GTESGeothermal Energy ScienceGTESGeoth. Energ. Sci.2195-478XCopernicus GmbHGöttingen, Germany10.5194/gtes-3-19-2015Overcoming challenges in the classification of deep geothermal
potentialBreedeK.katrin.breede@tu-clausthal.deDzebisashviliK.FalconeG.Dept. of Geothermal Engineering and Integrated Energy Systems, Institute of
Petroleum Engineering, Clausthal University of Technology, Clausthal, GermanyK. Breede (katrin.breede@tu-clausthal.de)7April201531193923June201417February201524February2015This work is licensed under a Creative Commons Attribution 3.0 Unported License. To view a copy of this license, visit http://creativecommons.org/licenses/by/3.0/This article is available from https://www.geoth-energ-sci.net/3/19/2015/gtes-3-19-2015.htmlThe full text article is available as a PDF file from https://www.geoth-energ-sci.net/3/19/2015/gtes-3-19-2015.pdf
The geothermal community lacks a universal definition of deep
geothermal systems. A minimum depth of 400 m is often assumed, with a
further sub-classification into middle-deep geothermal systems for reservoirs
found between 400 and 1000 m. Yet, the simplistic use of a depth cut-off is
insufficient to uniquely determine the type of resource and its associated
potential. Different definitions and criteria have been proposed in the past
to frame deep geothermal systems. However, although they have valid
assumptions, these frameworks lack systematic integration of correlated
factors. To further complicate matters, new definitions such as hot dry rock
(HDR), enhanced or engineered geothermal systems (EGSs) or deep heat mining
have been introduced over the years. A clear and transparent approach is
needed to estimate the potential of deep geothermal systems and be capable of
distinguishing between resources of a different nature. In order to overcome
the ambiguity associated with some past definitions such as EGS, this paper
proposes the return to a more rigorous petrothermal versus hydrothermal
classification. This would be superimposed with numerical criteria for the
following: depth and temperature; predominance of conduction, convection or
advection; formation type; rock properties; heat source type; requirement for
formation stimulation and corresponding efficiency; requirement to provide
the carrier fluid; well productivity (or injectivity); production (or
circulation) flow rate; and heat recharge mode. Using the results from data
mining of past and present deep geothermal projects worldwide, a
classification of the same, according to the aforementioned criteria is
proposed.
Review
In the past, definitions such as hydrothermal and petrothermal have been
created to categorize deep geothermal systems, i.e. systems with a depth
greater than 400 m, into two groups. The first group includes geothermal
reservoirs that provide a heat source, a natural reservoir with high enough
permeability, and a water recharge. The second group comprises geothermal
systems where only a natural heat source exists, while the underground heat
exchanger must be created artificially and water must be supplied for water
circulation within. Hydrothermal systems (HSs) are clearly dominant in
comparison to petrothermal systems (PSs) with regards to number of
occurrences worldwide and megawatts of electricity generated.
In 1970, the hot dry rock (HDR) concept was introduced to describe a system
which uses hot and dry rock as a heat source and where an artificial
underground heat exchanger had to be created (Cummings and Morris; 1979;
Tester et al., 1989; Potter et al., 1974). However, during the history of
deep drilling, it was found that most rocks are actually not completely dry,
but contain at least some naturally occurring water. This finding led to the
development of a definition of hot wet rock (Duchane, 1998). In addition,
the category of hot fractured rock was created to describe geothermal
reservoirs that consist of hot rocks, typically crystalline, that are
already naturally fractured due to fault systems or that require artificial
fracturing (Genter et al., 2003). Stimulated geothermal systems, deep heat
mining (Häring, 2007), and deep earth geothermal were also introduced to
describe deep geothermal systems that are typically created in crystalline
rocks and are independent from water-bearing structures. All these definitions
are actually related to PSs.
Recently, the new definition of enhanced or engineered geothermal systems
(EGSs) was introduced for deep geothermal systems, which required technical
enhancement such as stimulation to create an artificial reservoir or the
supply of water (MIT, 2006a; AGRCC, 2010; Williams et al., 2011; BMU, 2011).
This definition is not solely related to PSs, but can also be applied to HSs
that require technical enhancement such as stimulation techniques or
artificial water supply for water circulation in order to increase the
productivity of the system.
On the hydrothermal side of deep geothermal systems, only the recently
developed definition of hot sedimentary aquifer (HSA) was additionally
introduced to describe HSs as having a heat source that is conduction-dominated,
rather than convection-dominated.
However, the creation of so many definitions for deep geothermal systems and
the fact that they are not recognized as internationally standards has
created some confusion about the actual classifications and which geological
setting or geothermal system is being described. An additional complication
is that, at a given geothermal site, different systems can exist; e.g. at
Soultz-sous-Forêts, where at one depth, an HFR system is present, and at
another depth, an HDR system is found.
This paper tries to meet the challenge of the classification of deep
geothermal systems by reintroducing the categories of petrothermal,
hydrothermal and, additionally, HSA. The term EGS is excluded from our new
classification as it carries a vague definition and provides insufficient
information about the system, e.g. if natural water is available in the
underground heat exchanger and if the permeability is high enough to produce
heat or electricity.
Definition of deep geothermal energy
Deep geothermal energy is defined by its depth, which has to be at least 400 m and a temperature of at least 20 ∘C. However, some authors
recommend using the term deep geothermal energy only for depths of at least
1000 m and temperatures of more than 60 ∘C. The depth range from
400 to 1000 m is sometimes referred to as middle-deep geothermal. Deep
geothermal systems are commonly divided into HSs and PSs, but deep
geothermal energy can also be used from mines, caverns, and tunnels. (PK
Tiefe Geothermie, 2007; VDI-Richtlinie 4640, 2010)
Definition of enhanced geothermal systems
In recent times, the term EGS has been used more and more. However, as
already reported by Breede et al. (2013), the definition of EGS is vague and
exists in different forms. For example, MIT (2006a) defines EGSs as
“engineered reservoirs that have been created to extract economical amounts
of heat from low permeability and/or porosity geothermal resources”.
Another definition is provided by the Australian Geothermal Reporting Code
Committee, which defines an EGS as “a body of rock containing useful energy,
the recoverability of which has been increased by artificial means such as
fracturing” (AGRCC, 2010).
Definition of petrothermal systems
The terminology petrothermal was first mentioned by Roberts and Kruger (1982),
while the term EGS was first proposed by Grassiani et al. (1999).
Petrothermal systems (PSs) are commonly defined as hot (>150 ∘C) and dry crystalline or dense sedimentary rocks, which do
not have high enough natural permeability and therefore require the
application of stimulation techniques in order to create an artificial
reservoir (Nag, 2008). Hence, these systems are independent from water-bearing structures and it is essential to provide water for both hydraulic
fracturing and as a carrier fluid (via water injection for circulation
through the underground heat exchanger, and subsequent production). The
natural permeability of the production well before stimulation, as opposed
to the injection well, defines the term petrothermal (Schulz, 2008); thus, the injection horizon could be an aquifer, which can be used for water
disposal. By this definition, Landau in Germany is not a PS, but an HS, as
hydraulic fracturing was only required for the injection well in order to
increase the injectivity index (Schindler et al., 2010). However, in many
geothermal projects, the injection well and production well have the same
technical design. Thus, they can be used alternatively as injector or
producer, according to the hydraulic schemes. This is the case at Soultz,
for example, where some wells were first used as producers and then as
injectors. In order to create the artificial heat exchanger and to use the
PS, at least two wells, one injection well and one production well, are
required.
Schulz (2008) and Kreuter (2011b) state that the following criteria have to
be fulfilled simultaneously in the case of a PS:
average natural permeability, before stimulation, of less than
10-14 m2;
production well does not allow for an economically relevant production; i.e.
the productivity index is less than 10-2 m3/(MPa s), without the application of stimulation
techniques;
using hydraulic fracturing, the production of the formation must be increased by at least 50 %.
