Geothermal energy and water use
Geothermal energy and water use
RPS Aquaterra and Hot Dry Rocks
Waterlines Report Series No 72, February 2012
Waterlines
This paper is part of a series of works commissioned by the National Water Commission on key water issues. This work has been undertaken by RPS Aquaterra Pty Ltd in partnership with Hot Dry Rocks Pty Ltd on behalf of the National Water Commission.
© Commonwealth of Australia 2012
This work is copyright.
Apart from any use as permitted under the Copyright Act 1968 , no part may be reproduced by any process without prior written permission.
Requests and enquiries concerning reproduction and rights should be addressed to the
Communications Director, National Water Commission, 95 Northbourne Avenue, Canberra
ACT 2600 or email bookshop@nwc.gov.au.
Online ISBN: 978-1-921853-56-2
Geothermal Energy and Water Use , February 2012
RPS Aquaterra and Hot Dry Rocks
Published by the National Water Commission
95 Northbourne Avenue
Canberra ACT 2600
Tel: 02 6102 6000
Email: enquiries@nwc.gov.au
Date of publication: February 2012
Cover design by: AngelInk
Front cover image courtesy of Hot Dry Rocks Pty Ltd
An appropriate citation for this report is:
RPS Aquaterra and Hot Dry Rocks, 2012, Geothermal Energy and Water Use , Waterlines,
National Water Commission, Canberra
Disclaimer
This paper is presented by the National Water Commission for the purpose of informing discussion and does not necessarily reflect the views or opinions of the Commission.
Contents
Introduction to geothermal resources
Engineered geothermal systems (EGS)
Hot sedimentary aquifers (HSA)
Low enthalpy aquifers (LEA; Direct Use)
Ground source heat pumps (GSHP)
Aquifer thermal energy storage (ATES)
Geothermal systems assessment (GSA)
Geothermal resources in Australia
Current status of geothermal resource utilisation
Future developments and trends in geothermal resource utilisation
Estimate of total industry growth/development
Geothermal water use: requirements and potential effects
EGS and HSA water-related impact issues
Low enthalpy geothermal systems impact issues
Projected industry water requirements
Availability of water resources in geothermal areas
Guiding principles for geothermal energy and water planning
Future policy needs for an expanding industry
Tables
Table 1: Installed stock of ground source heat pumps by the end of 2007 (EHPA
Figures
Figure 1: Tectonic plate boundaries of the Earth (modified from Geothermal
Figure 2: Worldwide distribution of geothermal power plants (modified from
NATIONAL WATER COMMISSION — WATERLINES iv
Figure 3: Geothermal energy applications in Australia (modified after Ayling
Figure 5: Schematic design of a binary cycle power plant (modified after Ayling
Figure 6: Schematic design of an HSA geothermal system (modified after
Figure 7: Industrial applications for LEAs (modified after Greenearth Energy
Figure 12: Schematic design of the Birdsville power station (modified after Ergon
Figure 14: Total sales of GSHP in the eight most significant European countries
Figure 15: Comparison of UK heat pump installations compared to selected
Figure 17: Australia’s 245 river basins, with geothermal licences superimposed
Figure 19: Australia’s 367 GMUs with geothermal licences superimposed
Figure 21: TDS concentrations in the Cadna-owie –Hooray Aquifer in the Great
NATIONAL WATER COMMISSION — WATERLINES v
AWRIS
BoM
CAGA
CO
2
CoAG
CSG
DECCW
DERM
DfW
DNRM
DPI
DPIPWE
Abbreviations and acronyms
$
1D
ABARE
ACT
AGEA
AGEG
ATES
AWR 2005
DRET
DSE
DWLBC
EA
EGS
EHPA
EIR
Australian dollars one-dimensional
Australian Bureau of Agricultural and Resource Economics
Australian Capital Territory
Australian Geothermal Energy Association
Australian Geothermal Energy Group
Aquifer Thermal Energy Storage
Australian Water Resources 2005 (the baseline assessment of water resources for the National Water Initiative)
Australian Water Resources Information System
Bureau of Meteorology
Central Adelaide Groundwater Area carbon dioxide
Council of Australian Governments coal-seam gas
Department of Environment, Climate Change and Water (NSW)
Department of Environment and Resource Management (Queensland)
Department for Water (SA), former DWLBC
Department of Natural Resource and Water (Queensland); now DERM
Department of Primary Industries (Vic.)
Department of Primary Industries, Parks, Water and Environment
(Tasmania)
Department of Resources, Energy and Tourism (Cth)
Department of Sustainability and Environment (Victoria)
Department of Water, Land and Biodiversity Conservation (SA); since July
2010 Department for Water (DfW)
Environment Agency (United Kingdom)
Engineered Geothermal Systems
European Heat Pump Association environmental impact report
NATIONAL WATER COMMISSION — WATERLINES vi
HR
HSA
HWR kbbl kL km kW kWe
GMU
GSA
GSHP
GW
GWh
HDR
HE
HFR
EPA 1970
ETS
FIT
GAB
GABCC
GABSI
GAP
GDP
GEA 2010
GERA 2005
GFC
GL
GL/a
GMA
Environment Protection Act 1970 (Vic.)
Emissions Trading Scheme feed-in tariff
Great Artesian Basin
Great Artesian Basin Coordinating Committee
Great Artesian Basin Sustainability Initiative
Groundwater Action Plan
Geothermal Drilling Program
Geothermal Energy Act 2010 (Qld)
Geothermal Energy Resources Act 2005 (Vic.) global financial crisis
Gigalitre = 1 000 000 000 litres = 1000 Megalitres gigalitres per annum
Groundwater Management Area
Groundwater Management Unit
Geothermal Systems Assessment
Ground Source Heat Pump
Gigawatt = 1 000 000 000 watts = 1000 Megawatts
Gigawatt hour = a unit of energy equal to 1 000 000 000 Watt hours hot dry rock hydrogen embrittlement hot fractured rock hot rock hot sedimentary aquifer hot wet rock thousands of barrels (1 kbbl is approximately 159 kL) kilolitre = 1000 litres kilometre = 1000 metres kilowatt = 1000 watts kilowatt electric = 1000 watts of electric capacity
NATIONAL WATER COMMISSION — WATERLINES vii
kWh
MWt mW/m 2
NCG
NRMA 2004
NSW
NT
NWC
NWI
ORC
PCV
PGEA 2000
PGER 2000
PGER 2007
L
LEA
L/min
L/s m
Ma
MA 1992
MDB
MDBA mg/L
ML
MRDA 1995
MW
MWe kilowatt hour = a unit of energy equal to 1000 watt hours. The kilowatt hour is most commonly known as a billing unit for energy delivered to consumers by electric utilities. litre low enthalpy aquifer (also referred to as ‘direct use’) litres per minute litres per second metre million years
Mining Act 1992 (NSW)
Murray –Darling Basin
Murray –Darling Basin Authority milligrams per litre
Megalitre = 1 000 000 litres = 1000 kilolitres
Mineral Resources Development Act 1995 (Tas.)
Megawatt = 1 000 000 watts = 1000 kilowatts
Megawatt electric (the electrical power produced from a geothermal system)
Megawatt thermal (the thermal power produced from a geothermal system) milliwatt per square metre non-condensable gas
Natural Resources Management Act 2004 (SA)
New South Wales
Northern Territory
National Water Commission (also referred to as the Commission)
National Water Initiative
Organic Rankine Cycle permissible consumptive volumes
Petroleum and Geothermal Energy Act 2000 (SA)
Petroleum and Geothermal Energy Regulations 2000 (SA)
Petroleum and Geothermal Energy Resources Act 2007 (WA)
NATIONAL WATER COMMISSION — WATERLINES viii
SA
SAHFA
SEO
SWMA
TDS
TJ
WA
WAP
PIRSA
REDP
REF
RET
RSPT
RWIA 1914
WCD
WMA 1999
WMA 2000
WMP
WSPA
UK y
Department of Primary Industries and Resources of South Australia
Renewable Energy Demonstration Program
Renewable Energy Fund
Renewable Energy Target
Resource Super Profit Tax
Rights in Water and Irrigation Act 1914 (WA)
South Australia
South Australian Heat Flow Anomaly
Statement of Environmental Objectives surface water management area total dissolved solids terrajoule (derived unit of energy)
Western Australia water allocation plan
Water Control District
Water Management Act 1999 (Tas.)
Water Management Act 2000 (NSW) water management plan
Water Supply Protection Area
United Kingdom year
NATIONAL WATER COMMISSION — WATERLINES ix
Glossary
advection blowdown closed-loop system conduction consumptive use crust enthalpy feedwater fumarole geyser hot springs lava magma open-loop system
The process where energy (heat) transfers via flow of fluids (water) from one level to another (convection is a special case of advection whereby fluid moves in closed-loop pathways).
The removal of liquids and/or solids from a process/storage vessel/pipeline by the use of pressure for the purpose of controlling boiler water parameters within prescribed limits to minimise scale, corrosion, etc. Blowdown is also used to remove suspended solids present in the system, caused by feedwater contamination, by internal chemical treatment precipitates, or by exceeding the solubility limits of otherwise soluble salts, and the water deficit is subsequently made up by more feedwater.
A closed-loop system has a geological context, whereby any geothermal working fluid brought to the surface via a production well is pumped back underground to the same geological unit via an injection well; these systems involve very low consumptive use, with water required only to top up if there are minor water losses. The
GSHP sector, however, adopts a slightly different (engineering context) definition of ‘closed-loop’ to describe the circulation of a refrigerant around a closed-loop of pipework (in some cases, air is used).
The process whereby energy (heat) transfers from one rock unit to another via direct contact.
The use of water for private benefit consumption purposes, including irrigation, industry, urban and stock and domestic use.
(NWI definition.)
The outermost layer of the Earth.
A measure of the total energy of a thermodynamic system. Enthalpy is a measurement of heat and is synonymous with temperature.
Water fed to a system to ‘make up’ or replace that which is lost by evaporation or other causes such as blowdown.
A small opening (fissure) in the Earth’s crust through which smoke and gasses are emitted; they are often associated with volcanoes.
A hot spring characterised by intermittent turbulent discharge of water and steam.
A source of geothermally heated groundwater that emerges onto the surface of the Earth from underground.
Magma that rea ches the Earth’s surface is called lava.
Molten rock found beneath the surface of the Earth which commonly collects in chambers beneath volcanoes.
Open-loop systems in the GSHP industry use water drawn from a well or surface water body (e.g. lake/stream) to circulate through the system and heat exchange unit, with the water being returned to the ground via a recharge well, or discharged to the surface.
NATIONAL WATER COMMISSION — WATERLINES x
Organic Rankine Cycle ORC is named for its use of an organic fluid within a Rankine cycle heat recovery process to generate energy from lower temperature sources, such as geothermal heat, solar ponds etc. (i.e. compared to coal- or gas-fired). parasitic loading Some of the energy produced by the power plant is consumed by the power plant itself (for pumps, fans, etc.), and so cannot be sent to the grid to meet consumer demand. reservoir volcano
A large volume of underground hot water and/or steam hosted in the rock within connected fractures or pores through which fluid can circulate; the reservoir can be engineered through fracture stimulation (general practice involves injection of pressurised fresh water, without the incorporation of chemicals) and working fluid can be artificially introduced.
An opening on the Earth’s crust through which lava, gas and ash can escape. working fluid (carrier) A working fluid (or carrier) is required to extract heat from the EGS to the surface. The fluid is usually water in liquid or vapour phase, depending on its temperature and pressure.
NATIONAL WATER COMMISSION — WATERLINES xi
Executive summary
Australia lacks conventional hydrogeothermal resources (e.g. similar to those in New
Zealand) , and Australia’s only currently operating geothermal power plant, located in
Birdsville, Queensland, yields just 80 kWe (net) from a non-conventional hot sedimentary aquifer (HSA) system. While Australia is seeking to position itself as a leading global developer of geothermal energy technologies, through collaborative initiatives by Australian governments, academia and industry, other countries are also investing in this nascent sector. For example, Germany is geologically similar to Victoria but with higher feed-in tariff arrangements providing significant financial support, and it already has four non-conventional geothermal energy electricity plants in operation, totalling about 7 MWe.
Australia has excellent potential for significant energy production from non-conventional engineered geothermal system (EGS) and HSA developments. EGS and HSA developments currently underway in Australia are each in the order of tens of megawatts in scale, the most advanced to date being located in South Australia. There is also considerable scope for energy production from shallow systems such as low enthalpy aquifers (LEA) and ground source heat pump (GSHP) applications. Given the scarcity of water resources in Australia, however, it is unlikely that there will be growth in (shallow) aquifer thermal energy storage
(ATES) applications in the foreseeable future.
The geothermal legislation in all jurisdictions is subject to the provisions of the various state and territory water acts, and existing arrangements are considered to be capable of managing geothermal project water issues if implemented appropriately (with some notable exceptions).
Improved integration would be aided by removing exemptions in geothermal legislation and possibly by combining legislation within the one act to cover the range of water balance elements (e.g. extraction, reinjection, and discharge to environment) that are controlled by separate water and/or environmental legislation.
Exemptions from the geothermal legislation for low enthalpy projects apply in four jurisdictions: Victoria (less than 70 ºC or shallower than 1000 m); Northern Territory (less than
70 ºC); New South Wales (less than 100 ºC); and Western Australia (small-scale GSHP or non-commercial direct use). However, no state or territory has an exemption from the provisions of the water legislation for water-interfering or water-taking activities associated with geothermal projects (other than the nominal but not material exemption in Tasmania).
Consumptive water-use requirements are generally quite low for exploration and construction stages (including EGS and HSA), which involve water use and disposal for well drilling, construction and testing activities. These water-related requirements are comparable to those for conventional drilling activities and thus could be managed under existing permit arrangements for water well drilling and testing issued by the relevant state or territory jurisdiction. Depending on the scale of the development, the volume of water involved over a specified time frame (e.g. as the geothermal field is developed over a number of years) may be deemed significant, and the sustainability of the extraction could be considered under existing water management arrangements in each of the jurisdictions.
Water-use requirements for different geothermal systems can vary markedly. Most operating
EGS/HSA geothermal systems for electricity generation recirculate the working fluid back into the target extraction formation. These closed-loop systems involve little to no consumptive water use, other than minor top ups (i.e. ~1% of total throughput). These water-use requirements are consistent with those required for most mining operations and thus could be managed under existing arrangements by the relevant jurisdiction.
Project approvals for closed-loop systems should incorporate requirements for management strategies should fluid losses be experienced, including addressing potential increased water use, water quality issues and thermal balances (all of which the geothermal operation would seek to manage carefully to ensure project viability).
NATIONAL WATER COMMISSION — WATERLINES xii
For water planning purposes, the potential geothermal energy water requirements are estimated to be around 1 gigalitre per annum (GL/a) per 40 MW installed capacity of electricity generation (approximately 3 ML/d per 40 MW). This includes allowances for construction and operational requirements for geothermal development over a range of EGS and HSA assumptions but excludes the cooling requirements of electricity generating plants
(by definition, it also does not allow for other low enthalpy or direct-use types of geothermal development).
Some geothermal systems are open-loop when operational (usually direct use shallow/low enthalpy systems, and, uniquely, the Birdsville HSA system), where the water is not recirculated back into the target extraction formation. These systems do involve water use and disposal, usually to/from separate water sources (e.g. often involving a surface water body). Options for sourcing and/or discharging of water for open-loop systems may trigger the need for specific licensing and planning requirements due to the higher risk of environmental, social and economic impacts, which could be managed appropriately under existing water policy and legislation. If there is significant growth in low enthalpy and GSHP systems then future planning and policy should consider heat balance issues along with water balance issues.
For geothermal power plants, the primary consumptive water requirement during the production phase is for cooling purposes, although there are some minor ancillary requirements such as power plant amenities and facilities. Geothermal power plants in
Australia are likely to use Organic Rankine Cycle (ORC) binary units. Where geothermal power plants are located remote from plentiful water sources, the combination of a hot climate and limited access to water will require innovative designs for power plant cooling systems.
In relation to the potential for impacts, the geothermal industry has some distinct differences compared to other resource sectors (mining, oil and gas), notably that EGS and HSA systems do not involve extraction of large volumes of rock/ore or oil/gas. Although EGS use similar drilling and well construction techniques to the oil and gas sector the major difference is that hydraulic fracture stimulation for EGS typically uses only water (no chemicals). A successful
EGS is also developed at great depth (up to 5000 m), with resistive layers above the reservoir that limit the potential for transmission of impacts towards the surface (e.g. from fracture stimulation or thermal gradients). HSA (and low enthalpy) systems are developed at lower temperatures and/or shallower depths, but these systems rely on the natural permeability of the aquifers, and the related flow and circulation patterns (i.e. do not involve fracture stimulation).
State or territory governments should consider a precautionary and adaptive approach to manage the potential environmental effects of any proposed fracture stimulation for geothermal purposes. For example, these activities could be constrained to the use of fresh water (i.e. no chemicals, proppants, gels, etc) and at depths in excess of 1000 m, as this would limit the potential for impacts without overly constraining the practices applied to geothermal developments. However, there also needs to be scope for site-specifics to be considered and investigated in detail by proponents to establish impacts and management plans for alternative approaches.
This report identifies a number of guiding principles that should be considered by jurisdictions to manage the potential impacts of geothermal-related water use, noting that geothermal legislation is subject to specific water acts for the management of water ‘take’. Fundamentally, geothermal companies should be treated under the same rules and regulations as other industrial water users, adequate allowance should be made in water sharing/allocation plans for those industrial uses, and project plans need to clearly and transparently communicate the water management objectives and regulatory regimes before they are approved.
NATIONAL WATER COMMISSION — WATERLINES xiii
1. Introduction to geothermal resources
1.1 Overview
Geothermal projects require access to water during several stages of development and operation. Some current geothermal exploration and development activity occurs in areas of low water supply potential and/or high water demand. However, water resources, and in particular groundwater resources, are still to be quantified in many parts of Australia. Access rights to water for geothermal applications will therefore require careful management and discussion by both water planners and the geothermal industry.
The Intergovernmental Agreement on a National Water Initiative (NWI) was signed at the
25 June 2004 Council of Australian Governments (CoAG) meeting. Through the NWI, the
Commonwealth and state governments have agreed on actions to achieve a more cohesive national approach to the way Australia manages, measures, plans for, prices, and trades water. While this initiative remains a work in progress, this report provides some insight into how to address the water use implications relating specifically to the geothermal industry.
Objectives of this report are to research and summarise current and prospective geothermal energy technologies, determine consumptive water use requirements and volumes, and promote discussion around water policy and management as it relates to the geothermal energy industry. This report also aims to:
summarise the types of geothermal technologies for the spectrum of uses, from heat transfer through to electricity production, and evaluate their impacts on water usage
quantify the extent and location of existing geothermal resource usage in Australia, and to predict future development trends
determine consumptive water use requirements across the geothermal resources industry
quantify the volume of this consumptive water use across all facets of the geothermal resources industry
consider water resource availability in the different geothermal production areas and the implications of potential water use
identify any water quality or groundwater technical issues that will need to be taken into consideration with the expansion of the geothermal energy industry
discuss geothermal energy use and water use in the context of the NWI
develop a discussion around water policy and management as it relates to the geothermal resources industry so that the report offers guidance as well as being used as a practical resource by water managers for consideration in water management and planning decisions.
This report is not designed to be a detailed technical report on geothermal energy; however, the reader is directed to further publications should more detail be required. The report is predominantly targeted towards water planners and others who have vested interests in the water and energy industries to provide a baseline of information for consideration in water management and planning decisions.
1.2 Geothermal energy
Geothermal energy is the thermal energy stored beneath the surface of the Earth, and is distributed between the host rock and natural fluids contained in pores and fractures within
NATIONAL WATER COMMISSION
— WATERLINES 1
the host rock. This heat is mainly the result of the radioactive decay of naturally occurring potassium, thorium and uranium isotopes in the Earth’s crust, which comprises ~80% of the total heat budget. The remaining heat originates from the planet’s primordial development.
In the geological r ealm, heat moves from the Earth’s interior toward the surface as the result of a number of heat transfer mechanisms. The two principal mechanisms of heat transfer are:
conduction —the process whereby energy (heat) transfers from one rock unit to another via direct contact
advection —the process where energy (heat) transfers via flow of fluids (water) from one level to another (convection is a special case of advection whereby fluid moves in closedloop pathways).
For instance, the heat under the crust melts rocks to produce magma, which wells up towards the surface of the crust due to buoyancy effects. The magma either reaches the surface, where it forms lava, or slowly cools and crystallises within the crust as granite. Surface manifestations of high heat flow include volcanoes, fumaroles, hot springs and geysers.
Surface heat flow is a measure of the flux of thermal power at the surface of the crust and is a function of the rate of heat generated within the crust plus heat conducted from the deeper mantle. The thermal state of the crust can be expressed at its surface in the form of heat flow units (mW/m 2 ) and it is generally assumed that heat is transported to much of the Earth’s surface by conductive means.
The average rate of heat flow through the crust is approximately 59 mW/m 2 (Tester et al.
2006). However, advantageous geological conditions prevailing in some areas of the Earth’s surface result in much higher values.
In order to transfer heat from deeper, inaccessible areas of the Earth to the shallow subsurface, a carrier is required. The most ubiquitous of these is water that has penetrated deep into the crust from rainfall recharge areas. One such transfer mechanism is found in earthquake-prone areas where active fault systems act as conduits for water to seep into the
Earth. The rainwater is heated as it descends into the crust and is eventually incorporated into the subsurface fluid flow system.
Power derived from geothermal sources can broadly be defined as being ‘conventional’ or
‘non-conventional’ resources. Conventional geothermal resources are commonly referred to as hydrothermal geothermal systems. These systems exploit naturally convecting hydrothermal (hot water or steam) resources from shallow depths (a few hundred metres to a few kilometres) i n the Earth’s crust. Hydrothermal geothermal resources are intimately associated with active tectonic plate margins (Figure 1). There are numerous hydrothermal geothermal power plants associated with these volcanic provinces (Figure 2), most notably in the USA, Indonesia, the Philippines and New Zealand. The world’s first geothermal power plant, which began operating at Larderello in Italy in 1904, is an example of a conventional geothermal resource and —despite being partially destroyed towards the end of World War
II —is still operating today.
NATIONAL WATER COMMISSION
— WATERLINES 2
Figure 1: Tectonic plate boundaries of the Earth (modified from Geothermal Education Office
2000)
Energy production from non-conventional geothermal resources can be differentiated into two main types:
hot sedimentary aquifers (HSA), where hot water resides in deeply buried aquifers within sedimentary basins (at depths of 2000 –3500 m)
engineered geothermal systems (EGS), where areas of high heat flow result in high temperatures at moderate depths (3000 –5000 m). A naturally occurring aquifer is absent, and so engineering techniques must be employed to create an artificial aquifer system.
These high heat flow regions are not associated with active plate margins.
Figure 2: Worldwide distribution of geothermal power plants (modified from Geothermal
Education Office 2000)
NATIONAL WATER COMMISSION
— WATERLINES 3
In 2010, the total installed capacity from worldwide geothermal power plants reached
10.7 GW, and the total world energy use was 67.2 GWh (Bertani 2010). Some 24 countries currently generate electricity from geothermal resources, nearly all of which exploit hydrothermal geothermal resources; i.e. those associated with active tectonic plate boundaries. The world’s biggest generator of geothermal electricity is the USA (3093 MW), followed by the Philippines (1904 MW) and Indonesia (1197 MW).
Australia’s only currently operating geothermal power plant is located in Birdsville,
Queensland, and yields just 80 kW (net) from an HSA system. The owner of the plant, Ergon
Energy, is in the process of expanding the capacity of the plant to over 300 kW (Beardsmore
& Hill 2010).
As there are no active plate tectonic processes operating in mainland Australia, we lack any conventional geothermal resources. There is however significant scope for energy production from HSA and EGS resources, as well as low enthalpy aquifers (LEA), ground source heat pumps (GSHP) and aquifer thermal energy storage (ATES) applications.
Several geothermal energy developments are currently underway in Australia. The most advanced include Geodynamics’ Innamincka Project in north-eastern South Australia (SA);
Petratherm’s Paralana Project near Arkaroola in eastern SA; and Panax Geothermal’s Penola
Project located within the Otway Basin close to the SA/Victoria border.
Initiatives introduced in recent years by Australian governments (Commonwealth, state and territory), academia and industry to collaborate and break technical barriers are designed to position Australia as a dominant global developer of EGS and HSA technologies. Two geothermal groups have been established in Australia: the Australian Geothermal Energy
Group (AGEG), which fosters the commercialisation of Australia’s geothermal energy resources; and the Australian Geothermal Energy Association (AGEA), which acts as the national industry association for the Australian geothermal energy industry.
As of 31 December 2010 there were 57 companies exploring for geothermal resources in
Australia, 10 of which were listed on the Australian Stock Exchange. A total of $3.2 billion has been committed in work programs to 2015 with large areas of Victoria, Tasmania, SA and
Western Australia (WA) under exploration permit. A number of permits have also been issued in New South Wales (NSW) and Queensland, and in late 2009 the Northern Territory (NT) invited applications for geothermal exploration leases. In the most recent review of the geothermal energy potential of the world, Bertani (2010) estimates Australia has a realistic potential of having 40 MW installed capacity by 2015. Other recent publications estimate as much as 100 MW of geothermal capacity may be commissioned by 2015 (Beardsmore & Hill
2010) and up to 2200 MW of base-load capacity by 2020 (MMA 2008).
