Hydrothermal Geothermal Energy

Extracts heat from naturally occurring underground reservoirs where hot water or steam has been heated by proximity to hot rock, converting thermal energy to electricity via steam turbines or binary cycle systems.

Earth's Internal Heat

Origin of Geothermal Energy

Primordial heat:

When Earth formed approximately 4.5 billion years ago, several processes generated enormous thermal energy:

Accretion heating: As planetesimals and protoplanetary material collided and merged, kinetic energy converted to heat
Gravitational compression: The increasing mass of the growing planet compressed interior material, raising temperatures
Core differentiation: As dense iron and nickel sank to form the core, gravitational potential energy released as heat

This primordial heat has been slowly dissipating ever since, but Earth's insulating crust and mantle retain substantial residual thermal energy.

Radioactive decay:

The decay of long-lived radioactive isotopes continuously generates heat within Earth:

Isotope	Half-life (billion years)	Heat production
Uranium-238 (²³⁸U)	4.47	~40% of radiogenic heat
Uranium-235 (²³⁵U)	0.70	~4%
Thorium-232 (²³²Th)	14.0	~40%
Potassium-40 (⁴⁰K)	1.25	~16%

These isotopes are concentrated in the crust and mantle. As they undergo alpha and beta decay, they release energy that converts to thermal energy through particle interactions with surrounding rock.

Heat budget:

Earth's total internal heat flow to the surface is approximately 44.2 terawatts (TW), comprising:

Radiogenic heat production: ~30 TW (60-70%)
Primordial heat loss: ~14 TW (30-40%)

For comparison, total human energy consumption is approximately 18 TW. Earth's internal heat flow far exceeds human energy needs, though only a small fraction is practically accessible.

Early in Earth's history, radiogenic heating was much greater because short-lived isotopes had not yet decayed. Heat production 3 billion years ago was approximately twice present-day levels, driving more vigorous mantle convection and plate tectonics.

The Geothermal Gradient

Temperature increases with depth below Earth's surface. This rate of temperature increase is called the geothermal gradient.

Average gradient:

In most continental crust, temperature rises at approximately:

\frac{dT}{dz} \approx 25-30°C/km

This means:

At 1 km depth: ~40-50°C (accounting for surface temperature)
At 3 km depth: ~100-120°C
At 10 km depth: ~300-350°C

Variation by tectonic setting:

Setting	Gradient (°C/km)	Examples
Stable continental interior	15-25	Canadian Shield, Siberian Craton
Normal continental	25-30	Most continents
Sedimentary basins	30-40	Gulf Coast, North Sea
Active margins	40-80	Cascades, Andes
Volcanic/rift zones	80-200+	Iceland, East African Rift
Mid-ocean ridges	100-300+	Mid-Atlantic Ridge

Areas with elevated geothermal gradients are prime targets for geothermal power development. Volcanic regions, rift zones, and tectonic plate boundaries concentrate accessible high-temperature resources.

Heat flow:

Heat flows from Earth's interior to the surface via conduction and convection:

q = -k\frac{dT}{dz}

Where:

q = heat flux (W/m²)
k = thermal conductivity of rock (~2-4 W/m·K)
dT/dz = geothermal gradient

Average surface heat flow:

Continental crust: ~65 mW/m²
Oceanic crust: ~101 mW/m²
Global average: ~87 mW/m² (0.087 W/m²)

This is roughly 0.03% of the solar energy absorbed by Earth's surface, illustrating why direct surface heat collection is impractical. Geothermal energy extraction requires accessing concentrated subsurface heat.

Temperature Profile Through Earth

Layer	Depth (km)	Temperature
Surface	0	~15°C (average)
Upper crust	0-15	15-400°C
Lower crust	15-35	400-1000°C
Upper mantle	35-660	1000-1900°C
Lower mantle	660-2890	1900-3500°C
Outer core	2890-5150	3500-5000°C
Inner core	5150-6371	5000-6000°C

The lithosphere (crust and uppermost mantle, ~100 km thick) transfers heat primarily by conduction, creating steep temperature gradients. Below, the convecting mantle maintains a nearly adiabatic temperature profile with much gentler gradients (~0.3°C/km).

