Available online at www.sciencedirect.com
Geothermics 37 (2008) 444–466
Management of the Balcova–Narlidere geothermal
reservoir, Turkey
Niyazi Aksoy a,∗ , Umran Serpen b , Şevki Filiz c
a
Dokuz Eylül University, Torbali Technical Vocational School of Higher
Education, 35120 Torbali-Izmir, Turkey
b Istanbul Technical University, Petroleum and Natural Gas
Engineering Department, 34469 Maslak-Istanbul, Turkey
c Dokuz Eylul University, Geological Engineering
Department, 35160 Buca-Izmir, Turkey
Received 12 January 2007; accepted 21 December 2007
Available online 7 March 2008
Abstract
The 2000–2005 management and field monitoring procedures at the Balcova–Narlidere geothermal field,
Turkey are described. During that period, fluid production increased from 140 to 300 kg/s and the living
space being heated grew from 0.64 to 1.6 million m2 . The shallow (depth <160 m) injection done between
1996 and 2002 cooled the fluids being produced; the hydraulic connection between shallow production
and injection wells was confirmed by tracer tests. Two deep injection wells were drilled to mitigate the
problem and to increase injection capacity. Because net fluid extraction was reduced, reservoir pressure
drawdown was controlled. Wells drilled after 2000 indicated that the eastern portion of the field had greater
potential and yielded higher temperature fluids. After testing and establishing well flow performance, pump
capacities were matched to production well capacities. Mineral scaling in wells and surface installations
was brought under control reducing the annual cost of inhibitors by about US$100,000. Since all production
and injection wells are located near the Agamemnon fault zone and because the capacity of the district
heating system is being continuously increased, there is the risk of thermal breakthrough in the production
wells.
© 2007 Elsevier Ltd. All rights reserved.
Keywords: Reservoir management; Tracer test; Cooling; Injection; Reservoir monitoring; Scaling; Balcova; Narlidere;
Turkey
∗
Corresponding author. Tel.: +90 232 853 1828; fax: +90 232 853 1606.
E-mail address: niyazi.aksoy@deu.edu.tr (N. Aksoy).
0375-6505/$30.00 © 2007 Elsevier Ltd. All rights reserved.
doi:10.1016/j.geothermics.2007.12.003
N. Aksoy et al. / Geothermics 37 (2008) 444–466
445
Nomenclature
A
b
Cr
Cw
h
k
M
Mi
Q
q
qi
t
Ti
T0
Tp
u
x
fracture (flow channel) sectional area (m2 )
fracture (flow channel) width (m)
rock specific heat (J/(kg ◦ C))
water specific heat (J/(kg ◦ C))
fracture (flow channel) height (m)
thermal conductivity of reservoir rock (J/(m ◦ C))
injected tracer mass (kg)
recovered tracer mass (kg)
fluid production rate (m3 /s)
fluid flow rate in the fracture (m3 /s)
fluid injection rate (m3 /s)
time (s)
injection temperature ( ◦ C)
undisturbed formation temperature ( ◦ C)
predicted temperature ( ◦ C)
mean fluid flow velocity (m/s)
distance (m)
Greek letters
β
variable, see Eq. (1b)
κ
rock thermal diffusivity (m2 /s)
rock density (kg/m3 )
ρr
ρw
injected water density (kg/m3 )
φ
rock porosity
1. Introduction
About 200 hot-spring areas have been identified in Turkey, most associated with low- or
medium-enthalpy geothermal systems. Hot waters from 20 of these areas are being utilized
to heat 6 million m2 of living space in 13 cities and towns, as well as 120 ha of greenhouses.
The country’s direct use capacity for district heating is 253 MWt (Serpen, 2005). There is
also widespread use of these thermal waters in balneotherapy, spas and traditional hot-spring
facilities.
With respect to electricity production based on geothermal resources, in addition to the
17.4 MWe Kizildere power plant, which has been operating since 1983, the 7.3 MWe Dora-1
plant came on line in 2006, so that the present (November 2007) total installed capacity for
geothermal power generation in Turkey amounts to 24.7 MWe. In addition, two power plants
with a total capacity of 52 MWe are currently under construction; i.e. a 45 MWe double-flash
plant at Germencik and a 7 MWe binary unit that will use wastewaters from Kizildere flash
plant. A second unit at Salavatli, the 9.5 MWe Dora-2 binary power plant is in a planning
stage.
It is expected that in the near future there will be rapid growth in geothermal power production
and greenhouse heating. On the other hand, geothermal district heating capacity may not grow or
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N. Aksoy et al. / Geothermics 37 (2008) 444–466
even decrease because these projects are becoming less attractive due to implementation problems
and because of competing fuels such as natural gas. The primary problems of Turkey’s geothermal
development for heating projects are: (1) the relatively small energy capacity of the fields (i.e. the
danger of over-exploiting them), (2) reservoir cooling and drawdown problems and (3) possible
pollution associated with geothermal development. However, these problems can be solved by
effective and comprehensive reservoir management practices.
In this paper we discuss the results of well drilling, well workover and tracer test activities,
and of water chemistry and reservoir monitoring studies carried out at the Balcova–Narlidere
geothermal (BNG) field between 2000 and 2005.
2. Overview of the field
The Balcova–Narlidere geothermal (BNG) field is located on the shore of the Aegean Sea
within the limits of Izmir (Fig. 1), Turkey’s third largest city. The population in the BNG area is
about 100,000; many living in multi-story buildings. The field supplies hot fluids to the presently
largest geothermal district heating system in the country.
The geothermal district heating project at Izmir (Fig. 2) started in 1996; in 2000, 0.64 million m2
of indoor space corresponding to 5489 houses, hotels, schools and a university hospital and campus
were being heated with geothermal energy (Toksoy et al., 2003). By the end of 2005, the heated area
had increased to 1.6 million m2 , and, in addition, the project supplied heat to 10 ha of greenhouses;
the most important milestones of the BNG project are given in Table 1. In November 2007 the
total heated area (excluding greenhouses) was 1.9 million m2 .
