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Drilling and Well Completion Cost Analysis of Geothermal Wells in Turkey

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Abstract and Figures

More than one thousand wells have been drilled in Turkey for geothermal energy development which ranked the country up to fourth ranking in total geothermal energy production worldwide. On the contrary to the number of the wells, there is very limited resources about the costs of these wells and whether it is more affordable to invest to geothermal energy in Turkey in comparison with other geothermal producer countries. The objective of this paper is to provide a numerical method and software to calculate the drilling, well completion and well testing costs of new wells which can be used as an estimation by operators who is interested in investing in this market and as a result provide a comparison of these costs with the well costs in other thermally active countries Well drilling and completion data from more than twenty wells have been analyzed and merged together to form a software to calculate the estimated costs of drilling, completion and well testing a well with a diesel rig in Turkey. This software is using the rig capacity, rig type, the drilling type (kelly or top drive), casing setting depths for each casing, existing drilling third party services (mud, directional drilling, performance drilling etc.) and estimated rate of penetration values from offset wells as the input. Software runs with already calculated casing running times, tripping speeds and connection times for each different size of casings and drillpipes together with the time estimations formulas and provides the service costs and time graphs with the option of changing each input easily. As the result of the study, it was observed that the associated costs in Turkey are the cheapest amongst the costs of the wells in Kenya, Iceland, Nevada, Australia and the United States. The major reasons of these low costs are mainly because of the following three main parameters. Firstly, daily operating costs of rigs and third-party services and labor costs in Turkey are more affordable compared to other countries. Secondly, the major equipment of the well which is the casings are chosen from the lowest cost option since wells are not overbalanced and there is no need for a high cost or high-grade casing to drill these wells. Thirdly, the drilling experience in Turkey resulted in a competitive market which resulted in more optimized wells with the minimum drilling times. In the literature, there is no published study for the estimation of drilling, well completion and well testing costs of geothermal wells in Turkey. This study and the associated software is very important for a geothermal operator to estimate the project times and related costs associated with their investment.
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PROCEEDINGS, 43rd Workshop on Geothermal Reservoir Engineering
Stanford University, Stanford, California, February 12-14, 2018
SGP-TR-213
1
Drilling and Well Completion Cost Analysis of Geothermal Wells in Turkey
Sercan Gul1, Volkan Aslanoglu1
1 Middle East Technical University, Petroleum&Natural Gas Engineering Department, Ankara, Turkey
sercan.gul@gmail.com, aslanoglu.volkan@metu.edu.tr
Keywords: geothermal energy, drilling, well completion, cost estimation
ABSTRACT
More than one thousand wells have been drilled in Turkey for geothermal energy development which ranked the country up to fourth in
total geothermal energy production worldwide. Despite of the high number of the wells, there are very limited resources on the costs of
these wells and whether it is more affordable to invest in geothermal energy in Turkey in comparison with other geothermal producing
countries. The objective of this paper is to provide a numerical method and code to calculate the drilling, completion and testing costs of
new wells which can be used as an estimation by operators who are interested in investing in this market and as a result provide a
comparison of these costs with the well costs in other thermally active countries. Well drilling and completion data from more than
twenty wells have been analyzed and merged together to form a software to calculate the estimated costs of drilling, completion and
testing a well with a diesel rig in Turkey. This software uses the rig capacity, rig type, the drilling type (kelly or top drive), casing
setting depths for each casing, existing drilling third party services (mud, directional drilling, performance drilling etc.) and estimated
rate of penetration values from offset wells as the input. The code runs with already calculated casing running times, tripping speeds and
connection times for each different size of casing and drill pipe together with the time estimation formulas and provides the service
costs and time graphs with the option of changing each input easily. As a result of the study, it was observed that the associated costs in
Turkey are the cheapest amongst the costs of wells in Australia, France, Germany, Iceland, Kenya, Netherlands and the United States.
The major reasons of these low costs are mainly because of the following three main parameters. Firstly, daily operating costs of rigs
and third-party services and labor costs in Turkey are more affordable compared to other countries. Secondly, the major equipment of
the well which are the casings are chosen from the lowest cost option since wells are not overbalanced and there is no need for a high
cost or high-grade casing to drill these wells. Thirdly, the drilling experience in Turkey resulted in a competitive market which resulted
in more optimized wells with minimum drilling times. In literature, there is no published study for the estimation of drilling, well
completion and well testing costs of geothermal wells in Turkey. This study and the associated code are very important for a geothermal
operator to estimate the project times and related costs associated with their investment.
1. INTRODUCTION
Increasing demand for energy with lower CO2 emissions in today’s world has resulted in the necessity of alternative energy sources. In
the last decade, there is more and more interest in renewable energy sources due to their low CO2 emissions and sustainability. One of
the most influenced energy source in Turkey today is geothermal energy. Turkey is ranked number 4 in the total capacity of geothermal
energy in the world with its 1,053-MW installed capacity (Gul, 2017). Figure 2 illustrates the top 10 countries in installed capacity
worldwide while Figure 3 illustrates the increase in the installed geothermal capacity of Turkey in last decade and under-development &
planned capacity for the following years. With the completion of the planned capacity addition, Turkey is estimated to be the third
largest geothermal operating country in the world with 1827 MW total capacity. Rig counts in Turkey for geothermal well drilling as of
January 2017 was 26, being ranked first with the total amount of 60 geothermal rigs worldwide. In total 32 of 98 drilling activities in
Europe is in Turkey (Hughes, 2017).
Turkey is situated on the Alps-Himalayas belt and, although, the geothermal energy potential of Turkey was historically estimated as
31500 MW, that value has recently been increased to 60000 MW (Mertoglu, Sismek, & Basarir, 2015). According to Geothermal
Country Update Report of Turkey, there are five major grabens which are Buyuk Menderes, Gediz, Dikili-Bergama, Kucuk Menderes
and Edremit grabens along the Northern Anatolian Fault zone and in the Central and Eastern Anatolia volcanic regions (Mertoglu,
Sismek, & Basarir, 2015). The geothermal gradient in Turkey ranges between 8.33 °C/100m to 11.10 °C/100m in thermally active
regions (Njolnbi, 2015).
On the other hand, the drilling costs are mostly affected by the daily rig rates from drilling contractors and with the developed
experience in the field by contractors and service companies, the daily drilling rig rates have been decreased dramatically in the last 3
years (Kaya, 2017). As illustrated in Figure 1, in the mentioned period Turkey has an average of 45% of the geothermal drilling rigs
throughout the world. Moreover, this ratio is approximately 30% compare with all the drilling rigs in Europe. Therefore, it can be
concluded that Turkey is currently a market leader in geothermal drilling activities in Europe and that is the main aspect of the reduction
in daily drilling costs.
Gul & Aslanoglu
2
Figure 1. Monthly well count (June 2012-October 2017) (Hughes, 2017)
Figure 2.Geothermal power operation capacity by country (Gul, 2017)
Figure 3.Installed geothermal capacity of Turkey by year (Richter, 2017)
0%
10%
20%
30%
40%
50%
0
10
20
30
40
50
Number of Wells
Date
Monthly Well Count
Turkey(Total Drilling) Turkey (Geothermal Wells)
Worldwide Geothermal Perc. Turkey's Percentage (Europe)
3567
1868
1809
1053
980
944
926
710
676
542
893
0 500 1000 1500 2000 2500 3000 3500 4000
United States
Philippines
Indonesia
Turkey
New Zealand
Italy
Mexico
Kenya
Iceland
Japan
Other
Top 10 Geothermal Countries
Installed Capacity - Total 13968 MW -November 2017
15 15 23 23 30 77 94 114 162 311 405
624 775
1053 1072 1272
1827
0
400
800
1200
1600
2000
Total Installed Capacity (MW)
Installed Geothermal Capacity in MW of Turkey by Year
Gul & Aslanoglu
3
2. THE COST OF DRILLING A GEOTHERMAL WELL
Geothermal drilling is very similar to oil and gas drilling with minor differences, which are explained in chapter 4 of this paper. The
drilling phase includes all the activities starting from the well spud until the target depth is reached. The cost of drilling a geothermal
well is estimated to be approximately 40% of the total investment cost for a new high temperature geothermal plant. This makes the
geothermal plant more expensive to build than conventional fuel fired power plants and as a result the cost of the well becomes a key
consideration when determining the economic viability of a geothermal field. Obtaining accurate costs for the geothermal well is
therefore very important as it quantifies a substantial percentage of the cost of the geothermal project (Carolyn, 2013). Drilling a
geothermal well is a complex process that uses expensive drill rigs, a wide range of drilling experts and a lot of financial muscle. It is
also a labor-intensive operation with most of the jobs being performed 24 hours a day, seven days a week, in all weather conditions.
Only extreme weather, mechanical failure or lack of supplies will warrant the shutting down of these operations (Carolyn, 2013).
Several factors affect the cost of geothermal wells. These factors include well design, the total depth of the well, the type of drill rig and
the methods used. Other parameters may include the efficiency of the drilling operation and the optimization of the drilling variables.
The total well time constitutes both the drilling and the non-drilling time (Carolyn, 2013).The general design of a vertical geothermal
well in Turkey is provided as in Figure 4. As can be seen in Figure 4, 26” hole are drilled to 200m and 20” casings are run at that depth
to prevent the chemical mixing in ground water zones. The next section follows as 17 ½” section drilling and 13 3/8” casing running at
an average depth of 700m and 12 ½” section drilling with 9 5/8” casing running at around 2000 meters depending on the formation
changing depths. The last section is always drilled with bit diameter of 8 ½” and 7” slotted casings are used to allow producing through
the casings and eliminate the perforation costs
.
