Hot Dry Rocks Pty Ltd
Geothermal Energy Consultants
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South Yarra, Vic 3141
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Full Life-Cycle Water Requirements for Deep Geothermal
Energy Developments in South
Australia
ABN: 12 114 617 622
SERVICES
Exploration
Rock Property Measurements
Project Development
Portfolio Management
Grant Applications
A Report Prepared for the Department of
Primary Industries and Resources (South
Australia) and the Australian School of
Petroleum
Tied Grant 4.5
E. Cordon and J.P. Driscoll
November 2008
i
Executive Summary
Geothermal exploration and development projects are underway in many parts of
South Australia, all of which require water resources. This report has been collated to
understand the full life cycle water requirements of a deep geothermal energy
development in South Australia. This is particularly important as much of the State is
arid or semi-arid and drought conditions have prevailed in many areas recently. The
focus of this report will be the three major stages of a deep geothermal energy
project: exploration, development and production.
There are two main forms of geothermal energy in South Australia which present
different technical and economic opportunities and challenges, known as Engineered
Geothermal Systems [EGS] and Hot Sedimentary Aquifers [HSA]. For both EGS and
HSA resources, several key factors are required to make a viable geothermal
system: heat source, reservoir, thermal insulation, working fluid and stress regime
impact.
Geothermal exploration aims to make an assessment of the geothermal potential of a
site by assessing the likelihood of each of the main components of a geothermal
system being present, namely: the availability of water, the likelihood of in situ
permeable aquifers of rock unit susceptible to artificial permeability enhancement;
and the likelihood of elevated temperatures at drillable depth. Two exploration
companies provided details of water usage from their respective shallow thermal
gradient drilling programs, estimating 50–85 kl for a single shallow, ‘heat flow’ hole.
Once a company has achieved a level of confidence in defining their potential
geothermal resource, deep geothermal resource drilling is planned and marks the
beginning of the development stage as it is currently accepted that the first deep
exploration well is converted into either an injection well or production well.
In this particular study, the development stage is predicted to require 276,265 m3 of
water based on the assumption that an EGS module consists of one injector [1st well]
and two producers [2nd and 3rd well] of 8.5” open-hole diameter. Wells are typically
drilled to a depth of 3,000 to 5,000 m in South Australia with an assumed separation
between wells being about 600 m.
As there are very few operational EGS in the world, hydrothermal projects are
generally used in comparison to provide an estimate water usage for the production
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phase of geothermal energy projects. In a typical, successful hydrothermal reservoir,
wells can produce a minimum of 5 MW of net electric power through a combination of
high temperatures and high flow. A review of the Soultz EGS field project was
included with particular reference to water usage where available.
Water losses were noted as an important aspect of developing a geothermal energy
project particularly in areas of restricted water availability. Several EGS field projects
carried out throughout the world were used to highlight the water losses issue.
An atlas of water resources in South Australia was compiled to describe their nature,
quality and availability. The atlas included surface water (river flows and catchments,
streams); groundwater, the Great Artesian Basin and town water supplies/reticulated
mains water (water storage, pipelines). Additionally, it was noted in some areas of oil
and gas development (such as the Cooper Basin in South Australia), high
temperatures are coupled with high volumes of water produced as a by-product of
hydrocarbon production. Although some fluid produced from the hydrocarbon
industry may not be suitable for use, there is the notion of an absolute minimum of
fluid that can easily be produced, collected and used as feedstock for an existing
reservoirs or new EGS developments. Further assessment of these water sources in
the vicinity hydrocarbon operations could, therefore, prove beneficial for potential
geothermal energy projects in such areas.
The report finally addresses the local procedures on how to access water resources.
Drought conditions in recent times in South Australia have led to a response from the
South Australian State Government to ensure available water resources are used in
an ecologically sustainable manner.
By identifying State water resources as being subjected to increasing use pressures,
the Water Resources Act 1997 allows the area to be proclaimed, for users to be
licensed, and requires the implementation of water allocation plans to help regulate
future development. Further regulatory measures put in place to protect water
resources include the National Water Initiative, water licensing arrangements and
regional water resource assessments in South Australia.
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Suggested recommendations for more accurate calculations of water requirements
are through the following steps:
Further research individual companies’ experience and water usage in recent
exploration drilling programmes;
Develop spreadsheet of volumes of water required for a range of currently
operating EGS production plants;
Develop software tools for calculating water requirements for specific stages of
geothermal projects;
Further investigate the suitability of co-produced water from hydrocarbon
operations for geothermal projects in proximal areas’
Disclaimer
The information and opinions in this report have been generated to the best ability of the author, and Hot Dry
Rocks Pty Ltd hope they may be of assistance to you. However, neither the author nor any other employee of
Hot Dry Rocks Pty Ltd guarantees that the report is without flaw or is wholly appropriate for your particular
purposes, and therefore we disclaim all liability for any error, loss or other consequence which may arise from
you relying on any information in this publication. A number of South Australian Government bodies and other
third parties provided some data presented in this report. The data are assumed to be an accurate transcription
from original documents but Hot Dry Rocks Pty Ltd makes no guarantee that this is truly the case.
Copyright
All data, information, text and figures within this commissioned report are protected under the Copyright Act
1968 (Section 193). Hot Dry Rocks Pty Ltd is to be duly and correctly attributed for such if portions of this report is reproduced in other forms. All concepts, ideas and other IP expressed in this report remain the property of
Hot Dry Rocks Pty Ltd.
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Table of Contents
1.0 ITRODUCTIO ........................................................................................................................................... 2
1.1 GEOTHERMAL ENERGY ................................................................................................................................. 2
1.1.1 Engineered Geothermal System (EGS) ................................................................................................. 3
1.1.2 Hot Sedimentary Aquifers (HSA) .......................................................................................................... 4
1.2 HEAT SOURCE ............................................................................................................................................... 4
1.3 THERMAL INSULATION .................................................................................................................................. 5
1.4 RESERVOIR .................................................................................................................................................... 5
1.5 WORKING FLUID ........................................................................................................................................... 6
2.0 STAGES OF A DEEP GEOTHERMAL PROJECT ................................................................................... 8
2.1 EXPLORATION ............................................................................................................................................... 8
2.1.1 Geothermal Systems Assessment .......................................................................................................... 8
2.1.2 Shallow ‘heat flow’ drilling .................................................................................................................. 9
2.1.3 Deep geothermal resource drilling ..................................................................................................... 10
2.2 DEVELOPMENT ............................................................................................................................................ 11
2.2.1 Drilling of the 1st well ......................................................................................................................... 11
2.2.2 Collection of primary in situ hydraulic permeability data in the 1st well ........................................... 12
2.2.3 Stimulation or creation of a reservoir in the 1st well .......................................................................... 13
2.2.4 Planning, drilling and stimulation of the 2nd well............................................................................... 14
2.2.5 Evaluation of the stimulated reservoir of the 2nd well ........................................................................ 17
2.2.6 Planning, drilling and stimulation of the 3rd well ............................................................................... 19
2.2.7 Evaluation of the stimulated reservoir of the 3rd well ......................................................................... 21
2.3 PRODUCTION ............................................................................................................................................... 23
2.3.1 EGS vs. hydrothermal reservoirs ........................................................................................................ 23
2.3.2 Water Requirement ............................................................................................................................. 23
2.3.3 Case study of an EGS field project—Soultz ........................................................................................ 24
2.3.4 Water losses ........................................................................................................................................ 26
3.0 ATLAS OF AVAILABLE WATER RESOURCES I SOUTH AUSTRALIA ...................................... 28
3.1 OVERVIEW .................................................................................................................................................. 28
3.2 SURFACE WATER IN SOUTH AUSTRALIA ..................................................................................................... 28
3.2.1 River flows and catchments ................................................................................................................ 29
3.2.2 Streams ............................................................................................................................................... 29
3.2.3 Development of surface water ............................................................................................................ 29
3.2.4 Available resource .............................................................................................................................. 30
3.3 GROUNDWATER IN SOUTH AUSTRALIA ....................................................................................................... 31
3.4 GREAT ARTESIAN BASIN ............................................................................................................................. 33
3.4.1 Overview ............................................................................................................................................. 33
3.4.2 Artesian aquifers ................................................................................................................................ 34
3.4.3 Free flowing bores .............................................................................................................................. 34
3.4.4 GAB springs........................................................................................................................................ 35
3.4.5 Capped bores ...................................................................................................................................... 35
3.5 COPRODUCED FLUIDS: ‘CONVENTIONAL’ GEOTHERMAL DEVELOPMENT IN HYDROCARBON FIELDS ......... 36
4.0 REGULATIOS FOR ACCESS TO WATER RESOURCES ................................................................. 38
4.1 REGULATORY FRAMEWORK ........................................................................................................................ 38
4.1.1 Introduction ........................................................................................................................................ 38
4.1.2 9ational Water Initiative .................................................................................................................... 38
4.1.3 Regional water resource assessments in South Australia ................................................................... 39
4.1.4 9atural Resources Management Act 2004 ......................................................................................... 39
4.1.5 Water licensing arrangements ............................................................................................................ 41
4.2 ENVIRONMENTAL WATER REQUIREMENTS ................................................................................................. 42
5.0 RECOMMEDATIOS .............................................................................................................................. 43
6.0 ACKOWLEDGEMETS .......................................................................................................................... 44
7.0 REFERECES .............................................................................................................................................. 45
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1.0 Introduction
A heightened awareness of the contributing factors to climate change and increased
pressure on governments to enhance their country’s energy security has raised the
profile of renewable energy sources around the world. In Australia, geothermal
energy is becoming an increasingly valid option due to its potential to generate large
quantities of clean, renewable energy. As a result, a number of geothermal
exploration and development projects are underway in South Australia, an area of
the country that has seen a particularly high uptake of work in the field.