The BNG area is located in the extensively exposed Upper Cretaceus Izmir Flysch structure;
the geothermal field is at the northern edge of the Seferihisar Horst. South of the geothermal field,
talus breccias cover the northern flank of the horst, while more recent sediments infill the Izmir
Bay further north (Fig. 1). The stratigraphic sequence of the area generally consists of Upper
Cretaceous Izmir Flysch, Miocene sediments, Pliocene volcanics, Quaternary talus breccias and
alluvium.
The Izmir Flysch, the most extensive outcropping formation of the region, is composed of
a variety of rocks (i.e. sandstones, clayey schists, phyllites, limestones, limestone olistoliths,
granodiorites, serpentinites and diabases). The wells in the BNG area are mainly completed in
lightly metamorphosed sandstones, clays and siltstones of the Izmir Flysch sequence (Öngur,
2001; Serpen, 2004).
The hot waters recharging the BNG system move through a major, about 2-km long, fracture
zone associated with the Agamemnon fault (Fig. 3). From this zone, the thermal waters flow mainly
into two permeable horizons, one in the alluvium located in the upper 100 m of the system, and the
other in ill-defined, more permeable (i.e. fractured) layers of the Izmir Flysch formation between
300 and 1100 m depth. These two permeable zones correspond to the shallow (upper) and deep
(lower) reservoirs of the BNG field.
Satman et al. (2002) indicated that fluid injection done in shallow (depth <160 m) wells was
not an effective operation and recommended it to be done deeper and at the edge of the field.
Based on a natural-state model, these authors estimated that (1) the natural fluid recharge was
about 50 kg/s, (2) the total heat input to the system was in the 24–33 MWt range and (3) the
temperatures in the BNG system increase toward the east.
Sarak et al. (2005) simulated the behaviour of the field using lumped-parameter (one- and
two-tank) models and predicted its future performance based on different production/injection
scenarios. The best match with measured water levels was obtained by the one-tank model, which
N. Aksoy et al. / Geothermics 37 (2008) 444–466
447
Fig. 1. (Top) Location of the main geothermal areas of western Turkey. 1, Balcova–Narlidere; 2, Germencik; 3, Salavatli
Sultanhisar; 4, Kizildere. (Middle) Schematic geologic map of the Balcova–Narlidere area showing location of wells and
springs in the geothermal field (see Fig. 3 for further details). (Bottom) Aerial view of the dashed rectangular area in the
middle panel, showing part of the city of Izmir.
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Fig. 2. Schematic diagram of the Balcova–Narlidere geothermal district heating system.
gave for the BNG field a recharge constant of 776.7 (±25.3) kg/MPa s and a storage capacity of
8.25 (±0.92) × 108 kg/MPa.
Early geophysical surveys by Tezcan (1962) and Ercan et al. (1986) covered an area extending from Agamemnon Hot Springs in the south up to the Izmir–Cesme Highway in the
north (Fig. 3). These first studies, which included resistivity, self-potential (SP) and gravity surveys, determined the thickness of the alluvium, identified a buried NE-SW striking
fault, and indicated the presence of hot water under the bed of the Ilica Stream. A controlled source audio-frequency magnetotellurics (CSAMT) survey (Yücel et al., 2001) carried
out north of the highway showed that that the geothermal potential in that region is small or
non-existent.
3. Field management
3.1. Drilling and workover activities
Since the 1960s a total of 44 wells have been drilled in the BNG field; 13 are deep and 31 are
shallow (i.e. depth less than 160 m). The wells presently being used for production, injection and
reservoir monitoring are shown in Fig. 3.
N. Aksoy et al. / Geothermics 37 (2008) 444–466
449
Table 1
Milestones in the Balcova–Narlidere geothermal project
Year
Milestone
1963
First exploratory well drilled (S1)
1983
Ten gradient wells drilled
Nine shallow wells drilled to install downhole heat exchanger (DHE)
Heating with DHE begins in the Medicine Faculty and Hospital of Nine September University
1992
First downhole pump starts producing geothermal water to heat the Thermal Hotel and Spa
Center
First deep well drilled (BD1)
First stage of the geothermal district-heating project
Injection begins in B9
1994
1995
1996
1999
Heated area reaches 646,517 m2 (Toksoy et al., 2003)
Izmir Province Geothermal Energy Advisory Board is created to monitor the geothermal
reservoir and heating project
2000
Launch of the reservoir monitoring and tracer tests (Aksoy, 2001), and reservoir performance
project (Satman et al., 2002)
2001
Work-over begins in the old wells (Aksoy, 2005)
CSAMT and SP surveys carried out to investigate geothermal features north of the
Izmir–Cesme highway (Yücel et al., 2001)
2002
Injection well BD8 completed
2003
Injection into B9 stopped
Well BD9 drilled, showing that the reservoir extended further east
2005
Heated space area reaches a total of 1.6 million m2
The first exploration well (S1) was drilled in 1963; 124 ◦ C-geothermal waters were found at
125 m depth. This well quickly became clogged with mineral deposits, and because of this scaling
problem no additional work was done in the field until 1983.
In 1983, 10 gradient wells, from 80 to 180 m deep, were drilled to determine the subsurface
temperature distribution in the area. The data showed that the highest temperature and heat flow
occurred at and around the Agamemnon hot spring, slowly decreasing toward the north. Also that
year, nine shallow production wells (i.e. depth <160 m) were completed in this high heat flow
region. To avoid future scaling problems, these wells were designed so as to allow the installation
of downhole heat exchangers (DHEs). The location of production and injection wells in the BNG
field is given in Fig. 3.
