Proceedings World Geothermal Congress 2010

Bali, Indonesia, 25-29 April 2010

Quantifying Risk in Geothermal Development – High Enthalpy and Low Enthalpy Cases

Miklos Antics and Pierre Ungemach

GPC IP, Paris Nord 2, Business Park, 165, rue de la Belle Etoile, B.P. 55030, 95946 ROISSY CDG CEDEX
m.antics@geoproduction.fr , pierre.ungemach@geoproduction.fr

Keywords: Geothermal energy, exploration, development, commercial insurance market, except for a few recent cases
risk assessment in Germany (e.g. Unterhaching project by Munich Re), is
not yet prepared to fit the geothermal risk insurance
ABSTRACT business into a standard product line because of the lack of
adequate size of market demand or nature of the unique risk
Like most resource harnessing ventures, geothermal energy
element which may not be "commercially insurable" with
shares both exploration and exploitation risks. Resource
conventional insurance methodologies. In order to bridge
discovery and confirmation is carried out mainly by
this gap, the World Bank has launched the GeoFund and
activities, among which are drilling operations, which incur
ARGeo programs.
high initial costs. These activities display relatively high
risks and are the major barrier to accelerated development While risk assessment is a complex procedure, relying on
worldwide. Once the resource is proven, it mobilizes surface exploration, and shallow drilling, it is necessary to
important financial resources for geothermal production set up a series of numerical criteria which could lead to the
infrastructure development, power plant and transmission definition of the success or failure when proceeding to the
line construction. Both the risk and high upfront capital cost phase of resource confirmation by drilling.
make geothermal ventures less attractive to conventional
financing schemes. Risk assessment addresses both financial issues and
reservoir management strategies.
To help accelerate geothermal development a number of
national governments have created risk mitigation As regards financial risks incurred at exploration level, the
instruments such as loan guarantees, guaranteed cost World Bank has produced a comprehensive overview
sharing of unsuccessful drilling projects and insurance summarised in Fig. 1 risk vs. expenditure chart. It shows
programs and incentive measures to help cover the upfront quite clearly that, in the compiled project areas located
costs of exploration drilling and power plant construction, chiefly in East Africa and Pacific Rim countries, the
in addition to tax cuts, mandated power purchase programs exploratory drilling risk could be minimised thanks to the
and even feed in tariffs to provide a market for geothermal filtering out of the less attractive, most risky, prospects
power and heat. identified in the preliminary reconnaissance stages, thus
leading to a 80% drilling success ratio.
This paper presents two case studies. The first addresses the
high enthalpy, power generation case, in the exploration After project commissioning and start-up, the first years of
phase where the main problems of quantifying success- exploitation provide the reservoir/production engineers and
failure risk of exploratory drilling are addressed and a management with additional clues on future development
numerical criterion to assess the well output from well alternatives.
testing figures proposed. The second study deals with a
large geothermal district heating (GDH) scheme, where the The latter are usually investigated by integrating all
drilling success ratio approached 100% (one recorded full pertinent data – reservoir characteristics, surface heat/power
and two partial failures out of around 100 wells) whereas loads, well productivities, plant performance, make-up well
exploitation of the low temperature deposits showed, in the drilling and plant production schedules, economic
early stages, severe technical and nontechnical parameters – into reservoir and economic models to assess
shortcomings leading to frequent, prolonged well ultimately well/field productivities and project economic
shutdowns and, ultimately, to their abandonment. A value.
quantified risk prognosis was at a stage projected 15 years
Reconnaissance
ahead which later proved relevant. High

1. INTRODUCTION
Many of the countries with geothermal resources have not
fully exploited their potential because of a variety of
Exploration
barriers (regulatory, policy, fiscal, technical, geographical, MT&
Risk

Geochemistry
etc.). Geothermal risk mitigation can be achieved by the
following key elements: establishment of reliable
geological data developed by state-of-the-art geoscientific Exploration Drilling
assessment methodologies, mobilization of the latest Feasibility Study&
exploration and drilling technologies, and availability of a Financial Closure
risk insurance product on the insurance market in Low
combination with support from government, bilateral and 0.1 0.5 1 5 10
Expenditure (US$ million)(Log Scale)
multilateral financial resources.