Figure 4:General design of a vertical geothermal well in Turkey
The estimated total cost of a geothermal well is studied in 11 different parts such as drilling location preparation, tubular equipment,
liner hangers, wellhead, drilling contract, mud service, drilling bits,directional drilling or performance drilling services, cementing,
logging, company labor and supervision. Out of these 11 steps of the drilling cost, only the costs of 4 of them (drilling contract,mud
service, drilling bits and directional drilling service) are a function of the total drilling time while the other 7 are not related to the rate of
penetrations in the drilling. Therefore, even though the main aim in drilling is to reduce the total active drilling times and obtain lower
costs, there will also be a constant amount of cost due to location preparation, tubular equipment, liner hangers, wellhead, cementing,
logging and company labor which will not be reducing as the total drilling times are decreased. This situation is illustrated in the
sensitivity analysis (appendix B) of the software.
As an example, for the case with 7” casing setting depth of 3000 meters and effective average rate of penetration in 8.5” section of 5.2
m/hr (other inputs as provided in Figure 5), the maximum share of the cost (approximately 42%) belongs to the drilling contract which
includes daily drilling rate, top drive rate, mobilization and demobilization rate, diesel costs and water costs. Tubular equipment is
ranked two with approximately 18% of share from the total cost of well which includes the 30” conductor casing, 20” surface casing, 13
3/8” and 9 5/8” intermediate casings and 7” production casing. Mud service, which is mud material, chemicals, personnel and mud
laboratory equipment, follow as ranked 3 with approximately 12% and drilling location preparation, which is site survey, location and
road construction and location rehabilitation follows up with 11.5%. All other associated costs, suchs as liner hangers, wellheads,
drilling bits, directional services, cementing, logging and company labor have a sum of 17% share in the total costs.
Hole Diameter
Casing Outer
Diameter
Well Profile
Depth (m)
26 ''
20 ''
200
17 1/2 ''
13 3/8 ''
700
12 1/4 ''
9 5/8 ''
2000
8 1/2 ''
7 ''
3250-4500
(dep ends from
fiel d to fiel d)
Gul & Aslanoglu
4
The costs associated with drilling a geothermal well can be outlined as follows:
1. Drilling location preparation
a. Site survey
b. Location and road construction
c. Location rehabilitation
2. Tubular equipment
a. 30" conductor casing
b. 20" casing
c. 13 3/8" casing
d. 9 5/8" casing
e. 7" casing
3. Liner hangers
a. 7" liner hanger
4. Wellhead
a. 21 1/4" x 2m casing head housing
b. 13 5/8" x 3m casing head housing
c. 11" master valve
5. Drilling contract
a. Daily drilling rate
b. Top drive rate
c. Mobilization rate
d. Demobilization rate
e. Diesel cost
f. Water cost
6. Mud service
a. Mud material and chemicals
b. Personnel
c. Mud laboratory equipment
7. Drilling bits
a. 26" tricone bit
b. 17 1/2" tricone bit
c. 12 1/4" tricone bit
d. 8 1/2" tricone bit
e. Nozzles
8. Directional services
a. Personnel
b. Equipment rental
c. Surveys
9. Cementing
a. 20" casing cementing operation
b. 13 3/8" casing cementing operation
c. 9 5/8" casing cementing operation
10. Logging
a. Pt log
b. Pts log
c. Compressor service
11. Company labor and supervision
a. Drilling manager
b. Drilling engineer
c. Geologist
As mentioned before, the costs associated with a geothermal well drilling and completion has been studied in 11 main items with a total
of 38 subitems.
Gul & Aslanoglu
5
3. SOFTWARE MODEL AND ESTIMATIONS
An excel spreadsheet has been developed to estimate the total required time and costs associated with each item in the outline provided
above. As the inputs, rig capacity (tons), rig type (single, double or triple stands), the rotary system (kelly or top drive), casing setting
depths for each section and the existence of directional drilling services should be provided. In the geothermal fields of Turkey, the
average rate of penetration (ROP) values are estimated as 4 m/hr. in 26” section, 8 m/hr. for 17.5” section, 5 m/hr. for 12 ¼” section and
4 m/hr. for 8.5” section. These values are input as default and can also be changed in the input page. Similarly, casing running times,
tripping speeds for drill pipes and drill collars and connection times for drill pipe, drill collar and directional surveys are also default but
can also be altered depending on the performance of rig crews. The visual of the “Input and constants” page is provided in figure 5.
The excel spreadsheet with open source code is accessible by contacting the researchers of this paper.
Rig Capacity (tons)
200
Rig Type
Double
Kelly or Top Drive?
Kelly
20" Casing Setting Depth (m)
200
13 3/8" Casing Setting Depth (m)
700
9 5/8" Casing Setting Depth (m)
2000
7" Casing Setting Depth (m)
3000
Hanged
Directional Drilling Services (Yes/No)
Yes
Estimated Effective ROP for 26.0" Section Drilling (m/hr)
4
Estimated Effective ROP for 17.5" Section Drilling (m/hr)
8
Estimated Effective ROP for 12.25" Section Drilling (m/hr)
5
Estimated Average ROP for 8.5" Section Drilling (m/hr)
5.2
20" BTC Casing Running Time
3.00
min/meter
13 3/8" BTC Casing Running Time
1.00
min/meter
9 5/8" BTC Casing Running Time
0.60
min/meter
7" BTC Casing Running Time
0.60
min/meter
Tripping Speed - Drillpipe
3.00
min/stand
Tripping Speed - Drillcollar
6.50
min/stand
Connection Time - Drillpipe (for Drilling)
10.00
min/single
Connection Time - Drillcollar (for Drilling)
15.00
min/single
Connection Time Addition for Directional Surveys
10.00
min/single
Figure 2:Input and constants page of the spreadsheet
Casing running times, tripping speeds and connection times for drill pipes, drill collars as well as the additional time for directional
surveys (the additional time for directional survey includes an if/else condition in the code in which if the directional drilling service is
selected as no in the input page, there will be no additional time reflected in the connection times) have been calculated from average
worker performances. These numbers are below the average compared to wells in Europe and the US but in the overall scenario for the
costs, these times do not reflect too much on the overall costs of the wells. Therefore, in the example simulated well, 20”, 13 3/8” and 9
5/8” BTC casing running times are approximated as 3, 1 and 0.6 min/meter respectively. Tripping speed for drillpipes and drillcollars
are accepted as 3 and 6.5 min/stand and connection times for drillpipes and drill collars are accepted as 10 and 15 minutes/single
respectively. The use of top drive increases connection and tripping times, but in the same time increases the daily rig costs as well as
non-productive times due to maintenance problems, therefore not all operators prefer rigs with top drives for geothermal drilling in
Turkey. The effect of directional drilling services mostly increases the rate of penetration since the reason of having a directional
drilling service is rather drilling a vertical well and staying in the limits of the lease and making sure that the well is not deviating.
Therefore, the use of mud motor increases the rate of penetration gradually especially in really high strength formations which in the
end compensates the additional cost due to service and decreases the total well costs.
The second page of the code calculates the estimated times for each operation depending on the provided inputs and provides
“Operation Time vs Depth” graph for the estimated well conditions as visualized in Table 1. The total time in hours or in days is
calculated by summing up all the time values and multiplying them by 1.1 to compensate for non-productive or unestimated times due
to well or field conditions.
Gul & Aslanoglu
6
In the simulated well and drilling conditions as provided in Table 1, drilling times were observed to be the lead participant in the total
well operations times with 57%. On the other hand, it was observed that a lot of time is spent in connection times (9%) in the simulated
example well since this well is drilled with kelly and therefore connection times taking longer than the top-drive case. Moreover, casing
running is observed to be 7% and trips as 6%, while all other operations such as casing cementing, wait on cement, wellhead operations
and well testing operations stand for the remaining 21% of the time spent in operations. This also matched with the general
understanding of well costs as the time spent on drilling the well is the most important part of deep geothermal drilling process since the
rate of penetration values are lower compared to oil and gas wells. More research should be performed on increasing the drilling speeds
on geothermal wells with either different types of muds or new technology drilling bits.
Table 1: Time estimation table with estimated input parameters in Figure 5
Item
Time (hours)
Time (days)
Cumulative time with
%10 allowance (days)
Depth (m)
Start of Operations
0.0
0.0
0.0
0
26" Section Drilling
50.0
2.1
2.3
200
26" Connection Time
5.0
0.2
2.5
200
26" Drillstring Trips
1.1
0.0
2.6
200
20" Casing Running
10.0
0.4
3.0
200
20" Casing Cementing
4.0
0.2
3.2
200
Wait on Cement
12.0
0.5
3.8
200
21 1/4" Wellhead
24.0
1.0
4.9
200
Run in Hole to Bottom
1.1
0.0
4.9
200
17 1/2" Section Drilling
62.5
2.6
7.8
700
17 1/2" Connection Time
8.3
0.3
8.2
700
17 1/2" Drillstrings Trips
7.0
0.3
8.5
700
13 3/8" Casing Running
11.7
0.5
9.0
700
13 3/8" Casing Cementing
6.0
0.3
9.3
700
Wait on Cement
12.0
0.5
9.8
700
13 5/8" Wellhead
24.0
1.0
10.9
700
Run in Hole to Bottom
2.3
0.1
11.0
700
12 1/4" Section Drilling
260.0
10.8
23.0
2000
12 1/4" Connection Time
43.3
1.8
24.9
2000
12 1/4" Drillstring Trips
15.0
0.6
25.6
2000
9 5/8" Casing Running
20.0
0.8
26.6
2000
9 5/8" Casing Cementing
8.0
0.3
26.9
2000
Wait on Cement
12.0
0.5
27.5
2000
9 5/8" Wellhead
12.0
0.5
28.0
2000
Run in Hole to Bottom
5.6
0.2
28.3
2000
8 1/2" Section Drilling
192.3
8.0
37.1
3000
8 1/2" Connection Time
33.3
1.4
38.6
3000
8 1/2" Drillstring Trips
22.5
0.9
39.6
3000
7" Casing Running
30.0
1.3
41.0
3000
Well Testing
48.0
2.0
43.2
3000
Others
48.0
2.0
45.4
3000
TOTAL
1090.16
45.42
Gul & Aslanoglu
7
Figure 3: Operation time vs. depth graph for the simulated example well
The last part of the spreadsheet is provides the related costs with all the 11 items as outlined in the previous parts of this paper. The
screenshot of the “cost” section is as in below figures.
