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Coal Mine: Amasra, Turkey
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Application of Longhole Directional Drilling for Methane Drainage at
the Amasra Hard Coal Mine
Amasra, Turkey
Pre-feasibility Study for
Coal Mine Methane Drainage and Utilization
Sponsored by
U.S. Environmental Protection Agency, Washington, DC USA
Prepared by:
Advanced Resources International, Inc.
REI Drilling, Inc.
February 2015
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Disclaimer
This report was prepared for the U.S. Environmental Protection Agency (USEPA). This analysis uses
publicly available information in combination with information obtained through direct contact with
mine personnel. USEPA does not:
(a) make any warranty or representation, expressed or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this report, or
that the use of any apparatus, method, or process disclosed in this report may not
infringe upon privately owned rights;
(b) assume any liability with respect to the use of, or damages resulting from the use of, any
information, apparatus, method, or process disclosed in this report; or
(c) imply endorsement of any technology supplier, product, or process mentioned in this
report.
Acknowledgements
This publication was developed at the request of the United States Environmental Protection Agency
(USEPA), in support of the Global Methane Initiative (GMI). In collaboration with the Coalbed Methane
Outreach Program (CMOP), Advanced Resources International, Inc. (ARI) and REI Drilling, Inc. (REI)
authored this report based on information obtained from the coal mine partner, HEMA.
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Table of Contents
Executive Summary
1 Introduction
2 Background
2.1 The Turkish Coal Industry
2.2 Coal Mine Methane in Turkey
2.3 Amasra Coal Project
2.4 HEMAEnergi
3 Summary of Mine Characteristics
3.1 Coal Production
3.2 Geological Characteristics
3.2.1 Regional Geology and Tectonics
3.2.2 Lithology
3.3 Mining and Geologic Conditions of Operations
3.4 Coal Seam Characteristics
3.4.1 Density
3.4.2 Proximate Analysis
4 Gas Resources
4.1 Overview of Gas Resources
4.2 Proposed Gas Drainage Approach
4.2.1 In-Seam Gas Drainage Boreholes
4.2.2 Horizontal Gob Boreholes
4.3 Estimating Production from In-Seam Gas Drainage Boreholes
4.3.1 COMET3* Model
4.3.2 Model Preparation & Runs
4.3.3 In-Seam Gas Drainage Borehole Model Results
4.4 Estimating Production from Horizontal Gob Boreholes
5 Market Information
6 Opportunities for Gas Use
7 Economic Analysis
7.1 Development Scenario
7.1.1 Pre-Drainage Project Development
7.1.2 Gob Gas Borehole Project Development
7.2 Gas Production Forecast
7.3 Project Economics
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7.3.1 Economic Assessment Methodology 50
7.3.2 Upstream (CMM Project) Economic Assumptions and Results 50
7.3.3 Downstream (Power Project) Economic Assumptions and Results 53
7.3.4 Downstream (CNG Project) Economic Assumptions and Results 55
8 Conclusions, Recommendations and Next Steps 58
Appendix 60
Works Cited 72
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List of Figures
Figure 1: Summary of Economic Results for the CMM Project 9
Figure 2: Summary of Economic Results for Power Project 10
Figure 3: Summary of Economic Results for CNG Project 11
Figure 4: Turkey Coal Consumption and Production, 1980-2014 13
Figure 5: Turkey's CH4 Emissions from Coal Mining (TurkStat, 2014) 14
Figure 6: Map of Amasra Project Location (HEMA, 2013) 15
Figure 7: Map Location of the Zonguldak Coal Field and the City of Amasra (Schwochow, 1997) 16
Figure 8: Mine Layout Indicating Location of East, West, and Southeast Production Blocks 17
Figure 9: Coal Production Estimate for Amasra Hard Coal Mine (AHPG, 2013) 18
Figure 10: Tectonic map of the Black Sea Region (Okay & Goriir, 2007) 19
Figure 11: Correlated stratigraphic column of Carboniferous formations in the Zonguldak and Amasra
regions (Burger, Bandelow, & Bieg, 2000) 20
Figure 12: Location of Longwall Panels of the East Production Block 23
Figure 13: The relationship between coal type and the parameters of Heat Value, Vitrinite reflectance,
Vitrinite Carbon, Volatile matter and Moisture content. (McCune, 2002) 25
Figure 14: Diagram of Proposed Gas Drainage Approach (Plan View) 30
Figure 15: Cross Section View of In-Seam Gas Drainage Borehole Placement 30
Figure 16: Cross Section View of Horizontal Gob Borehole Placement 31
Figure 17: COMET® Model Layout for In-Seam Gas Drainage Borehole Well Spacing Cases 32
Figure 18: Methane Isotherm Used in Simulation 34
Figure 19: Relative Permeability Curve Used in Simulation 35
Figure 20: Simulated Per-Well Gas Production Rate 37
Figure 21: Simulated Per-Well Cumulative Gas Production 37
Figure 22: Simulated Reduction in Gas Content Over Time - 2 Wells Per Panel Case 38
Figure 23: Simulated Reduction in Gas Content Over Time - 4 Wells Per Panel Case 38
Figure 24: Illustration of Reduction in Gas Content Over Time 39
Figure 25: Gob Gas Flow Rate for 1000 m Gob Borehole Configurations (70% CH4) 40
Figure 26: Bi-Annual Electricity Prices for Industrial Consumers in Turkey, 2008-2013 41
Figure 27: Drilling Scenarios for Pre-Drainage Development 44
Figure 28: Drilling Scenario for Gob Gas Borehole Development 44
Figure 29: Pre-Drainage Gas Production Forecast for Case 1 45
Figure 30: Pre-Drainage Gas Production Forecast for Case 2 46
Figure 31: Pre-Drainage Gas Production Forecast for Case 3 47
Figure 32: Pre-Drainage Gas Production Forecast for Case 4 48
Figure 33: Gob Gas Production Forecast 49
Figure 34: Simplified Schematic Diagram of CMM Project 50
Figure 35: Summary of Economic Results for the CMM Project 53
Figure 36: Summary of Economic Results for Power Project 55
Figure 37: CNG Station and O&M Costs Versus Throughput (Johnson, 2010) 57
Figure 38: Summary of Economic Results for CNG Project 58
Figure 39: CMM Project Cash Flow for Case 1 (2 wells per panel; 3 years pre-drainage) 60
Figure 40: CMM Project Cash Flow for Case 2 (2 wells per panel; 5 years pre-drainage) 61
Figure 41: CMM Project Cash Flow for Case 3 (4 wells per panel; 3 years pre-drainage) 62
Figure 42: CMM Project Cash Flow for Case 4 (4 wells per panel; 5 years pre-drainage) 63
Figure 43: Power Project Cash Flow for Case 1 (2 wells per panel; 3 years pre-drainage) 64
Figure 44: Power Project Cash Flow for Case 2 (2 wells per panel; 5 years pre-drainage) 65
Figure 45: Power Project Cash Flow for Case 3 (4 wells per panel; 3 years pre-drainage) 66
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Figure 46: Power Project Cash Flow for Case 4 (4 wells per panel; 5 years pre-drainage) 67
Figure 47: CNG Project Cash Flow for Case 1 (2 wells per panel; 3 years pre-drainage) 68
Figure 48: CNG Project Cash Flow for Case 2 (2 wells per panel; 5 years pre-drainage) 69
Figure 49: CNG Project Cash Flow for Case 3 (4 wells per panel; 3 years pre-drainage) 70
Figure 50: CNG Project Cash Flow for Case 4 (4 wells per panel; 5 years pre-drainage) 71
List of Tables
Table 1: Coal Thickness Range by Seam for the East, West, and Southeast Production Blocks 22
Table 2: Minimum and average density of the HEMA wells in Amasra 24
Table 3: Vitrinite reflectance values of Zonguldak and Armutcuk 26
Table 4: Virtrinite reflectance values of the Amasra region 26
Table 5: Coal Analysis Results for East Block Coals (AHPG, 2013) 27
Table 6: Coal Analysis Results for Southeast Block Coals (AHPG, 2013) 27
Table 7: Coal Analysis Results for West Block Coals (AHPG, 2013) 28
Table 8: Liberated Methane Measurement at TTK Colliery Drifts in 1997 (AHPG, 2013) 28
Table 9: COMET3® Input Parameters Used to Simulate In-Seam Gas Drainage Borehole Production 33
Table 10: Fuel Prices in Turkey, 16 June 2014 41
Table 11: Potential CMM Utilization Options 42
Table 12: Summary of Input Parameters for the Evaluation of Upstream Economics (CMM Project) 51
Table 13: Preliminary Cost Estimate for Phase I and Phase II 52
Table 14: Summary of Input Parameters for the Evaluation of Downstream Economics (Power Project) 54
Table 15: Summary of Input Parameters for the Evaluation of Downstream Economics (CNG Project)... 56
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Executive Summary
With funding from the United States Environmental Protection Agency (USEPA), under the auspices of
the Global Methane Initiative (GMI), this pre-feasibility study evaluates the technical and economic
viability of methane drainage utilizing longhole directional drilling at the Amasra Hard Coal Mine in
Turkey.