Although geothermal energy may pose a reasonable solution to address the issues
mentioned above, it should not be considered in isolation from other local constraints.
As much of South Australia’s climate is defined as arid (annual rainfall <250 mm) or
semi-arid (annual rainfall 250–500 mm), water remains a valuable commodity. It is
therefore essential that an investigation into the water required by geothermal energy
projects be carried out.
The following report aims to quantify the volumes and rates of water required at
successive stages of exploration, development and production of geothermal
resources.
1.1 Geothermal Energy
Geothermal energy is the energy in form of heat beneath the surface of the solid
Earth. This heat is the result of the planet’s primordial development (~20% of the
total heat budget) and the radioactive decay of naturally occurring potassium, thorium
and uranium isotopes, which comprises the remaining ~80% of the total heat budget.
The average rate of heat flow through the crust is approximately 59 mW/m2 (Tester
et al, 2006).
Heat moves from the Earth’s interior toward the surface as the result of a number of
heat transfer mechanisms. For instance, the heat melts nearby 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 remains within the crust
as a hot rock package. Surface manifestations of heat flow include volcanoes,
fumeroles, hot springs and geysers.
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The accessible geothermal energy in South Australia exists in two main forms, which
present different technical and economic opportunities and challenges; Engineered
Geothermal Systems (EGS) and Hot Sedimentary Aquifers (HSA). Both EGS and
HSA resources differ from ‘conventional’ geothermal energy systems which are
based largely on magmatic related heat sources and naturally convective fluid systems.
Whilst the main economic driver for the development of EGS and HSA resources is
the production of electricity, there is an increasing focus on cascading systems,
where the heat is used for applications after electricity production (such as spaceheating and agricultural purposes).
1.1.1 Engineered Geothermal Systems (EGS)
EGS systems are variously known as hot rock (HR), hot fractured rock (HFR), hot
wet rock (HWR) or hot dry rock (HDR) resources. EGS resources are characterised
by predominantly conductive heat transfer.
A viable EGS resource requires four fundamental prerequisites:
1. A heat source that provides elevated thermal energy density within the Earth
(e.g. thermally anomalous granites; radioactive iron oxides). In effect, the
heat source must generate heat faster than it can dissipate, thus causing the
temperature of the rocks to increase until the flow of heat out of the rocks
reaches equilibrium with the rate of generation.
2. 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).
3. A reservoir, otherwise defined as a volume of space, within the rock such as
connected fractures or pores through which fluid can circulate. The reservoir
can be either naturally occurring or artificially engineered.
4. A carrier, or working fluid, to extract heat from the subsurface geothermal
system 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.
An assessment of the geothermal potential of a site can be broken down into an assessment of the likelihood of each of the components of a geothermal system being
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present. Only the heat source needs to occur naturally as, given favourable conditions, the reservoir and fluid can be artificially introduced. For example, geothermal
fluids extracted to drive a turbine in a geothermal power plant can be re-injected into
the reservoir after use.
The Landau EGS project in Germany began operations in November 2007 and is
regarded as the first commercial power plant of its kind. A single extraction bore
produces 3 MW of electricity using Organic Ranking 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 3,000 m. The waste water is then fed through a district heating
system before being returned underground via an injection well in order to recharge
the subsurface plumbing system. Expansion of the Landau EGS project is planned
with the addition of a further 5 MW generating capacity.
1.1.2 Hot Sedimentary Aquifers (HSA)
A HSA geothermal system can be described as a type of hydrothermal system, but a
HSA is usually not associated with ‘conventional’ geothermal resources such as
those currently exploited in volcanic provinces such as New Zealand, Indonesia and
the Philippines. An example of a HSA play is the Otway Basin, which straddles the
South Australian / Victorian state boundary. Several companies are seeking to
produce hot water from deeply buried, high yielding aquifers in the basal sections of
this sedimentary basin.
1.2 Heat Source
The Proterozoic rocks of South Australia generate significantly more heat than most
similarly aged cratonic rocks worldwide. This has been attributed to the abundance of
granites which have anomalously high concentrations of radioactive thorium, uranium
and potassium. 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 series of ‘hotspots’, rather than one continuous
anomaly.
Heat flow of 92 ± 3 mWm-2 has been reported in the Mount Gambier region of South
Australia, with regional averages exceeding 80 mWm-2 (Cull, 1979). Historical heat
flow datasets from western Victoria report heat flow values of 110 mWm-2 and
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114 mWm-2 for Stawell and Castlemaine, respectively (Sass, 1964). Purss & Cull
(2001) undertook further heat flow studies at Horsham and Warracknabeal and reported values of 89.8 ± 7.3 mWm-2 and 97.0 ± 8.7 mWm-2, respectively. They reported that whilst the values are significantly less than those measured previously by
Sass (1964), they remain high by global standards.
1.3 Thermal Insulation
For both EGS and HSA systems, a thick, low thermal conductivity overlying
sequence such as coals, carbonaceous shales or fine-grained siltstones is preferable
to act as an insulatory blanket to conductive heat. Low conductivity sediments are
deposited within basins throughout South Australia. In the Otway Basin, the
regionally extensive Cretaceous Eumeralla Formation provides the insulatory
lithology to the Pretty Hill Formation; whilst fine-grained sediments of Adelaidean age
insulate large swathes of the state north of Adelaide, including many of Torrens
Energy and Petratherm’s permits. Further north, the Cooper Basin has thick
packages of Palaeozoic to Mesozoic carbonaceous siltstones, shales and coal.
1.4 Reservoir
Historically, crystalline basement, and in particular granitic basement, has been the
preferred medium for engineered geothermal 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.
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. Natural internal stresses that operate at depth
within the granite cause the separated rock faces to slip 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.
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The distribution of joints with depth and their azimuth is very critical. The orientation
of the joints in relation to the stress field is also very important, as this 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. If pressurisation up to, near, or above, the minimum
stress at the depth of the reservoir is necessary to open fractures and allow the required fluid volume to pass, the likelihood is high that runaway growth of the stimulated rock volume will occur, leading to an undesirable increase in water loss.
For a 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 >3,000 m in order to achieve
required temperature.
The South Australian Otway Basin contains several high-yielding aquifers at various
depths. The deepest is the Early Cretaceous Pretty Hill Formation (part of the Crayfish Subgroup), which was deposited within localised depocentres during the initial
rifting stage of basin development. The asymmetric nature of these sub-basins led to
the deposition of thick sandstone/conglomeratic lithofacies adjacent to the bounding
fault systems. Such areas potentially have higher porosity and are regarded as favourable geothermal targets.
1.5 Working Fluid
The working fluid is the medium through which heat can be extracted from the subsurface realm and brought to surface, otherwise referred to as a heat transmission
fluid. Most EGS operations plan on utilising water for this purpose but potential other
mediums include supercritical CO2 (Brown, 2000; Pruess, 2006).
In order to commercially exploit a HSA resource, detailed data on the temperature
and water-flow characteristics of the 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.
HSA systems utilise water at temperatures typically between 100°C and 150°C.
Water at this temperature will not flash spontaneously into steam at sufficient
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pressures to turn electricity generator turbines. The geothermal heat contained within
the water (the ‘primary fluid’) is therefore transferred to another medium with a lower
boiling-point, termed the ‘working’ or ‘binary’ fluid. The high-pressure vapour of the
binary fluid can then be used to turn a turbine. This is referred to as binary cycle
electricity generation. The primary fluid and working fluid are confined to separate
closed loops throughout the process, so there are few or no emissions to the
atmosphere.
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2.0 Stages of a Deep Geothermal Project
The following sections discuss the water requirements during the three major stages
of a deep geothermal energy project: exploration, development and production.
2.1 Exploration
Geothermal exploration aims to locate geological systems capable of producing fluid
at sufficient temperature to generate electricity. Exploring for geothermal resources in
a setting with conductive heat flow involves identifying heat sources, thermal insulation, potential reservoir units and a fluid to transfer the heat. Australia has very little
surface evidence of geothermal energy, and is generally a continent free of surface
emissions of geothermal heat. Geothermal exploration in Australia is therefore focussed on identifying those areas where conductive heat flow results in elevated temperatures at accessible depth. Identifying those locations requires a different exploration strategy to that employed for convective geothermal systems (e.g. volcanic areas).
The general progression of an exploration program includes the following steps:
1. Desktop geothermal systems assessment;
2. Shallow ‘heat flow’ drilling;
3. Deep geothermal resource drilling
The following sections discuss the water requirement of each of these steps.
2.1.1 Geothermal Systems Assessment
An initial desktop geothermal systems assessment is carried out during the exploration phase of a geothermal energy project to assess the likelihood of each of the key
components of a geothermal system being present. These can be broken down into
the following components:
The likelihood of elevated temperatures at drillable depth,
The likelihood of in situ permeable aquifers or a rock unit susceptible to
artificial permeability enhancement; and
The availability of water—the medium by which heat is brought to the surface
in a geothermal operation is usually water. For an EGS development the
system will need to be charged with enough water to fill the reservoir volume.
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An assessment of water availability should also include any special permission
requirements for its extraction. This issue is dealt with in Section 4 of this
report.
From this assessment, a drilling program is designed to ascertain further information
about the area’s geothermal energy resource potential.
The following sections discuss the water requirements of these drilling stages and
include comments supplied by exploration companies regarding their experience during recent drilling exploration programmes.
2.1.2 Shallow ‘heat flow’ drilling
Using the outcomes identified in a geothermal systems assessment, a rotary mud
and/or diamond drilling program is designed and comprises a series of shallow ‘heat
flow’ holes. Such ‘heat flow’ holes are used to further ascertain local heat flow and
other geological information of the area.