Most of the existing geological risk mitigation instruments Figure 1: Expenditure and risk prior to geothermal
have been supported by government funding. The development (source World Bank)
1
Antics and Ungemach

However, the decision making process is clouded by the The geothermal well output test programme should record
many uncertainties affecting model inputs. A purely for several values of wellhead pressure the following
deterministic or probabilistic approach could be misleading. parameters:
A thorough coupled deterministic-probabilistic approach − total mass flow rate
could prove more relevant but by all means unrealistic − temperature of single phase and/or quality of flow
considering the huge numbers of model runs involved, (enthalpy or dryness)
indeed a tedious and costly exercise if manageable ever, − chemical composition (constituents) of the phases
unless kept within reasonable limits by adequate
constraints. In order to provide a good assessment of the well
performance, it is also important to keep record of:
Acuna et al. (2002) review the case of a liquid-dominated − extreme pressure values
field in the Philippines where a strategic decision is to be − description of the test, reason for selecting a
taken as to whether a deep, poorly produced reservoir particular method
underlying the presently exploited shallow seated reservoir − history of the well (drilling records)
should be developed or not.
− correlation to other measurements, e.g. downhole
pressure measurements, interference with wells
In order to overcome the aforementioned limitations the
nearby
authors suggest an interesting methodology outlined
hereunder.
Any method is used for testing; it is governed by the well
characteristics, the resources available and the accuracy. It
• up to ten different exploitation strategies were
is recommended to carry out several measurements using
selected;
the same method and check the results with another
• the economic model calculates the project NPV
method.
(net present value) probability distribution. The
uncertainty for each relevant parameter is Available methods for flow measurements are:
described by the most likely (50% probability – − Orifice plate (sharp-edged orifices in combination
P50); pessimistic (10% probability – P10) and with a cyclone separator)
optimistic (90% probability – P90) values, o single phase measurements – pressure
defining the parameter cumulative probability drop across the plate associated with
function; temperature measurement
• in order to reduce the number of reservoir o two phase measurements – phases must
simulation runs for the P10, P50, P90 be separated
uncertainties allocated to the parameters for each − Calorimeters – not very appropriate for
exploitation strategy, the model results were superheated steam and hot water, most adequate
synthesised, after preliminary model tests, by for two-phase flow mixtures
using a polynomial approximation to key output
data, and four cases reflecting changes in steam The flow results observed directly are used to calculate
extraction rates and make up well drilling from the steam tables, the mass and heat flow enthalpy and
schedules constrained by existing well dryness fraction.
deliverabilities.
The isentropic power is equal to:
The polynomial approximation of reservoir performance (as
well deliverability vs. cumulative produced steam) proved
rewarding in that it enabled integration of this key
Wis = q v ∆his (1)
uncertainty into the probabilistic economic model to assess
the risk impact on project NPV. ∆his = (hv − hc ) − Tc (S v − S c ) (2)

2. THE HIGH ENTHALPY CASE

where qw is the steam (vapour) mass flow rate, ∆his is the
The resource confirmation phase is accomplished by a
series of deep exploratory drill holes aiming at determining isentropic enthalpy drop, h is the specific enthalpy, S is the
the potential of the resource which ultimately leads to the entropy, T is the temperature and v, c are subscripts
design capacity of the power plant. referring to inlet vapour and condenser respectively.

After the drilling phase is completed, the wells are The steam mass flow is equal to:

q t (ht − h f )
thoroughly tested.
qv = (3)
2.1 Methodology
hv − h f
Drilling records and further downhole measurements in a
closed well give a rough indication of the output to be
where qt is the total flowrate at wellhead, h is the specific
expected, and therefore the method of flow measurement
enthalpy and the subscripts t, v and f refer to wellhead (total
that is the most adequate.
flow), vapour and separated liquid respectively.
The observation of the wellhead pressure over a period of
There is an optimum flash temperature. If the latter
time provides useful indication of any changes in either
decreases, vapour flow will increase but at the expense of
quantity or quality of flow.
the isentropic enthalpy drop, which will diminish.
The well measurement programme must comprise a full
The maximum useful work is given by:
range of output testing at intervals of several days, linked
together in time by wellhead pressure reading, preferably
automatically recorded.
2
 Antics and Ungemach

max
Wnet = −(∆H − T0 ∆S ) ]
Tgfout

Tgfin
= −∆B (4)
accurate enthalpy figures if the boiling takes place within
the well.

