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 - 1 - 3 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,
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,
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:
• 2010 - DOE grant to investigate CO2 geothermal in open systems,
• 2014 – 2015, LBNL modeling of geothermal production and resource depletion
over 30 years with the validated TOUGH2 computer code.
• 2015 – 2016, Intensive in-house thermodynamic modeling using
TOUGH2 and other models.
• 2015 – 2016, 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.
o
o
• World market:
12,500 MW installed with a growth rate of 4.5%.
Estimated potential of 250,000 MW.
• U.S. Market:
o
3,500 MW installed with a growth rate of about 3%.
o
At least 75,000 MW potential at 95% resource probability (USGS
2009).
• 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
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.
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.
• 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 2016. The demonstration project will require about 7 months from
October 2016 to April 2017. 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 2017. 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.
GreenFire Energy Inc.
Additional Information for
Cleantech to Market Program
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 74-316C, 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
94608. [Paper]
[email protected] , [email protected] ,
[email protected] , [email protected]
1|Page
2|Page
3|Page
Source: US Energy Information Administration
Overview Presentation
MARCH 2016
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 1910
2
ECO2G Revolutionizes Geothermal with a Closed Loop and sCO2
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
ECO2G Exploits the Massive Potential of Geothermal Energy
US Geothermal Resource
- MWe
ECO2G works where hydrothermal cannot
100,000
Hot Brittle
Zone
80,000
Vast majority of
geothermal resources
untapped
60,000
40,000
Hydrothermal
ECO2G
Enhanced Hydrothermal
ECO2G
Source USGS
20,000
Plastic
Zone
ECO2G
ECO2G
0
In Service
Identified
Suspected
High Permeability
Low Permeability
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
4
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
Environmentally benign
A Revolution in Power Generation
Utility-scale baseload power that complements
wind and solar power generation
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
ECO2G Offers Clean, Baseload, Competitive Power
Cost per MWH
ECO2G
Geothermal
Not risk adjusted
Natural Gas - Advanced Combined Cycle
= Non-Dispatchable
Natural Gas - Conventional Combined Cycle
= Dispatchable
Wind
Hydroelectric
Source: US Energy Information
Administration, April 2014
Natural Gas - Advanced Combined Cycle w Carbon Capture
Conventional Coal
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
$250.0
6
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: sCO2 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
ECO2G Creates Power, Not Legal Issues
8
ECO2G: Rapid Market Entry with Existing Projects
Many geothermal projects fail to
achieve projected production or
lose production over time
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
11
5
Strong Incentive for Operators to Cooperate
Some operators struggling to meet minimum production levels
Potential for additional revenue under wheeling/resale
arrangements
27
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
Strategy Will Initially Focus on Improving Existing Projects
7 years & beyond
5 -7 years
Green field projects
Acquire & fix “failed”
projects
2-5 years
JVs to augment power
at existing installations
Leases in place
Permits obtained
Geophysical analysis done
Need to perform all project steps
Wells drilled and logged
Power interconnect available
10
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
Slimming the belly of the duck
Growth in non-dispatchable wind and
solar is creating challenges for grid operators
Operators, regulators looking for dispatchable low-carbon solutions
ECO2G systems well positioned to step into the gap with competitively
priced, flexible energy
11
GreenFire is Building a Strong Portfolio of IP
Patents Pending:
Proprietary Research and Database:
Exclusive license with Los Alamos National
Laboratory for CO2-EGS design, a related
ECO2G™ technology
Pioneering research into closed-loop ECO2G™
Basic foundational patent application for
closed-loop ECO2G™
Accessing heat in the plastic zone
 Developing in-house team and expertise to rapidly assess the
potential of geothermal resources using advanced modeling
software
Optimized thermosiphon conditions
Additional proprietary projects:
Diverse, tiered, closed loop and/or open
geothermal power production systems in a
single project (Tiered Geothermal™)
 Finishing first ECO2G flow and thermal depletion modeling with
Lawrence Berkeley National Laboratory
 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
GreenFire Energy Inc. Team and Relationships
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
Management
Team
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
Advisory
Board
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
Collaborating
Research
Partners
Lawrence Berkeley National Laboratory
Pacific Northwest National Laboratory
University of Utah
Electric Power Research Institute
13
Thank you!
