The Nature of Heat and Thermodynamics
The heat capacity of water is 4.184 joules
per kilogram per deg K. The heat capacity of average rock is 2000 joules/kg/deg
K. Thus, more than twice as much energy is needed to change the
temperature of water than to change the temperature of rock by the same amount.
This means that water as a medium, stores more energy than rock. It also means
that dry rock as a medium is much more susceptible to losing temperature and
does so faster. The higher the heat capacity the higher will be the thermal
inertia, which refers to its ability to keep heat. Higher thermal inertia = higher
heat capacity = more stable temperature.[2]
This means that hydrothermal geothermal systems and those EGS systems that
introduce water into a created fracture system will lose heat much slower than
a comparable closed-loop system in dry rock without water.
Heat is a form of energy. Energy is defined
as the ability to do work. Heat measures how that energy is transferred from
one body or space to another. Temperature measures the average kinetic energy
of a body or space. The first law of thermodynamics, known as the Law of
Conservation of Energy, states that energy cannot be created nor destroyed but
can only change from one form to another. Electrical, mechanical, light, heat,
and nuclear energy are examples of forms of energy. Common measures of heat are
expressed in calories, joules, and BTU (British thermal units). Electrical
energy is measured in kilowatt-hours (kWh).[3]
Total absence of heat in a body or space means that the body or space is at Absolute
zero, or 0-degrees Kelvin, which is equivalent to -278-deg Celsius. It is a
theoretical limit that has been approached in cryogenic experiments but never
reached. This also means that a body or space at any temperature above Absolute
zero contains some heat energy. A ground temperature of 50 deg F, or 10 deg C
contains quite a bit of heat energy that can be tapped for heating, and it can
receive heat energy for cooling.
Drilling and
Production Challenges in Geothermal Wells
Drilling into
a hydrothermal system often means drilling into hard and brittle igneous or
metamorphic rock with an existing fracture system that provides the porosity
and permeability for the hydrothermal system. Hydrothermal reservoirs often occur
in underpressured rocks. This means that the pressure in the wellbore is higher
than the pressure of the surrounding rocks. This also often means that operations
during drilling into existing fracture systems often lead to loss circulation
problems, since fluids move from high pressure to low pressure. Lost
circulation is when the circulation of drilling mud, drill cuttings, and
formation fluids back to the surface is disrupted. In normal circulation
drilling mud is sent through the inside of the drill pipe and out through the
jets in the drill bit to mix with the cuttings from the drill bit and help
bring them up in the space outside of the drill pipe known as the annulus. The
drilling mud also cakes the borehole with the goal of limiting loss of drilling
mud or gain of formation fluids. Loss circulation zones, especially in fractured
basement rocks, can be from large fractures that cannot be sealed off, so it is
not uncommon for such zones to result in abandoning the well. According to
PetroWiki, lost circulation in geothermal wells can be “frequent and severe,”
and materials and treatment costs for lost circulation issues can account for 15%
of well costs. Trying to fix loss circulation can damage the hydrothermal
reservoir. Loss circulation zones can also be troublesome for cementing casing.
In geothermal wells with thermal cycling of hot fluids the casing string is
cemented from total depth to surface. Lighter cement components like foam,
perlite, and bentonite, as well as silica flour, are used to help cement across
loss circulation zones. Underpressured rocks can also lead to more ‘differential
sticking’ which refers to drill pipe getting stuck on one side of a well bore
due to the pressure differential between the space within the well bore and the
space surrounding it. If it is severe, it can be reduced by lowering the
drilling mud weight. Other options include pumping oil or nitrogen into the
hole but in some cases that may not work.[4]
Geothermal
brines differ quite a bit but may be very corrosive. Some prominent fields have
quite corrosive brines. Corrosion is a production risk for some geothermal
systems. The heat of the water adds to its corrosiveness as do high amounts of
dissolved solids. Corrosion can strongly affect tubulars like drill pipe and
casing. Some tubulars can be damaged in less than a decade of use. Drill pipe and
casing need to be inspected often where corrosive fluids are present.[5]
“A World
Bank study concluded that approximately 22% of all geothermal wells worldwide
“fail” due to poor brine production, high non-condensable gases (NCGs), low
wellhead pressure, corrosive brine, and insufficient permeability. Remedial
well “workovers” often involve additional drilling with high cost and risk.”[6]
Geothermal Energy
Development: Challenges, Opportunities, and Synergies
Recent
innovations in geothermal energy development include improved waste-heat
recovery efficiency, deployable on-site direct mineral extraction units to
recover lithium and other minerals from geothermal brines, thermal energy
storage, underground heat exchange, and closed-loop geothermal via conduction
and working fluids. These have been improving risk reduction and project
economics. Knowledge discovered during oil and gas exploration and development
has led to a better understanding of subsurface geology, petrophysics,
geochemistry of brines, geomechanics and structural geology. Tools have been
developed that work in the high temperatures and pressures of oil and gas wells
in areas with high geothermal gradients (hotter temp. vs. depth gradients) and
in even much hotter geothermal wells. Reservoir rock characterization of
geothermal brine host rocks, including igneous rock petrology is important.