In 1994, the 564-m deep well BD1 was completed, showing a maximum temperature of 130 ◦ C
and proving the existence of a deep geothermal production zone. Initially, the well had artesian
flow; later, fluid production was maintained using an air compressor. Eventually, BD1 became
blocked by mineral scales. BD2, the second deep (677 m) well, was drilled in 1995 and, just
like BD1, it was also clogged by scale deposits after a short fluid production period. The use of
chemical inhibitors did not prevent scaling in either well.
In the 750-m deep BD3 well, also drilled in 1995, a frequency-controlled downhole line shaft
pump (LSP) was used for the first time. It was found that the inhibitors worked effectively when
utilized together with LSPs, and that wellbore scaling was easier to control.
Five more deep wells (BD4, BD5, BD6, BD7 and ND1) were drilled by 1999. Although at that
time a total of 26 production wells had been completed, the maximum rate of fluid extraction was
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N. Aksoy et al. / Geothermics 37 (2008) 444–466
Fig. 3. Map showing location of the production, injection and monitoring wells in the Balcova–Narlidere geothermal field
(as of November 2007), the schematic geology of the area, and the boundaries of the geothermal system derived from
geophysical (Tezcan, 1962; Yücel et al., 2001), geological (Aksoy, 2001; Öngur, 2001) survey data and static temperature
measurements.
only 140 kg/s. Most of the BNG wells were operating at low capacity or had been abandoned due
to problems such as mineral scaling, casing collapse, or general deterioration. Wells ND1 and N1,
which were drilled in the north-western portion of the field, showed that permeability decreases
to the north of the Agamemnon fault.
A well workover program began in 2001 (Aksoy, 2005). By the end of 2004, as a result of this
well rehabilitation work, the maximum fluid production rate grew from 177 to 419 kg/s, a 237%
increase (Table 2.) However, due to interference between wells and a drop in reservoir pressure,
total fluid production decreased to less than 330 kg/s in 2005.
In 2002, new wells began to be drilled to determine the limits of the geothermal field and to
increase fluid production and injection capacities. Wells BD8, BD9, BD11 and BD12, drilled in
the eastern portion of the field in a heavily populated area, proved that the geothermal reservoir
extended in that direction and that reservoir temperatures were higher in the east. In addition, the
750-m deep injection well BD10 was drilled on the western border of the field to reduce reservoir
pressure drawdown in that region.
3.2. Well inflow performance
To obtain the inflow performance characteristics for the BNG production wells we used multirate tests. Well deliverability plots for most wells show a linear relationship between changes in
bottomhole pressures and fluid production rates, indicating that Darcy flow predominates in those
wells (Aksoy, 2007). From the geothermal field management point of view, not only flow rates
N. Aksoy et al. / Geothermics 37 (2008) 444–466
451
Table 2
Results of well workovers in the Balcova–Narlidere geothermal field
Well
B1
B5
B7
B10
B11
BD1
BD2
BD3
BD4
BD5
BD6
BD7
Workover date
2002
2001
2003
2003
2002
2002
2001
2002
2003
2002
2004
2001
Operation
DHE removed and DHP installed
DHE removed and DHP installed
DHE removed and DHP installed
DHP replaced
Well cleaned and tested
Wellbore scale removed and DHP installed
Wellbore scale removed and DHP installed
Slotted liner installed between 450 and 750 m depth
DHP replaced
Bottomhole cleaned
Bottomhole cleaned
DHP replaced
Total production capacity
Production rate (kg/s)
Before
After
–
–
30
11
–
–
33
40
–
40
23
40
42
28
70
15
50
33
50
28
40
23
177
419
DHE, downhole heat exchanger; DHP, downhole pump.
are important, but also the temperature (or enthalpy) of the fluids being produced. For a given
application and ambient (air) temperature the hotter the fluids the smaller will be amount that has
to be extracted (and injected).
Fluid production and injection operations, an important aspect of a geothermal reservoir management strategy, should be planned so as to minimize costs. Sener et al. (2003) calculated that
the cost of operating the BNG field could be reduced by as much as 50% and that a significant
amount of electricity could be saved.
An analysis of the multi-rate test data showed that some wells could potentially operate at
higher capacity. However, the diameter of the well casings did not allow the installation of larger
capacity downhole pumps (DHPs). As a result, in 2003 it was decided that the diameter of
production casings in future wells would be increased from 9 5/8 to 13 3/8 inches to allow the
installation of 100-kg/s capacity DHPs.
To reduce (or even prevent) reservoir cooling and to increase the productivity of the field
Satman et al. (2002) recommended that the return waters should be injected into deeper wells
located at the edges of the field. (i.e. BD3, BD5, BD8, BD9 and BD10; Fig. 3). Injectivity tests
were performed on the latter five wells in 2002. The computed injectivity indices varied between
0.5 kg/(s bar) (well BD5) and 333 kg/(s bar) (well BD8); these indices were high in wells located
along the Agamemnon fault. It was found that the north-western ND1 and N1 wells had very low
permeability, and that permeability decreases to the north of the Agamemnon fault.
Injection into shallow wells was stopped completely in 2003, and by the end of 2005, 60%
of the extracted fluid was being injected into the deep BD8 and BD10 wells. Because of its high
injectivity, the 630-m deep BD8 well was used as an injector. As shown in Fig. 2, all the return
(cooled) geothermal fluids from the heating facility in the Balcova sector are injected into BD8
and those from the Narlidere facility into BD10. The injectivity index of BD10 was estimated at
3 kg/(s bar); which would allow injecting the waters at a rate of 40 kg/s by increasing the wellhead
pressure by 6 bar.
As of 2005, the total injection capacity in the BNG field was 190 kg/s (150 kg/s into BD8 and
40 kg/s into BD10). Only in the winter months of December, January and February the total fluid
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N. Aksoy et al. / Geothermics 37 (2008) 444–466
extraction rate is above 190 kg/s; during the rest of the year there is enough capacity to inject all
the return waters from the heating facilities. One should add that thermal waters used in spas,
health centers and pools, and the water that is leaking from the secondary circuit (between 30 and
60 kg/s) are disposed at the surface (i.e. not injected back into the reservoir).