Government incentives, such as research and development grants and supportive legislative frameworks, have helped nurture the geothermal industry in Australia. The Commonwealth
Department of Resources, Energy and Tourism (DRET), in close cooperation with AGEG and
AGEA, released the Australian Geothermal Industry Development Framework (DRET 2008a) and Geothermal Technology Roadmap (DRET 2008b) to identify strategies for the development of Australia’s emerging geothermal industry. As part of this process, DRET administered the Geothermal Drilling Program (GDP) fund.
The $50 million GDP fund provided assistance to companies seeking to drill proof-of-concept geothermal wells. Two rounds of funding announced in 2009 resulted in seven companies being offered $7 million each for the following projects:
MNGI Pty Ltd (a wholly owned subsidiary of Petratherm Ltd) at Paralana, SA (Round 1)
Panax Geothermal Ltd at the Limestone Coast (Otway Basin), SA (Round 1)
Hot Rock Ltd at Koroit in the Otway Basin, Victoria (Round 2)
Geodynamics near Bulga in the Hunter Valley, NSW (Round 2)
NATIONAL WATER COMMISSION
— WATERLINES 4
Green Rock Energy Geothermal WA1 Pty Ltd in the Perth metropolitan area, WA
(Round 2)
Greenearth Energy Ltd near Geelong, Victoria (Round 2)
Torrens Energy Ltd at Parachilna, SA (Round 2).
The GDP funds (round 2) were relinquished by four of the companies in early August 2011 as they were unable to match the governments funds (DRET 2011).
The Australian Government also awarded $153 million to two companies (Petratherm and
Geodynamics) as part of the Renewable Energy Demonstration Program (REDP). State governments have also awarded grants and funding to a number of companies holding geothermal exploration permits, as well as grants and seed funds for research centres in a number of states.
In essence, the geothermal energy potential in Australia can be best viewed as a continuum between high enthalpy, deeply buried resources (2000 –5000 m) suitable for large-scale commercial electricity generation (EGS and HSA), through to low enthalpy, shallow resources, suitable for small-scale LEA (direct use heating and industrial processes), GSHP and ATES (Figure 3).
Figure 3: Geothermal energy applications in Australia (modified after Ayling 2007a)
NATIONAL WATER COMMISSION
— WATERLINES 5
1.3 Engineered geothermal systems (EGS)
Engineered geothermal systems (EGS) are non-conventional geothermal systems, variously known as hot fractured rock (HFR), hot wet rock (HWR), hot dry rock (HDR) or hot rock (HR) resources. These systems target geological formations several kilometres below ground level.
The concept of EGS was first recognised and developed by the Los Alamos National
Laboratory in Fenton Hill, New Mexico in the 1970s. The project was initially funded by the US
Government; however, active collaborations were soon established under initiatives of the
International Energy Agency with the United Kingdom (UK), Germany, France and Japan.
Further projects were undertaken in the UK, Germany, France, Sweden and Japan with varying levels of success, culminating in the first commercial EGS power plant in Landau,
Germany in 2007.
Unlike conventional geothermal systems, conduction is the dominant heat transfer mechanism within EGS domains. EGS projects offer much greater potential applications over conventional geothermal operations since they are technically feasible over much greater areas of the Earth’s crust. This is because they do not have to rely on a naturally occurring reservoir since hydraulic fracture stimulation can significantly increase permeability to achieve economic fluid flow rates (i.e. provided there is a suitable water source).
Several physical elements are required for a viable EGS development (Figure 4). Firstly, a high heat flux source covered by a sufficiently thick sequence of rock that thermally insulates this heat (low thermal conductivity sedimentary sequences such as carbonaceous siltstones and coals are optimal for this purpose). Secondly, a fluid reservoir, defined as a large volume of underground connected fractures or pores, is required within the rock, through which fluid can circulate at relatively shallow depth (<5000 m). It should be noted that the maximum depth of 5000 m is based on economic rather than technical considerations. Finally, a working fluid (or carrier) is required to extract heat from the EGS to the surface. Recharge is vital to replace or partly replace fluid extracted from the reservoir. The fluid is usually water in liquid or vapour phase, depending on its temperature and pressure.
Only the heat source and thermally insulating sediments need to occur naturally as, given favourable conditions, the reservoir can be engineered through fracture stimulation and fluid can be artificially introduced. For example, geothermal fluids extracted to drive a turbine in a geothermal power plant can be reinjected into the reservoir after use.
Once borehole access to the reservoir is established and sufficient flow rates are achieved, the system is primed for electricity generation. A working fluid (usually water) is introduced into the system via an injection well. The water captures heat from the reservoir unit as it circulates underground. The heated water is then brought to the surface via a production well and used to generate electricity before being pumped back underground via the injection well.
The entire operation is therefore a closed-loop engineered system. The only water required would be top-up water if there were any minor losses from the system.
A commercial scale example of an EGS is the Landau project in Germany, which began operations in November 2007. It comprises a single extraction bore producing 3 MW of electricity using Organic Rankine Cycle (ORC) technology. The temperature of the water is approximately 160 °C, flowing at 50–80 litres per second (L/s) from a depth of 3000 m. The water is then fed through a district heating system before being returned underground via an injection well to effectively form a closed-loop system. Expansion of the Landau Project is planned with the addition of a further 5 MW generating capacity.
NATIONAL WATER COMMISSION
— WATERLINES 6
Figure 4: Schematic design of an EGS development
Standard practice in the geothermal industry for hydraulic fracture stimulation most commonly involves pressurised freshwater without the addition of the chemicals that are typically used in the coal-seam gas (CSG) industry. The fracture stimulation is developed over a local scale, ensuring the integrity of the overlying low conductivity units.
The type of electricity power plant used is dependent on the temperature of the geothermal resource and the volume of fluid available (Ayling 2007a). Steam-power plants are routinely used in conventional geothermal resources. As stated previously, Australia lacks these high enthalpy and high pressure systems; thus, almost all proposed Australian geothermal power plants plan on utilising ORC technology, termed binary cycle systems (Figure 5).
NATIONAL WATER COMMISSION
— WATERLINES 7
Figure 5: Schematic design of a binary cycle power plant (modified after Ayling 2007a)
A binary cycle power plant utilises a heat exchanger to transfer energy from the geothermal fluid to a secondary working fluid (typically isopentane or ammonia) that has a lower boiling point and higher vapour pressure than steam at the same temperature. Hot water from a production well is circulated through the heat exchanger, and the cooled water is returned to the underground reservoir, thus forming a closed-loop system. The working fluid is pumped through the heat exchanger where it is vaporised and then expanded through a turbine to generate electricity. The vapour exiting the turbine is then condensed, either by cold air radiators or cold water, and recycled back through the heat exchanger in a second closedloop system.
Low enthalpy geothermal resources are being exploited for geothermal power generation in a number of localities worldwide. However, it should be noted that the thermal efficiency of binary cycle systems is low, in the range 5.8
–13.8% (Tester et al. 2006). Economic considerations are therefore as crucial to the development of a project as the actual temperature and flow rate of the resource itself. The lowest temperature installed plant is at
Chena Hot Springs in Alaska, where plants use 74 °C geothermal fluids to run three ORC units for a total of 730 kW (gross) of electricity (Lund et al. 2010).
NATIONAL WATER COMMISSION
— WATERLINES 8
1.4 Hot sedimentary aquifers (HSA)
A hot sedimentary aquifer (HSA) geothermal system can be described as a subset of hydrothermal geothermal systems in that naturally occurring fluids reside within a naturally permeable reservoir that may be up to several kilometres deep. In this case, boreholes are used to access the reservoir and bring the hot water to the surface, as well as to inject the thermally depleted water back into the reservoir (Figure 6); however, there is usually no need for other engineering works such as hydraulic fracture stimulation since the reservoir is naturally permeable. An example of an HSA system in Australia is the Otway Basin, which straddles the SA –Victoria state boundary. Several companies are seeking to produce hot water from deeply buried, high yielding aquifers in the basal sections of this sedimentary basin.
Figure 6: Schematic design of an HSA geothermal system (modified after Driscoll, 2006)
HSA systems are developed to make maximum benefit of convection, advection and conduction processes. Whilst convection might be an important process within some HSA systems, conduction is the principle heat transfer mechanism at the target depths since the required insulating sediment blanket would inhibit the development of large convection cells.
In addition, modelling by Mortimer (2010) indicates that the extent to which convection plays a role is strongly dependent on just two parameters: vertical permeability; and temperature. If sediments are stratified and/or have low vertical permeability, they are unlikely to maintain convection cells. The lateral movement of heat advectively, along with flowing groundwater, is less affected by vertical stratification, and conduction of heat between rock masses is independent of fluid transfer advection/convection.
An HSA project at Unterhaching in Germany was commissioned in 2009 and produces
3.4 MW using Kalina technology for the electrical power generation.
NATIONAL WATER COMMISSION
— WATERLINES 9
1.5 Low enthalpy aquifers (LEA; Direct Use)
There is a long history of direct use geothermal systems, otherwise known as low enthalpy aquifers (LEAs), for small-scale commercial and domestic purposes sourced from geological units up to several hundreds of metres deep (Figure 7). Present day applications include snow melting from pavements in Klamath Falls, Oregon through to alligator farming in the
Rocky Mountains, Colorado. A number of LEA applications have been operating in Australia including aquaculture (fish farming), balneology (hot springs and bathing), agribusiness and industrial uses (product drying and abattoirs), and district heating systems. Indeed, there is much scope for cascading geothermal operations whereby otherwise-waste heat from EGS or
HSA operations is used for LEA purposes before the fluid is reinjected back into the subsurface realm.
Figure 7: Industrial applications for LEAs (modified after Greenearth Energy 2011)
NATIONAL WATER COMMISSION
— WATERLINES 10
1.6 Ground source heat pumps (GSHP)
Ground source heat pumps (GSHPs) are the shallowest geothermal system, and are classified as a conventional application. GSHPs utilise the stable nature of the Earth’s temperature at relatively shallow depths (down to a maximum depth of approximately 150 m), although many units do not extend past a few tens of metres. The constant low enthalpy conditions (usually less than 30 °C) at these depths can be used to provide heating or cooling to domestic and industrial sectors. During the winter months, cold working fluid from the surface is pumped through an underground pipe network where it absorbs heat from the relatively warmer surrounding rock. The warmed fluid is then return to the surface where it is used to heat buildings. The same principle operates during summer where liquid warmed by the atmosphere is pumped underground where it transfers heat to the relatively cooler surrounding rocks and returns to the surface to act as air conditioning.
GSHPs are subdivided depending on whether they are closed-loop or open-loop systems.
1.6.1 Closed-loop GSHPs
Closed-loop GSHPs circulate fluid, typically a refrigerant, through a shallow underground pipe network. An advantage of the closed-loop system is that it is non-consumptive since there are no fluid losses. Depending on local requirements, the underground pipe network can be arranged in several different configurations, and can even utilise a body of water (Figure 8).
The units are energy efficient, especially so when the temperature contrasts between the ground and air temperature is maximised (i.e. during the height of summer and winter).
Figure 8 Closed-loop GSHP showing various orientations of pipework (modified after Ayling
2007b)
NATIONAL WATER COMMISSION
— WATERLINES 11
Vertical loops are most practical when land surface footprint is minimal. Pipe diameters are typically 150 mm in diameter and extend to a depth of between 50 –150 m. Horizontal loops are utilised where there is sufficient land surface available, for instance under parks and car parks. Horizontal loops are placed in trenches to a depth of approximately 2 m; however, longer lengths of pipework are required to overcome temperature instability at these shallow depths. Horizontal loops are cheaper and easier to install than vertical loops, and they are thus usually more appropriate for domestic applications. A slinky loop is a hybrid of these two loop systems and deployed where the available land is insufficient in size, or where drilling to deeper depths is prohibitively expensive.
1.6.2 Open-loop GSHPs
Open-loop systems physically extract groundwater or utilise surface water for the purpose of stripping energy (heat) for heating and cooling purposes. Unlike closed-loop GSHPs, the water is not recirculated, and is reinjected to its source or to another discharge point. By its nature, open-loop systems are only applicable at sites with adequate supplies of water.
1.7 Aquifer thermal energy storage (ATES)
Aquifer thermal energy storage (ATES) uses similar principles as GSHPs. However, rather than utilising the stable nature of the Earth, an aquifer is utilised as the thermal storage medium. Thermal energy is balanced or stabilised over a seasonal period, where the waste heat lost to the source during the summer months from cooling is matched to that required in winter months for heating.
ATES developments are not common and information regarding energy balances, operating temperatures and monitoring, and the polarity reversal of wells is not within the public domain.
It is therefore not possible to comment further on ATES schemes.
1.8 Geothermal systems assessment (GSA)
Cooper and Beardsmore (2008) developed a holistic approach to delineating geothermal resources with a prospect evaluation and engineering/geological risk management methodology synonymous to that proposed by Magoon and Dow (1994) in their Petroleum
Systems analysis volume. The GSA framework (Figure 9) addresses the principal geological risks at the basin or tenement scale. Thus, risk mitigation strategies can be employed when exploring for geothermal resources. Further detailed work at a geothermal project scale is required to progress exploration in areas that a GSA outcome might highlight.
The GSA approach applied by the industry in developing geothermal resources considers water-related factors as a key component of the risk matrix (Figure 9), including:
lithology, stratigraphy and stress characteristics
permeability, porosity, fluid circulation patterns and constraining factors (aquitards) and related modelling
water quality, geochemistry and isotope analysis.
Essentially, geothermal developments must take account of hydrogeological conditions to ensure that the development maintains the existing conditions at a low level of risk of influence from potential impacts such as water quality issues, subsidence and so on.
NATIONAL WATER COMMISSION
— WATERLINES 12
Figure 9: The GSA framework as described by Cooper and Beardsmore (2008)
1.8.1 GSA development considerations
The GSA framework can be used as the basis of a simple risk-based evaluation system which can be applied to conventional and non-conventional geothermal systems. The four critical geothermal development considerations are:
1. Heat flow: probability that heat flow measurements or assumptions reliably characterise the geothermal system under investigation (i.e. not simply temperature but heat flux). Estimated from geographic coverage and ‘uncertainty’ of heat flow estimates.
2. Thermal resistance: probability that thermal resistance and heat transfer mechanisms will be encountered at depth beneath the level of shallow exploration-well intersects
(purely conductive, convective component, advective component).
3. Reservoir: probability that reservoir properties and volumetric extent are as assumed from shallow exploration wells. Estimated from geographic coverage, data type and reservoir type. Includes void connectivity and prevailing stress regime.
4. Water: probability that water supply or chemistry will not adversely impact on the project.
The variables are defined by measurable factors with intrinsic distributions. For example, in petroleum exploration, reservoir risk incorporates the distributions of porosity, permeability, area and net/gross thickness data. These factors are typically combined in Monte-Carlo simulations to define the overall probability distribution of reservoir risk. This process provides a disciplined and uniform approach to help mitigate exploration/drilling risks (Capen 1992;
Rose 1992).
NATIONAL WATER COMMISSION
— WATERLINES 13
The methodology considers each component of the GSA risk matrix and places a confidence rating on the data used based on experience and current understanding in the area of interest.
Some aspects of risk in the geothermal system share varying degrees of co-dependence. For example, heat flow and thermal resistance risk share a common link via rock thermal conductivity measurements.
By understanding and quantifying the GSA risk elements of each critical technical area, steps can be taken to establish development plans with low financial risk prior to significant expenditure (being proactive rather than reactive). For example, if the chemistry of groundwater is studied and found to be corrosive, then project plans can incorporate appropriate materials to temper pipework and well casings.
Given the increasingly vocal debate over water issues, access to water is a major consideration for geothermal developments. This report is designed to provide some guidance on the geothermal issues in relation to water planning, notably regarding security of supply as well as to manage third-party impacts.
As is demonstrated herein, consumptive water use requirements are generally quite low for operating geothermal schemes that recirculate the working fluid (i.e. closed-loop or reinjecting), and also for exploration and construction stages (including EGS and HSA). The geothermal legislation is fundamentally subject to the provisions of the various water acts in all states and territories. The nominal gaps in NSW and Tasmania are not material in that activities that result in water take and discharge are subject to licensing under water and/or environmental legislation, as is the case in every state and territory. Thus existing water management arrangements are considered to be capable of managing geothermal developments if implemented appropriately. For example, in some states, although low enthalpy geothermal projects are exempt from geothermal legislation (i.e. low enthalpy being less than 70 ºC or shallower than 1000 m in Victoria; less than 70 ºC in NT; less than 100 ºC in NSW; and small-scale GSHP or non-commercial direct use in WA), such projects are subject to existing water acts and planning regulations. In Tasmania, although Section 48 of the Water Management Act 1999 (the WMA 1999) has an exemption relating to groundwater extraction generally, including for geothermal activities, there is the power to develop a Water
Management Plan (WMP) as a response to development pressures in a specific area. (For example, at the time of writing, the Wesley Vale WMP is the first such plan about to be declared for water resources management generally (not for geothermal purposes).) The general exemption to take groundwater may also be removed by the appointment of a groundwater area under Section 124A of the WMA1999, thus requiring a licence to take groundwater. It is understood that this exemption in Tasmania will be further addressed with the upcoming promulgation of a new water management framework that has been developed under the National Water Commission’s Raising National Water Standards program. There is also a review process underway in NSW and Queensland on water management arrangements in relation to the resources and energy sector.
In relation to the potential for impacts, the geothermal industry has some distinct differences from the mining, oil and gas industries (for example, EGS and HSA systems do not involve extraction of large volumes of rock/ore or oil/gas). Further, although it does use similar drilling and well construction techniques to the oil and gas sector, a successful EGS is developed at greater depth (up to 5000 m), with resistive layers above the reservoir that limit the potential for transmission of impacts (e.g. from hydraulic fracture stimulation or thermal gradients) towards the surface. HSA and low enthalpy systems are developed at shallower depths, but these systems rely on the natural permeability of the aquifers, and the related flow and circulation patterns (i.e. do not involve fracture stimulation). In summary, water supply and potential impact management issues for geothermal developments could be managed under existing water planning frameworks as the geothermal legislation in all jurisdictions is fundamentally subject to the provisions of the various water acts, as discussed in detail in
Section 2.3.
NATIONAL WATER COMMISSION
— WATERLINES 14
1.8.2 Heat flow
Large areas of central Australia have been shown to exhibit very high heat flow values with the rocks generating significantly more heat than most similarly aged rocks worldwide. This has been attributed to an abundance of grani tes in the Earth’s crust which have anomalously high concentrations of naturally occurring radioactive thorium, uranium and potassium
(referred to as internal radiogenic heat generation). Neumann et al. (2000) referred to the area as the South Australian Heat Flow Anomaly (SAHFA). It is worth noting, however, that the SAHFA has been geographically defined on the basis of a relatively limited data set. The anomaly may perhaps be better described as a serie s of ‘hotspots’ rather than one continuous anomaly. A number of studies for various companies and government agencies have been compiled to produce a heat flow map of Australia (Figure 10).
In accordance with the second law of thermodynamics, heat flows in three dimensions through rock, always towards the lower temperature. As the lowest temperature influencing a rock mass is generally at the surface, and as most data sets are gathered from ‘onedimensional’ (1D) vertical bore holes, 1D conductive heat flow models are normally developed as a first approximation of the regional heat flow regime. This heat flow modelling allows for interpolation and extrapolation of temperature at depth as it honours the thermodynamic principles of heat transfer. The depths over which temperature can be interpolated or extrapolated depend on the depth to which the assumption of purely vertical conductive heat transfer holds true. The assumption fails if a) there is a component of advective heat transfer via fluid flow, b) there is appreciable lateral conduction of heat, or c) temperatures exceed about 300 °C, at which point radiation starts to play a role in heat transfer.
Figure 10: Heat flow map of Australia showing extent of electricity grid infrastructure (HDR
2011)
Heat flow is the product of temperature gradient and rock thermal conductivity. It is calculated, or modelled, from measurements of these two parameters, and therefore heat flow is not directly measured itself. Reliable modelling of heat flow is a precision skill that requires experience and a detailed understanding of physical conditions in the borehole and the physical properties of the rocks, including advective processes that may influence bore temperature (such as groundwater flow or borehole advection) and the temperature dependence of conductivity.
NATIONAL WATER COMMISSION
— WATERLINES 15
Finally, heat flow models are only as reliable as the data that have been used to generate them. It is therefore important that the temperature, conductivity and radiogenic heat generation data used to model heat flow represent as closely as possible the actual thermal conditions.
1.8.3 Thermal resistance
A thick overlying sequence with low thermal conductivity —such as coals, carbonaceous shales or fine-grained siltstones —is generally necessary as an insulating blanket to boost the temperature for both EGS and HSA geothermal systems. Examples of low conductivity sediments include:
the Otway Basin, which straddles the Victoria –SA border. The regionally extensive thick
Cretaceous Eumeralla Formation provides the insulatory lithology to the underlying
Cretaceous Pretty Hill Formation.
the Cooper –Eromanga Basin which straddles the Queensland–SA–NT border. Thick packages of Palaeozoic to Mesozoic carbonaceous siltstones, shales and coal act as the insulatory cover.
1.8.4 Reservoir
A reservoir is defined, in the geothermal context, as the volume which hosts the working or carrier fluid. Historically, crystalline basement, and in particular granitic basement, has been the preferred medium for EGS reservoirs because of the notion that fluid losses from a circulation system can be constrained if the host rock mass has negligible in situ porosity and permeability in a bulk sense (i.e. other than where hydraulically fractured for the purposes of
EGS). A competent rock mass also helps constrain and control reservoir growth.
Granites have an internal fabric of joints and fractures. These need to be artificially widened in order to act as conduits for substantial flow of water or any other heat transport medium. This is achieved by increasing the pore pressure through the injection of fluid, usually water, into the base of a deep injection well, leading to the slight opening of pre-existing fractures. The common practice of hydraulic fracture stimulation for geothermal energy requirements uses pressurised fresh water with no chemical additives (i.e. geothermal is not comparable to the coal-seam gas industry in this regard). Natural internal stresses that operate at depth within the granite cause the separated rock faces to slip under the influence of pressure in a process referred to as ‘micro-sliding’. When the pore pressure is returned to normal, the fractures close again but do not fit neatly due to the slipping; a network of voids that are all in communication is thus produced. The resulting zone of enhanced permeability represents an artificially engineered reservoir.
The distribution of joints with depth and their orientation with respect to the in situ stress field is critical as this determines the growth orientation and geometry of the stimulated reservoir.
Furthermore, the nature of the joint network and in situ stress field determines to a large extent the pressure required to stimulate the rock mass.
The stress field controls not just the creation of the reservoir but also the subsequent operation and heat extraction. Pressurisation at levels just in excess of the minimum stress value is optimal since this results in fractures remaining open and allows sufficient fluid flow.
However, if pressurisation greatly exceeds the minimum stress at the depth of the reservoir, the likelihood is high that runaway growth of the stimulated rock volume will occur, leading to an undesirable increase in water loss.
For an HSA system, a potential reservoir unit must have adequate porosity and permeability, perhaps enhanced by fracture permeability along preferential stress directions. Typically, the target units are at depths >2000 m in order to achieve required temperature.
NATIONAL WATER COMMISSION
— WATERLINES 16
1.8.5 Working or carrier fluid (water)
The working or carrier fluid is the medium by which heat is extracted from the subsurface and brought to surface (also referred to as a heat transmission fluid). All currently operating and planned geothermal operations utilise water for this purpose, but research continues on using supercritical CO
2
as a working fluid (Brown 2000; Pruess 2006). Section 3 discusses water requirements and attributes in more detail.
In order to commercially exploit an HSA resource, detailed data on the temperature and water-flow characteristics of the groundwater aquifer need to be obtained. Flow characteristics are especially important in order to ensure reinjection does not cool the system and exhaust the resource too quickly. Two criteria need to be fulfilled: high-yielding aquifers and hot water within the aquifer.
The geological risks associated with water in EGS projects relate to the presence of water in adequate volumes to ‘charge’ the system and provide ‘make-up’ water in case of circulation losses. In some cases groundwater may provide sufficient water volumes, but meteoric sources can also be considered. In arid areas water availability and access may be an issue; however, the water allocation planning framework should take this into consideration.
The availability of water can only be assessed on a case-by-case basis when information is available regarding the location of specific prospects.
NATIONAL WATER COMMISSION
— WATERLINES 17
2. Geothermal resources in Australia
2.1 Geological background
Australia lies wholly within the Indo –Australian plate, and active tectonic plate boundaries are therefore absent. Large earthquakes are rare events and limited to intra-cratonic events, such as the magnitude 7.2 Meeberrie earthquake (Western Australia) of April 1941 —the largest recorded onshore earthquake in Australia (Geoscience Australia 2004). The most recent volcanic activity in Australia has been recorded in the vicinity of the Victoria –SA border.