Other oil and gas technologies in common use like microseismic, real-time
subsurface data delivery via fiber optics, cuttings analysis, Xray diffraction
and Xray fluorescence (XRD/XRF), and a multitude of geophysical well logging
tools gather data for reservoir characterization and modeling. Enhanced
geothermal systems (EGS) involve hydraulic fracturing to induce fracture
networks in the host rock in order to increase flow rates of the hot brine.
These tools can also monitor a geothermal reservoir through time, documenting
changes in pressure, temperature, or fluid characteristics.
Estimates suggest
that only 2% of global geothermal resources occur in permeable regions amenable
to conventional geothermal production. Currently, enhanced geothermal utilizing
horizontal drilling and hydraulic fracturing offers the best power production potential
for widespread deployment away from the known developed hot spots in the
hottest areas. Advanced geothermal systems (AGS) utilize closed-loop heat
transfer and recovery and directional drilling. They could eventually be
deployed virtually anywhere at drillable depths but since the heating of the
working fluid by the surrounding hot rock and fluids is by conduction rather
than by open-loop convection with direct use of the hot fluids, the heat
transfer rate and power potential are much lower. AGS will require more wells,
although those wells could be drilled in structurally flat, more drillable
sedimentary rock more often. Conduction
is less efficient and has limitations. Closed loop AGS can, however, be used to
hot rocks as well, producing less power but also avoiding many of the significant
drilling and production problems of conventional geothermal and EGS. It can
utilize lower temperature heat which most often correlates to shallower depths.
That makes it deployable in far more places than EGS systems. EGS also is
likely to continue to have a high failure rate, at least in the short-term
until different geothermal reservoirs are better understood. AGS, once drilled
and deployed is not likely to have significant failure rates since it is not
moving water through the reservoir and drilling can occur more in known
sedimentary rock sequences than EGS. Of course, EGS costs more but also
produces more power. These and other factors make comparing open-loop EGS to
closed-loop AGS a bit more complex. AGS can also be deployed in existing boreholes
so that is another advantage and a potential synergy with oil and gas companies
in hot areas that may want to defer plugging of marginally productive wells to
get new value from them by retrofitting closed-loop geothermal. Closed-loop AGS
with supercritical CO2 as a working fluid deployed heavily could also help to
market a small amount of captured CO2 from combustion sources. In the case of
CO2 plume geothermal systems, CO2 sequestration is combined with closed-loop
geothermal. In terms of power production EGS systems should make the bulk of
new geothermal power away from the traditional geothermal areas. Closed-loop
AGS will likely stay niche but under certain circumstances could flourish.
Mining heat through well casing open to
rock involves cycling hot water and/or an enclosed secondary working fluid
through the hot rock to the surface then injecting it back into the subsurface.
A producing well and an injection well makes a loop that connects surface and
subsurface. In flash steam geothermal this is an open-loop and in binary cycle
geothermal it is a similar open loop that is used to heat a second closed loop
with a working fluid that increases plant efficiency.
The development
potential of geothermal is constrained foremost by cost and geography, with the
accessible high-heat sources well defined and well confined to specific places.