3.3. Production history and pressure changes
Since the fluids from BNG field are used for heating, the amount extracted from the reservoir
varies depending on the air temperature, i.e. fluid production is higher during the winter and
lower in the summer. In 2000 the peak fluid extraction rate was 140 kg/s; it increased to 300 kg/s
in the winter of 2004. Since injection has not kept pace with production, the average reservoir
pressure has decreased over the years. Of course, during the summer months, and because of
natural recharge, when the net fluid extraction (production minus injection) was smaller, there
were temporary pressure increases (Aksoy, 2007).
Between 2000 and 2004, the depth to the water level in well ND1 varied between 10 and 27 m.
In 2004 and 2005, net fluid extraction increased because of the expansion of the district heating
project and insufficient injection. In those years, the lowest water level depths recorded in ND1
were 36.76 and 50.33 m, respectively (Aksoy, 2007). During the 2004–2005 winter, these low
levels caused problems for the pumps operating in shallow wells; some of the pumps installed at
75 m depth had to be stopped because of pump cavitation.
3.4. Tracer tests
Until 2003, the shallow wells, all of which are located on the south-western part of the
BNG field, accounted for 54% of fluid production and 100% of injection. The 48-m deep
well B9, located in the western part of the field (Fig. 3), was selected as an injector because
it accepted rates of up to of 100 kg/s without the use of pumps. Between 1996 and 2003, almost
all the waste geothermal fluids were sent to B9; during that period an average of 75 kg/s was
injected into it. To determine the interconnection between wells, uranine (Na–Fluorescein) was
injected into B9 in May 2000 (Aksoy, 2001). This tracer was selected based on the results
of Adams and Davis (1991) who found it to be stable at temperatures below 200 ◦ C for 2–3
years.
At the beginning of the tracer test, a mixture of 0.95 kg uranine and 6250 L of water (i.e. uranine
concentration: 152 mg/L) was pumped into B9. Throughout the test, flow rates in the production
(B4, B10, B11 and BTF3) and injection (B9) wells were kept constant; the totals rates were 44
and 29 kg/s, respectively. Wells B4, B10, B11 were 125 m deep, while the depth of BTF3 was
100 m. The other production wells in the field (B1, B5, B7, BD1, BD2, BD3, BD4, BD5, BD6
and BD7) were idle because the test was done in the summer. Note that at that time wells BD8,
BD9, BD10, BD11 and BD12 had not been drilled yet.
Uranine concentrations in the produced fluids were measured during a 3-month period using
a GGUN-FL02 fluorometer. The test data – the tracer return curves are shown in Fig. 4 – were
analyzed with the computer program TRINV (Arason and Björnsson, 1994) that uses an automatic
inversion technique to estimate the hydraulic characteristics of the flow channels in the reservoir
(Axelsson et al., 2005). The basic assumption in TRINV is that there is 1D flow along a narrow
channel (e.g. fracture zone) connecting the injection and production wells. The cross-sectional
area of this flow channel is A = hb, where h and b are its height and width, respectively; the TRINV
results (Mi /M, Aφ and u) are given in Table 3.
N. Aksoy et al. / Geothermics 37 (2008) 444–466
453
Fig. 4. Measured and computed tracer–return curves for Balcova–Narlidere production wells B4, B10, B11 and BTF3
(injection well: B9). “tfd”, time of first tracer detection (or tracer breakthrough); “pat”, peak arrival time; “u”, fluid flow
velocity through the shallow reservoir.
It took from 13 to 18 h for the tracer injected into B9 to reach the production wells (i.e. the time
of first tracer detection, or tracer breakthrough), and the peak arrival times varied between 35 and
60 h (Fig. 4). The tracer test showed that the injected water flowed through the shallow reservoir
at velocities that varied between 6.9 × 10−4 and 1.2 × 10−3 m/s (Fig. 4), quickly reaching many
of the production wells. The thermal front arrived at the shallow production wells (B4, B10 and
B11) in 10–20 days.
Therefore, the tracer test indicated a geothermal reservoir with quite permeable fractures,
and a serious risk of thermal breakthrough in the production wells. If the cooling in shallow
production wells had continued for 1–2 more years, it would have been impossible to utilize the
fluids discharged from these wells for space heating purposes.
Table 3
Model parameter obtained using TRINV (i.e. Mi /M, Aφ, and u), and parameters used to match measured and computed
fluid production temperatures in wells B4, B10, B11 and BTF3, Balcova–Narlidere geothermal field
Well
B4
B10
B11
BTF3
Q (kg/s)
10
21
9
4
Distance to B9 (m)
Mi /M
Aφ (m2 )
u (m/s)
114.3
85.6
160.4
268.5
3.3 × 10−3
0.077
0.024
0.095
0.001
7.5 × 10−4
6.9 × 10−4
1.1 × 10−3
1.2 × 10−3
9.0 × 10−4
5.4 × 10−4
0.7 × 10−4
Other parameters used to obtain a match were: qi (injection rate into B9) 29 kg/s; κ, 10−6 m2 /s; k, 2.0 J/(m ◦ C); Cr ,
1000 J/(kg ◦ C); Cw , 4200 J/(kg ◦ C); ρw , 980 kg/m3 ; ρr , 2700 kg/m3 ; rock porosity, 0.03 (Satman et al., 2002); fracture
porosity, 1.0.
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N. Aksoy et al. / Geothermics 37 (2008) 444–466
Fig. 5. Effects of injection into B9 well on the wellhead temperatures of shallow wells in Balcova–Narlidere geothermal
field.
3.5. Observed cooling effect
Downhole pumps are used in the BNG wells to maintain fluid pressures above boiling.
If conductive well heat losses are ignored, and because there is no flashing in the wellbore, changes in wellhead temperatures would be equal to those occurring in the reservoir.
Under these assumptions reservoir temperature changes could be directly monitored at the surface.