Charcoal dated from beneath basalt flows in the Mount Gambier and Mount Schank area yield ages of 18 100 and 4700 years respectively (Sheard 1990).
Australia can be separated into three broad provinces based on the age and character of the underlying basement rocks (Figure 11). The oldest crust is located in the Western Shield
Province whilst the youngest is found in the Eastern Province.
Figure 11: Broad divisions of the Australian continental crust, based on basement rock age
Notes: Archean crust 3800 Ma to 2500 Ma; Proterozoic crust 2500 Ma to 570 Ma; Phanerozoic crust <570 Ma)
(modified from McLaren et al. 2003, and Beardsmore & Hill 2010). Named localities refer to EGS and HSA projects listed in Sections 2.2.1 and 2.2.2.
NATIONAL WATER COMMISSION
— WATERLINES 18
The Central Shield Province is unusual compared to similarly aged Proterozoic rocks elsewhere in the world in that large areas are enriched with anomalously high concentrations of heat-producing radiogenic elements (uranium, thorium and potassium), primarily hosted in granite and granodiorite rocks. In particular, the eastern and northern portions of SA (and adjoining states) record significantly higher than average heat flows (Cull 1982; McLaren et al.
2003) and have been termed the South Australian Heat Flow Anomaly (see Section 1.8.2). All of Australia’s currently operating uranium mines and numerous uranium prospects are located within the Central Shield Province, including the world’s largest uranium mine at Olympic
Dam.
The Eastern Province has seen regular volcanism throughout the Cainozoic era (<65 Ma).
There is a general decreasing age of events from north to south. The most recent manifestation of this volcanic activity is the extensive volcanic plain with more than 400 recorded eruption points stretching from Melbourne in Victoria through to south-eastern SA.
The origin of these volcanics is subject to much conjecture since they d o not fit a ‘mantle hot spot’ model. Seismic tomography data acquired in southern Queensland, northern SA, the coastal areas of Victoria and north-eastern WA indicate low seismic velocity anomalies in the upper crust, possibly indicating elevated temperatures (Graeber et al. 2002; Saygin & Kennett
2010). These areas are also the main focus of the Australian geothermal industry.
To date, no surface thermal manifestations, such as hot springs, have been identified as being associated with volcanism. Beardsmore and Hill (2010) note this is surprising given the geologically recent volcanic activity in south-eastern Australia. The authors offer an explanation in which the ambient groundwater flow through large regionally extensive shallow unconfined aquifers ‘advectively washes away’ any steam or hot water discharge from the subsurface geological features.
Australia therefore lacks conventional (volcanic) high enthalpy hydrothermal geothermal energy systems such as those targeted in New Zealand and Indonesia, and is generally devoid of surface emissions of geothermal heat such as fumaroles, geysers and volcanic activity.
Much of Australia is overlain by sedimentary basins of various sizes and depths. The sedimentary infill of these basins is important since those containing high percentages of coal and fine-grained sediments (clay and siltstones) will display excellent thermal insulation characteristics. These low conductivity sediments retard heat flow to the surface, resulting in elevated temperatures at depth. Of particular note is the Gippsland Basin in Victoria which contains one of the largest brown coal reserves in the world. Other basins in NSW and
Queensland contain thick accumulations of black coal.
2.2 Current status of geothermal resource utilisation
Whilst Australia is devoid of plate tectonic activity and volcanic high enthalpy hydrothermal geothermal energy systems, it does have a long and varied history of utilising geothermal resources, from electricity generating in Queensland to hot spring developments in Victoria and swimming pool heating in Western Australia.
2.2.1 Engineered geothermal systems (EGS)
Australia (and in particular the Cooper-Eromanga Basin area of north-eastern SA – southwestern Queensland) has a number of geological and geophysical attributes which are conducive to the testing of EGS technologies. These include extremely high heat-producing basement rocks, thick fine-grained insulating sediments, and a favourably aligned stress regime conducive for horizontal fracture development.
NATIONAL WATER COMMISSION
— WATERLINES 19
Geoscience Australia (Budd et al., 2007) estimated the amount of thermal energy in the
Australian crust at 1.9 x 10 10 petajoules (6.0 x 10 11 MWt.yrs) between the 150 °C isotherm and 5000 m depth. Just 1% of that thermal energy is equal to 26 000 years of Austr alia’s primary energy usage in 2004.
A number of EGS projects are currently underway in Australia, with the most advanced being the Innamincka Project and the Paralana Project (for location see Figure 11).
Case study: Innamincka Project (Geodynamics)
Geody namics’ Innamincka project (for location see Figure 11) is located within the Cooper-
Eromanga Basin in north-eastern SA. The project area includes the first geothermal exploration licences issued in 2001 by the South Australian government. The project suffered early technical difficulties with well design and construction, but this has since been rectified
(Section 5.3.1 has further information).
A total of five deep wells have been drilled to date:
Habanero-1, -2 and -3: The temperature at the top of the granite (3667 –3690 m depth) penetrated by all three wells is 227.5 °C whilst a temperature of 245 °C is recorded over the depth interval 4200 –4300 m (Chen & Wyborn 2009).
Jolokia-1: The bottom hole temperature is recorded as 278 °C at 4900 m (Geodynamics
2010).
Savina-1: The well has been drilled to 3700 m but the temperature data recorded is still confidential (as of September 2011).
In March 2009 the wells Habanero-1 and -3 achieved the proof of concept phase of the project by demonstrating heat extraction via a two-well circulation test from the engineered subsurface reservoir (Geodynamics 2009a). A 1 MW power plant has been constructed on site and this will be commissioned later in 2011 by the drilling of a further two deep wells
(Habanero-4 and -5). The work program for these two wells suggests they will be used to engineer a second, deeper fractured reservoir. This idea of creating multiple stacked reservoir layers should markedly increase the flow rate (Geodynamics 2010).
Stage 2 of the project will see upscaling to a 25 MW commercial demonstration plant by 2015, whilst Stage 3 will see the large-scale deployment of a number of EGS power plants in the area.
Geodynamics recently announced a partnership with Origin Energy to explore the HSA potential of the shallower section in their Innamincka Project.
Case study: Paralana Project (Petratherm)
Petratherm’s Paralana project (for location see Figure 11) is located in SA’s northern Flinders
Ranges. A deep well (Paralana-2) has been drilled to 4012 m ,recording a temperature of
176 °C at a depth of 3672 m, and an extrapolated temperature of 190 °C ± 1 °C at 4000 m
(Petratherm 2010). A fracture stimulation program was completed in July 2011 (Petratherm
2011) —inclement weather conditions and flooding has delayed the work program by several months. A second deep well (Paralana-3) will be drilled to intersect the reservoir and confirm both reservoir connectivity and rate of fluid flow.
Future work will see a (up to) 7.5 MW demonstration plant to supply electricity to the Beverley uranium mine, some 10 km from the Paralana project. Petratherm signed a Memorandum of
Understanding with the Beverley mine owner (Heathgate Resources) in 2006 (Petratherm
2006). Expansion plans will see the project upscaled to a 30 MW commercial power plant.
NATIONAL WATER COMMISSION
— WATERLINES 20
2.2.2 Hot sedimentary aquifers (HSA)
Case study: Birdsville power station (Ergon Energy)
The Birdsville geothermal power station (for location see Figure 11, and schematic design
Figure 12) is located in south-western Queensland, close to the SA border. The site is located within the Great Artesian Basin (GAB) and generates just 120 kW gross (80 kW net) electricity from a single 1280 m deep artesian bore flowing at 27 L/s and 98 °C. It accounts for all of Australia’s current operating geothermal power output (Beardsmore & Hill 2010). The plant owner, Ergon Energy, plans to increase the capacity of the plant to 300 kW via drilling of a new high capacity bore into this HSA target.
Figure 12: Schematic design of the Birdsville power station (modified after Ergon Energy
2008)
Case study: Penola Project (Panax Geothermal)
Panax Geothermal’s Penola project (for location see Figure 11) is located within the Otway
Basin in south-eastern SA, and comprises the initial part of their greater Limestone Coast
Project. The Initial well, Salamander-1, reached a maximum depth of 4025 m and intersected two thick sandstone packages within the Pretty Hill Formation; intervals 2901 –3570 m and
3570 –4000 m yielded average porosities of 13.2% and 10.2% respectively. A temperature of
171.4 °C at 4000 m was recorded (Panax Geothermal 2010).
The Penola project is currently on hold until a joint venture partner is identified and/or there is an improvement in financial market conditions.
2.2.3 Low enthalpy aquifers (LEA)
Commercialisation of Low Enthalpy Aquifers (LEAs) is becoming increasingly attractive in
Australia since they are recognised as a cheap source of thermal power. Unless otherwise stated, much of this section is derived from Beardsmore and Hill (2010).
NATIONAL WATER COMMISSION
— WATERLINES 21
District heating
Portland in Victoria was the site of an open-loop district heating system commissioned in
1983. Four bores at depths between 1250 –1420 m intersected the Dilwyn Formation with flow rates of 65 L/s and temperatures of 56 –59 °C being recorded (Burns et al. 2000; Chopra
2005). The system was decommissioned in 2006 due to environmental regulations —the poor condition of the bore was in danger of collapse with the potential for cross-contamination of aquifers, and serious economic inefficiencies were introduced by the need for cooling prior to discharge of the post-heating system water. At its peak, the system supplied a number of municipal buildings including the Civic Hall, Arts Centre, Senior Citizens Centre, Aquatic
Centre, Library, Tourist Information Office, History House, Portland Hospital, Richmond Henty
Hotel Motel, Police Station and the Maritime Discovery Centre. Burns et al. (1995) estimated the annual energy savings achieved by the system at 8 857 014 MJ per annum.
The Sebel Deep Blue Warrnambool geothermal spa in Victoria utilises a single bore (openloop, 735 m deep) to supply 43 °C water at a maximum rate of 50 L/s to provide hot water and space heating for the resort’s 122 rooms. Sustainability Victoria (2007) projected the geothermal water would provide annual fuel savings of $40 000 and water/heat sales of an additional $60 000 per annum (to a local caravan park and the yacht club). While the original project design was for 700 ML of water to be treated via a small-scale desalination plant to supply the local water authority, Wannon Water, the plant has not been built, and the outlet of the waste water is via surface runoff.
These two examples show that problems can occur with poor integration of geothermal and water management arrangements, especially if exemptions apply, as discussed in
Section 2.3. While current water planning frameworks may be capable of integrating geothermal developments into existing arrangements, this is not always achieved in practice.
It is suggested that exemptions in legislation increases the potential for poor integration, and this is not aided by different acts covering different parts of the water balance (e.g. extraction, reinjection, discharge to environment).
Balneology
The Peninsula Hot Springs resort, located at Rye on the Mornington Peninsula (Victoria), utilises 45 °C water from the Mepunga Formation at a depth of 637 m and flow rate of 4.5 L/s.
The resort opened in June 2005 and is currently undergoing a major expansion. About
210 000 L of water per day is being used by the (single bore) open-loop system at present; however, the expansion plans will see the establishment of a (recirculation) closed-loop system, with water being returned to the aquifer via an injection bore (Peninsula Hot Springs
2009). The expansion plans will result in flow rates increasing up to 50 L/s with further utilisation planned for geothermal resources including aquaculture, greenhouses and space heating.
As well as the Peninsula Hot Springs at Rye and the Sebel Deep Blue spa in Warrnambool, both in Victoria, a number of other places in Australia utilise geothermal resources for balneology including Queensland (Innot and Kooma), NT (Mataranka), SA (Dalhousie),
Tasmania (Hastings) and NSW (Moree, Lightening Ridge, Burren Junction, Walgett,
Yarrangobilly and Pilliga), all of which are open-loop systems.
Many of these springs discharge to surface and the flow rate is often poorly constrained (i.e. significant opportunity exists for water management improvements).
Aquaculture
Two sites currently utilise geothermal resources to farm barramundi (a tropical freshwater fish). In Robe (SA) Robarra sources water from the Dilwyn Formation via a single (open-loop)
335 m bore at a temperature of 29 °C. The system is estimated to provide in excess of 43 TJ of thermal energy per annum. A similar open-loop facility is operated by Mainstream
Aquaculture in Werribee (Victoria) using 28 °C water.
NATIONAL WATER COMMISSION
— WATERLINES 22
Other
A number of swimming pools in Perth utilise geothermal energy to heat their water. One example is the Claremont pool where warm water (43 °C) is sourced from the Yarragadee
Formation from a depth of 864 m. The flow rate is 13.7 L/s, with closed-loop recirculation and zero net extraction volume. The water is circulated through a heat exchanger to maintain a constant pool temperature of 26.5 °C. The geothermal water is injected back into the same aquifer level at a temperature of 29 °C and the system is estimated to utilise 15.3 TJ of thermal energy per annum. Similar systems are operational at Christchurch and Craigie swimming pools, and at the Challenge Stadium where hot water is also used to supply domestic hot water. Paynesville swimming pool in Victoria and the University of Southern
Queensland swimming pool in Toowoomba (Queensland) are further examples of this geothermal application. These closed-loop systems do not involve the consumption of water in terms of licensed volumes.
Midfield Meats, based in Warrnambool (Victoria), utilises open-loop geothermal water in its industrial meat processing facility for washing down and sterilising purposes.
Hot water at 68 °C from two bores (approximately 500 m deep) was used as open-loop process water in paper manufacturing at the Maryvale Paper Mill near Traralgon (Victoria) in the 1950s (Cull 1979). These operations continued for a number of years until operations ceased as a result of significant dewatering of the aquifer due to expansion of the Latrobe
Valley brown coal mining operations (King et al. 1987).
2.2.4 Ground source heat pumps (GSHP)
The Geoscience Australia building in Canberra, ACT, hosts one of the largest GSHP systems in the southern hemisphere, supplying 2500 kW of thermal power to a floor space of approximately 40 000 m 2 . The closed-loop system became operational in 1997 and it is estimated the projected energy savings will be in excess of $1 million over the 25 year life of the plant. Some 352 vertical bores, buried to a depth of 104 m, supply low enthalpy water
(with an undisturbed temperature of 18.2 °C) to 210 GSHPs.
Closed-loop GSHPs comprise the overwhelming number of installations in Australia. The lack of open-loop GSHPs is a function of the ongoing water debate in Australia. The only openloop systems thought to be operating in Australia are located within Sydney and source water from Sydney Harbour. These include the Sydney Opera House, the Powerhouse Museum, the Finger Wharf Apartments, as well as an air-conditioning system for the Australian Mutual
Provident (AMP) Society building on Sydney Cove, which became operational in the 1960s.
At present there are three GSHP suppliers and installers operating in Australia. Whilst there is no definitive list of all operating GSHPs in Australia, information can be sourced from
Geoexchange Australia Pty Ltd ( www.geoexchange.com.au
), while Chopra (2005) lists the following installations (it should be noted the list does not include residential installations):
•
New South Wales: Lithgow Hospital; NPWS Tourist and Information Centre, Jindabyne;
Macquarie University, North Ryde; Detention Centre, Dubbo; Cowra Shire Council offices;
Wagga Wagga Civic Centre; Surry Hills Community Facility; Woolloomooloo Wharves;
NSW Department of Environment and Conservation, Lidcombe; Australia Telescope
National Facility CSIRO, Marsfield.
•
Victoria: Victoria University of Technology, Werribee; Station Pier, Port Melbourne;
Wangaratta High School; Monash University, Melbourne; Bandiana ALTC; East Melbourne library; Mount Hotham ski lodge; Corryong Council offices; Acacia College, Mernda.
•
Queensland: Logan Institute of TAFE; Royal Australian Air Force base, Amberley.
NATIONAL WATER COMMISSION
— WATERLINES 23
•
South Australia: Royal Adelaide Hospital, North Terrace; Bureau of Meteorology (BoM),
Kent Town; Garden East Apartments, Adelaide; Coober Pedy Police Station; Mount
Barker TAFE.
•
Tasmania: Grand Chancellor Concert Hall, Hobart; Queen Victoria Museum and Art
Gallery, Launceston; Southern Cross Homes/Aged Care, Moonah; Antarctic Centre,
Hobart; Westpac Call Centre, Launceston; Hobart Aquatic Centre; Integrated Energy
Management Centre, Hobart; Elisabeth Street Pier Building, Hobart; Aurora Energy offices, Launceston
•
Australian Capital Territory: ACTEW Corporation, Canberra; Geoscience Australia,
Canberra; Duntroon Headquarters, Canberra; Airport Caltex, Pialligo; ANU Research
Laboratory, Canberra; Solomon Islands High Commission, Canberra.
•
Northern Territory: BoM, Darwin.
Residential installations numbered more than 2000 in the year 2000, and were increasing by a factor of 50% per annum (Burns et al. 2000).
2.2.5 Aquifer thermal energy storage (ATES)
To date there have been no ATES developments in Australia, and as these developments are usually more common in the much colder northern hemisphere climate it is expected that their detailed consideration is not warranted.
2.3 Geothermal energy legislation
Geothermal resources in Australia are legislated and regulated by the individual state and territory governments (Beardsmore & Hill 2010). The degree of geothermal activity by industry in each state and territory is partly a reflection of the different approaches taken by each individual government agency. A total of 418 geothermal permits have either been awarded or are under application as of December 2010, with a total forecast exploration expenditure of approximately $3.2 billion.
The subsections below identify that geothermal legislation is specifically subject to the provisions of the various water acts in all states and territories except NSW and Tasmania.
The gaps in NSW and Tasmania are nominal (i.e. not material) in that activities that result in water take and discharge are subject to licensing under water and/or environmental legislation, as is the case in every state and territory. This confirms that the existing water and environmental management arrangements are capable of managing geothermal projects if implemented appropriately. Exemptions from the geothermal legislation are identified, notably for low enthalpy systems (i.e. in practical terms, this would usually be for direct use of heat rather than electricity generation), and some implications are discussed further in Section 3.2.
2.3.1 South Australia
In South Australia, water resources (groundwater, surface water and watercourses) and licensing/permitting requirements are administered by the SA Department for Water (DfW) under the Natural Resources Management Act 2004 (NRMA 2004). The main method of managing water allocation and use is the process of prescription, which is administrated by the DfW, and results in the development of a Water Allocation Plan (WAP) by one of the eight
Natural Resources Management boards (NRM boards) operating in SA. The WAP sets the principles or rules under which consumptive pools, entitlements and allocations are created, and details how water is allocated to new licensed water users and how licences or entitlements can be traded. The DfW assists NRM boards in the preparation of WAPs by providing data (hydrogeological and hydrological) and advice about licensing, permits, legislation, policy and intergovernmental agreements. Once an NRM board has prepared a
NATIONAL WATER COMMISSION
— WATERLINES 24
draft WAP, the community is consulted. Once community consultation has been completed,
WAPs are adopted by the relevant Minister and become state government policy.
The Petroleum Act 2000 regulates geothermal resources in SA, subject to an amendment proclaimed in late 2009 ( Petroleum and Geothermal Energy Act 2000 (PGEA 2000) and the
Petroleum and Geothermal Energy Regulations 2000 (PGER 2000)). The Department of
Primary Industries and Resources of South Australia (PIRSA) regulates the PGEA 2000. The
PGEA 2000 allows for concurrent overlapping resource licences (minerals, petroleum and geothermal).
The PGEA 2000 does not authorise water take outside the provisions of the NRMA 2004. The
PGEA 2000 stipulates that a geothermal company must prepare and submit an
Environmental Impact Report (EIR) and a Statement of Environmental Objectives (SEO), or demonstrate the EGS/HSA project can achieve the objectives of an existing SEO. As part of the development of the SEO and EIR, potential water sources for operations must be identified, including consulting with all relevant stakeholders (including government agencies) to identify their concerns and offer mitigation strategies. Once this process is completed the geothermal company must apply for specific activity approvals pursuant to the PGER 2000
Regulation 18 or 19, where PIRSA is informed of the source of water. Whilst the SEO covers most water requirements for exploratory geothermal drilling and field operations, activities that may involve substantial water volumes (e.g. extended fracture stimulation activities, or makeup water to offset water losses from an operational system), then a specific water licence would be required under the terms of the relevant WAP.
Whilst the PGEA 2000 covers high temperature resources —such as EGS and HSA applications (see above) —there is no clear stipulation as to whether certain geothermal activities (e.g. low enthalpy) are not covered by the Act. Informal discussions with PIRSA staff suggest that LEAs and GSHPs may not be covered by the PGEA 2000, and these would fall under the NRMA 2004. Proponents must obtain a well construction permit from DfW for a specified geothermal well-casing design that is designed for aquifer resource protection (e.g. through engineering measures to isolate aquifer units).
In terms of water allocation and licensing, some parts of SA are not prescribed under the
NRMA 2004, and thus any development in these areas would not require a water allocation
(i.e. if an adequate water supply can be identified in a non-prescribed area, then a licence or allocation is not required). The Water Allocation Plan (WAP) for the Far North Prescribed
Wells Area (South Australian Arid Lands Natural Resources Management Board, 2009) covers a large part (but not all) of the arid north-eastern quarter of SA, including the SA component of the Great Artesian Basin and the Cooper Basin, areas of significant geothermal prospectivity.
With regards to discharge of water (i.e. not involving reinjection) for geothermal operations falling under PGER 2000, the key issue for PIRSA is whether discharge is sustainable. It is understood that the option preferred by PIRSA would be that water used in geothermal operations is reinjected to the same aquifer to maintain pressure and support sustainability; however, PIRSA will consider alternatives if the geothermal operator can demonstrate the system will be more sustainable via discharging by other methods. In any case, a licence for water take and discharge would be required under the NRMA 2004.
2.3.2 Western Australia
In Western Australia, the statutory instrument that gives authority to take surface or groundwater is a water extraction licence issued under the Rights in Water and Irrigation Act
1914 (RWIA 1914). Under the RWIA 1914, it is illegal to take water from or discharge water to a watercourse or aquifer without a licence.
The taking, use or discharge of water for any geothermal exploration, development and operations in WA is subject to the RWIA 1914. However, there is ongoing dialogue within the
Western Australian Government as to the definition of ‘take’ of water for deep geothermal
NATIONAL WATER COMMISSION
— WATERLINES 25
projects (e.g. questions such as of whether hot saline water sourced from 3000 m in a closedloop system that reinjects to the same aquifer should be treated differently from other water use activities).
The Petroleum Amendment Act (2007) was introduced to amend the Petroleum Act (1967) to provide for the exploration and recovery of geothermal energy in Western Australia. The amended Act is known as the Petroleum and Geothermal Energy Resources Act (2007), but it does not cover non-commercial uses or heat pumps. The PGER 2007 does not authorise water take outside the provisions of the RWIA 1914, but it does exempt from the PEGR 2007 any small-scale ground-source heat pumps used at or near the source and non-commercial small-scale uses of geothermal heat. The regulations currently being drafted may specify whether the small-scale recovery of geothermal energy in prescribed circumstances is for a commercial or non-commercial purpose, and it is anticipated that the Western Australian
Government will assess each geothermal project on its merits.
The PEGR 2007 allows the Western Australian Government to progressively release blocks of land for open tender. Several block acreage release tenders have resulted in a favourable response from industry, and further releases are anticipated in 2011.
2.3.3 Victoria
In Victoria, the Water Act 1989 is the legislation that governs the way water entitlements are issued and allocated, including defining water entitlements and establishing the mechanisms for managing Victoria's surface water and groundwater. The Department of Sustainability and
Environment (DSE) is the statutory body that manages water resources.
Groundwater resources in Victoria are managed by geographic extent of the aquifers, referred to as Groundwater Management Units (GMUs), with groundwater allocation and sharing being managed through licences issued by rural water corporations. GMUs can be designated Groundwater Management Areas (GMAs), Water Supply Protection Area
(WSPAs) and Unincorporated Areas. GMAs and WSPAs may be depth limited or depth unlimited. The Water Act 1989 provides a mechanism for capping water resources should groundwater resources in a particular GMU be shown to be in danger of being depleted or subject to adverse impacts. The cap, referred to as Permissible Consumptive Volumes
(PCVs), is set by the Minister for Water and represents the maximum volume of water that can be allocated in a GMA or WSPA. Many GMAs and WSPAs are already allocated to their
PCV limit. In these areas new licences cannot be issued and the only way to acquire new water in these areas is to purchase a licence from an existing groundwater entitlement holder.
The Geothermal Energy Resources Act 2005 (GERA 2005) and Geothermal Energy
Resources Regulations 2006 provide the framework for the large-scale commercial and sustainable exploration and extraction of geothermal energy resourc es in Victoria. The ‘use’ of geothermal energy (i.e. electricity production) is regulated through existing planning and environmental law. The GERA 2005 allowed the state government to release blocks of land across the entire state for open tender. Two tenders held in 2006 and 2008 resulted in much of the state being licensed (23 out of a possible 31 blocks). Total committed expenditure during the five-year tenure of the permits exceeds $364 million. The GERA 2005 allows for multiple concurrent overlapping resource exploration licences.
The GERA 2005 specifies that, in all instances, provisions of the Water Act 1989 apply to all geothermal water licensing and permitting issues. Irrespective of whether water is reinjected back into the same groundwater reservoir from where it was extracted, or whether the water is discharged to surface watercourses, the water from geothermal activities is considered a
‘waste’ product and regulation would be governed by the Environment Protection Act 1970
(EPA 1970). An environmental licence would be required in all circumstances, although a licence is not required under the Water Act 1989 to discharge to a surface watercourse.
