GREENFIRE GLOBAL COMMERCIALIZATION OF CLOSED LOOP CO2 GEOTHERMAL

Transcription

1 GREENFIRE GLOBAL COMMERCIALIZATION OF CLOSED LOOP CO2 GEOTHERMAL APPLICANTS & AFFILIATIONS John R. Muir, Andrew J. Van Horn, Geothermal Resources Council Geothermal Energy Association * Lawrence Berkeley National Laboratory * Baker Hughes * Geothermal Resources Council * Geothermal Energy Association * Electric Power Research Institute * US Department of Energy Geothermal Technologies Office" INTELLECTUAL PROPERTY STATUS, PATENT OR TECH TRANSFER NUMBERS: Exclusive license from Alamos National Laboratory US Patent No. 6,668,554; Applications re optimized thermosiphon and "tiered" geothermal TIME TO MARKET Years C2M OBJECTIVES GreenFire Energy has spent several years designing and developing an innovative, environmentally superior renewable power technology, ECO2G. GreenFire s next generation geothermal technology will produce no carbon emissions and, unlike other geothermal technologies, consumes no process water, because supercritical CO2 is the working fluid. While ECO2G technology will have global applicability, particularly along the Rim of Fire, projected electricity price structures in the western United States suggest that international markets may offer the best opportunities for commercialization. GreenFire needs an assessment of the market potential for the ECO2G technology and an evaluation of the opportunities, risks and revenues that can be obtained in domestic and international markets. This information will be an essential component of GreenFire s strategic business plan. We believe that the information and insights provided by the C2M project will be instrumental in developing a credible market assessment. GreenFire would welcome the opportunity to work with the C2M program, in order to: Develop a strategic business plan for entry into the global energy market by selecting foreign countries with the most attractive combination of geothermal resources, promising electricity markets, and potential local partners and other means of market entry. Determine likely market sizes for ECO2G as a function of projected electricity prices, the Levelized Costs of Energy (LCOE), geothermal resource characteristics and demand growth over the next 30 years for baseload power, competing flexible technologies and renewable power in these electricity markets. For those countries with adequate geothermal resources for ECO2G,

2 understand the regulatory, environmental, political, market and cultural conditions for commercialization and profitable operations. Identify favorable and unfavorable regulations, government and utility policies, local development hurdles, and legislation that will shape the mix of renewable energy sources in the geothermal regions of these countries, particularly in places that are actively seeking to limit emissions of greenhouse gases (GHG) and promote green power. Point out how projected electricity contract/power purchase agreement prices and payments for energy, capacity and ancillary services are structured and are expected to change as these markets evolve. Indicate how contract terms might best be structured to accommodate the costs and returns and operating characteristics of flexible baseload power sources like ECO2G. Help GreenFire understand the logistics of operating in the selected countries including international taxation, skilled labor, availability and costs of drilling rigs, electric interconnection, site acquisition, permitting and project development requirements, and other barriers to achieving profitable operations. Estimate future revenue streams for 1 MW, 5 MW, and 25 MW ECO2G power plants for selected values of LCOE: $50/MWh, $80/MWh, $100/MWh and $150/MWh or breakeven prices appropriate for the designated local electricity market. Determine which of the candidate country and regional electricity markets are the best for ECO2G. Summarize the opportunities; describe complementary technologies, competitive threats and barriers to commercialization. Identify fatal flaws, potential show-stoppers, key uncertainties and next steps. Define a potential exit strategy for GreenFire s investments in each selected foreign country. Identify national or multi-national companies that might be potential partners, such as existing geothermal or international developer/driller/builder/energy company partners around the world for project development purposes, in-kind assistance, licensing, or stake-out investments in GreenFire and, ultimately, for acquisition of GreenFire Energy. Provide introductions to the companies currently sponsoring the C2M program, as well as other companies that might be interested in funding GreenFire s projects." TECHNOLOGY ECO2G is an environmentally advanced renewable power technology designed to access the vast unexploited geothermal resources located around the world. Lack of subsurface permeability has been the greatest constraint for conventional hydrothermal projects. To circumvent the permeability problem, ECO2G circulates supercritical CO2 in a closed-loop pipe system to gather and transfer high temperature heat. In essence, we reliably create our own permeability. A further advantage of ECO2G is that it eliminates the need for process water, thus removing another important constraint in geothermal development. ECO2G reduces drilling risk, a major obstacle to project development. Conventional hydrothermal projects require the right combination of heat,

3 water and permeability with the result that about half of all drilled wells fail to produce. In contrast, ECO2G s optimized closed-loop design requires only sufficient heat, minimizing drilling risk. By reducing the risks of drilling, ECO2G can transform geothermal development from a series of wildcatting ventures into an industrial process. We are now completing the integration of engineering and technical designs along with cost and performance modeling below-ground and above-ground. These models indicate ECO2G will create power in the range of 5 to 10 cents per kwh with 22% resource depletion in 25 years. GreenFire technology development: DOE grant to investigate CO2 geothermal in open systems, , LBNL modeling of geothermal production and resource depletion over 30 years with the validated TOUGH2 computer code , Intensive in-house thermodynamic modeling using TOUGH2 and other models , Intensive research on drilling technology using engineering resources from the Baker Hughes" CUSTOMERS We envision ECO2G fitting well into the developing energy cloud made up of utility-scale interconnected grids and microgrids, special-use customers (data centers, military), and complementary wind and solar projects, in domestic and international markets. Market Opportunities Geothermal power is the greatest anomaly in the worldwide energy sector. No other baseload, clean power source has such an imbalance between its potential and its current degree of utilization. World market: o 12,500 MW installed with a growth rate of 4.5%. o Estimated potential of 250,000 MW. U.S. Market: o 3,500 MW installed with a growth rate of about 3%. o 2009). At least 75,000 MW potential at 95% resource probability (USGS Geothermal has the greatest potential for any baseload energy source to reduce worldwide GHG emissions. Recent USGS research indicates that 70% of geothermal resources are yet to be discovered.. Problems addressed by ECO2G Creates clean baseload and flexible power with zero GHG emissions and