In his second draft for the renewable energy law in Germany (EEG),
Schulz (2009) recommended that the productivity enhancement factor should be
100 % (a factor of 2) instead of only 50 % (a factor of 1.5). How
high this factor should be depends on the determined productivity index prior
to hydraulic fracturing and is thus site dependent. The idea behind the
enhancement factor is that the productivity must be increased in such a way
that it is economical to produce geothermal energy at the given site. The
productivity index has to be determined using hydraulic tests before any
hydraulic fracturing techniques are applied. However, prior application of
chemical stimulations is possible.
The values for the permeability threshold, productivity index and the
productivity enhancement factor of 50 % are based on field experience,
mainly gathered from the European HDR project at Soultz-sous-Forêts in
France. However, it is difficult to generalize from this site alone, as
different productivity indices have been determined at different depths
varying from 1 to more than 100 (Schill et al., 2013). Thus, the complexity
of the geological conditions has to be taken into account before determining
which productivity enhancement factor is suitable for a given formation.
When considering past nomenclature, PSs could fall into the following
categories (GtV, 2014c):
enhanced geothermal systems (EGSs),
engineered geothermal systems (EGSs),
hot dry rock (HDR),
hot wet rock (HWR),
deep heat mining (DHM),
stimulated geothermal systems (SGSs),
deep geothermal probes.
PSs are used most commonly for electricity generation (Hirschberg et al.,
2015a) and combined heat and power (CHP) production due to drilling costs
being much higher than for HSs. However, with increasing costs for heating
oil, PSs could also become economic for heating in the future. The exception
is the deep geothermal probe, which is a closed-loop system that employs a
heat transfer medium to recover heat being stored in any rock formation.
Geothermal probes are used for heating purposes only.
PSs are always conduction-dominated (Sass and Goetz, 2011); i.e. the heat
moves through the material from a hotter zone to a cooler zone.
There exists a transition zone between HSs and PSs, where a project
could be classified as either petrothermal or hydrothermal. Thus, at the
same geothermal site, different geothermal systems can co-exist at different
depths, as it is the case for Soultz and Landau. Experience gained from deep
wells showed that the classic definition of the HDR Technology, which refers
to a hot and almost completely dry basement rock, is invalid (Schulz, 2008).
Definition of hydrothermal systems
Hydrothermal systems (HSs) are defined by the availability of a water-bearing
structure, such as an aquifer, which is used by the production and injection
well (Bertani, 2012). To ensure high enough flow rates and thus high
productivity of the wells, high permeabilities are required and the water-bearing structure should be vertically and laterally extensive to guarantee
the sustainability of the HS (GtV, 2014d). Looking at the definition of PS
proposed by Schulz (2008), the permeability of the productive horizon in HSs
should be at least 10-14 m2 and the productivity index
at least 10-2 m3 / (MPa s). Thus, HSs are
convection-dominated; i.e. the heat is transported by the movement of hot
material (Huenges, 2010a). Volcanic systems are the most representative type
of HSs worldwide. Additional common hydrothermal reservoir rocks are
sedimentary porous aquifers, such as sandstones or conglomerates, secondary
fractured and/or cavernous rocks, such as limestones, or young and deep
fault systems, such as those found in the Upper Rhine Valley (Huenges, 2010b;
GtV, 2014d). Often major fault zones are targeted for HSs, as they commonly
provide much higher permeability values. However, due to the existing
pre-stresses, these fault zones might present more risk for induced
seismicity than initially estimated (Hirschberg et al., 2015b). Typically,
hydrothermal reservoirs in Germany are found in the North German Basin, the
Upper Rhine Graben and the Molasse Basin, located in the north, south-west
and south of Germany, respectively.
Besides the original exploration well in a HS field, at least one further
appraisal well must be drilled. In some cases, an additional third well is
drilled to reduce hydro-mechanical shearing in the reservoir, which thereby
reduces the risk of induced seismicity (Cuenot, 2013). Although HSs do not require
stimulation, Huenges (2010c) states that it might be sensible to use chemical
stimulation in order to enhance permeability in the near-wellbore region.
Definition of hot sedimentary aquifers
In recent years, the term HSA has been created for deep and hot sedimentary
aquifers that are, in contrast to common HSs, conduction-dominated (Mortimer
et al., 2010; Huddlestone-Holmes and Hayward, 2011; Huddlestone-Holmes and
Russel, 2012). However, Clean Energy Australia (2014) refers to HSA systems as convective
systems. Various minimum temperatures are given by different authors:
75 ∘C (cleanenergyaus, 2014), 130 ∘C (Huddlestone-Holmes
and Russel, 2012), 140 ∘C (Barnet, 2009). Also, different depths
are proposed: 1 to 3 km (cleanenergyaus, 2014); 2.5 to 3 km (newworldenergy,
2014). A maximum depth of 4.5 km was given by Huddlestone-Holmes and Russel
(2012), reflecting that the likelihood that the permeability would be too low at
greater depths. The Australian Energy Resource Assessment states that the
depth should be “shallow enough for natural porosity and permeability to be
preserved so that fluid circulation can occur without artificial
enhancement”. Although, stimulation techniques are not required, they might
be applied to increase the near-wellbore permeability (Huddlestone-Holmes
and Hayward, 2011). However, this statement does not clearly indicate which
type of stimulation would be required below 4.5 km, although it is most
likely to be hydraulic fracturing.
Specific values could neither be found for porosity, permeability nor for
flow rates. The permeability of HSA systems can either be matrix permeability in
sandstone or fracture permeability in tight limestones or fault zones
(Huddlestone-Holmes and Hayward, 2011). Huddlestone-Holmes and Russel (2012)
state that the rock density should be lower than the crystalline basement
rocks, which are targeted for HDR or EGS resources, and should be around
2400 kg m-3.
Another requirement is that the reservoir must be covered by a thick cap
rock made of clay and/or coal rich sequences, which acts as a thermal
insulator (Mortimer et al., 2010). This is also the case for volcanic HSs and
true for all geothermal systems, as the cap rock significantly reduces heat
loss.
For HSA systems in Australia, newworldenergy (2014) states that at least one of the
following geological settings should be fulfilled:
Radioactive decay in basement rocks acts as a heat source for overlying aquifers
Remnant heat from old volcanic centres ensures an elevated geothermal gradient
Hot water welling up from deep basins along thermal density and/or pressure gradients
Rapid tectonic uplift brought a deep hot water formation closer to the surface and compressed the geothermal gradient.
Stimulation techniques
Stimulation techniques such as hydraulic stimulation, chemical stimulation,
and thermally induced fracturing are commonly used to enhance the
permeability of geothermal reservoirs, thereby increasing their productivity, to
create new fractures and hence an artificial underground heat exchanger, or
to clean the wells of drill cuttings. The selection of the most appropriate
stimulation technique depends on, among other parameters, the desired depth
of invasion, i.e. the radius of influence.
The most common stimulation technique is hydraulic stimulation, as it
provides the largest depth of invasion and can be applied to re-open and/or
create fractures up to several hundreds of metres away from the borehole
(ENGINE, 2008b). Fractures generated by hydraulic stimulation can be tensile
(perpendicular to minimum principal stress axis), shear (perpendicular to
maximum principal stress axis), or a combination of both, and their
orientation and distribution depends on the overall stress field (Zimmermann
et al., 2010a). In some cases, it is recommended to isolate intervals in the
wells and perform consecutive stimulations of these intervals rather than
carrying out a massive hydraulic stimulation. This is an expedient to reduce
the risk of creating shortcuts and larger seismic events (ENGINE, 2008b).
Hydraulic stimulation is a requirement for the creation of an artificial
petrothermal heat exchanger.
An example of quantitative values for evaluating the impact of hydraulic
fracturing in matrix-dominated formations and correlating input/output
parameters is given by Groß Schönebeck. Three hydraulic stimulation
treatments were carried out separately in a well over 6 days: the cyclic
waterfrac treatment in the low permeable volcanic rocks and gel-proppant
treatments in the lower and upper Dethlingen sandstones. For the waterfrac
treatment, 13 170 m3 of fluids and 24.4 tons of quartz sand (the
latter as proppant) were injected. The maximum wellhead pressure of 58.6 MPa
was reached at the maximum flow rate of 9 m3 min-1, with the
total duration of the treatment being 6389 min. (Zimmermann et al., 2010a).