The following companies have kindly provided details of their water usage
experience when drilling shallow ‘heat flow’ holes in South Australia.
Company A (Petratherm Limited)
Phase 1: Paralana 1B drilled to 492 m and Callabonna drilled to 693.5 m
This was a rotary mud drilling program carried out at the Paralana and Callabonna
project areas. In both project areas three sumps were dug: a returns sump (approximately 5 x 3 x 2.5 m), a middle settling sump (3 x 3 x 2.5 m), and an uptake sump (3
x 3 x 2.5 m). All sumps were filled with water from local shallow bores prior to drilling
(total volume approximately 82.5 kl). Initially, they required regular topping up (approximately 8–16 kl per 24 hour period). Once the ponds were better sealed, water
requirements dropped back to around 2–8 kl per 24 hours during drilling.
Phase 2: Deepening of Paralana 1B DW1 drilled from 492 to 1807.5 m
This was the diamond drilling program at Paralana (diamond tail). Two sumps were
used, both approximately 3 x 3 x 3 m (total volume 54 kl). Daily water losses
amounted to approximately 2–4 kl as a result of both drilling and sump losses. Most
water was lost either on the surface of the sumps due to evaporation or water filtrating out of the sumps as very little water was lost down hole.
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In both drilling phases, the main logistical issue faced was the trucking or piping of
water from local bores. As stock was using some of the bores, this meant careful
monitoring was required to ensure sufficient supplies for stock (i.e. the need to rotate
bore usage).
Company B (name withheld by request)
During Company B’s shallow ‘heat flow’ drilling programme, several factors were
considered regarding water usage. These included:
The tracks used for carting water were sensitive to the constant truck traffic,
as they would soon turn to bulldust. The area was in drought and was only
serviced by bores and windmills. Subsequently, the company undertook to drill
water bores at each exploration well, from which water was then used for
drilling rotary mud and diamond wells. A submersible pump was put in the
water bore and water was pumped straight into the adjacent sump for the
exploration well.
As the water from the bores was pumped and used as required, it is difficult to
estimate the amount of water used during the drilling program. Additionally,
the company encountered artesian flow after the precollars, and from then on
they did not need to pump at all as the sumps were naturally filling with
artesian water. As a conservative estimate, 50 kl of water was used for the
most recent well.
2.1.3 Deep geothermal resource drilling
Once a company has reached a level of confidence in defining its potential
geothermal resource, a ‘deep’ well is drilled to a typical depth of 3–5 km. This marks
the beginning of the development stage of the geothermal resource.
Throughout 2009, Petratherm—in joint venture with Beach Petroleum—plans to drill
two wells to a depth of about 4 km to confirm the expected thermal resource, establish an underground heat exchanger at Paralana and undertake circulation tests.
Four local water bores are currently being drilled at the project site to meet drilling
requirements. Whilst the water bores are targeting shallow, non-prescribed aquifers
rather than the deeper prescribed artesian water, they still require water permits.
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2.2 Development
The source of information for much of this section is Mil-Tech UK Ltd (2006). The water requirements quoted in this section assume that an EGS module consists of one
injection well (1st well) and two production wells (2nd and 3rd well) of 8.5” open-hole
diameter. Although EGS developments are in their infancy, it is currently accepted
that the first deep exploration well will be converted into either an injection well or
production well. In South Australia, deep geothermal wells are generally being drilled
to a depth of around 3,000–5,000 m. A separation of 600 m between wells has been
used in modelling studies, which indicate that this distance will be necessary to create sufficient volume heat exchangers to last around 20 years. It is also assumed that
the stress regime at depth will be such that the shearing on natural joints will occur
when the overpressure in the joint is in the range of 2–5 MPa (Pine and Batchelor,
1984; Baria et. al, 1985).
2.2.1 Drilling of the 1st well
There is a general tendency to use brine for drilling deep hot granitic rocks. One of
the main reasons is that the aperture of the joints at depth can be very small and
easily plugged if drilling mud based on bentonite is used. If bentonite-based mud is
used then it may be necessary to vent the well a number of times after completion to
clear the joints of the mud cake and plugging material.
A number of mud pools (4 or 5) of around 400 m3 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 granite 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. Coarser particles that escape the shaker tables are usually
deposited within the first mud pool, thus this is designed in such a way that an
excavator can remove these particles on a regular basis.
The establishment of five mud pools will give a storage capacity of around 2,000 m3,
excluding evaporation losses and losses in the formation. Once the 1st well is
completed, development progresses in a series of stages. Each stage has its own
water requirements. These are described in detail in the following sections.
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2.2.2 Collection of primary in situ hydraulic permeability data in the 1st well
Once geophysical logs have been run, small scale injection tests are used to assess
the undisturbed hydraulic properties in the open section of the well. The quantity of
water and the pressure required will depend on the state of existing flowing joints and
the tightness of the formation. A short description and an estimation of the water
requirement for these tests follows.
Stage 1: slug test in the 1st well
By definition, a ‘slug test’ is the response of a well-aquifer system to an
instantaneous change of the water level, i.e. a response to an impulse in flow. The
impulse excitation can be achieved by several methods, such as the sudden
withdrawal of a weighted float or by the rapid injection of a small volume of water.
The water level in the well must be at least 30 m or deeper below the surface, to
allow the filling of the well. A sensitive down-hole pressure transducer is deployed
below the water level. The well is filled at around 10 l/s until the height of the water
has increased by 15–20 m. After the injection, the pressure decay in the well is
monitored until it reaches a steady state. Additional tests can be carried out with
increasing heights of water columns to 25 m and 35 m, to confirm or check if the
initial pressure influences the response. These tests are important to assess the
initial hydraulic condition of the open-hole section. [Note: this is only possible in ‘dry’
holes. Habanero overpressured rocks do not suit a test such as this].
The slug test also gives information required to design the subsequent low rate
injection test (Stage 3 below). The total amount of water used is negligible, in the
range 2–5 m3.
Stage 2: production test in the 1st well
A production test of formation fluid yields important information about the pressure
and temperature conditions deep in the well where any future heat exchanger may
be located. The fluid chemistry and the gas content are important parameters to
design a pilot plant in such a way that scaling and corrosion can be minimised.
A well can be put on production by using a buoyancy effect or a down-hole pump. A
down-hole submersible pump is preferable where possible. A submersible pump can
be deployed at a depth of around 100–150 m.
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Depending on the outcome of the slug test, it is probable that the well could produce
on the order of one cubic metre per hour, which may be sufficient to obtain several
well-bore volumes of fluid within a few weeks. A down-hole pressure gauge, gas
sampling at the wellhead and a surface flowmeter would provide further information
on the draw-down characteristics of the well.
If a production test is planned, then it would be necessary to have a water storage
facility on site to store the recovered in situ fluid. A storage facility of around 450 m3
would be necessary if a well provides three bore-volumes of in situ fluid from a 4,000
m deep hole with 8.5” nominal diameter.
Stage 3: low rate injection tests in the 1st well
The main objective of a ‘low rate injection test’ is to determine the hydraulic
properties of the un-stimulated open-hole section of the well. Water is injected under
low pressure into a packed-off section at the base of the bore.
Three or four injection tests with flow rates from around 0.2 l/s to 0.6 l/s are carried
out. Each injection lasts for around 8–10 hours, followed by shut-in periods of 12–14
hours. Wellhead or (preferably) down-hole (close to the casing shoe) pressure is
monitored to determine the actual pressure in the open hole section. Approximately
45–50 m3 of water is required to carry out these tests.
2.2.3 Stimulation or creation of a reservoir in the 1st well
The objective of stimulation is to initiate shearing of joints and thus develop an EGS
reservoir (sometimes called an ‘underground heat exchanger’) at the required depth.
Normally a pre-stimulation test is carried out to ensure all wellhead sensors, seismic
systems, down-hole PTF (pressure-temperature-flow) tool, and injection pumps are
working satisfactorily prior to the main stimulation. A pre-stimulation test will also
show if estimates of proper injection pressures derived from previous tests are correct. After the stimulation, a post-fracturing injection test is carried out to quantify the
efficiency of the stimulation.
Stage 4: pre-stimulation test of the 1st well
This test consists of injecting approximately 400–600 m3 of fluid (either fresh water or
saturated brine) at a constant flow rate of around 5–7 l/s. Saturated brine can be very
useful in helping stimulation near the bottom of the well but this is dependent on the
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in situ stress regime. After the pre-stimulation test, the wellhead is shut in to observe
how pressure declines, thus giving some indication of the leak off, or far field connectivity.
Stage 5: main stimulation of the 1st well
During the main stimulation, fresh water is injected in steps with increasing flow
rates. Sometimes it is helpful to initiate the stimulation by using a wellbore full of
dense saturated brine before the fresh water. Three to four flow rate steps are normally used. The actual flow rates vary depending on the leak off, or whether it is a
closed system or an open system. Flow rate steps of around 30, 40, 50 and maybe
70 l/s are not unreasonable. Normally, the selected step of the injected flow rate is
continued until the wellhead or down-hole pressure reaches an asymptote, indicating
that the far field leak off is balanced by the injected flow. This is feasible in a relatively open system, but most observed EGS developments have poor far field connectivity and the wellhead pressure continues to increase. In this case, injection may
be carried out at 30 l/s for 24–30 hours, 40 l/s for 24–30 hours, 50 l/s for 24–30 hours
and 70 l/s for 3 days. The total injected volume may therefore vary, but is typically
between 28,000 m3 to 31,000 m3.
Stage 6: post-stimulation test of the 1st well
A post-stimulation test is conducted to evaluate the enhancement in permeability resulting from stimulation of the reservoir. Possible injection flow rates would be around
7, 30, 40 and 50 l/s for about 12, 12, 24 and12 hours respectively. The apparent reduction in the injection pressure compared to the injection pressure required for the
same flow rate during the pre-stimulation test gives a quantitative indication of the
improvement in permeability of the stimulated rock mass. The total volume of water
used for this test would be around 7,200 m3.