4 without process water consumption Provides 95% availability, secure, baseload power, 24/7 without huge ramping requirements and operational changes to the grid. Learning curve to achieve material reductions in project risk, cost and time. Makes geothermal generation possible on a much larger scale both in the U.S. and worldwide. Modular design enables more precise matches with available resources and electricity demand. SCALING ECO2G addresses the global power market First priority will be to fix/augment the 70% of existing geothermal projects that are underperforming or that can be expanded o Rehabilitating an underperforming existing site with failed wells and available transmission will significantly reduce market entry cost and time o No interference with existing, conventional hydrothermal wells, even where co-located. o Successful hydrothermal projects use only about 10-15% of the available heat. ECO2G can gather heat without being limited to natural fractures, so, we estimate we can get to 50%. GreenFire may buy or enter into partnerships to acquire nonperforming projects o Permitted but abandoned projects that have sufficient heat and transmission capacity o A Memorandum of Understanding is in place with one geothermal owner and several other existing sites are currently being examined GreenFire might inexpensively acquire the many known geothermal resources that cannot be developed using conventional technology Licensing or acquisition transactions o GreenFire will contemplate technology licensing or acquisition o GreenFire would like to learn whether licensing the technology internationally is a feasible business model o GreenFire would also like to learn about multinational firms that could purchase the company. ADVANTAGES Conventional geothermal is limited to moderate temperature zones where there is sufficient permeability for water to flow to production wells and so is limited to use only about 2% of the available geothermal resource. A competing technology Enhanced Geothermal Systems (EGS) has tried for decades to create artificial permeability. However, EGS is still far from commercialization because of the difficulty of creating long symmetrical racks in complex and varied terrains. ECO2G uses oil and gas drilling technology to create closed-loop sealed wells. Further, supercritical CO2 is better than water for heat transfer in this system, and thus eliminates the water constraint. This simplified approach reduces the complexity and risk of drilling, thus transforming geothermal development from a series of wildcatting ventures into an industrial process.

5 This approach will also be successful because, in comparison to conventional water-based geothermal, ECO2G: Enables geothermal power to be developed in many more sites ECO2G benefits from the R&D expenditures of the oil industry to reduce drilling costs Can access significantly more of a given geothermal heat resource Uses extracted heat much more efficiently Can generate revenue in less than half the time with less capital Is less likely to engender opposition on environmental grounds than other renewables, Modular 1 to 5 MW power units can provide fast flexible power for gridbalancing BARRIERS Power pricing structures in some jurisdictions may not be favorable to geothermal power production, despite the inherent advantages of geothermal power as a renewable resource. For example, California s regulatory and legislative mandates provide incentives to solar, wind and energy storage technologies, but effectively penalize new geothermal power projects by allowing curtailment of this reliable renewable baseload resource, hence, reducing its revenues and economic attractiveness, unless flexibility can be properly compensated. Even in such jurisdictions, however, the inherent advantages of geothermal power as a baseload power source will ultimately be valuable. For example, as the CAISO Energy Imbalance Market expands regionally and as coal-fired (or nuclear) plants retire, there will be a need for additional baseload power, which is also renewable. Today there is a perception that geothermal drilling and power projects are too risky and geographically limited to comprise a significant share of the market. However, ECO2G makes possible technological and cost advances that can make geothermal more economically competitive. Although supercritical CO2 turbines exist, they need some modifications to be optimized for the input temperatures ECO2G will produce. GreenFire has had discussions with current manufacturers that indicate that this is an engineering cost, but not a feasibility issue. FEEDBACK LBNL: Test results indicate the CO2 geothermal systems can generate power more efficiently than water-based systems. Baker Hughes: Various configurations of ECO2G wells are feasible, each with its own cost and risk. Advances in directional drilling and well completion technologies will reduce risk and costs over time. USGS: Geothermal heat represents a vast energy source, and most geothermal resources are yet to be discovered. Unfortunately, even the best conventional systems use only about 15% of the available heat, so the process is less efficient than it might be.

6 GreenFire Advisors: GreenFire s Advisory Board members represent the disciplines necessary to develop ECO2G, most with deep experience in the conventional geothermal industry. Its members have decades of experience in the technical, business and market disciplines needed for success. Each is contributing time and effort to the future success of the ECO2G technology and to GreenFire to develop and deploy ECO2G as the best next generation technology for advancing geothermal power production ACADEMIC/JOB TITLE(S) John Muir - Sr. VP Business Development, Andy Van Horn - Member Advisory Board STATUS Company or LLC formed, Other DOE funding, Significant lab performance data, Founder(s) plus >2 full-time equivalent employees TIME TO MARKET BACKGROUND GreenFire intends to select a demonstration site from 5 current options by June The demonstration project will require about 7 months from October 2016 to April If the demonstration project succeeds as expected, then the project will be converted to the first phase of a commercial project at that site by November Bear in mind that we will be using an existing geothermal site with permits in place, wells drilled, and an available connection to the power grid.