However in many geothermal fields boiling takes place

where ∆B is commonly referred to as change in outside the well. Therefore downhole temperature
availability (Tester, 1976). For a given fluid and a fixed T0 measurements or geothermometers do not give correct
value of the enthalpy of the steam-water mixture entering
and a reinjection temperature Tgfout which has a minimum
the well. In such cases a modified version of the Russell-
value T0, the maximum work (per unit weight of geothermal James method has to be applied. The modification is based
fluid or per unit heat transferred) possible from an ideal on measuring the flow rate of 100°C geothermal water from
reversible process is a function of only Tgfin , the geothermal the silencer after separation from the steam fraction. The
total flow and enthalpy from the discharging well can be
source temperature. A plot of this value is given in fig. 2. extracted by iteration from the Russell-James empirical
formula.

2.3. Power potential estimate

The process described here (DiPippo, 2008) is a single flash
cycle where the geothermal fluid is wet steam (mixture of
water and steam) at the wellhead. The analysis presented
here is based on fundamental thermodynamic principles,
namely the principle of energy conservation (i.e. First Law
of thermodynamics) and the principle of mass conservation.
Figure 3 shows the basic operating principles of the single
flash process.

S
4
T GE CT
5
dry
4 steam
3 P2
saturated
liquid
C
IP
P1
6
1
w et
steam

Figure 3: Single flash process schematics

The well (1) is producing wet steam which is separated via
a separator (S). The saturated liquid phase is reinjected
(waste heat disposal) and the dry steam flows directly to the
Figure 2: Maximum useful work ( ∆B ) plotted as a turbine. After expansion in the turbine (T), the steam is
function of geothermal fluid temperature for condensed in the condenser (C) and reinjected together with
saturated steam and saturated water sources the saturated liquid collected at the separator outlet.
(Tester, 1976)
The processes undergone by the geothermal fluid are best
2.2. Enthalpy measurements viewed in a thermodynamic state diagram in which the fluid
In a paper issued in 1962 Russell James described an temperature is plotted on the ordinate and the fluid specific
empirical method to measure flow rate from a discharging entropy is plotted on the abscissa. A temperature-entropy
high-temperature well. James’s experiment showed that diagram is presented in fig. 4.
“the critical discharge pressure can be used to measure the
T critical point saturation
mass flow or the energy flow of steam-water mixture
1 curve
passing through pipes”. Based on the experiment the compressed
flash superheated
following empirical equitation describes the relation liquid
2 vapor
between the various measured components: 3 4
separator
liquid + turbine
M * H 1.102
= 0.184 (5)
vapor

3600 * A * p c0.96 6
5s 5
7

where M is the total flow (t/h), A is the cross-section area of S

the discharging pipe (cm2) , pc is the critical pressure (bar a)
and H is the enthalpy (kJ/kg). To use this formula to Single flash cycle. Temperature vs entropy
calculate flow rate from discharging well, the enthalpy must
be known. Downhole temperature measurements can yield Figure 4: Temperature vs. entropy diagram of the single
flash cycle (DiPippo, 2008).