4300 Horton Street, Unit 15
Emeryville, CA 94608
Office: (888) 320-2721
www.greenfireenergy.com
14
GreenFire Energy Inc. – Reinventing Geothermal Power
GreenFire Energy is developing utility-scale CO2-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 (sCO2) 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 sCO2.
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 sCO2 in geothermal applications plus GreenFire’s
multiple patents pending for closed-loop sCO2 geothermal power production

ECO2G exploits heat that hydrothermal technology cannot access
o
o
o
Closed loop system circulates supercritical CO 2 to transfer heat; does not need
subsurface permeability, fractures or formation water circulation
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.
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
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
o
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
o
Can rehabilitate failed or underperforming hydrothermal projects with sufficient
underlying heat
o
ECO2G projects that are co-located with hydrothermal projects can be rapidly deployed
to shorten time to revenue
o
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
o
o
o
o
o

Competitive cost between $0.05 and $0.10 per KWh
Power output inherently and naturally complementary to wind and solar
intermittency
High availability, 24/7 baseload power ability contributes to meeting Renewable
Energy Portfolio Standards
Employs cost advantages of sCO 2 turbines
Robust and reliable power for special high value applications
ECO2G is the most environmentally benign form of grid-scale power
o
o
o
o
o
o
o
o
No GHG emissions
No process water consumption
No waste streams
Smallest footprint
No explosives or dangerous chemicals
No visual obstructions
No danger or impediment to wildlife
No seismicity
o No surface subsidence
2|Page
.
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





i
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 94608
888-320-2721
www.greenfireenergy.com
[email protected]
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|Page
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. Oldenburg1, Lehua Pan1, Mark P. Muir2, Alan D. Eastman2, Brian S. Higgins2
1
Energy Geosciences Division 74-316C, Lawrence Berkeley National Laboratory, Berkeley, CA 94720
2
Greenfire Energy, 4300 Horton Ave, Unit 15, Emeryville, CA 94608
[email protected], [email protected],
[email protected], [email protected], [email protected]
Keywords: Enter your keywords here. CO2, 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 CO2 for certain flow rates, while the CO2 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 CO2 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
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 CO2 as the working fluid.
We note that CO2 at a given post-turbine pressure and temperature is assumed to be available at the wellhead for injection. In Figure 1,
this CO2 is shown available at 7.5 MPa and 75 ºC. If a high flow rate in the well is desired, the CO2 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 CO2 flowing from inlet (upper left-hand side) to outlet (upper
right-hand side). WHinj = wellhead of injection leg; WBinj = wellbottom of injection leg; WBpro = wellbottom of
production leg; WHpro = 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 CO2 from supercritical to gaseous conditions, this is not
formally a phase change. Therefore, we have only single-phase flow in the CO2-filled pipe and in the liquid-dominated geothermal
system. Because the CO2 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 (CO2-rich and H2O-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 CO2 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 CO2. 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 CO2 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 CO2-injection and production conditions are shown in Table 1. The total
length of the well is 6 km. The working fluid (CO2) 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
Oldenburg, Pan, Muir, Eastman
Table 2. Properties of the (6-inch diameter) well.
Horizontal well (lateral)
Value
Units
Parameter
1100
m
Length
0.168 (6.61 inch) m
Diameter
0.154 (6.06 inch) m
Tube I.D.
steel
-
Material
m
Roughness factor
m
Length
4.57x10
Vertical sections of well:
-5
2500
0.168 (6.61 inch) m
Diameter
0.154 (6.06 inch) m
Tube I.D.
steel
-
Material
m
Roughness factor
4.57x10
-5
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
Oldenburg, Pan, Muir, Eastman, Higgins
Table 1. Properties of various regions of the closed-loop reservoir model.
Zone
Thickness
(m)
Porosity
(vol %)
Overburden
155
5
Reservoir
158
25.4
Underburden
55
5
High-k zone
40
25.4
around well
*under liquid-saturated conditions.