It has been estimated in the code and calculations that no main equipment such as cementing units, drilling rigs or directional drilling
equipment are owned by the operator and these are all obtained as third-party services. Bottom hole assembly (BHA) length in the
calculations and time estimations are estimated as 200 meters for each section.
The effect of directional drilling (extra time due to survey times) is reflected only on 12.25” and 8.5” drilling sections. After each
cementing operation, due to high temperatures, the common procedure is to wait on cement for 12 hours in Turkey.
Therefore, the same value is considered after each cementing job in each diameter of casings. Moreover, since all drilling operations are
conducted with mobile or semi-mobile rigs, the space below the structure is generally very limited and almost no contractor uses
wellhead installation mechanisms with their rigs. For the same reason, the wellhead operation time is considered as 24 hours for 21 1/4
“and 13 5/8” wellheads and 12 hours for 9 5/8” wellheads since the work conducted for 9 5/8” wellhead is mostly only the make-up of
the master valve and some adapters to get ready for production from the well. For each tricone bit, the life of the bit is estimated as 100
hours, which is the general assumption of the operators and service companies. For the company labor and supervision, total costs are
included in a way to include the travel costs of the personnel. In the time estimations, 10% allowance is added to total times to
compensate for the unexpected time losses and non-productive times in the operations. The associated costs of all spare equipment such
as casings, drilling bits, wellhead, etc. are illustrated in provided figures. As the daily rig rates, it has been estimated to be $9000 for
rigs with capacity lower than 200 tons (small rigs) and $11000 for rigs with capacity higher than 200 tons (big rigs). Similarly,
mobilization and demobilization costs are $50000 and $75000 for small and big rigs respectively. The model is not compensating for
the increases in ROP due to performance drilling, therefore this value should be changed in the software if there is an expected increase
in ROP. Lastly, the casing running times are calculated to include the casing running equipment preparations in the field. There is a 1.3
safety factor for casing lengths (to compensate for the damaged casing threads during casing running) and a 1.5 safety factor for drilling
bits (suggested to be stored in the field in case of extra bit needs).
It should also be noted that the costs associated with every item in Figure 4 are mostly estimations and are subject to chang e by different
operators/contractors and/or suppliers of equipment and therefore should not be taken as final costs of each operation or equipment but
as an estimation on pricing of the whole project.
0
500
1000
1500
2000
2500
3000
3500
0 5 10 15 20 25 30 35 40 45 50
Depth (m)
Operation Time (days)
Operation Time vs Depth
Gul & Aslanoglu
8
Drilling Location Preparation
Unit Cost ($)
Unit
Quantity
Total Cost ($)
Site Survey
10000
Ea
1
10,000.00
Location and Road Construction
50000
Ea
1
50,000.00
Location Rehabilitation
200000
Ea
1
200,000.00
Tubular Equipment
Unit Cost ($)
Unit
Quantity
Total Cost ($)
30" Conductor Casing
250
meters
20
5,000.00
20" Casing
150
meters
260
39,000.00
13 3/8" Casing
100
meters
910
91,000.00
9 5/8" Casing
75
meters
2600
195,000.00
7" Casing
60
meters
1300
78,000.00
Liner Hangers
Unit Cost ($)
Unit
Quantity
Total Cost ($)
7" Liner Hanger
20000
Ea.
1
20,000.00
Wellhead
Unit Cost ($)
Unit
Quantity
Total Cost ($)
21 1/4" x 2M Casing Head Housing
10000
Ea.
1
10,000.00
13 5/8" x 3M Casing Head Housing
6000
Ea.
1
6,000.00
11" Master Valve
20000
Ea.
1
20,000.00
Drilling Contract
Unit Cost ($)
Unit
Quantity
Total Cost ($)
Daily Drilling Rate
11000
day
45.42
499,658.25
Top Drive Rate
0
day
45.42
0.00
Mobilization Rate
50000
Ea.
1
50,000.00
Demobilization Rate
50000
Ea.
1
50,000.00
Diesel Cost
5000
liters/day
45.42
340,676.08
Water Cost
2000
liters/day
45.42
18,169.39
Mud Service
Unit Cost ($)
Unit
Quantity
Total Cost ($)
Mud Material and Chemicals
200,000.00
Personnel
1000
day
45.42
45,423.48
Mud Laboratory Equipment
200
day
45.42
9,084.70
Drilling Bits
Unit Cost ($)
Unit
Quantity
Total Cost ($)
26" Tricone Bit
20000
Ea.
1
20,000.00
17 1/2" Tricone Bit
12500
Ea.
1
12,500.00
12 1/4" Tricone Bit
9000
Ea.
4.5
40,500.00
8 1/2" Tricone Bit
5000
Ea.
3
15,000.00
Nozzles
100
Set
9.5
950.00
Directional Services
Unit Cost ($)
Unit
Quantity
Total Cost ($)
Personnel (2DD + 1MWD)
1500
day
45.42
68,135.22
Equipment Rental
3000
day
45.42
136,270.43
Cementing
Unit Cost ($)
Unit
Quantity
Total Cost ($)
20" Casing Cementing Operation
15000
Operation
1
15,000.00
13 3/8" Casing Cementing Operation
30000
Operation
1
30,000.00
9 5/8" Casing Cementing Operation
20000
Operation
1
20,000.00
Logging
Unit Cost ($)
Unit
Quantity
Total Cost ($)
PT Log
7500
Operation
1
7,500.00
PTS Log
7500
Operation
1
7,500.00
Compressor Service
7500
Operation
1
7,500.00
Company Labor and Supervision
Unit Cost ($)
Unit
Quantity
Total Cost ($)
Drilling Manager
10000
Ea.
1
10,000.00
Drilling Engineer
4000
Ea.
5
20,000.00
Geologist
4000
Ea.
3
12,000.00
Grand Total
2,359,867.55
Figure 4: Cost estimations page of the spreadsheet for the simulated example well
Gul & Aslanoglu
9
4. COMPARISON OF GEOTHERMAL AND OIL & GAS WELLS
In geothermal drilling, some specific problems are encountered more compared to oil and gas drilling [6]. These problems can be listed
as below:
1. High-temperature instrumentation and seals.
Geothermal wells expose drilling fluid and downhole equipment to higher temperatures than in common oil and gas drilling. High-
temperature problems are most frequently associated with the instruments used to measure and control drilling direction and logging
equipment. Most of the tools have limitations of 150°C active bottom hole temperature during drilling.
2. Logging
Geothermal logging units require wirelines that can withstand much higher temperatures than those encountered in everyday oil and gas
applications.
3. Thermal expansion of casing
Thermal expansion can cause buckling of casing and casing collapse, which can be costly. Cement operations take more precedence for
geothermal drilling rather than oil & gas. For the same reason, there is no hanger slips used in the wellhead in geothermal drilling to let
the casings expand and prevent possible collapses due to thermal expansion effect.
4. Drilling fluids and mud coolers
Mud coolers are mostly used when flow line temperature exceeds 75°C. High mud temperature causes danger for rig personnel and
results in longer trip times as well as damages the mud pump components. Other than this, the increase in mud temperatures decreases
the mud viscosity and yield point, which results in more usage of viscosifier to obtain the required rheological properties.
5. Drill bits
Formations bearing geothermal reservoirs tend to be harder and more fractured crystalline compared to sedimentary formations in oil
and gas operations. Most of the resources are in formations that are igneous, influenced by volcanic activity or altered by high
temperatures. These formations are generally more difficult to drill due to geophysical activities and confined stresses.
6. Lost circulation
Geothermal reservoirs are quite often under-pressured and prone to lost circulation due to faults associated in the zones, which results in
very difficult casing and cementing operations. In total loss circulations, lower cuttings carrying capacity of the mud results in higher
torque and drag, which may result in stuck pipe problems. Similarly, in casing operations, an empty well means higher pipe weights and
in some situations, it is not possible to cement these casings even while mixing them with lost circulation materials.