After the isolation of this section with a bridge plug at 4300 m for the
first and at 4123 m for the second treatment, two gel-proppant treatments in
highly permeable sandstones were performed over 4 days. In total, 95 tons
of proppants and 280 m3 of cross-linked gel were injected into the
lower Dethlingen formation with a flow rate of 4 m3 min-1 and 113
tons of proppants for the first treatment; 310 m3 of cross-linked gel
were injected into the upper Dethlingen formation at flow rates ranging from
3–3.5 m3 min-1 for the second treatment (Zimmermann et al.,
2010b). The production test, which lasted 11.8 h and produced about
356 m3 of fluids, showed an overall productivity increase after the
stimulations by more than a factor of 4. 30 % of the total flow came
from the volcanic rocks and 70 % from the sandstones (Zimmermann et al.,
2010a). However, it can be argued that hydraulic fracturing in
matrix-dominated formations is not the most common situation in deep
geothermal projects.
Another example of hydraulic performance improvement of a PS through
hydraulic fracturing is given by the Fenton Hill project, which has been
referred to as a PS by Kruger (1990). In the second phase of this PS, a total
fractured volume of 1 km3 was created, flow rates were increased up to
18.5 L s-1, and the permeability was improved to a value of 3 to
5 m2 (MIT, 2006f).
Of course this is only one example; a case-by-case investigation of the
geomechanics involved must be carried out to estimate the benefit of
hydraulic stimulation. In some cases, the productivity index can be much
higher than reported above. Schindler et al. (2010), for example, quote
productivity improvement by a factor of 20 after massive hydraulic
stimulations in crystalline rocks.
Jung (2013) presented an overview of different hydraulic stimulation
techniques used for EGSs, such as multi-zone hydraulic fracturing in
crystalline basements (based on the original HDR concept), multi-zone massive
injection in naturally fractured crystalline rock formations (in order to
generate multiple wing cracks), and open-hole massive injection in naturally
fractured crystalline rock formations.
The second most common stimulation technique is chemical stimulation, which
is applied to enhance the permeability in the near-wellbore region, i.e. up
to a distance of few tens of metres (ENGINE, 2008b). This technique is also
called acidizing as acids such as hydrochloric acid (HCL) and hydrofluoric
acid (HF) are commonly used to react with carbonates and silicates,
respectively. The only additives that might be used for geothermal systems
are as follows: corrosion inhibitor, inhibitor intensifier, and high-temperature
iron-control agent (ENGINE, 2008b). According to Schumacher and
Schulz (2013), acidizing with HCL can significantly improve the performance
of a geothermal well drilled into carbonate rock. In addition, it is an
effective means to remove fine materials from the walls of the wells, i.e. to
clean the well from drill cuttings and from scaled minerals that decrease
permeability (Schumacher and Schulz, 2013; ENGINE, 2008b). The aim of
acidizing in sandstones is to dissolve naturally occurring clay or material
that originated from drilling and completion works and other plugging minerals in
the near-wellbore region, thereby increasing the permeability (ENGINE, 2008b). In
this case, the acidizing is performed in three stages: pre-flush (HCL), main
flush (HCL-HF mixture) and overflush (HCL, or KCL, NH4CL or fresh water)
(ENGINE, 2008b). Chemical stimulation can be applied to any of the following
deep geothermal systems: HS, HSA, PS, EGS.
Schumacher and Schulz (2013) analysed improvements after several acidizing
steps in a number of wells in the carbonate rocks of the south German Molasse
Basin; their findings are relevant for analogue geothermal projects
worldwide. The normalized flow rate for these wells was taken as
10 L s-1, with an observed improvement of over 10 % per m3 of
15 % HCL used. The analyses indicate that the first acid treatment
significantly increased the productivity, whereas subsequent treatments did
not have such a great impact any more, and in some cases resulting in
deterioration of well performance.
Thermal fracturing is used in volcanic rock environments, such as found in
Iceland, to increase the permeability of existing flow paths, to create new
ones, and is achieved with a combination of induced temperature and pressure
changes (ENGINE, 2008b). It is used when the temperature difference between
injected fluid and rock formation is significant (Flores et al., 2005).
Tulinius et al. (2000) provide some quantitative values for this type of
stimulation for a 2500 m deep well in geothermal area of Bouillante, France,
which was characterized by low steam output before stimulation. A
253 ∘C reservoir was stimulated in periods up to 72 h using
seawater mixed with an inhibitor to prevent anhydrite scaling at a flow rate
up to 25 L s-1 and initial wellhead pressure of 2.5 MPa, which
decreased gradually and was close to zero for maximum injection at the end of
the programme. The thermally induced fracturing resulted in a 50 %
increase of productivity.
General Information about Petrothermal Systems.
ProjectLocationhOperatorDescriptionStart dateEnd dateStatusWell depth [m]Distance between producer and injector [m]Le MayetFRUnknownResearch, Cornet (2012); MIT (2006b)1978, Cornet (2012)1987, Cornet (2012)Concluded experimental, Cornet (2012)200–800, Cornet (2012)100, Cornet (1987)SoultzaFREuropean cooperation project, MIT (2006c)R&D, Genter (2012)1987, MIT (2006b)Not ended*power plant of stage 1.0 dismantled, planning stage Soultz 2.0 with different power plant, J. Scheiber, personal communication, 20153600, 5080, 5100 and 5270, Genter et al. (2010)450, 600 and 650, Genter et al. (2010)GeneSys HannoverDEBGRb, EGEC (2013)Demonstrate single-well concepts, Tischner et al. (2010)2009, Tischner et al. (2010)Not ended*Under development, Tischner et al. (2013)3901, Tischner et al. (2013)Single well, Tischner et al. (2010)GeneSys HorstbergDEBGRb, EGEC (2013)Demonstrate single-well concepts, BGR (2014a)2003, Tischner et al. (2010)2007, BGR (2014b)Concluded experimental, BGR (2014b)3800, Tischner et al. (2010)Single well, Tischner et al. (2010)Groß SchönebeckDEGFZc, Schmidt & Clemens GmbH, BINE (2012)1st in situ geothermal laboratory, EGS research, Zimmermann et al. (2009)2000, Zimmermann et al. (2009)Not ended*Under development, not generating electricity, GtV (2014a)4309–4400, Zimmermann et al. (2009); Henninges et al. (2012)470, Urpi et al. (2011)MauerstettenDEExorka, GFZc, TUBAFd, Schrage et al. (2012a)Research, Schrage et al. (2012b)2011, Schrage et al. (2012a)Not ended*Under development, not generating electricity, GtV (2014a)4545, Exorka (2014)Single-well drilled, Exorka (2014)FalkenbergDEBGRb (coordinator), Kappelmeyer and Jung (1987)Investigation of hydraulic fracturing at shallow depth, Tenzer (2001)1977, Tenzer (2001)1986, Tenzer (2001)Concluded experimental, MIT (2006d)300–500, Kappelmeyer and Jung (1987)eight wells within area of 100 m × 100 m, Kappelmeyer and Jung (1987)Bad UrachDEForschungs-Kollegium Physik des Erdkörper, MIT (2006g)HDR demonstration pilot in Germany, Tenzer (2001)1977, Tenzer (2001); 2006, Wyborn (2011)1981, MIT (2006h); 2008, Wyborn (2011)Single-well concept abandoned, Schanz et al. (2003); consideration as deep geothermal probe, iTG (2010)4445, Tenzer (2001) and 2793, iTG (2010)100, iTG (2010)BaselCHGeopower Basel, Giardini (2009)Planning to develop EGS project, Ladner and Häring (2009)1996, Giardini (2009)2009, Giardini (2009)Abandoned due to Induced seismicity, Giardini (2009)5000, Ladner and Häring (2009)Second well not drilled, Ladner and Häring (2009)FjällbackaSEUniversity of Technology, Gothenburg, Sweden, Jupe et al. (1992)Experimental project, Portier et al. (2007)1984, Jupe et al. (1992)1995, Wallroth et al. (1999)Concluded experimental, Wallroth et al. (1999)70–500, Jupe et al. (1992)100, Wallroth et al. (1999)RosemanowesGBCSMe, MIT (2006e)Experimental project, MIT (2006e)1977, MIT (2006e)1992, MIT (2006e)Concluded experimental, MIT (2006e)2000–2600, MIT (2006e)300 (vertically), MIT (2006e)EdenGBEGS Energy Limited, Baria et al. (2013)Commercial CHP, Baria et al. (2013)2010, Baria et al. (2013)Not ended*Early stage, under development, not generating electricity, Baria et al. (2013)Target depth 4000, Baria et al. (2013)Unknown at this stageUnited DownsGBGeothermal Engineering ltd, EGEC (2013)commercial CHP, three-well system, Bridgland (2011)2010, Atkins (2013)Not ended*Early stage, under development, not generating electricity, Atkins (2013)Target depth 4500–5000, Atkins (2013)Unknown at this stageLitoměřiceCZMunicipality of Litoměřice, Gryndler (2009)Experimental, proof of concept, Stibitz et al. (2011)2007, Tym (2013)Not ended*Under development, not generating electricity, Stibitz et al. (2011)Drilled up to 2111; target depth 5000, Stibitz et al. (2011)600 planned, Tym (2011)FerencszállásHUEU-FIRE kft. and Mannvit kft., Ministry of National Development, Sverrisson et al. (2013)Commercial CHP, Sverrisson et al. (2013)2012, Sverrisson et al. (2013)Not ended*Early stage, under development, not generating electricity, Sverrisson et al. (2013)Target depth 4000, Sverrisson et al. (2013)Unknown at this stageNewberryUSAAltaRock Energy, Davenport Newberry, Cladouhos et al. (2012)Demonstration for EGS stimulation/ Research, Cladouhos et al. (2012)2010, Cladouhos et al. (2012)Not ended*Under development, not generating electricity, Newberry EGS Demonstration (2014)Over 3000, Sonnenthal et al. (2012)Second well not yet drilled, Newberry EGS Demonstration (2014)Northwest GeysersUSACalpine Corporation, Garcia et al. (2012)EGS demonstration, Garcia et al. (2012)2009, Rutqvist et al. (2013)Not ended*Under development, not generating electricity, Garcia et al. (2012)3396, Garcia et al. (2012)525, Garcia et al. (2012)Fenton HillUSALos Alamos National Laboratory, MIT (2006f)First HDR in the world, MIT (2006f)1974, MIT (2006f)1993, MIT (2006f)Concluded experimental, MIT (2006f)2932–4390, MIT (2006f)100; 380 (vertically), MIT (2006f)ParalanaAUPetratherm Limited, Beach Energy, Reid and Messeiller (2013)Commercial power development, Reid and Messeiller (2013)2005, Petratherm (2014)Not ended*Under development, not generating electricity, Petratherm (2014)4003, Bendall et al. (2014)Second well not yet drilled, Petratherm (2014)
ProjectLocationhOperatorDescriptionStart dateEnd dateStatusWell depth [m]Distance between producer and injector [m]Cooper Basin (Innamincka)AUGeodynamics Ltd., Origin Energy, Majer et al. (2007)Largest demonstration project in the world, Stephens and Jiusto (2010)2003, Majer et al. (2007)Not ended*temporarily shut down, planning small scale project, Geodynamics (2014)4421, Majer et al. (2007)UnknownOlympic DamAUGreen Rock Energy Ltd, Lovelock (2011)Commercial power development, Lovelock (2011)2005, Meyer et al. (2010)Not ended*Early stage, under development, not generating electricity, Lovelock (2011)target depth 5500, Lovelock (2011)Unknown at this stageParachilnaAUTorrens Energy Ltd, Torrens Energy (2014)Commercial power development, Torrens Energy (2014)2007, Canaris (2009)Not ended*Under development, not generating electricity, Torrens Energy (2014)target depth 4500, Torrens Energy (2014)Unknown at this stageFromeAUGeothermal Resources Pty Limited, Geoscience Australia and ABARE (2010)Commercial power development, Geothermal Resources (2014)2006, Geothermal Resources (2014)Not ended*Under development, not generating electricity, Geothermal Resources (2014)target depth 3250, Goldstein et al. (2010)Unknown at this stagePohangKRNexgeo Inc., KIGAM, KICT, SNU, POSCO, Innogeo Tech. Inc., Lee et al. (2011)Proof of concept power generation EGS, Lee et al. (2011)2010, Lee et al. (2011)Not ended*Under development, not generating electricity, Lee et al. (2011)Target depth 5000, Lee et al. (2011)Unknown at this stageHijioriJPJapan's New Energy, DiPippo (2012), NEDOf, Sasaki (1998)Developing HDR technologies, Sasaki (1998)1985, Sasaki (1998)2002, DiPippo (2012)Abandoned due to failure to create a reservoir, Grant and Bixley (2011)1800–2200, DiPippo (2012)33, 38, 63 shallow reservoir, 90 and 130 deep reservoir, DiPippo (2012)OgachiJPCRIEPIg, Kaieda et al. (2010)Test run HDR project in shallow depth, Kaieda et al. (2005)1989, Kaieda et al. (2005)2002, Kaieda et al. (2005)Concluded, experimental (Kaieda et al. (2010)1000–1300, Kaieda et al. (2005)50 shallow reservoir; 80 and 200 deep reservoir, Kaieda et al. (2005)
* See status; a not clear whether Soultz project is hydro- or petrothermal;
b BGR – Bundesanstalt für Geowissenschaften und
Rohstoffe; c GFZ – Helmholtz Centre Potsdam – GFZ German Research
Centre; d TUBAF – TU Bergakademie Freiberg; e CSM – Camborne
School of Mines; f NEDO – New Energy and Industrial Technology
Development Organization; g CRIEPI – Central Research Institute of the
Electric Power Industry; h country abbreviation after ISO 3166
Alpha-2; CHP– combined heat and power production; KIGAM – Korea Institute of Geoscience and Mineral
Resources;
KICT – Korea Institute of Construction Technology;
SNU – Seoul National University;
POSCO – Pohang Iron and Steel Company.
Systematic overview of past and present deep geothermal systems
The following review consisting of PSs and HSA systems is not meant to be
exhaustive, as it is based solely on information that is available in the
public domain. This review excludes conventional HSs, because the focus of
this paper is on PSs and HSA systems in relation to the widespread term EGS. The
overview is divided into PS (see Tables 1–3) and HSA (see Tables 4–6). The
PS database consists of 26 projects worldwide, whereas the HSA database
consists of 10 projects. Conventional HSs, such as volcanic systems
or vapour-dominated systems, are not presented in the tables.
Wherever the literature did not state whether a given project is a PS or an HSA system,
and when the present authors did not agree with the classification offered
by the literature, an independent view was taken.
Whether the heat source of a project was conduction-dominated or
convection-dominated was difficult (and in most cases impossible) to find in
the literature in order to differentiate HSs from HSA systems.
Petrophysical properties of petrothermal systems.