The temperatures of the fluid produced by the shallow wells (B1, B4, B5, B10, B11 and BTF3)
and their relationship with injection into B9 were investigated. Field data showed that an injection
rate increase is accompanied by a decrease in produced fluid temperatures. In the summer when
the rate is reduced, these temperatures recover. During June–October, when fluid injection (and
production) is at a minimum, the temperatures of the shallow wells recover, although they do
not reach their initial values. For example, B4 and B10 fluid temperatures, which had an initial
value of 114 ◦ C, dropped to 81.5 and 84.7 ◦ C, respectively, in the winter of 2002 (Fig. 5). In other
words, the geothermal district heating project that utilized shallow wells which started operation
in 1996, had wells showing fluid production temperature decreases between 16.7 and 34.6 ◦ C in
early 2002.
At the beginning of 2003, B9 was converted into an observation well and injection started
in BD8. Over the following 18 months, temperatures in shallow wells B4, B5 and B10
increased continuously (Fig. 5). After the winter months of 2004, however, temperatures in
those wells recovered only by 4–5 ◦ C. As before changing to deep injection, produced fluid
temperatures, which dropped during the winter, recovered during the summer. Similar temperature changes were observed in shallow wells B1 and B7, which began producing after
2003.
An inspection of the water level in ND1 and temperature changes indicates that shallow well
temperatures drop when the water levels in these wells fall (Fig. 6). This is because the Ilica
N. Aksoy et al. / Geothermics 37 (2008) 444–466
455
Fig. 6. Plots of depths to water level in observation well ND1 (black dots) and wellhead temperatures in Balcova–Narlidere
shallow production wells B1, B4, B5, B7 and B10 (grey dots) vs. time.
Stream that flows close to the shallow wells (Fig. 3) recharges the geothermal field. In winter
when reservoir pressures drop (i.e. water levels in the wells falling to 40–50 m depth), cold
surface water enters the system. We should stress that this recharge not only affects the shallow
wells but also the deep wells as evidenced not only by their cooling (see Fig. 7), but also by the
increase in magnesium content and the decrease in silica and boron concentrations in their waters
(Serpen, 2004).
We conclude that the cooling that was observed in shallow wells was not only caused by
injection into B9 but also by the influx of cold surface waters. After B9 injection stopped, shallow
well temperature increased for about 18 months, and only slightly later on (Fig. 5). This indicates
that injection has a greater effect on the cooling of shallow wells than does the influx of cold
surface waters.
With regard to the deep wells, it was found that BD1, BD2, BD4, BD6 and BD7, located in the
western portion of the field, cooled by 6–8 ◦ C, and that this phenomenon quickened after 2005.
456
N. Aksoy et al. / Geothermics 37 (2008) 444–466
Fig. 7. Plots of depths to water level in observation well ND1 (black dots) and wellhead temperatures of Balcova–Narlidere
deep production wells BD1–BD7 (grey dots) vs. time.
We consider that this cooling is related to the water level in the field (Fig. 7). In 2005, when water
levels in ND1 dropped to 50 m depth, there was a pronounced temperature decrease in those deep
wells. Since injection into well BD10 had not yet begun at that time, we surmise that the cooling
is due to cold water entering the field from the southwest in response to the reservoir pressure
drawdown.
N. Aksoy et al. / Geothermics 37 (2008) 444–466
457
3.6. Cooling model
As the cold water moves through the system, it picks up heat from the surrounding hot rock
mass. Bodvarsson (1972) presented analytical solutions for fluid temperatures when injection was
done into a horizontal, infinite fracture (or flow channel) of narrow and uniform width. Axelsson
et al. (1995) introduced a 1D fracture model to estimate the temperature of the injected fluid at
any distance x, along the flow channel. The temperature of the fluid, flowing at a rate q through
the channel, is given by Eq. (1) (Axelsson et al., 1995).
⎧
khx
⎨ T − (T + T ) erf
√
0
0
i
Cw q κ(t − x/β) for t > x/β
T (x, t) =
(1)
⎩
T0 for t ≤ x/β
where the water flow rate (q) along the channel, β and ρf are given by,
Mi
M
qCw
β=
ρcf hb
q = qi
ρCf = ρw Cw φ + ρr Cr (1 − φ)
(1a)
(1b)
(1c)
In Eq. (1), Ti denotes the inlet (at x = 0) temperature of the injected fluid, and T0 is the
temperature of the rock mass.
The fluid produced at the wellhead at a rate Q is a mixture of injected waters at temperature
T(x,t) and rate q, and of “native” geothermal waters at temperature T0 and rate (Q − q). The
resulting production temperature (Tp ) is given by,
Tp = T0 −
q
[T0 − T (x, t)]
Q
(2)
Tracer test data, B4, B10 and B11 wellhead temperatures measured between October 2000
and June 2001, and Eq. (1) were used to estimate the dimensions of the flow channel, and the
percentage of injected water that moves in the single flow channel connecting the injection well
with a given production well.
First, by using Mi /M and Aφ values obtained from the tracer test (Table 3) and Eqs. (1) and (2),
we estimated the temperatures of wells B4, B10 and B11. When were compared these calculated
temperatures with those measured between October 2000 and June 2001, no good matches were
obtained.
Our next step was to use an inverse solution scheme by substituting Mi /M, h and b values into
Eqs. (1) and (2), and solving the equations backward using a trial and error method. Following
that procedure we tried to get the best match between measured and estimated temperatures. The
parameter values that give the best fit between measured and calculated temperatures, as well as
the parameters used, are given in Fig. 8. According to these results, we can assume that there is
a flow channel (i.e. a fracture zone) between well B9 and B4 that is 70 m wide and 0.5 m high
(Fig. 8, top panel). Fifteen percent of the fluid injected into B9 flows through this channel. The
corresponding results for the channels connecting wells B9-B10, and B9-B11 are shown in the
middle and lower panel of Fig. 8, respectively. Note that the values shown in this figure differ
from the ones obtained using the TRINV code (Table 3), which were too small and did not match
the observed temperature declines in the wells.