5. DISCUSSIONS AND CONCLUSIONS
Geothermal drilling costs follow the general oil and gas industry trend, which exemplifies a total dependence to crude oil prices. This
situation is likely to persist as long as the geothermal drilling sector does not build-up a strong market share of its own (Dumas, Antics,
& Ungemach, 2013). As shown in figure 8, a graph with the current trend of oil prices vs yearly average daily drilling rates has been
prepared. As can be seen in the figure, the trend of daily rig rates in Turkey are also following the trend of crude oil prices. That can best
be explained by the decreasing interest in demand which results in a more competitive market. On the other hand, another graph
comparing the total drilling costs from Australia, France, Germany, Iceland, Kenya, Nevada (US), Netherlands and US Oil & Gas with
the simulation results from the developed code is shown as in figure 9. In this calculation, the same inputs shown in figure 5 have been
used only with changes in production casing setting depth and ROP (decreasing average ROP 20% percent in each 500 meters
increment). The estimated average ROP for 8.5” section vs depth has been provided in table 2.
Table 2: Depth vs ROP values for the comparison study
Depth (m)
8.5 section ROP
(m/hr)
Total Estimated
Cost ($)
2100
7.50
2,028,640
2500
6.20
2,158,660
3000
5.20
2,359,867
3500
4.30
2,619,311
4000
3.60
2,935,344
4500
3.00
3,339,145
Gul & Aslanoglu
10
Figure 5: Crude oil prices vs daily rig rates in Turkey
As can be seen from figure 8, total well costs (drilling, well completion and well testing) have been compared with other geothermal
producing countries, with blue dots showing the results from the model provided. As illustrated here, well costs in Turkey are gradually
cheaper compared to other countries. The reasons of cheaper well construction can be explained in three manners. Firstly, daily
operating costs of rigs, third-party services and labor costs in Turkey are more affordable compared to other countries. Secondly, the
major equipment of the well, which are the casings, are chosen from the lowest cost option since wells are not overbalanced and there is
no need for a high cost or high-grade casing to drill these wells. Thirdly, the drilling experience in Turkey resulted in a competitive
market which resulted in more optimized wells with the minimum drilling times. There is also the need to note that the costs associated
with value added taxes are not included in model estimation calculations.
Figure 6: Comparison of published well costs of different countries vs model results in different depths in Turkey
2006 2008 2010 2012 2014 2016 2018
0 $/bbl
40 $/bbl
80 $/bbl
120 $/bbl
160 $/bbl
0 $/day
5000 $/day
10000 $/day
15000 $/day
20000 $/day
25000 $/day
Crude Oil Price
Daily Drilling Rate
750-900 HP, 100-120 ton (1000-1500 m) 1350-2000 HP, 200-320 ton (1500-3500 m) Crude Oil Price
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
0 3,000,000 6,000,000 9,000,000 12,000,000
Depth (m)
Cost (Million $)
Australia France Germany
Iceland Kenya Nevada (U.S)
Netherlands US Oil Wells Simulation results in Turkey
Gul & Aslanoglu
11
REFERENCES
Augustine, C., Tester, J. W., Anderson, B., & Petty, S. (2006). A Comparison Of Geothermal With Oil And Gas Well Drilling Costs.
Proceedings, Thirty-First Workshop on Geothermal Reservoir Engineering (pp. 1-15). Stanford: Stanford University.
Carolyn, K. (2013). Cost Model for Geothermal Wells. Geothermal Training Programme, 23.
Dumas, P., Antics, M., & Ungemach, P. (2013). Report on Geothermal Drilling. Geoelec.
Gul, S. (2017, December 01). Medya Enerji. Retrieved December 15, 2017, from Medya Enerji: www.medyaenerji.com
Huddlestone-Holmes, C. R. (2015). Forecast Costs for Geothermal Energy in Australia. Proceedings World Geothermal Congress 2015
(p. 11). Melbourne: International Geothermal Association.
Hughes, B. (2017, December 01). Baker Hughes Rig Count. Retrieved December 15, 2017, from Baker Hughes Rig Count:
http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-rigcountsoverview
Kaldal, G. S., Jonsson, M., Palsson, H., & Karlsdottir, S. N. (2015). Structural Analysis of Casings in High Temperature Geothermal
Wells in Iceland. Proceedings World Geothermal Congress 2015 (pp. 1-11). Melbourne: International Geothermal
Association.
Kaya, T. (2013). “An Overview on Geothermal Drilling and Projects in Turkey, 2013”. European Geothermal Congress (p. 7). Pisa:
European Geothermal Energy Council.
Kaya, T. (2017). An Overwiev on Geothermal Drilling and Projects in Turkey, 2017. Salt Lake City, Utah: Geothermal Resources
Council & Geothermal Energy Association.
Klein, C. W., Lovekin, J. W., & Sanyal, S. K. (2004). New Geothermal Site Identification and Qualification. California Energy
Commission, Public Interest Energy Research Program. Pier Public Interest Energy Research.
Lukawski, M. Z., Anderson, B. J., Augustine, C., Capuano Jr., L. E., Beckers, F. K., Livesay, B., & Tester, J. W. (2014). Cost analysis
of oil,gas, and geothermal well drilling. Journal of Petroleum Science and Engineering, 118, 1-14.
Mertoglu, O., Sismek, S., & Basarir, N. (2015). Geothermal Country Update Report of Turkey (2010-2015). Proceedings Worl
Geothermal Congress 2015 (p. 9). Melbourne: International Geothermal Association.
Njolnbi, D. N. (2015). A New Approach for Estimating the Geothermal Gradient and Deep Subsurface Temperature Distribution in
Turkey, Istanbul: Istanbul Technical University.
Richter, A. (2018, January 09 ). ThinkGeoEnergy. Retrieved January 12, 2018, from ThinkGeoEnergy: www.thinkgeoenergy.com
Shevenell, L. (2012). The Estimated Costs as a Function of Depth of Geothermal Development Wells Drilled in Nevada. GRC
Transactions, 36, 121-128.
Sveinbjornsson, M. B., & Thorhallsson1, S. (2012). Cost and Effectiveness of Geothermal Drilling. SIMS 53rd conference in Reykjavik
(p. 13). Reykjavík: Scandinavian Simulation Society.
Tester, J. W., Anderson, B. J., Batchelor, A. S., Blackwell, D. D., DiPippo, R., Drake, E. M., . . . Veatch, R. W. (2016). The Future of
Geothermal Energy. Idaho National Laboratory, U.S. Department of Energy National Laboratory operated by Battelle Energy
Alliance. Idaho Falls: U.S. Department of Energy.
Gul & Aslanoglu
12
APPENDIX A. DATA
Table A1: Geothermal power operation capacity by country (Gul, 2017)
Top 10 Geothermal Countries
Installed Capacity - MW (November 2017) - 13.968 Mw In Total
Rank
Country
Capacity
1
United States
3567
2
Philippines
1868
3
Indonesia
1809
4
Turkey
1053
5
New Zealand
980
6
Italy
944
7
Mexico
926
8
Kenya
710
9
Iceland
676
10
Japan
542
-
Other
893
-
TOTAL
13968
Table A2: Installed geothermal capacity of Turkey by year (Richter, 2017)
Turkey Geothermal Development
Installed Capacity (1984-2017)
Year
Capacity (MW)
1984
15
1985
15
2006
23
2007
23
2008
30
2009
77
2010
94
2011
114
2012
162
2013
311
2014
405
2015
624
2016
775
2017
1053
Under Construction
1072