2.2.4 Planning, drilling and stimulation of the 2nd well
Once the stimulation and the post-stimulation test of the 1st well is completed, an
assessment is made to see if the extent and quality of the reservoir is suitable for
progressing to the next stage. The next stage is the targeting and design of the 2nd
well to intersect the target. During the drilling of the 2nd well, wellhead pressure on
the 1st well is monitored for any pressure response from the drilling activities in the
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2nd well. Once the 2nd well is completed, similar tests to that carried out in the 1st well
are required. Tests to be repeated on the 2nd well are listed below:
Stage 7: slug test in the 2nd well
Once the 2nd well has been drilled and completed, a slug test similar to the one
performed after the completion of the 1st well, as detailed in Stage 1, should be
carried out (total amount of water approximately 2–5 m3).
Stage 8: production test in the 2nd well
If the 2nd well is going to be the injection well, it is useful to carry out a production test
to evaluate major flowing fractures in the open part of the well. For example, if major
flowing fractures are identified just below the casing shoe, it may be worth sealing
this fracture and using other methods to initiate or encourage fractures to flow as
near to the bottom of the well as possible. This kind of evaluation is only possible if
the production test is carried out using a buoyancy drive, as this technique facilitates
the use of a PTF tool to log the well.
Production of formation fluid allows confirmation of observations from the 1st well
about the pressure-temperature conditions at the depth of the future heat exchanger.
Similarly, the fluid chemistry and the gas content data obtained in the 1st well can be
reconfirmed.
Details pertaining to the production test are as Stage 2 (total amount of water
approximately 450 m3).
Stage 9: low rate injection test in the 2nd well
As mentioned previously, the main objective of the low rate injection test is to
determine the hydraulic properties of the un-stimulated open-hole section of the well.
A low flow rate injection test is not absolutely necessary for the 2nd well because the
stress regime and other conditions at depth should be similar to that found in the 1st
well. It is, however, advisable in order to improve confidence in the data set. The
derived values are used as inputs for numeric models and planning of the
stimulation. A temperature or flow log collected at this stage will subsequently be
used to assess the success of the stimulation, and to identify predominant flowing
zones.
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A low rate injection test at this stage also provides a good opportunity to examine the
hydraulic communication between the wells, and may help in planning the strategy
for the pre-stimulation test and the main stimulation. Details on the mechanics of this
test are as detailed in Stage 3 (total amount of water approximately 45–50 m3).
Stage 10: pre-stimulation test in the 2nd well
This test is similar to that carried out in the 1st well, as described in Stage 4 (total
amount of water approximately 400–600 m3). Monitoring the pressure response in the
1st well to the injection in the 2nd well is very important.
Stage 11: main stimulation of the 2nd well
The stimulation procedure in the 2nd well is similar to the one carried out in the 1st
well, as described in Stage 5, except that the rates and periods of injection depend
on the pressure response in the 1st well. In the earlier stages of injecting, the 1st well
will generally be shut-in to raise the pressure in the reservoir for shearing of natural
joints. Once the wellhead pressure increases to an acceptable degree, however, it is
helpful to open the 1st wellhead to vent the fluid and encourage the fluid to channel to
the 1st well.
If the 2nd well intersects the reservoir engineered during stimulation of the 1st well—
for example, in the Geodynamics Cooper Basin Project this would equate to the
drilling of Habanero 2 and 3—then water requirements will be in the order of
approximately 15% of the 1st well is value—approximately 4,200–4,650 m3. However,
if the 2nd well is being drilled as part of a larger project—for example, in the
Geodynamics Cooper Basin Project this would equate to the drilling of Jolokia 1 and
Savina 1—then water requirements will be identical to the 1st well—approximately
28,000–31,000 m3).
Stage 12: post-stimulation test for the 2nd well
The decision whether to perform a post-stimulation test on the 2nd well depends on
the pressure response to the stimulation observed in the 1st well. A rapid pressure
response of the 1st well to the stimulation of the 2nd well suggests that a hydraulic link
is established between the two wells. If the 1st well is put on production during the
latter part of the stimulation of the 2nd well and shows promising returns then it may
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not be necessary to proceed with a post-stimulation test on the 2nd well. However, if
the response in the 1st well is poor, then a post-stimulation test should be carried out
on the 2nd well. A post-stimulation test on the 2nd well will help establish a sound
understanding of the behaviour of a rock mass to stimulations.
The procedure for carrying out the post-stimulation test is identical to that in the 1st
well, as described in Stage 6 (total amount of water approximately 7,200 m3).
Stage 13: small-scale circulation test between the 1st and 2nd well
Once a hydraulic link between the two wells has been established, a small-scale
circulation loop between the wells should be established. Wells with a separation of
600 m and a good hydraulic link should show a breakthrough time for a tracer of
around 4–6 days. The storage of injected fluid in the reservoir may increase during
this stage to accommodate 20 l/s flow through the system. This is due to the lag in
production flow because of the breakthrough time (~5 days), and an estimated 20%
of the injected volume could be stored in the reservoir before breakthrough, for
instance in dilated apertures of the joints.
An initial starting step of 20 l/s results in approximately 2,600 m3 of water being
required to initiate a circulation test. This increases with water loss into the formation.
For example, 10% water loss in the formation via leak off increases the figure to
3,600 m3 for a three-week circulation test.
Note: A separator, a heat exchanger, a heat load, and water storage facility will be
required to implement this test.
2.2.5 Evaluation of the stimulated reservoir of the 2nd well
Stages 14, 15 and 16 are used as backups in case the initial stimulation does not
produce the desired result. In principle, there should be no need for further treatment
provided everything works to plan and the natural conditions in the underground are
favourable. But if the low flow rate circulation test (Stage 13) shows that the total
impedance for circulation is above 0.3 MPa/l/s (or another cut-off value based on an
economic model) then remedial treatments might be needed to improve this. Data
from previous hydraulic tests are examined to determine whether the higher
impedance (restriction to flow) is due to effects near the wellbore or further out in the
reservoir. If the restriction is near the wellbore, then Stages 14 or 15 (or both) should
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be implemented. If the restriction is deeper in the reservoir, then Stage 16 is
implemented. The problem of high impedance near the wellbore and in the reservoir
can also be treated by other methods such as an injection of proppant or viscous gel.
Stages 14 and 15: reduction of near wellbore impedance
If the hydraulic data indicate that there is a need to reduce the friction associated with
turbulent flow near the well bore, then a very high flow rate injection should be
carried out to mobilise as many joints as possible, from those critically aligned to
those aligned to the sigma max direction. This will mean reaching injection pressure
above that of the sigma mean value at depth. Experience has shown that injection
flows in the range of 75–100 l/s should help in solving this problem. Stages 14 and 15
are identical procedures for treating the 1st and 2nd wells, respectively. In both cases,
injection of around 2,000 m3 at flow rates in the range of 75–100 l/s should suffice but
this should be evaluated for each specific case. Care should also be taken not to
damage the formation, damage the cement at the casing shoe, or block the well with
breakouts or cavings off the borehole walls.
Stage 16: reduction of the reservoir impedance
If the hydraulic data indicate that there is a need to reduce the impedance to flow
within the reservoir, due to a possible lack of connectivity between the wells, then a
possible strategy is to inject in both wells simultaneously (‘focussed injection’). Flow
rates injected in each well will depend on where the restriction is thought to lie.
Assuming that the pressure to shear joints is the range of 2–3 MPa and the restriction
is the middle of the reservoir, then an injected flow of between 30–50 l/s for up to 24
hours may be sufficient to improve the connectivity between the wells. This is a
relatively new and efficient technique, but needs to be implemented in conjunction
with real time microseismic monitoring to guide it through. Total volume of water
required is estimated to be around 9,000 m3.
Stage 17: alternatives to Stage 16
Alternative methods are to inject in one well at a time with much higher flow rate
(>50 l/s) or to use viscous fluid (approximately 30–50 cp) to reduce the flow
impedance.
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Stage 18: 2nd small-scale circulation test between the 1st and 2nd well
Once the work to optimise the impedance in the reservoir is completed, a circulation
loop between the wells should be established to evaluate the improvement made to
the reservoir characteristics. A 20 l/s circulation loop should be established as
previously, to compare the results. As mentioned in Stage 13, a tracer break-though
time of around 4–6 days for a separation of around 600 m between the wells can be
considered satisfactory. As also mentioned in Stage 13, the storage of injected fluid
in the reservoir may increase to accommodate flow through the system.
At 20 l/s, around 2,600 m3 of water would be required to initiate a circulation test.
Taking a worst scenario of losing 10% in the formation via leak off, this brings the
figure up to 3,600 m3 for a three-week circulation test.
2.2.6 Planning, drilling and stimulation of the 3rd well
Once the stimulation and the post-stimulation test of the 2nd well is completed, an
assessment is made of the extent and the quality of the reservoir to decide if it is
suitable for progressing to the next stage. The next stage is the targeting and the
design of the 3rd well. Once this has been established, the well is drilled to intersect
the target. During the drilling of the 3rd well, wellhead pressures on the 1st and 2nd
wells are monitored for a pressure response from the drilling activities in the 3rd well.
Once the 3rd well is completed, similar tests to that carried out in the 1st and 2nd wells
are repeated. Wellhead pressures in the 1st and 2nd wells are monitored throughout
all injection and production tests in the 3rd well.
Earlier tests to be repeated on the 3rd well are listed below:
Stage 19: slug test in the 3rd well
A slug test similar to the one performed in Stage 1 should be carried out (total
amount of water approximately 2–5 m3).