7 GreenFire Energy Inc. Additional Information for Cleantech to Market Program 1 P age Lawrence Berkeley National Laboratory modeled ECO2G geothermal production and resource depletion over 30 years with the validated TOUGH2 computer simulation. Nonconfidential elements of this work were presented in a recent paper that can be found in the Proceedings of the 41st Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, February 22-24, 2016, SGP-TR-209: "Numerical Simulation of Critical Factors Controlling Heat Extraction from Geothermal Systems Using a Closed-Loop Heat Exchange Method," Curtis M. Oldenburg, Lehua Pan, Energy Geosciences Division C, Lawrence Berkeley National Laboratory, Berkeley, CA 94720; Mark P. Muir, Alan D. Eastman, and Brian S. Higgins, GreenFire Energy, 4300 Horton Ave, Unit 15, Emeryville, CA [Paper] cmoldenburg@lbl.gov, mark.muir@greenfireenergy.com, alan.eastman@greenfireenergy.com, brian.higgins@greenfireenergy.com

8 2 P age

9 3 P age Source: US Energy Information Administration

10 Overview Presentation MARCH 2016

11 GreenFire Energy Inc. Reinventing Geothermal Power Mission Harness the vast potential of geothermal power for global economic growth Develop, use, and license ECO2G technology for worldwide deployment Create shareholder value Protect our climate and communities Market Global, multi-billion dollar market for electrical power that increasingly requires: 24/7 availability and reliability Competitive generation costs Zero carbon emissions Low or no water consumption Commercial scale Global applicability Safety and sustainability First Geothermal Power Plant Lardarello Italy about

12 ECO2G Revolutionizes Geothermal with a Closed Loop and sco 2 Hydrothermal requires fractures for water circulation; cannot operate in the plastic zone ECO2G does not require water and can use high temperatures in the plastic zone 3

13 ECO2G Exploits the Massive Potential of Geothermal Energy US Geothermal Resource - MWe ECO2G works where hydrothermal cannot 100,000 80,000 60,000 40,000 20,000 0 Vast majority of geothermal resources untapped Source USGS In Service Identified Suspected Hot Brittle Zone Plastic Zone Hydrothermal ECO2G ECO2G Enhanced Hydrothermal ECO2G ECO2G Conventional geothermal can access only 2% of available geothermal resources Geothermal: the Marginalization of Earth s Largest and Greenest Energy Source, 2016 Peter GEISER, Bruce MARSH, Markus HILPERT High Permeability Low Permeability 4

14 ECO2G Enables a Superior Business Model Transforms geothermal business from wildcatting projects to a predictable and repetitive industrial process Reduced drilling risk; up to 50% of conventional wells fail to produce Avoids production loss from thermal depletion, closed fractures Can rehabilitate failed or underperforming hydrothermal projects Co-location with hydrothermal projects shortens time to revenue Cost reductions from oil and gas technology development Cost reductions from learning curve at specific sites and with multiple sites ECO2G will integrate into the energy cloud of the future Competitive cost between $0.05 and $0.10 per KWH Power output naturally complementary to wind and solar output High availability, 24/7 baseload power for Renewable Portfolio Standards Robust and reliable power for special high value applications A Revolution in Power Generation Utility-scale baseload power that complements wind and solar power generation Environmentally benign No GHG emissions No process water consumption No waste streams No Smallest footprint dangerous chemicals or explosives No fracking or induced seismicity No surface subsidence 5

15 ECO2G Offers Clean, Baseload, Competitive Power Cost per MWH ECO2G Geothermal Not risk adjusted Natural Gas - Advanced Combined Cycle Natural Gas - Conventional Combined Cycle Wind Hydroelectric atural Gas - Advanced Combined Cycle w Carbon Capture Conventional Coal = Non-Dispatchable = Dispatchable Source: US Energy Information Administration, April 2014 Advanced Nuclear Biomass Natural Gas - Advanced Turbine Integrated Coal Gasification Natural Gas - Conventional Turbine Solar PV IGCC w Carbon Capture Offshore Wind Solar Thermal $0.0 $50.0 $100.0 $150.0 $200.0 $

16 ECO2G is at Convergence of Advanced Energy Technologies Subsurface: drilling technology from the oil & gas industry Directional/horizontal drilling in hot formations Precision drilling to connect wells Multiple lateral wells from a single vertical shaft Surface: sco 2 turbine technology from power industry Off-the-shelf 10 MW turbines available in 2017 Improve generation efficiency over conventional binary systems and some steam turbines at high temperatures Low mass to output capability Costs and risks greatly reduced because ECO2G uses proven technologies from existing industries 7

17 ECO2G Creates Power, Not Legal Issues 8

18 ECO2G: Rapid Market Entry with Existing Projects Many geothermal projects fail to achieve projected production or lose production over time 5 Example: California Projects Substantial Opportunity to Work with Troubled Projects Rapid Path to Revenue Interconnection already in place Existing PPAs with offtakers, potentially adaptable to ECO2G Permitting, environmental considerations already addressed Access, additional infrastructure in place Strong Incentive for Operators to Cooperate Some operators struggling to meet minimum production levels Potential for additional revenue under wheeling/resale arrangements Few Attractive Alternatives EGS has not been commercialized Water shortages in the western US raise concerns on EGS Many sites heavily explored/drilled already Below 75% Between 75% and 85% Above 85% 9

19 Strategy Will Initially Focus on Improving Existing Projects 7 years & beyond 5-7 years Green field projects 2-5 years Acquire & fix failed projects JVs to augment power at existing installations Leases in place Permits obtained Geophysical analysis done Wells drilled and logged Power interconnect available Need to perform all project steps 10