Hydrothermal Systems

Definition and Requirements

Heat source: Hot rock (typically >150°C for electricity generation)
Fluid: Water or steam to transport heat
Permeability: Fractures or porous rock allowing fluid circulation

When all three elements naturally occur together, the system is called a "conventional hydrothermal resource." These represent the most economically exploitable geothermal resources.

Types of Hydrothermal Reservoirs

Vapor-dominated (dry steam) systems:

Rare but highly valuable. The reservoir contains superheated steam rather than liquid water.

Characteristics:

Reservoir temperature: 230-250°C
Pressure: Below saturation pressure for the temperature
Steam produced directly at wellhead
Very efficient for power generation

Examples: The Geysers (California), Larderello (Italy), Kamojang (Indonesia)

Only about 5% of known hydrothermal resources are vapor-dominated, but they produce approximately 50% of global geothermal electricity due to their superior thermodynamic properties.

Liquid-dominated (hot water) systems:

Most common type. The reservoir contains pressurized hot water.

Characteristics:

Temperature range: 150-350°C
Water remains liquid under reservoir pressure
"Flashes" to steam when pressure drops at surface
Some systems are two-phase (water + steam)

High-temperature liquid-dominated systems (>180°C) can use flash steam technology. Lower-temperature systems require binary cycle plants.

Geopressured systems:

Deep sedimentary formations containing hot water under very high pressure, often with dissolved methane.

Characteristics:

Depth: 3-6 km
Temperature: 150-200°C
Pressure: 70-100 MPa (10,000-15,000 psi)
Contain dissolved methane (energy bonus)

Found along Gulf Coast of USA. Not commercially developed due to technical challenges.

Reservoir Characteristics

Temperature:

Minimum temperatures for electricity generation:

Dry steam plants: >180°C
Flash steam plants: >180°C (preferably >230°C)
Binary cycle plants: >100°C (practical minimum ~120-150°C)

Higher temperatures enable higher thermodynamic efficiency and more economical power generation.

Flow rate:

Sufficient fluid flow is essential. Production wells typically require:

Flow rate: 50-200 tonnes/hour per well
Wellhead pressure: 5-25 bar (flash) or 10-50 bar (dry steam)

Flow rate depends on reservoir permeability, well design, and drawdown management.

Depth:

Hydrothermal wells typically range from:

Shallow (volcanic): 500-1500 m
Standard: 1500-3000 m
Deep: 3000-5000 m

Drilling costs increase roughly exponentially with depth, making shallow high-temperature resources most economical.

Chemistry:

Geothermal fluids contain dissolved minerals and gases:

Component	Concentration	Issues
Silica (SiO₂)	100-1000 ppm	Scaling in pipes, equipment
Chloride	100-100,000 ppm	Corrosion
CO₂	0.1-5%	Emissions, pH effects
H₂S	0.01-2%	Toxic emissions, corrosion
Arsenic	0.1-50 ppm	Environmental concern
Mercury	ppb levels	Environmental concern

Fluid chemistry significantly affects plant design, materials selection, and environmental management.

Power Plant Technologies

Dry Steam Plants

Principle:

Steam from the reservoir flows directly through the turbine. No phase change required at surface.