3
Antics and Ungemach

The main processes undergone by the geothermal fluid are: affected by the amount of moisture that is present during
flashing (1-2), separation (2-3 liquid; 2-4 steam), expansion the expansion process; the higher the moisture, the lower
in the turbine (4-5) and, condensing (5-6). the efficiency. This effect can be quantified by using the so-
called Baumann rule which says that a 1% average moisture
Flashing causes a 1% drop in turbine efficiency. Since geothermal
The cycle of thermodynamic processes (DiPippo, 2008) turbines generally operate in the wet region, we must
begins with the geothermal fluid under pressure at state 1, account for the degradation in performance. Adopting the
close to the saturation curve. The flashing process is Baumann rule, the isentropic efficiency for a turbine
modelled as one at constant enthalpy, i.e. isenthalpic operating with wet steam will be given by:
process, because it occurs steadily, spontaneously,
essentially adiabatically, and with no work involvement.
⎡ x 4 + x5 ⎤
We also neglect any change in the kinetic or potential η tw = η td × ⎢ ⎥ (11)
energy of the fluid that undergoes flash. Thus we may ⎣ 2 ⎦
write:
Where the dry turbine efficiency, ηtd, may be assumed
h1 = h2 constant, (85%):

Separation ηtd=0.850 (12)

The separation process is modelled as one at constant
pressure, i.e. isobaric process, once the flash has taken From fig. 4, it is clear that the quality at the turbine outlet,
place. The quality or dryness fraction, x, of the mixture hat state 5, depends on turbine efficiency. State 5 is determined
forms after the flash, state 2, can be found from: by solving eq. 8 using the turbine efficiency and the fluid
properties at state 5s, the ideal turbine outlet state, which
are easily calculated from the known pressure and entropy
h2 − h3
x2 = (6) values at state 5s. The ideal outlet enthalpy is found from:
h4 − h3
⎡ s − s6 ⎤
by using the so-called lever rule from thermodynamics. h5 s = h6 + [h7 − h6 ] × ⎢ 4 ⎥ (13)
This gives the steam mass fraction of the mixture and is the ⎣ s 7 − s6 ⎦
amount of steam that goes to the turbine per unit total mass
flow into the separator. where the entropy term, by itself, gives the fluid outlet
dryness fraction for an ideal turbine. When the Baumann
Turbine expansion rule is incorporated into the calculation, the following
The work produced by the turbine per unit mass of steam working equation emerges for the enthalpy at the actual
flowing through it is given by: turbine outlet state:

wt = h4 − h5 (7) ⎡ h6 ⎤
h4 − A⎢1 − ⎥
assuming no heat loss from the turbine and neglecting the
h5 = ⎣ h7 − h6 ⎦ (14)
changes in kinetic and potential energy of the fluid entering A
and leaving the turbine. The maximum possible would be 1+
generated if the turbine operated adiabatically and h7 − h6
reversibly, i.e. constant entropy or isentropically. The
process shown in fig. 4 from 4-5s is the ideal process. The where the factor A is given by:
isentropic turbine efficiency, ηt, is defined as the ratio of the
actual work and the isentropic work, namely:
A ≡ 0.425(h4 − h5 ) (15)

h4 − h5
ηt = (8) The above equations are valid if it is assumed that the
h4 − h5 s quality at the turbine inlet, x4=1, i.e. the steam at the turbine
inlet is saturated steam. If x4<1 eq. 9 becomes:
The power developed by the turbine is given by:
⎡ h6 ⎤
W& t = m& s wt = x 2 m& total wt h4 − A⎢ x 4 − ⎥
(9)
⎣ h7 − h6 ⎦
h5 = (16)
A
This represents the gross mechanical power developed by
1+
the turbine. The gross electrical power will be equal to the h7 − h6
turbine power times the generator efficiency:
Based on the methodology described above, a spreadsheet
W& e = n gW& t (10) was developed. In order to calculate enthalpies and
entropies for the thermodynamic cycle, steam tables were
All auxiliary power requirements for the plant must be implemented based on the IAPWS-IF97
subtracted from this to obtain the net, saleable power. These (http://www.cheresources.com/iapwsif97.shtml).
so-called parasitic loads include all pumping power, cooling
tower fan power, and station lighting. After completion of the well drilling, at least three months
must pass before necessary measurements can be carried
Before eq. 8 can be used computationally, it must be out to deem if a well meets the predefined success criteria.
recognised that the isentropic efficiency of a turbine is Of these three months, one is reserved for thermal recovery
4
 Antics and Ungemach