Groundwater management is coordinated between government agencies, with any issues examined by the Department of Primary Industries (DPI) in partnership with DSE. At present, it is unclear from the Water Act 1989 licensing arrangements whether closed-loop systems
NATIONAL WATER COMMISSION
— WATERLINES 26
are classified non-consumptive in Victoria, and an ongoing dialogue within DSE is seeking to resolve this issue. Geothermal operations that are exempt from the GERA 2005 (i.e. low enthalpy resources shallower than 1000 m or temperatures lower than 70 °C) continue to be managed under existing statutory arrangements within the Water Act 1989 and EPA 1970. It is suggested that integration of water issues relating to geothermal developments is problematic under these conditions: exemptions in geothermal legislation, the involvement of a number of agencies operating under various acts, and licensing/management covering different parts of the water balance (e.g. extraction, reinjection, discharge to environment, etc).
The Victorian Government has stated that water allocation, pricing, use and discharge requirements for the geothermal energy industry should be level with those that apply to other water users (DPI 2010).
2.3.4 Tasmania
Two legislative mechanisms provide a framework for surface water and groundwater use in
Tasmania: water licences under the Water Management Act 1999 (WMA 1999) and irrigation rights under the Irrigation Clauses Act 1973 . The Department of Primary Industries, Parks,
Water and Environment (DPIPWE) is primarily responsible for managing water resources in
Tasmania.
Although Section 48 of the WMA 1999 has an exemption relating to groundwater extraction generally, including geothermal activities, there is the power to develop Water Management
Plans (WMP) in specific areas where water resources are considered to be reaching their sustainable limit (e.g. at the time of writing, the Wesley Vale WMP is about to be declared).
The general exemption to take groundwater may be removed by the appointment of a groundwater area under Section 124A of the WMA 1999 requiring a licence to take groundwater.
Geothermal resources are classified as ‘Category 6’ minerals under the Mineral Resources
Development Act 1995 (MRDA 1995) in Tasmania, and tenements are granted as a 'Special
Exploration Licence'. The MRDA 1995 allows ‘over the counter’ applications for licences, which has resulted in a large proportion of the state being licensed for exploration. Licences can co-exist with existing or future minerals and petroleum exploration titles.
While construction of wells and bores in Tasmania requires a well works permit, geothermal exploration activities are exempt from the well works permit system under the MRDA 1995.
However, geothermal operations are treated as mining operations under the WMA 1999 and could therefore require a licence under the WMA 1999 through a Water Management Plan or the appointment of a groundwater area.
2.3.5 New South Wales
The take and use of surface water and groundwater resources in New South Wales is legislated by the Water Act 1912 and the Water Management Act 2000 (WMA 2000), with the
NSW Office of Water (within the Department of Trade and Investment, Regional Infrastructure and Services) being responsible for water resources management. By definition, the term
'take' includes both the consumptive extraction of water (e.g. via a pump) and/or the
'incidental' take of water (e.g. leakage into a bore and/or work such as an excavation, opencut mine, underground mine). The current NSW Government has committed to an extensive review of planning legislation and the competing land use demands for agriculture, mining and the environment. A review of specific water regulations related to aquifer interference is also being undertaken.
Under the Water Act 1912 , water resources are managed under a system of surface water management areas (SWMAs) and Groundwater Management Areas (GMAs). The Water Act
1912 remains active until a Water Sharing Plan (WSP) has commenced under the WMA
2000. WSPs delineate specific water source areas and prescribe the rules related to trade
NATIONAL WATER COMMISSION
— WATERLINES 27
within and between zones within a water source. WSPs provide rules for sharing water between the environment and water users, and prescribe long-term and annual extraction limits based on climatic variability and the availability of water for extraction. A number of
WSPs have been commenced and plans are currently being prepared to include those surface and groundwater water sources not yet covered (inland groundwater is subject to embargo under WA 1912 as per NSW Government Gazette 159, December 2008). In general, once a WSP has been commenced, the water trade market is the primary mechanism for the purchase of entitlement. Where a water source is not fully committed and further water is deemed available for release, the WMA has provisions that enable a
'controlled water allocation' process to be applied. The controlled allocation process is still under development and not yet implemented.
WSPs made under the WMA 2000 set limits on the availability of water by specifying a limit on the total volume of water available for extraction from water sources within the plan area.
This limit is termed the Long-Term Average Annual Extraction Limit. A water access licence from the Office of Water specifies shares in the available water from a water source (the
‘share component’). This licence ensures that the total volume taken from a water source remains within defined extraction limits.
The Mining Act 1992 (MA 1992) governs geothermal exploration, which is considered as
‘Group 8: Geothermal Substances’ under the Mining Regulation 2010, and defines a geothermal substance as ‘any substance occurring naturally underground that is heated by the natural processes of the Earth to a temperature in excess of 100 °C’ (which would exclude low enthalpy applications). The MA 1992 allows ‘over the counter’ applications but the associated licence fee structure and issues with overlapping minerals licences (especially coal) are possible reasons for the low number of applications compared to other states (just
15 exploration permits awarded as of January 2011). Application for a Group 8 geothermal exploration licence requires the Minister’s consent. At the time of writing the MA 1992 is not specifically subject to the Water Act 1912 (or the WMA 2000). Activities that result in water take are subject to licensing under the Water Act 1912 (or WMA 2000). A review by NSW on these matters is in progress.
2.3.6 Queensland
In Queensland, the Water Act 2000 is the legislation that gives authority to take surface water or groundwater. The Department of Environment and Resource Management (DERM) is the statutory body that oversees water planning activities.
The Geothermal Exploration Act 2004 treats geothermal energy as a specific and unique
‘substance’ in Queensland, to facilitate exploration for geothermal energy through a tender process on areas selected by the state government. This Act was repealed by the
Geothermal Energy Act 2010 (GEA 2010), due to take effect in March 2012, which provides a regulatory framework for the exploration and production of geothermal energy. Two mechanisms are now available for licence applications: the more prospective areas will fall under a tender process whilst other areas will be available for ‘over the counter’ applications.
Delays in implementation of legislation have resulted in a limited number of exploration licences being granted in Queensland, although a larger number are under application.
The GEA 2010 states a geothermal licence holder cannot take or interfere with water as defined under the Water Act 2000 unless the taking or interference is authorised under the
Water Act 2000 . This applies to all geothermal activities including exploration, development and operations. Furthermore, the GEA 2010 specifies that drilling of water bores must comply with construction and drilling standards as defined by the Water Act 2000 . The treatment and disposal of any water resulting from geothermal work is legislated under the GEA 2010, so there may be further opportunities to better integrate the sector within existing water planning frameworks.
As with NSW, the Queensland Government is reviewing legislation and regulatory frameworks with regards to groundwater and the coal-seam gas (CSG) industry.
NATIONAL WATER COMMISSION
— WATERLINES 28
Amendments to the Water Act 2000 will support management and protection of water resources, by requiring CSG operators to prepare periodic underground water impact reports, whilst amendments to the Environmental Protection Act 1994 will require CSG operators to submit environmental management plans to demonstrate their effective protection of environmental values, including groundwater quality, and will introduce groundwater level trigger thresholds. Whilst these amendments are focused on the CSG industry, it is possible these may have future implications for the geothermal industry.
2.3.7 Northern Territory
The Water Act 1992 (as amended 2008) controls water resources in the NT, and is administered by the Department of Natural Resources, Environment, the Arts and Sport. The
Water Act 1992 allows for the declaration of Water Control Districts (WCDs) in areas that may be at risk of becoming stressed due to water extraction. A Water Allocation Plan (WAP) directs the management of water in a WCD. The WAP outlines the vision, objectives, strategies and performance indicators for the particular water source, and sets limits to the availability of water assigned to specified beneficial uses, rules for managing licences and water trading.
The Geothermal Energy Act 2009 (GEA 2009) aims to facilitate and regulate the exploration and extraction of geothermal energy in the NT. The GEA 2009 stipulates that geothermal operations require two rights: a right to the heat energy, which would be granted through a production licence; and a right to water. The rights to the use, flow and control of water — regardless of temperature —is subject to the Water Act 1992 , under which water extraction licences and ground discharge licences (i.e. water injected back into groundwater) are issued.
The GEA 2009 allows for ‘over the counter’ applications for most of the Northern Territory, although an area proximal to Katherine is currently reserved to allow for a competitive tender process. As of January 2011, some 14 applications were being processed. Low enthalpy geothermal resources are excluded from the GEA 2009 since the regulations explicitly state geothermal water is a substance at 70 °C or more.
2.4 Future developments and trends in geothermal resource utilisation
2.4.1 Engineered geothermal systems (EGS) and hot sedimentary aquifers (HSA)
The number of companies exploring for geothermal resources suitable for electricity generating purposes (both EGS and HSA) increased rapidly in the period 2004 –10. During this time, most state and territory governments around Australia passed appropriate legislation and regulation to ensure companies had the opportunity to explore for geothermal resources. The most active states are currently Victoria and SA, and this is reflected by the number and geographical extent of geothermal exploration licences in these states.
In 2007 the Australian Government announced a 20% Renewable Energy Target Scheme by
2020 (RET) and a $500 million Renewable Energy Fund (REF). However, at the time of writing there remains uncertainty over carbon pricing policy which, together with the loss of risk appetite by the private sector post-Global Financial Crisis (GFC), has resulted in many companies being unable to fund exploration and development activities.
There has thus been a level of rationalisation of the geothermal industry in Australia in the past 18 months. Whereas in the mid 2000s many resources companies were diversifying and embarking on geothermal exploration activities, a number of these same companies have since relinquished their geothermal exploration permits and are now concentrating on their core resource assets.
NATIONAL WATER COMMISSION
— WATERLINES 29
There are now 57 companies that hold geothermal exploration licences in Australia and this number may well decrease should further rationalisation of the industry continue. This number does not include companies that are targeting GSHPs and LEAs for direct use applications.
An increasing number of Australian geothermal companies have commenced exploration activities overseas —in particular in Asia, South America and Europe—targeting both conventional and non-conventional geothermal resources. By doing so, they hope to generate cash flow and thus fund their geothermal resource activities in Australia.
Initially, most geothermal companies focused their attention on either HSA or EGS projects.
However, there is a growing trend for companies to explore for both types of geothermal resources in the same area. Drilling deeper to exploit hotter EGS resources may not always be more economically or geologically viable than exploring for less hot and shallower HSA resources. It is noteworthy that Geodynamics, regarded as having the most developed EGS resource in Australia (Section 2.2), is now in a joint venture with Origin Energy to explore the
HSA potential of the shallower section in their Innamincka Project.
New exploration permits are still being granted, in particular in Queensland, WA and SA. It is also noteworthy that the NT will soon issue its first geothermal exploration licences. Figure 13 shows the current geothermal exploration licences in Australia superimposed on a heat flow map of Australia (HDR 2011).
Given the high cost of drilling, one of the most important drivers for geothermal exploration is the quality and quantity of geological and geophysical data already collected from previous minerals and petroleum exploration and development activities. Proximity to the national grid and other infrastructure is another important driver. It is therefore envisaged that the focus of
EGS and HSA exploration will continue in the areas already being targeted.
Figure 13: Heat flow map of Australia with geothermal exploration permits superimposed
Note: Licences correct as of 1 December 2010 (HDR, 2011).
NATIONAL WATER COMMISSION
— WATERLINES 30
2.4.2 Low enthalpy aquifers (LEA)
There has, in recent years, been an increasing demand in Australia for utilising LEAs for a range of domestic and commercial applications. When a site has been chosen, the aquifer architecture and plumbing characteristics must be scrutinised to ensure the suitability of the aquifer to the intended application. To date, very little work has been undertaken in Australia to match aquifer potential to specific applications, although it is likely that site-specific studies have been undertaken ‘in-house’ by geoscientific and/or engineering entities.
The following section therefore outlines the geographical locations most likely to be growth centres, or ‘hot spots’ with substantial LEA potential. Whilst the information focuses on the major population and commercial centres of Australia, it is likely that interest in LEA utilisation will continue to grow in areas where non-renewable resources are too expensive, such as remote locations away from the electricity grid or gas pipeline network.
Increasing numbers of LEA applications tapping the same aquifer will necessitate strict planning and regulation in order to ensure the sustainability of the aquifer system. However, a mechanism to achieve this is not yet in place. Increasing demands on groundwater resources and aquifers as a result of climate change and population growth has already led to more stringent government regulations, most recently in Adelaide and Brisbane. This trend is likely to continue for the foreseeable future, and data pertaining to Australia’s water resources is set to increase in quantity and quality.
Perth
The Gnangara groundwater system, within the Perth groundwater province (also referred to as the Swan Coastal Plain), refers to the series of shallow aquifers in the vicinity of Perth: the
Superficial, Mirrabooka, Leederville and Yarragadee aquifers. The shallowest aquifer, the
Superficial Aquifer, comprises Tertiary –Quaternary floodplain sandy deposits, and is underlain by the semi-confined Mirrabooka Aquifer (up to 160 m deep).
The Leederville Aquifer is up to 500 m thick and is sited within the Cretaceous Warnbro
Group (Leederville Formation). The geological unit comprises interbedded, poorly consolidated, fine- to coarse-grained sandstone and black, carbonaceous shale, distinctive glauconitic shale and lignite seams.
The most significant aquifer within the Perth Basin is the Yarragadee Aquifer, which lies several hundred metres below ground surface and attains a maximum thickness of approximately 1000 m. The aquifer is part of the Jurassic Yarragadee Formation, consisting of interbedded fine- to coarse-grained feldspathic sandstone, siltstone and claystone with minor conglomerate and coal. The basal section is dominated by finer-grained siltstone and clay, which grades up-section to a more sand-prone sequence. The aquifer is primarily composed of non-marine fluvial, poorly sorted sandstones which are porous and poorly cemented, hence allowing for considerable groundwater reserves.
The Yarragadee Aquifer is already tapped for geothermal purposes —heating of the
Claremont and other swimming pools (Section 2.2.3). The aquifer is also one of the exploration targets of Green Rock Energy, which plans to install absorption chillers for baseload chilled water at the University of Western Australia campus at Crawley, Perth.
Concerns have already been raised, however, over the long-term sustainability of the
Gnangara groundwater system, since the climate of south-western Western Australia has seen a steady decline in rainfall coupled with an increase in demand for water.
Melbourne
Greater Melbourne lies within the Port Phillip groundwater province, which comprises two primary aquifer systems —a series of Tertiary aquifers that overlie the Bedrock Aquifer (DSE
2009).
NATIONAL WATER COMMISSION
— WATERLINES 31
Approximately 80% of the groundwater resource in the Port Phillip Basin is currently utilised, sourced from around 4000 bores (Nott 2004). This groundwater is used for a variety of nongeothermal applications including irrigation, horticulture, stock watering and industry. Since bore yield, aquifer depth and water quality (especially in terms of salinity) vary on a local scale, any potential open-loop LEA installation would be subject to both detailed hydrogeological support studies and significant planning issues. In addition, the salinity issue would be a factor for the long-term cost and efficiency of any installation.
The Miocene –Pliocene Upper Tertiary Aquifer comprises a varied sequence of sedimentary units including claystone, siltstone, sandstone and gravel. Major geological units include the
Moorabool Viaduct Sand (Otway Basin and west of Port Phillip Basin), the Brighton Group
(Port Phillip Basin and Nepean Peninsula), and the Baxter Sandstone (Western Port Basin).
The Middle Tertiary Aquifer was deposited during the Oligocene –Miocene and comprises claystone, siltstone, sandstone, marl and limestone. Geological formations include the
Gellibrand Marl and Jan Juc Formation in the Otway Basin, the Fyansford Formation and
Batesford Limestone in the Port Phillip Basin, and the Sherwood Marl in the Western Port
Basin.
The Paleocene –Oligocene Lower Tertiary Aquifer consists of both sedimentary and volcanic units. It unconformably overlies the Bedrock Aquifer and the lithologies include claystone, siltstone, sandstone, gravel, coal and basalt. The aquifer is dominated by the Dilwyn
Formation and Eastern View Group in the Otway Basin, the Werribee Formation and Older
Volcanics in the Port Phillip Basin and Nepean Peninsula), and the Childers Formation and
Older Volcanics in the Western Port Basin.
The Bedrock Aquifer comprises metasedimentary Ordovician –Silurian sandstone and shale, and Devonian granite intrusives. These units form the rugose topography in the vicinity of
Melbourne.
Adelaide
The Mount Lofty – Flinders Range groundwater province covers the city of Adelaide and surrounding areas. The deep Tertiary Aquifer beneath Adelaide yields high-quality water which is used for a variety of purposes including soft-drink and beer manufacturing, horticultural production, irrigation of recreational and sports fields, and a number of other industrial uses. It is therefore feasible that groundwater in the vicinity of Adelaide might be suitable for low enthalpy geothermal installations.
However, in 2007 the South Australian Government prescribed all groundwater in the Central
Adelaide Groundwater Area (CAGA) as the resource was being increasingly developed
(DWLBC 2010). The Adelaide and Mount Lofty Ranges Natural Resources Management
Board, with technical support from the Department for Water, has initiated a water allocation plan for the CAGA to ensure the resource is managed and developed in a sustainable manner. This work involves the development of a multi-layered groundwater flow model (RPS
Aquaterra, 2011), which could be easily adapted to evaluate direct geothermal use scenarios.
Sydney
The Sydney Metropolitan area is covered by the Sydney groundwater province, which comprises two coastal sand aquifers (the Botany Sandbeds and Metropolitan Coastal Sands) and the porous rock aquifer (the Sydney Basin).
The Botany Sandbeds and Metropolitan Coastal Sands aquifers provide groundwater supply options for local areas in Sydney, which obtains most of its water supply from Warragamba
Dam on the edge of the Blue Mountains in western Sydney. The aquifers generally have a relatively shallow water table and are readily recharged by direct rainfall infiltration.
Unregulated use in some areas by heavy industry (such as tanneries, dry cleaners and wool scourers) for many decades has resulted in pollution and contamination in some parts of the
NATIONAL WATER COMMISSION
— WATERLINES 32
aquifer network, particularly in the Botany area. New boreholes in areas of contamination are banned and a cleanup of the contaminated aquifer is ongoing.
The Sydney Basin aquifer underlies much of Sydney. However, the aquifer is not very permeable, provides low bore yields, and contains relatively poor quality water. It provides only limited quantities of groundwater for mining and quarrying activities in some areas.
Expansion of subsurface infrastructure in the Sydney area, especially car parks and tunnels, is placing pressure on the aquifers. In addition, contamination of the aquifers remains a major concern given the existing heavy industry dominance in some areas, and due to fertilisers and agricultural chemicals associated with golf courses. A Catchment Allocation Plan is being developed for the Sydney area to ensure sustainable use of the groundwater supply (DECCW
2010).
Brisbane
The Brisbane Metropolitan area straddles two groundwater provinces: the Tasman; and the
Clarence-Morton. Alluvial aquifers underlie Brisbane. However, at present the groundwater is used for irrigation purposes only. There was an initiative (commissioned 2005) called the
Brisbane Aquifer Project, with the objective to assess and establish a network of bores for the extraction and treatment of 20 ML of drinking water per day. The project established a number of exploratory boreholes and test production bores to measure the water quality and actual yield in a number of southern suburbs. The project was declared successfully completed in April 2008.
In 2007, a moratorium was introduced (NRW 2007) on construction of works that take groundwater from the Brisbane aquifer area (such as stock or domestic purposes, commercial or industrial purposes, or for irrigation purposes). The moratorium also applies to works if they would increase the amount of groundwater taken. The moratorium was deemed necessary to secure the sup ply of groundwater resources for Brisbane’s water supply.
2.4.3 Ground source heat pumps (GSHP)
It is difficult to comment on the future development of GSHPs in Australia since statistical data concerning the current and past installation capacity and number of operating systems is not routinely collected by any single central organisation. However, data available from the
European Heat Pump Association (EHPA) demonstrates trends in the European context which may indicate potential for Australia.
Statistics from EHPA (2008) indicate growth in European sales for the eight most significant countries from 2004 –07 (Figure 14). Table 1 shows installed stock for selected countries during the same period. EHPA (2008) reports a significant fall in the number of installations in
Sweden during 2008 (due to a number of reasons, most importantly because the market was growing too rapidly and may have overheated). Growth in France and Germany remained strong in the same period. A number of other European markets are prime for development, including the Netherlands, UK and Eastern Europe.
NATIONAL WATER COMMISSION
— WATERLINES 33
Figure 14: Total sales of GSHP in the eight most significant European countries 2004 –07
(EHPA 2008)
Table 1: Installed stock of ground source heat pumps by the end of 2007 (EHPA 2008)
Country 2004 2005 2006 2007
Austria
Estonia
Finland
France
Germany
Norway
Sweden
Switzerland
Total
30,577
1,475
30,000
49,950
48,662
9,562
195,531
33,000
398,757
35,810
1,985
33,500
63,150
60,861
11,562
230,094
38,128
475,090
43,045
2,735
38,000
81,600
87,875
14,062
270,111
45,258
582,686
50,280
3,485
42,500
100,200
114,889
16,562
310,128
52,388
690,432
In 2009 the UK Environment Agency (EA) published its own market analysis for GSHPs in the
UK. Figure 15 shows the uptake of UK GSHPs in comparison to selected European markets for the period 2004 –07 (EA 2009).
EHPA (2008) stated that there were 3500 installations in the UK in 2008. During its consultation process, the EA estimated that number would increase to 8000 GSHP installations in the UK by 2009 (EA 2009). Considering the number of GSHPs installed elsewhere in Europe, there is huge scope for growth in the UK. Current uncertainty surrounding the UK G overnment’s Renewable Heat Incentive (the key driver for growth) has constrained potential growth since May 2010. It is anticipated that the Renewable Heat
Incentive Scheme will be launched in June 2011, and will facilitate the UK Government’s 2020 renewable energy targets.
NATIONAL WATER COMMISSION
— WATERLINES 34
Figure 15: Comparison of UK heat pump installations compared to selected European markets 2004 –07 (EA 2009)
In Australia, the GSHP market is comparatively immature. The European experience has shown that government initiatives are critical for growth, especially for the domestic markets shown where support is needed for the often expensive up-front capital costs.
Understanding how the Commonwealth and state governments intend to promote the uptake of GSHPs will be crucial to forecast the market growth, and thus the potential impacts from the water usage element associated with any market growth. Any potential impacts identified should be integrated into forward planning, thereby providing a mechanism for water and energy planners to inform each other and develop mutually acceptable development frameworks.
2.4.4 Aquifer thermal energy storage (ATES)
There are currently no plans to develop ATES projects in Australia and, given the plethora of water issues being discussed in Australia at this time, it is anticipated this status quo will continue, at least in the short term. Projects are being planned and developed in several
European countries, specifically the Netherlands, Norway, UK and France.
2.5 Estimate of total industry growth/development
This section presents details on the development of the geothermal industry under various incentive scenarios. The water usage issues are discussed in Section 3.
For the purposes of this report, three broad geothermal development scenarios are used:
no incentives (low development scenario)
incentives for GSHPs and LEAs only (similar to existing domestic and light industry rebate schemes)
incentives for all types (i.e. a full development scenario).
NATIONAL WATER COMMISSION
— WATERLINES 35
2.5.1 No incentives for geothermal applications (low development scenario)
As discussed in Section 2.4, development and deployment of large-scale geothermal electricity projects will most likely be delayed. Australian geothermal companies may well continue to focus on overseas geothermal opportunities.
Even with no incentives for geothermal applications, the growth for GSHPs and LEAs is likely to continue at moderate levels since an increasing number of companies are keen to show their green credentials. Water usage issues are discussed in Section 3.
2.5.2 Incentives for GSHPs and LEAs (similar to existing domestic and light industry rebate schemes)
With regards to GSHPs and LEAs, experience in comparable European markets suggest rapid uptake of these applications if government incentives are made available.
In Europe, the German Government enacted the Heat Act on 1 January 2009 whereby all owners of new buildings are obliged to purchase part of their heat demand from renewable energy sources. Grants of €20/m² living space, but not more than €3000 per house for existing houses and €10/m² living space, but not more than €2000 per house for new houses, are mandated. The experiences of Germany show that cascading use of LEAs can improve the economic efficiency of these geothermal applications (Schellschmidt et al., 2010). Thus, many installations combine district or space heating with greenhouses and thermal spas.
Korea has also seen a rapid uptake of GSHP and district heating systems since the Korean government implemented subsidising programs for renewable energy deployment (Song et al., 2010). The installed capacity of GSHP and district heating systems rose by over 960% in the five years to 2009 (17.51 MWt in 2005 to 185.7 MWt in 2009). There was a particularly large jump in installation capacity in 2009 due to an active rural subsidy program for greenhouse heating.
In Australia, the Photovoltaic Rebate Program, introduced in 2000, is an example of implementation and outcomes of a renewable energy scheme. The program initially offered
$4000 rebates to households to install small-scale solar energy power systems. By November
2007 the program had helped install 10 000 solar systems and was receiving an average of
153 new applications each week.