458
N. Aksoy et al. / Geothermics 37 (2008) 444–466
Fig. 8. Effects of injection into B9 on the wellhead temperature of Balcova–Narlidere production wells B4, B10 and B11
(measured vs. computed temperatures).
The cooling of the produced fluid calculated on the basis of the flow channel cross-sectional
areas (Aφ) obtained from tracer tests and the ratio of injected water (Mi /M) (Table 3), cannot
explain the one that was measured, which requires a larger amount of injected water (i.e. more
tracer) to reach the production wells. It is significant that the tracer test was performed during the
summer when the production and injection rates are at a minimum, and a temperature recover
N. Aksoy et al. / Geothermics 37 (2008) 444–466
459
Fig. 9. Water samples from the Balcova–Narlidere geothermal area plotted on the Na, K and Mg triangular plot of
Giggenbach (1988). Concentrations given in weight percent. Dam: sample from the lake behind the Balcova Dam”.
is observed in the production wells. Very likely, the flow pattern in the reservoir in the summer
months differs markedly from that in the winter months. Thus, it is not surprising that a tracer test
performed during the summer is not diagnostic of temperature changes during the wintertime.
3.7. Water chemistry and scaling problems
The chemical compositions and isotope contents of hot- and cold-water samples collected in
and around the BNG field are presented in Table 4. The cold waters are of Ca–Mg–HCO3 type,
while the hot waters are of Na–HCO3 type. The 18 O and 2 H ratios plot parallel to the Eastern
Mediterranean Water Line drawn by Gat and Carmi (1970), indicating that the geothermal waters
are of meteoric origin (Aksoy, 2001; Serpen, 2004).
Most of the water samples when shown on the Na–K–Mg triangular diagram of Giggenbach
(1988) fall in the immature water zone (Fig. 9). Only some of the water samples from deep wells
(i.e. BD2, BD3, BD4, BD6 and BD9) plot on the partially equilibrated and mixed water region
of the diagram (Serpen, 2004).
Geothermometric methods were used to determine reservoir temperatures. The silica (quartz)
geothermometer (Fournier, 1977) indicated values close to the highest temperatures measured
in the wells (i.e. 141 ◦ C in BD9). On the other hand, the Na/K geothermometer (Truesdell,
1976) gave reservoir temperatures in the 156–172 ◦ C range, while those given by the Na–K–Ca
geothermometer (Fournier, 1979) were between 181 and 191 ◦ C.
Chloride concentrations (Fig. 10) show an increase towards the eastern part of the geothermal
field. These data and downhole temperatures (see below) indicate that the hot water recharging
the system ascends in the eastern part of the BNG field, and that there is cold water inflow from
the west; the lowest well temperature (71 ◦ C) was measured in well KC1 located in the northwest
460
Table 4
Chemical and isotopic characteristics of the thermal and cold waters in the Balcova–Narlidere geothermal field
Sample
Li+
Na+
K+
Mg2+
Ca2+
B
SiO2
F−
Cl−
HCO3 − CO3 −
SO4 −
TDS
δ18
(mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) (mg/kg) O(‰)
105
102
105
97
102
109
116
130
135
135
135
117
135
125
138
101
90
34
40
18
7.1 1890
7.091905
7.101891
7.301780
7.011948
8.171819
8.161836
8.201875
8.161842
8.201926
8.262030
8.281853
8.222021
8.031970
8.022050
7.901907
6.982190
7.421049
7.071515
7.49 695
1.12
1.43
1.33
1.50
1.35
0.97
1.50
0.85
1.40
1.20
1.50
1.40
1.32
0.95
1.21
0.90
1.15
0.42
0.75
<0.05
345.1
420.7
412.3
401.9
447.3
412.2
364
402.7
492
487.7
497.1
445
458
366.6
426.7
345.4
534.7
158.9
317
16.8
26.1
31.2
28.5
27.5
36.8
26.7
31
30.6
42.4
41
36.7
29
33.4
28.6
35.3
27.7
36.4
13.6
21.7
1.6
4.9
8.1
9.6
7.6
9.4
9.3
9.5
4.8
3.1
3.3
2.5
3.2
2.9
5.8
2.9
9
8.8
16.2
11
10.1
23.2
34.0
32.0
22.7
38.1
36.3
34.0
19.7
23.8
20.4
20.4
22.1
22.1
23.9
13.7
22.2
39.4
71.0
41.0
18.2
9.9
10.5
9.7
15.5
10.0
10.3
9.5
8.3
11.4
10.6
12.4
11.0
15.3
9.7
14.3
7.1
10.8
2.5
3.7
0.1
111.0
120.7
114.6
142.8
115.9
103.4
138.0
117.1
198.0
191.0
185.0
162.5
187.0
147.0
206.6
143.0
68.0
49.4
62.6
21.7
16
8.10 710
<.05
16.9
2.2
29.5
88.2
0.5
18.7
1.9
0.1
190
172
178
216
180
180
171
182
198
211
221
227
198
194
276
138
179
62
138
10
550
896
836
611
826
638.4
615
316
690
705
701
575
429.6
389
650
690
1173
446
590
110
0.1
26
367
2.9
5.1
3.8
3.8
2.8
4.2
4.3
6.3
62.4
65
201
130
123
110
124
177.6
124.8
219
165
194
198
170
160
167
175
165
179
192
207
187
190
204
159
141
147
149
9
1250
1210
1170
1245
1370
1350
1290
1243
1350
1310
1350
1480
1470
1270
1390
1290
1155
1070
1010
160
40
210
T, wellhead temperature during sampling; EC, electrical conductivity; TU, tritium units; Dam, water from the lake behind the Balcova Dam.