Away from the hottest areas most attractive to geothermal energy developers the
economic viability and feasibility drop off considerably. A disclaimer of this
book is that it is important to note that new tech applied to geothermal like hydraulic
fracturing in EGS and efficient closed-loop power cycles is not currently even
close to economically competitive with fossil fuels. Thus, the development of
these and complimentary technologies is likely to be confined to specific
niches where decarbonized power, decarbonized baseload power, direct use, and demonstration
of technology are desired. Geothermal is expected to be a significant part of
the energy transition to lower carbon sources but is not expected to be deployed
more widely until the 2030’s. By increasing geothermal brine flow rates through
hydraulic fracturing, EGS has the potential to expand the geography viable for economic
geothermal energy extraction. The utilization of existing infrastructure can
create synergies that lower costs for small-scale geothermal energy production
through technologies like closed-loop in existing oil and gas wells or mine
water geothermal in existing mines. Again, geothermal should not be considered
a feasible replacement for fossil fuels, at least in the next decade or two. It
is theoretically possible that development of ultra-deep supercritical
geothermal could replace fossil fuels, but that possibility is likely decades
away if it manifests. Fossil fuel advocate and author Alex Epstein notes that
geothermal cannot scale up due mainly to its geographical constraints. This is
why it only makes up 1% of global energy production, or about 16GW equivalent.[7]
Ultra-deep and ultra-hot geothermal is additionally constrained by technology:
drilling, casing, probing, and producing such deep and hot rocks is limited by
the depths, the high pressures, and the heat. Deeper, hotter, and higher
pressured rocks also lead to economic constraints. The reservoir brines can be
too hot to allow data to be gathered with existing tools, but estimates can be
made using laboratory conditions.
Heat recovery
innovations are applicable to recovering geothermal heat and heat from other
sources like waste-heat from combustion flues. Improved working fluids utilized
for heat transfer and exchange, notably hydrocarbons like butane and pentanes in
Organic Rankine cycles and supercritical CO2 (sCO2) in sCO2 cycles, are making
heat recovery more efficient, thereby reducing both cost per unit of energy and/or
unit of heat produced.
For geothermal
away from hot spots, commercial viability is the goal, and much will be needed
to help get it there including government subsidization, venture capital, and
private industry investment. Geothermal has a low energy density but like solar
and wind is not reliant on extracting energy from a known quantity of fuel but
from the environment itself and so is not wholly comparable in terms of energy
density. Sun, wind, and ground heat are not finite like fuels, though ground
heat can have some depletion. Strategic partnerships are being forged between
geothermal developers, oil and gas companies, oilfield service companies, and drilling
contractors.
For both EGS
and AGS there are quite a variety of designs and configurations, often
proprietary, that will be piloted, and field tested soon. As more projects come
online, understanding and modeling should get better, and economics should become
clearer and more predictable.
All geothermal
energy development, even in the most favorable areas, is constrained by high
upfront costs compared to other forms of energy development. That has limited
its growth. However, studies in the mid 2010’s revealed that geothermal
electricity generation in California was very favorable for providing clean
baseload power as well as clean peak load power, avoiding significant costs
from other sources. Other renewable sources like solar may cost less but do not
provide the reliability and dispatchability of geothermal. In October 2021
Lazard analyzed unsubsidized levelized cost of energy (LCOE) for geothermal
generation at $56-$93 per MWh. This is down about 18% from their 2019 analysis
of $69-$112 per MWh. In comparison utility scale solar had a much smaller 2019-2021
decrease from $32-$42 per MWh to $30-$41 per MWh, about a 1.5% drop. The
subsidized LCOE for geothermal for 2021 was $47-$89 per MWh.[8]
[9]
Those numbers represent quite a variability of economic projections for
different projects to consider.
While
geothermal will not come close to replacing a significant amount of fossil
fuels any time soon, it can help lower carbon emissions, provide baseload
power, provide heat for direct use, and provide off-grid power and heat especially
for vulnerable facilities. Thus, it is being developed more for these niche
uses. Without more significant breakthroughs there will be no geothermal
‘boom.’ However, it is expected to grow significantly from current levels
through the 2020’s and perhaps ramp up even more in the 2030’s as different
technologies mature, and more is understood about the rocks, reservoirs, and
reservoir stimulation.
Quantifying AGS Energy Production and Economics
There are some
important considerations when evaluating economics of AGS. Time will tell how
close power production, reservoir heat loss and stabilization, and longevity
match model projections, but the metrics look pretty good that the match will
be “in the ballpark.” Eavor predicts their loop systems will last 100+ years
with low decline rates for electricity production after higher initial decline
rates for the first 5-10 years. This longevity is an additional selling point
when comparing to other kinds of power plants.[10]
The desirability value of firm capacity clean baseload power is another selling
point.
Closed Loop Geothermal in Existing Oil and Gas Wells:
Micro Geothermal Heat Recovery
Since drilling
and casing wells is the major cost of geothermal wells, there is a great
economic advantage to utilizing existing wells for geothermal. In addition,
there are non-producing wells that could be utilized for geothermal to defer
the time to incur plugging costs. Utilizing existing oil and gas and
unproductive geothermal wells for closed loop AGS in the oil and gas wells,
typically in sedimentary basins with high geothermal gradients. In the U.S. there
are such favorable areas in the Rockies, inland from the Gulf Coast, with some
spotty areas in the mid-continent, Illinois and Appalachian Basins. The Rockies
and the Gulf Coast areas are best but there are pilot projects in smaller
hotspots as well.