Rock
grain
density
(kg m-3)
2700
2700
2700
2700
Rock grain
specific
heat
(J/(kg °C))
1000
1000
1000
1000
Thermal
cond.*
(W/(m °C))
Pore
compress.
(Pa-1)
k
(Case 1)
(m2)
k
(Case 2)
(m2)
k
(Case 3)
(m2)
4.0
4.0
4.0
4.0
7.25 x 10-12
7.25 x 10-12
7.25 x 10-12
7.25 x 10-12
10-20
10-18
10-20
10-18
10-15
10-12
10-15
10-12
10-15
10-12
10-15
10-10
4. RESULTS
4.1 Full-reservoir (3D) base case
When CO2 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 CO2 pressure and temperature arises from how CO2 is
injected into the wellhead. In our conceptualization, CO2 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 CO2 through the U-shaped well. For CO2 at 7 MPa and 75 ºC injected at 60 kg/s into the 6-inch well, the CO2 heats up to
approximately 110 ºC and attains a pressure of 12.5 MPa. In the thermosiphon scenario, no compression is used and the CO2 from the
outlet of the turbine flows freely down the well. Regardless of whether extra compression is needed or not, as CO2 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 CO2 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 CO2 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 CO2 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
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 CO2 temperatures is shown in Figure 4. If the CO2 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 CO2
(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 CO2 is advantageous for increasing the energy gained by the flowing CO2.
(a)
(b)
Figure 4: Simulation results of the effect of different inlet CO2 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 CO2 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 CO2 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 CO2 on the other hand, the situation is more complicated because CO2 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 CO2 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 CO2, 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
Oldenburg, Pan, Muir, Eastman, Higgins
(a)
(b)
Figure 5: Simulation results of the effect of different CO2 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 CO2 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 CO2 explicitly also. We show in
Figure 7 a comparison of CO2 and water at the same mass flow rate in the closed-loop system. We observe that water gains more energy
through the system than CO2 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 CO2,
but the fact is that the water simply heats up in the system. On the other hand, the CO2 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
Oldenburg, Pan, Muir, Eastman
(a)
(b)
Figure 7: Simulation results for CO2 and H2O as working fluids. (a) Water gains more energy through the loop at 60 kg/s than
CO2. (b) Water temperature increases in each part of the closed loop whereas CO2 temperature may decline due to
decompression effects.
As might be inferred from the above comparison, the transition of CO2 from supercritical to gaseous form during passage through the
closed loop also enables a thermosiphon. In this variation, we investigate the flow rates that can be sustained solely by thermosiphon
assuming CO2 arrives at the injection well at a temperature of 35 ºC. As shown in Figure 8a, energy gain will be in the range of 2.5 MW
at steady state, with a thermosiphon possible for flow rates up to approximately 25 kg/s (Figure 8b). This analysis considered only the
subsurface part of the closed loop; losses during energy recovery (e.g., the heat rejection equipment) will lead to a slightly smaller
sustainable thermosiphon flow rate.
(a)
(b)
Figure 8: Simulation results for various CO2 flow rates. (a) Energy gain correlates directly with flow rate at 35 ºC inlet
temperature. (b) The closed loop will operate without need for pump only at flow rates below about 25 kg/s.
5. CONCLUSIONS
We have used a detailed coupled pipe-reservoir model to investigate the effects of various parameters on the energy gain of CO2
flowing in a U-shaped well through a geothermal reservoir. Reservoir permeability is a primary control on energy gain by the working
fluid, with natural convection strongly favoring heat transfer to fluid in the pipe. Because of compressibility, the energy gain by flowing
CO2 in the pipe is a complicated function of initial temperature, flow rate, and pipe diameter. Considering the generation and
sustainability of a thermosiphon, we find a flow rate of about 25 kg/s is the most that can be sustained in a 6-inch pipe with 35 ºC CO2
available at injection wellhead. Variables considered included pipe diameter, well depth, horizontal well length, temperature gradients,
flow rates, and pressures. Based on the unique compressibility of supercritical CO2 that can produce a thermosiphon, further modeling is
warranted of CO2 as a working fluid for closed-loop heat extraction, particularly using iTOUGH2 (Finsterle, 1999; 2005) optimization
techniques to determine the best combination of parameters to maximize energy gain and above-ground power production.
