeable and impermeable zones.
Since low resistivity usually indicates low-permeability conductive clays, MT surveys may be used to locate the base of a geothermal caprock and, indirectly, its high thermal gradient.The dimensions of the reservoir can then be mapped and used to identify drilling targets and prospective locations of production and injection wells.

Enhancing Nature
The hydrothermal fields that are now online and that were discovered through these techniques and models represent the geothermal industry's low-hanging fruit.The future of geothermal energy lies in more-complex systems that must be coaxed into production and in recovering more heat from those already in existence through EGS projects (right).
Similar to processes in oil and gas operations, conceptual modeling may be used to plan and execute EGS projects for hydrothermal reservoir development.Using data gained from years of production to construct better models, engineers can assess the potential response of these geothermal fields to infill drilling, water injection and other processes that help extend the field and improve reservoir efficiency.
At Desert Peak near Fernley, Nevada, a geothermal field was discovered and defined in the 1970s and 1980s.It has been delivering power to a double-flash power plant since 1986 and is typical of the deep-circulation, or fault-controlled, geothermal systems of the western USA. 12An EGS project that would expand the operation through hydraulic and chemical stimulation is under study.The study will determine the distribution of rock types, faults, alteration minerals and mineralized fractures east of the existing hydrothermal field to create a new structural model of the field. 136.For more on MT: Brady J, Campbell > Enhanced geothermal systems potential in the USA.Estimates for the potential energy payout from EGS resources at depths between 3 and 10 km are more than 13 million exajoules (EJ).Recovery of even a small percentage would be more than enough to supply all the electrical needs of the nation.

Category of Resource
Thermal Energy, in Exajoules [1 EJ = 10 The model proposed is based on analysis of mud logs and cores and incorporates new data from three wells drilled in the production portion of the field.Two cross sections have been constructed based on correlations observed in these three wells (above).
Researchers logged a candidate stimulus well, 27-15, adjacent to the current production area to aid in evaluating lithologies and characterizing stress and fractures.Gamma ray and caliper data were recorded and borehole images were also acquired.Features identified from these resistivity-contrast-generated images include bedding planes, lithologic contacts, foliations, conductive mineral grains, drilling-induced fractures and natural fractures. 14n combination with other petrologic and petrographic studies incorporated into a GeoFrame model, this imaging provided a more complete understanding of the geological characteristics of the well as a candidate for EGS.Further rock mechanics testing conducted at the Schlumberger TerraTek Geomechanics Center of Excellence in Salt Lake City, Utah, USA, will characterize rock strengths and stress behavior of potential reservoir rocks within the proposed stimulation interval.
The researchers noted that the productive portion of the Desert Peak geothermal field lies within an older structural horst bounded by north-west-trending faults.The results of tracer tests indicate that fluids injected into the production area can cross into currently non productive areas along younger northeast-trending faults.The scientists were unable, however, to determine the depth of the fluid transmissivity and whether the basement fault served as a barrier or conduit to geothermal fluids.Upcoming hydraulic and chemical stimulation experiments are expected to increase permeability and fluid-fracture connectivity in this enhanced system.