20 ECO2G Helps Integrate Intermittent Wind and Solar ECO2G could be an important part of the solution Mid-day over-generation, late-day shortages Growth in mid-day generation from solar creates potential over-generation Early evening problems as demand rises, solar generation declines Existing baseload resources poorly suited to deal with the problem Peaking power resources are available, but expensive and carbon-intensive Growth in intermittent renewables a continued challenge Certain states likely to continue boosting Renewable Portfolio Standards Federal regulation of carbon emissions via EPA Declining solar costs, favorable net metering deals driving behind-the-meter adoption Growth in non-dispatchable wind and solar is creating challenges for grid operators Slimming the belly of the duck Operators, regulators looking for dispatchable low-carbon solutions ECO2G systems well positioned to step into the gap with competitively priced, flexible energy 11

21 GreenFire is Building a Strong Portfolio of IP Patents Pending: Exclusive license with Los Alamos National Laboratory for CO2-EGS design, a related ECO2G technology Basic foundational patent application for closed-loop ECO2G Accessing heat in the plastic zone Optimized thermosiphon conditions Diverse, tiered, closed loop and/or open geothermal power production systems in a single project (Tiered Geothermal ) Proprietary Research and Database: Pioneering research into closed-loop ECO2G Finishing first ECO2G flow and thermal depletion modeling with Lawrence Berkeley National Laboratory Developing in-house team and expertise to rapidly assess the potential of geothermal resources using advanced modeling software Additional proprietary projects: ECO2G well design ECO2G system balance and performance Project Portfolio Identify, analyze, and prioritize scores of locations and capture detailed information on the top 10 sites for ECO2G Focus on failed or underperforming sites that can be made productive using ECO2G 12

22 GreenFire Energy Inc. Team and Relationships Management Team Advisory Board Collaborating Research Partners Joseph Scherer, CEO: Attorney/MBA with 30+ years experience in project finance including renewable energy Dr. Brian Higgins: PhD in Mechanical Engineering with extensive experience in thermodynamics and power cycles Joseph Osha, CFO : MBA/CFA with extensive public and private market experience in renewable energy John Muir, VP Business Development: MBA with several successful exits in technology ventures Dr. Alan Eastman, Principal Research Scientist, Co-Founder: PhD in chemistry with 37 patents, industrial experience Mark P. Muir, Senior Consulting Scientist, Co-Founder: MBA and geologist specializing in hydrogeology Dr. Leland Roy Mink: Former Director of DOE Geothermal Technologies Program; expertise in geology, hydrogeology, and geothermal resource characterization Lou Capuano, Jr.: 40 years of geothermal drilling expertise; widely recognized industry expert; current President of the Geothermal Resources Council (GRC) Halley Dickey: 40 years of experience in power generation systems development; expert in geothermal power system design and SCO2 turbines Dr. Andy Van Horn: Ph.D. with 35+ years experience as an economic, technical and regulatory consultant to utilities, EPRI, EPA, IPP generators, electricity, natural gas and emission market participants U.S. Department of Energy Lawrence Berkeley National Laboratory Pacific Northwest National Laboratory University of Utah Electric Power Research Institute 13

23 Thank you! 4300 Horton Street, Unit 15 Emeryville, CA Office: (888)

24 GreenFire Energy Inc. Reinventing Geothermal Power GreenFire Energy is developing utility-scale CO 2-based geothermal energy (ECO2G ) technology for projects worldwide. ECO2G generates reliable, affordable, baseload power with zero emissions and little or no water consumption. In contrast, conventional hydrothermal technology requires a rare combination of heat, water and subsurface permeability that limits its application to a small percentage of geothermal regions. Geothermal energy potential is vast but underutilized. i The USGS estimates that 70% of overall geothermal resources have yet to be discovered. ii But conventional technology can access less than 2% of geothermal resources. iii Exploiting advanced drilling technology from the oil and gas industry, ECO2G is a closedloop system that circulates supercritical carbon dioxide (sco 2) to collect and move heat. Consequently, ECO2G consumes little or no process water and emits no greenhouse gases. Conceptual schematic. Actual configuration will depend on site-specific factors. ECO2G accesses heat in the very high temperature, but low-permeability, plastic zone where conventional hydrothermal cannot work. The temperatures and depths that characterize the plastic zone are optimal for use with sco 2. Business Strategy GreenFire intends to form joint partnerships with owners and operators of existing projects with sufficient underlying heat that are substantially underperforming to restore or augment power generation. Because these projects already have leases, permits, power purchase agreements, transmission facilities and other physical infrastructure, including potentially usable dry wells, GreenFire can generate revenue in the near term. Proprietary Technology: ECO2G is protected by GreenFire s exclusive license from Los Alamos National Laboratories of the seminal patent for sco 2 in geothermal applications plus GreenFire s multiple patents pending for closed-loop sco 2 geothermal power production