Stage 20: production test in the 3rd well
If the 3rd well is the production well, it is advisable to carry out a production test prior
to any major injection, to evaluate major flowing fractures in the open part of the well.
An example of how to remedy these flowing fractures was described in Stage 8.
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Formation fluid produced from the 3rd well will confirm what was observed in the 1st
well about the pressure-temperature conditions at the depth of the future heat
exchanger. Similarly, the fluid chemistry and the gas content data obtained in the 1st
and 2nd well will be reconfirmed.
Details pertaining to the production test were discussed in Stage 2 (total amount of
water approximately 450 m3).
Stage 21: low rate injection test in the 3rd well
A low flow rate injection test is not absolutely necessary for the 3rd well for the same
reasons as explained in Stage 9. The mechanics and reasoning for a low rate
injection test, however, are detailed in Stages 3 and 9 (total amount of water
approximately 45–50 m3). A low rate injection test also provides a good opportunity to
examine the hydraulic communication between wells, and may help in the design of
the pre-stimulation test and the main stimulation.
Stage 22: pre-stimulation test in the 3rd well
This test is similar to that carried out in the 1st well, as described in Stage 4 (total
amount of water approximately 400–600 m3). Monitoring of a pressure response in
the 1st and 2nd wells to the injection in the 3rd well is very important.
Stage 23: main stimulation of the 3rd well
Although the stimulation procedure in this well is similar to the ones carried out in the
1st and 2nd wells, the rate of injected flow and the period of injection will depend on
the pressure response in the 1st and 2nd wells. In earlier stages of injecting, the 1st
and 2nd wells are shut-in to raise the pressure in the reservoir for shearing of natural
joints, but once the wellhead pressures increase to an acceptable degree, it may be
helpful to open the wellheads to vent the fluid and encourage the fluid to channel to
the other wells.
As with the 2nd well main stimulation (Stage 11), the water requirements will depend
on whether the 3rd well is intersecting the engineered reservoir or whether it is part of
the larger project area. Water requirements will therefore be in the order 4,200–
4,650 m3 to 28,000–31,000 m3.
Stage 24: post-stimulation test for the 3rd well
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The decision whether or not to perform a post-stimulation test on the 3rd well
depends on the responses of the 1st and 2nd wells for the same reasons noted in
Stage 12.
The procedure for carrying out the post-stimulation test is identical to that of the 1st
well, as described in Stage 6 (total amount of water approximately 7,200 m3).
Stage 25: small-scale circulation test between the 1st and 3rd well
Once a hydraulic link between the wells has been established, a small-scale
circulation loop between the wells is required, using the 1st well as the injector and
the 3rd well as the producer. The 2nd well is shut-in and its in situ pressure monitored.
Details of this test are included in Stage 13 (total amount of water approximately
2,600–3,600 m3).
2.2.7 Evaluation of the stimulated reservoir of the 3rd well
Stages 26, 27 and 28 are used as backups in case the initial stimulation does not
produce the desired result. In principle there should be no need for further treatment
provided everything works to plan and the natural conditions in the underground are
favourable. But if the low flow rate circulation test (Stage 25) shows that the total
impedance for circulation is above 0.3 MPa/l/s (or another cut-off value based on an
economic model) then remedial treatments might be needed to improve this. Data
from previous hydraulic tests are examined to determine whether the higher
impedance (restriction to flow) is due to effects near the wellbore or further out in the
reservoir. If the restriction is near the wellbore then Stage 26 or 27 should be
implemented. If the restriction is deeper in the reservoir, then Stage 28 is
implemented. The problem of high impedance near the wellbore and in the reservoir
can also be treated by other methods such as an injection of proppant or viscous gel.
Stages 26 and 27: reduction of near wellbore impedance
Descriptions of these processes are as Stages 14 and 15 (total amount of water
approximately 2,000 m3).
Stage 28: reduction of the reservoir impedance
Description of this process is as Stage 16, although in this instance the two wells
referred to should read wells 1 and 3 (total amount of water approximately 9,000 m3).
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As before, alternative methods are to inject in one well at a time with much higher
flow rate (>50 l/s) or to use viscous fluid (approximately 30–50 cp) to reduce the flow
impedance.
Stage 29: 2nd small-scale circulation test between the 1st and 3rd well
Once the work to optimise the impedance in the reservoir is completed, a circulation
loop between the wells should be established to evaluate the improvement made to
the reservoir characteristics. Details of this test are as for Stage 18 (total amount of
water approximately 2,600–3,600 m3).
Stage 30: circulation with moderate flow rate (~40 l/s)
Once the basic circulation has been established and the reservoir characteristics look
acceptable, the next stage is to increase the flow through the overall reservoir using
three wells. An intermediate stage of injecting around 40 l/s in the 1st well and
producing 20 l/s from each of the 2nd and 3rd wells is recommended, as is tracking the
behaviour of the system by another tracer test. Microseismic monitoring is also a
useful tool to understand subsurface reservoir characteristics. The fluid storage
volume in the reservoir may need to further increase to accommodate 40 l/s flow
through the system. Two assumptions are made for the storage or charging of the
reservoir. The first is the breakthrough time (~5 days) and the second is that 20% of
the injected volume will be stored in the reservoir before the breakthrough occurs, for
instance in dilated apertures of the joints. This suggests that around 2,600 m3 of
water is required to charge the system. An acceptable worst case for water loss
during circulation is 10%, which brings the figure up to 6,500 m3 for a three-week
test.
Note: It is probable that microseismic activity will increase as water losses increase.
This needs to be monitored diligently and decisions possibly made to reduce the fluid
losses, as continuous microseismic activity may damage the reservoir.
Stage 31: circulation at near commercial scale (~70–100 l/s)
No one has yet reached flow rates in the region of 70–100 l/s. This stage will depend
very much on the result of the 40 l/s circulation test. If everything works satisfactorily,
then it may be possible to jump to the injection of 70 l/s in the 1st well. If not, a staged
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approach of increasing in steps of 10 l/s would be appropriate. Again, the evolution of
the reservoir using hydraulic, tracers and microseismic data will help to understand
what is happening in the subsurface realm. The two assumptions mentioned in Stage
30 for the storage or charging of the reservoir hold true. Thus approximately
4,000 m3 would be required to charge the system. As before, an acceptable worst
case for water loss during circulation is 10%, which brings the figure up to 13,000 m3
for a three-week test.
Appendix 1 includes a spreadsheet to assist in quantifying the total water volumes
which may be required to complete progressive stages of development.
2.3 Production
2.3.1 EGS vs. hydrothermal reservoirs
In terms of thermal energy, a kilogram of hot water at temperatures of 150°C to
300°C has a low energy content compared to a kilogram of hydrocarbon liquid.
Therefore, for a producing geothermal well to be comparable in energy content to an
oil well, high mass flow rates of hot water are required. As there is only one
commercial EGS plant in the world, hydrothermal projects are used for comparison to
provide an estimate of water usage for the production phase of geothermal energy
projects.
In a typical, successful hydrothermal reservoir, wells produce net electric power
through a combination of high temperatures and high flow rate. For instance, a well in
a shallow hydrothermal reservoir producing water at 150°C needs to flow at about
125 kg/s to generate 4.7 MW (Tester et al., 2006) of net electric power to the grid.
Generators rely on high flow per well to compensate for the capital cost of drilling and
completing the system at depth, and they need very high permeability to meet
required production and injection flow rates. Therefore as the starting target for EGS,
it is assumed that the fluid temperature and production flow-rate ranges will need to
emulate those in existing hydrothermal systems.
2.3.2 Water Requirement
As with exploration and development stages, the operation of an EGS project
requires that water be available for a reasonable cost. In many cases, it is likely that
the systems will be maintained without additional water through management of
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pressure in the reservoir, but in some cases water will likely be needed to replace
losses in the reservoir. As the size of the reservoir may need to be expanded
periodically to maintain the heat-exchange area, the system will progressively require
the addition of more water.
2.3.3 Case study of an EGS field project—Soultz
There have been several major EGS R&D projects carried out around the world.
These have had the main aim of demonstrating the feasibility of the concept by
stimulating and operating an engineered reservoir. These major projects have
included: Fenton Hill (United States), Rosemanowes (England), Hijiori and Ogachi
(Japan), Cooper Basin (Australia) and smaller projects in Germany and Sweden.
As a result of the interest generated by the initial Fenton Hill project, several
European countries began similar experiments. The EGS technology was not well
understood at the time and subsequently the cost of large-scale experiments quite
high. Soultz, in the Upper Rhine Valley was nominated as the site most suitable to
pool both finance and resources to form a Europe Project. In the initial stages, the
European Commission and relevant energy ministries of France, Germany and the
United Kingdom funded the project.
The following points outline the project history for Soultz, with reference to water
usage where available (modified from Tester et al., 2006):
1987: First well GPK1 was drilled to 2,002 m depth. Drilling was difficult and
overran the budget. The lower than expected temperature of 140°C at 2,000 m
was attributed to convection cells within the granitic basement.
1988: Three existing oil wells were deepened to penetrate the granite in order
to provide good coupling for seismic sondes.
1990: An existing oil well, designated EPS1, was deepened from 930 m by
continuous coring to 2,227 m where a temperature of 150°C was recorded.
Despite drilling problems, the well allowed a very sound characterisation of the
natural fracture framework.
1991: GPK1 was stimulated with high flow rates targeting the open-hole section
from 1,420–2,002 m. A fractured volume of 10,000 m3 was created, according
to evidence from microseismic mapping. It is possible that a natural fracture
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was intersected, which terminated fracture growth and allowed the loss of
injected fluid.
1992: GPK1 was deepened from 2,002–3,590 m, reaching a temperature of
168°C. There was a belief that in a slightly tensional regime like that at Soultz,
large-scale injection was not necessary and one could access the flowing
fracture network just by improving the connection from the well to the network.