In November 2007, the scheme —now called the Solar Homes and Communities Plan— increased the rebate to $8000 per household, aiming to install a further 15 000 units within five years. By May 2008 the scheme was means tested due to the popularity of the rebate.
There followed a huge increase in uptake of the scheme, from 420 applications per week in
May 2008 to 6043 per week in May 2009.
It is likely that a similar scheme for GSHP would see a corresponding increase in GSHP installations. The water use implications of this scenario are discussed in Section 3 (e.g.
Table 2).
2.5.3 Incentives for all geothermal applications (full development scenario)
An example of how the geothermal industry in Australia could grow can be seen from experiences in Germany. Whilst Germany is regarded as having poorer geothermal potential than Australia, the enactment of supportive renewable energy incentives by the German government has resulted in a surge of geothermal projects currently being developed. In addition, a maximum feed-in tariff (FIT ) of €0.27/kWh (approximately $0.36/kWh; December
2010 exchange rate) has been introduced (Schellschmidt et al. 2010). These incentives not
NATIONAL WATER COMMISSION
— WATERLINES 36
only provide viable economic conditions for the operation of geothermal installations, they also stimulate the build up of a geothermal power industry in Germany and have opened new opportunities for geosciences and for the drilling and service industry. This has certainly been seen at recent international geothermal symposia.
This example should be considered carefully, however, as the push by Germany to diversify its energy sources and to increase its indigenous supplies of electricity can be considered to result from the ongoing tensions between Russia and Ukraine over natural gas supplies, with ramifications for Europe. The most recent escalation occurred in January 2009 when Russia cut all gas supplies to Ukraine. As Ukraine acts as a major transit corridor for Russian gas supplies to Europe —with approximately 80% of Russia’s gas passing through—18 European countries reported major deficiencies or cut-offs in their gas supplies during a particularly harsh European winter.
In Australia in 2008, the AGEA commissioned McLennan Magasanik Associates Pty Ltd to independently assess the business development plans of Austral ia’s geothermal energy companies, to estimate how much electricity generation capacity the Australian geothermal industry expects to deploy by 2020 and at what price (MMA, 2008). The findings indicated that:
the Australian geothermal energy industry can be expected to provide at least 1000 MW, and potentially up to 2200 MW, of base-load capacity by 2020 into the national electricity market
capacity potentially represents up to 40% of the Australian Government’s 2020 RET of
45 000 GWh —the equivalent of the output of up to 6000 MW of wind farms
an estimated $12 billion would be invested to develop 2200 MW of installed capacity
the cost of generating electricity from geothermal resources is expected to move rapidly down the cost curve through to 2020 —through learning, experience and economies of scale outcomes commencing at around $120/MWh at small scale (10 MW to 50 MW) and decreasing to around $80/MWh at large scale (300 MW or greater) by 2020
price is expected to be the lowest cost of any form of renewable energy
most of the capacity is expected to come from developments in SA, with other states increasing their contribution toward the end of the 2020 period
restricted access to risk capital since the GFC began has cast some doubt over the ability of the industry to reach those targets. Other recent publications estimate that Australia has a realistic potential of having 40 MW installed capacity (Bertani 2010) to as much as
100 MW of geothermal capacity (Beardsmore & Hill 2010) by 2015.
The water use implications of this scenario are discussed in Section 3 (e.g. Table 2).
NATIONAL WATER COMMISSION
— WATERLINES 37
3. Geothermal water use: requirements and potential effects
3.1 Overview
Geothermal energy is a developing industry in Australia. Information regarding water use and effects on water resources is relatively scant since most data is considered proprietary by geothermal companies. Information contained within this section is therefore drawn from a combination of Australian experience, augmented by overseas experience where it can be used as analogous to the Australian context.
With some notable exceptions (e.g. Swan Coastal Plain in Perth), the majority of licences for major geothermal development in Australia are located in areas where the sustainable yield of
Groundwater Management Units (GMUs) has yet to be quantified. This uncertainty can be accommodated in the water planning process, by ensuring that an adequate allowance is provided in water sharing/allocation plans for industrial purposes (i.e. including geothermal, oil and gas, and mining), to meet the needs of projects that have not yet been identified, explored or developed. This approach is not applied everywhere (see previous comments in relation to developments at Portland and Warrnambool), but has been successfully applied to
South Australia’s Far North Water Allocation Plan and provides a degree of certainty for major geothermal resources development. Similarly, the potential for development of low enthalpy
(shallow) geothermal systems, which may arise in urban areas over coming decades, also needs to be considered under urban water planning and review arrangements.
3.2 EGS and HSA water-related impact issues
3.2.1 Water planning issues overview for EGS and HSA
Section 2.3 identified that the overall geothermal legislation is explicitly subject to the provisions of the various water acts in all states and territories except NSW and Tasmania.
The gaps in NSW and Tasmania are nominal (i.e. not material) in that activities that result in water-take and discharge are subject to licensing under water and/or environmental legislation, as is the case in every state and territory. This confirms that the existing water management arrangements are capable of managing geothermal projects if implemented appropriately. Some jurisdictions have certain exemptions from the geothermal legislation for low enthalpy geothermal projects (i.e. such exemptions would generally not apply to
EGS/HSA for electricity generation, but could apply to projects for direct use of heat):
Victoria exempts low enthalpy being less than 1000 m deep and/or less than 70 °C
New South Wales exempts low enthalpy being less than 100 °C
Northern Territory exempts low enthalpy being less than 70 °C
Western Australia exempts small scale GSHP used at or near source, and noncommercial small-scale uses of geothermal heat (but these are still subject to the provisions of the water legislation)
South Australia does not specify whether certain geothermal activities (e.g. low enthalpy) are exempt from their geothermal legislation, but it does stipulate that all geothermal activities are subject to the provisions of the NRM Act 2004.
Despite the low enthalpy geothermal exemptions, no state or territory has an exemption from the provisions of the water legislation for water interfering or taking activities associated with geothermal projects.
NATIONAL WATER COMMISSION
— WATERLINES 38
In Tasmania, there is a general exemption from licensing/allocations for groundwater extraction for all uses (including geothermal). However, there are powers under the Water
Management Act 1999 to invoke water management plans in areas where there are serious pressures on water systems. It is understood that this nominal (but not material) exemption in
Tasmania will be further addressed with the upcoming promulgation of a new water management framework that has been developed in consultation with the Commission.
Pressure management of the subsurface reservoir is of critical importance in both EGS and
HSA projects. To achieve feasibility, EGS projects will usually require an introduced fluid that is reinjected into the artificially created reservoir to act as the working fluid, as well as to maintain reservoir pressure and inhibit fracture closure. Likewise, HSA developments require reservoir pressures to be maintained otherwise natural pore voids may close, thus leading to decreasing reservoir permeability and production/injection flow rates. In both instances, an inability to maintain and manage reservoir pressures will ultimately lead to a decreased operational lifespan of the project.
In addition, regulators are most unlikely to allow the reinjection of fluids into different aquifers so as to prevent the mixing (and potential contamination) of fluids of different hydrogeochemical compositions. From the geothermal operator ’s viewpoint, it would be ill advised to introduce fluids with varying hydrogeochemical properties into the reservoir system as this may well lead to complications with precipitation and scaling of the reservoir and/or bore network.
It is for these reasons that most EGS and HSA projects for electricity generation in the planning and development stages within Australia are designed to be closed-loop systems, with very low consumptive use during scheme operation. Most of the water produced from the production well is reinjected to the same subsurface aquifer (or engineered reservoir in the case of EGS projects). However, low enthalpy aquifer systems (typically for direct use of the heat rather than electricity generation) often involve single-well or open-loop systems, and thus involve potential for substantial consumptive use. In any case, the existing water legislation and planning arrangements can be made applicable to all geothermal developments, as outlined in Section 2.3.
Water demand is highest in geothermal projects where the volumes of in situ fluids contained within the formations are inadequate to stimulate and operate an engineered underground reservoir. Water consumption can be controlled by using closed-loop systems, fluid reinjection, non-evaporative cooling and general pressure management, although most geothermal projects will require a long-term water supply at some scale (e.g. for make-up requirements). While guidance is provided in this report of the potential range of consumptive requirements, it is not feasible to be exact at this time, as this is a developing rather than a mature industry and every scheme will have site-specific factors that need to be taken into consideration.
3.2.2 Exploration water issues for EGS and HSA
Since Australia is generally devoid of conventional surface manifestations of geothermal heat, geothermal exploration in Australia is focused on identifying those areas where conductive heat flow and thermal insulation results in elevated temperatures at accessible depth.
Identifying those locations requires a different exploration strategy to that employed for conventional geothermal systems.
The general progression of an exploration program in Australia includes the following steps:
Desktop geothermal systems assessment (GSA, detailed in Section 1.8 of this report).
S hallow ‘heat flow’ drilling.
Deep ‘appraisal’ drilling.
NATIONAL WATER COMMISSION
— WATERLINES 39
Once a GSA of an area has been completed, several areas of interest are typically identified.
A drilling program is designed which comprises a series of shallow ‘heat flow’ bores, and these bores are used to further ascertain local heat flow and other geological information of the area.
Cordon and Driscoll (2008) cite two exploration companies that provided details of water usage from their respective shallow ‘heat flow’ drilling programs in SA, estimating 50–85 kL for a single shallow bore. Both companies faced logistical and environmental issues with sourcing the water. Petratherm noted the main logistical issue faced was the trucking or piping of water from local bores. As stock was using some of the bores, this necessitated monitoring and rotation of bore usage to ensure sufficient supplies for stock . Company ‘B’
(which requested its name be withheld in the Cordon and Driscoll, 2008, report) drilled its own water bores adjacent to the exploration bore since the trucks planned on carting water from nearby bores would have severely impacted upon the sensitive track network.
Whilst both companies were exploring in sparsely populated parts of SA, they worked with the local community and government to minimise real and perceived environmental impacts of the drilling program.
Once a company has achieved a level of confidence in defining its geothermal resource, deep drilling is planned to appraise the reservoir characteristics —typical to a depth of 3000–
5000 m. This marks the beginning of the development stage as economic considerations dictate the first deep exploration well is converted into either an injection well or production well (drilling one well to 3000 –5000 m is widely anticipated to cost $12–15 million).
Cordon and Driscoll (2008) cite Petratherm ’s plan to drill two wells at its Paralana project to a depth of approximately 4000 m. Four local water bores were being drilled at the project site to meet drilling requirements. The site is within the Far North Prescribed Wells Area (PWA), and thus the shallow aquifer (non-GAB) water bores required a well construction permit and a water licence/allocation.
3.2.3 EGS and HSA development water issues
Cordon and Driscoll (2008) utilised technical data from Mil-Tech UK Ltd (2006) to predict the development stage as requiring a total of about 280 ML of water. This is based on the assumption that an EGS module consists of one injector (first well) and two producers
(second and third wells) of 8.5” open-hole diameter. Bores are typically drilled to a depth of
3000 –5000 m with an assumed separation between bores being about 600 m.
Closed-loop HSA projects require substantially less water since they do not require fracture stimulation or reservoir charging. Cordon and Driscoll (2008) estimated approximately 2 ML of water for each of the HSA deep bores to be drilled.
Water requirements and volumes are comprehensively reviewed in Cordon and Driscoll
(2008) and are surmised here:
Several mud sumps (typically four or five) are constructed to allow the hot drilling brine to flow slowly from the first pool to the last. This is done with four objectives. Firstly, to cool the circulating brine; secondly, to settle very fine particles of rock from the brine; thirdly, to allow a place to store brine during over-and-under balancing; and, finally, the last mud pool is used to prepare the required density of brine for injection.
A number of in situ small-scale hydraulic permeability tests (such as slug tests, production tests and low-rate injection tests) are undertaken in the first bore to assess hydraulic properties in the bore both before and after stimulation activities. The quantity of water required is dependent on the tightness of the formation.
NATIONAL WATER COMMISSION
— WATERLINES 40
Stimulation of the reservoir section to initiate shearing of joints and fractures and thus develop the EGS underground heat exchanger. During the stimulation process, fresh water is injected in increasing flow rate steps, typically 30 –70 L/s, with no addition of chemicals (some developments have involved the use of chemicals). Once stimulation is completed, then a post-fracturing injection test is undertaken to quantify the efficiency of the stimulation.
The second bore is designed and drilled to intersect the underground heat exchanger.
Similar hydraulic permeability tests are performed to evaluate the reservoir section in the second bore, and additional stimulation activities are usually undertaken. Reservoir connectivity is quantified by performing a communication test between the first and second bores. An inert tracer compound is utilised to gauge fluid flow through the reservoir. The tracer is introduced via the injection well and detected at the first production well, with breakthrough generally in the order of four to six days. If the initial stimulation does not produce the desired result then remedial treatments can be employed to reduce impedance to flow.
The third bore is drilled and similar tests and activities to that undertaken in the second bore are undertaken.
Once reservoir characteristics are acceptable and basic circulation has been established between the wells, then circulation with increasing flow rates is undertaken. Flow rate is increased from approximately 40 L/s up to commercial rates of approximately 100 L/s.
3.2.4 Operational water issues for EGS and HSA
As there are only a handful of operational EGS plants in the world and none yet in Australia, conventional geothermal projects are generally used in comparison to provide an estimate of water usage for the production phase of EGS and HSA energy projects. In a typical, successful conventional geothermal reservoir, individual production wells can produce 5 MW or more of net electric power through a combination of high temperatures and high flow.
Minor volumes of water are required for periodic maintenance activities during operation of a geothermal system. The production and/or reinjection capacity from an individual well tends to decrease with time, depending on a number of variables including changes within the reservoir, rates of chemical deposition and mechanical conditions of the well. To restore or regain some of the capacity, well maintenance/rehabilitation is undertaken with a work-over drilling rig as this is much cheaper and shorter (typically one week) than drilling a new well.
The New Zealand code of practice for deep geothermal wells (NZS 2403:1991) requires 12 hours minimum of water stored for quenching a well (the injection of cold water into a well to prevent the formation of steam and/or reduce temperatures) during a work-over, and notes a typical rate of 13 L/s. Acid cleaning is another rehabilitation method that involves injecting an acid solution into the production or reinjection zone for a short period of time (hours) to dissolve any build-up of scaling products within the formation around the well. The flow rate of water required for this operation is similar to a well quench at approximately 13 L/s.
The primary use of water in power plants is cooling, although there are other ancillary uses related to power generation. There are a number of different types of cooling systems and the selection of these is based on the type of power plant, geothermal resource chemistry, site meteorological conditions and access to a cooling source such as a river or aquifer. These issues are discussed in detail in the next section.
3.2.5 Controlling EGS water losses
Controlling water losses is an important aspect of developing a geothermal energy project particularly in areas of restricted water availability. Such losses can have significantly negative economic and environmental impacts if not managed.
Australian EGS projects are likely to encounter risks associated with water supply. Consider, for example, a hypothetical EGS project consisting of six wells each producing hot water at
100 L/s. If all the water is reinjected with 1% loss per cycle (estimate based on international
NATIONAL WATER COMMISSION
— WATERLINES 41
experience), the project has to make up 6 L/s, or 0.5 ML, per day, throughout its entire life.
While that may not necessarily be a problem, it does imply that a permanent supply of water might be required for many EGS projects.
Water loss mitigation strategies can be employed. In the case of shallow ‘heat flow’ bores, the main water losses can be attributed to evaporation on the surface of the sumps or water filtrating out of the sumps as very little water is lost down hole. In one drilling project sumps were resealed, which resulted in significant decreases in water loss from 8 –16 kL to 2–8 kL in a 24-hour period during drilling (Cordon & Driscoll 2008).
EGS field projects carried out throughout the world have experienced the impact of water losses through trial production testing. The following anecdotes detail some of the issues encountered (documented in Tester et al., 2006, Chapter 4).
Fenton Hill, USA
The reservoir could be circulated in such a manner that the fractured volume did not continue to grow and, thus, water losses were minimised.
If water was injected at high enough pressures to maintain high flow rates, the reservoir continued to grow and water losses were high. The fractures were being jacked open under high injection pressures, causing extension of the fractures and increased permeability. At lower pressures, this did not happen, so the permeability was lower and flow rates much lower.
Rosemanowes, UK
An experimental proppant (sand) was carried into the joints as part of a secondary stimulation using high viscosity gel. Proppants are small-sized particles that are mixed with hydrofracturing fluids to hold fractures open after a hydraulic fracturing treatment (proppant materials are carefully sorted for size and shape, hardness, and chemical resistance to provide an efficient conduit for production of fluid from the reservoir to the wellbore). This stimulation significantly reduced the water losses and impedance, but encouraged shortcircuiting and lowered the flow temperature in the production borehole.
Ogachi, Japan
Fluid losses within the reservoir were high during injection testing because the wells were not properly connected. Once connection between wells was improved, fluid loss was reduced.
3.3 Low enthalpy geothermal systems impact issues
Given the similarity of low enthalpy aquifers (LEAs), ground source heat pumps (GSHPs) and aquifer thermal energy storage (ATES) schemes with regards to water requirements and effects on water resources, these applications have been combined for the purposes of consideration of water use issues. They are referred to collectively as ‘low enthalpy geothermal systems’.
Several potential impacts on groundwater via utilisation of low enthalpy geothermal systems have been identified, and these can be classed as either hydrogeological or thermogeological events. The lack of information from an Australian context of low enthalpy geothermal systems necessitates the use of international examples.
For the current scale of development (limited/isolated), the issues discussed below should be manageable within existing arrangements for bore licensing and water allocation planning.
Should there be an intense concentration of development, then specific water management
NATIONAL WATER COMMISSION
— WATERLINES 42
arrangements may need to be developed (e.g. considering the thermal energy balance of an urban aquifer, as well as its water and salt balance).
3.3.1 Hydrogeological impacts of low enthalpy systems
Potential hydrogeological impacts relating to low enthalpy geothermal systems can be grouped into drilling-related issues, and water balance and aquifer hydraulic issues.
There are three main drilling-related hydrogeological scenarios that may result in adverse impacts from the drilling of low enthalpy geothermal systems (Banks, 2008), these being:
inadvertent penetration of artesian conditions
drilling through two aquifers, inducing leakage from one to another
drilling on contaminated land sites, thus resulting in conduits for contaminants to the aquifer.
The application of existing permitting and driller licensing arrangements should be adequate to manage the first two drilling-related risks, and existing contaminated sites legislation and land planning regulations should be adequate to deal with the third risk.
In regard to aquifer and hydraulic issues, if the scheme is open-loop then there will be discharge to a receiving water body that is either different to the extraction water body, or the extraction/discharge water body itself may be an open-ended system. This can lead to potential impacts on the water body that might be due to temperature or water chemistry, in addition to the water balance impact. Options for sourcing and/or discharging of water for open-loop systems (e.g. to/from bores/lakes/rivers/marine waters) may trigger the need for specific licensing and planning requirements due to the higher risk of environmental, social and economic impacts, which should be managed appropriately under existing water policy and legislation, as discussed in Section 2.3.
Abstraction quantities from open-loop low enthalpy systems in London have been shown to be mostly between 10 –20 L/s (from 25–30 sites), with lesser numbers of sites abstracting between 0 –10 L/s and 20–30 L/s (from 10–15 sites each). Five sites recorded >50 L/s.
In closed-loop (essentially non-consumptive) schemes, where water is reinjected to the aquifer, there will be localised drawdown or mounding of water levels/pressures around wells, which could affect existing users (Banks, 2008).
The reinjection of water can cause increased rates of dissolution where the formation is susceptible (notably carbonate-type formations). For example, Younger (2006) investigated the potential for limestone dissolution as a result of cooling by low enthalpy geothermal schemes. Injection of warm water could also result in the clogging of pore space (Banks,
2008) through dissolution and re-deposition. It should be noted that much of this is speculative at this stage as the research is yet to be undertaken.
Thermogeologically, the primary constraint on the capacity of an area or location to support low enthalpy geothermal systems is the number of schemes that can be installed without thermal interference between the schemes, as discussed in the next section.
NATIONAL WATER COMMISSION
— WATERLINES 43
3.3.2 Thermal impacts of low enthalpy systems
The lack of information from an Australian context of low enthalpy geothermal systems necessitates the use of international examples. Since 2003, the Spatial Strategy for London,
UK, requires onsite generation of renewable energy, with GSHPs recognised as such a technology. This has resulted in a major uptake in London of open-loop systems. To begin with these were consumptive (open-loop), but the majority are now non-consumptive (closedloop).
Though closed-loop, it is recognised that there is now a developing density of schemes that may be affecting the overall temperature of the Chalk aquifer from which the groundwater is being sourced. A study on the regional distribution of ground temperature in the Chalk aquifer of London (Headon et al., 2009), indicated that there is potential modification of the subsurface thermal regime as a result of recharge. Elsewhere, such as in Winnipeg, Canada, research has also been undertaken to try to determine the extent of the merging of thermal plumes in the carbonate aquifer beneath the city (Ferguson & Woodbury 2005).
This is not to suggest that all centres of growth are now having adverse impacts on the aquifers from which they are sourced. However, Australia has the opportunity to learn from the experiences of those places that have already undergone growth.
Consents to investigate and discharge to the aquifer are the main requirement in the UK for potential installers. As the applications become more complex, it is expected that the granting of future licences will depend on the quality and thoroughness of the supporting assessments
(Fry, 2009).
Many of the issues related to closed-loop systems are actually in relation to the sustainability of the installation. For example, problems might arise with the efficiency of the system as a result of hydraulic breakthrough, or the lack of appreciation that injection wells require specialist design. Hydraulic breakthrough can be defined as the possibility that warm (or cold) water may flow back to the abstraction well, thereby compromising the capability of the system to provide its optimum heating output.
3.4 Geothermal power plants
3.4.1 Geothermal power plant types and cooling systems
The three main types of geothermal power plants used to generate electricity are binary cycle, dry-steam and flash-steam units. All of these plant types are based on the Rankine thermodynamic cycle, which essentially converts heat to work. The lower the temperature of the heat rejection (waste) part of the cycle, the higher the generation capacity from the same heat source (i.e. the greater the overall efficiency). The type (or combination of types) selected for a particular development is a function of the geothermal resource characteristics.
Geothermal power plants in Australia are likely to use relatively low enthalpy sources (e.g. compared to coal-fired power) and thus use binary generation plants, as noted in Section 1.
A binary cycle unit uses a working fluid with a low boiling point and high vapour pressure, heated in the heat exchanger by the geothermal fluid until it boils and changes state to a gas.
The binary working fluid is then expanded through a turbine generator where power is generated. The binary working fluid is then condensed back to a liquid in a cooler before being pressurised back to working pressure by a pump (Figure 5).
Dry-steam and flash-steam units utilise a steam turbine generator to generate power and are typically used for higher enthalpy resources (such as fossil-fuel and conventional geothermal power plants). These units will not be considered further, as they are generally unlikely to be utilised in Australian geothermal projects.
NATIONAL WATER COMMISSION
— WATERLINES 44
Coolers for what are expected to be the predominantly binary cycle geothermal power plants may be air-cooled radiators, heat exchangers or cooling towers, are discussed below:
Closed-cycle water cooling
Requires a water source for initial filling, preferably low salinity and low corrosive potential to minimise pipework and pump maintenance issues.
Higher parasitic loads for pumping cooling water through the system and cooling fans for forced draft cooling.
As the heat is being rejected into the atmosphere, the cooling capacity is dependent on the ambient temperature and humidity. An increase in air temperature or humidity decreases cooling capacity.
Water is lost from the cooling tower through evaporation and drift.
If the geothermal working fluid is being condensed (i.e. a steam turbine is used) the cooling system will gain water at a greater rate than the amount of water that is evaporated in the cooling tower over the majority of ambient conditions.
Cycles of concentration of salts in cooling tower basins can drive the feedwater/blowdown requirements (refer to glossary for definitions). For a resource with a high salinity there will be a high blowdown requirement and this can make water-based cooling systems impractical.
Air cooling
No cooling water is required.
High parasitic loads for the large number of cooling fans required.
Air-cooled binary plants typically suffer from load reduction on hot days.
Hybrid cooling systems
Utilise solely air cooling where the cooling load and ambient conditions allow, and water cooling at other times. When the cooling load increases or the ambient temperature/humidity increases, cooling water is sprayed onto the air coolers to provide evaporative cooling, which increases the capacity of the cooling system.
Water use is minimised as water is only used when it is required.
Once-through water cooling
Requires the power plant to be located by a water source —such as a lake, river or the sea —so only used where water resources are considered plentiful and as such are unlikely to be implemented in Australia unless located along the coast.
Minor parasitic loads, mainly pumping (i.e. some of the power generated is used to run pumps in the plant, rather than being distributed to the grid).
The plant cooling capacity, and hence generation capacity, remains constant as long as the water source is at a relatively stable temperature.
In the case of a direct contact condenser, the condensed geothermal fluid is discharged into the lake, river or the sea (more water output than taken in). This condensed geothermal fluid may have contaminants in it that require environmental consideration.
Examples of cooling systems utilised in geothermal power plants
Birdsville Power Plant (Australia): Binary cycle plant with cooling of the binary fluid by cooling water through heat exchangers. Cooling water is cooled by air-cooled cooling tower.