In Development
1272
Planned
1827
Table A3: Additional Installed Geothermal Plan Capacity During 2017
ADDITIONAL CAPACITY DURING 2017
Rank
Country
Capacity (MW)
1
Turkey
325
2
Indonesia
165
3
Chile
48
4
Iceland
45
5
Mexico
25
6
United States
24
7
Japan
5
8
Portugal (Azores)
3
9
Hungary
3
-
TOTAL
643
Gul & Aslanoglu
13
Table A4: Crude oil prices WTI (2007-2017) from Nasdaq, Nymex (Crude Oil WTI)
Month
Year
Crude
Oil Price
Month
Year
Crude
Oil Price
Month
Year
Crude
Oil Price
Month
Year
Crude
Oil Price
October
2007
82.15
$/bbl
April
2010
84.14
$/bbl
October
2012
103.39
$/bbl
April
2015
57.42
$/bbl
November
2007
91.27
$/bbl
May
2010
75.54
$/bbl
November
2012
101.17
$/bbl
May
2015
62.50
$/bbl
December
2007
89.43
$/bbl
June
2010
74.73
$/bbl
December
2012
101.17
$/bbl
June
2015
61.30
$/bbl
January
2008
90.82
$/bbl
July
2010
74.52
$/bbl
January
2013
105.04
$/bbl
July
2015
54.43
$/bbl
February
2008
93.75
$/bbl
August
2010
75.88
$/bbl
February
2013
107.66
$/bbl
August
2015
45.72
$/bbl
March
2008
101.84
$/bbl
September
2010
76.11
$/bbl
March
2013
102.61
$/bbl
September
2015
46.29
$/bbl
April
2008
109.05
$/bbl
October
2010
81.72
$/bbl
April
2013
98.85
$/bbl
October
2015
46.96
$/bbl
May
2008
122.77
$/bbl
November
2010
84.53
$/bbl
Haz
2013
99.35
$/bbl
November
2015
43.13
$/bbl
June
2008
131.52
$/bbl
December
2010
90.07
$/bbl
June
2013
99.74
$/bbl
December
2015
36.56
$/bbl
July
2008
132.55
$/bbl
January
2011
92.66
$/bbl
July
2013
105.21
$/bbl
January
2016
29.92
$/bbl
August
2008
114.57
$/bbl
February
2011
97.73
$/bbl
August
2013
108.06
$/bbl
February
2016
31.05
$/bbl
September
2008
99.29
$/bbl
March
2011
108.65
$/bbl
September
2013
108.78
$/bbl
March
2016
37.34
$/bbl
October
2008
72.67
$/bbl
April
2011
116.32
$/bbl
October
2013
105.46
$/bbl
April
2016
40.75
$/bbl
November
2008
54.04
$/bbl
May
2011
108.18
$/bbl
November
2013
102.58
$/bbl
May
2016
45.98
$/bbl
December
2008
41.53
$/bbl
June
2011
105.85
$/bbl
December
2013
105.49
$/bbl
June
2016
47.69
$/bbl
January
2009
43.91
$/bbl
July
2011
107.88
$/bbl
January
2014
102.25
$/bbl
July
2016
44.22
$/bbl
February
2009
41.76
$/bbl
August
2011
100.45
$/bbl
February
2014
104.82
$/bbl
August
2016
44.84
$/bbl
March
2009
46.95
$/bbl
September
2011
100.83
$/bbl
March
2014
104.04
$/bbl
September
2016
45.06
$/bbl
April
2009
50.28
$/bbl
October
2011
99.92
$/bbl
April
2014
104.94
$/bbl
October
2016
49.29
$/bbl
May
2009
58.10
$/bbl
November
2011
105.36
$/bbl
May
2014
105.73
$/bbl
November
2016
45.28
$/bbl
June
2009
69.13
$/bbl
December
2011
104.26
$/bbl
June
2014
108.37
$/bbl
December
2016
52.61
$/bbl
July
2009
64.65
$/bbl
January
2012
106.89
$/bbl
July
2014
105.22
$/bbl
January
2017
53.63
$/bbl
August
2009
71.63
$/bbl
February
2012
112.70
$/bbl
August
2014
100.05
$/bbl
February
2017
54.36
$/bbl
September
2009
68.38
$/bbl
March
2012
117.79
$/bbl
September
2014
95.89
$/bbl
March
2017
50.91
$/bbl
October
2009
74.08
$/bbl
April
2012
113.75
$/bbl
October
2014
86.13
$/bbl
April
2017
52.23
$/bbl
November
2009
77.56
$/bbl
May
2012
104.16
$/bbl
November
2014
76.96
$/bbl
May
2017
49.91
$/bbl
December
2009
74.88
$/bbl
June
2012
90.73
$/bbl
December
2014
60.55
$/bbl
June
2017
46.13
$/bbl
January
2010
77.12
$/bbl
July
2012
96.75
$/bbl
January
2015
47.45
$/bbl
July
2017
54.78
$/bbl
February
2010
74.72
$/bbl
August
2012
105.28
$/bbl
February
2015
54.93
$/bbl
August
2017
51.87
$/bbl
Gul & Aslanoglu
14
Table A5: Yearly daily drilling rates in Turkey
Rig Type
Daily Rig Cost (Yearly Average)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
750-900 HP, 100-120 ton
(1000-1500 m)
$10.000
$10.000
$11.000
$12.500
$14.000
$14.000
$13.000
$13.000
$11.000
$10.000
1350-2000 HP, 200-320 ton
(1500-3500 m)
$14.000
$15.250
$15.500
$16.500
$19.500
$19.500
$18.500
$18.000
$15.000
$12.000
(Kaya, “An Overview on Geothermal Drilling and Projects in
Turkey, 2013”, 2013)
Yearly Averaged Rig Rate
Table A.6: Annual U.S Inflation (1985-2017) from Worldbank
Year
Inflation (%)
Year
Inflation (%)
Year
Inflation (%)
Year
Inflation (%)
1985
3.56
1993
2.95
2001
2.83
2009
-0.36
1986
1.86
1994
2.61
2002
1.59
2010
1.64
1987
3.74
1995
2.81
2003
2.27
2011
3.16
1988
4.01
1996
2.93
2004
2.68
2012
2.07
1989
4.83
1997
2.34
2005
3.39
2013
1.46
1990
5.40
1998
1.55
2006
3.23
2014
1.62
1991
4.23
1999
2.19
2007
2.85
2015
0.12
1992
3.03
2000
3.38
2008
3.84
2016
1.26
Table A.7: Geothermal drilling features in EU
Country
Depth
(m)
Total Cost (USD)
Unit Cost (USD/m)
Well Description
France
2.000
3.600.000
1.800
Deviated geothermal district heating doublets
Germany
2.000
4.800.000
2.400
Deep, deviated wells.
Italy
3.000
9.000.000
3.000
Mainly 2000-3000 m deep high enthalpy, dry-wet stram wells
Netherlands
4.000
19.200.000
4.800
Wells drilled on a lump sum base
Table A.8: Drilling cost of a geothermal well in Australia based on the SAM model (Huddlestone-Holmes, 2015)
Country
Depth (m)
Total Cost (USD)
Unit Cost (USD/m)
Well Description
Diameter (in)
Australia
2.500
7.200.000
2.880
Completely within sedimentary basin
8
Australia
4.000
11.200.000
2.800
Completely within sedimentary basin
8
Australia
3.000
11.200.000
3.733
Sedimentary basin with crystalline basement
8
Australia
4.000
19.200.000
4.800
Sedimentary basin with crystalline basement
8
Australia
5.000
28.800.000
5.760
Sedimentary basin with crystalline basement
8
Australia
4.000
16.800.000
4.200
Sedimentary basin with crystalline basement
6
Table A.9: Average well cost for different regions of Nevada by using Klein Regression (Shevenell, 2012)
Country
Depth
(m)
Total Cost
Escalated to
2016 (USD)
Unit Cost
(USD/m)
Region
Reservoir Depth
(ft)
Year
Cost (USD)
Nevada (U.S)
2.502
6.715.112
2.684
Beowawe
8207
1985
2.907.000
Nevada (U.S)
504
2.030.158
4.026
Bradys
1654
1992
1.152.000
Nevada (U.S)
1.677
565.945
337
Desert Peak
5501
1985
245.000
Nevada (U.S)
2.899
8.964.434
3.092
Dixie Valley
9509
1988
4.417.000
Nevada (U.S)
516
987.901
1.913
San Emidio
1694
1987
468.000
Nevada (U.S)
335
8.578.698
25.580
Soda Lake
1100
1987
4.064.000
Nevada (U.S)
922
2.018.666
2.190
Steamboat
3023
1986
905.000
Nevada (U.S)
909
2.721.600
2.994
Stillwater
2982
1989
1.341.000
Gul & Aslanoglu
15
Table A.10: Summary for an average well in Kenya (Carolyn, 2013)
Unit
Total
Pre-spud costs
Drillsite preparation
Fixed
$70.000
Rig mobilisation and transport
On-off
$420.000
Sum
$490.000
Daily operating costs
Rig rental with crew
Day rate
$1.893.000
Rig rental with crew-standby
Day rate
$350.000
Air compressors, balanced drilling
Day rate
$9.500
Cementing equipment
Day rate
$8.000
Maintenance Engineering
From table
$24.000
Drill stem inspection
Fixed
$300.000
Directional drilling equipment rentals
Day rate
$1.250
Lodging, catering (camp&food)
Day rate
$82.030
Sum
$2.667.780
Drilling consumables
Rock bits
From table
$182.000
Drilling detergent
From table
$46.000
Diesel&lubricationg oil
From table
$736.424
Cement
From table
$39.674
Cement additives
From table
$3.967
Drilling mud
From table
$170.610
Sum
$1.178.675
Casing and wellhead