In December
2022 oilfield service company Baker Hughes launched a consortium called Wells2Watts
as a private industrial partnership between Baker Hughes, Continental
Resources, INPEX and Chesapeake Energy Corporation with additional support from
technology providers Vallourec and GreenFire Energy to develop a first-ever
closed loop geothermal test facility in the world at the Hamm Institute for
American Energy in Oklahoma City. The focus is on retrofitting wells close to
the end of their productive life for closed loop geothermal electricity
production. The test well is expected to “simulate relevant subsurface
environments to test the closed-loop system for many well configurations,
validate engineering performance models, and offer scale for field pilot efforts.”
Inpex has worked with geothermal since 2011 in Japan and Indonesia. Baker
Hughes has decades of experience in geothermal. The projects are expected to be
focused in North America and Asia Pacific regions.[11]
Organic Rankine
Cycles (ORCs) for Waste-Heat Recovery in Closed-Loop Systems
An Organic
Rankine Cycle is a closed thermodynamic cycle that utilizes a working fluid.
Such a system can be used to produce power at temperatures from 80 deg C to 400
deg C. Expansion turbines produce the power. Before 2009 most projects used
axial turbines and radial inflow turbines. In 2009 Exergy launched the radial
outflow turbine (ROT) which is more efficient than previous turbine designs.
Other advantages include being more accommodating to working fluid expansion,
low speed operation, low noise, high reliability, longer bearing life, minimal
3D effects and turbulence, fewer leaks and friction losses, and quick and easy
maintenance. Exergy installed the first radial outflow turbine in a geothermal
plant in Italy in 2012. Since then, ROT tech is involved in close to 450MW of
geothermal projects globally.[12]
Optimizing Closed
Loop(s) and the ORC System
Canadian AGS
design company Eavor and German turbine company Turboden published in 2022 a
paper about optimization of their collaborative design for the German project currently
being developed. They compared different working fluids, some of which are
optimized at different temperatures and in their modeling found that normal
pentane as a working fluid offers the best efficiency at the expected inlet
temperatures for their project. Other working fluids considered were normal
butane, isopentane, and cyclopentane.[13]
Supercritical CO2
as a Working Fluid in AGS Closed-Loop Systems
Closed loop
geothermal may utilize supercritical CO2 (sCO2) as a working fluid. It offers
some interesting advantages as a working fluid. Insulated co-axial tubing or a
tube-in-tube system can be used where the cooled sCO2 is sent down the center
of the tubing, gathers heat, and expands and rises in the annulus between thinner
tubing and the outer tubing of the co-axial or tube-in-tube configuration. It
is actually cooled after spinning a turbine for power production at the surface
before being sent back down. This is for thermodynamic reasons as the cooler
fluid can extract more heat.
In closed-loop
AGS power generation is a direct function of thermal surface area. Thus, longer
wells, typically directional or horizontal wells, will yield higher power
production. A U-loop system involves 2 wells drilled from surface, turned
horizontal and meeting in the middle. They can be steered with conventional oil
and gas geosteering techniques, then joined with precision through magnetic
ranging technology also used in the oil and gas industry. Modeling for a U-loop
system indicates for two 3000m (9842ft) long laterals connected for a total
horizontal length of 6000m (19684ft) could produce about 1MW of energy in hot
rocks of about 450 deg C temperature. In comparison, most conventional
geothermal wells (injector/producer pairs) produce between 6 and 10MW of power.