of the well and for setting up wellhead and flow-test exploration/step out/development drilling, which enabled to
equipment. As soon as the well has heated up and the reliably assess the geothermal source reservoir prior to
wellhead equipment is in place, discharge will be started to development. This resulted later in a 95 % geothermal
last for the remaining two months. drilling success ratio according to the success/failure
criteria set forth by the ad-hoc geothermal steering
Chemical monitoring of geothermal wells is a standard committee. Second, the coverage by the State of the
practice. It is intended to operate a well at as low wellhead geological risk amounting to 80 % of the costs incurred by
pressure as possible - for maximizing the output. A the first, assumed exploratory, drilling.
controlling factor for deciding on such a minimum “safe”
wellhead pressure is the downhole scaling potential of the As a result of the high drilling success ratio, the so-called
geothermal fluid. Low operating pressure may lead to short-term provisional fund could be allocated, at a later
precipitation and scaling in the borehole and surface stage, to the so-called long-term exploitation mutual
pipelines. In slightly mineralized geothermal systems the insurance budget line.
precipitation of silica is the controlling factor. In this case
the wells can be operated safely at wellhead pressures as 3.2. Exploitation risks
low as 5 bars-a. In the case of highly saline geothermal
Those could not be estimated from scratch. A (long-term)
fluid, operating well head pressure lower than 20 bars-a will
fund initially financed by the State was created in the 1980s
lead to a rapid downhole scaling in the form of metal
to cope with the hazards induced by the exploitation of the
sulfide minerals and amorphous metal silica deposits. This
geothermal fluid. Later this could be supplied by operators’
will drastically reduce the well output. Scaling in the
subscriptions.
borehole can cause the reduction of total flow.
It soon became obvious that the, initially overlooked,
The predefined success criteria will be the minimum power
hostile thermochemistry of the geothermal fluid provoked
potential of the well for which the project will be economic.
severe corrosion and scaling damage to casing and
equipment integrities resulting in significant production
3. THE LOW ENTHALPY CASE losses. A prospective survey commissioned in 1995 aimed
The Paris Basin geothermal district heating projects and at assessing the exploitation risks and related restoration
accomplishments faced five levels of risks, exploration costs projected over a 15 year well life. This exercise was
(mining, geological), exploitation (technical, managerial), applied to thirty three doublets. The governing rationale,
economic/financial (market, institutional, managerial), developed by Ungemach (2002), consisted of (i) listing
environmental (regulatory, institutional) and social potential and actual, technical and nontechnical, risks
acceptance (image) respectively. ranked and weighted as shown in table 4, and (ii)
classifying risks according to three levels (1 : low, 2 :
3.1 Exploration risk medium, 3 : high), each subdivided in three scenario
colourings (A : pink, B : grey, C : dark) regarding projected
The mining/geological risk could be minimized thanks to
workovers deadlines and expenditure. This analysis led to a
two favourable factors and incentives. First, the existence of
symmetric distribution, i.e. eleven sampled sites per risk
a dependable hot water aquifer (Dogger limestones) of
level, each split into three (A), five (B) and three (C)
regional extent evidenced thanks to previous hydrocarbon
scenario colourings.

Table 1: Summary of risk factors

Risk description Nature Ranking Status Remarks
weight
Last known casing Technical 1 Fine Residual steel thickness >75% nominal WT
status 1 before treatment
2 Fair Residual steel thickness >50% nominal WT
before treatment
3 Bad Residual steel thickness <50% nominal WT
before treatment
Damaging kinetics Technical 1 Low Corrosion rate <150µm/an before treatment
1 2 Medium Corrosion rate >150µm/an before treatment
3 High Corrosion rate >300µm/an before treatment
Chemical inhibition Technical 1 High Provisional statement
efficiency 1 2 Low Provisional statement
Casing lining Technical 1 Full No diameter restrictions
opportunities 1 2 Partial Some diameter restrictions
3 None Total diameter restrictions
New well drilling Technical 1 Long term > 20 yrs
expectation 1 2 Medium term > 10 yrs
3 Short term < 10 yrs
Other Non 1 favorable
technical 2 hostile
3