Process:

Production wells tap steam reservoir
Steam passes through rock catcher (removes large debris)
Centrifugal separator removes moisture and particulates
Steam drives turbine connected to generator
Exhaust steam condenses in condenser
Condensate reinjected or used for cooling

Thermodynamics:

For dry steam at typical conditions (180-250°C, 5-15 bar):

Ideal Carnot efficiency:

\eta_{Carnot} = 1 - \frac{T_c}{T_h} = 1 - \frac{313K}{523K} \approx 40\%

Actual efficiency: 20-30% (accounting for irreversibilities)

Characteristics:

Simplest plant design
Highest efficiency among geothermal technologies
Limited to rare vapor-dominated resources
Typical plant size: 20-100 MW per unit

Major installations:

Site	Location	Capacity	Notes
The Geysers	California, USA	1,517 MW	World's largest geothermal complex
Larderello	Tuscany, Italy	~800 MW	First geothermal power (1904)
Kamojang	Java, Indonesia	200 MW	Oldest in Indonesia (1975)
Matsukawa	Japan	23.5 MW	Only dry steam in Japan

Flash Steam Plants

Principle:

High-pressure hot water from the reservoir "flashes" to steam when pressure drops. The steam drives the turbine.

Single-flash process:

Production well brings pressurized hot water to surface
Water enters flash separator (lower pressure than reservoir)
Portion of water vaporizes ("flashes") to steam
Steam separated from remaining liquid (brine)
Steam drives turbine
Brine and condensed steam reinjected

Flash physics:

When pressure drops below saturation pressure, water partially vaporizes. The flash fraction depends on initial temperature and flash pressure:

x_{flash} = \frac{h_1 - h_f}{h_{fg}}

Where:

x_flash = mass fraction that flashes to steam
h₁ = enthalpy of incoming fluid
h_f = liquid enthalpy at flash pressure
h_fg = latent heat of vaporization at flash pressure

For water at 250°C flashing to 1 bar: ~15-20% becomes steam.

Double-flash process:

The brine from the first flash separator enters a second, lower-pressure separator for additional steam extraction.

Benefits:

15-25% more power than single-flash
Better utilization of geothermal fluid
More complex plant, higher capital cost

Triple-flash:

A third stage extracts even more energy. Used where very high-temperature resources justify added complexity.

Efficiency:

Configuration	Efficiency	Typical temperature
Single-flash	10-15%	180-250°C
Double-flash	15-20%	230-300°C
Triple-flash	18-25%	>280°C

Characteristics:

Most common geothermal technology (~65% of global capacity)
Requires high-temperature resources (>180°C)
Plant sizes: 5-150 MW per unit
Some emissions (CO₂, H₂S) from flashed steam

Binary Cycle Plants

Principle:

Geothermal fluid heats a secondary working fluid with lower boiling point. The working fluid vaporizes and drives the turbine. Geothermal fluid never contacts turbine.

Process:

Geothermal fluid (hot water) pumped from well
Passes through heat exchanger
Transfers heat to organic working fluid
Working fluid vaporizes at lower temperature than water
Vapor drives turbine connected to generator
Working fluid condenses, recirculates (closed loop)
Cooled geothermal fluid reinjected

Working fluids:

Fluid	Boiling point	Critical temp	Applications
Isobutane	-12°C	135°C	Most common
Isopentane	28°C	187°C	Higher temp resources
R-134a	-26°C	101°C	Low temp resources
R-245fa	15°C	154°C	Medium temp
Ammonia	-33°C	132°C	Kalina cycle

The Organic Rankine Cycle (ORC) is the standard binary configuration. The Kalina cycle uses ammonia-water mixture and can achieve slightly higher efficiency but greater complexity.

Efficiency:

Binary plants operate at lower temperatures, limiting thermodynamic efficiency:

Resource temp	Binary efficiency
100°C	5-8%
120°C	8-10%
150°C	10-13%
180°C	12-15%

Characteristics:

Can utilize lower-temperature resources (100-180°C)
Zero emissions (closed loop, no contact with atmosphere)
CO₂ in geofluid remains sequestered
Smaller unit sizes: 1-50 MW typical
Higher capital cost per kW than flash
~90% of new US geothermal plants since 2000

Advantages over flash:

Applicable to moderate-temperature resources
No direct emissions
Works with corrosive/scaling fluids (isolated by heat exchanger)
Modular, scalable design

Combined Cycle and Hybrid Systems

Combined flash-binary:

High-temperature resources can use flash for initial power extraction, then binary cycle on the remaining brine.