ProjectRock typePorosityPermeability (K) [m2]/transmissivity (T) [m2 s-1]BHT/Reservoir temperature [∘C]Le MayetGranite, Cornet (2012)UnknownUnknown22, Wyborn (2011)SoultzaGranite, MIT (2006c)Altered rock: 0.25, Ledésert et al. (2010); connected porosity: 0.0025–0.003, Portier and Vuataz (2009)Fresh Soultz granite: K = 4 × 10-19, Ledésert et al. (2010)200, Genter et al. (2010)GeneSys HannoverBunter sandstone, Tischner et al. (2013)<0.1, ENGINE (2008a)K = 10-18, Tischner et al. (2013)169, Tischner et al. (2013)GeneSys HorstbergBunter sandstone, Tischner et al. (2010)0.03–0.11, Orzol et al. (2005)Ki<40 × 10-15, GeneSys Hannover (2014a)150, Tischner et al. (2010)Groß SchönebeckSandstone and andesitic volcanic rocks, Zimmermann et al. (2009)0.08 to 0.10, Zimmermann et al. (2010a)Ki= 10-14 to 10-13, Zimmermann et al. (2009); Ki up to 16.5 × 10-15, Zimmermann et al. (2010a)150, Henninges et al. (2012)MauerstettenLimestone, Schrage et al. (2012a)UnknownUnknown130, Schrage et al. (2012a)FalkenbergGranite, MIT (2006d)UnknownUnknown13.5, Kappelmeyer and Jung (1987)Bad UrachGneiss, Tenzer et al. (2000)UnknownT (rock matrix) 10-7 to 10-6, T (fractures) 10-4 to 10-3 at 3320–3488 m, Schanz et al. (2003)172 at 4445 m, Tenzer (2001); 112 at 3200 m, iTG (2010)BaselGranite, Ladner and Häring (2009)UnknownK = 1 × 10-17 estimated, Ladner and Häring (2009)174, Ladner and Häring (2009)FjällbackaGranite, Portier et al. (2007)UnknownK = 10-18 to 10-17, Jupe et al. (1992) T = 10-8 to 10-7, Wallroth et al. (1999)16, Wallroth et al. (1999)RosemanowesGranite, MIT (2006e)UnknownKi= 10-18 to 10-17, Parker (1999)79–100, MIT (2006e)EdenGranite, Baria et al. (2013)0.15 estimated, Atkins (2013)K = 9.9 × 10-16 estimated, Atkins (2013)180 estimated, Baria et al. (2013)United DownsGranite, Atkins (2013)0.15 estimated, Atkins (2013)K = 9.9 × 10-16 estimated, Atkins (2013)180–200 estimated, Atkins (2013)LitoměřiceSedimentary and granite, Stibitz et al. (2011)UnknownUnknown63.5, Stibitz et al. (2011); 178 to 207.5 estimated at 5 km, Stibitz et al. (2011)FerencszállásMetamorphic schist and partly granitoid, Sverrisson et al. (2013)UnknownUnknown170 estimated, Sverrisson et al. (2013)NewberryVolcanic rocks, Fittermann (1988)0.01 to 0.20, Sonnenthal et al. (2012)K = 1.0 × 10-18 to 1.5 × 10-12, Sonnenthal et al. (2012)315, Cladouhos et al. 2012)Northwest GeysersMetasedimentary rocks (greywacke), Romero et al. (1995)0.01, Rutqvist et al. (2013)K = 2 × 10-14, Rutqvist et al. (2013)about 400, Garcia et al. (2012)Fenton HillCrystalline rock, Brown (2009)UnknownUnknown180 to 327, MIT (2006f)ParalanaMetasediments, granite, Petratherm (2014)UnknownUnknown190, Reid and Messeiller (2013)Cooper BasinGranite, Majer et al. (2007)UnknownUnknown243 to 264, Bendall et al. (2014)Olympic DamGranite, Lovelock (2011)UnknownUnknown85.3 at 1934.2 m, Bendall et al. (2014) 190 estimated at target depth, Lovelock (2011)ParachilnaGranite, Geoscience Australia and ABARE (2010)UnknownUnknown98.4 at 1807 m, 240 estimated at 4500 m, Torrens Energy (2014)FromeGranite, Geoscience Australia and ABARE (2010)UnknownUnknown93.5 at 1761 m, 200 estimated at 4080 m, Geoscience Australia and ABARE (2010)PohangPaleozoic granodiorite, Lee et al. (2011)UnknownUnknown180 estimated, Lee et al. (2011)HijioriGranodiorite, Sasaki (1998)0.01, Sasaki (1998)K (Rock matrix) 10-19 to 10-21, Sasaki (1998)190, DiPippo (2012)OgachiGranodiorite, Kaieda et al. (2010)UnknownK = 0.8 × 10-15 to 0.2 × 10-13, Kaieda et al. (2005)228, Kaieda et al. (2005)
a not clear whether Soultz project is petrothermal or HSA;
i permeability calculated from Darcy into m2 under assumption that
water temperature is only 10 ∘C and fresh water;
BHT – bottomhole temperature.
ProjectFlow rate [L s-1]Stimulation techniquesSeismic event (Richter scale)Type of power plantInstalled electrical capacity [MWe]Thermal capacity [MWth]Flow assurance problemLe Mayet5.2, Wyborn (2011)Hydraulic fracturing with and without proppant, Cornet (2012); MIT (2006b)Microseismic, not felt on surface, Cornet (2012)None*0*0*UnknownSoultza30, BMU (2011)Hydraulic stimulation and acidizing, Genter et al. (2010)Microseismic (M =-2 to 2.9), Genter (2012)ORC, Genter et al. (2010)1.5, Genter et al. (2010)Non-scheduled, Dumas (2010)Corrosion due to high salt contents, BMU (2011)GeneSys Hannover7 (planned), BGR (2014c)Hydraulic fracturing, Tischner et al. (2013)No seismic event due to geothermal activity, Tischner et al. (2013)None*0*2 (planned), Tischner et al. (2013)Salt precipitation removed with coiled tubing, GeneSys Hannover (2014b)GeneSys Horstberg4, Tischner et al. (2010)Hydraulic fracturing, Tischner et al. (2010)No measured event, Kreuter (2011a)None*0*1 to 1.4, Tischner et al. (2010)UnknownGroß Schönebeck4.4, Blöcher et al. (2012)Hydraulic: gel proppant and fracturing, Zimmermann et al. (2009); Thermal, ENGINE (2008b), Chemical, Henninges et al. (2012)Negligible (max. -1.8 to -1.0 M), Blöcher et al. (2012)ORC, BINE (2012)1, BINE (2012)0*High salt content (265 g L-1), BINE (2012)Mauerstetten–Chemical, Schrage et al. (2012b); hydraulic stimulation, iTG (2013)UnknownModular binary planned, Exorka (2014)0*0*UnknownFalkenberg3.5**, Kappelmeyer and Jung (1987)Hydraulic fracturing, Tenzer (2001)Microseismic, MIT (2006d)None*0*0*UnknownBad Urach50 for single-well; 15–25 estimated for doublet, iTG (2010)Hydraulic fracturing, Schanz et al. (2003)Microseismic, Schanz et al. (2003)None*3 evaluated, Tenzer (2001)17 evaluated, Tenzer (2001)High flow impedances in a single well, Schanz et al. (2003); Torn-off drill pipes in borehole, iTG (2010)BaselUnknown at this stageHydraulic fracturing, Ladner and Häring (2009)Frequent earthquakes (max. 3.4 M), Ladner and Häring (2009)None*0*0*Unknown at this stageFjällbacka0.9** to 1.8**, Wallroth et al. (1999)Hydraulic fracturing and acidizing, Portier et al. (2007)Microseismic, Wallroth et al. (1999)None*0*0*Too high fluid losses and flow impedance, Wallroth et al. (1999)Rosemanowes4–15, MIT (2006d)Hydraulic fracturing, MIT (2006d), viscous gel stimulation, Parker (1999), proppants, Parker (1999)Max. magnitude 3.1, Bromley ane Mongillo (2008)None*0*0*Temperature drawdown, very low flow rate, pressure drop, MIT (2006e)Eden55 estimated, Baria et al. (2013)Hydraulic stimulation planned, Baria et al. (2013)Unknown at this stageNone*4 estimated, Baria et al. (2013)3.45 estimated, EGEC (2013)Unknown at this stageUnited Downs150 estimated, Bridgland (2011)Planned, Bridgland (2011)Unknown at this stageNone*10 estimated, Atkins (2013)50 estimated, Bridgland (2011)Unknown at this stageLitoměřice120 estimated, Gryndler (2009)No stimulation for a drilled exploration well, Stibitz et al. (2011)Unknown at this stageKalina cycle, CHPi planned, Gryndler (2009)4.4 estimated, Gryndler (2009)50 estimated, Gryndler (2009)Unknown at this stageFerencszállás160 estimated, Sverrisson et al. (2013)Hydraulic fracturing and acidizing planned, Sverrisson et al. (2013)Unknown at this stageORC, Sverrisson et al. (2013)5 estimated, Sverrisson et al. (2013)20 estimated, Sverrisson et al. 2013)Unknown at this stageNewberryUnknown at this stageHydro-shearing, multi-zone isolation techniques, Cladouhos et al. (2012)Microseismic, Cladouhos et al. (2012)None*0*0*UnknownNorthwest Geysers9.7, Garcia et al. (2012)Thermal fracturing, Walters (2013)Microseismic (0.9 to 2.87 M), Garcia et al. (2012); Walters (2013)None*0*0*Corrosion in production well, Walters (2013)Fenton Hill10.6 to 18.5 (test), MIT (2006f)Hydraulic fracturing, MIT (2006f)Microseismic, Brown (1995)Binary, MIT (2006f)0.06, MIT (2006f)3–5, MIT (2006f)Creating connection between wells, pressure drop in and near wellbore, MIT (2006f)Paralana70 estimated, Reid and Messeiller (2013)Hydraulic stimulation, Reid and Messeiller (2013)Microseismic ≤ 2.6 M, Petratherm (2014)ORC planned, Reid and Messeiller (2013)3.5, Reid and Messeiller (2013)0*Unknown
Operational characteristics of petrothermal systems.