Making the Good Better
The dominant tools of EGS-reservoir modeling, drilling, hydraulic fracturing and water injection-are familiar to petroleum engineers.Unfortunately, their use in geothermal applications is more than a matter of adapting them to increased temperatures.
For example, in oil and gas formations, both induced and natural fracturing are reasonably well-understood concepts.But because oil sands are fractured to increase flow in discrete stratigraphic intervals-and the goal in a geothermal resource is to maximize heat exchange in large volumes of fractured crystalline rock-the operations differ greatly in their application.Whereas traditional hydraulic fracturing operations are constrained predominantly by rock stresses and boundary considerations, complex rock and fluid interactions and heat transfer must be considered when determining injection rates, pumping times and injection temperatures for fracturing geothermal formations.
In recent years, stimulation of oil-bearing formations by fracturing has become increasingly sophisticated and efficient as the industry developed methods for modeling, plotting, tracking and even controlling fracture direction.But most of these techniques rely heavily on electronic sensors placed downhole near the sandface depth.Temperature limitations render these devices useless in geothermal zones.
Still, oilfield-style interventions are being applied successfully in many of the world's largest geothermal fields, which are typically the highest temperature volcanic-hosted systems.These operations are essentially EGS and include such established projects as the Salak geothermal field, operated by Chevron.The largest of its kind in Indonesia, the Salak field is located within a protected forest about 60 km [37 mi] south of Jakarta (next page, top right).
Chevron has maintained steam production levels and optimized heat recovery at Salak through infill drilling and water injection into deep wells on the field's margins where permeability is low.Through the use of tracers, chemical and microseismic monitoring, and pressuretemperature surveys of individual wells, Chevron has been able to gauge the impact of its injection strategy and to move injection wells farther from the field's center and closer to its edges.This approach has simultaneously generated more area for infill drilling and expanded the field.It has also allowed the company to convert several injection wells into producers once the formation has thermally recovered.
More recently, geophysical data, including MT and time-domain electromagnetic surveys on the field's margins, have identified potential reservoir extensions to the west and north of the proven area.To the west, the Cianten Caldera exhibits a low-resistivity layer at depths similar to those in the Salak reservoir, and microseismic data show distinct depth distribution of the proven reservoir through the western area.
Drilling results in the caldera indicated noncommercial temperatures.Ring dike intrusions appeared to preclude fluid circulation from the proven reservoir.Geothermal reservoir boundaries tend to be vague, and new wells often encounter low-permeability but hot formations that must be stimulated to provide adequate injection rates.The operator therefore began a long-term, > One of two Desert Peak cross sections.This conceptual cross section of the geothermal field shows the stratigraphy and interpreted structure from Well 29-1 in the south to Well 27-15 in the north.The key features of this section are the gently dipping top of the basement rocks in the north, the presence of a pre-Tertiary 1 (PT-1) interval in Well 27-15 and the thick Tertiary section (green) in the southern wells.Faults and structural interpretations are based on lithologies and stratigraphic sequences encountered in each well, and locations of lost circulation zones identified from well cuttings and well logs.Well 27-15 is the candidate for hydraulic stimulation.(Adapted from Lutz et al, reference 13.) massive cold-water injection program.This operation takes advantage of the extreme temperature differences between the injectate and the formation-more than 149°C [268°F]-and the formation's relatively high coefficients of thermal contraction to create fractures.

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Three injection stimulations were conducted on one low-permeability well in the Cianten Caldera that lies within the boundaries of the Salak concession.These stimulations included injection of about 9.8 million bbl [1.6 million m 3 ] of water.To evaluate the impact of these treatments on injection performance, the operator used a modified Hall plot and analysis that indicated fracture development within the formation (below right).Injectivity improvements were also quantified through periodic pressure-falloff tests and the creation of a geomechanical reservoir simulation model calibrated against field history. 15The final analysis concluded that injectivity had been increased significantly.Two additional wells drilled in the area will undergo the same type of stimulation to allow injection of water produced from the high-temperature core of the reservoir.

The Great Heat Exchange
Hot dry rock-HDR-reservoirs represent particularly high-potential geothermal systems.The total amount of heat that may be unlocked from these reservoirs worldwide through injection or fracturing has been estimated at 10 billion quads-about 800 times more than that estimated for all hydrothermal sources and 300 times that available from hydrocarbon reserves.> Salak field, Indonesia.HDR systems are essentially reservoircreation projects.One of the most important lessons learned at Fenton Hill is that it is nearly impossible to connect two existing boreholes by creating a hydraulic fracture between them.Reservoirs should therefore be created by stimulating or creating fractures from the initial borehole and then accessing them by two production boreholes (left). 17ork at Fenton Hill also advanced the case for HDR fields by defining which critical factors in their construction are controllable.For example, the reservoir's size is a direct linear function of the amount of fluid injected into it (next page).Similarly, temperature, injection pressure and flow rate, production backpressure, and the number and placement of wells are all manageable variables within HDR field development.