δD (‰)
Tritium
(TU)
−7.97
−47.44
2.00
−8.08
−7.77
−8.10
−45.83
−43.90
−42.51
1.45
1.25
0.90
−5.54
−5.89
−38.25
−38.61
2.05
1.30
−6.10
−35.80
6.90
−6.41
−39.79
4.70
N. Aksoy et al. / Geothermics 37 (2008) 444–466
B1
B4
B5
B7
B10
B11
BTF3
BD1
BD2
BD3
BD4
BD5
BD6
BD7
BD9
BD10
BH1
KÇ1
IS1
Cold
spring
Dam
T (◦ C) pH EC (␮
S/cm)
N. Aksoy et al. / Geothermics 37 (2008) 444–466
461
Fig. 10. Chloride distribution (in mg/kg) in the Balcova–Narlidere geothermal field. Data from water samples collected
from deep and shallow wells in the field. The smallest value (138 mg/kg) is in the SW corner of the map; the highest
(276 mg/kg) was measured in well BD9.
(Fig. 3). The lake behind the Balcova Dam to the south, and the Ilica Stream flowing in the western
part of the field (Fig. 1) are the source of the cold waters recharging the geothermal system.
As mentioned earlier, scaling, consisting of more than 98% calcium carbonates, was the main
reason why the BNG field, despite being discovered in 1963, could not start commercial operation
until the 1980s.
Mineral saturation in a water sample from BD1 (Table 4) was analyzed for adiabatic boiling
and conductive cooling using computer program WATCH (Arnorsson et al., 1982; Arnorsson
and Bjarnason, 1993; Bjarnason, 1994). Borehole boiling in an artesian geothermal well caused
by pressure drawdown is an adiabatic process, when conductive heat losses to the formation are
ignored. Under these conditions, many minerals (primarily calcium carbonates) tend to become
oversaturated and precipitate. This is verified by the chemical composition of the scale samples
and by the WATCH calculations.
The amount of non-condensable gases in the BNG reservoir fluids was calculated to be
776 mg/L, almost all CO2 (Aksoy, 2001); under these conditions, the boiling pressure of the
geothermal fluid is about 5 bar. When wells are produced using downhole pumps, the geothermal
water reaches the heat exchanger at pressures above boiling and leaves it at 60 ◦ C (the secondary
circuit in the district heating system operates within the 60–80 ◦ C range; Fig. 2). The return fluids
cool by conduction as they flow towards the injection well; however mineral saturation calculations indicate that under these conditions, the fluids remain under-saturated with respect to calcite,
the most prevalent scale mineral in the BNG field.
Initially, the recommended dosage for the phosphate-based scale inhibitor was 15 mg/L, and
was used for many years. After 2001, it was reduced to less than 1 mg/L based on inspections of
wellheads and other surface installations. Annually, over US$100,000 is saved in scaling inhibitor
costs by reducing the dosage and by using a less expensive brand.
3.8. Conceptual model of the field
A conceptual model of the BNG system was developed (Fig. 11) on the basis of well logs,
water chemistry, isotope, tracer test and other field data.
The geothermal system is fed by meteoric water that infiltrates over a 35-km2 area south of
the field (Serpen, 2004). The average elevation of the recharge area and the geothermal field is
900 and 100 m above sea level, respectively. The meteoric waters penetrate deep into the system
by flowing down a high-permeability fracture zone associated to the Agamemnon fault (Serpen,
462
N. Aksoy et al. / Geothermics 37 (2008) 444–466
Fig. 11. Conceptual model of the Balcova–Narlidere geothermal field.
2004). The temperature of the infiltrated waters increase as they pick up heat from the rocks; the
terrestrial heat flow in the area is about 110 mW/m2 (Serpen, 2004). Eventually, because of its
lower density the heated water ascends and is found in a hot zone parallel to the Agamemnon fault
(Fig. 3). As mentioned earlier, the largest sources of cold waters in the region are the Balcova
Dam and the Ilica Stream, which recharge the shallow and deep geothermal reservoirs. As these
waters move into the system they mix with the thermal fluids.
Because the BNG district heating system works in the 60–80 ◦ C range, we consider the field
abandonment temperature to be 80 ◦ C. The 3D distribution of temperature in the BNG system,
developed based on the static temperatures measured in the wells is given in Fig. 12. The volume of
the geothermal system with temperatures equal or above 80 ◦ C is about 4.5 km3 . Using the water
and rock characteristics given in Table 3 and the subsurface temperature distribution (Fig. 12),
we calculated that the useful heat stored in that system is about 3.8 × 1017 J. By useful heat we
mean the thermal energy corresponding to temperatures equal or above 80 ◦ C, the abandonment
temperature.
N. Aksoy et al. / Geothermics 37 (2008) 444–466
463
Fig. 12. Temperature distribution in the Balcova–Narlidere geothermal field (dimensions in m).
The natural recharge rate of 160 ◦ C water (mean temperature based on geothermometric data)
is 50 kg/s (Satman et al., 2002; Serpen, 2004). Based on 2005 data, during that year, 4.2 × 109 kg
hot water (mean temperature: 120 ◦ C) was produced, 2.0 × 109 kg of 60 ◦ C water was injected
and the natural recharge of the field, which includes the cold-water influx from the surface, was
about 1.6 × 109 kg. That means that the thermal input associated with the natural fluid recharge
is approximately 1.1 × 1015 J, that with injection is about 5.0 × 1014 J, and the thermal output
due to fluid production is 2.1 × 1015 J. If we ignore thermal recharge by conduction, it is obvious that the geothermal system is being depleted (i.e. recharge < discharge) in both mass and
energy.
4. Discussion and summary
From the time when the first well was drilled in 1962 until the year 2000, no studies were
made to investigate in detail the characteristics of the BNG field, particularly its boundaries. As
a result, there was no clear strategy on how to develop the system and unnecessary wells were
drilled very close to each other in the western portion of the field (Fig. 3). Most of these early
wells quickly became unusable because of design and completion errors, and scaling problems.