ProjectFlow rate [L s-1]Stimulation techniquesSeismic event (Richter scale)Type of power plantInstalled electrical capacity [MWe]Thermal capacity [MWth]Flow assuranceproblemCooper Basin19 at 215 ∘C, Geodynamics (2014)Hydraulic stimulation, Majer et al. (2007); Holl (2012)≤3.7 M, Majer et al. (2007)1 MWe pilot plant, Geodynamics (2014)1 for proof of concept (Geodynamics (2014)0*UnknownOlympic DamUnknownHydraulic fracturing, Meyer et al. (2010)UnknownProbably binary, Love-lock (2011)400 planned, Green Rock Energy (2014)0*UnknownParachilnaUnknownUnknownUnknownORC, Beardsmore and Metthews (2008)0*0*UnknownFromeUnknownHydraulic fracturing, Goldstein et al. (2010)UnknownORC, Giles (2009)0*0*UnknownPohang40 estimated, Lee et al. (2011)Hydraulic fracturing planned, Lee et al. (2011)Unknown at this stageBinary planned, Lee et al. (2011)1.5 estimated, Lee et al. (2011)0*Unknown at this stageHijiori16**, MIT (2006c)Hydraulic fracturing, Sasaki (1998)Microseismic, Sasaki (1998)Binary, DiPippo (2012)0.13, DiPippo (2012)8, DiPippo (2012)High water losses, precipitation of anhydrite, DiPippo (2012); rapid temperature drawdown in one production well, Grant and Bixley (2011)Ogachi6.7** to 20**(test), Kaieda et al. (2005)Multiple wells with multiple fracture zones; hydraulic fracturing, Kaieda et al. (2005)Few microseismic, Kaieda et al. (2010)None*0*0*Low water recovery rate in circulation tests, Kaieda et al. (2005)
* See status; ** Injection flow rate; a not clear whether
Soultz project is petrothermal or HSA. ORC – Organic Rankine Cycle; CHP – Combined heat and power
production.
The databases for PSs and HSA systems are each divided into three parts: general
information, petrophysical properties, and operational characteristics.
Table 1 (PS), resp. Table 4 (HSA), comprises general information about PSs,
resp. HSA, such as location, operator, description, start date, end date,
status, well depth, and distance between producer and injector at depth. The
description contains the main goal of each project, whereas the status
informs whether a project is still under development, ongoing, concluded, or
abandoned.
Table 2 (PS), resp. Table 5 (HSA), presents petrophysical properties of the
reservoir such as rock type, porosity, permeability or transmissivity, and
temperature. However, only a few porosity and permeability values could be
found in the literature. Permeabilities are given in m2. In the case of
permeabilities given in Darcy, the values were converted into m2 under
the assumption of the presence of fresh water and temperatures of only
10 ∘C, which the authors admit is an oversimplification. In some
cases, only transmissivities were available, which were converted into
permeabilities in the cases where reservoir thicknesses were available in the
public domain.
General information about hot sedimentary aquifers.
ProjectLocationOperatorDescriptionStart dateEnd dateStatusWell depth [m]Distance between producer and injector [m]St. GallenCHITAG Tiefbohr GmbH, Geothermie Stadt St. Gallen (2014)Hydrothermal heat production project, Hirschberg et al. (2015c)2009, Geothermie Stadt St. Gallen (2014)2014, Hirschberg et al. (2015c)Abandoned, Hirschberg et al. (2015c)4450, Hirschberg et al. (2015d)Single well, Hirschberg et al. (2015e)BruchsalDEEnBWj, EWBk, Rettenmaier (2012)Commercial, Herzberger et al. (2010)1985, Herzberger et al. (2010)Not ended*On-going, generating electricity, GtV (2014a)1874 to 2542, BMU (2011)1500, Herzberger et al. (2010)LandauDEBESTEC, Geox, Baumgärtner (2012)First EGS in town in DE, Baumgärtner (2012)2004, Baumgärtner (2012)2014, GtV (2014b)Abandoned due to groundwater contamination resulting from well damage, Geothermie-Nachrichten (2014)3170–3300, Baumgärtner (2012)1500, Bracke (2012)InsheimDEPfalzwerke geofuture GmbH, Pfalzwerke geofuture (2014)New concept: side-leg injection well, Baumgärtner (2012)2007, Baumgärtner (2012)Not ended*On-going, generating electricity, Ganz et al. (2013)3600-3800, Pfalzwerke geofuture (2014); Baumgärtner (2012)UnknownNeustadt-GleweDEWEMAG, Stadt Neustadt-Glewe, Geothermie Neubrandenburg, BMU (2011)Commercial, Pilot plant for low-enthalpy, Broßmann and Koch (2005)1984, Broßmann and Koch (2005)Not ended*On-going, generating electricity, GtV (2014a)2320, Bracke (2012)1500, BMU (2011)UnterhachingDEGeothermie Unterhaching, Rödl & Partner, Richter (2010)First CHPi Kalina power plant in Germany, Richter (2010)2001, Richter (2010)Not ended*Ongoing, generating electricity, GtV (2014a)3350 to 3590, Richter (2010)4500, Bracke (2012)Southampton***GBSGHCl, Southampton (2014a)CHP station, district heating and chilling system, Smith (2000)1981, Smith (2000)Not ended*On-going, Southampton (2014a)1800, Smith (2000)Single well, Smith (2000)AltheimATMunicipality of Altheim, Terrawat, Pernecker (1999)Commercial, Pernecker (1999)1989, Pernecker (1999)Not ended*On-going, generating electricity, Bloomquist (2014)2165–2306, City of Altheim (2014)1700, City of Altheim (2014)Birdsville***AUErgon Energy, Ergon (2014)The only operating HSA power station in Australia, Ergon (2014)1992, Ergon (2014)Not ended*On-going, generating electricity, Ergon (2014)1280, Ergon (2014)Single well, Ergon (2014)Penola***AURaya Group Limited, Panax Geothermal (2014)Proof of concept for commercial power generation, Graaf et al. (2010)2010, Panax Geothermal (2014)Not ended*Under development, not generating electricity, Panax Geothermal (2014)4025, Graaf et al. (2010)Single well; 10 wells planned, Proactive Investors (2009)
* See status; *** Project indicated as HSA in the
literature;
j EnBW – Energie Baden-Württemberg AG;
k EWB – Energie und
Wasserversorgung Bruchsal GmbH;
l SGHC – Southampton Geothermal Heating.
Company
Table 3 (PS), resp. Table 6 (HSA) shows operational characteristics such as
flow rate, stimulation technique, seismic event, type of power plant,
installed electrical capacity, thermal capacity, and flow assurance
problems. In most cases, the production flow rate was given. However, in
some cases, only injection flow rates could be found in the literature.
Stimulation techniques state whether stimulation was applied or not and, in
the cases where stimulation was performed, the method that was applied is
given. Whenever the information was available in the public domain, it was
differentiated in the tables which type of hydraulic stimulation was
applied. In the case of missing differentiation in the references, the
tables refer generically to hydraulic stimulation, which could mean either
one of the hydraulic stimulation techniques, such as hydraulic fracturing,
hydraulic shearing or a combination of both. Seismic events are given in
Richter scale magnitudes. The type of power plant is commonly only available
for those projects which are ongoing. All projects employ only binary power
plants, such as organic rankine cycles (ORCs) or Kalina cycles. In the event
of the information being available, it was possible to differentiate which
type of binary power plant was used for each project. Installed electrical
and thermal capacities could only be provided for the ongoing projects.