Wairakei Geothermal Power Plant (New Zealand): Steam turbines with direct contact condensers, utilising a once-through cooling system using river water.
Ohaaki Geothermal Power Plant (New Zealand): Steam turbines with direct contact condensers with a closed-system cooling system utilising a natural draft cooling tower.
NATIONAL WATER COMMISSION
— WATERLINES 45
Kawerau Power Plant (New Zealand): Steam turbine with a direct contact condenser with a closed cooling system and a forced draft cooling tower.
Mokai Geothermal Power Plant (New Zealand): Two back-pressure steam turbines exhausting into a binary cycle process. The binary plant utilises banks of forced aircoolers.
Power plant cooling issues for Australian systems
Geothermal power plants in Australia are likely to use low enthalpy resources and binary generation plants. In addition, some are likely to be located in remote areas away from water sources and in hot climates. A hot climate and a low enthalpy resource is likely to restrict the use of air coolers and a lack of water for cooling would result in hybrid cooling systems being the most probable application.
As noted above, the EGS and HSA systems under development in Australia are closed-loop in which geothermal fluid is reinjected into the reservoir. If adequate volumes of water cannot be withdrawn from the reservoir then this limits the cooling options. For HSA-type systems, cooling water make-up can be sourced from the geothermal fluid itself, which equates to an increase in consumptive take. A small proportion of the geothermal fluid that has been through the binary plant can be further cooled in cooling ponds and used as make-up water to replace cooling water lost through evaporation or as spray in hybrid cooling towers. This geothermal fluid may require treatment to provide water of suitable quality for cooling water.
EGS systems, where water is injected into the ground, would require an input of additional feedwater to make up for evaporative losses in the cooling tower.
The amount of cooling water required will vary substantially between plants, ranging up to
50 L/s per MW (the maximum figure relates to a once-through cooling system). The amount used will be a function of the technologies selected, resource chemistry and local meteorological conditions.
This cooling water requirement essentially forms a demand for geothermal industrial purposes
(additional to the demand for geothermal well drilling and testing) in relation to water resources assessment (are the resources available?) and water allocation planning (is the extraction sustainable?).
3.4.2 Other power plant water requirements
Auxiliary cooling water
Binary plants (the likely generation system for Australian conditions) typically don’t require auxiliary cooling water systems; however, large pumps may require seal water control systems (water cooling of pump seals).
Steam turbine systems require auxiliary cooling water for generator cooling, lube oil systems, gas removal systems and pump seal water control systems. Smaller steam turbine systems
(units less than 10 MW) can typically use air cooling on their auxiliary systems. The auxiliary cooling water system usually shares the same cooling system as the cooling water system.
As such, losses in the system are from evaporative losses in the cooling tower. However, make-up water is generally only required for plants that are not condensing steam. The amount of auxiliary cooling required is a function of the equipment specified and not necessarily related to the size of the power plant. Where water is scarce it is possible to design a plant that uses a closed non-evaporative cooling water system or is all air cooled.
Wash-water systems
Wash-water systems will not be expected to be required for closed-loop geothermal systems such as EGS and HSA, but may be required for geothermal steam turbine systems.
NATIONAL WATER COMMISSION
— WATERLINES 46
Steam turbine systems typically separate the steam from the brine by a cyclone separation vessel. A small amount of particulates from the reservoir and dissolved solids carry over with the steam. These solids can precipitate out and cause build-up and erosion on turbine blades.
To minimise scaling on turbines, wash water may be injected at points between the steam separator and the turbine. The wash water is injected into the steam line as a mist or spray to scrub the steam.
Dosing systems
Dosing systems may be required on the geothermal fluid and cooling water systems. On the cooling-water side, dependent on the chemistry and the materials used, chemical injection may be required to adjust pH, inhibit bacterial growth or inhibit metal corrosion. On the geothermal fluid side, chemical injection may be required to inhibit calcite and silica formation, which can cause scaling. Dosing systems typically use condensate in the case of conventional geothermal steam turbine.
For an EGS or HSA system that would typically be used in Australia, dosing chemicals are likely to be needed to limit heat exchanger fouling both from scaling on the geothermal side and pH and bacterial growth on the cooling water side. The amount of chemical dosed is dependent on the requirements of the system and each system will have its own unique properties. The volume of water required for dosing in the absence of condensate is likely to be of the order of up to 0.1-0.2 L/s per dosing system.
Power plant amenities and facilities
Most power plants have facilities such as toilets, showers, washing facilities, safety showers, irrigation, and a lunch room, which all require a potable water source. The volume of water required would be in the order of 0.1 L/s, but they would only operate when there is demand, which depends on staffing levels. The total demand volume is quite small, essentially comparable to typical domestic demands. HSA systems may be able to generate their own potable water from the geothermal fluid with suitable water treatment depending on the geothermal fluid chemistry.
Geothermal working fluid sampling
Steam sampling, either for monitoring the chemistry or for measuring flows via the tracer method, require the geothermal fluid to be condensed or cooled to ambient temperatures for analysis. Manual-grab samples are typically condensed or cooled with water; manual sampling typically requires approximately 10 –20 L per sample. Automatic samplers may require up to 0.7 L/s of water for cooling samples.
Fire systems
For steam turbine systems a sprinkler system will typically be required around the generator and hydraulics plant. If a flammable fluid is used in a binary plant this will also need sprinkler and fire water systems. Fire water is typically stored in a tank or pond, generally in the order of a few hundred cubic metres, although this is dependent on the fire code requirements.
Generally, the fire system tank or pond is kept full and, other than initial filling, only requires top-up water if the system is used or for leakages and evaporation in the case of a pond.
3.5 Projected industry water requirements
Projections of water requirements in an expanding geothermal sector are primarily restricted to electricity generating developments associated with EGS and HSA, since LEAs and
GSHPs are generally closed-loop systems that require negligible water for well development or for operations. The water requirements for EGS and HSA developments are substantially different since HSA operations do not usually require fracture stimulation nor initial fluid charging of the reservoir (i.e. HSA systems make use of the in situ aquifer properties),
NATIONAL WATER COMMISSION
— WATERLINES 47
whereas EGS uses water for engineering effective circulation of the working fluid. For operational water make-up requirements, however, both HSA and EGS are considered to require about 1% make-up (see Section 4.1).
For an EGS development, the reported average water requirement for drilling and construction of 280 ML (Cordon & Driscoll, 2008) is based on a three-bore configuration (a
‘triplet’) comprising two production bores and one injection bore. Such a triplet would normally be expected to supply approximately 10 MWe of power —dependent on resource flow rate and temperature characteristics. Thus, an average of 280 ML of water might be consumed for each 10 MWe EGS development.
For an HSA triplet construction, Cordon and Driscoll (2008) estimated approximately 2 ML of water for each of the bores to be drilled; thus, 6 ML might be consumed for each 10 MWe
HSA development.
Section 1 detailed the predictions of three different reports as to the potential of geothermal electricity generating capacity in Australia (MMA, 2008; Beardsmore & Hill, 2010; Bertani,
2010). Table 2 provides a preliminary estimate of the water requirements for two different scenarios for each of the publications using the above estimates. One scenario assumes that there will be an equal number of EGS and HSA developments (EGS 50%: HSA 50%) whilst the second scenario assumes that substantially more EGS developments will be commercialised (EGS 75%: HSA 25%).
Based on the values in Table 2, the potential geothermal energy water requirements could be estimated to be around 1 GL/a per 40 MW installed capacity (or 3 ML/d per 40
MW). This ratio could be used for broad planning purposes, and includes allowances for construction and operational requirements for geothermal development over a range of EGS and HSA assumptions, but excludes the cooling requirements of electricity generating plants
(by definition, it also does not allow for other low enthalpy or direct use types of geothermal development).
Table 2: Preliminary estimate of develoment and operational water requirements for two different scenarios of projected geothermal electricity generating capacity in Australia
Author Projection year
Projected installed capacity
(MW)
40
Water need (GL/a)
[EGS 50%; HSA 50%]
Water need (GL/a)
[EGS 75%; HSA 25%]
Bertani (2010) 2015 0.8 1.1
Beardsmore and
Hill (2010)
MMA (2008) lower forecast
MMA (2008)
2015
2020
100
1,000
2.1
20.5
2.7
27.4
2020 2,200 45.1 60.2 upper forecast
Note: These estimates do not include power plant cooling requirements, as the type of cooling system will be determined on a case by case basis and there is considerable variation between systems.
NATIONAL WATER COMMISSION
— WATERLINES 48
4. Availability of water resources in geothermal areas
4.1 Overview
The climate across Australia is characterised by its temporal (seasonal and annual) and spatial variability. As such, climate is a determining factor in Australian water management and planning. Extensive areas of central and western Australia are classified as semi-arid or arid, with average annual rainfall <500 mm (Figure 16). Precipitation occurs sporadically and can be concentrated and intense, causing both local and widespread flooding. Evaporation rates tend to be extreme and surface water dries out very quickly. Indeed, Australian rivers exhibit annual variability about double those of the rest of the world since flood years are typically followed by prolonged periods of drought (Kollmorgen et al. 2007).
Figure 16: Australian average annual rainfall based on standard 30-year climatology (1961 –
1990) (BoM 2009), (annotated with geothermal case study projects and main concentrations of geothermal energy exploration licences)
Rainfall generally increases towards the coast since these areas are adjacent to moisture sources (the oceans) and have greater probability of access to rain-producing weather systems. Topography also exerts a marked influence on rainfall as demonstrated by the mountains of north-eastern Queensland, south-eastern Australia and western Tasmania.
Some of these areas have average annual rainfall exceeding 3000 mm.
Concerns over water scarcity coupled with increasing demands on water resources have been raised in all parts of Australia in recent years, particularly in light of persistent droughts and climate change. An intergovernmental agreement (the National Water Initiative, or NWI; see Section 1.1) was formulated and signed by all Commonwealth, state and territory governments at the June 2004 CoAG meeting (with the exception of Tasmania, which signed the Agreement on 3 June 2005, and Western Australia, which signed the Agreement on 6
April 2006).
NATIONAL WATER COMMISSION
— WATERLINES 49
The NWI signifies the Commonwealth, state and territory governments' shared commitment to water reform. It places an emphasis on greater national compatibility in the way Australia measures, plans for, prices, and trades water, and a greater level of cooperation between governments. It builds upon the previous CoAG framework for water reform, which was signed by all governments in 1994. A major activity to support the NWI has been a comprehensive review of Australia’s water resources, referred to as the Australian Water
Resources 2005 (AWR 2005).
AWR 2005 is the baseline assessment of water resources taken at the beginning of the NWI and against which future data, and the success of NWI reform processes, can be measured.
AWR 2005 addressed the following issues:
How much water do Australia's systems have?
How much water do we store?
When does it become available?
What is the variability of our water resources between years?
What are the connections between resources?
A series of regional water resource assessments were undertaken throughout Australia as part of AWR 2005. These assessments were for specific water management areas/units in
Australia. They included surface water management areas (SWMAs), groundwater management units (GMUs), capital city water supply areas, inter-jurisdictional and combined water management areas.
Groundwater and surface water have traditionally been managed independently of each other without appreciating the interconnectivity between these resources. As a result, it is likely that double counting of resources has occurred. This could therefore exacerbate over-allocation of resources in some regions. Over-allocation is where the total volume of water able to be extracted by entitlement holders at a given time exceeds the environmentally sustainable level of extraction for that particular system.
This is significant for the geothermal industry because all geothermal systems will use water at some stage, at least for well drilling, and to varying levels for operational losses (around
1%), and also where cooling of electricity generation plants is required. Geothermal energy legislation is subject to the provisions of existing water legislation and planning arrangements, and access to water for geothermal projects is managed accordingly. Depending on which state or territory is being explored, geothermal projects would need to work with water allocation plans and obtain water entitlement/access licences, which may require geothermal projects to utilise established water trading markets, where they exist.
4.2 Water budget
As part of AWR 2005, the following information was forthcoming from Kollmorgen et al. 2007.
In 2004 –05, rainfall for Australia was 2 789 400 GL (average 364 mm), which was substantially below the long-term average (457 mm) for most of the country (except in south-western WA and northern NSW).
The 2004 –05 year was preceded by over five years of below average rainfall across large parts of Australia, particularly the eastern states and south-west WA. This below average rainfall trend continued during the 2005 –10 period. (Subsequently, in mid-2010 one of the strongest La Niña events on record resulted in above average rainfall in the eastern states and northern Australia (BoM 2011a), although south-western WA continues to experience drought conditions.)
On average, 90% of rainfall is directly evaporated back to the atmosphere or used by plants —only 10% runs off to rivers and streams or recharges groundwater aquifers.
NATIONAL WATER COMMISSION
— WATERLINES 50
In 2004 –05, total surface water runoff was estimated at 242 800 GL and total groundwater recharge estimated at 49 200 GL giving a total net inflow to Australia’s water resources of 292 000 GL. Based on these figures, surface water runoff made up 83%, and groundwater recharge, 17% of total net inflows.
Of the total surface water runoff (242 800 GL) over 60% occurred in Australia’s three northern drainage divisions. Runoff was greatest in the Gulf of Carpentaria drainage division (62 060 GL) followed by the Timor Sea drainage division (50 240 GL) and the
North-East Coast drainage division (40 210 GL). In contrast to the high levels of surface water runoff in northern Australia, the Murray –Darling Basin (MDB) is relatively dry, with only 6% of Australia’s runoff.
Compared to the total 2004 –05 water recharge of 292 000 GL, water use totalled approximately 18 700 GL. Whilst this overall picture may appear satisfactory, the highly variable nature of supply and demand across Australia means that in a number of areas resources were stressed. These areas included:
– capital city water supplies where water restrictions were imposed, such as Melbourne,
Sydney, Perth, and Brisbane (in recent months water restrictions have been eased in many parts of Australia)
– inter-jurisdictional areas such as the Murray –Darling Basin and the Great Artesian
Basin (GAB). Groundwater extractions in the GAB total 550 GL/y whilst recharge it approximately 325 GL/y (these are average annual figures rather than figures for the
2004 –05 year).
The apparent over-utilisation of the GAB is an issue of concern that requires ongoing monitoring. The Mereenie Sandstone provides the water supply to Alice Springs and the high utilisation of this resource reflects the policy adopted to ‘mine’ the groundwater resource in the aquifer.
This is significant for geothermal areas because the Cooper-Eromanga Basin in particular (a sub-basin of the GAB) has been identified as a highly prospective area for geothermal development, and sourcing water supplies from the GAB would be an option most projects would consider. Other options exist, however, including co-produced water from conventional oil and gas operations, and also from coal-seam gas operations. It is recommended that all feasible options be considered by geothermal developments, including the option for developers to fund the capping of uncontrolled GAB bores in order to improve aquifer pressures and thus reduce impacts generally, and also to increase the available GAB water for productive purposes, including geothermal.
4.3 Surface water
A total of 245 river basins have been identified in Australia (Figure 17). Kollmorgen et al.
(2007) noted the total surface water storage capacity in Australia’s dams (including estimates of farm dam storage) had not increased significantly since a value of nearly 126 000 GL was reported in 1996 –97. Data on water storage in large dams was previously published by the
Australian Bureau of Agricultural and Resource Economics (ABARE). This is now found on the BoM website. At the time of writing, the most recent data (BoM 2011b) indicates the
2010 –11 La Niña event resulted in a marked increase in reserves from 49.6% full on
25 February 2009 to 73.8% on 25 February 2010 (57 827 914 ML out of an accessible capacity of 78 398 745 ML).
The 2010 –11 La Niña event reversed the decreasing trend in water storages across eastern
Australia. However, it should be noted that each of the previous 15 years recorded below average rainfall, especially in south-eastern Australia.
Many of Australia’s largest dams are primarily built to provide a combination of hydroelectricity and irrigation supplies. These include Tasmania and the Snowy Mountains in
NSW, with the latter also supplementing irrigation supplies in the MDB. Lake Gordon in
NATIONAL WATER COMMISSION
— WATERLINES 51
Tasmania is Australia’s largest dam with storage capacity of 12 450 GL. Major dams are also located adjacent to the capital cities for public water supply and/or flood mitigation purposes.
Figure 17 : Australia’s 245 river basins, with geothermal licences superimposed (licences correct as of 1 December 2010)
Equally important are dams for irrigation purposes, with Lake Argyle (10 760 GL) on the Ord
River, located in northern WA, being Aus tralia’s second largest reservoir. Irrigators within the
MDB are served by a number of large capacity storages including the Dartmouth Reservoir
(3906 GL), Lake Eildon (3390 GL) and Lake Hume (3038 GL).
Given the hydrological variability of Australia’s surface water systems, especially in the more arid zones where there are many geothermal projects proposed but where there are few if any large water storages, it may be problematic for geothermal projects to utilise surface water supply systems (i.e. groundwater may be preferred). Geothermal developments nearby to major surface water storages would increase competition for an already scarce water resource.
AWR 2005 divided Australia into a number of geographical regions to effectively categorise the surface water resources —these regions are known as surface water management areas
(SWMAs). These SWMAs were primarily mapped on a catchment to subcatchment scale, and a total of 340 SWMAs have been defined in Australia.
NATIONAL WATER COMMISSION
— WATERLINES 52
4.4 Groundwater
Groundwater is defined as the subsurface water that occurs beneath the watertable in soils and geologic formations that are fully saturated (Freeze and Cherry 1979). Groundwater can be further described in terms of aquifers and aquitards. An aquifer is a saturated permeable geological unit that can transmit significant volumes of water under ordinary hydraulic gradients for economic activities (Figure 18; DNRM 2005), whilst aquitards are low permeability units within the stratigraphic sequence. Aquitards may have sufficient permeability to transmit water as part of the regional groundwater flow, but this permeability is insufficient to allow development of the resource (Freeze & Cherry, 1979). The size and subsurface depth of aquifers and aquitards tends to be highly variable, being dependent on both local and regional geological and hydrological factors.
Groundwater makes up approximately 17% of Australia’s accessible water resources and accounts for over 30% of our total water consumption (NWC 2008). However, these values were calculated during the most recent drought. Given the heavy rains associated with the
2010 –11 La Niña event it is most likely these figures will be amended by the BoM in its
Australian Water Resources Information System (AWRIS) update.
Figure 18: Schematic of the subsurface groundwater environment (DNRM 2005)
High quality groundwater resources are referred to as potable water and are used for human drinking water applications. Lower grade water tends to be allocated to agriculture, livestock and industrial processes.
The availability of groundwater is generally controlled by several important parameters: the type of strata that hosts the aquifer (i.e. whether it is a sedimentary or fractured rock aquifer system); the degree of connectivity of the voids (whether they be fractures within the rock, or pore throats in sedimentary grains); and the process of recharge, storage and transmission of water. Sedimentary aquifers typically yield at higher rates and store a greater volume of water compared to fractured rock aquifers due to the generally greater interconnection of granular pore spaces compared to fractured networks.
A major controlling factor in groundwater availability is the rate of recharge to the aquifer system versus the rate of extraction. Regions of high rainfall typically have significant volumes of groundwater available in shallow aquifer systems (assuming an aquifer is present). In drier climatic regions, such as the central parts of Australia, aquifers tend to be located at deeper levels below the E arth’s surface, and are often associated with large volumes of water still resident from the geologic past. Replenishment rates in these arid to semi-arid areas are typically low, and recharge zones may be great distances away from the area of extraction.
NATIONAL WATER COMMISSION
— WATERLINES 53
A number of priorities have been identified for future groundwater reform (NWC 2008), the most urgent being to return over-allocated systems to sustainable levels. Other priorities identified by the Commission include the need for nationally harmonised groundwater measurement standards and definitions, a groundwater stocktake in northern Australia, and urgent implementation of a sustainable integrated groundwater and surface water cap in the
Murray –Darling Basin.
AWR 2005 divided Australia into a number of geographical regions to effectively categorise groundwater resources —these regions are known as groundwater management units
(GMUs). Some 367 GMUs have been defined in Australia (Figure 19) and these often fall across more than one SWMA. Groundwater sharing agreements have been formalised between different states where GMUs straddle multiple jurisdictions.
Figure 19 : Australia’s 367 GMUs with geothermal licences superimposed (licences correct as of 1 December 2010)
Since a number of factors —such as rate of recharge and level of extraction—can vary through the seasons, the absolute volume of groundwater within a particular GMU is difficult to measure. A proxy —referred to as the sustainable yield—is therefore adopted; this is the amount of water that can be sustainably extracted (Figure 20). It is clear that a number of geothermal licences are located in areas where the sustainable yield has yet to be quantified.
In addition, a number of geothermal permits are sited in north-eastern SA where the GMU is regarded as having a moderate level of extraction.
NATIONAL WATER COMMISSION
— WATERLINES 54
Figure 20: Sustainable yield of each GMU in Australia (from AWR 2005) with geothermal licences (correct as of 1 st December 2010) superimposed
4.5 Co-produced fluids
In the United States alone, approximately 8000 GL of hot water are produced annually as a by-product of conventional petroleum production (Table 3) — primarily concentrated in nine states (Curtice and Dalrymple 2004; cited in Tester et al. 2006). This resource could potentially generate over 4200 MW of electrical power from 100 °C resources from the states listed in Table 3.
Historically, this co-produced water is a costly inconvenience in most mature petroleum areas
(Tester et al. 2006). There is, however, growing awareness that rather than disposing of this water, the resource can be used to produce geothermal electricity for petroleum field operations or to supply to the national grid.
The key factors required for successful geothermal electrical power generation from coproduced fluids include sufficiently high flow rates and temperature from a well or group of wells in relatively close proximity to each other. Although some of the fluid produced from the petroleum industry may not be suitable for use, a certain fraction may always be available that can be easily produced, collected and used as feedstock for geothermal developments.
NATIONAL WATER COMMISSION
— WATERLINES 55
Table 3: Equivalent geothermal power from co-produced hot water associated with existing petroleum production in selected states of the US
State
Alaska
California
Illinois
Kansas
Louisiana
New Mexico
Oklahoma
Texas
Wyoming
Total water produced
Annually
(kbbl)
1 688 215
5 080 065
2 197 080
6 326 175
2 136 573
1 214 797
12 423 264
12 097 990
3 809 087
Total water production rate (kg/s)
8522
25 643
11 090
31 933
10 785
6132
62 709
61 097
19 227
Equivalent power
(MW@
100 °C)
153
462
200
575
194
110
1129
1099
346
Equivalent power
(MW@
150 °C)
528
1590
688
1980
669
380
3888
3786
1192
Total 46 973 246 237 138 4268 14 701
Note: 1 kbbl is 1000 barrels, or approximately 159 kL; 50 million kbbl is about 8000 GL
(Curtice & Dalrymple 2004; cited in Tester et al. 2006.)
Equivalent
Power
(MW@
180 °C)
733
2205
954
2746
927
527
5393
5252
1654
20 391
Within Australia, co-produced water is of particular significance in the Cooper-Eromanga
Basin where a number of geothermal licences overlap existing petroleum operations. Each petroleum field has a large evaporation basin to dispose of water co-produced during the extraction of petroleum, so water sources are spread throughout the area. The size of each evaporation basin varies depending on the rate of fluid production. The water is mineralised
(predominantly salts) and contains varying levels of bacteria, so the suitability of such sources for geothermal operations may be limited. Further assessment of water sources co-produced during petroleum operations could lead to geothermal energy projects in these areas; however, this type of development has not yet been widely considered in water planning and management frameworks.
NATIONAL WATER COMMISSION
— WATERLINES 56
5. Water quality
5.1 Overview
Most major geothermal projects for electricity generation (proposed and developed
EGS/HSA) that plan on utilising groundwater resources will use closed-loop systems, as discussed in Section 3.2, although regulators need to be aware of the additional water balance impacts associated with systems that do not recirculate the working fluid (i.e. singlebore, open-loop systems). In principle, to reduce water and heat balance impacts, water extracted for the purposes of geothermal utilisation should be returned to the subsurface environment once heat energy has been extracted. From the perspective of geothermal companies the costs involved with reinjection are offset by benefits, including reduced water consumption (and thus reduced entitlement, licensing and compliance issues), and the maintenance of aquifer pressures and thus reduced impacts.
Since the extracted groundwater remains within the closed-loop system there is no interaction with the outside environment and thus negligible (if any) impact on groundwater quality throughout the extraction/injection process. It should be noted that many of the groundwater aquifers being targeted for geothermal utilisation lie at depths of a few kilometres (in the case of electricity production, both EGS and HSA), and several hundred metres (LEAs). With the notable exception of the GAB, deeper aquifers are less frequently used for human consumption purposes.
There is always a risk of borehole failure and subsequent inter-aquifer leakage in any groundwater extraction operation. As is common practice within the groundwater extraction industry, any shallower intersected aquifers should be sealed off to minimise the risk of interaquifer leakage. All bores utilised for geothermal activities need to be cased to ensure the stability of the borehole during extraction/injection processes. While there is no specific construction standard for geothermal boreholes in Australia there is a set of minimum construction requirements for water bores (Land and Water Biodiversity Committee, 2003).