25 ECO2G exploits heat that hydrothermal technology cannot access o Closed loop system circulates supercritical CO 2 to transfer heat; does not need subsurface permeability, fractures or formation water circulation o Enhances, and doesn t interfere with, hydrothermal projects by harvesting heat in the impermeable zone below the hydrothermal resource, even where the hydrothermal area has been depleted. o Accesses much hotter and more common impermeable resources that are inaccessible to hydrothermal ECO2G transforms the geothermal business model from a semi-custom wildcatting industry into a predictable and repeatable industrial process o o o o o Reduced drilling risk in seeking heat only; up to 50% of conventional wells fail to produce, principally due to lack of permeability and water circulation Longer lived than hydrothermal as no process water is used; 60% of hydrothermal projects (in CA) degrade swiftly to produce at less than 75% of design, generally due to reduced water circulation or thermal depletion Can rehabilitate failed or underperforming hydrothermal projects with sufficient underlying heat ECO2G projects that are co-located with hydrothermal projects can be rapidly deployed to shorten time to revenue Learning curve and cost reductions expected based on overall scaling ability, continued oil and gas technology development and many more wells per site ECO2G will integrate into the energy cloud of the future 2 P a g e o Competitive cost between $0.05 and $0.10 per KWh o Power output inherently and naturally complementary to wind and solar intermittency o High availability, 24/7 baseload power ability contributes to meeting Renewable Energy Portfolio Standards o Employs cost advantages of sco 2 turbines o Robust and reliable power for special high value applications ECO2G is the most environmentally benign form of grid-scale power o No GHG emissions o No process water consumption o No waste streams o Smallest footprint o No explosives or dangerous chemicals o No visual obstructions o No danger or impediment to wildlife o No seismicity o No surface subsidence

26 . Management Joseph Scherer, CEO: Attorney/MBA with 30+ years experience in project finance including renewable energy Joseph Osha, CFO: MBA/CFA with extensive public and private market experience in renewable energy Dr. Brian Higgins, CTO: PhD in mechanical engineering, assistant professor at Cal Poly SLO, and 15+ years experience designing pollution control equipment for utility boilers John R. Muir, Sr. VP Business Development: MBA with several successful exits in technology ventures Dr. Alan Eastman, Founder and Senior Research Scientist: PhD in chemistry with 37 patents, industrial experience Mark P. Muir, Founder and Senior Consulting Scientist: MBA and geologist specializing in hydrogeology GreenFire Energy Advisory Board: Takes an active role in assisting GreenFire with drilling design, engineering design, economic and cost modeling, power market analysis and government relations. Dr. Leland Roy Mink: Former Director of DOE Geothermal Technologies Program; expertise in geology, hydrogeology, and geothermal resource characterization Lou Capuano, Jr.: 40 years of geothermal drilling expertise; widely recognized industry expert; past President of the Geothermal Resources Council (GRC) Halley Dickey: Decades of experience in power generation systems development; expert in geothermal power system design and sco 2 turbines Dr. Andy Van Horn: 35+ years experience as an economic, technical and regulatory consultant to utilities, EPRI, EPA, independent power producers, and energy and environmental market Research Partners U.S. Department of Energy Lawrence Berkeley National Laboratory Pacific Northwest National Laboratory University of Utah Electric Power Research Institute Company Information: 4300 Horton Street Unit 15 Emeryville, CA info@greenfireenergy.com i Future of Geothermal Energy by Idaho National Laboratory and MIT, 2006 ii Quantifying the Undiscovered Geothermal Resources in the United States 2009 by Colin F. Williams, Marshall J. Reed, Jacob DeAngelo, and S. Peter Galanis Jr iii Geothermal: The Marginalization of Earth s Largest and Greenest Energy Source, 2016 Peter Geiser, Bruce Marsh, Markus Hilpert 3 P a g e