In what follows, specific projects have been highlighted which presented
ambiguity in their classification.
Petrothermal systems
The European HDR project Soultz-sous-Forêts in France was categorized as
a PS, although there has been much debate among experts as to whether this
system should be categorized as HDR, HFR or HSA (IGA R&R, 2013). This
discussion has probably arisen because two different reservoirs are connected
to the project: the upper reservoir being in a fractured granite formation
with higher permeabilities (3 × 10-14 m2) and the lower
reservoir in a fresh granite formation with much poorer permeabilities
(1 × 10-17 m2) (Kohl et al., 2000). Although Soultz was
initially planned as an HDR project and therefore created in crystalline
basement rocks, it was found that the reservoir contains permeable structures
with substantial volumes of natural brine. Hence, it differs from the
classic definition of HDR and the geothermal anomaly is mainly controlled by
natural fluid flow (Genter et al., 2010). However, the low hydraulic
connection of the fracture system required a permeability enhancement using
hydraulic stimulation. Following the definition in Sect. 2, this would
indicate that Soultz is a PS as hydraulic stimulation was required to enhance
the productivity index.
Petrophysical properties of hot sedimentary aquifers.
ProjectRock typePorosityPermeability (K) [m2]/Transmissivity (T) [m2 s-1]BHT/reservoir temperature [∘C]St. GallenMalm, shell limestone, Hirschberg et al. (2015e)UnknownUnknown>145, Brunner and Huwiler (2014)BruchsalBunter sandstone, Herzberger et al. (2010)UnknownT = 8.1 × 10-5–4.0 × 10-3, Herzberger et al. (2010)120, Herzberger et al. (2010)LandauSedimentary and igneous rocks, Atkins (2013)UnknownUnknown159, Baumgärtner (2012)InsheimKeuper, perm, bunter sandstone, granite, Baumgärtner (2012)UnknownUnknown160, Baumgärtner (2012)Neustadt-GleweSandstone, BMU (2011)Well logging ∼0.25, lab ∼0.22, BMU (2011)Well logging Ki∼1.4 × 10-12, laboratory measurements Ki∼0.5 × 10-12, BMU (2011)99, Bracke (2012)UnterhachingLimestone, Dumas (2010)UnknownUnknown122 and 133, Richter (2010)Southampton***Triassic Sherwood Sandstone, Smith (2000)UnknownKm= 2.63 to 5.26 × 10-13, Atkins (2013), Southampton (2014c)76, Smith (2000)AltheimLimestone, City of Altheim (2014)0.08–0.28, ENGINE (2008b)T = 1 × 10-4–1 × 10-2, ENGINE (2008b)106, Bloomquist (2014)Birdsville***UnknownUnknownUnknown98, Ergon (2014)Penola***Sandstone, Panax Geothermal (2014)0.14, Hot Rock Limited (2010)Km= 5.96 × 10-15–1.2 × 10-14, Graaf et al. (2010)171.4, Graaf et al. (2010)
i permeability calculated from Darcy into m2 under assumption that
water temperature is only 10 ∘C and fresh water;
m Permeability calculated from transmissivity in case of known reservoir
thickness; *** Project indicated as HSA in the literature:
Southampton, Atkins (2013); Penola, Graaf et al. (2010); Birdsville, RBS
Morgans (2009).
Operational Characteristics of Hot Sedimentary Aquifers.
ProjectFlow rate [L s-1]Stimulation techniquesSeismic event (Richter scale)Type of power plantInstalled electrical capacity [MWe]Thermal capacity [MWth]Flow assurance problemSt. Gallen6 to 12, Brunner and Huwiler (2014)Chemical stimulation, Hirschberg et al. (2015e)3.5 M, Hirschberg et al. (2015d)None*0*0*Overly low flow rate; gas flow during production tests, Brunner and Huwiler (2014)Bruchsal28.5, Herzberger et al. (2010)UnknownMicroseismic, Rettenmaier (2012)Kalina, Herzberger et al. (2010)0.55, Herzberger et al. (2010)5.5, GtV (2014a)High salt contents (100 g/l); high CO2 concentration, Herzberger et al. (2010)Landau70 to 80, Baumgärtner (2012)No stimulation for producer; hydraulic for injector, Baumgärtner (2012)Microseismic (≤2.7 M), Baumgärtner (2012)ORC, Ganz et al. (2013)Up to 3.6, Baumgärtner (2012)2 to 5, Baumgärtner (2012)Well leakage resulting in groundwater contamination, Geothermie-Nachrichten (2014)Insheim60–85, Baumgärtner (2012)Yes, Baumgärtner (2012)M: 2.0 to 2.4 and Micro-seismic, Groos et al. (2012)ORC, Ganz et al. (2013)5, Ganz et al. (2013)Planned; ca. 6 available, Ganz et al. (2013); Baumgärtner (2012)UnknownNeustadt-Glewe35, Bracke (2012)UnknownUnknownORC, Bracke (2012)0, Ganz et al. (2013)7, GtV (2014a)High salt content, high gas concentration, Bracke (2012)Unterhaching150, Richter (2010)Acidizing, BMU (2011)UnknownKalina, Ganz et al. (2013)3.36, Richter (2010)38, Richter (2010)UnknownSouthampton***35, Atkins (2013)UnknownUnknownCHP plant, Southampton (2014b)2.7, Southampton (2014d)Heat 23; chilled water 10.5, Southampton (2014d)UnknownAltheim81.7, City of Altheim (2014)Chemical, Pernecker (1999), hydraulic, ENGINE (2008b)UnknownORC, City of Altheim (2014)1.0, Bloomquist (2014)12.4, City of Altheim (2014)Clogging by a mixture consisting of stone material and bentonite, Pernecker (1999)Birdsville***27, Ergon (2014)UnknownUnknownORC, Ergon (2014)0.08, Ergon (2014)Non scheduled, Ergon (2014)UnknownPenola***Unknown at this stageUnknownUnknownNone*59 MW (planned), Proactive Investors (2009)0*Initial mud damage during drilling, solved with acidizing, Graaf et al. (2010)
* See status;
*** Project indicated as HSA in the literature;
CHP – Combined Heat Power.
ORC – Organic Rankine Cycle.
Typical parameter ranges for petrothermal systems and hot
sedimentary aquifers.
ParameterPetrothermalHot sedimentary aquiferPermeability10-19–10-14 m210-15–10-12 m2Temperature130–400 ∘C76–171.4 ∘CWell depth1800–5000 m1280–4450 mRock typeIgneousSedimentaryStimulationHydraulicHydraulic and/or chemicalPorosity0.01–0.250.08–0.28Flow Rate4–50 L s-127–150 L s-1
Some explanation is necessary also for the Northwest Geysers project.
According to Walters (2013), this is an EGS demonstration project, launched
in 2009 with the main goal of enhancing the permeability of hot,
low-permeable rocks by means of thermal fracturing and creating an EGS
doublet capable of producing 5 MW. Garcia et al. (2012) refer to the high
temperature reservoir (HTR) of this EGS demonstration area as
non-hydrothermal HDR due to conductive temperature gradients and the project
not being part of the pre-existing HS. However, the same source
mentions presence of steam entries in the HTR in previously abandoned wells
after re-opening and deepening.
Hot sedimentary aquifers
The HSA database consists of 10 projects, whereof only 3 projects
(Southampton, Birdsville, and Penola) were actually indicated as HSA in the
literature. Since the term HSA was only invented recently and there is no
international standard for the categorization of such a geothermal system,
it has to be assumed that not all projects which are HSA are also indicated
as such in the literature. Therefore, based on the geological setting,
additional hydrothermal projects were added to the tables, where it can be
assumed that they are HSA projects.