Benefits:

10-20% more power than flash alone
Better resource utilization
Common in high-temperature fields

Geothermal-solar hybrid:

Solar thermal energy supplements geothermal heat, boosting fluid temperature and power output.

Geothermal-biomass hybrid:

Biomass combustion supplements geothermal heat for higher efficiency.

Thermodynamic Analysis

Carnot Efficiency Limit

Maximum theoretical efficiency for any heat engine:

$$\eta_{Carnot} = 1 - \frac{T_c}{T_h}$$

Where temperatures are in Kelvin.

Hot side (°C)	Cold side (°C)	Carnot limit
150	40	26%
200	40	34%
250	40	40%
300	40	45%

Geothermal plants typically achieve 40-60% of Carnot efficiency due to:

Irreversibilities in heat exchange
Turbine inefficiency
Parasitic loads (pumps, fans)
Practical temperature differences required

Exergy Analysis

Exergy (available work) better characterizes geothermal resource quality than energy alone.

Specific exergy of geothermal fluid:

e = (h - h_0) - T_0(s - s_0)

Where:

h, s = enthalpy and entropy of geofluid
h₀, s₀ = reference state (ambient conditions)
T₀ = ambient temperature (K)

Higher-temperature resources have higher specific exergy and greater power potential per unit mass flow.

Utilization Efficiency

Geothermal utilization efficiency compares actual power output to exergy input:

\eta_u = \frac{W_{net}}{E_{in}} = \frac{W_{net}}{\dot{m} \cdot e}

Typical values:

Dry steam: 50-70%
Flash steam: 35-50%
Binary: 25-45%

Parasitic Loads

Geothermal plants have significant auxiliary power requirements:

Component	% of gross output
Production well pumps	5-15%
Injection pumps	2-5%
Cooling system	5-15%
Working fluid pumps (binary)	3-8%
Gas extraction	1-3%
Total parasitic	15-40%

Low-temperature binary plants have the highest parasitic loads (up to 40% of gross), significantly reducing net output.

Global Deployment

Installed Capacity

As of year-end 2024, global hydrothermal geothermal power capacity reached approximately 15-17 GW across 28-35 countries.

Top 10 countries (2024):

Rank	Country	Capacity (MW)	% of national electricity
1	United States	3,937	<1%
2	Indonesia	2,653	~5%
3	Philippines	1,984	~12%
4	Türkiye	1,734	~3%
5	New Zealand	1,207	~18%
6	Kenya	985	~45%
7	Mexico	976	~2%
8	Italy	916	~2%
9	Iceland	786	~25%
10	Japan	576	<1%

Global totals:

Installed capacity: ~15-17 GW
Annual generation: ~95-100 TWh
Share of global electricity: ~0.3-0.4%
Number of geothermal fields: ~200
Number of power plants: ~600+
Production wells: ~3,700

Historical Development

Year	Event
1904	First geothermal electricity at Larderello, Italy (experimental)
1911	First commercial geothermal plant, Larderello (250 kW)
1958	Wairakei, New Zealand (first large flash plant)
1960	The Geysers, USA (first US commercial plant, 11 MW)
1970s	Rapid expansion during oil crises
1980	Global capacity: ~2 GW
1987	The Geysers peak: >2,000 MW
2000	Global capacity: ~8 GW
2010	Global capacity: ~11 GW
2020	Global capacity: ~14 GW
2024	Global capacity: ~16-17 GW

Growth has been modest compared to solar and wind, averaging ~3-5% annually. The geographic limitation to tectonically active regions constrains expansion.