5
Antics and Ungemach

The next step applied the workover/repair unit costs to the and 1999. This situation incited several operators to pass
concerned wells, required to forecast the workover types cogeneration contracts and public and private JV, a
and relevant schedules, thus leading to the synthetic compromise deemed satisfactory to remain competitive and
expenditure breakdown summarized in table 5. This secure the survival of the geothermal heating grid
evaluation illustrates the paradox between competing (if not regardless from any environmental considerations
conflicting) well heavy duty maintenance strategies, i.e. whatsoever.
repeated repair of damaged infrastructures vs. re-drilling/re-
completion of new wells reflected by scenarios 2 (A, B, C) In 2008, both a sharp increase of oil prices and natural gas
and 3 (A, B, C). Here, the optimum, in terms of investments tariffs and growing environmental concerns (global
but not necessarily cash flows, is represented by scenarios warming and related climatic disasters) modify again the
2B and 3B, case 2C displaying definitely the worst profile. energy panorama. Taxation of greenhouse gases becomes a
realistic working hypothesis for the future, limiting the
uncertainty margin of geothermal heating prices. In this
Table 2: Recapitulation of provisions (sinking funds) perspective a 45 €/MWht selling price appears a reasonable
required by heavy-duty well workover/repair/redrilling threshold safeguarding the economic feasibility of most
over 15 years (cost per well/year, 103 EUR) operating grids.
SCENARIO A B C
Risk level 1 3.4. Environmental risks
Yearly provision 74 99 125 Damages caused to the environment by casing leaks,
Risk level 2 uncontrolled well head blowouts and workover operations
Yearly provision 203 193 255 have been minimized. Limitation of the environmental risks
(229) (221) (277) is to be credited to the periodical (quarterly) doublet
Risk level 3 monitoring and casing inspection logging imposed by the
Yearly provision 222 (241) 201 (213) 206 (277) competent mining/environmental authority (DRIRE) and
TOTAL 173 (186) blowout control/waste processing equipments currently
(Weighted average) operated by the industry.

3.5. Social acceptance

In conclusion, an average provision (fiscally deductible) of Geothermal energy, particularly direct uses of low-grade
0.19 million euros (around 186,000 €/yr) has been heat, has a structural image problem. The product and the
recommended to cope with future exploitation hazards
recovery (heat exchange) process remain somewhat
resulting in a 12 % increase of initially anticipated OM
mysterious or esoteric to the public as opposed to obvious,
costs. Loose management remaining the exception, visible, competing solar, wind and fuel sources. For many
managerial risks could be reliably regarded as minimized in years indifference, at the best, was the prevailing attitude.
year 2000. Surprisingly, the risk model matched
In the early days of geothermal development (the infancy
expectations as of late 2002.
stage), it was regarded as a poorly reliable and costly,
occasionally, environmentally hazardous technology.
3.3. Economic/financial risks Nowadays mature engineering and management and
They represent a major uncertainty owing to a somewhat growing environmental (clean air) concerns have gained
unpredictable, if not chaotic, energy market and pricing wider acceptance by the public of the geothermal district
context in which geothermal heat must prove competitive. heating alternative. Still, image building efforts need to be
This is indeed a difficult challenge bearing in mind that persued to popularize the technology.
geothermal district heating grids are structurally, especially
under Paris Basin conditions, strongly capital intensive and 3.6. Success/failure criteria of the SAF short term
financially exposed, in case of low equity/high debt ratios, a guarantee
distinctive attribute of Paris Basin loan policies. An example of quantified risk occurrence and coverage
criteria for a GDH deep drilling application, is illustrated in
At the time, in the wake of the second oil shock, most
geothermal district heating doublets were commissioned, fig. 5. Here, the success/failure zones are delineated by two
oil prices, dollar exchange and inflation rates stood high hyperbola Q(To-Ti)=C, with Q well discharge, To and Ti
well head formation and grid rejection temperatures and C a
and accordingly feasibility projections shaped very
constant defined by a given internal rate of return (success
optimistic, in spite of their fragile financial planning. A few
years later, these trends were totally reversed. This, added criteria) and zero net present value (failure threshold). The
to the dramatic technical, financial and managerial algorithm used to calculate are presented in eq. The points
characteristic to the full success curve are described in eq.
problems undergone by most geothermal doublets,
17. Similarly those characterising failure are described by
endangered grid operation to a stage the abandonment of
the geothermal district heating route was envisaged. These eq. 18.
difficulties could be overcome at the expense of the shut in
of technically irreparable/economically infeasible doublets
and rationalizing exploitation technologies and
management of the remaining 34 doublets operated to date.