27 PROCEEDINGS, 41st Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, February 22-24, 2016 SGP-TR-209 Numerical Simulation of Critical Factors Controlling Heat Extraction from Geothermal Systems Using a Closed-Loop Heat Exchange Method Curtis M. Oldenburg 1, Lehua Pan 1, Mark P. Muir 2, Alan D. Eastman 2, Brian S. Higgins 2 1 Energy Geosciences Division C, Lawrence Berkeley National Laboratory, Berkeley, CA Greenfire Energy, 4300 Horton Ave, Unit 15, Emeryville, CA cmoldenburg@lbl.gov, lpan@lbl.gov, mark.muir@greenfireenergy.com, alan.eastman@greenfireenergy.com, brian.higgins@greenfireenergy.com Keywords: Enter your keywords here. CO 2, numerical modeling, T2Well, TOUGH2, closed-loop, thermosiphon ABSTRACT Closed-loop heat exchange for geothermal energy production involves injecting working fluid down a well that extends through the geothermal resource over a significant length to absorb heat by conduction through the well pipe. The well then needs to return to the surface for energy recovery and fluid re-injection to complete the cycle. We have carried out mixed convective-conductive fluid-flow modeling using a wellbore flow model for TOUGH2 called T2Well to investigate the critical factors that control closed-loop geothermal energy recovery. T2Well solves a mixed explicit-implicit set of momentum equations for flow in the pipe with full coupling to the implicit three-dimensional integral finite difference equations for Darcy flow in the porous medium. T2Well has the option of modeling conductive heat flow from the porous medium to the pipe by means of a semi-analytical solution, which makes the computation very efficient because the porous medium does not have to be discretized. When the fully three-dimensional option is chosen, the porous medium is discretized and heat flow to the pipe is by conduction and convection, depending on reservoir permeability and other factors. Simulations of the closed-loop system for a variety of parameter values have been carried out to elucidate the heat recovery process. To the extent that convection may occur to aid in heat delivery to the pipe, the permeability of the geothermal reservoir, whether natural or stimulated, is an important property in heat extraction. The injection temperature and flow rate of the working fluid strongly control the ultimate energy recovery. Pipe diameter also plays a strong role in heat extraction, but is correlated with flow rate. Similarly, the choice of working fluid plays an important role, with water showing better heat extraction than CO 2 for certain flow rates, while the CO 2 has higher pressure at the production wellhead which can aid in surface energy recovery. In general, we find complex interactions between the critical factors that will require advanced computational approaches to fully optimize. 1. INTRODUCTION There are many reasons that producing fluid directly from liquid-dominated geothermal systems is problematic, whether this is native fluid or a working fluid that is injected and produced for heat recovery (aka an open loop), for example: (1) the produced fluid may contain dissolved chemical components from the rock making it corrosive to the well and surface collection pipes; (2) produced fluid may transport chemical species (e.g., acid gases) from the reservoir to the surface where they must be handled as hazardous pollutants; (3) the produced fluid itself may be hazardous and require special handling or incur disposal costs; (4) injected working fluid may react with the rock and lead to formation damage, either excessively dissolving the reservoir or plugging it up; or (5) there may not be sufficient permeability in the geothermal reservoir to inject or recover working fluid at sufficient rates. One way to avoid these problems is to keep reservoir fluids isolated from the geothermal energy recovery infrastructure through the use of a closed-loop circulation system in which the working fluid never contacts the host rock. Various configurations of systems exist to isolate the host rock and native geothermal fluids from working fluids for energy recovery. In the first class of designs, the circulation system is installed in a single vertical borehole. For example, one such downhole heat exchanger design has U-shaped tubing emplaced in boreholes with perforated casings (e.g., Lund, 2003). Another kind of device in a single borehole is the wellbore heat exchanger that includes open-hole sections for limited rock-fluid interaction in low-permeability host rock (e.g., Nalla et al., 2005). Another single wellbore configuration is the coaxial or tube-in-tube design (e.g., Horne, 1980; Wang et al., 2009) with insulated central tubing. Prior study of single-well closed-loop heat exchange systems using water as working fluid have concluded that the limitations of thermal conduction through the pipe and into the working fluid, combined with local thermal depletion of the reservoir around the pipe, limit the heat extraction capability of these systems (e.g., Nalla et al., 2005). However, recent developments in reservoir stimulation, drilling technology, and the use of novel working fluids, coupled with the imperative to lower environmental impacts of geothermal energy, are inspiring renewed interest in closed-loop systems. In this study, we consider a wide U-shaped configuration with a significant horizontal portion to increase contact with the hightemperature reservoir as shown in Figure 1. The idea is that the reservoir in the horizontal section could be stimulated (e.g., by hydraulic fracturing) during well construction to enhance reservoir natural convection. Furthermore, many of these systems could be built in parallel to extract heat from the reservoir. In addition, while water is an excellent working fluid to extract heat, other fluids such as supercritical CO 2 may have significant advantages due to their expansion upon heating, which under certain conditions creates a thermosiphon that can entirely or partially eliminate the need for pumping and provides a high-pressure outlet stream that can be used to generate power. The purpose of this paper is to demonstrate the modeling capabilities that we have applied to such a system, and to 1

28 Oldenburg, Pan, Muir, Eastman, Higgins describe our modeling results that examine critical factors and their role in controlling performance of the U-shaped closed-loop heat exchanger using CO 2 as the working fluid. We note that CO 2 at a given post-turbine pressure and temperature is assumed to be available at the wellhead for injection. In Figure 1, this CO 2 is shown available at 7.5 MPa and 75 ºC. If a high flow rate in the well is desired, the CO 2 may have to be compressed just before injection into the well. This compression process will increase the injection temperature and pressure as will be shown in the results below. We note further that the U-shaped closed loop would require the use of horizontal drilling and careful ranging to create the long horizontal run of the well with vertical return sections, topics not discussed in this paper. In addition, while we assume a stimulated zone in some of our simulations, we address neither the process nor the cost of stimulating the reservoir in this study. Our study is focused on modeling and simulation of the flow and heat transfer processes involved in the U-shaped closed loop heat recovery system and does not address either surface energy recovery or economic feasibility. Figure 1: Sketch of closed loop geothermal energy system for CO 2 flowing from inlet (upper left-hand side) to outlet (upper right-hand side). WH inj = wellhead of injection leg; WB inj = wellbottom of injection leg; WB pro = wellbottom of production leg; WH pro = wellhead of production leg. 2. METHODS Simulations of the closed-loop system are carried out using a member of the TOUGH (Pruess et al., 2001; 2012) family of codes called T2Well (Pan et al., 2011; Pan and Oldenburg, 2014). T2Well models flow in the wellbore by solving the 1D transient momentum equation of the fluid mixture with the drift-flux model (DFM), and flow in the reservoir using standard (multiphase) Darcy s law. Although we model compression and decompression in the well that takes CO 2 from supercritical to gaseous conditions, this is not formally a phase change. Therefore, we have only single-phase flow in the CO 2 -filled pipe and in the liquid-dominated geothermal system. Because the CO 2 is isolated from the reservoir by the well casing, there is no advective coupling between the pipe and the reservoir. This is a greatly simplified system compared to the two-phase (CO 2 -rich and H 2 O-rich) wellbore-reservoir coupling processes which T2Well is capable of modeling (e.g., Oldenburg et al., 2012; Oldenburg and Pan, 2013). For single-phase conditions in the pipe, the transient momentum equation of CO 2 pipe flow, including temporal momentum change rate, spatial momentum gradient, friction loss to the pipe wall, gravity, and pressure gradient, is solved to obtain the velocity of flowing CO 2. In the reservoir, natural convection may occur depending on the permeability which limits convection and the buoyancy which drives it. In the case where the permeability of the reservoir is very small, heat transfer to the pipe is by conduction only, and the semi-analytical model of Ramey (1962) is used to model heat transfer between the reservoir and the fluid in the pipe. We refer to cases with only conduction in the reservoir as the pipeonly model. We use ECO2N V 2.0 (Pan et al., 2014) to model the thermophysical properties of CO 2 and water. Grid generation is carried out using WinGridder (Pan, 2003). 3. MODEL SYSTEM 3.1 Well The U-shaped well consists of a long (1 km) horizontal leg within the reservoir connected to two 2.5 km-long vertical injection and production sections. Base-case properties of the well and CO 2 -injection and production conditions are shown in Table 1. The total length of the well is 6 km. The working fluid (CO 2 ) is introduced at the inlet side (left-hand side in Figure 1) and produced out of the outlet on the right-hand side. Thermal conductivity of steel is 50.2 W/(m K), much higher than that of the reservoir rock and can therefore be ignored in the model. 2