Casing
From table
$556.718
Casing accessories & consumables
From table
$29.350
Wellhead equipment
From table
$79.550
Sum
$665.618
Services
Drilling supervision
From table
$30.000
Civil engineering
From table
$6.000
Site geologist
From table
$12.000
Geological services
From table
$9.000
Reservoir engineering
From table
$6.000
Planning & logistics
From table
$12.000
Logging services
Fixed
$30.000
Sum
$105.000
TOTAL
$5.107.073
TOTAL +15% CONTINGENCY
$766.061
PROJECT TOTAL
$5.873.134
Gul & Aslanoglu
16
Table A.11: U.S onshore oil well depth vs. cost (Lukawski, et al., 2014)
Country
Depth (m)
Total Cost (USD)
Unit Cost (USD/m)
U.S Onshore Oil
555
548.107
988
U.S Onshore Oil
945
772.036
817
U.S Onshore Oil
1.339
1.173.000
876
U.S Onshore Oil
1.940
2.768.836
1.427
U.S Onshore Oil
2.643
4.682.709
1.772
U.S Onshore Oil
3.361
6.848.041
2.038
U.S Onshore Oil
4.146
12.936.478
3.120
U.S Onshore Oil
4.911
16.999.206
3.461
Table A.12: EGS well drilling-cost estimates from Wellcost Lite model (Tester, et al., 2016)
Country
Depth (m)
Total Cost (USD)
Unit Cost (USD/m)
U.S
1.500
2.300.000
1.533
U.S
2.500
3.400.000
1.360
U.S
3.000
4.000.000
1.333
U.S
4.000
5.200.000
1.300
U.S
5.000
7.650.000
1.530
Table A13: Turkey Market Comparison (2012-2017)
2012-2017 Europe Continent Rig Count
Oct-17
Lowest
Highest
Average
St.Deviation
Turkey
23
18
44
30,89
6,41
Europe
91
82
153
118,45
20,85
Share
25,27%
19,12%
35,63%
26,20%
3,66%
2012-2017 Worldwide Geothermal Rig Count
Oct-17
Lowest
Highest
Average
St.Deviation
Turkey
13
1
26
13,37
7,02
Worldwide
41
32
66
45,97
8,02
Share
31,71%
2,22%
47,92%
29,25%
13,92%
Gul & Aslanoglu
17
Table A.14: Drilling activities in Europe (June 2012-October 2017) (Hughes, 2017)
Date
Europe
Turkey
Norway
Sakhalin
Romania
U.K
Offshore
Poland
Italy
Serbia &
Montenegro
Germany
Netherlands
Percentage
(Turkey)
Jan-13
134
30
22
7
8
22
5
3
4
8
8
22.39%
Feb-13
135
31
21
7
8
20
6
4
4
8
9
22.96%
Mar-13
133
30
20
7
8
21
5
3
4
6
8
22.56%
Apr-13
136
29
20
7
8
19
4
5
6
7
8
21.32%
May-13
124
29
18
9
8
14
3
5
4
5
7
23.39%
Jun-13
138
32
19
9
8
18
5
5
5
5
9
23.19%
Jul-13
139
32
16
11
8
16
8
5
5
6
8
23.02%
Aug-13
143
32
22
11
8
18
7
3
5
5
9
22.38%
Sep-13
139
33
25
11
8
10
6
4
5
4
9
23.74%
Oct-13
136
37
19
8
8
13
8
3
5
4
7
27.21%
Nov-13
137
37
20
8
9
15
9
3
5
6
5
27.01%
Dec-13
126
36
14
8
8
12
9
4
5
4
5
28.57%
Jan-14
126
36
14
5
8
14
6
5
5
4
6
28.57%
Feb-14
132
36
17
7
9
12
3
5
5
7
7
27.27%
Mar-14
148
40
21
7
9
16
3
7
5
5
10
27.03%
Apr-14
151
42
21
5
12
20
3
5
5
4
10
27.81%
May-14
149
42
18
7
13
19
3
5
5
3
10
28.19%
Jun-14
147
42
16
8
14
12
5
4
5
4
11
28.57%
Jul-14
153
42
17
12
12
14
7
5
5
4
12
27.45%
Aug-14
143
42
12
12
13
14
7
5
5
3
8
29.37%
Sep-14
148
43
15
12
15
13
7
5
5
2
8
29.05%
Oct-14
148
44
16
7
14
15
7
5
5
4
10
29.73%
Nov-14
149
44
17
7
15
17
7
4
5
5
10
29.53%
Dec-14
148
44
14
7
15
18
7
4
5
3
10
29.73%
Jan-15
128
37
13
6
11
15
7
4
5
3
6
28.91%
Feb-15
133
31
19
6
13
20
7
4
5
3
6
23.31%
Mar-15
135
32
18
6
13
19
7
3
5
4
8
23.70%
Apr-15
119
30
18
6
12
15
7
5
5
3
4
25.21%
May-15
116
30
18
6
10
16
7
5
5
3
5
25.86%
Jun-15
113
30
19
6
8
12
7
5
5
2
6
26.55%
Jul-15
108
28
20
8
8
12
7
3
5
0
5
25.93%
Aug-15
109
28
16
8
8
12
7
3
5
1
7
25.69%
Sep-15
109
28
17
8
8
14
6
4
5
1
5
25.69%
Oct-15
108
29
15
8
7
14
8
3
5
3
3
26.85%
Nov-15
108
30
14
8
6
12
12
3
5
3
3
27.78%
Dec-15
114
30
17
7
7
9
12
3
5
6
4
26.32%
Jan-16
108
29
18
5
7
8
10
3
5
7
4
26.85%
Feb-16
107
29
18
6
7
7
7
4
5
7
2
27.10%
Mar-16
96
28
19
6
6
9
4
5
3
5
4
29.17%
Apr-16
90
29
17
6
4
8
4
5
3
4
3
32.22%
May-16
95
29
17
10
4
9
4
5
3
3
2
30.53%
Jun-16
91
29
16
8
3
9
4
5
3
3
2
31.87%
Jul-16
94
29
20
8
3
10
4
4
3
2
2
30.85%
Aug-16
96
31
17
8
5
9
8
4
3
3
3
32.29%
Sep-16
92
29
16
8
6
8
8
3
3
1
3
31.52%
Oct-16
87
31
9
7
6
7
8
3
3
2
4
35.63%
Nov-16
97
29
15
7
6
10
8
4
3
4
3
29.90%
Dec-16
99
29
16
7
6
11
8
4
3
4
2
29.29%
Jan-17
98
32
12
7
6
8
8
5
3
3
3
32.65%
Feb-17
107
29
16
12
7
11
10
4
3
3
2
27.10%
Mar-17
94
23
15
12
7
8
10
4
3
4
0
24.47%
Apr-17
91
21
17
11
7
8
10
3
3
2
23.08%
May-17
95
23
18
11
5
10
10
4
3
3
1
24.21%
Jun-17
91
21
15
11
5
8
10
4
3
3
2
23.08%
Jul-17
82
20
13
11
5
10
10
2
2
2
24.39%
Aug-17
91
18
15
11
5
12
10
2
2
4
3
19.78%
Sep-17
91
21
11
10
7
10
7
3
2
4
3
23.08%
Oct-17
91
23
16
11
7
6
6
4
3
2
2
25.27%
Gul & Aslanoglu
18
Table A.5: Geothermal drilling worldwide (June 2012-October 2017) (Hughes, 2017)
Date
Worldwide
Turkey
Indonesia
Kenya
France
Italy
Algeria
Philippines
Germany
Iceland
Netherlands
Percentage
(Turkey)
Feb-14
40
11
1
9
1
2
1
1
27.50%
Mar-14
42
11
9
2
0
1
1
1
26.19%
Apr-14
41
10
9
2
1
1
1
24.39%
May-14
35
10
9
1
1
0
0
1
28.57%
Jun-14
37
10
9
1
1
0
2
27.03%
Jul-14
38
10
10
2
2
2
26.32%
Aug-14
42
10
10
2
3
2
23.81%
Sep-14
40
10
10
2
3
1
25.00%
Oct-14
36
10
0
10
2
1
4
1
27.78%
Nov-14
35
10
10
2
1
4
1
28.57%
Dec-14
34
10
10
2
1
4
1
29.41%
Jan-15
32
10
10
1
3
1
31.25%
Feb-15
66
13
2
10
2
3
1
0
19.70%
Mar-15
36
14
10
2
2
1
38.89%
Apr-15
40
17
10
2
0
3
42.50%
May-15
40
17
10
2
1
3
42.50%
Jun-15
42
17
0
11
2
1
4
1
40.48%
Jul-15
42
18
3
11
1
3
0
42.86%
Aug-15
48
18
4
12
2
3
1
1
37.50%
Sep-15
44
18
3
12
1
1
0
1
40.91%
Oct-15
44
19
2
11
1
0
2
1
0
43.18%
Nov-15
47
20
1
10
2
1
3
1
1
42.55%
Dec-15
52
20
2
10
2
1
4
1
1
38.46%
Jan-16
49
20
2
10
2
1
3
1
0
1
40.82%
Feb-16
51
21
1
10
2
3
2
1
0
41.18%
Mar-16
48
22
4
10
2
1
3
1
0
1
45.83%
Apr-16
48
23
5
10
2
1
2
1
47.92%
May-16
54
23
5
10
2
1
2
2
1
42.59%
Jun-16
53
23
5
10
2
1
2
1
0
43.40%
Jul-16
57
23
6
10
2
2
1
1
40.35%
Aug-16
57
25
6
10
2
2
2
1
43.86%
Sep-16
56
23
7
10
2
0
2
0
2
1
41.07%
Oct-16
55
25
6
10
2
1
1
2
1
45.45%
Nov-16
51
23
5
10
2
1
1
2
1
45.10%
Dec-16
51
24
6
10
0
2
0
1
1
2
47.06%
Jan-17
60
26
12
10
1
2
1
1
2
43.33%
Feb-17
52
23
11
10
2
1
2
1
44.23%
Mar-17
44
19
9
10
2
0
1
1
0
43.18%
Apr-17
43
17
7
10
2
1
1
1
39.53%
May-17
40
18
5
8
2
1
1
1
1
45.00%
Jun-17
35
14
6
7
2
0
1
2
1
40.00%
Jul-17
35
12
8
7
1
2
1
2
0
34.29%
Aug-17
37
11
9
7
1
2
0
1
2
1
29.73%
Sep-17
36
13
7
7
1
2
1
1
2
1
0
36.11%
Oct-17
41
13
8
7
2
2
1
1
1
1
1
31.71%
Gul & Aslanoglu
19
APPENDIX B. SENSITIVITY ANALYSIS
30
35
40
45
50
55
60
1000000
1400000
1800000
2200000
2500 3000 3500 4000
Total Operation Cost ($)
Total Operation Time and Operation Cost vs 7" Casing Setting Depths
Total Operation Cost ($) Total Operation Time (days)
40
45
50
55
60
65
70
1000000
1200000
1400000
1600000
1800000
2000000
0 2 4 6 8 10 12
Total Operation Cost
Estimated Average ROP for 8.5" Section
Total Operation Time and Operation Cost vs 8.5" Estimated Average ROP
Total Operation Cost ($) Total Operation Time (days)
... Kivure [18] evaluated the geothermal well drilling cost of a case study to find the most expensive geothermal well drilling section; and his analysis showed that the directional well drilling expense is higher than vertical well geometry at the same well depth. Gul and Aslanoglu [19] made a numerical study of drilling and testing cost of wells to predict the drilling cost. They used the drilling data of twenty wells to estimate the drilling cost trend. ...