Major Geothermal Fields

The Geysers (California, USA):

Capacity: 1,517 MW (18 plants)
Type: Dry steam (vapor-dominated)
World's largest geothermal complex
Operating since 1960
Peak production ~2,000 MW (1987), declined due to steam depletion
Wastewater injection program extends field life

Larderello (Italy):

Capacity: ~800 MW
Type: Dry steam
First geothermal power plant in history (1904)
Continuous operation for over 110 years
Pioneered geothermal technology

Cerro Prieto (Mexico):

Capacity: 720 MW
Type: Flash steam
One of largest flash plants globally
Operating since 1973

Makiling-Banahaw (Philippines):

Capacity: ~458 MW
Type: Flash steam
Major contributor to Philippine renewable energy

Salak (Indonesia):

Capacity: ~377 MW
Type: Flash steam
Part of Indonesia's extensive geothermal development

Hellisheiði (Iceland):

Capacity: 303 MW electricity + district heating
Type: Flash + binary
Combines power and heat production
CarbFix CO₂ injection project

Countries with High Geothermal Penetration

Country	Geothermal share	Notes
Kenya	~45%	Rapid development, targeting 5 GW by 2030
Iceland	~25%	Also >90% of heating from geothermal
El Salvador	~24%	Significant renewable contribution
New Zealand	~18%	Expanding capacity
Nicaragua	~15%	Central American geothermal belt
Costa Rica	~12%	Part of diverse renewable mix
Philippines	~12%	Long history of development

These countries demonstrate geothermal's potential as a major electricity source where resources exist.

Economics

Capital Costs

Geothermal power is capital-intensive. Major cost components:

Component	% of total	Cost drivers
Exploration	10-15%	Surveys, test wells, risk
Drilling	30-50%	Depth, geology, well count
Power plant	25-35%	Technology, capacity
Steam gathering	10-15%	Piping, separators
Transmission	5-10%	Distance to grid

Total installed costs (2020-2024):

Region/type	$/kW
Global weighted average	$3,500-4,500
Flash (high-temp)	$2,500-4,000
Binary (moderate-temp)	$3,500-5,500
Best projects	$2,000-2,500
Challenging projects	$5,000-7,000

Costs have not declined as dramatically as solar/wind due to:

Site-specific geology (no standardization)
Drilling technology improvements slower than solar manufacturing
Limited scale compared to other renewables

Operating Costs

Geothermal has relatively low operating costs but requires ongoing reservoir management:

Component	$/MWh
Operations & maintenance	$10-20
Well workover/replacement	$5-15
Make-up wells (field decline)	$5-20
Royalties/land lease	$2-5
Total O&M	$20-50

Unlike fossil fuels, geothermal has no fuel cost, but reservoirs require active management to maintain production.

Levelized Cost of Electricity (LCOE)

Global average LCOE (2022-2024):

$$LCOE \approx $0.05-0.08/kWh$$

Metric	Value
IRENA global weighted average (2022)	$0.056/kWh
Range (project-dependent)	$0.04-0.14/kWh
Geothermal hotspots (Iceland, etc.)	$0.04-0.06/kWh
Moderate-temp binary	$0.08-0.12/kWh

Geothermal LCOE is competitive with fossil fuels and other renewables in favorable locations, but higher than utility-scale solar/wind in most markets.

Capacity Factor

Geothermal's key economic advantage is high capacity factor:

Technology	Capacity factor
Geothermal	80-95%
Nuclear	90-93%
Natural gas CC	40-60%
Coal	40-80%
Hydropower	30-50%
Wind (onshore)	25-45%
Solar PV	15-25%

High capacity factor means geothermal plants generate electricity nearly continuously, providing baseload power. This partially offsets higher capital costs.

Annual generation:

A 100 MW geothermal plant at 90% capacity factor produces: $$100 MW \times 8760 h \times 0.90 = 788,400 MWh/year$$

A 100 MW solar plant at 20% capacity factor produces: $$100 MW \times 8760 h \times 0.20 = 175,200 MWh/year$$

Geothermal produces 4.5× more energy per MW installed.

Exploration Risk

Geothermal development faces unique exploration risk:

Drilling costs: $1-5 million per well
Success rate: 50-80% for production-grade wells
Several wells typically needed per MW
Early-stage exploration can be 15-30% of total cost
Risk concentrated before revenue begins

This front-loaded risk profile deters some investors. Government risk mitigation programs (e.g., drilling insurance, exploration grants) can facilitate development.