29 Oldenburg, Pan, Muir, Eastman Table 2. Properties of the (6-inch diameter) well. Value Units Parameter Horizontal well (lateral) 1100 m Length (6.61 inch) m Diameter (6.06 inch) m Tube I.D. steel - Material 4.57x10-5 m Roughness factor Vertical sections of well: 2500 m Length (6.61 inch) m Diameter (6.06 inch) m Tube I.D. steel - Material 4.57x10-5 m Roughness factor 3.2 Reservoir The reservoir is assumed to be a liquid-dominated geothermal reservoir in permeable sediments at a depth of approximately 2500 m with hydrostatic pressure of 25 MPa and initial temperature of 250 ºC. The discretized domain and the vertical sections of the well (red lines) are shown in Figure 2a. As shown, we model one-half of the system (mirror plane symmetry) along the axial direction of the horizontal section of the well and assume no heat or fluid flow occurs out of the lateral boundary, such as might be appropriate if there were a series of these U-shaped wells installed parallel to each other 100 m apart in the reservoir. Figure 2b shows a vertical cross section through the horizontal section of the well showing the graded discretization with refinement around the well. Note the 40 m x 40 m region around the well that will be modeled as a stimulated region in one of our scenarios. The details of the refinement around the well are shown in Figure 2c. We refined the grid to this extent to ensure that we would capture sharp temperature gradients between the reservoir and pipe that occur in cases of strong natural convection in the reservoir. In the case of the zero-permeability reservoir, we do not discretize the reservoir at all, but instead assume that heat transfer is by conduction as calculated using Ramey s (1962) semianalytical solution. We always use the semi-analytical solution for heat transfer all along the vertical injection and production parts of the well to avoid having to discretize the overburden. Properties of the reservoir are presented in Table 2. We point out the set of simulations presented here assume a reservoir thermal conductivity of 4 W/(m ºC), consistent with measurements of sandstone (e.g., Zimmerman, 1989). (a) (b) (c) Figure 2: Discretization of the reservoir part of the closed-loop model showing (a) 3D domain (blue = overburden, red = underburden, and green = reservoir region) including the vertical legs (red lines) of the closed-loop well, (b) cross section of the horizontal well region, and (c) closeup of the well region. 3

30 Oldenburg, Pan, Muir, Eastman, Higgins Table 1. Properties of various regions of the closed-loop reservoir model. Zone Thickness (m) Porosity (vol %) Rock grain density (kg m -3 ) Rock grain specific heat (J/(kg C)) Thermal cond.* (W/(m C)) Pore compress. (Pa -1 ) k (Case 1) (m 2 ) k (Case 2) (m 2 ) k (Case 3) (m 2 ) Overburden x Reservoir x Underburden x High-k zone around well x *under liquid-saturated conditions. 4. RESULTS 4.1 Full-reservoir (3D) base case When CO 2 is injected at a specified rate into the well, it may either heat up as it compresses or cool down as it expands as controlled by its initial conditions, the injection rate, and the pipe flow capacity. This change in CO 2 pressure and temperature arises from how CO 2 is injected into the wellhead. In our conceptualization, CO 2 will be delivered to the wellhead from the energy recovery infrastructure at the surface, e.g., from the outlet of a turbine, at a certain pressure and temperature. These conditions may not be compatible with the desired flow rate for CO 2 through the U-shaped well. For CO 2 at 7 MPa and 75 ºC injected at 60 kg/s into the 6-inch well, the CO 2 heats up to approximately 110 ºC and attains a pressure of 12.5 MPa. In the thermosiphon scenario, no compression is used and the CO 2 from the outlet of the turbine flows freely down the well. Regardless of whether extra compression is needed or not, as CO 2 flows down the well into hot regions of the subsurface, its energy changes as it loses gravitational potential, heats up by compression and by absorbing heat through the hot pipe wall, and as its velocity changes. These four forms of energy, pressure-volume, thermal, kinetic, and gravitational potential are all accounted for in T2Well in the output energy gain (MW) that we will report below. We note that because mass is conserved in the pipe, and the inlet is at the same elevation as the outlet, the gravitational potential energy difference across the system is always zero. Results of energy gain for CO 2 flowing through the pipe-reservoir system for Cases 1, 2, and 3 for the full-reservoir (3D) system are shown in Figure 3. The low-k and standard-k (Cases 1 and 2, respectively) cases both produce about 1.75 MW at nearly steady state. In the low-k case (Case 1), convection is negligible in the reservoir. The small differences between Cases 1 and 2 show that convective heat transfer is not very important for the reservoir with 1 Darcy permeability. On the other hand, Case 3, with a high-k zone around the well, produces about twice as much energy as Cases 1 and 2 and demonstrates that natural convection in the reservoir can greatly enhance energy recovery. We note also in Figure 3a that the thermal resource is not appreciably depleted over the 30 years of simulation for the non-stimulated case. The model system has a constant-temperature boundary condition at the bottom that serves to replenish heat. For Case 3 with stimulated near-well region, Figure 3b shows that the energy gain declines over time as local convective heat transfer to the pipe appears to exceed the conductive heat transfer into the near-well region needed to replenish extracted heat. Temperature along the well is shown for the three cases in Figure 3b. The temperature profile Geo T represents the ambient (no-flow, or initial) pipe temperature, which reflects the geothermal gradient in the vertical parts of the well and the reservoir temperature in the horizontal parts of the well. When CO 2 is injected the temperature in the well is lower than the initial temperature everywhere except near the tops of the inlet and outlet sides of the well. This shows that there is potential for heating of the CO 2 all along the well except at shallow depths near the inlet and outlet points. The data for Case 3 in this figure demonstrate the strong benefit of the convective heat transfer that occurs if the near-well region can be stimulated to support natural convection. 4