... Figure 6 shows Italy and Turkey's well drilling cost based on QUE$TOR drilling cost. In addition, the available well drilling cost in some European countries based on other references [16,17,19,26] is illustrated in this graph. It appears that the QUE$TOR well drilling costs of Italy and Turkey are in the middle range of other available well drilling costs in Europe. ...
... The well drilling cost of the Kizildere geothermal power plant shows good compatibility with Turkey's presented model. The points related to the well drilling cost of Italy, Germany, Iceland, and the Kipsang model are close to the well drilling cost model based on QUE$TOR. Figure 7 shows the well drilling cost of the USA model according to QUE$TOR and other performed well drilling expenses [10,12,17,19,25,34] in different regions of the USA. It can be seen that some points are exactly compatible with the presented model. ...
Article
This paper reports a comprehensive survey of well drilling time and cost. The models include both specific correlations on various well types and generalised correlations for rough estimation. The models are derived from robust multivariable regression to minimise the residuals. Africa has the highest construction cost component in well drilling and the United States has the lowest. Data in various regions are compared with European and World average drilling data. Drilling time in Italy is similar to Europe and world averages. The proposed model directly estimates both the drilling cost and time to be used in fundamental research and feasibility studies for geothermal power plants applicable worldwide.
... Wells of measured depth between 2000 and 4000 m can cost between 3 and 10 million dollars [20]. These costs can be attributed to expensive drill rigs, recruitment of expert individuals, and manual labor [21]. In addition to installation costs, it is also vital to consider changes in the performance of the wells over their lifetime. ...
Article
Geothermal energy is a promising alternative to conventional fossil-based energy sources. Geothermal reservoirs are pools of water heated by magma deep below the Earth's crust, the steam of which can be used to power turbines or pass through heat pumps. Recovering this heat to the surface requires construction and subsequent cementation of subsurface geothermal wells. The conditions to which the cemented annulus is exposed are frequently harsher and more extreme than that of oil and gas wells. Cement slurries used in geothermal wells are vulnerable to acidic and carbon dioxide-rich brine and temperatures above 500 °C. Overall, well failure is a consequence of degradation of cemented annuli and cracking due to exposure to these severe conditions. This literature review addresses the durability problems associated with the use of inadequate cementing materials for such harsh conditions. New alternative cementitious formulations that have been developed in response to the weaknesses of conventional cementing materials are discussed. Relevant studies are compiled and broken into main sections such as current cementing methods and challenges, alternative cementitious materials, monitoring systems, and environmental impact. This work introduces a thorough analysis of materials from the early 1950s until 2021 identifying the significant knowledge gaps. These gaps include designing chemical additives for geothermal well cements and understanding the broad chemical composition of alternative cementitious materials. The review also proposes promising sources for potential geothermal well cements based on technologies in other harsh environments, such as marine and fire-prone applications.
... By multiplying the cost per meter length of the casing with the total length of the casing, the overall casing procurement cost can be calculated that is USD 29,507 per well. The casing cost obtained from this calculation is slightly higher than that reported by Gul & Aslanoglu [16] but lower than the assumption used by Kipsang [17]. Casing prices may vary by country, possibly due to differences in regulations and infrastructure availability. ...
Article
Full-text available
Indonesia is currently reviewing the use of underground coal gasification (UCG) technology to utilize deep-seated coal. UCG may exploit the coal deposit that is not feasible for open-pit mines due to its great depths. In this study, the UCG plant in two coal mines, the Kideco Jaya Agung (KJA) and the Indominco (IMM) coal mines, will be compared their economics in producing low heating value gas with a capacity of 170,000 MJ/hour. The UCG plants implement the linking vertical well (LVW) technique combined with reverses combustion linking (RCL). The discounted cash flow (DCF) method is used for financial analysis to determine the minimum selling price of UCG low heating value gas. The study aims to understand the economic feasibility of applying UCG technology to Indonesia’s different characteristics of coal deposits. The results show the minimum prices of the low heating value UCG gas of KJA and IMM UCG plants are USD 3/MMBTU and USD 3.57/MMBTU, respectively. The operating cost of the IMM UCG is higher than that of the KJA UCG plant due to its thinner and deeper coal seams.
... Since exploration drilling costs are a large portion of the exploration cost, it can be concluded that lower geothermal exploration cost in Turkey is due to low cost of drilling. This is confirmed by Gul and Aslanoglu (2018) which described that standard well cost in Turkey is in the range of 3.3 million USD for a 4500 m deep well, which is cheap compared to other countries. This is due to the following reasons: ...
Technical Report
Full-text available
This study evaluates exploration methods, strategies, results and costs of 5 geothermal projects in Indonesia. Observations are compared to reported cases from other leading geothermal countries. Exploration strategy plays an important role in determining success of the exploration stage. Consequently, exploration strategy determines commerciality and is important for decision making at the development stage gate. There is a gap in the Indonesian geothermal industry where significant elements of actual exploration strategies and costs have hardly been published with an actual reference. In this study, exploration methods, strategies, results and expenditures, along with total project costs are collected from feasibility studies, exploration reports and annual reports. Cost indices are used to reflect historical changes. This study adopted quantitative methods that involve descriptive-comparative analysis. Exploration variables are evaluated prior to conducting statistical examination of the findings. In the 5 Indonesian geothermal projects the number of explorations wells ranges from 2 to 10 drilled from 1 to 5 well pads. Exploration drilling success ratio in the 5 projects ranges from 33 to 67%. The power density ranges from 6 to 15 MW/km 2 and the recent average exploration well output acquired from 29 wells in the 5 projects is 5 MW/well. The exploration cost in the 5 projects is expected to be in the range 15-40% of the overall planned project cost. This amounts to 0.6-2 million USD per MW which is significantly higher than in reference projects in other countries where the exploration cost was in the range of 0.2-0.8 million USD per MW.
... The constant demand for energy from fossil fuels, such as oil and natural gas is driving the energy industry to explore more for innovative materials that are cost effective and can drill in deeper drilling depths, and unexplored areas (Sercan and Volkan 2018). Among all the functions of drilling muds, the lifting and suspendability of drilled cuttings are the most important functions required to prevent poor hole cleaning, and subsequently avoid the occurrence of wellbore drilling problems (Kelessidis and Bandelis 2004;Caenn et al. 2017;Ismail et al. 2019). ...
Article
Cuttings lifting to the surface is a special function of drilling muds and it can lead to undue torque and drag, differential pipe sticking and wellbore collapse if this function is not effectively applied. In this study, cuttings lifting to the surface separating facility by water-based mud (WBM) containing enriched polypropylene–nanosilica composite (PP–SiO2 NC) modified by (3-aminopropyl) triethoxysilane (APTES) and those formulated with partially hydrolyzed polyacrylamide (PHPA) were examined. The effect of different annular velocities (66.1, 92.4, 118.8, 138.6, 234.1 ft/min), cuttings diameter (0.5–0.99, 1.0–1.99, 2.0–2.79, 2.8–4.0 mm) and hole inclinations (45°, 60°, 75° and 90°) in a cuttings rig simulator (2.4-in. × 1.2-in., 16-ft. long annulus) with and without pipe rotation were investigated. The results showed that more cuttings were lifted out of the hole with higher concentrations of APTES modified PP–SiO2 NC in WBM than with the PHPA muds, which is due to increased colloidal forces that increase the interaction between the cuttings and the APTES modified PP–SiO2 NC particles. The lifting of cuttings significantly depends on flow rate. The lifting will increase with an increase in the annular velocity and with the whirling motion of the drill pipe with or without enriched PP–SiO2 NC or PHPA. This is because higher flow rate produces larger axial forces to drive the cuttings and reduces the cuttings slip velocity. The recovery of cuttings is most difficult at the hole angle of 45°, due to the decreased in the axial annular velocity with increasing hole deviation. The laboratory results indicate improved lifting ability of the WBM with the presence of the APTES modified PP–SiO2 NC, demonstrating the necessity for its application in a cuttings transport process.
Article
Full-text available
An economic assessment of different geothermal power cycle configurations to generate cost models is conducted in this study. The thermodynamic and exergoeconomic modeling of the cycles is performed in MATLAB coupled to Refprop. The models were derived based on robust multivariable regression to minimize the residuals by using the genetic algorithm. The cross-validation approach is applied to determine a dataset to examine the model in the training phase for validation and reduce the overfitting problem. The generated cost models are the total cost rate, the plant’s total cost, and power generation cost. The cost models and the relevant coefficients are generated based on the most compatibilities and lower error. The results showed that one of the most influential factors on the ORC cycle is the working fluid type, which significantly affects the final economic results. Other parameters that considerably impact economic models results, of all configurations, are geothermal fluid pressure and temperature and inlet pressure of turbine. Rising the geothermal fluid mass flow rate has a remarkable impact on cost models as the capacity and size of equipment increases. The generated cost models in this study can estimate the mentioned cost parameters with an acceptable deviation and provide a fast way to predict the total cost of the power plants.