Hema Energi (HEMA) is currently developing a 5 million metric tonne (Mt) per year mine in Amasra,
Turkey. The mine is located on a coal license obtained from TTK and will supply a 1,320 megawatt (MW)
mine-mouth power plant currently under development. HEMA has been working on developing the
coalbed methane resources outside of the mining areas and they would now like to initiate
degasification efforts at the mine itself. The coal seams in the Zonguldak coal region where the Amasra
Mine is located are known to be very gassy and over the years there have been several disastrous
explosions resulting in numerous fatalities. HEMA realizes that an aggressive pre-mine drainage
program will substantially reduce the methane content of the coal in advance of mining, thus making
the mining environment safer and more productive.
Extending over an area of 50 square kilometers (km2) the mine is located in north-central Turkey within
the Zonguldak Coal Basin, approximately 250 kilometers (km) to the west of Istanbul on the Black Sea
coast. After obtaining a coal license from TTK, HEMA has the right to mine below -400 meters (m) on 14
km2 of the area with the remaining 35.6 km2 to be mined from the surface. Total coal resources for the
mine are estimated at 573 Mt. To initiate development of these resources, a mining plan covering 13
km2 has been prepared with the mine area divided into three blocks, namely the East Block, West Block,
and Southeast Block.
The Amasra Mine presents an ideal site for a pre-mine drainage CMM program for several reasons.
Firstly, the company is committed to developing this new mine and has already spent nearly $100
million on developing the production shafts. Secondly, being a new mine, it will likely be very gassy and
thus, will benefit greatly from pre-mine drainage. Lastly, the mine is located within the environs of the
town of Amasra which provides a ready market for the produced gas. We believe that a pre-feasibility
study at the Amasra Mine is well justified given the high likelihood of project implementation and the
resulting methane reductions.
The principal objective of this pre-feasibility study is to assess the technical and economic viability of
methane drainage utilizing longhole directional drilling at the Amasra Hard Coal Mine, and using this gas
to produce electricity or compressed natural gas (CNG). The proposed gas drainage approach discussed
in this study will focus on the East Block since it will be the first area to be mined. However, it is
envisioned that the proposed drilling program will also be utilized in the West and Southeast blocks. For
the East Block, the proposed gas drainage approach is to use a combination of in-seam drilling in
advance of mine developments, and gob gas drainage via horizontal gob boreholes. Flanking in-seam
boreholes to shield and drain gas ahead of development galleries are proposed with horizontal gob
boreholes (HGBs) drilled into the gob area above the formation to drain gas as longwall mining
progresses.
The use of longhole directional drilling will allow for longer length and more accurate placement of
boreholes for improved in-seam methane drainage efficiency. In addition, longhole directional drilling
allows for the implementation of innovative gob gas drainage techniques that may be more efficient
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than cross-measure boreholes and at lower cost than superjacent techniques. Other benefits of
longhole directional drilling include the ability to steer boreholes to stay in-seam, flank projected
gateroads, or hit specific targets such as adjacent coal seams or gas bearing strata. This technique
promotes a more focused, simplified gas collection system with improved recovered gas quality because
of the reduced amount of wellheads and pipeline infrastructure. Additionally, the proposed drainage
approach is less labor intensive, can be accomplished away from mining activity with proper planning,
and provides additional geologic information (such as coal thickness, faults, and other anomalies, etc.)
prior to mining.
The primary markets available for a CMM utilization project at the Amasra Mine are power generation
using internal combustion engines and vehicle fuel in the form of CNG. Given the relatively small CMM
production volume, as well as the requirement for gas upgrading, constructing a pipeline to transport
the gas to demand centers would be impractical. Based on the gas supply forecasts generated in this
pre-feasibility study, the mine could be capable of operating as much as 8.8 MW of electricity capacity
or produce over 1.5 million diesel liter equivalents (DLE) per month. Generating electricity on site is
attractive, because the input CMM gas stream can be utilized as is, with minimal processing and
transportation. Additional generating sets can be installed relatively cheaply and infrastructure for the
power plant and distribution system is already planned. While the CNG utilization option requires
significant processing of the CMM gas stream to increase its methane concentration and remove
contaminants, the current high price of transportation fuel in Turkey improves the economics of this
utilization option. However, this option should be investigated more thoroughly in a full-scale feasibility
study, should the project advance to that development stage.
The proposed pre-drainage project - which utilizes long, in-seam boreholes to drain gas ahead of mining
- focuses on mining of the six coal seams (EC100 through EC600) located in the East Production Block.
Based on the mine maps provided by HEMA, a total of 42 individual longwall panels are scheduled to be
mined over a 24-year period. The mining plan is to work from the upper coal seam (EC100) down to the
lower ones (EC200 - EC600). Flanking in-seam boreholes are utilized to drain gas ahead of development
galleries. Long directionally drilled boreholes cover the entire length of each panel from a single setup
location, allowing drainage of multiple mining levels.
Based on the mine development schedule provided by HEMA, boreholes were assumed to be drilled and
put on production three to five years prior to the initiation of mining activities at each panel. CMM gas
production profiles were generated for a total of four project development cases:
• Case 1: 2 wells drilled per panel; 3 years pre-drainage
• Case 2: 2 wells drilled per panel; 5 years pre-drainage
• Case 3: 4 wells drilled per panel; 3 years pre-drainage
• Case 4: 4 wells drilled per panel; 5 years pre-drainage
The methane drainage approach proposed at this mine also includes a large gob degasification program
involving horizontal gob boreholes (HGBs). HGBs will be drilled into the gob area above the formation to
drain gas as longwall mining progresses. HGBs will also be drilled between the EC300 and EC400 seams
due to the separation of the seams. A total of 19 HGBs are assumed to be drilled in the East Production
Block prior to the start of mining. Upon completion, HGBs will be placed on vacuum once mining
progresses. The production duration of each HGB is dependent on the length of time it takes to mine
each longwall panel, and it is assumed that each HGB continues to produce gob gas for an additional
three months after the panel is mined through. Underground, the in-seam gas collection system is
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assumed to be integrated with the gob gas drainage system (i.e., combined pipelines). The development
of the HGB portion of the project is assumed to be the same for all four in-seam gas drainage cases.
Based on the forecasted gas production, as shown in Figure 1, the breakeven cost of producing gas
through in-seam drainage boreholes is estimated to be between $64 and $91/1000 cubic meter (m3)
($2.33 and $3.15 per million British thermal unit {MMBtu}). The results of the economic assessment
indicate the lowest CMM production costs are associated with the 2 wells drilled per panel cases, with 5
years of pre-drainage (Case 2) preferred over 3 years (Case 1).
Summary of Economic Results
CMM Supply
CMM Supply Forecast
0 5 10
Total Wells Put On Production
Wells
Years
Breakeven
per
of Pre-
Gas Price
Case
Panel
Drainage
$/1000m3
1
2
3
71.93
2
2
5
63.57
3
4
3
90.85
4
4
5
84.00
Case Description
1 2 wells per panel; 3 years pre-drainage
2 2 wells per panel; 5 years pre-drainage
3 4 wells per panel; 3 years pre-drainage
4 4 wells per panel; 5 years pre-drainage
Figure 1: Summary of Economic Results for the CMM Project
As shown in Figure 2, the breakeven power sales price, inclusive of the cost of methane drainage, is
estimated to be between $0,049 and $0,056 per kilowatt-hour (kWh). Based on a breakeven CMM price
of $64 per thousand cubic meters (1000m3) ($2.33/MMBtu) (Case 2), the mine could generate power at
a price equivalent to $0.049/kWh. A CMM-to-power utilization project at the mine would be
economically feasible if the mine currently pays a higher price for electricity.