31 Oldenburg, Pan, Muir, Eastman (a) (b) Figure 3: Simulation results of the effect of reservoir permeability on energy gain in the closed loop. (a) High-permeability in the reservoir favors convective heat transfer to the pipe. (b) The effects of convective heat transfer to the pipe are largest in the horizontal section of the closed loop. The effect of different initial CO 2 temperatures is shown in Figure 4. If the CO 2 is initially at 40 ºC instead of 75 ºC prior to compression and injection into the well, it ends up leaving the well having gained more energy due to the larger temperature difference between the working fluid and reservoir. Figure 4 shows approximately 50% improvement in energy gain for the lower temperature CO 2 (Figure 4a). However, the production temperatures of the 40 ºC case are still significantly cooler (Figure 4b) than for the 75 ºC case. We conclude that starting with colder CO 2 is advantageous for increasing the energy gained by the flowing CO 2. (a) (b) Figure 4: Simulation results of the effect of different inlet CO 2 temperatures on energy gain in the closed loop for the lowpermeability (Case 2) and high-permeability (Case 3) reservoirs. (a) Low inlet temperature improves energy recovery; (b) Heating due to convection of heat from reservoir to CO 2 occurs for high-permeability (Case 3) reservoir. The next variation we show is flow rate. As seen in Figures 5a and 5b, energy recovery may be lower for either higher or lower injection flow rates. For CO 2 as the working fluid, the reasons are more complicated than for a nearly incompressible fluid such as water, for which a similar effect was observed but for different reasons by Nalla et al. (2004). Specifically, for water with all other things equal, the flow rate can be so small that the fluid heats up too much thereby reducing the temperature difference between fluid and reservoir at the downstream ends of the well, resulting in little energy recovery. Or the flow rate may be so high that not enough time is allowed for water to efficiently absorb heat during its rapid flow through the pipe. In short, flow rate alone leads to an optimal flow rate in a waterbased system. For CO 2 on the other hand, the situation is more complicated because CO 2 density can change significantly as it heats up and expands during flow in the pipe, leading to changes in velocity even though mass flow rate is constant. Nevertheless, there is an optimum flow rate for CO 2 to maximize energy gain. The initial temperature of the injected CO 2 plays the same general role as it does for water in that colder initial temperatures lead generally to better heat gain. But for CO 2, both the effects of flow rate and initial temperature affect energy gain. As shown in Figure 5a, the 60 kg/s case is better than either the 30 kg/s or 90 kg/s cases, even though the 60 kg/s case is not the coldest (Figure 5b). 5

32 Oldenburg, Pan, Muir, Eastman, Higgins (a) (b) Figure 5: Simulation results of the effect of different CO 2 flow rates on energy gain in the closed loop for the low-permeability (Case 2) reservoir. (a) Intermediate flow rate (60 kg/s) is better than 30 kg/s or 90 kg/s for energy recovery; (b) Only the low flow-rate case results in CO 2 temperature higher at outlet than at inlet of closed loop. Another obvious factor in energy gain along the pipe is the pipe surface area. Another complication arises here with pipe diameter as a parameter because mass flow rate and pipe diameter are strongly correlated. As shown in Figure 6a, the best combination from among what we tested was 60 kg/s with a 10-inch pipe. Note that the 10-inch pipe is also the best choice if one fixes the injection rate at 48 kg/s (Figure 6a), and that the 10-inch pipe produces the highest outlet temperature at fixed injection rate (Figure 6b). (a) (b) Figure 6: Simulation results of the effect of pipe diameter on energy gain in the closed loop. (a) High flow rates in large-diameter pipes favor heat transfer to the pipe. (b) At fixed flow rate, larger temperatures develop in larger-diameter pipes in the closed loop. We mentioned the behavior of water above in a hypothetical context, but we compared water with CO 2 explicitly also. We show in Figure 7 a comparison of CO 2 and water at the same mass flow rate in the closed-loop system. We observe that water gains more energy through the system than CO 2 does because it starts out with a smaller temperature so there is greater heat conduction to the water in the pipe during its passage through the reservoir. Furthermore, we observe that the water temperature steadily rises as it flows through the pipe, arriving at the outlet of the production well as hot water. The greater energy gain might be seen at first as an advantage over CO 2, but the fact is that the water simply heats up in the system. On the other hand, the CO 2 goes from supercritical form to high-pressure gaseous form at the outlet which means it can potentially spin a turbine for efficient energy conversion; that is not possible for water under the same conditions. 6