One could argue about the classification of the St. Gallen project in
Switzerland. The project's aim was to use the naturally fractured Malm
formation in a depth of 4 to 4.5 km for an HS. However, during the
preparations for the production test, an unexpected high gas inlet in the
well required interventions to secure the well, which in turn resulted in
induced seismic activity. Therefore, the project was put on hold in order to
evaluate the gathered data from the production test and to readjust further
project steps (Geothermie Stadt St. Gallen, 2014). The encountered dissolved
natural gas in the well indicates that St. Gallen might actually be a
geo-pressured system. However, it is likely that the gas was coming from
deep-seated, highly faulted permo-carboniferous formations, which were
penetrated by deep drilling. Hirschberg et al. (2015a), who do not
differentiate between HS and HSA, classify St. Gallen as an HS. The analysed
data with low flow rates of only 6 to 12 L s-1, the existing gas inlet
in the well, the increased risk of induced seismicity, and limited financial
funds, eventually resulted in the abandonment of the project in May 2014
(Hirschberg et al., 2015c).
Results and discussionPetrothermal Systems
For almost all PSs, hydraulic fracturing was applied (with the exception of
Northwest Geysers, where thermal fracturing was conducted instead). For four
projects, stimulation was either not yet performed or no information about
it could be found in the public domain. For the projects Eden and United
Downs, it was only stated that stimulation will be applied in the future. In
the cases of Mauerstetten, Soultz-sous-Forêts, and Fjällbacka, not
only was hydraulic fracturing carried out, but chemical stimulation of the
near-wellbore region was also performed. Groß Schönebeck was the
only project where all three stimulation techniques (hydraulic, chemical and
thermal) were implemented.
The well depths of PSs vary widely within a range of 70 to 5000 m. However,
most projects are deeper than 1800 m, with exception of the three shallow
HDR systems Le Mayet, Falkenberg, and Fjällbacka, which were never
operational, but were only implemented for research and demonstration
purposes.
The temperature range of most of the PSs is 130 to 400 ∘C,
excluding the three abovementioned shallow systems and Rosemanowes, which
have a lower temperature range of 79 to 100 ∘C.
Rock types are usually crystalline and volcanic, with rocks such as granite
and granodiorite with exception of GeneSys Hannover (Bunter sandstone),
GeneSys Horstberg (sedimentary), Mauerstetten (limestone), and Northwest
Geysers (metasedimentary rocks).
For those nine projects where porosity values were available in the public
domain, the porosity shows a very wide range from 0.0025 to 0.25, depending
on the type of porosity. For example, the former value represents the
connected porosity, such as the fresh Soultz granite, and the highest value
is related to the altered rock in Soultz. However, most projects have
porosities in the range of 0.01 to 0.20.
Permeability values were available for 13 petrothermal projects: the lowest
value was found for Hijiori in Japan with 10-21 m2 and the highest
one for Newberry with 1.5 × 10-12 m2. Hence, the
permeability range is 9 orders of magnitude. In addition, the permeability
changed significantly for one project: in the case of Newberry, permeability
values from 10-18 to 1.5 × 10-12 were found in the
literature. The latter value is high enough for HSs, but considering the whole
permeability range together with other factors such as water not being
naturally available, the Newberry project should still be categorized as a
PS.
The production flow rate ranges from 4 to 50 L s-1. However, flow
rates as high as 120 L s-1 are expected in Litoměrice in the Czech
Republic and 150 L s-1 in the case of United Downs in Great Britain.
The most common flow assurance problems were high salt content, high fluid
losses, pressure drop, and corrosion.
Hot sedimentary aquifers
For only 5 of the 10 HSA projects, information could be found that
stimulation was applied to increase the permeability. For three projects
hydraulic fracturing was applied; for two projects both hydraulic and chemical
stimulation was conducted. Unterhaching in Germany was the only project
where chemical stimulation alone was applied. No information as to whether
stimulation techniques were conducted or not could be found for the
remaining three projects, which are indicated as HSA in the literature.
The well depth ranges from 1280 to 4450 m for the HSA projects. The
encountered rock types are mostly sandstone and limestone and other
sedimentary rocks; this is, for instance, the case for Bruchsal.
For Birdsville, no information about a rock type could be found. In the
cases of Landau and Insheim, igneous rocks were found in addition to
sandstone.
Porosity values were found for 3 of the 10 projects only, ranging from 0.08
to 0.28. For three projects, permeability values were given in the literature
with a range of 5.96 × 10-15 to
1.4 × 10-12 m2. The lowest value was found to be for the
Penola project in Australia, which was indicated as HSA in the literature.
Production flow rates of 6 to 150 L s-1 were found, whereof the
highest flow rate was encountered in Unterhaching and the lowest one in St.
Gallen (6 L s-1). As mentioned before, one of the reasons for
abandonment of the latter project was the overly low flow rates. Excluding St.
Gallen, the lowest flow rate is 27 L s-1.
The most common flow assurance problems were high salt content followed by
overly low flow rate and high gas concentration.
Numerical criteria for classification of deep geothermal potential
Table 7 shows the most typical ranges for different parameters such as
permeability, temperature, well depth, rock type, flow rate, stimulation
technique, and porosity for both PSs and HSA systems. These values are based
on the authors' database and are not meant to be exclusive. The values are
quite similar to each other and sometimes the parameter ranges are even
overlapping, suggesting that these quantitative parameters may not be used
to differentiate PSs from HSA systems.
Additional important parameters such as productivity index and the
productivity enhancement factor resulting from stimulation were unavailable
in the public domain for most of the projects.
Conclusions
Over the past 40 years, more and more geothermal system classifications
such as hot dry rock, enhanced or engineered geothermal systems, hot wet
rock, hot fractured rock, and HSA systems have been defined in order to
better characterise geothermal projects. However, some of these definitions
are deceptive, such as that for deep heat mining, which suggests that the
geothermal heat is mined and therefore not available anymore after the
geothermal production. Other definitions (such as those for EGS) are not
specific, as they provide only the information that the geothermal system was
somehow enhanced by some technical measure such as water supply, stimulation
of the reservoir etc.
This study recommends re-introducing three known definitions such as
petrothermal, hydrothermal, as well as HSA, and abandoning the ambiguous
terminology such as EGS. This threefold classification provides more
information compared to the defined EGS, which is unfortunately quite common
nowadays.
The definition of petrothermal already includes the information that not
enough water is contained in the subsurface and thus water has to be supplied
and re-injected after geothermal production. Hence, more than one well is
required for the project. However, this is not a distinctive criterion, as
most of HSs and HSA systems consist of two wells, with exception of Birdsville and
Southampton. In addition, the permeability is too low for the production well
and therefore hydraulic fracturing has to be applied as stimulation in order
to create an artificial reservoir. PSs, which sit in the first-proposed
category, indicate a conduction-dominated heat source. Based on the authors'
own database, typical permeability ranges are in the order of 10-19 to
10-14 m2 , the most common formation type is igneous such as
granite, well depth is typically more than 1800 m, and hydraulic
stimulation has to be applied in order to create an artificial reservoir. The
temperature of investigated petrothermal projects varies significantly with
typical ranges between 130 and 400 ∘C.
On the other hand, the definition of hydrothermal informs us that a
geothermal reservoir, with high enough permeability and sufficient water
supply, is already available and that (usually) no stimulation needs to be
applied, but the project might be improved if formation damage is reduced
via more careful drilling or the near-wellbore region is stimulated. HSs,
which occupy the second proposed category, can be managed with only one well
if the water is additionally used for other purposes such as balneology.
However, for sustainability and to maintain high pressure in the reservoir,
it might be required to re-inject the produced water, which would mean that
a second well would be necessary. Re-injection might also be necessary in
case of the water being saline to avoid environmental risks. HSs indicate a
convection-dominated or an advection-dominated heat source.
The third proposed category is HSA systems. These systems are similar to common and
conventional HSs with the difference being that the heat supply is
conduction-dominated and the heat source is similar to PSs, such as high heat
producing granites seen in the Australian HSA systems. The analysis of HSA
projects resulted in the following typical parameter ranges: permeability
from 10-15 to 10-12 m2, temperature from 76 to
171.4 ∘C, well depth between 1280 and 4450 m,; reservoir rock
types are typically sedimentary, such as sandstone and limestone.
Acknowledgements
The authors would like to acknowledge the financial support of the Open
Access Publishing Fund at Clausthal University of Technology to publish this
paper.Edited by: G. Beardsmore
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