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While many of the technological questions associated with HDR systems were answered through the work at Fenton Hill, uncertainties about reservoir creation remain.Although a relationship can be established between fluid volume injected and resulting volume made available for heat exchange, the fractured surface area within that volume of rock is more difficult to quantify.
One approach renders an order-of-magnitude estimate of the rock volume required.This is obtained by equating the heat flow rate from the reservoir with the change in stored thermal energy, assuming uniform extraction of heat throughout the volume.The heat flow rate is a function of rock density, volume and heat capacity, and the change in rock temperature over time.
A numerical simulation study by Sanyal and Butler suggests the electrical power generation rate achievable on a unit rock volume basis is 26 MW e /km 3 [106 MW e /mi 3 ]. 18This powerproduction correlation requires a volume of roughly 0.19 km 3 [0.05mi 3 ] to generate 5 MW e .Such a cube would measure 575 m [1,886 ft] on each side, and the simulation is based on an assumption of uniform properties, including permeability, within the stimulated region.
The study concluded that if constant production is maintained, generation capacity is primarily a function of the stimulated rock volume.Other considerations may include well configuration, number of wells within a reservoir volume, reservoir mechanical properties, reservoir stress state and natural fracture features.These characteristics collectively determine how the reservoir is best stimulated to create the requisite volume and the flow paths necessary for effective heat extraction. 19The EGS concept as applied to HDR.Fractures are generated from an injection well (blue) drilled into a low-permeability reservoir of deep crystalline rock.Production wells (red) are then drilled into the fractured zone.Injected water is heated as it flows from the injection well to the production wells.
AUT09-RVF-10 Despite the progress being made on the technological aspects of HDR exploitation, commercial viability of these prospects remains elusive as a consequence of their depth and temperature.For example, commercial hydrothermal well depths range from less than 1 km to a rare few that reach about 4 km [13,000 ft], such as the EGS project in Soultz-sous-Forêts, France.HDR wells, because they are in crystalline basement formations, are typically much deeper.As a consequence, HDR wells are likely to be characterized by varied lithology and the extensively documented problems associated with deep drilling and completion. 20e Gap Owing to the obvious similarities between hydrocarbon and heat mining, it is tempting to assume that adapting the technology of the former to the latter is a matter of focus.Recent development of tools for use in some applications-HPHT oil and gas wells, hydrothermal fields and steamflooding-encourages such assumptions.
Geothermal energy resources, however, differ across the world, and the ease with which this technology transfer will take place is a function of those differences.The highest grade of resource-hydrothermal-is shallow, permeable and hot and has a natural water-recharge system.
The techniques and methods used to tap that resource are and will continue to be familiar to oilfield personnel.
Lower-grade resources that require intervention in the form of injection or fracturing, or whose temperatures are below the boiling point of water, are also being produced at a profit through the use of technology adapted from the petroleum industry.Coproduction is a current technique that uses the hot water produced with oil and gas to run binary plants, which in some cases generate all the field's electricity needs.
But the real prize in geothermal energy production will come once the technology required for EGS and HDR reservoirs is widely available.Despite current barriers to commerciality, HDR projects do have an advantage over those for conventional hydrothermal systems in that they can be located near major electricity markets.
That they still require much technological innovation, however, has created a tendency among many of those best equipped to solve these problems-petroleum industry professionals-to abandon the notion of HDR developments in favor of more immediate and familiar pursuits.
With the prospects of large payoffs, there has been progress on making HDR projects economically attractive, including the vital area of reservoir-creation monitoring and control.In the Cooper basin of Australia, for example, geophysicists recently applied microseismic multiplet analysis to a dataset from an HDR hydraulic fracturing operation to help characterize the developing fracture system within the reservoir. 21he greatest potential for improving the economics for geothermal energy projects, as in any high-risk, high-cost venture, is by risk reduction through a better understanding of the subsurface.The unknowns that affect drilling and completion risk, environmental impact, stimulation and overall project success are all exacerbated by a lack of knowledge about lithology, stress regime, natural seismicity, preexisting faults and fractures, and temperature at depth. 22orrecting these shortcomings will be a matter of growth, but of a type with which the E&P industry is long familiar.It took the offshore industry more than 50 years of lessons learned between the first well drilled in shallow water just out of sight of land to routine placement of wells in water depths of more than 3,000 m [10,000 ft] and hundreds of kilometers from shore.Moving from shallow, high-grade hydrothermal formations to deep, hot dry rocks will require a similar evolution in technology, equipment and trained personnel.Given the prize in the offing, however, it is certainly just a matter of time. -RvF 1 1. Blodgett L and Slack K (eds): Geothermal 101: Basics of Geothermal Energy Production and Use.Washington, DC: Geothermal Energy Association (2009), http://www.geo-energy.org/publications/reports/Geo101_Final_Feb_15.pdf(accessed August 1, 2009).
Indonesia and lessons learned from the original HDR project located in the southwest of the United States.