For geothermal bores, each state or territory develops their own procedures, which may (or may not) refer to the New Zealand Code of Practice for Deep Geothermal Wells (NZS
2403:1991). For example, SA applies an objectives-based process that requires the geothermal proponent to submit their well design plans for review. This non-prescriptive approach is designed to provide maximum flexibility for companies to incorporate new technology and refined well-design practices without being tied to specific legislation. The outcome of the engineering review of the well design is a recommendation to accept the well design, or for the company to review and amend the well-design specifics. Under these arrangements the possibility of borehole failure during geothermal operations (as distinct from bore construction which involves fracture stimulation) should be no different from normal groundwater extraction activities. While best practice methods for geothermal bore construction and fracture stimulation are still being developed in a process of continuous improvement it is recommended that technical guidance should be developed and applied in due course.
The likelihood that a closed-loop geothermal project could impact on water quality for other users in connected systems is negligible. However, mitigation strategies for dealing with this unlikely scenario should still be employed and dialogue should be initiated between water planners and geothermal operators at an early stage of any proposed development.
The quality of the water utilised for geothermal operations depends on a number of factors including the local geology, the temperature of the resource and the source of the fluids.
Water salinity and chemistry need to be assessed to determine whether the fluid is applicable for specific industrial purposes.
NATIONAL WATER COMMISSION
— WATERLINES 57
5.2 Water salinity
As water flows through the subsurface environment it dissolves traces of the rocks and sediments it encounters en route. The total concentration of dissolved minerals within the water is referred to as total dissolved solids (TDS), and this is often taken as a proxy for water salinity. TDS is measured in milligrams per litre (mg/L) with values of <1000 mg/L generally acceptable for domestic and irrigation purposes, and 1000 –10 000 mg/L for agriculture.
Seawater is approximately 35 000 mg/L.
Most minerals are only sparingly soluble in water (Nahm 1977) and the movement of groundwater can be measured in terms of a few millimetres to hundreds of metres per year, depending on the lithology through which it travels. Groundwater within large, deep basins often has transit times measured in hundreds of thousands of years over hundreds to thousands of kilometres.
High enthalpy EGS and HSA projects will likely have differing TDS values since the in situ water within the different reservoir types has different evolution and habitat origins. For example, the GAB —presently the focus of HSA exploration by a number of geothermal companies —typically has TDS concentrations in a range of three orders of magnitude from
<200 to >10 000 mg/L (Radke et al. 2000), whereas in situ fluid in the Soultz-sousForêts
EGS project in France had concentrations of approximately 100 000 mg/L (Sanjuan et al.
2006). Although Australian geothermal operations generally describe the production fluid as
‘brine’, there is very limited publicly available data stating actual salinity values.
There is typically a trend of increasing TDS with increasing depth of an aquifer and distance from recharge areas, as documented in the GAB (Radke et al. 2000) and illustrated in
Figure 21.
By their very nature, in situ EGS fluids are typically more saline than HSA systems. This is because EGS fluids are sourced from deep, fractured rocks (usually crystalline) with low porosity and permeability. There is therefore slow solute movement and increased residence time within the EGS realm. HSA systems typically have more benign water chemistry, as discussed in Section 5.3.
5.3 Water chemistry
5.3.1 Gaseous components
In the absence of coal seams, the most likely gaseous components in groundwater, also referred to as non-condensable gases (NCG), are carbon dioxide (CO
2
), hydrogen sulfide
(H
2
S) and ammonia (NH
3
). These NCGs are usually only found in very small concentrations.
In conventional steam turbines utilising geothermal fluids directly, NCGs can reduce power output by reducing the proportion of condensable steam. However, all geothermal systems proposed in Australia will utilise heat exchangers to drive ORC units, rather than directly utilising geothermal steam.
An incident at Geodynamic’s Innamincka project in April 2009 highlights the significant potential problem associated with gaseous emissions. Corrosion associated with dissolved
H
2
S was attributed to hydrogen embrittlement (HE) within the well casing, resulting in a blowout of the Habanero-3 well (Geodynamics 2009b). Although not specifically stated by Gaffney et al. (1988), the blow-out of Della1 (near the Innamincka project) in 1987 due to ‘corrosive groundwater’ might also have been due to HE. HE is exacerbated by excessive concentrations of H
2
S and/or excessive pressures, resulting in hydrogen atoms diffusing into the tensile steel of the casing. HE can be managed by understanding the chemistry of the water and ensuring the correct grade of steel is utilised in all pipework.
NATIONAL WATER COMMISSION
— WATERLINES 58
Figure 21: TDS concentrations in the Cadna-owie –Hooray Aquifer in the Great Artesian Basin
(GAB) (from Radke et al. 2000). Distinctive regions of TDS concentrations can be delineated which are the result of proximity to recharge areas and direction of groundwater flow.
NATIONAL WATER COMMISSION
— WATERLINES 59
Trace amounts of H
2
S were present within the Portland district heating system (see Section
2.2.3) and this had to be removed at the cooling towers (Chopra, 2005). Whilst H
2
S is a common constituent of groundwater in volcanic provinces, it is likely to be uncommon in deep groundwater in Australia. However, H
2
S is recorded from the Cooper –Eromanga Basin in central Australia, the site of a number of high enthalpy geothermal exploration and development projects. The provenance of H
2
S in the Cooper –Eromanga Basin is poorly understood. It might come from a number of possible inorganic and organic sources, including:
sulfides and sulfates associated with minerals within the Big Lake Suite granodiorite (e.g. magmatic hydrocarbon gases as described in Japan by Kiyosu et al. 1992)
metagenesis —dry gas generation from coal measures dominated by Type III organic matter at presentday temperatures within the ‘post-mature’ window ~190–210 °C
thermochemical sulfide reduction —transformation of some petroleum products at high temperature to H
2
S (e.g. Cai et al. 2005).
Managing the risk of major problems arising from non-condensable gases does not require any significant technological development. Rather, it is largely a matter for the geothermal operator to ensure compliance with the specific state or territory environmental standards and regulations.
5.3.2 Dissolved minerals
The amount of dissolved minerals and solids in groundwater increases significantly with temperature (Tester et al. 2006). Some potentially harmful dissolved minerals such as boron and arsenic are associated with volcanic-sourced geothermal fluids and are detrimental to surface water and groundwater systems. However, there is a lack of information about the distribution and magnitude of harmful minerals in non-conventional Australian geothermal project fluids.
Silica is a dissolved mineral that is frequently present in geothermal fluids since silica is a major component of rocks and sediments. Whilst not detrimental to health, the presence of silica can lead to silica scaling on the interior of pipes, heat exchangers and other plant. This phenomenon is a result of silica precipitating out of solution due to decreasing pressure and/or temperature. Silica removal from pipe networks is a costly and time-intensive process.
Remedial applications such as pressure management and/or chemical additives to manage the water chemistry are thus the preferred strategy prior to scaling becoming a problem.
The probability of EGS and HSA projects for electricity generation causing contamination of surface or shallow groundwater is low since all currently proposed developments to date propose closed-loop systems where produced fluids are reinjected into the deep subsurface.
Open-loop LEA systems involving surface discharge or reuse (such as Warrnambool ) would require more active management.
One further possible cause of groundwater contamination is the drilling and development phase of the project. Bores must be carefully monitored during this phase to ensure any leakage of drilling fluid is rapidly identified and managed. Bore completion and casings should be firmly cemented to ensure shallower aquifers are isolated and remain uncontaminated.
Refer to Section 5.1 for a discussion of bore construction standards.
NATIONAL WATER COMMISSION
— WATERLINES 60
6. Water policy and management
6.1 NWI and geothermal systems
The Intergovernmental Agreement on the NWI was signed at the 25 June 2004 CoAG meeting. Through the NWI, Commonwealth and state governments have agreed on actions to achieve a more cohesive national approach to the way Australia manages, measures, plans for, prices, and trades water. This initiative remains a work in progress. Whilst the NWI does not specifically refer to the geothermal industry, it is taken that references to the ‘minerals and p etroleum’ industries covers the entire resources sector, including geothermal.
As any geothermal system operation involves the circulation of water in the subsurface, the systems should be considered within the normal water planning processes. For example, there is potential for geothermal activities to impact on existing water users and waterdependent ecosystems in terms of localised groundwater level drawdown (around production wells) and/or mounding (around injection wells). There is also potential for cumulative impacts; for example, if a high density/intensity of geothermal schemes develops in a localised area (e.g. GSHPs in metropolitan areas) where they may affect the subsurface water/heat balance and hence impact on other water users or the efficiency of the various schemes. With the possible exception of potential heat balance issues associated with any concentrated development of low enthalpy and GSHP systems, existing water planning and policy arrangements are generally capable of considering the issues of specific and cumulative impacts (refer to Section 2.3 for more detail). If there is significant growth in low enthalpy and GSHP systems, then future planning and policy should consider heat balance issues along with water balance issues.
Under Clause 34 of the NWI, the signatory governments agreed that there may be special circumstances facing the ‘petroleum and minerals’ sector that need to be addressed by policies and measures beyond the scope of the NWI agreement. In this context, all governments noted that specific project proposals would be assessed according to environmental, economic and social considerations, and that factors specific to mining
(resources) sector development projects (such as isolation, relatively short project duration, water quality issues, obligations to remediate and offset impacts) may require specific management arrangements outside the scope of the NWI.
In both its 2009 and 2011 Biennial Assessments of national water reform progress (NWC,
2009; NWC 2011), the Commission found that the circumstances in which Clause 34 would apply are not well defined nor are they identified in a consistent and transparent manner. Little progress had been made since the signing of the NWI in detailing the special provisions for the petroleum and minerals industries, although at the time of writing some Commission projects on these topics are nearing completion (notably the cumulative, water-related, impacts of the mining industry (Jensen 2010), and co-produced water management for the oil and gas industry). As a consequence, although the resources sector generally is not yet comprehensively integrated with broader water planning processes or markets, integration of the geothermal sector in particular would be readily achievable within current frameworks.
Section 2.3 identified that the geothermal legislation is subject to the provisions of the various water acts in all states and territories except NSW and Tasmania. The gaps in NSW and
Tasmania are nominal (i.e. not material) in that activities that result in water take and discharge are subject to licensing under water and/or environmental legislation, as is the case in every state and territory. Along with examples presented in Sections 1.8 and 2.3 of how geothermal projects are currently being managed, this indicates that the existing water management arrangements are capable of managing geothermal projects if implemented appropriately.
NATIONAL WATER COMMISSION
— WATERLINES 61
The Commission recommended that NWI-consistent water access entitlements be defined for the resources sector in order to provide those industries with secure access to water and the ability to trade water rights with other users. Particular circumstances and potential third-party impacts that might limit the applicability of NWI-consistent water access entitlements should be clearly identified and managed.
While the geothermal energy sector has not previously been explicitly addressed within the
NWI considerations of the resources sector, the following section provides some broad context on major geothermal water use characteristics, before further discussing water planning implications for the geothermal industry.
6.2 Groundwater management
6.2.1 Regional water planning and high value areas
Regional water plans work at a high level and provide the opportunity to apply consistent costing principles across a range of supply options, including optimisation of surface and groundwater resources, aquifer storage and recovery, treated waste water, desalination, and inter-basin transfers. It is important that such planning processes allow for the involvement of the geothermal and related electricity generation industry to ensure that all options are on the table.
In addition to addressing water availability through technical options, the NWI also provides an opportunity for users to secure additional water through trading. Supply risks can be managed through participation in water markets, which provide a degree of flexibility of particular value to the electricity generation industry.
The Great Artesian Basin (GAB) and the Murray –Darling Basin (MDB) are two of the major regions that incorporate high value groundwater resources within Australia. The GAB contains a vast groundwater resource which, due to the high temperatures exhibited, provides an area of natural interest to the geothermal energy industry. The MDB on the other hand, whilst covering a large spatial extent, brings with it issues relating to an already highly developed system with many competing water users.
Planners and managers in high value or highly developed areas such as these should find useful information in this paper to support them in their initiatives. It will be important that future arrangements for the geothermal industry and related electricity generators are as consistent as possible with the framework principles for access and pricing under the NWI.
6.2.2 Open-loop and closed-loop geothermal systems
Several classification systems may be applied to geothermal projects. The early chapters of this report provide a geothermal energy classification that integrates depth and heat flux (i.e.
EGS, HSA, GSHP, LEA, etc). Open-loop or closed-loop is the other main classification system that is used by the industry in general, including the associated finance and engineering sectors.
All deep geothermal systems that involve reinjection (EGS and HSA) are classified as closedloop, based on the geological context that injection occurs to the same formation as the extraction (albeit possibly at a shallower level compared to the deep extraction).
The (shallow) GSHP sector, however, adopts a different definition of closed-loop to describe the circulation of a fluid (water, refrigerant or, in some cases, air) around a closed loop of pipework. Almost all GSHP systems are closed-loop systems, especially in Australia. Openloop GSHP systems, on the other hand, use water drawn from a well or surface water body
(e.g. lake/stream) to circulate through the system and heat exchange unit, with the water being returned to the ground via a recharge well, or discharged to the surface.
NATIONAL WATER COMMISSION
— WATERLINES 62
This option is obviously practical only where there is an adequate supply of relatively clean water (which typically constrains the application of open-loop GSHPs in Australia), and all local codes and regulations regarding groundwater discharge are met.
Regardless of definition, from a water resources and potential consumption/use viewpoint, closed-loop systems are inherently non-consumptive and thus involve few risks in relation to water management and the NWI. During operation, closed-loop systems generally do not require an ongoing source of water, aside from potential top ups where fluid losses are manifest (this would not apply to GSHP closed-loop systems). Project approvals for closedloop systems should incorporate requirements for management strategies should fluid losses be experienced, including addressing potential water losses due to over-pressurisation, water quality and thermal balances (all of which the geothermal operation would seek to avoid to ensure project viability).
Options for sourcing and/or discharging of water for open-loop systems (e.g. to/from bores/lakes/rivers/marine waters) may trigger the need for specific licensing and planning requirements due to the higher risk of environmental, social and economic impacts. Therefore water policy for open-loop systems should incorporate more stringent approvals and management processes because of their greater exposure to other environmental systems.
6.2.3 Geothermal construction and operation issues
From the geothermal indust ry’s perspective, important considerations for water planners in terms of water use and access include the following:
Rights to extract water from specific geological units and use it for geothermal well construction and testing, including pressure injection to geological units that may be distinct from the extraction unit. Specific, but not significant, consumptive use requirements would be required, but over short-term time frames, usually less than one year.
Rights to extract and inject water from/to the same geological units for closed-loop
EGS/HSA geothermal operations (low consumptive use during operations or around 1% make-up).
Options to use the water produced by geothermal operations for specific purposes (e.g. essential human needs, irrigation, aquaculture, etc.) under arrangements consistent with the NWI framework principles, and subject to the standard impact assessment procedures for water allocation planning and licensing.
For GSHP systems, applicability of the existing/proposed water planning frameworks.
Reliability of tenure.
Where hydraulic fracture stimulation is employed, an understanding of the in situ stress field of a reservoir is critical. If pressurisation greatly exceeds the minimum stress at the depth of the reservoir, there is the potential for the continual growth of the fractured rock volume, leading to an increase in water loss. Pressure should be maintained at a rate that prevents this from occurring (especially during scheme operation).
Any make-up water volumes required need to be carefully managed and monitored
(regulated if necessary) to prevent the potential for additional water pressure to create fracture extensions leading to water losses (refer to above point). Rights to the required make-up water volumes for geothermal power utilisation may need to be secure in some instances (e.g. cooling water for electricity generation —see Section 6.2.4), but should otherwise be issued on the same basis as every other user so that water trade can be applied to achieve the desired security.
NATIONAL WATER COMMISSION
— WATERLINES 63
Micro-seismic evidence from EGS project exploration and testing indicates a typical radius of influence of fracture stimulation in the order of 300 –500 m from the well in a horizontal direction, with some cases extending up to around 1000 m (less than this amount in a vertical direction). For wells that are typically around 4000 m deep there is negligible potential for fracturing to extend up to the surface. Specifically, issues that have been identified with CSG developments are not applicable to EGS/HSA systems. Where relatively shallow or low enthalpy geothermal systems are proposed (i.e. <1000 m depth) it would be prudent for regulators to adopt a precautionary approach and stringently regulate fracture stimulation activity to ensure a low level of risk of environmental impacts.
Using a precautionary approach would bring the industry in line with the Commonwealth position in regards to CSG development, which is another energy-related industry encountering water policy-related uncertainty due to its infancy and rapid growth.
6.2.4 Electricity generation issues
Electricity generation issues relating to the geothermal industry are common to those relating to the electricity generation industry generally. Recognising the linkages between water supply and energy security, the Commission and DRET commissioned a report to investigate the impact of changed water availability for electricity generation in Australia and to identify future management options for the sector (Smart & Aspinall 2009). In particular, the study looked at the implications of the agreement by state and territory governments to introduce:
water access entitlement and planning frameworks that enhance the security and commercial certainty of water access for all users, and provide adequate opportunity for productive, environmental and public benefit considerations to be identified and considered in an open and transparent way
water market arrangements that facilitate the efficient trade of water, thereby giving water-using businesses access to flexible opportunities to trade water and choose how they utilise their water access entitlements
water pricing arrangements, such as full cost recovery for water services, that promote economically efficient and sustainable use of water resources and water infrastructure assets.
The report stated that geothermal power plants were likely to have a higher water intensity compared to coal-fired power plants since geothermal turbines operate at lower thermal efficiencies. However, this statement is potentially misleading since it appears to assume that all geothermal power plants are water cooled. In fact, geothermal power plants can be either water cooled, air cooled or a combination of both, depending on availability of water (see
Section 3.4). Smart and Aspinall (2009) detailed the factors influencing choice of cooling systems with electricity generating power plants. Air cooling performs less effectively in hotter ambient conditions, since the lowest temperature the cooling plant can condense vapour is limited by the ambient dry bulb temperature —resulting in significant reductions in both efficiency and generator capacity relative to water cooling. Whilst water-cooled geothermal power plants would be more efficient in hot inland areas in Australia, water access constraints may mean this is not viable —although synergies with CSG and other co-produced water could be explored. A compromise could be hybrid cooling in which air cooling is predominantly used, with additional water cooling used during peak temperatures.
Smart and Aspinall (2009) concluded that the NWI reforms have only had a marginal impact on the electricity generation industry. The water requirements of existing power stations have been largely taken into account in catchment level water planning, and this does not appear to have had a material impact on their water access arrangements. Some in the industry commented that it was difficult to get involved in local community consultation processes where adjustments to supply arrangements were considered. There had been some water trading at the margin, although there was a view that water markets are far less transparent than is desirable.
NATIONAL WATER COMMISSION
— WATERLINES 64
Recommendations from Smart and Aspinall (2009) included:
Governments should ensure that future licence arrangements are made as consistent as possible with the pricing and access frameworks of the NWI, particularly with respect to supply security, security of tenure, trading entitlements, and pricing.
To facilitate improved water use efficiency by the electricity generation industry, water supply access arrangements should not mandate ‘take or pay’ arrangements, nor exclude participation in water trading unless agreed by electricity generators.
In line with the NWI, the full opportunity cost of all supply and savings options should be reflected in the price of all supply options when considering these in regional water planning processes. This should form the basis of pricing for the selected options for generators.
In light of the need to reduce carbon emissions and the impact on water demand for cooling in power stations, priority should be given to focusing research and development in Australia on water management and efficiency in electricity generation.
From the electricity generation industry’s perspective, important considerations for water access include:
rights to extract water
rights to water stored in reservoirs or in river flows
rights to discharge water
reliability of tenure.
These considerations will be particularly important in the water-limited prospective geothermal areas mentioned in Section 4. Current water access arrangements for the electricity industry involve licences and contracts specifically tailored for the adequate supply of water for electricity generation, notably to provide a highly secure supply of water to large power stations. While aspects of these licences and contracts are consistent with the water access framework set out by the NWI, there are examples of where the licences and contracts do not meet the requirements including:
limited rather than perpetual tenure
limitations or conditions on trading
imposing conditions such as water use efficiency and discharge rules
‘take or pay’ conditions.
Moving forward, policy makers should consider the impact of the current arrangements on investment decisions for new generation capacity and the implications for water efficiency.
They should also consider the impact of inconsistencies between existing contracts (both within and between jurisdictions) on the relative competitiveness of existing generators.
Water pricing policies being adopted in regional schemes, such as the South East
Queensland Regional Water Security Program, are sometimes based on a fixed and variable charge to cover the supply of purified recycled water as well as cover the cost of storage and infrastructure. Whilst these arrangements are consistent with the principles of the NWI, there is a ‘take or pay’ component associated with the fixed charge. On the surface, this appears to discourage generators from considering further investment such as dry cooling, as they will still be required to meet the take or pay commitment. They are not able to sell any water saved under such a scheme in the event that they do make savings. This does not, on the face of it, appear to be consistent with the pricing framework of the NWI and should not be applied to new geothermal developments.
NATIONAL WATER COMMISSION
— WATERLINES 65
6.3 Guiding principles for geothermal energy and water planning
The consequences of not managing the water risks and uncertainties associated with geothermal energy may be significant. Therefore, the careful, transparent and integrated consideration of water-related impacts in all approval processes is recommended.
6.3.1 Geothermal energy within the resources sector
Clause 34 of the NWI provides for special management arrangements for mining and petroleum activities. However, it does not preclude parties from including the resources sector in their water planning regimes. Since Clause 34 of the NWI is only intended to operate in exceptional circumstances, NWI-consistent water access entitlements could be made available wherever possible to the resources sector in general and to geothermal energy in particular. Where Clause 34 is applied in relation to geothermal developments, a clear and transparent explanation of why it is used to invoke special arrangements, rather than complying with the normal water planning and management regime, should be provided. For example, in South Australia, resources developments can be managed within the water planning regime or under specific arrangements outside the water planning regime, or through a combination of the two. However, the Commission has identified that the question of how resources sector activities relate to water planning processes in most jurisdictions appears to require further consideration.
Wherever there is potential for significant water resource impacts, geothermal energy and water use activities should be incorporated into NWI-consistent water planning and management regimes from their inception. Given the lack of experience around water impacts of geothermal operations in Australia, this will likely require a precautionary approach (at least initially) that demands innovation from water managers and planners, and coordination with existing project approval processes.
6.3.2 Guiding principles
The following guiding principles should be considered by state and territory jurisdictions to manage the potential impacts (including cumulative impacts) of geothermal-related water use
(noting that some jurisdictions already reflect a number of these principles in their current arrangements):
Wherever possible, geothermal activities should operate under the same rules and regulations as other water users, with acknowledgement of the higher security needs of water for cooling power-generation plants.
Project approvals need to reflect water management objectives and regulatory regimes.
They should be transparent, including clear and public articulation of predicted environmental, social and economic risks along with conditions implemented to manage the risks.
Given the nascent position of the industry in Australia, a precautionary and adaptive approach to managing and planning for geothermal activities is essential to enable improved management in response to evolving understanding of uncertainties.
The interception of water by geothermal activities should be licensed to ensure it is integrated into water sharing processes from their inception. This is important for all phases of deep geothermal projects, which can involve significant consumptive use.
Open-loop GSHPs also may have high demands, although these systems are not common in Australia, and substantial growth in the short to medium term is considered unlikely.
NATIONAL WATER COMMISSION
— WATERLINES 66
Jurisdictions should consider the water and heat balances and water quality issues of geothermal activities, and manage those impacts under regulatory arrangements that are part of, or consistent with, NWI-stipulated statutory-based water plans developed for groundwater management units.
NWI-consistent water plans should be completed to enable geothermal operators to secure their necessary water supplies, either through the issue of entitlements or by purchase from willing sellers. Where geothermal activities access low quality water, water planning regimes should be extended to encompass these resources.
Policy makers should ensure that the geothermal industry is included when consulting water planners, the community and other water users to plan and develop policy options for future water resource management. For example, water allocation plans should make adequate allowance for industrial users, as has been successfully shown in South
Australia’s Far North Water Allocation Plan.
If discharges to surface waters are unavoidable, they should be conditioned so that environmental values and water quality objectives, including public health and ecological objectives, are met (this is particularly applicable to open-loop systems).
A suitable precautionary approach to manage fracture stimulation of EGS would be to constrain such activities to the use of fresh water (i.e. no chemicals, proppants, gels, etc) and depths greater than 1000 m, to reduce the potential for environmental impacts.
Water produced as a by-product of geothermal activities that is fit for purpose for other industries or the environment should be included in NWI-compliant water planning and management processes. This will enable geothermal producers to manage their resource in accordance with the principles of the NWI (particularly applicable to open-loop systems).
6.4 Future policy needs for an expanding industry
The increasing value placed on water resources by federal, state and territory government agencies has resulted in the Australian geothermal industry becoming very aware of its roles and responsibilities with regards to water use.
The Water Act (2007) (Cth) recognises growing concern in relation to the potential impact of resources development throughout many parts of the basin; thus, Section 255AA was drafted to ensure that the water impact of any future mining activity on floodplains is considered. The section specifies that prior to licences being granted for ‘subsidence mining’ operations (which would appear to relate to any subsurface mining operation) on floodplains that have underlying groundwater systems forming part of the MDB system inflows, an independent expert study must be undertaken to determine the impacts of any proposed mining operation on the connectivity of groundwater systems, surface and groundwater flows, and water quality. Since open-lo op geothermal is effectively ‘mining hot water’ and closed-loop geothermal is effectively ‘mining heat’ from underground, it is expected that geothermal operations would fall under this caveat.