The economic/financial risks were controlled thanks to debt

renegotiation, technological/managerial improvements and
stable heat selling prices agreed in long term and users
subscription contracts. These contracts, passed in the mid
1980s, expired in the late 1990s/early 2000s. Negotiation of
these contracts was clouded by depleted, downward
trending, deregulated energy prices prevailing in years 1998

6
 Antics and Ungemach

Numerical application:
Flow rate
INV=12 106 €
Full OMC= 5 105 €
Success n=20 years
nh=8256 hr/yr
r=5% (total failure)
QM
Partial r=10% (total success)
Success Full equity (zero debt)
Qm (failure)
Subsidies=25% INV
c=35.45/MWt
Total
Ti=45.4°C
Failure
Full success
Q=299 m3/h ; no subsidy, c=35 €/MWht
Twh=70°C Ti=45°C
Tm TM Temperature Twh=65°C Ti=40°C
Q=200 m3/h ; 25% subsidy, c=45 €/MWht
Twh unchanged
Figure 5. Success/failure curves
Total failure
Full success: Q=246 m3/h ; no subsidy, c=35 €/MWht
Twh=70°C Ti=45°C
(
Q Twh − Ti ) = 1.161 1⋅ nh ⋅ c ⎡⎢ A ⋅ INV + OMC + INV
n ⎥
⎤ 17 Twh=65°C Ti=40°C
⎣ ⎦ Q=155 m3/h ; 25% subsidy, c=45 €/MWht
Total failure: Twh unchanged
⎛
Q′⎜ T
⎞= 1 ⎡ INV ⎤
− Ti ⎟ 1.161 ⋅ nh ⋅ c ⎢ A′ ⋅ INV + OMC +
⎥⎦
18 CONCLUSIONS
⎝ wh ⎠ ⎣ n
Geothermal energy shares both exploration and exploitation
Where: risks.
Q, Q’ = flowrate (yearly average) (m3/h)
Twh = production wellhead temperature (°C) Two case studies were presented. The first addresses the
Ti = injection temperature (yearly average) (°C) high enthalpy, power generation case, in the exploration
r (1 + r )
n phase where a numerical criterion to assess the well output
A= 19 from well testing figures was proposed. The second study
(1 + r )n − 1 dealt with a large geothermal district heating (GDH)
scheme, where the drilling success ratio approached 100%.
r ' (1 + r ')
n
The success/failure curves and numerical criteria set out by
A' = 20
(1 + r ')n − 1 SAF were presented. Exploitation of the low temperature
deposits showed, in the early stages, severe technical and
INV = capital investment (€) non technical shortcomings. A quantified risk prognosis
OMC = operation and maintenance costs (€/yr) was at a stage projected 15 years ahead which later proved
c=heat selling price (€/MWht) relevant.
n = project lifetime (years)
nh = number of operating hours per year
r, r’ = discount rates REFERENCES
World Bank: Geothermal Energy. An Assessment.
www.worldbank.org, 2003.
Acuna, J. A., Parini, M. A. and Urmeneta, N. A.: Using a
Large Reservoir in the Probabilistic Assessment of
Field Management Strategies. Proceedings of the 27th
Workshop on Geothermal Reservoir Engineering,
Stanford University, Stanford, CA, January 28-30,
2002.
DiPippo, R.: Geothermal Power Plants: Principles,
Applications, Case Studies and Environmental Impact.
Second Edition, Elsevier, pp. 91-94, 2008.
Ungemach, P. Insight into Geothermal Reservoir
Management. European Summer School on
Geothermal Energy Applications. Text Book. Oradea,
Romania, April 26-May 5, 2001. Rosca, M. Edt., pp.
43-76. 2001.