7
Oldenburg, Pan, Muir, Eastman, Higgins
ACKNOWLEDGMENTS
Support for this work was provided by GreenFire Energy. Additional support was provided by the Assistant Secretary for Fossil Energy
(DOE), Office of Coal and Power Systems, through the National Energy Technology Laboratory (NETL), and by Lawrence Berkeley
National Laboratory under Department of Energy Contract No. DE-AC02-05CH11231.
REFERENCES
Finsterle, S., 1999. iTOUGH2 user’s guide. LBNL-40040, p.130.
Finsterle, S., Demonstration of optimization techniques for groundwater plume remediation using iTOUGH2, Environmental Modelling
and Software, 21(5), 665–680, doi:10.1016/j.envsoft.2004.11.012, 2005.
Horne, R.N., Design considerations of a downhole coaxial geothermal heat exchanger, Geothermal Resources Council Transactions, 4,
569, 1980.
Lund, J.W., 2003. The use of downhole heat exchangers. Geothermics, 32(4), pp.535-543. Pan, L., and C.M. Oldenburg. "T2Well—An
integrated wellbore–reservoir simulator." Computers & Geosciences 65 (2014), 46-55.
Nalla, G., Shook, G.M., Mines, G.L. and Bloomfield, K.K., 2005. Parametric sensitivity study of operating and design variables in
wellbore heat exchangers. Geothermics, 34(3), pp.330-346.
Oldenburg, C.M., and L. Pan, Porous Media Compressed-Air Energy Storage (PM-CAES): Theory and Simulation of the Coupled
Wellbore–Reservoir System, Transport in Porous Media, 97(2) 201-221, 2013.
Oldenburg, C.M., B.M. Freifeld, K. Pruess, L. Pan, S. Finsterle, and G.J. Moridis. Numerical simulations of the Macondo well blowout
reveal strong control of oil flow by reservoir permeability and exsolution of gas. Proceedings of the National Academy of Sciences
109, no. 50 (2012): 20254-20259.
Pan, L., 2003. Wingridder-an interactive grid generator for TOUGH2. Lawrence Berkeley National Laboratory.Pan, L., and C.M.
Oldenburg. "T2Well—An integrated wellbore–reservoir simulator." Computers & Geosciences 65 (2014), 46-55.
Pan, L., C.M. Oldenburg, Y. Wu, and K. Pruess, T2Well/ECO2N Version 1.0: Multiphase and Non-Isothermal Model for Coupled
Wellbore-Reservoir Flow of Carbon Dioxide and Variable Salinity Water, Lawrence Berkeley National Laboratory Report LBNL4291E, 2011.
Pan, L., Spycher, N., Doughty, C. and Pruess, K., 2014. ECO2N V. 2.0: A New TOUGH2 Fluid Property Module for Mixtures of
Water, NaCl, and CO2. Ernest Orlando Lawrence Berkeley National Laboratory Report LBNL-6930E, Berkeley, CA (US).
Pruess, K., C.M. Oldenburg, and G.J. Moridis. TOUGH2 User's Guide Version 2. E. O. Lawrence Berkeley National Laboratory Report
LBNL-43134, 1999; and LBNL-43134 (revised), 2012.
Pruess, K., 2010. Enhanced geothermal systems (EGS) with CO2 as heat transmission fluid--A scheme for combining recovery of
renewable energy with geologic storage of CO2. Lawrence Berkeley National Laboratory.
Ramey Jr, H.J., 1962. Wellbore heat transmission. Journal of Petroleum Technology, 14(04), pp.427-435.
Wang, Z., McClure, M.W. and Horne, R.N., 2009. A single-well EGS configuration using a thermosiphon. In Workshop on Geothermal
Reservoir Engineering, Stanford University, Stanford, CA.
Zimmerman, R.W., 1989. Thermal conductivity of fluid-saturated rocks. Journal of Petroleum Science and Engineering, 3(3), pp.219227.
8