In 2004 –05, mining operations accounted for less than 1% of the total water consumed in the
MDB (approximately 20 GL). However, the rapidly expanding CSG industry in many parts of
NSW and Queensland means this percentage will certainly rise rapidly. Previously, the huge volumes of co-produced water were disposed of in large evaporation ponds. However, this disposal method has potential long-term environmental impacts linked to ecological damage, groundwater contamination and depletion, salt disposal and accumulation, landscape impacts and the amount of land required. Queensland has now mandated that the use of evaporation ponds be discontinued. Synergies between geothermal energy and CSG extraction are thus being explored (Mortimer and Cooper 2010).
NATIONAL WATER COMMISSION
— WATERLINES 67
During exploratory and development phases of geothermal activity (both open- and closedloop systems), requirements for water use and disposal should be incorporated into exploration permits issued by the relevant jurisdiction.
In cases where water needs to be brought in from external sources (i.e. EGS in low-yielding aquifers), transfer of water between different sources may provide additional concerns, due to the potential for geochemical issues. Further management arrangements may need to be incorporated into the water planning process in these instances.
With regards to electricity generation issues, it will be important for policy makers to examine how the existing and emerging arrangements are facilitating efficient resource allocation over time and encouraging power stations to implement the most efficient water management programs. The access and pricing framework of the NWI provides a good starting point for any such assessment.
NATIONAL WATER COMMISSION
— WATERLINES 68
7. Conclusions
Australia lacks conventional hydrogeothermal resources (e.g. similar to those in New
Zealand) , and Australia’s only currently operating geothermal power plant, located in
Birdsville, Queensland, yields just 80 kWe (net) from a non-conventional hot sedimentary aquifer (HSA) system. However, Australia has excellent potential for significant energy production from (deep) non-conventional HSA and engineered geothermal system (EGS) developments. EGS and HSA developments currently underway in Australia are each in the order of tens of megawatts in scale, the most advanced to date being located in South
Australia. In addition, there is considerable scope for energy production from shallow systems such as low enthalpy aquifers (LEA) and ground source heat pump (GHSP) applications.
Given the scarcity of water resources in Australia however, it is unlikely that there will be growth in aquifer thermal energy storage (ATES) applications in the foreseeable future.
Initiatives introduced in recent years by Australian governments, academia and industry to collaborate and break technical barriers aim to position Australia as a dominant global developer of EGS and HSA technologies. Other countries are also actively pushing to develop their non-conventional geothermal resources, most notably in Europe and the USA. It is notable that Germany, geologically similar to Victoria, but with much higher feed-in tariff arrangements that provide substantial financial support to this developing industry, already has four non-conventional geothermal power plants in operation at Landau (3.5 MWe),
Unterhaching (3.4 MWe), Nuestadt-Glewe (230 kWe) and Bruchsal (550 kWe). At least two more are in the construction phase and due for commissioning in 2011: Insheim (5 MWe) and
Sauerlach (5 MWe).
The geothermal legislation in all jurisdictions is subject to the provisions of the various water acts in all states and territories except NSW and Tasmania. The gaps in NSW and Tasmania are nominal (i.e. not material) in that activities that result in water-take and discharge are subject to licensing under water and/or environmental legislation, as is the case in every state and territory). Where low enthalpy and GSHP resources are exempted from geothermal legislation (such as in Victoria, NSW, WA and NT), the operations are still subject to existing water and planning legislation. Existing arrangements are thus considered to be capable of managing geothermal project water issues if implemented appropriately. Improved integration would be aided by removing exemptions in geothermal legislation and possibly by combining legislation within the one act to cover the range of water balance elements (e.g. extraction, reinjection, and discharge to environment) that are controlled by separate water and/or environmental legislation.
In relation to the potential for impacts, the geothermal industry has some distinct differences from the mining, oil and gas industries (for example, EGS and HSA systems do not involve extraction of large volumes of rock/ore or oil/gas). Although EGS use similar drilling and wellconstruction techniques to the oil and gas sector, the major difference is that hydraulic fracture stimulation for EGS typically uses only water (no chemicals). A successful EGS is also developed at great depth (up to 5000 m), with resistive layers above the reservoir that limit the potential for transmission of impacts (e.g. from hydraulic fracture stimulation or thermal gradients) towards the surface. HSA and low enthalpy systems are developed at less hot temperatures and shallower depths, but these systems rely on the natural permeability of the aquifers, and the related flow and circulation patterns (i.e. do not involve fracture stimulation).
There may be some benefit in water planners considering a precautionary approach to manage the potential environmental effects of any proposed shallow fracture stimulation by constraining such activities to the use of fresh water (i.e. no chemicals, proppants, gels, etc) and at depths in excess of 1000 m, provided there is scope for site-specifics to be considered and investigated in detail by proponents to establish impacts and management plans.
NATIONAL WATER COMMISSION
— WATERLINES 69
During exploratory and development phases of major geothermal activity, well drilling, construction and testing activities involve water use and disposal. These water-related requirements are comparable to those for conventional drilling activities and thus could be managed under existing permit arrangements for water well drilling and testing issued by the relevant jurisdiction.
Consumptive water use requirements are generally quite low (around 1%) for operating geothermal schemes that recirculate the working fluid (i.e. closed-loop or reinjecting), and also for the exploration and construction stages (including EGS and HSA). For such schemes, water supply/security issues are not significantly different from those facing other sectors.
Depending on the scale of the development, the volume of water involved over a specified time frame (e.g. as the geothermal field is developed over a number of years) may be deemed significant, and the sustainability of the extraction should be considered under existing water management arrangements, including assessment of the potential environmental impacts and socioeconomic factors.
Water use requirements for different geothermal systems can vary markedly. Most EGS/HSA geothermal systems designed for electricity generation are closed-loop when operational, where the water is recirculated back into the target extraction formation. Closed-loop systems involve little to no consumptive water use, other than minor top-ups (i.e. ~1% of total throughput). These water use requirements are consistent with those required for most mining operations and thus could be managed under existing arrangements by the relevant jurisdiction. Project approvals for closed-loop systems should incorporate requirements for management strategies should fluid losses be experienced, including addressing potential increased water use, water quality issues and thermal balances (all of which the geothermal operation would seek to manage carefully to ensure project viability).
For water planning purposes, the potential geothermal energy water requirements are estimated to be around 1 GL/a per 40 MW installed capacity of electricity generation (or 3
ML/d per 40 MW). This includes allowances for construction and operational requirements for geothermal development over a range of EGS and HSA assumptions, but excludes the cooling requirements of electricity generating plants (by definition, it also does not allow for other low enthalpy or direct use types of geothermal development).
Some direct use geothermal systems are open-loop when operational (usually shallow/low enthalpy systems, but also some HSA systems), where the water is not recirculated back into the target extraction formation. These systems do involve water use and disposal, usually to/from separate water sources (e.g. often involving a surface water body). Options for sourcing and discharging water for open-loop systems (e.g. to or from bores, lakes, rivers or marine waters) may trigger the need for specific licensing and planning requirements due to the higher risk of environmental, social and economic impacts, which could be managed appropriately under existing water policy and legislation, although historically this has not always been effective. If there is significant growth in low enthalpy and GSHP systems, then future planning and policy should consider heat balance issues along with water balance issues.
For geothermal power plants, the primary consumptive water requirement during the production phase is for cooling purposes, although there are some minor ancillary requirements such as power plant amenities and facilities. Geothermal power plants in
Australia are likely to use Organic Rankine Cycle (ORC) binary units. Where geothermal power plants are located remote from plentiful water sources, the combination of a hot climate and limited access to water will require innovative designs for power plant cooling systems.
With some notable exceptions (e.g. Swan Coastal Plain near Perth, WA), the majority of licences for major geothermal development in Australia are located in areas where the sustainable yield of Groundwater Management Units (GMUs) has yet to be quantified. This uncertainty can be accommodated in water planning processes by ensuring that an adequate allowance is provided in water plans for industrial purposes (i.e. including geothermal, oil and gas and mining), to meet the needs of projects that have not yet been identified, explored or developed.
NATIONAL WATER COMMISSION
— WATERLINES 70
This approach has been successfully applied to South Australia’s Far North Water Allocation
Plan, and provides a degree of certainty for major geothermal resources development.
Similarly, the potential for development of low enthalpy (shallow) geothermal systems, which may arise in urban areas over coming decades, also needs to be considered under existing urban water planning and review arrangements.
Given concerns over water scarcity, coupled with increasing demands on water resources in
Australia, geothermal companies, water planners and policy makers need to consider all options for water sources. For example, two industries within Australia that produce substantial volumes of water in excess of local needs are the petroleum and CSG industries.
Disposal of co-produced water in both industries is usually a costly exercise, financially and environmentally. Rather than disposing of this water, the resource could be used to produce geothermal electricity provided the fluids are co-produced at sufficiently high flow and temperatures. Although some of the fluids co-produced by the petroleum industry may not be suitable for use, a certain fraction may always be available that can be easily produced, collected and used for geothermal developments. Co-produced water is of particular significance in the Cooper-Eromanga Basin where a number of geothermal licences overlap with existing petroleum operations. A separate Waterlines document addresses the issue of co-produced water management.
Finally, this report identifies a number of guiding principles (see Section 6.3) that should be considered by state and territory governments to manage the potential impacts of geothermalrelated water use. Most fundamental is that geothermal companies should be treated under the same rules and regulations as other industrial water users, adequate allowance should be made in water allocation plans for those industrial uses, and project plans need to clearly and transparently communicate the water management objectives and regulatory regimes before they are approved.
NATIONAL WATER COMMISSION
— WATERLINES 71
Bibliography
AWR, 2005. www.water.gov.au/ (web page retrieved 14 March 2011).
Ayling BF 2007a, Electricity Generation from Geothermal Energy in Australia , Geoscience
Australia, Educational Factsheet GA10662 .
Ayling BF 2007b, Direct-use of Geothermal Energy: Opportunities for Australia , Geoscience
Australia, Educational Factsheet GA10660 .
Banks D 2008, An Introduction to Thermogeology: Ground Source Heating , Blackwell
Publishing.
Beardsmore GR and Hill AJ 2010, ‘Australia — Country Update’. Proceedings World
Geothermal Congress 2010, Bali, Indonesia , 25 –29 April 2010 .
Bertani R 2010, ‘Geothermal Power Generation in the World 2005–2010 Update Report’,
Proceedings World Geothermal Congress 2010, Bali, Indonesia , 25 –29 April 2010.
Brown D 2000, ‘A Hot Dry Rock geothermal energy concept utilizing supercritical CO
2
instead of water ’, in : Proceedings of the Twenty-Fifth Workshop on Geothermal Reservoir
Engineering, Stanford University , pp.233
–238.
Budd AR, Holgate FL, Gerner E and Ayling BF, 2007, ‘Geoscience Australia’s Onshore
Energy Security Program —the Geothermal Energy Project’, Proceedings, 3rd Hot
Rock Energy Conference, Adelaide August 2007 .
Bureau of Meteorology (BoM) 2009, ‘Average rainfall – Annual’. www.bom.gov.au/jsp/ncc/climate_averages/rainfall/index.jsp
(web page retrieved
25 February 2011).
Bureau of Meteorology 2011a, ‘La Niña continues to dominate in the Pacific’. ENSO Wrap-Up
Archive. Issued 19 January 2011.
Bureau of Meteorology 2011b, ‘Australia’s Water Storages’. http:water.bom.gov.au/waterstorage/awris/index.html
(web page retrieved
27 February 2011).
Burns KL, Creelman RA, Buckingham NW and Harrington HJ 1995, ‘Geothermal
Development in Australia ’. Proceedings World Geothermal Congress 1995,
Florence, Italy, 18 –31 May 1995 , pp. 45 –50.
Burns KL, Weber C, Perry J and Harrington HJ 2000, ‘Status of the geothermal industry in
Australia ’. Proceedings of the World Geothermal Congress 2000, Kyushu-Tohoku
Japan, May 28 –June 10 2000 , pp. 99 –108.
Cai C, Hu G, He H, Li J, Li J and Wu Y 2005, ‘Geochemical characteristics and origin of natural gas and thermochemical sulphate reduction in Ordovician carbonates in the
Ordos Basin, China ’. Journal of Petroleum Science & Engineering , 48 (3 –4), pp.
209 –226.
Capen E 1992, ‘Dealing with exploration uncertainties’, in : Steinmetz, R., (Ed.), The Business of Petroleum Exploration, Treatise of Petroleum Geology, Handbook of Petroleum
Geology, American Association of Petroleum Geologists , Tulsa, Oklahoma, pp. 29 –
62.
Chen D and Wyborn D 2009, ‘Habanero Field Tests in the Cooper Basin, Australia: A Proofof-Concept for EGS ’. GRC Transactions 33 , pp. 159 –164.
NATIONAL WATER COMMISSION
— WATERLINES 72
Chopra PN 2005 ‘Status of the Geothermal Industry in Australia, 2000–2005’. Proceedings
World Geothermal Congress 2005, Antalya, Turkey, 24 –29 April 2005 .
Cooper GT and Beardsmore GR 2008, ‘Geothermal systems assessment: understanding risks in geothermal exploration in Australia ’. Proceedings of the PESA Eastern
Australasian Basins Symposium III, Sydney 14 –17 September 2008 , pp. 411 –420.
Cordon E and Driscoll JP 2008, ‘Full Life-Cycle Water Requirements for Deep Geothermal
Energy Developments in South Australia ’. Department of Primary Industries and
Resources (South Australia) and the Australian School of Petroleum.
Cull JP 1979, ‘Heat-flow and geothermal energy prospects in the Otway Basin, southeastern
Australia ’. Search 10 , pp. 429 –433.
Cull JP 1982, ‘An Appraisal of Australian Heat Flow Data’. BMR Journal of Australian Geology and Geophysics , 7 (1), pp.11
–21.
Curtice RJ and Dalrymple ED 2004, ‘Just the cost of doing business’. World Oil , pp. 77 –78.
DECCW 2010, ‘State of the catchments – Sydney Metropolitan Area, Groundwater’.
DNRM 2005a, ‘Great Artesian Basin Draft Water Resource Plan: Overview, Report and Draft
Plan ’. Queensland Department of Natural Resources and Mines, Brisbane.
DPI 2010, ‘Geothermal energy in Victoria – Landholder information’. Department of Primary
Industries, Victoria.
DRET 2008a, Australian Geothermal Industry Development Framework . Department of
Resources, Energy and Tourism.
DRET 2008b, Australian Geothermal Industry Technology Roadmap . Department of
Resources, Energy and Tourism.
DRET 2011, Geothermal Drilling Program. http://www.ret.gov.au/energy/clean/acre/gdp/Pages/default.aspx
(web page retrieved 25 January 2012).
Driscoll, J., 2006. Geothermal prospectivity of Onshore Victoria, Australia. Victorian Initiative for Minerals and Petroleum Report 85 , Department of Primary Industries.
DSE, 2009. Melbourne Groundwater Technical Atlas. www.ourwater.vic.gov.au/monitoring/groundwater/general/melbourne-groundwaterdirectory/technical-atlas (web page retrieved 27 January 2011).
DWLBC 2010, Central Adelaide Groundwater Area: Prescription of Groundwater Resources.
Fact Sheet 79.
EA 2009, Ground source heating and cooling pumps – state of play and future trends.
Ergon Energy 2008. ‘Birdsville Organic Rankine Cycle Geothermal Power Station’. 2pp. www.ergon.com.au/__data/assets/pdf_file/0008/4967/Birdsville-GeoThermal-ORC-
Power-brochure.pdf
(webpage retrieved 7 November 2011).
European Heat Pump Association 2008, European Heat Pump Statistics Outlook 2008 .
Ferguson G and Woodbury AD 2005, ‘Thermal sustainability of groundwater-source cooling in
Winnipeg, Manitoba ’. Canadian Geotechnical Journal , 42 (5), pp. 1290 –1301.
Freeze RA and Cherry JA 1979, Groundwater . Prentice Hall, New Jersey.
NATIONAL WATER COMMISSION
— WATERLINES 73
Fry V 2009, ‘Lessons from London: Regulation of open loop ground source heat pumps in
Central London ’. Quarterly Journal of Engineering Geology and Hydrogeology , 42 , pp. 325 –334.
Gaffney, Cline & Associates 1988, ‘Investigations of the causes behind the Della 1 blow-out’.
Geodynamics 2009a, Stage 1 - Proof of Concept Complete . ASX release 31 March 2009.
Geodynamics 2009b, Habanero 3 well incident investigation . ASX release 21 August 2009.
Geodynamics 2010, Annual Report 2009-2010 . ASX release 22 October 2010.
Geoscience Australia 2004, Meeberrie Earthquake . Educational Factsheet GA10001 .
Geothermal Education Office 2000, http://geothermal.marin.org/ (web page retrieved 10
January 2011).
Graeber FM, Houseman GA and Greenhalgh SA 2002, ‘Regional Teleseismic Tomography of the Western Lachlan Orogen and the Newer Volcanic Province, Southeast
Australia’. Geophysics Journal International 149 , pp. 249 –266.
Greenearth Energy 2011, http://www.greenearthenergy.com.au/geothermal/ (web page retrieved 21 January 2011).
Headon J, Banks D, Waters AJ and Robinson VK 2009, ‘Regional distribution of ground temperature in the Chalk aquifer of London, UK’. Quarterly Journal of Engineering
Geology and Hydrogeology , 42 , pp. 313 –323.
Hot Dry Rocks 2011, ‘Heat flow map of Australia’. Unpublished.
Jensen T 2010 , Water issues in jurisdictional planning for mining: an overview of current practice , Waterlines Report Series No 29, National Water Commission, Canberra.
King RL, Ford AJ, Stanley DR, Kenley PR and Cecil MK 1987, Geothermal Resources of
Victoria . Department of Industry Technology and Resources and Victorian Solar
Energy Council. Melbourne, Australia.
Kiyosu Y, Asada N and Yoshida Y 1992, ‘Origin of light hydrocarbon gases from the
Matsukawa geothermal are a in Japan’. Chemical Geology , 94 (4), pp. 321 –329.
Kollmorgen A, Little P, Hostetler S and Griffith H 2007, ‘A baseline assessment of water resources for the National Water Initiative Level 2 Assessment —Water Availability
Theme, National Perspective’. Australian Water Resources 2005 . Canberra.
Land and Water Biodiversity Committee 2003, ‘Minimum construction requirements for water bores in Australia’. September 2003. ISBN 1 9209 2009 9. available for download from: www.iah.org.au/pdfs/mcrwba.pdf
.
Lund JW, Gawell K, Boyd TL and Jennejohn D 2010, ‘The United States of America Country
Update 2010 ’. Proceedings World Geothermal Congress 2010, Bali, Indonesia , 25 –
29 April 2010.
McLaren S, Sandiford M, Hand M, Neumann N, Wyborn L and Bastrakova I 2003, ‘Chapter
12 —The Hot Southern Continent: Heat Flow and Heat Production in Australian
Proterozoic Terranes ’. Geological Society of Australia Special Publication 22 , pp.
151 –161.
McLennan Magasanik Associates Pty Ltd 2008, ‘Installed capacity and generation from geothermal sources by 2020 ’.
NATIONAL WATER COMMISSION
— WATERLINES 74
Magoon LB and Dow WG 1994. ‘The Petroleum System’, in: Magoon, L.B. and Dow, W.G.
(Eds), The Petroleum System –from source to trap , American Association of
Petroleum Geologists, Memoir 60 , pp. 3 –24.
Mil-Tech UK Ltd 2006, ‘Assessment of water requirement and storage aspects for a development of a deep Hot Dry Rock (HDR) system Olympic Dam, South Australia ’.
Report prepared for Green Rock Energy Ltd..
Mortimer L 2010, ‘Geothermal flow rates in Australia—what can we expect and how we can mitigate pre-drill risks ’. PESA News Resources , 105 , pp. 66 –67.
Mortimer, L. and Cooper, G.T., 2010. Greening Coal Seam Gas (CSG) Through Geothermal
Synergies: Using Co-produced Water For Renewable Energy Production. PESA
News Resources , 108 . 75 –78.
Nahm GY 1977, Groundwater . Department of Minerals and Energy, Victoria.
National Water Commission 2008, ‘Groundwater position statement’. National Water
Commission, Canberra.
National Water Commission 2009, ‘Australian Water Reform 2009: Second biennial assessment of progress in implementation of the National Water Initiative ’, NWC,
Canberra.
National Water Commission 2011, The National Water Initiative – securing Australia’s water future: 2011 assessment, NWC, Canberra.
Neumann NL, Sandiford M and Foden J 2000, ‘Regional geochemistry and continental heat flow: implications for the origin of the South Australian heat flow anomaly ’. Earth and
Planetary Science Letters 183 , pp. 107 –120.
NZS 2403:1991, ‘Code of Practice for Deep Geothermal Wells’. Standards New Zealand.
Nott R 2004, Groundwater occurrence in the Port Phillip Basin . Department of Sustainability and Environment Groundwater Notes #8.
NRW 2007, ‘Brisbane aquifer moratorium’. http://www.simonfinnmp.com/_dbase_upl/MorSheet.pdf
(web page retrieved 10
January 2011)
Panax Geothermal 2010, ‘Salamander-1 Well Bottom Hole Temperature Increases to
171.4 °C’. ASX release 13 May 2010. 1pp.
Peninsula Hot Springs, 2009. The Peninsula Springs Vision. www.peninsulahotsprings.com/uploads/files/PHSevolutionSPRING09web.pdf
(web page retrieved 10 January 2011)
Petratherm 2006, ‘Petratherm signs MoU with Heathgate Resources for supply of electricity to
Beverley Uranium Mine ’. ASX release 1 November 2006.
Petratherm 2010, Paralana Update . ASX release 24 March 2010.
Petratherm, 2011. Paralana Fracture Stimulation Works Successfully Completed . ASX release 19 July 2011.
Pruess K 2006, ‘Enhanced geothermal systems (EGS) using CO
2
as working fluid —A novel approach for generating renewable energy with simultaneous sequestration of carbon ’. Geothermics , 35 , pp. 351 –367.
NATIONAL WATER COMMISSION
— WATERLINES 75
Radke BM, Ferguson J, Cresswell RG, Ransley TR and Habermehl MA 2000,
‘Hydrochemistry and implied hydrodynamics of the Cadna-owie–Hooray Aquifer,
Great Artesian Basin, Australia ’. Bureau of Rural Sciences , Canberra.
Rose PR 1992, ‘Chance of success and its use in petroleum exploration’, in : Steinmetz R,
(ed.), The Business of Petroleum Exploration, Treatise of Petroleum Geology,
Handbook of Petroleum Geology, American Association of Petroleum Geologists ,
Tulsa, Oklahoma, pp. 71 –86.
RPS Aquaterra 2011, ‘Adelaide Plains Numerical Groundwater Model (AP2011)’. Report to
Department for Water (planned to publish December 2011).
Sanjuan B, Pinault JL, Rose P, Gérard A, Brach M, Braibant G, Crouzet C, Foucher J-C,
Gautier A and Touzelet S 2006, ‘Tracer testing of the geothermal heat exchanger at
Soultz-sousForêts (France) between 2000 and 2005’. Geothermics , 36 , pp. 622 –
653.
Saygin E and Kennett BLN 2010, ‘Ambient Seismic Noise Tomography of Australian
Continent ’. Tectonophysics 481 , pp. 116 –125.
Schellschmidt R, Sanner B, Pester S and Schulz R 2010, ‘Geothermal Energy Use in
Germany ’. Proceedings World Geothermal Congress 2010, Bali, Indonesia , 25 –29
April 2010
Sheard MJ 1990, ‘A Guide to Quaternary Volcanoes in the Lower South-East of South
Australia ’. Mines and Energy Review, South Australia 157 , pp. 40 –50.
Smart A and Aspinall A 2009, Water and the electricity generation industry , Waterlines Report
Series No. 18, National Water Commission, Canberra.
Song Y, Kim H and Jong Lee T 2010, ‘Geothermal Development in Korea: Country Update
2005-2010 ’. Proceedings World Geothermal Congress 2010, Bali, Indonesia , 25 –29
April 2010
South Australian Arid Lands Natural Resources Management Board 2009, Water Allocation
Plan for the Far North Prescribed Wells Area . Government of South Australia.
February 2009.
Sustainability Victoria 2007, The heat is on at Warrnambool . Press release 9 November 2007.
Tester JW, Anderson BJ, Batchelor AS, Blackwell DD, DiPippo R, Drake EM, Garnish J,
Livesay B, Moore MC, Nichols K, Petty S, Toksöz MN and Veatch RW, 2006, The
Future of Geothermal Energy – Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century , MIT Press, pp. 1-9; 2-29; 4-1 –4-52.
Younger PL 2006, ‘Potential pitfalls for water resources of unregulated development of ground source heating resources ’. Proceedings of the Annual Conference of the
Chartered Institute of Water & Environmental Management .
NATIONAL WATER COMMISSION
— WATERLINES 76