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Summary of Economic Results
Power Supply
Power Supply Forecast
0 5 10
Generating Capacity
Wells
Years
Breakeven
per
of Pre-
Power Price
Case
Panel
Drainage
$/kWh
1
2
3
0.0526
2
2
5
0.0485
3
4
3
0.0561
4
4
5
0.0533
Description
2 wells per panel; 3 years pre-drainage
2 wells per panel; 5 years pre-drainage
4 wells per panel; 3 years pre-drainage
4 wells per panel; 5 years pre-drainage
Figure 2: Summary of Economic Results for Power Project
As shown in Figure 3, the breakeven CNG sales price, inclusive of the cost of methane drainage, is
estimated to be between $0.22 and $0.26/DLE ($0.84 and $0.98 per diesel gallon equivalent {DGE}).
Due to economies of scale associated with CNG station capacity, the optimal case for CNG production is
Case 4, which produces CNG at a price equivalent to $0.22/DLE ($0.84/DGE). A CMM-to-CNG utilization
project at the mine would be economically feasible if the mine currently pays a higher price for
transportation fuel (e.g., CNG or diesel fuel).
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Summary of Economic Results
CNG Supply
CNG Supply Forecast
E f 50
-a
> I 40
tS O
3 "o
30
13 °
5 20
0 5 10
CNG Station Throughput
Wells
Years
Breakeven
per
of Pre-
CNG Price
Case
Panel
Drainage
$/DLE
1
2
3
0.260
2
2
5
0.235
3
4
3
0.236
4
4
5
0.222
Case Description
1 2 wells per panel; 3 years pre-drainage
2 2 wells per panel; 5 years pre-drainage
3 4 wells per panel; 3 years pre-drainage
4 4 wells per panel; 5 years pre-drainage
Figure 3: Summary of Economic Results for CNG Project
The most effective gas drainage program for the mine is likely to be a combination of horizontal gob gas
boreholes combined with in-seam gas drainage boreholes, both drilled from within the mine. Due to the
relatively low permeability of the coals, the drainage efficiency improves as more wells per panel are
drilled, and as drainage time increases. Based on the forecasted gas production, the breakeven cost of
producing CMM through in-seam drainage boreholes combined with HGBs is estimated to be between
$64 and $91/1000 m3 ($2.33 and $3.15/MMBtu). The results of the economic assessment indicate the
lowest CMM production costs are associated with the 2 wells drilled per panel cases, with 5 years of pre-
drainage (Case 2) preferred over 3 years (Case 1).
In terms of utilization, the power and CNG options both appear to be economically feasible. More
rigorous engineering design and costing would be needed before making a final determination of the
best available utilization option for the drained methane. As of the end of 2013 the average rate of
electricity for industrial customers was S0.1038/kWh (inclusive of all taxes and levies). When compared
to the breakeven power sales price calculated in the economic analysis, utilizing drained methane to
produce electricity could generate profits of between $48 and $55 per megawatt-hour (MWh) of
electricity produced. In terms of transportation fuels, the current diesel price in Turkey is $2.07 per liter
(I). With a breakeven CNG sales price estimated to be between $0.22 and $0.26/DLE, utilizing drained
methane to produce CNG could generate profits of between $1.81 and $1.85 per DLE of CNG sold.
Both potential utilization options appear to be economically feasible and removing the cost of mine
degasification from downstream economics, as a sunk cost, would reduce the marginal cost of electricity
and CNG production and improve the economics. Furthermore, depending on the development
approach and utilization option selected for the project, net emission reductions associated with the
destruction of drained methane are estimated to range between 2.2 million and 3.8 million tonnes of
carbon dioxide equivalent (tC02e) over the 30-year project life.
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1 Introduction
Under the auspices of the Global Methane Initiative (GMI), the U.S. Environmental Protection Agency
(USEPA) works with coal mines in the U.S. and internationally to encourage the economic use of coal
mine methane (CMM) gas that is otherwise vented to the atmosphere. Methane is both the primary
constituent of natural gas and a potent greenhouse gas when released to the atmosphere. Reducing
emissions can yield substantial economic and environmental benefits, and the implementation of
available, cost-effective methane emission reduction opportunities in the coal industry can lead to
improved mine safety, greater mine productivity, and increased revenues.
The GMI is an international partnership of 42 member countries and the European Commission that
focuses on cost-effective, near-term methane recovery and use as a clean energy source. USEPA, in
support of the GMI, has sponsored feasibility and pre-feasibility studies in China, India, Kazakhstan,
Mongolia, Poland, Russia and Ukraine. These studies provide the cost-effective first step to project
development and implementation by identifying project opportunities through a high-level review of gas
availability, end-use options, and emission reduction potential. This study extends USEPA pre-feasibility
support to Turkey. As a major coal mining country and one with significant challenges related to
methane emissions into mine workings, success in delivering CMM projects in Turkey will contribute
greatly to reducing regional and global methane emissions.
The principal objective of this pre-feasibility study is to assess the technical and economic viability of
methane drainage utilizing longhole directional drilling at the Amasra Hard Coal Mine. The Amasra Hard
Coal Mine is an excellent candidate for increased methane use and abatement, and was chosen for this
pre-feasibility study on the following basis:
• Hema Energi is currently developing a 5 million ton per year mine in Amasra, Turkey. The mine
is located on a coal license obtained from TTK and will supply a 1,320 MW mine-mouth power
plant currently under development. Based on the mining plan, coal production from the East
Block is expected to commence in 2015.
• The coal seams in the Amasra Mine area are known to be very gassy and over the years there
have been several disastrous explosions resulting in numerous fatalities. HEMA realizes that an
aggressive pre-mine drainage program will substantially reduce the methane content of the coal
in advance of mining, thus making the mining environment safer and more productive.
• Being a new mine, it will likely be very gassy and thus, will benefit greatly from pre-mine
drainage.
• The company is committed to developing this new mine and has already spent nearly $100
million on developing the production shafts.
• The mine is located within the environs of the town of Amasra which provides a ready market
for the produced gas.
We believe that a pre-feasibility study at the Amasra Mine is well justified given the high likelihood of
project implementation and the resulting methane reductions. This pre-feasibility study is intended to
provide an initial assessment of project viability. A final Investment Decision (FID) should only be made
after completion of a full feasibility study based on more refined data and detailed cost estimates,
completion of a detailed site investigation, implementation of well tests, and possibly completion of a
Front End Engineering & Design (FEED).
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2 Background
2.1 The Turkish Coal Industry
Coal exploration and mining in the Zonguldak Basin began in the 18th century and continues to be a
source of energy and coking coal for the region to this day. Hard coal resources in the basin are
estimated at 1,335 million tonnes (Mt), with proven reserves of 534 Mt (EUROCOAL, 2014). Coal
resources associated with the Amasra Hard Coal Mine are estimated to be 573 Mt, which represents
about 43% of Turkey's total hard coal resources, with 265 Mt of economical reserves being reported
(HEMA, 2014). At the end of 2012, Turkey's total proved reserves of coal were 2,343 Mt, with 23%
being hard coal and the remaining 77% being lignite (BP, 2013).
In 2012, Turkey ranked 12th in global coal production with 70 Mt of production (EIA, 2013) with roughly
95% being lignite (EUROCOAL, 2014). Between 1980 and 2012, Turkey's coal production increased by 51
Mt for a compound average growth rate (CAGR) of roughly 4%. Over the same period, coal consumption
has enjoyed a CAGR of 5% increasing by 78 Mt tons to a total of 98 million tons in 2012 (EIA, 2013). As
shown in Figure 4, in order to account for the growing imbalance between supply and demand, Turkey
now imports 29 Mt of coal, representing 29% of the country's total coal consumption (EIA, 2013).
In 2012, coal accounted for 26% of Turkey's total energy consumption by fuel (BP, 2013). Of this, a large
majority is used for power generation. According to EUROCOAL, coal is responsible for producing 26.1%
of Turkey's gross electricity production (2010) while natural gas provides 46.5%, hydropower provides
24.5%, oil provides 1.0%, and wind and other renewables provide the remaining 1.9%. Currently, the
majority of Turkey's coal-fired power plants use lignite, with only one power station (300 MW) fueled
with domestic hard coal from the Zonguldak Basin; the Iskenderun power plant (1,200 MW) uses
imported hard coal (EUROSTAT, 2014). As envisioned, the Amasra Hard Coal Mine will feed the 1,320-
MW mine-to-mouth Amasra Bartin power station, which has been proposed by Hema Elektrik (HEMA,
2014).