This was found not to be true, and large-scale injections were necessary to
create connectivity.
1993: GPK1 was again stimulated using large flow rates, this time targeting the
newly drilled segment from 2,850–3,590 m.
1994: GPK1 was flow tested by producing back the injected fluid.
1995: GPK2 was stimulated in the open-hole section from 3,211–3,876 m, with
a maximum pressure of about 10 MPa and a flow of 50 kg/s. Acoustic
monitoring showed the reservoir growing with a tendency for the fracture cloud
to grow upward, forming a stimulated volume of about 0.24 km3. GPK1
showed a significant pressure response to the stimulation, which
demonstrated a connection between the two wells. A two-week circulation test
was then performed by injecting into GPK2 and producing from GPK1. The
rate was stepped up from an initial rate of 12 kg/s to 56 kg/s.
During 1995–1996, some circulation tests included the use of an electric
submersible pump. With the production well pumped, a circulation rate of
more than 21 kg/s was achieved. The surface temperature of the produced
water approached 136°C (injection was at 40°C), with a thermal power output
of about 9 MWt.
1996: GPK2 was restimulated, using a maximum rate of 78 kg/s with a total
volume of 58,000 m3 injected.
1997: Following the stimulation in 1996, a four month closed-loop flow test was
conducted injecting into GPK2 and producing from GPK1. Injection and
production stabilised at 25 kg/s, with no net fluid losses. Only 250 kWe
pumping power was required to produce the thermal output of 10 MWt.
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In 1997–1998, the project was gradually transferred to industrial management.
With new funding, the decision was made to deepen GPK2 to 5,000 mTVD to
reach 200°C. The predicted temperature of 200°C was reached at a depth of
4,950 mTVD. Measurement of the initial, natural pre-stimulation productivity
index in the new deep part of GPK2 was 5 MPa/l/s. This was consistent with
those seen in the depth range of 3,200–3,800 m.
2000: GPK2 was stimulated using heavy brines in an attempt to preferentially
stimulate the deeper zones. Nearly 23,400 m3 water was injected at flow rates
of 30 kg/s to 50 kg/s. No leak-off to the upper reservoir was detected.
2001: The deep production wells for the high temperature reservoir were drilled.
All wells were started from the same pad, GPK3 was drilled to 5,093 m to
target an area created from GPL2 in 2000.
2003: The deviated well GPK4 was drilled to 5,105 mTVD from the same
platform as GPK2 and GPK3 into a target zone selected from the stimulation
of GPK3. During drilling of GPK4, the reservoir was tested by injecting into
GPK3 and producing from GPK2. The tests established that there was an
excellent connection between the two wells with a productivity index of 0.3
MPa/l/s.
Following completion, GPK4 was stimulated using a heavy brine to encourage
the development of deep fractures. However, a linear aseismic zone became
apparent, separating GPK4 from the other two deep wells. Therefore no good
connection was developed between GPK4 and the rest of the reservoir.
Soultz began generating 1.5 MWe power sometime in the past year.
2.3.4 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.
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
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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. This stimulation significantly
reduced the water losses and impedance, but encouraged short circuiting 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.
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3.0 Atlas of Available Water Resources in South Australia
Water is a major factor influencing the development of South Australia and has been
made a particularly important state issue due to drought conditions in recent years.
Geothermal companies, therefore, have to be mindful of the availability of surface
water and groundwater resources in South Australia.
3.1 Overview
The climate across the majority of South Australia, approximately 85%, is classified
as either semi-arid or arid. In such areas, rainfall occurs sporadically and can be
concentrated and intense causing both local and widespread flooding. Evaporation
rates tend to be high, range up to extreme in the far north of the State, and surface
water dries out very quickly.
The remaining 15% of the State, namely the southern and coastal areas, are
temperate with annual rainfall ranging between 300 mm and 1,000 mm. The rain
mainly falls in winter and early spring, causing streams to flow. Evaporation rates are
high during summer, and streams tend to become a series of pools before drying up
entirely.
The majority of surface water in South Australia is fresh to marginally saline, but high
stream flows are often turbid. In some areas, surface water can be brackish when
salt is flushed from drier catchments or concentrated by summer evaporation.
There has been increased deep rainfall infiltration to groundwater as a result of land
clearing in the state and widespread increases in soil salinity due to groundwater
levels rising towards surface. Groundwater is accessible in more than half the state
all year round and is therefore a major natural water source in much of South
Australia. There is a high proportion of groundwater to surface water due to the
generally low and variable rainfall.
3.2 Surface Water in South Australia
As reported in the Australian Government’s Australian Natural Resources Atlas, the
mean annual stream flow entering South Australia is 9,300 GL, with the Murray River
discharging 7,220 GL of this external supply. The balance enters the north of the
State from Queensland and the Northern Territory via the Lake Eyre Basin streams.
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The mean annual stream flow generated within South Australia is 1,940 GL. The
following sections summarise surface water sources in South Australia as described
in the Australian Natural Resources Atlas, 2008.
3.2.1 River flows and catchments
River flows in South Australia are extremely variable and are governed largely by the
State’s climatic regime. Seasonal distribution depends on catchment location. The
majority of annual discharge in the south and coastal areas occurs between July and
November, whilst in the north, a greater proportion of run-off occurs from very short
duration events such as thunderstorms.
The Murray River, which has its headwaters in Queensland, New South Wales and
Victoria, is South Australia’s most reliable water resource. The largest surface water
resources in South Australia are in the Murray-Darling and Lake Eyre basins. The
catchment areas for both basins extend interstate and most river flows from the
catchments are sourced from interstate rainfall.
3.2.2 Streams
The majority of streams in South Australia are ephemeral and often flow for less than
six months of the year. Most of these streams have permanent water either in deep
pools, which reflect the regional ground water levels, or localised areas of low base
flow usually supplied by local aquifers. Base flow varies from year to year depending
on the rainfall from previous seasons.
More permanent streams are those beginning in the Mount Lofty Ranges near
Adelaide and the drains and streams in the southern part of the south-east region of
the State. The Mount Lofty Ranges provide catchment for Adelaide’s domestic water
supply, but the surface resources of the south-east have not been utilised to any
large degree, due to the abundance of good quality groundwater in the region.
3.2.3 Development of surface water
There are three major surface water supply systems in the State: the Adelaide
Metropolitan, the mid-north reservoirs and the Tod River systems. The State’s major
reservoirs are listed in Table 1 and may provide a source of water for geothermal
companies to use in their operations. Metropolitan water supply reservoirs are
located in the Torrens, Onkaparinga, South Para, Little Para and Myponga
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catchments, and have a combined capacity of 200 GL. The Tod River reservoir has a
capacity of 11.3 GL and supplies 2.5 GL/year for domestic use in the Eyre Region,
and the mid-north reservoirs of Baroota, Bundaleer and Beetaloo are interconnected
with the Morgan-Whyalla pipeline system from the Murray River.
Table 1. Major reservoirs in South Australia.
Reservoir Name
Capacity
Length of
Height of
(ML)
Wall (m)
Wall (m)
Type of Wall
Area of
Water
Spread (ha)
Barossa
4,515
144
28.6
Concrete arch
62
Happy Valley
11,600
806
23.6
Earth with clay core
178
Hope Valley
2,840
950
20.5
Earth with clay core
52
Kangaroo Creek
19,160
131
65
Concrete faced rock fill
103
Little Para
20,800
225
53
Concrete faced rock fill
125
Millbrook
16,500
288
31
Earth with clay core
178
Mount Bold
46,180
192
50.6
Concrete gravity arch
308
Myponga
26,800
226
49
Concrete arch
280
South Para
43,330
284
44.2
Rolled fill
400
Baroota
6,140
301
30.5
Earth with clay core
63
Beetaloo
3,180
210.3
33.5
Curved concrete gravity
33
Bundaleer
6,370
333
24.1
Earth with clay core
63
Middle River
470
131
20
Post tensioned concrete
11
gravity
Tod River
11,300
351
25
Earth with clay core
134
Warren
4,790
116.4
17
Concrete gravity
105
Blue Lake*
36,000
N/A
N/A
Natural volcanic crater
N/A
* The Blue Lake at Mount Gambier is a volcanic crater containing groundwater from local aquifer
systems, which seeps into the crater through porous limestone. The regional City of Mount Gambier
uses about 10% of its capacity each year.
3.2.4 Available resource
The following account of available surface water resources in South Australia is in
accordance with recent reporting from SA Water (SA Water website, 2008).
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Due to a diverse range of harvesting methods and an acceptance of high-risk of
failure from farm dam supplies in South Australia, it has not been possible to
estimate the total divertible surface water resource. The divertible yield is, therefore,
assumed to be equal to the sustainable yield, which has been determined as the
maximum volume of water that can be diverted after taking account of in-stream
environmental water requirements.
In South Australia, proposed policy recommends that the total storage capacity of
farm dams allowed in a catchment should not exceed 50% of the median run off from
private land. Of the 50% allowed for dam capacity, only half of this volume is
considered to be diverted for use annually, with the other half being lost to
evaporation, seepage and dam overflow or not available during periods of stream
drought. Based on this, the total sustainable yield of the resource generated within
the State is estimated to be 300 GL, or 15% of the mean annual streamflow. Of the
sustainable yield, 50% (or 7.5% of the mean annual stream flow) has already been
developed for use.
The Adelaide metropolitan catchments are fully committed with a developed yield of
130 GL, far exceeding their sustainable yield of 47 GL.
The Murray River is heavily committed with a developed yield of 736 GL (licensed)
and a current use of 595 GL. The use is currently 84% of its sustainable yield of 704
GL, defined by a cap imposed by the Murray Darling Basin Commission.