Environmental Aspects

Emissions

CO₂ emissions:

Geothermal plants emit some CO₂ dissolved in geofluids:

Plant type	g CO₂/kWh
Binary (closed loop)	~0 (operational)
Flash/dry steam (open)	15-55
High-CO₂ fields	Up to 200
Global average	~45
Natural gas combined cycle	~400
Coal	~900

Binary plants with reinjection have near-zero operational emissions. Flash and dry steam plants release CO₂ from the geofluid, though far less than fossil fuels.

Some plants (Iceland, New Zealand) reinject CO₂ back into reservoirs, approaching zero emissions even for flash systems.

H₂S emissions:

Hydrogen sulfide is toxic and malodorous. Modern plants use:

Gas extraction systems
Chemical scrubbing (Stretford, LO-CAT processes)
Reinjection

Typical H₂S emissions reduced to <1 kg/MWh with abatement.

Lifecycle emissions:

Including construction, drilling, and operations:

Geothermal: 15-55 g CO₂eq/kWh
Wind: 7-15 g CO₂eq/kWh
Solar PV: 20-50 g CO₂eq/kWh
Natural gas: 400-500 g CO₂eq/kWh

Water Use

Geothermal water use is complex:

Open-loop systems (flash/dry steam):

Extract geofluid, some lost to evaporation
Cooling towers evaporate water
Net water consumption: 5-20 L/kWh

Closed-loop binary:

Geofluid reinjected (minimal loss)
Cooling still requires water
Some use air cooling (zero water, lower efficiency)

Reservoir sustainability:

Long-term extraction can deplete reservoirs:

Steam pressure decline
Temperature reduction
Chemical changes

Reinjection of extracted fluids and supplemental water (wastewater, treated effluent) maintains reservoir pressure. The Geysers uses 20 million gallons/day of treated wastewater to sustain production.

Land Use

Geothermal has modest land footprint:

Component	Land use
Power plant	1-5 hectares per 100 MW
Well pads	0.1-0.5 ha each
Steam gathering	Pipelines across field
Total	10-50 ha per 100 MW

Comparable to or less than solar/wind per unit energy produced, given high capacity factor.

Induced Seismicity

Fluid injection can trigger small earthquakes:

Activity	Risk level	Magnitude
Production (extraction)	Low	Generally <2.0
Reinjection	Moderate	Typically <3.0
EGS stimulation	Higher	Up to 3-4+

Conventional hydrothermal operations rarely cause felt earthquakes. Enhanced Geothermal Systems (EGS), which require hydraulic stimulation, pose greater seismic risk (addressed in separate article).

Basel, Switzerland (2006): EGS project cancelled after M3.4 earthquake The Geysers: Frequent M2-3 events, rare M4+, managed through injection protocols

Monitoring and adaptive management can reduce seismic risk.

Thermal and Chemical Pollution

Thermal discharge:

Cooling water discharge can affect local water bodies. Air cooling eliminates this but reduces efficiency.

Brine disposal:

Extracted brines contain dissolved minerals (silica, heavy metals). Proper reinjection prevents surface contamination.

Scaling and corrosion:

Mineral precipitation (silite, calcite) and corrosion products must be managed to prevent equipment failure and ensure fluid does not contaminate surface environment.

Dispatchability and Grid Services

Baseload Power

24/7 generation (unlike solar/wind)
Unaffected by weather
Predictable output
High availability (95%+)

This makes geothermal valuable for grid stability, especially as variable renewables increase.

Flexibility

Modern geothermal plants can provide limited flexibility:

Load following: 50-100% range
Ramp rate: 2-5% per minute (slower than gas turbines)
Frequency regulation: Limited capability
Reserve capacity: Can provide spinning reserve

While less flexible than gas turbines, geothermal can adjust output to complement variable renewables.