Turkey Coal Consumption and Production, 1980-2014
million tonnes
120
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2.2 Coal Mine Methane in Turkey
Limited information is available on CMM emissions from active mines in Turkey, and the Global
Methane initiative International CMM Projects Database currently identifies no active projects in Turkey
(GMI, 2014). Figure 5 shows methane (CH4) emissions from coal mining in Turkey. The majority of coal
produced in Turkey is lignite of which approximately 90% is produced from opencast mines (EUROCOAL,
2014). As a result, CH4 emissions from surface coal mines were roughly 60 billion grams (Gg), or roughly
60,000 tonnes (t), in 2012 while underground mines accounted for 31 Gg of CH4 (31,000 t) (TurkStat,
2014).
100 ¦
80
60
40
20 -
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
Figure 5: Turkey's CH4 Emissions from Coal Mining (TurkStat, 2014)
2.3 Amasra Coal Project
Hema Energi is currently developing a 5 Mt per year mine in Amasra, Turkey. The mine is located on a
coal license obtained from TTK and will supply a 1,320 MW mine-mouth power plant currently under
development (Figure 6). Based on the mining plan, coal production from the East Block is expected to
commence in 2015. The coal seams in the Amasra Mine area are known to be very gassy and over the
years there have been several disastrous explosions resulting in numerous fatalities. HEMA realizes that
an aggressive pre-mine drainage program will substantially reduce the methane content of the coal in
advance of mining, thus making the mining environment safer and more productive.
The Amasra Mine presents an ideal site for a pre-mine drainage CMM program for several reasons.
Firstly, the company is committed to developing this new mine and has already spent nearly $100
million on developing the production shafts. Secondly, being a new mine, it will likely be very gassy and
thus, will benefit greatly from pre-mine drainage. Lastly, the mine is located within the environs of the
town of Amasra which provides a ready market for the produced gas. We believe that a pre-feasibility
study at the Amasra Mine is well justified given the high likelihood of project implementation and the
resulting methane reductions.
¦ Surface
¦ Underground
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Figure 6: Map of Amasra Project Location (HEMA, 2013)
2.4 HEMA Energi
Hema Enerji, a subsidiary of Turkish conglomerate Hattat Holding, is developing the 5 Mt per year
Amasra Hard Coal Mine. In addition to coal mining, the company is also involved in the oil, natural gas,
and power sectors in the West Black Sea Region. Hattat Holding was founded in 1996 and currently
includes 21 companies in its diversified portfolio, which has interests in industry, energy, tourism, real
estate, and construction. Hattat Holding, which currently employs around 4,000 people, has the
operation rights for the Zonguldak Kandilli, Amasra, and Bartin coal sites, and methane research rights in
Zonguldak, Amasra, Bartin, and Kastamonu.
3 Summary of Mine Characteristics
Extending over an area of 50 km2 the mine is located in north-central Turkey within the Zonguldak Coal
Basin, approximately 250 km to the west of Istanbul on the Black Sea coast (Figure 7). After obtaining a
coal license from TTK, HEMA has the right to mine below -400 m on 14 km2 of the area with the
remaining 35.6 km2 to be mined from the surface. Total coal resources for the mine are estimated at
573 Mt. To initiate development of these resources, a mining plan covering 13 km2 has been prepared
with the mine area divided into three blocks, namely the East Block, West Block, and Southeast Block
(Figure 8).
The surface above the mine is characterized as uneven and hilly with steep slopes present towards the
coast. The mine area is crisscrossed by numerous rivers (e.g., Bartin and Karacay rivers) and
intermittent streams with lands dedicated to agriculture and livestock. Several settlements are located
above the mine (e.g., Bostanlar village, Karayusuflar, and Camhk quarters) at elevations ranging between
+250 and +300 m. With coal being produced at elevations between -450 and -500, 700 to 800 m of
overburden separates these settlements from the mined seams.
Page 15
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The Amasra region experiences a typical Black Sea climate with temperatures between seasons, and
between day and night, being fairly consistent. As observed at the Bartin Meteorology Station, the
highest temperatures are in July and the lowest temperatures fall in October with average annual
precipitation of between 1000-1200 millimeters (mm) (Yilmaz, 2010).
BULGAJMAS,
„ Uliltbul-"""
\r* ~ *-
ir-;.
longuldfl. i
jNSCt . •"
f
Rlack Sea
Vjuniuiri
A
ltmi<
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T L K K Pi Y
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v
\ GEORGIA
t$plr
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'ARMENIA-
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7Vv .
1
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S YRI A
iplfg
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Hitiiktiui deposit
Brownooul ikptuit
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Black Sea
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brtgl\ Armutguk
I
i
y
aradort
Am usu
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/* * **~M
0
Zonguldak Coal Field
•l» Mtici
20
-------
Figure 8: Mine Layout Indicating Location of East, West, and Southeast Production Blocks
3.1 Coal Production
TTK has approved the mining plan for the Amasra Hard Coal Mine, as developed by HEMA. The
integrated plan covers all aspects of mine development including the layout of longwall panels,
ventilation system design, electrical distribution system, gas drainage system, water pumping system,
roadways, coal transportation system, and men and material haulage systems. HEMA's design takes
into consideration the proximity of the coal seams to be mined, the likely geotechnical conditions, and
the need to operate effectively and safely.
Page 17
-------
The production layout is based on the utilization of mechanized systems to fully extract the seams
without pillars. Based on geologic conditions, namely the location of faults, HEMA has divided the
license area into three production blocks. The mine is designed to achieve peak coal production of
approximately 5 Mt per year. Figure 9 shows annual coal production for the East, West, and Southeast
blocks as estimated by HEMA (AHPG, 2013).
(N(Nr>lr«l(N(Nr>lr>lr>l(Nr>lr>lrMrMr»l(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
¦ West Block ¦ East Block ¦ Southeast Block ¦ West Block Gateways ¦ East Block Gateways ¦ Southeast Block Gateways
Source: AHPG (2103)
Figure 9: Coal Production Estimate for Amasra Hard Coal Mine (AHPG, 2013)
3.2 Geological Characteristics
3.2.1 Regional Geology and Tectonics
The Amasra region of the Zonguldak Coal Basin overlays a Precambrian basement consisting of granites
and amphibolites (Sinayug & Giimrah, 2009) and is a part of the Western Pontides tectonic province.
Topographically, the area is characterized as mountainous with steep slopes that plunge into the sea.
The Zonguldak Coal Basin is part of a Hercynian continental sliver, which stretches from Istanbul to
Amasra and is commonly referred to as the Istanbul zone. The area was part of a thick Ordovician-
Carboniferous age sedimentary package, which was deposited on the south-facing continental margin of
Laurasia (Tiiysiiz, 1999). In the Cretaceous, the Istanbul zone was rifted away from Laurasia as a result
of back-arc extension created by the northward-subducting Neotethys, and drifted south along two
transform faults shown in Figure 10, the Western Black Sea fault to the west and the West Crimean fault
to the east (Tiiysiiz, 1999). During the Early Eocene the Istanbul zone was incorporated into the Alpine
Orogenic belt of northern Turkey.
Page 18
-------
East European Platform
East European
Platform
) Scythian Platform
Forcdeep Basin,
-x Greater Caucasus
Crimea
North Dobrudja>T
Block 1
Moesian )
Platform f
West
East
Black Sea
Basin
Basin
Thracian
Basin
Island
Istanbul
suture
deflection
Tauride-Anatolide platforms
n^"°*
| | ooanccnj>. | [ WWCirwW. | | Alc0.o,og^. 31WI{OT* £5*'"®
Source: modified from Okay et al., 1994
Figure 10: Tectonic map of the Black Sea Region (Okay & Goriir, 2007)
The structure of the Istanbul zone, shown in Figure 10, is very complex due to extensive faulting and
folding that occurred in the pre-Cretaceous Hercynian and the late-Cretaceous Alpine orogenies
(Karacan & Okandan, 2000). Carboniferous sediments were buried 300 m to 2500 m and subsequently
uplifted and eroded during the Mercynian orogeny in the Late Carboniferous. In the Eocene the
Carboniferous sediments were reburied to greater than 4000 m by a thick series of cretaceous
carbonate sediments and thereafter uplifted and eroded in the Alpine Orogeny (Raven Ridge Resources,
Inc., 1998). Two separate major deformationai events are interpreted from faults that cut through the
Carboniferous strata, but not the cretaceous strata (Hercynian in age, syndepositional with coal) and
faults that cut through both the carboniferous and cretaceous (Alpine in age).