3.3 Groundwater in South Australia
Groundwater is defined as the reserve of water that exists within pores and crevices
of rock and soil beneath the earth’s surface (Australian Natural Resources Atlas,
2008). These areas are variable in both size and subsurface depth, and are referred
to as ‘aquifers’. High quality groundwater resources, referred to as ‘potable water’,
are usually used for drinking water purposes, whilst lower grade water is used for
livestock and industrial processes.
Groundwater is a vital commodity in many areas, supplying approximately 65% of all
irrigation water demand. Locally, groundwater plays a significant role in industrial
processes such as in the Piccadilly Valley of the Mount Lofty Ranges, which supplies
most of the spring and mineral water supplies of South Australia. In addition, soft
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drink and beer manufacturers utilise water from a deep Tertiary aquifer located
beneath Adelaide.
The availability of groundwater is generally controlled by two important parameters:
the type of strata that hosts the aquifer (i.e. whether it is a sedimentary or fractured
rock aquifer system), and the degree of connectivity of the voids (whether they be
fractures within the rock, or pore throats in sedimentary grains). Sedimentary aquifers
typically yield at higher rates and store a greater volume of water compared to fractured rock aquifers.
A further 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 northern South Australia, aquifers tend to be located at deeper levels below the earth’s surface, and are often associated with large volumes of water still resident from the geologic past. Present day
replenishment rates in these arid to semi-arid areas are typically low.
Groundwater currently accounts for 430 GL (35%) of the 1,200 GL of water use in
South Australia. The most productive aquifers are generally Quaternary and Tertiary
sedimentary limestone in the higher rainfall areas, which yield supplies of up to
200 l/s. Sedimentary aquifers also supply good quality groundwater in semi-arid and
arid environments. Fractured rock aquifers yield up to 30 l/s with salinities generally
increasing towards the north of the state as rainfall decreases.
Groundwater is extensively relied on for potable uses throughout south-eastern
South Australia (e.g. Blue Lake in Mount Gambier) and on the Eyre Peninsula. Many
of South Australia's remote communities rely entirely on groundwater for their potable
water needs.
A plethora of geothermal companies have an interest in the Great Artesian Basin
which underlies approximately 38% of South Australia. It is one of the largest artesian groundwater basins in the world and is discussed more fully in Section 3.4.
Utilisation of groundwater resources by geothermal companies will be carefully monitored to ensure extraction does not exceed recharge. The National Groundwater Action Plan initiated by the National Water Commission in 2007 funds hydrogeological
investigations to help overcome critical groundwater knowledge gaps. The National
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Water Commission and the over-arching National Water Initiative is discussed in
Section 4.1.
3.4 Great Artesian Basin
The Great Artesian Basin Coordinating Committee (GABCC) was established early in
2004. Its primary roles are to provide advice from community organisations and
agencies to Ministers on the efficient, effective and sustainable whole-of-resource
management of the basin, and to coordinate activity between stakeholders. The following information about the Great Artesian Basin has been sourced from the
GABCC website (2008).
3.4.1 Overview
The Great Artesian Basin (GAB) covers an area of over 1,711,000 square km2 (Figure 1), and has estimated water storage of 8.7 million GL, although only a very small
proportion of this water is recoverable from bores.
The GAB consists of alternating layers of water bearing (permeable) sandstone aquifers and non-water bearing (impermeable) siltstones and mudstones. This sequence
varies from less than 100 m thick on the outer extremities of the GAB to over 3,000 m
in the deeper parts. Water temperatures vary from 30°C in the shallower areas to
over 100°C in the deeper areas.
Throughout most of the GAB, groundwater generally flows to the south-west, although more to the north-west and north in the northern section. The rate at which it
flows through the sandstones varies between 1—5 m/year. Recharge by infiltration of
rainfall into outcropping sandstone aquifers occurs mainly along the eastern margins
of the GAB, and specifically along the western slopes of the Great Dividing Range.
Natural discharge occurs mainly from mound springs in the south-western area.
These springs are natural outlets through which the groundwater flows to the surface.
Some of the oldest waters are found in the south-western area of the GAB. These
have inferred ages of up to 2 million years (dating back to the base of the Pleistocene). The sedimentary rocks that make up the GAB were deposited during the Jurassic and Cretaceous Periods (195–65 million years ago).
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Figure 1. Map of the Great Artesian Basin highlighting intake areas, direction of flow and concentration of
springs (taken from http://www.nrw.qld.gov.au website).
3.4.2 Artesian aquifers
Bores drilled to penetrate the GAB vary in depth up to 2,000 m, with the average
being 500 m. Historically, many bores drilled in the GAB initially flowed at rates of
over 10 ML/day. However, the majority of flows are now between 0.01 and 6 ML/day.
Total flow from the GAB reached a peak of over 2,000 ML/day around 1915, from
approximately 1,500 bores. Since then, artesian pressure and water discharge rates
have declined, while the number of bores has increased. The total flow from the GAB
during 2000 was in the order of 1,500 ML/day.
3.4.3 Free flowing bores
Over 3,300 artesian bores exist across the GAB. These are bores in which the standing water level is above ground surface. About 820 of these artesian bores are uncontrolled and usually flow freely into bore drains. Flows from the remainder are fully
or partially controlled by headworks (See 3.4.5). Many free flowing artesian bores
discharge up to 8 ML/day, but the majority have smaller flows.
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The significant loss of water through uncontrolled free flowing artesian bores is an
issue for the reasons given below:
Water loss reduces water pressure, which reduces flow rate and can increase
costs to access water. In some areas, water has ceased to flow due to the
loss of pressure. Nearly 1,400 bores have ceased to flow over time in the
GAB.
Up to 90% of water flowing into bore drains can be lost due to evaporation and
seepage.
3.4.4 GAB springs
In addition to free flowing artesian bores, there are over 600 groups of groundwater
springs in the GAB, equivalent to over 1,000 individual springs. Springs are generally
associated with rapid aquifer thinning, or faults along which groundwater flows upwards. GAB springs are generally characterised by conical mounds—they are often
referred to as ‘mound springs’—formed by deposits brought up from groundwater
aquifers with a central wet core.
3.4.5 Capped bores
Not all bores flow uncontrolled. Property owners and governments began installing
headworks and piping to control flows from bores almost 50 years ago. In the intervening period, many free flowing bores have been controlled and much water has
been saved. However, the rate of change has been too slow to stem the fall in pressure or stop the waste of water across the GAB. In 1999, Commonwealth and State
Governments initiated partnership agreements with landholders (the ‘GAB Sustainability Initiative’—GABSI) to share the cost of capping and piping bores. The work is
intended to be completed over a 15 year period as part of the implementation of the
GAB Strategic Management Plan. Thus far, under GABSI, approximately 68 bores
have been capped and an estimated 2,382 km bore drains eliminated throughout
New South Wales, South Australia and Queensland. GABSI programs are estimated
to save 18,583 ML/year at present and have involved 306 properties. Including the
GABSI program, a total of 98,550 ML/year has been saved since bore capping and
piping began in South Australia in 1977.
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3.5 Coproduced Fluids: ‘Conventional’ Geothermal Development in
Hydrocarbon Fields
In some areas of oil and gas development, high temperatures are coupled with high
volumes of water produced as a by-product of hydrocarbon production. This is of particular significance to the Cooper Basin where geothermal licences for a number of
companies overlap with existing hydrocarbon operations. Each oil and gas field has a
large evaporation pond to house water co-produced from the extraction of hydrocarbons, so water sources are spread throughout the Basin area. The size of the ponds
varies depending on fluid rates to surface. 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 coproduced by hydrocarbon operations could prove beneficial to geothermal energy
projects in these areas.
In the United States, water is produced from massive water-flood recovery fields and
from most mature hydrocarbon areas; the disposal of this co produced water is an
expensive problem (Tester et al., 2006).
The key factors required for successful geothermal electrical power generation include sufficiently high fluid rates from a well or group of wells in relatively close proximity to each other, at temperatures in excess of 100°C. Although some fluid produced from the hydrocarbon industry may not be suitable for use, a certain fraction of
fluid may always be available that can be easily produced, collected and used as
feedstock for an existing geothermal reservoir or new EGS development.
Table 2 shows that co-produced water in the United States amounts to at least 40
billion barrels per year, primarily concentrated in just several states (Curtice and Dalrymple, 2004; taken from Tester et al, 2006). This resource could potentially generate
over 3000 MW of electrical power.
Table 2. Equivalent geothermal power from co-produced hot water associated with existing hydrocarbon
production in selected states of the US (table from Curtice and Dalrymple, 2004; taken from Tester et al, 2006).
State
Alabama
Total water pro-
Total water
Equivalent
Equivalent
Equivalent
duced annually
production
power
power
power
(kbbl)
rate (kGPM)
(MW@100°C)
(MW@140°C)
(MW@180°C)
203,223
18
18
47
88
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Arkansas
258,095
23
23
59
112
California
5,080,065
459
462
1,169
2,205
Florida
160,412
15
15
37
70
Louisiana
2,136,573
193
194
492
928
Mississippi
592,518
54
54
136
257
Oklahoma
12,423,264
1,124
1,129
2,860
5,393
Texas
12,097,990
1,094
1,099
2,785
5,252
Totals
32,952,141
2,980
2,994
7,585
14,305
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4.0 Regulations for Access to Water Resources
Drought conditions in recent years have led to a response from the South Australian
State Government that will ensure available water resources are used in an ecologically sustainable manner. Where state water resources have been identified as being
subject to increasing use pressures, or their environmental values are degrading, the
Natural Resources Management Act 2004 (which superseded the Water Resources
Act 1997) allows the area to be ‘proclaimed’. This means users must be licensed,
and water allocation plans are implemented to help regulate future development. The
water allocation plans may also allow water rights or entitlements to be traded.