Well rehabilitation work that followed has, however, increased the maximum fluid production rate
from 177 to 419 kg/s. Such improvement led to an increase in the capacity of the district heating
system (see Section 2).
Because the boundaries of the system were not defined at that time an area, now known to be
in the eastern part of the geothermal field, was opened to development, while the northern portion
was kept protected; later on Yücel et al. (2001) showed that that northern region does not have
464
N. Aksoy et al. / Geothermics 37 (2008) 444–466
any significant geothermal potential. Because of urban development, it is no longer possible to
carry out geophysical surveys in the eastern parts of the system.
Since the area is heavily populated, all activities related to drilling are done under very difficult
conditions. In 2007, blowouts occurred while wells BD11 and BD12 were being drilled, but
neither the nearby houses nor their inhabitants were hurt.
The 3D models of the field (Fig. 12) show that the temperature decreases rapidly toward the
north, away from the Agamemnon fault, and increases toward the east, confirming results of
geophysical surveys conducted in the north. Based on that temperature distribution, wells BD8,
BD9, BD11 and BD12 were sited. These four wells are the hottest and most productive wells in
the field at this time (November 2007) and confirmed that that the highest temperatures are in the
eastern part of the field.
Since present fluid production at the BNG field is done with the help of downhole pumps, in
order to have high production capacities (i.e. exceeding 40 kg/s) the wells should have 13 3/8
inch diameter production casings to allow the installation of the appropriate size pumps. Pumped
production reduces scaling tendency as it keeps the thermal fluid at pressures above boiling. By
managing the use of scaling inhibitors, the initial scaling problem in the BNG production wells
was solved and very large savings were made.
Increases in net fluid extraction led to enhanced reservoir pressure drawdowns; by the
2004–2005 winter, water levels had fallen to 55 m depth, causing pump cavitation problems
in some shallow wells, requiring the shutdown of the pumps temporarily.
The tracer test carried out in well B9 showed that water injected into this well reached shallow
production wells in 13–18 h, indicating that the injectate moves very fast between wells through a
small volume flow channel (fracture zone). This shallow injection was stopped because it caused
cooling in nearby shallow production wells. After injection into B9 was stopped, the temperature
in the shallow wells increased during a 2-year period. Field measurements show that there is an
increase in cold-water recharge when the pressure in the geothermal reservoir drops.
Because 90% of fluid injection in the field (approximately 60% of total production) is done
in well BD8, and because recent developments indicate that the eastern portion of the field is an
important production zone, it appears that the sustainability of hot fluid production is dependent
on the success of injection into BD8. The cooling observed in neighbouring wells BD3 and BD2,
may be related to that operation. The fact that injection is concentrated in BD8 together with the
fact that all wells, including BD8, are lined up along the Agamemnon fault increases the risk of
thermal breakthrough in the production wells.
The amount of heat being extracted from the BNG field is significantly higher that its natural thermal recharge. Consequently, the sustainability of the district-heating project depends on
mining the heat stored in the subsurface rocks (i.e. on thermal sweeping efficiency). To date, all
production wells that have been drilled to extract fluid from the Agamemnon fault and its associated fracture zone. Future wells should be located and designed with the purpose of mining the
heat from the rocks. However, the fact that the permeability is very high along the Agamemnon
fault and that permeability is relatively low in the northern part of the field will have a negative effect on such heat mining. This is because the injected water will tend to move along the
Agamemnon fault and its fracture zone and lead to premature breakthroughs.
Reservoir pressure drawdown, which increases the effective stress on the subsurface rocks, and
the thermal contraction due to cooling, may result in a reduction in rock volume. Stefansson (1997)
stated that subsidence of between 10–15 cm and 11.6 m has occurred in certain geothermal areas
under commercial exploitation. The deformation of the ground surface in the heavily populated
area of the BNG field could have serious social and economic impacts.
N. Aksoy et al. / Geothermics 37 (2008) 444–466
465
5. Recommendations
Based on the results of this study, we recommend the following for the Balcova–Narlidere
geothermal field:
• New wells should be drilled directionally if a sufficient number of appropriate well pads cannot
be located in this densely populated area.
• The modeling of the BNG reservoir should be updated; the last of these studies was done in
2000 (Satman et al., 2002). The field has been monitored since the year 2000 and many new
and deep wells have been drilled, indicating that the geothermal field extends toward the east.
• Because the field stretches along a single east–west line parallel to the Agamemnon fault line,
combined with the fact that production and injection are being carried out in the same zone
increases the risk of production well cooling, which threatens sustainability of the districtheating project. Thus, injection at some distance from the production zone, probably a few
hundred meters north of the production wells should be investigated.
• Cooling projects based on geothermal energy can be very attractive considering both the complementary market segment and the local demand. Altun (2006) showed that absorption cooling
is not economically feasible for the BNG project. Even if we accept that a cooling project is
feasible it would require further development of the field. Additional reservoir pressure drawdown may occur if the cooling project is implemented. A careful study of its effect on the
sustainability of the system is needed.
• A tracer test should be done in well BD8 to investigate the long-term impact of the long-term
effects of injecting waste geothermal fluids into this well.
• The risk of ground surface deformation (subsidence and rebound) and the effects of seismic
activity that might occur because of fluid injection (and production) should be investigated.
Such phenomena may have severe social and economic impacts on the densely populated area
where the BNG field is located.
Acknowledgements
This study was funded by the Dokuz Eylül University Research Fund (Project No:
0922.20.01.09) and Balcova Geothermal Inc. The authors acknowledge the support provided
by Balcova Geothermal Ltd. and express their gratitude to its manager Fasih Kutluay. Thanks are
due especially to Dr. Macit Toksoy, Chairman of the Izmir Province Geothermal Energy Advisory
Board, for his assistance and support in the development of geothermal energy projects. Thanks
are extended to Dr. R.G. Bloomquist, Dr. P. Ungemach and the journal’s Editorial Team for their
useful suggestions and comments on the manuscript.
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