The Zonguldak basin is defined structurally by en echelon anticlines and synclines that trend
approximately east-west. These structures are intersected and in some cases truncated by faults
throughout the basin. There are three main orientations of faults in the Istanbul zone: N-S, E-W, and
NNW-SSE. The Midi fauit trends E-W and is believed to be active since the Carboniferous, and is
penecontemporaneous with the Carboniferous formations (Raven Ridge Resources, Inc., 1998). The
area to the north of the Midi fault was down thrown while the area to the south of the fault was
uplifted, and subsequently eroded. Carboniferous strata are largely absent immediately south of the
fault due to the tectonic history, but it is believed that Carboniferous strata are present farther south of
the fault. The Okusne fauit truncates the midi fault and Kozlu formation to the west and is oriented N-S.
The West Crimean fault is the eastern boundary of the Zonguldak basin (Burger, Bandelow, & Bieg,
2000). The northern boundary of the Zonguldak basin is the subject of some debate as it extends out
beneath the Black Sea.
Page 19
-------
3.2.2 Lithology
The coal bearing formations within the Zonguldak basin include the Alacaagzi, Kozlu, and Karadon,
oldest to youngest respectively (Figure 11). The formations are Westphalian stage Carboniferous clastic
sedimentary packages developed on Visean age carbonates of the Yilani formation (Karayigit, Gayer, &
Demirel, 1997). The coal bearing formations are unconformably overlain by Cretaceous units, which are
generally composed of limestone and dolomitic limestone (Ho§g6rmez, et al., 2002). The coal seams
present in these formations were deposited as part of a progradational delta and flood plain system
(Tiiysiiz, 1999). This structural regime is a complex set of vertical and horizontal dipping coal beds that
create lateral discontinuity throughout the basin.
Tuff
Agojisfam'
¦ Piric Tonstcin
t
Pic Tonstcin
mtii!
Kokaksu „M1),
ZONGULDAK
AMASRA - BART1N
Cretaceous
Tuff
-KjirLSfxilssams _ f
Tavan Tonstcin
•*Ka]in Tonstein
mi Tuff
-300m
-100
ca. 50km
Dolomitic
limestone
Conglo-
merate
Chronostatigraphic marker
|—i
Tuff Tonsteio
Sandstone Silicone Mndilone Limestone Sandy
Limestone
LithoiCratigraphif? Uoundiry Bioilrsligraphie Boundary
marine
Fauna
Figure 11: Correlated stratigraphic column of Carboniferous formations in the Zonguldak and Amasra
regions (Burger, Bandelow, & Bieg, 2000)
Page 20
-------
The Namurian age Alacaagzi formation marks the transition from carbonate platform rocks to
continental-derived clastic rocks (Raven Ridge Resources, Inc., 1998). The Alacaagzi formation is a
succession of grey-greenish mudstones, siltstones, and thin sandstones with thinning coal seams
interbedded in the upper section. The Alacaagzi formation has thin coal seams that are laterally
extensive and are lenticular in shape (Raven Ridge Resources, Inc., 1998).
Coal deposits from the Westphalian are prevalent worldwide. The Kozlu and Karadon formations host
the Westphalian coal deposits, but are separated both geographically and temporally (Raven Ridge
Resources, Inc., 1998). The Kozlu coal seams are Lower Westphalian (A) in age and found throughout
the basin, and the Karadadon coal seams, which are Upper Westphalian (B, C, and D) in age, are found
almost exclusively in the Amasra region.
The Kozlu formation is divided into the Kilic and Dilaver members. Rock analysis reveals that coal seams
within these members have a total organic content (TOC) of 7.5 to 85.2% with organic matter that is
predominantly vitrinite rich and type III kerogen (Ho§gormez, et al., 2002). The lithology of the Kilic
member is a coarse-grained sandstone conglomerate interbedded with coal seams that fine upward into
the Dilaver formation. The Dilaver member is an interbedded claystone, coal, and conglomerate that
coarsens upward into the Karadon formation (Raven Ridge Resources, Inc., 1998).
The Kilic member is a basal Westphalian A age coal bearing sequence approximately 300m thick at
Armutcuk, where it is the major coal bearing interval and increases in thickness to the east. The Kilic
lateral continuity is limited in the Zonguldak region due to non-deposition or erosion. The Dilaver
member is the upper member of the Kozlu Formation and is also a Westphalian A coal bearing sequence
and is the main coal bearing interval at Zonguldak. The Karadon formation is the uppermost
Carboniferous formation and lies directly beneath the Zonguldak formation, a massive cretaceous
limestone unit, and is time transgressive and usually consists of coarse grained sediments.
The Karadon formation, which is pervasive throughout the Amasra region, is dominated by sandstones
and conglomerates with coals and subordinate siltstones and claystones (Karayigit, Gayer, & Demirel,
1997) and ranges from 260 m to 700 m thick. A fireclay is present at the base of the Karadon formation,
but is not laterally continuous throughout the basin. This fireclay is thought to provide a seal over the
Kozlu formation, and may play an important role in containing methane gas accumulations.
The spatial and temporal relationship between these formations is important in understanding the
depositional environment. The ages and locations of the coal bearing formations described above
illustrate that coal deposits are older in the west and become younger to the east. The Westphalian B,
C, and D Karadon formation is the coal bearing interval at Amasra (Raven Ridge Resources, Inc., 1998).
The coal bearing formations imply that the progradational delta of the Wesphalian system was building
in a west to east direction.
3.3 Mining and Geologic Conditions of Operations
Mine reserves are comprised of six seams in the East Production Block, seven seams in the West
Production Block, and two seams in the Southeast Production Block. Coal seams are generally 1-3 m in
thickness with interburden thickness varying from 1-40 m between seams. With overburden depths
ranging from 700 m to 800 m the mine will utilize the multi-seam longwall mining method to extract
coal. A total of 103 longwall panels have been identified for development, with 42 in the East
Production Block, 38 in the West Production Block, and 23 in the Southeast Production Block (Table 1).
Page 21
-------
EAST PRODUCTION BLOCK
WEST PRODUCTION BLOCK
SOUTHEAST PRODUCTION BLOCK
Coal
Panels
Coal Thickness (m)
Panels
Coal Thickness (m)
Panels
Coal Thickness (m)
Seam
Mined
Min
Max
Avg
Mined
Min
Max
Avg
Mined
Min
Max
Avg
100
2
1.25
1.62
1.44
7
0.88
2.06
1.51
200
2
1.61
1.65
1.63
7
1.50
2.31
1.76
300
9
1.58
2.74
2.10
7
1.29
1.65
1.46
400
10
1.80
3.29
2.50
7
0.94
2.32
1.37
12
1.10
3.21
2.17
500
10
1.63
3.72
2.52
5
0.94
1.50
1.22
11
1.00
1.65
1.28
600
9
0.86
1.17
1.01
1
0.80
0.80
0.80
700
4
1.06
1.85
1.36
Table 1: Coal Thickness Range by Seam for the East, West, and Southeast Production Blocks
The rank of the coals is High Vol. Bituminous A-B and the gas content of the coal seams is between 6 and
13 m3/ton. The coal seams overlying the mining area are greater than 250 m above the uppermost
EC100 seam, and additional investigation is needed to determine any gas contribution of the immediate
adjacent strata and any residual coal from the working seam.
Due to the low permeability of the coal seams, estimated to be approximately 1 millidarcy (mD) or less,
longer drainage times will be required to achieve a reduction of methane levels in advance of mining.
Longhole in-seam directional drilling will have great application at this mine property due to the use of
multi-seam longwall mining. However, the final approach for in-seam methane drainage will require
further investigation and discussion with mine management.
The mining plan proposed by HEMA utilizes a fully mechanized production system with shearer
loaders/plow and compatible powered support. Drum shearers with a 0.80 m cutting depth will
advance at a rate of 7.29 to 12.34 meters per day as coal is produced from faces ranging between 207
and 240 m in length. Mining will be conducted in four shifts, three of which will be for production and
one for maintenance. With an estimated coal thickness of 2 m, production from a shearer loader is
expected to produce 6000 ton run-of-mine (ROM) coal per day, while a plow is projected to produce
3500 ton ROM coal per day (AHPG, 2013).