Presentation
Ulumbu geothermal system is a quarternary volcanic geothermal system located in East Nusa Tenggara. This geothermal system belongs to high-enthalpy system with reservoir temperature about 230°-240°C. Ulumbu geothermal reservoir consist of lava and pyroclastic rock with top of reservoir is on depth 900-1200 m or elevation -100 m from sea level. The main heat source of Ulumbu geothermal system is from magmatic intrusion of Poco Leok volcano, where the fumarole discharged is. The upflow zone is indicated to be towards Lungar area.The hydrothermal fluids flow laterally to the outflow zone in the west of Ulumbu field. Landslide hazard should be a consideration in development of Ulumbu geothermal area. With probabilistic approach toward the resource assessment, it calculated that Ulumbu geothermal P10, P50, P90 are 71.02 MW, 105 MW, 150.57 MW respectively. Hence, the resource is sufficient to facilitate the 2x20 MW field extension. Ulumbu geothermal system has 2 layers of reservoir that is, vapor-dominated reservoir in the top of the reservoir and liquid-dominated reservoir in the bottom of the reservoir. Development wells are planned with standard hole for the early stage and with "decision-making stages principle" the next development well can use big hole. The development strategy for 30-years production of Ulumbu geothermal is also based on 4 principles of this project development: 1) Risk management; 2) Low cost; 3) Optimum output; 4) Environmentally friendly while maintaining technical, economic, environmental, and social sustainability. We recommend using single-flash steam power plant technology since it is cheapest technology with minimum efficiency difference and requires smaller land area than double-flash due simpler plant design. In order to develop this project, we must invest 142,648,600 USD with IRR of 11% NPV of 17,292,771 USD and benefit to cost ratio 2.04 with the proposed electricity price is 14.8 cents USD/kWh. As our conclusion, we decided that the Ulumbu Units 5-6 (2x20 MW) field extension project is technically and economically feasible to develop.
Conference Paper
Full-text available
Geothermal electricity price is greatly affected by essential constituent predominantly exploration and development costs. Both of exploration and development drilling costs in Indonesia are accountable for nearly up to 51% of power generation project investment. Consequently the effectiveness of resource planning which followed by successful drilling operation executions will resulted in commercial well that will provide sufficient steam supply in the duration of project lifetime. This paper presents statistical evaluation of drilling performance which is conducted by using geothermal drilling unit cost (cost/ meter) criteria. This study investigates drilling cost comparison with reference to 203 drilling activities which conducted from 2011 to 2019 using statistical method. Geothermal wells in Indonesia are mostly drilled to a depth ranges from 1200 to 2800m which represented a wide range of various reservoir depths. The results indicate that drilling cost in Indonesia range from 2000 to 3900 USD/m with mean average of 3499 USD/m which somewhat higher than other geothermal leading countries. Drilling performance exhibit "learning curve" gradually from exploration to operation phase. We also evaluate the effect of influencing factors which affected drilling cost in Indonesia among others are drilling depths, geological setting, operational challenges, contractual scheme and other global factors such as oil price trend. This study also offers subsurface geothermal information in Indonesia which obtained from drilling activities presented in a table that contains the maximum depth of drilling, range of reservoir depth, reservoir temperature, and well capacity. By considering information on well productivity, we estimate that drilling cost per MW well capacity distribution of productive wells in Indonesia are in the ranges of 0.4 to 1.5 MUSD per MW.
Chapter
The oil and gas well construction is often associated with the unknowns and uncertainties while executing the operations. Because, while drilling, the drilling bit is under the ground where the information is usually gained through interpreting several surface and downhole sensors. Considering the lack of direct access to and visual of the downhole in real-time, the information from these sensors is vital to carry out safe and engineered operations. Typically, these sensors relay basic information such as the pressure in the pipes via a pressure transducer, the weight of the pipes via load transducer, etc. In the well construction process, there are many events where data is not collected or merely the quality is less than desired. Recent want of automation of the well construction process of several oil and gas companies showed the advance and amount of the existing sensors is inadequate. There is a need for more advanced sensors to collect meaningful data and more advanced materials while constructing the well. In the process of well construction, there are many events that the sensors are not used and no data is collected. At the recent years, the oil and gas industry showed a keen interest in automation of the well construction. Researchers started to seek advanced sensors to automate the parts of the process, for example, automation of drilling fluid measurements, automation of pipe handling, etc. An example of drilling fluid measurement automation sensors and materials is presented. The results of this recent successful endeavor motioned the need for more emphasis on the advanced sensors and materials for well construction. In this chapter, the authors are providing a review of select relatively advanced materials and sensors in various disciplines in well construction. The oil and gas industry needs a stronger highlight on the better, advanced sensors and materials to carry out the operations safely and systematically. We hope that this review will increase awareness in the industry to gain more insight into the advanced sensors and materials and use them to accomplish safe and optimized operations.
Article
Full-text available
Abstract Deep-borehole heat exchangers (DBHE) are generally coaxial pipes installed in deep boreholes and has become an alternative approach to utilize geothermal energy. Since the performance of the DBHE system can be affected by several parameters, it is important to optimize the design of parameters for the DBHE. In this paper, based on the analytical method, we carried out the sensitivity analysis of DBHE design parameters, including outer pipe diameter, inner pipe diameter, flow rate, outer pipe materials, grout materials, and borehole depth during continuous operation for 4 months. The sensitivity analysis results indicate that the heat extraction rate can be significantly affected by outer pipe diameter, borehole depth, and flow rate. The effects of grout materials, inner pipe diameter and outer pipe materials are of second-order. Finally, an optimization method based on the lowest Average Energy Cost index was proposed to optimize these DBHE design parameters under different geological conditions. Given the cost in this study, a combination scheme of all the optimal parameters is given for different depth wells under different geological conditions.
Conference Paper
Full-text available
Large temperature changes are a central design concern in a diverse range of structures. Large and quick wellbore temperature changes in high temperature geothermal wells, e.g. during discharge and quenching of wells, produce large thermal stresses in the production casing which can cause casing failures. The wellbore temperature change during discharge causes the wellhead to rise due to thermal expansion of the casings, since the wells are constructed of several concentric steel casings which are fully cemented to the top. The structural integrity of such casings is essential for the utilization of high temperature geothermal wells. The casings in connection to the wellhead form a structural system which involves nonlinear interaction of the contacting surfaces. Therefore, the structural system is analyzed numerically with the use of the nonlinear finite element method (FEM). Three FEM models are presented here with the purpose of evaluating the structural integrity of high temperature geothermal well casings. A load history is used in the analysis, consisting of transient wellbore temperature and pressure changes.
Article
Expected well costs can be a major factor in whether companies obtain financing due to expense and moderate success rates of drilling. Well permitting records are reported by state agencies, and well production from individual wells within producing areas are reported monthly (in NV) so that one can determine, in retrospect, which of the permitted wells actually led to geothermal production and power generation. A companion paper (Shevenell, 2012, this volume) compiles and evaluates geothermal well records submitted to the Nevada Division of Minerals, and estimates the success rates of geothermal wells drilled in Nevada since the early stages of exploration in the 1970s and 1980s, through construction of the power plants currently in existence in northern Nevada. This paper uses that information to estimate the minimum expected costs associated with drilled wells and production per MW, assuming well depths are a dominant factor in determining costs. Because depths are not the only factor determining power plant costs, costs noted here are likely minima.
Article
This paper evaluates current and historical drilling and completion costs of oil and gas wells and compares them with geothermal wells costs. As a starting point, we developed a new cost index for US onshore oil and gas wells based primarily on the API Joint Association Survey 1976–2009 data. This index describes year-to-year variations in drilling costs and allows one to express historical drilling expenditures in current year dollars. To distinguish from other cost indices we have labeled it the Cornell Energy Institute (CEI) Index. This index has nine sub-indices for different well depth intervals and has been corrected for yearly changes in drilling activity. The CEI index shows 70% higher increase in well cost between 2003 and 2008 compared to the commonly used Producer Price Index (PPI) for drilling oil and gas wells. Cost trends for various depths were found to be significantly different and explained in terms of variations of oil and gas prices, costs, and availability of major well components and services at particular locations.
A Comparison Of Geothermal With Oil And Gas Well Drilling Costs
  • C Augustine
  • J W Tester
  • B Anderson
  • S Petty
Augustine, C., Tester, J. W., Anderson, B., & Petty, S. (2006). A Comparison Of Geothermal With Oil And Gas Well Drilling Costs. Proceedings, Thirty-First Workshop on Geothermal Reservoir Engineering (pp. 1-15). Stanford: Stanford University.
Cost Model for Geothermal Wells
  • K Carolyn
Carolyn, K. (2013). Cost Model for Geothermal Wells. Geothermal Training Programme, 23.
Forecast Costs for Geothermal Energy in Australia
  • C R Huddlestone-Holmes
Huddlestone-Holmes, C. R. (2015). Forecast Costs for Geothermal Energy in Australia. Proceedings World Geothermal Congress 2015 (p. 11). Melbourne: International Geothermal Association.
Baker Hughes Rig Count
  • B Hughes
Hughes, B. (2017, December 01). Baker Hughes Rig Count. Retrieved December 15, 2017, from Baker Hughes Rig Count: http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-rigcountsoverview
An Overwiev on Geothermal Drilling and Projects in Turkey
  • T Kaya
Kaya, T. (2017). An Overwiev on Geothermal Drilling and Projects in Turkey, 2017. Salt Lake City, Utah: Geothermal Resources Council & Geothermal Energy Association.
New Geothermal Site Identification and Qualification
  • C W Klein
  • J W Lovekin
  • S K Sanyal
Klein, C. W., Lovekin, J. W., & Sanyal, S. K. (2004). New Geothermal Site Identification and Qualification. California Energy Commission, Public Interest Energy Research Program. Pier Public Interest Energy Research.