4.1 Regulatory Framework
4.1.1 Introduction
The National Water Commission (NWC) is an independent statutory authority within
the Federal Department of the Environment, Water, Heritage and the Arts. It is the
result of an intergovernmental agreement signed by all Australian, state and territory
governments at the June 2004 Council of Australian Governments (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).
The NWC was established under the National Water Commission Act 2004, and is
responsible for driving progress towards the sustainable management and use of
Australia's water resources under the National Water Initiative (NWI). In addition, the
NWC advises CoAG and the Federal Australian Government on national water issues and the progress of the NWI.
4.1.2 National Water Initiative
The NWI signifies the Australian, 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 the preparation of the Australian Water Resources 2005
(AWR 2005).
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AWR 2005 is the baseline assessment of water resources taken at the beginning of
the National Water Initiative—against which future data, and the success of NWI reform processes, can be measured.
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, groundwater management units, capital city water supply areas, interjurisdictional and combined water management areas.
4.1.3 Regional water resource assessments in South Australia
South Australia has been divided into a number of water management blocks according to whether the area is:
A surface water management area,
A groundwater management unit, or
An interjurisdictional, combined area and capital city water supply area.
The following URL link connects to an interactive site where South Australian regional water resource assessments can be downloaded. The site includes information on
a series of attributes including water management frameworks, water resource caps,
sustainable yields and water entitlements.
http://www.water.gov.au/RegionalWaterResourcesAssessments/Maps/SA/GMU/SA_
GMU.aspx?Menu=Level1_7
Geothermal companies should refer to this site for specific information relating to
their licenses.
4.1.4 Natural Resources Management Act 2004
There is a requirement under South Australia’s Natural Resources Management Act
2004 (‘the Act’) to manage water in a sustainable manner. A five-yearly review is required of water allocation plans for groundwater management units and water management areas to assess the capacity of the resource to meet ongoing demand. In a
number of instances, where a system has been clearly over allocated or overused,
measures have been adopted to reduce water allocations and use.
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Large-scale groundwater development can result in several detrimental impacts on
the resource, including lowering of water tables, salt water intrusion, land subsidence
and lowered base flow in streams. Where the use of groundwater, surface water or
water bores is concentrated or strategic, the resource is protected by Prescription
under the Act (see Figure 2). In addition, the Act also allows for the establishment of
regional Natural Resources Management Boards. These bodies have the responsibility to develop a management framework that balances the economic, social and environmental demands on the available groundwater resources.
Figure 2. Map of Prescribed Areas in South Australia. (taken from: www.dwlbc.sa.gov.au).
Management plans (Water Allocation Plans) exist or are being developed or revised
for those regions where the groundwater resources have been prescribed, with the
aim of achieving levels of acceptable use. An important aspect of groundwater management is the appropriate allocation of water extraction rights and the role of adequate groundwater resource monitoring. The water allocation plan is undertaken in
consultation with the community and is ultimately approved by the Minister.
Section 150 of the Act specifies “A water allocation may be fixed by specifying the
volume of water that maybe taken and used or by reference to the purpose for which
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the water may be taken and used or in any other manner”. Allocations are thus apportioned as volume specific [in mega litres] or purpose. For example, in the Far
North, the geothermal industry has been given an allocation as part of the mining industry volume allocation in the plan. On the other hand, the petroleum industry has
been given an allocation in the basis of purpose for co-production of water with its oil
and gas production. Different areas have different allocation procedures and it is
therefore vital the geothermal industry consult and engage PIRSA in the first instance
at an early stage of their proposed operations.
A water allocation plan is not required for geothermal activities within non-prescribed
areas. A water bore construction permit is required only if a bore is being drilled specifically for water resources, and this will apply to the geothermal industry if a
bore is drilled to fulfill water requirements for the geothermal project.
There is provision in the Act [section 125] for the Governor, under recommendation
from the Minister, to declare an area of the State a Prescribed Area.
4.1.5 Water licensing arrangements
South Australia is in the process of making changes to water licensing arrangements
as part of its commitment to the NWI. The existing water licences will be separated
into their main components: a Water Access Entitlement, a Water Allocation, a Site
Use Approval, a Water Resource Works Approval and a Delivery Capacity Entitlement. Recently the Natural Resources Management (Water Resources and Other
Matters) Amendment Act 2007 was proclaimed. This Act gives the Government the
power to amend the Natural Resources Management Act 2004 to give effect to the
separated scheme. The legislative changes aim to benefit water users by making water transfers easier and more efficient, expanding the choices available for water
management, and providing clarity for all aspects of water access entitlements. The
purpose is to create greater certainty for investors, and increase the efficiency of water markets and water use.
Existing licence holders will continue to own a secure, personal property right in water (the new Water Access Entitlement). In fact, for most licensees, the proposed
changes will make little or no significant difference. However, the changes will improve the opportunities for those who wish to participate in the water trading market,
making it explicitly clear to buyers and sellers what is being bought and sold.
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The Natural Resources Management Act 2004 will not actually be amended to give
effect to the new entitlements for several years. A significant amount of work must be
completed prior to the implementation of the separated scheme. A new water register
system must be established, relevant water allocation plans amended, and policies
and procedures developed to specify how the new component rights will be applied.
Regulations pertaining to each prescribed area can be downloaded from the following URL:
http://www.legislation.sa.gov.au/LZ/C/A/NATURAL%20RESOURCES%20MANAGE
MENT%20ACT%202004.aspx
Licensing and allocation of water permits is dealt with more fully under section 146 of
the Act—the following URL link should be accessed:
http://www.legislation.sa.gov.au/LZ/C/A/NATURAL%20RESOURCES%20MANAGE
MENT%20ACT%202004/CURRENT/2004.34.UN.PDF
4.2 Environmental Water Requirements
The South Australian Government is committed to ensure all water resources are
used in a sustainable manner. The State Water Plan provides a suite of policy
principles that addresses protection and management of the ecological values of
water-dependent ecosystems. The purpose of these principles is to provide guidance
and direction to the authorities preparing water plans on how to deal with these
issues in an integrated manner—whether they are Catchment Water Management
Boards, water resource planning committees or local government.
The State Water Plan recognises that there is a range of ecosystems associated
with, and dependent on, water. These include watercourses, riparian zones,
wetlands, floodplains and estuaries. The Plan also requires a monitoring strategy to
be implemented to assess the changes in the condition of the water resources of the
State. Ongoing monitoring and evaluation are identified as vital procedures to allow
measurement of the change in condition of the water resource. The success of
policies within management plans will be measured by how they meet catchment,
stream health and economic objectives. Geothermal companies may be required to
monitor groundwater quality if they access it for their projects.
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5.0 Recommendations
An initial review of available data and information was carried out to assess the full
life-cycle water requirements for deep geothermal energy developments in South
Australia. This was achieved by addressing the following broad areas:
Introduction about geothermal energy;
Key stages of a geothermal project;
Atlas of available water resources in South Australia;
Regulations on how to access water resources.
Recommendations for more accurate calculations of water requirements include:
Further research of individual companies’ experience and water usage in recent
exploration drilling programmes;
Development of spreadsheet of volumes of water required for a range of
currently operating EGS production plants;
Development of software tools for calculating water requirements for specific
stages of geothermal projects;
Further investigation of the suitability of co-produced water from hydrocarbon
operations for geothermal projects.
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6.0 Acknowledgements
The authors wish to thank the organisations and individuals who contributed to the
compilation of this report. In particular we would like to thank:
Roy Baria for his technical input into this report;
Green Rock Energy Ltd: for the use of information from their own assessment
of water requirements for the development of a deep HDR system;
PIRSA: in particular Tony Hill, Elinor Alexander and Mike Malavazos;
Petratherm Ltd;
Other geothermal exploration companies that provided water usage information
from recent drilling programs
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7.0 References
AUSTRALIAN NATURAL RESOURCES ATLAS (2008): www.anra.gov.au
BARIA R., HEARN K.C. AND BATCHELOR A.S., 1985. Induced seismicity during the hydraulic stimulation of the potential Hot Dry Rock geothermal reservoir—submitted to
the Fourth Conference on Acoustic Emission/Microseismic Activity in Geology Structures and Materials, Pennsylvania State University, 22–24 Oct., 26 pp
BROWN, D., 2000. A Hot Dry Rock geothermal energy concept utilizing supercritical
CO2 instead of water. In: Proceedings of the Twenty-Fifth Workshop on Geothermal
Reservoir Engineering, Stanford University, 233–238
CULL, J. P., 1979. Heat-flow and geothermal energy prospects in the Otway Basin,
southeastern Australia. Search, 10, 429–433
GREAT ARTESIAN BASIN CONSULTATIVE COUNCIL (GABCC) WEBSITE (2008):
http://www.gabcc.org.au/tools/getFile.aspx?tbl=tblContentItem&id=12
TESTER ET AL.,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.
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., 17 pp
NEUMANN, N., 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, 107–120
PINE R.J. AND BATCHELOR A.S., 1984. Downward migration of shearing in jointed rock
during hydraulic injections. Int. J. Rock Mech. Min. Sci., 21(5), 249–263
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PRUESS, K., 2006. Enhanced geothermal systems (EGS) using CO2 as working fluid—A novel approach for generating renewable energy with simultaneous sequestration of carbon. Geothermics, 35, 351–367
PURSS, M. B. J. AND CULL, J. 2001. Heat-flow data in western Victoria. Australian
Journal of Earth Sciences 48, 1–4
SASS, J. H., 1964. Heat-flow values from Eastern Australia. Journal of Geophysical
Research 69(18), 3889–3893
SA WATER WEBSITE (2008)
http://www.sawater.com.au/SAWater/Education/OurWaterSystems/Mains.htm
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