The design of the underground workings and the layout of the panels are heavily influenced by the
presence of faults. For example, Figure 12 is a diagram of the East Production Block showing the
location of the proposed longwall panels. The East Block area covers 4.2 km2 and is bounded by the
Central Fault at the west, Tuna Fault at the North, an anomaly at the east, and the Fault No.2 at the
south. The East Block will be the first area mined and, as such, will be the focus of the pre-feasibility
study. The inclinations of the seams of the East Block vary between 6° and 12°, and the production
panels are named EC100-101, EC100-102 and so on from north to south. Longwall faces will be
operated as single cut, retreat, and back-caving. The tailgate will also be allowed to cave, but the
maingate will be supported with 4 to 8 m wide pack walls in order to be maintained for the next panel.
The maingate of a former panel will be used as the tailgate of the latter panel. The selection of the
back-caving U-type longwall production method is due to the high spontaneous combustion risk
associated with Westphalia-C coal in the production Block. The subsidence associated with caving has
been calculated to be 54 to 64 centimeters (cm) after 8 to 10 years. "Filling" will be conducted in order
to minimize the subsidence; however, expropriation of settlements located above the mining area is
planned, if necessary (AHPG, 2013).
Page 22
-------
Figure 12; Location of Longwal! Panels of the East Production Block
3.4 Coal Seam Characteristics
A total of 222 boreholes have been drilled by HEMA throughout the license area, with additional
boreholes planned to be drilled as part of the drilling program. HEMA has 6 drilling rigs working on the
Arnasra Project, and has experienced core recoveries in the coal bearing strata averaging 99.55%. From
the borehole data, cross-sections have been prepared and a tectonic map of the field has been
developed. Coal seam correlations indicate a total of 6 coal seams in the East Block, which are WC aged
and occur in the Karadon formation, numbered EC-100, 200, 300, 400, 500 and 600. The reserves of the
4.2 km2 East Block are calculated to be approximately 45.0 Mt. In the Southeast Block, 2 coal seams,
which are WG aged and occur in the Karadon formation, are numbered SEC-400 and 500. The reserves
of the 3.7 km2 Southeast Block are calculated to be approximately 21.0 Mt. Finally, in the West Block a
total of 7 coal seams, which are WA aged and occur in the Kozlu formation, are numbered WA-100, 200,
300, 400, 500, 600, and 700. The reserves of the 4.1 km2 West Block are calculating to be approximately
37.0 Mt (AHPG, 2013). The following sections discuss the characteristics of the coal seams in more
detail.
Page 23
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3.4.1 Density
Petrophysical analyses were conducted on 5 HEMA density logs and a pay flag curve was constructed
using a density cut off of 2.0 grams per cubic centimeter (gm/cc). Minimum and average densities were
computed from the coal seams identified by the play flag curve. Table 2 shows the minimum and
average densities from the well log analysis exercise.
CALCULATED DENSITY
WELL
Mean
Min
1 Mean
Min 1
(tons/a
cre*ft)
gm/cc
HEMA 23
2,315
1,964
1.94
1.86
HEMA 24
2,239
1,883
1.64
1.37
HEMA 25
2,415
1,938
1.62
1.36
HEMA 26
2,256
1,869
1.74
1.40
HEMA 27
2,377
1,883
1.63
1.35
Wtd Avg.
2,322
1,908
1.68
1.38
Table 2: Minimum and average density of the HEMA wells in Amasra
3.4.2 Proximate Analysis
The parameter most commonly used to describe coal rank is vitrinite reflectance, which is the
percentage of light reflectance, measured microscopically in immersion oil, from the polished surface of
a vitrinite maceral when illuminated with plane-polarized white light. In coal, vitrinite reflectance values
vary systematically with carbon content and are widely used as a thermal maturity, or rank, indicator
(McCune, 2002). Figure 13 provides the various parameters that are used to characterize coal by rank.
Page 24
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Figure 13: The relationship between coal type and the parameters of Heat Value, Vitrinite reflectance,
Vitrinite Carbon, Volatile matter and Moisture content. (McCune, 2002)
Petrographic analysis was performed on five samples taken from the Zonguldak and Armutcuk regions.
The thermal maturity of the samples ranged from 0.92 to 1.29% R0 (Table 3). The rank of coals found in
the Zonguldak and Armutcuk regions were high volatile A to medium volatile bituminous coal (Raven
Ridge Resources, Inc., 1998). Samples taken from the Amasra region, shown in Table 4 have a thermal
maturity of 0.58 to 1.04 % Rmax (Karayigit, Gayer, & Demirel, 1997). These values were determined from
samples taken from 9 well cores in the Westphalian D and A and the Namurian formation in the Amasra
Coal fields (Wells K-3, K-4, K-8, K-9, K-ll, K-12, K-16, K-7, k-24). Westphalian C and D coals have a
thermal maturity of 0.58 to 0.83 %Rmax and a mean value of 0.74 %Rma!<. Westphalian A-B coal has a
thermal maturity of 0.69-1.04% R^x and a mean value of 0.85% Rma>0. Namurian coal has a thermal
maturity of 0.70 to 0.73% Rmax and a mean value of 0.71% Rmax (Karayigit, Gayer, & Demirel, 1997). All of
the coal samples taken from Amasra fall within the three high volatile bituminous coal subcategories of
the American Society for Testing Materials (ASTM) standards, ranging from high volatile C bituminous
coal to high volatile A bituminous coal (Trinkle and Hower, 1984).
Page 25
-------
Zonguldak/Armutcuk Reflectance
(Raven Ridge 1998)
Mine Area
Depth (m)
Sample Number
% Ro
Karadon
360
7935
1.29
Karadon
560
7934
1.12
Kozlu
560
7942
1.16
Armutcuk
Not Provided
7941
0.92
Table 3: Vitrinite reflectance values of Zonguldak and Armutcuk
Amasra Reflectance
(Karayigit et al. 1998)
Formation
Vitrinite Max
Vitrinite Avg
Vitrinite Min
{% Rmax)
{% Rmax)
{% Rmax)
Westphalian D-C
0.83
0.74
0.58
Westphalian A-B
1.04
0.85
0.69
Namurian
0.73
0.71
0.7
Table 4: Virtrinite reflectance values of the Amasra region
Additionally, coal samples taken during gallery developments and from boreholes were collected by
HEMA and sent to accredited laboratories for analysis where moisture, ash, volatile matter, fixed
carbon, total sulphur content, FSI, and calorific value measured. Analysis results for the East, Southeast,
and West blocks are summarized in Table 5, Table 6, and Table 7, respectively (AHPG, 2013). The results
from the proximate analysis indicate that the Zonguldak Coal basin has dry coals with moisture content
less than 5%. The amount of ash in the study group suggests that the ash content increases towards the
southwest in the Zonguldak region while volatile matter decreases.
Page 26
-------
Test
Type
Moisture
(%>
Asli
(%)
Volatile
Matter
<%)
Fixed
Carbon
(%)
Total
Sulphur
<%>
FSI
Upper CV
(kcal/kg)
Lower C'V
(kcalkg)
EC100
Original
Basis
2.58
30.-10
27.74
39,29
0.68
1
5102
4906
Dry
Basis
-
31.25
28.47
40.28
0.70
5236
5050
EC'200
Original
Basis
2.39
31.81
27.19
38.61
0.98
I
4970
4778
Dry
Basis
-
32,64
27,84
39.52
1.00
5087
4905
EC'300
Original
Basis
2.73
26.88
28.68
41.21
0.60
1
5433
5219
Dry
Basis
-
27.76
29.44
42.27
0.61
5574
5372
EC'400
Original
Basis
25.47
29,80
42.51
0.86
1
5569
5343
Dry
Basis
-
26.09
30.46
43.45
0.88
5684
5476
EC'5 00
Original
Basis
2.15
22.41
31.50
43.94
0.78
1
5857
5317
Dry
Basis
-
22.96
32,17
44.87
0.80
5979
5762
EC600
Original
Basis
1.98
30.99
29.18
37.55
0.52
1
5152
4957
Dry
Basis
-
31.67
29,78
38.23
0.53
5252
5064
Ave.
Original
Basis
2.27
26.44
29.79
41.25
0.69
1
5503
5209
Dry
Basis
-
27.12
30.46
42.21
0.71
5622
5418
Table 5: Coal Analysis Results for East Block Coals (AHPG, 2013)
Test
Type
Moisture
<%)
Ash
(•/.)
Volatile
Matter
(%)
Fixed
Carbon
(%)
Total
Sulphur
{"/«>
FSI
Upper
CV
(kcal kg)
Lower
CV
(kcal/kg)
SEC'400
Original
Basis
2.06
22 21
32.11
43.63
0.83
5932
5714
Dry-
Basis
-
22.71
32,77
44.52
0.85
6053
5845
SEC'500
Original
Basis
2.21
25.93
29.75
42.11
0.93
5555
5344
Dry
Basis
-
26.47
30.44
43.08
0.95
56S5
5482
Ave.