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Subsurface temperature predictions.Temperatures measured in wells drilled into hydrothermal systems are compared with temperatures calculated from geothermometers before drilling.The dashed line indicates the location where points would plot if measured and calculated values agreed perfectly.Points above the line indicate calculated temperatures that were underestimated.(Adapted from Duffield and Sass, reference 9.)

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Evaluating injection performance.A modified Hall plot provides a qualitative indicator of injection performance.The Hall integral (orange) is a straight line if the well skin factor does not change over time.A steeper slope indicates some type of flow resistance, such as plugging or scaling, while a shallower slope indicates formation stimulation.In subtle cases, such as this one in Salak field, plotting the Hall derivative (blue) on the same scale improves the diagnosis.A derivative curve above the integral curve indicates increased resistance and below the integral curve-as shown here-ongoing stimulation.This analysis confirmed fracture development during cold-water injection in the field.(Adapted from Yoshioka et al, reference 15.) Unlike hydrothermal EGS, there are, as yet, no commercial HDR fields, so experience with these systems has been confined primarily to pilot projects.Of particular importance to the concept is an extended study at Fenton Hill-the first HDR project-that began in the early 1970s.The Fenton Hill HDR site is about 64 km [40 mi] west of Los Alamos, New Mexico, USA.It includes two confined reservoirs created in crystalline rock at 2,800 and 3,500 m [9,200 and 11,480 ft] with reservoir temperatures of 195°C and 235°C [383°F and 455°F], respectively.Flow tests were conducted in each of the reservoirs for almost a year.The project, conducted over a period of about 25 years, ended in 1995.

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Controlling reservoir size.During a massive hydraulic fracture test at Fenton Hill, a linear relationship was established between the seismically active reservoir volume and the volume of injected fluid, as determined from microseismic event location data.(Adapted from Duchane and Brown, reference 16.) Alternative energy comparative value.Among renewable energy sources, geothermal energy is one of the most attractive based on the capacity factor-the percentage of energy actually produced by a plant compared with its potential output when operated continually at full capacity.It also compares favorably with other alternative energy sources when different metrics are used.(Capacity factor data from Kagel A: A Handbook on the Externalities, Employment, and Economics of Geothermal Energy.Washington, DC: Geothermal Energy Association, 2006.) 2. "FirstSuccessful Coproduction of Geothermal Power at an Oil Well," JPT Online (October 21, 2008), http://www.spe.org/jpt/2008/10/first-successful-coproductiongeothermal-oil-well/ (accessed July 14, 2009).3. Pollack HN, Hurter SJ and Johnson JR: "Heat Flow from the Earth's Interior: Analysis of the Global Data Set," Reviews of Geophysics 31, no. 3 (August 1993): 267-280.> Approach," Schlumberger white paper, www.slb.com/media/services/consulting/business/thermal_dev.pdf(accessed September 15, 2009).5.A fumarole is a vent or opening in the Earth's surface through which steam, hydrogen sulfide or other gases escape.