Ancillary Services

Geothermal plants can provide:

Voltage support (synchronous generators)
Inertia (rotating mass)
Black start capability (some plants)

These grid services become more valuable as synchronous fossil generation retires.

Future Outlook

Growth Projections

Scenario	2030 capacity	2050 capacity
Current trend	20-25 GW	30-40 GW
Accelerated (with EGS)	30-40 GW	60-90 GW
High ambition (DOE GeoVision)	-	60 GW (US alone)

Growth depends heavily on:

Enhanced Geothermal Systems development
Cost reductions in drilling
Policy support
Successful new market development

Technology Improvements

Drilling:

Advanced drill bits (PDC, hybrid)
Automated drilling systems
High-temperature electronics
Millimeter-wave drilling (experimental)

Target: 50% reduction in drilling costs could double economically viable resources.

Power conversion:

Supercritical CO₂ cycles
Advanced organic fluids
Higher-efficiency turbines
Improved heat exchangers

Exploration:

Machine learning for resource prediction
Advanced geophysical imaging
Distributed fiber-optic sensing
Reduced exploration risk

Enhanced Geothermal Systems (EGS)

EGS creates artificial reservoirs in hot dry rock by hydraulic stimulation. This could vastly expand geothermal potential beyond natural hydrothermal sites.

Key developments:

Fervo Energy: Successful EGS demonstration in Nevada (2023)
Utah FORGE: DOE research site advancing EGS techniques
European projects: Soultz, Rittershoffen demonstrating viability

EGS could enable geothermal anywhere with sufficient geothermal gradient, potentially increasing global potential from ~200 GW (hydrothermal) to 2,000+ GW.

Supercritical Geothermal

Accessing supercritical fluids (>374°C, >22 MPa for water) could dramatically increase power output per well:

IDDP project (Iceland): Drilled to 4.5 km, encountered 450°C+ fluids
Potential: 10× power per well compared to conventional

Technical challenges remain (materials, well control), but success could transform geothermal economics.

Summary

Key Specifications

Parameter	Value
Global capacity (2024)	~16 GW
Annual generation	~95-100 TWh
Capacity factor	80-95%
LCOE	$0.05-0.08/kWh
Plant efficiency	10-25%
CO₂ emissions	15-55 g/kWh
Plant lifetime	30-50 years

Technology Comparison

Type	Temp (°C)	Efficiency	Best for
Dry steam	>180	20-30%	Vapor-dominated fields
Single flash	>180	10-15%	High-temp liquid
Double flash	>230	15-20%	Very high-temp liquid
Binary ORC	100-180	8-15%	Moderate-temp resources

Strengths and Limitations

Strengths:

Baseload, dispatchable power (24/7)
High capacity factor (80-95%)
Low emissions (especially binary)
Small land footprint per MWh
Long plant life (30-50 years)
Domestic resource (energy security)
Combined heat and power possible

Limitations:

Geographically constrained (tectonic regions)
High upfront capital cost
Exploration risk (drilling before revenue)
Slow development timeline (5-10 years)
Limited scalability compared to solar/wind
Potential induced seismicity
Reservoir depletion risk

Role in Energy Transition

Hydrothermal geothermal energy occupies a valuable but constrained niche in the global energy system:

Current role:

Provides reliable baseload power in favorable regions
Critical energy source for Kenya, Iceland, Philippines, El Salvador
Complements variable renewables with firm capacity
~0.3% of global electricity

Future potential:

Conventional hydrothermal: Limited by geography (~200 GW global potential)
With EGS: Potential 10× expansion to most continental regions
Could provide 3-5% of global electricity by 2050 with aggressive development

Geothermal's unique value lies in providing carbon-free baseload power. As grids integrate more solar and wind, firm dispatchable resources become increasingly valuable. Hydrothermal geothermal, combined with emerging EGS technology, can fill this role in many regions, complementing variable renewables and contributing to deep decarbonization of electricity systems.