Original
Basis
2.13
24.07
30.93
42.87
0.88
*>
5743
5529
Dry
Basis
-
24.59
31.61
43.80
0.90
5869
5664
Table 6: Coal Analysis Results for Southeast Block Coals (AHPG, 2013)
Page 27
-------
Test
Type
Moisture
<%)
Ash
(%>
Volatile
Matter
(%)
Fixed
Carbon
<%)
Total
Sulphur
(%)
FSI
Upper
CV
{kral'kg)
Lower
CV
(kcal/kg)
WA100
Original
Basis
1.50
15.89
33.50
49.10
1.09
3
6809
6568
Diy
Basis
•
16.13
34.01
49.85
1.11
6912
6677
WA200
Original
Basis
1.25
14.S6
33.07
49.84
0.63
3
6850
6604
Dry
Basis
-
15.14
33.71
50.82
0.64
6983
6744
WA300
Original
Basis
2.20
16.00
30.28
51,52
0.55
4
6714
6471
Dry
Basis
-
16.43
30.94
52.62
0.57
6859
6593
VVA400
Original
Basis
2.43
8.20
32.21
57.16
0.46
4
7502
7242
Dry-
Basis
•
8.15
33.03
58.58
0.47
7690
7438
WA500
Original
Basis
1.84
9.68
32,55
55,93
0.49
5
7492
7161
Dry
Basis
-
9.85
33.17
56.98
0.50
7556
7307
WAfiOO
Original
Basis
1.53
20.79
29.78
47,90
0.74
5
6498
6271
Dry
Basis
-
21.07
30.26
48.68
0.75
6553
6381
WA700
Original
Basis
1.42
38,34
23.51
36,73
0.55
4
4731
4562
Dry
Basis
-
38.88
23.85
37.26
0.56
4800
4637
Ave.
Original
Basis
1.74
17.68
30.70
49.74
0.64
4
6657
6411
Dn
Basis
-
17.95
31.28
50.68
0.66
6765
6540
Table 7; Coal Analysis Results for West Block Coals (AHPG, 2013)
4 Gas Resources
4.1 Overview of Gas Resources
The coals of the Zonguldak Basin are known to be gassy. According to a geological assessment
commissioned by TTK to evaluate the CBM potential of the coals in the production area, the in-situ
methane content ranges from 6 to 13 rrf /t. As shown in Table 8, the specific emissions of Karadon and
Kozlu District colliery drifts measured between 10.1 and 11.5 m3/t mined in 1997, and together both
collieries liberated almost 22 million cubic meters (Mm ) of methane. When factoring in the gas content
of adjacent seams, total methane emissions of 16 m /t are estimated (AHPG, 2013).
Mining District
Annualized
Methane
Liberated (m3)
Annualized Coal
Production (tonnes)
Specific Emissions
(m'Vton mined)
Karadon District
7.746.6S3
675.074
11.5
Kozlu District
14.130.940
1.400.482
10.1
Average
21.877.62.3
2.075.556
10.5
Table 8: Liberated Methane Measurement at TTK Colliery Drifts in 1997 (AHPG, 2013)
The mine ventilation plan proposed by HEMA includes the use of shaft number 1 for intake air and shaft
Page 28
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number 3 for return air. Two exhaust fans will be installed at shaft number 3 (1 main and 1 backup fan),
and are designed to work with 4800-9000 Pascal depression and up to 430 cubic meters per second
(m3/sec) flow rate. When designing the ventilation plan for the mining area HEMA took into
consideration all Turkish Mining Regulations, the anticipated methane emissions from each of the seams
in the respective areas, the assumed level of methane drainage capture, maximum acceptable velocities
and international good practice. The key design parameters of the ventilation plan include:
• Maximum 0.87% methane in all return roadways;
• Maximum 1.25% methane at production face;
• Two simultaneously working longwalls (12,000 t/d for East and 7,000 t/d for Southeast);
• 5 m3/t methane emission during mining after drainage; and
• Ventilation velocity within the regulated limits (AHPG, 2013).
4.2 Proposed Gas Drainage Approach
The proposed gas drainage approach discussed in this study will focus on the East Block since it will be
the first area to be mined. However, it is envisioned that the proposed drilling program will also be
utilized in the West and Southeast blocks. For the East Block, the proposed gas drainage approach is to
use a combination of in-seam drilling in advance of mine developments and gob gas drainage via
horizontal gob boreholes. Flanking in-seam boreholes to shield and drain gas ahead of development
galleries are proposed with horizontal gob boreholes drilled into the gob area above the formation to
drain gas as longwall mining progresses.
The use of longhole directional drilling will allow for longer length and more accurate placement of
boreholes for improved in-seam methane drainage efficiency. In addition, longhole directional drilling
allows for the implementation of innovative gob gas drainage techniques that may be more efficient
than cross-measure boreholes and at lower cost than superjacent techniques. Other benefits of
longhole directional drilling include the ability to steer boreholes to stay in-seam, flank projected
gateroads, or hit specific targets such as adjacent coal seams or gas bearing strata. This technique
promotes a more focused, simplified gas collection system with improved recovered gas quality because
of the reduced amount of wellheads and pipeline infrastructure. Additionally, the proposed drainage
approach is less labor intensive, can be accomplished away from mining activity with proper planning,
and provides additional geologic information (such as coal thickness, faults, and other anomalies, etc.)
prior to mining.
4.2.1 In-Seam Gas Drainage Boreholes
In-seam gas drainage boreholes will be drilled in parallel to advance and flank the gateroad
developments. Figure 14 illustrates the proposed placement of the gas drainage boreholes. The long
directionally drilled boreholes will cover the entire length of each panel from a single setup location to
shield and drain gas ahead of development galleries. As shown in Figure 15, the boreholes will be drilled
down-dip and, depending on drilling conditions and hole deviations, can be drilled up to 1500+ meters.
The ability to drain multiple mining levels for each panel from a single setup location will be
advantageous at this mine property due to the use of multi-seam longwall mining. Coordination of
drilling operations with mine plans is vital to the success of an in-seam drainage program.
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Figure 15: Cross Section View of In-Seam Gas Drainage Borehole Placement
4.2.2 Horizontal Gob Boreholes
Horizontal gob boreholes (HGBs) will be drilled into the gob area above the formation to drain gas as
longwall mining progresses. Gob boreholes are generally placed at a distance of greater than five times
the mining height above the rubble zone in order to remain intact after undermining of the longwall
panel; typical placement is 20 to 30 m above the mining level. As shown in Figure 16, the HGBs will be
drilled parallel to the mining direction on the up-dip and tailgate (ventilation return) side of the longwall
panel. Due to separation between the EC300 and EC400 seams (up to 44 meters), it is recommended
Page 30
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that a horizontal gob borehole be placed between these seams. It would not be expected for the gob to
extend through the EC300 and EC400 interburden after longwall mining. Upon completion, gob
boreholes are typically placed on vacuum (-10 to -20 kilopascal {kPa}) once mining progresses.
Figure 16: Cross Section View of Horizontal Gob Borehole Placement
4.3 Estimating Production from In-Seam Gas Drainage Boreholes
The objectives of this pre-feasibility study are to perform an initial assessment of the technical and
economic viability of methane drainage utilizing longhole directional drilling in the mine area, and to
identify end-use options. The gas production profiles generated for both the pre-drainage in-seam gas
drainage boreholes and the horizontal gob boreholes will form the basis of the economic analyses
performed in Section 7 of this report. Additionally, estimating the gas production volume is critical for
planning purposed and the design of equipment and facilities.
A reservoir model designed to simulate five-year gas production volumes from pre-drainage boreholes
located in the study area was constructed. The following sections of the report discuss the construction
of the in-seam gas drainage borehole model, the input parameters used to populate the reservoir
simulation model, and the simulation results.
4.3.1 COMET3® Model
The reservoir model was constructed using ARI's proprietary reservoir simulator, COMET3®. A total of
two single-layer models were constructed in order to calculate gas production for a longwall panel
located within the project area. The models were designed to simulate production from long
directionally drilled boreholes drilled from within the mine and spaced according to two well spacing
cases: 250 m and 83 m between wells (2 and 4 wells per panel, respectively). The models were each
run for five years in order to simulate gas production rates and cumulative production volumes from a
typical longwall panel within the project area.