Thus, we see that AGS is very limited to small amounts of power production.[14]
Closed-loop
AGS also has potential to be retrofitted in unproductive conventional geothermal
wells as well as oil and gas wells. Downhole heat exchangers (DHX) can help to
optimize heat transfer. This is because a DHX is exposed to higher brine
temperatures downhole so that the working fluid surfaces at a higher
temperature. In oil and gas applications the DHX-based system can help to power
oilfield operations or to pump oil. A gravity head pump, a downhole pump
powered by a thermosiphon created by the heat of the surrounding rock. sCO2 as
a working fluid can do this more efficiently than water. The thermosiphon
effect can thus be a key feature of closed-loop technology.[15]
CO2-Plume
Geothermal (CPG) Systems continue to be explored in order to take advantage of
the efficiency advantages of CO2 as a working fluid, which include its improved
efficiency over water in harnessing the thermosiphon effect. CPG systems
can be effective at low temperatures (~100 deg C) which are available in many
sedimentary basins at reasonably shallow depths. It also takes less energy to
inject the CO2 into cooler rocks with a lower geothermal gradient. Many of
these basins contain saline aquifers thought to be suitable for CO2
sequestration, which includes having permeable reservoirs and impermeable cap
rock to form a seal. Supercritical CO2 is injected and gradually displaces the
saline water in the reservoir. Utilizing the thermosiphon effect and other
efficiency improvements from supercritical CO2 as a working fluid can decrease
the costs of producing energy through CO2 turbines as well as offsetting some
of the parasitic pumping costs that keep operations costs for CO2 sequestration
high. CPG configurations may utilize a vertical injection well and a vertical production
well. The greater direct reservoir access in horizontal wells may be utilized
in the future. CPG systems can be direct or indirect. A direct CPG system utilizes
the produced CO2 to run a turbine to produce electricity. An indirect CPG
system utilizes a secondary closed-loop cycle to produce power.[i]
[i]
Saar, Martin O., September 1, 2012. Numerical Modeling of CO2-Plume Geothermal
(CPG) Systems. Geothermal Energy and Fluids. Project
CO2 Plume – Geothermal Energy and Geofluids (ethz.ch)
[1]
Connor, Nick, May 22, 2019. What is Heat and Work in Thermodynamics –
Definition. Thermal Engineering. What
is Heat and Work in Thermodynamics - Definition (thermal-engineering.org)
[2]
Heat Capacity and Energy Storage. Penn State, College of Earth and Mineral
Sciences. OER Initiative. Accessed 2022. Heat Capacity
and Energy Storage | EARTH 103: Earth in the Future (psu.edu)
[3]
Lloyd, Donal Blaise, 2011. The Smart Guide to Geothermal: How to Harvest
Earth’s Free Energy for Heating and Cooling. PixyJack Press.
[4]
Geothermal drilling and completion. PetroWiki. Accessed 10/2022. Geothermal
drilling and completion - PetroWiki (spe.org)
[5]
Ibid.
[6] Muir,
John R. (Greenloop), December 2020. New Opportunities and Applications for
Closed-Loop Geothermal Systems. Geothermal Rising Bulletin, Vol 49, No. 4. New
Opportunities and Applications for Closed-Loop Geothermal Energy Systems.pdf
[7]
Epstein, Alex, 2022. The Truth About Geothermal Energy. Energy Talking Points
| Geothermal
[8]
Lazard’s Levelized Cost of Energy Analysis, Version 13.0. November 2019. Lazard’s
Levelized Cost of Energy Analysis—Version 13.0
[9]
Lazard’s Levelized Cost of Energy Analysis, Version 15.0. October 2021. Lazard’s
Levelized Cost of Energy Analysis—Version 15.0
[10]
Arianna Bonzanini(1), Christian Besoiu(2), Michael
Holmes(2), Joseph Bonafin(1)(1) Turboden S.p.A
(2)
Eavor Technologies Inc. Joint Development Between Eavor and Turboden. GRC
Transactions, Vol. 46, 2022. Joint Development Between Eavor and
Turboden - Eavor
[11]
Baker Hughes Launches Consortium Exploring Technologies to Transform Abandoned
Wells for Geothermal Energy Production. Baker Hughes. December 8, 2022. Baker
Hughes Launches Consortium Exploring Technologies to Transform Abandoned Wells
for Geothermal Energy Production | Baker Hughes
[12]
Exergy’s Radial Outflow Turbine. 2022. RADIAL
OUTFLOW TURBINE – Exergy (exergy-orc.com)
[13]
Arianna Bonzanini(1), Christian Besoiu(2), Michael Holmes(2), Joseph
Bonafin(1)(1) Turboden S.p.A
(2) Eavor Technologies Inc. Joint Development
Between Eavor and Turboden. GRC Transactions, Vol. 46, 2022. Joint
Development Between Eavor and Turboden - Eavor
[14] Muir,
John R. (Greenloop), December 2020. New Opportunities and Applications for
Closed-Loop Geothermal Systems. Geothermal Rising Bulletin, Vol 49, No. 4. New
Opportunities and Applications for Closed-Loop Geothermal Energy Systems.pdf
[15] Ibid.
No comments:
Post a Comment