A typical longwall panel at the mine is estimated to have a face width of 250 m and a panel length of 700
m covering an aerial extent of 17.5 hectares (ha) (43 acres {ac}). Based on these dimensions, model
grids were created in COMET3® to accommodate each of the well spacing scenarios. The model grid for
the 250 m well spacing case (2 wells per panel) consisted of 65 grid-blocks in the x-direction, 42 grid-
blocks in the y-direction, and one grid-block in the z-direction. The model grid for the 83 m well spacing
case (4 wells per panel) consisted of 65 grid-blocks in the x-direction, 44 grid-blocks in the y-direction,
and one grid-block in the z-direction. The total area modeled is roughly 51 ha (125 ac) and 34 ha (83 ac)
for the 2- and 4-wells per panel cases, respectively. The model areas include the 17.5 ha (43 ac)
Page 31
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longwall panel area as well as a boundary area to account for migration of gas from coal seams of
adjacent panels. The model layout for each of the well spacing cases is shown in Figure 17.
2 Wells Per Panel Case
Model length = 3,317 (1,011 m)
Model width = 1,641 ft (500 m)
• • W W » W
1 » II » 8 X
i! j : i : ! : : : : rj • I j j
to: : : ::::::::
i»:; :
HttI 1111 ft 111 tit'
Total 11lodel ares 12j ac (51 lid)
Niimhpr of wells: ?
Lateral length: 2,297 ft (700 m)
Spacing between wells: 820 ft (250 m)
4 Wells Per Panel Case
- Model length - 3,317 (1,011 m)
» Model width = 1.094 ft (333 m)
* Total model area = 83 ac (34 ha)
fcfcfc} I { [ M | j j f 1 i j { { j 1} { r 1 { 1 { | FF
nod | 11 1 I 11 1 I j} f I t t i t I'M 11 1 M 1
• n i n n ? r.i
• io ii j# a x
Wells
LW Panel
Number of wells: 4
Lateral length: 2,297 ft (700 m)
Spacing between wells: 273 ft (83 m)
>S<9
-------
Reservoir Parameter I
Notes I
Avg. Coal Depth, m
500
Based on mine data
Avg. Coal Thickness, m
2
Based on mine data
Coal density, g/cc
1.68
Log analysis
Pressure Gradient, kPa/m3
9.80
Assumption
Initial Reservoir Pressure, kPa
4896
Calculated from Avg. depth and pressure gradient
Initial Water Saturation, %
100
Assumption
Langmuir Volume, m3/tonne
13.81
Isotherm analysis
Langmuir Pressure, kPa
1966
Isotherm analysis
In Situ Gas Content, m3/tonne
9.85
Calculated from reservoir pressure and isotherm
Desorption Pressure, kPa
4896
Assumes fully saturated conditions; Desorption
pressure equal to initial reservoir pressure
Sorption Times, days
17
Analog (Sinayuc and Gumrah, 2009)
Fracture Spacing, cm
2.54
Analog
Absolute Cleat Permeability, md
0.5
Analog
Cleat Porosity, %
2
Analog
Relative Permeability
Curve
Analog; See following slide
Pore Volume Compressibility, kPa 1
27.6 x 10-4
Assumption
Matrix Shrinkage Compressibility, kPa 1
6.9 x 10-6
Assumption
Gas Gravity
0.6
Assumption
Water Viscosity, (mPa-s)
0.44
Assumption
Water Formation Volume Factor, reservoir
1.00
Calculation
barrel per stock tank barrel (RB/STB)
Completion and Stimulation
Assumes skin factor of 2 (formation damage)
Pressure Control
In-mine pipeline with surface vacuum station providing vacuum
pressure of -13.5 kPa
Well Spacing
Two cases: 250 m (2 wells per panel) and 83 m (4 wells per panel)
between wells
Table 9: C0MET3® Input Parameters Used to Simulate In-Seam Gas Drainage Borehole Production
4.3.2.1 Permeability
Coal bed permeability, as it applies to production of methane from coal seams, is a result of the natural
cleat (fracture) system of the coal and consists of face cleats and butt cleats. This natural cleat system is
sometimes enhanced by natural fracturing caused by tectonic forces in the basin. The permeability
resulting from the fracture systems in the coal is called "absolute permeability" and it is a critical input
parameter for reservoir simulation studies. Absolute permeability data for the coal seams in the study
area were not provided. However, permeability values in the Zonguldak coal basin can range between
0.1 md and 100 md (Sinayug & Giimrah, 2009). For the current study, permeability values were
assumed to be 0.5 mD.
4.3.2.2 Langmuir Volume and Pressure
The Langmuir volume and pressure values were taken from the methane adsorption isotherm work
performed on HEMA CBM-1 coal samples. The average of the raw isotherms was thought to be most
representative of the conditions in the Amasra area. The corresponding Langmuir volume used in the
reservoir simulation models for the Amasra area is 13.81 m3/t (442.5 standard cubic feet per ton
{scf/ton}) and the Langmuir pressure is 1,966 kPa (285.2 pounds per square inch absolute {psia}). Figure
18 depicts the methane isotherms utilized in the reservoir simulations.
Page 33
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Pressure (kPa)
Figure 18: Methane Isotherm Used in Simulation
4.3.2.3 Gas Content
Gas desorption analyses performed during the coring program indicate a high level of dispersion. Due to
the limited amount of data available, coal seams were assumed to be fully saturated with respect to gas
despite the fact that some of the desorption data falls below the adsorption isotherm. As a result, an
initial gas content value of 9.85 m3/t (316 scf/ton) was used in the simulation study as calculated by the
isotherm (Figure 18).
4.3.2.4 Relative Perm eability
The flow of gas and water through coal seams is governed by permeability, of which there are two
types, depending on the amount of water in the cleats and pore spaces. When only one fluid exists in
the pore space, the measured permeability is considered absolute permeability. Absolute permeability
represents the maximum permeability of the cleat and natural fracture space in coals and in the pore
space in coals. However, once production begins and the pressure in the cleat system starts to decline
due to the removal of water, gas is released from the coals into the cleat and natural fracture network.
The introduction of gas into the cleat system results in multiple fluid phases (gas and water) in the pore
space, and the transport of both fluids must be considered in order to accurately model production. To
accomplish this, relative permeability functions are used in conjunction with specific permeability to
determine the effective permeability of each fluid phase.
Relative permeability data for the coal of the project area was not available. Therefore, the relative
permeability curve used in the simulation study was obtained from an analogous coal basin. Figure 19 is
a graph of the relative permeability curves used in the reservoir simulation of the study area.
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Figure 19: Relative Permeability Curve Used in Simulation
4.3.2.5 Coal Seam Depth and Thickness
Based on mine data, the coal seams in the East Block range in depth from 400 m to 530 m below sea-
level with coal seams ranging between 1 and 3 m in thickness. For modeling purposes, the depth to the
top of the coal reservoir was assumed to be 500 m, and the coal thickness is taken to be 2 m.
4.3.2.6 Reservoir and Desorption Pressure
Initial reservoir pressure was computed using a hydrostatic pressure gradient of 9.8 kPa/rrT (0.433
psi/ft) and the midpoint depth of the coal seam. Because the coal seams are assumed to be saturated
with respect to gas, desorption pressure is set equal to the initial reservoir pressure for the seam. The
resulting initial and desorption pressures used in the model is 4,896 kPa (710 psia).
4.3.2.7 Porosity and Initial Water Saturation
Porosity is a measure of the void spaces in a material. In this case, the material is coal, and the void
space is the cleat fracture system. Since porosity values for the coal seams in the mine area were not
available, a value of 2% was used in the simulations. Typical porosity values for coal range between 1%
and 3%. The cleat and natural fracture system in the reservoir was assumed to be 100% water
saturated. This assumption is consistent with drilling information and well test data.
4.3.2.8 Sorption Time
Sorption time is defined as the length of time required for 63% of the gas in a sample to be desorbed. In
this study a 17 day sorption time was used, which is consistent with the coals in the region. Production
rate and cumulative production forecasts are typically relatively insensitive to sorption time.
4.3.2.9 Fracture Spacing
A fracture spacing of 2.54 centimeters (1 inch) was assumed in the simulations. In COMET3®, fracture
spacing is only used for calculation of diffusion coefficients for different shapes of matrix elements and it
does not materially affect the simulation results.
4.3.2.10 Well Spacing
As discussed previously, two well spacing cases were modeled consisting of 250 m between wells and 83
m between wells, or 2 and 4 wells per panel, respectively.
4.3.2.11 Completion
Long in-seam boreholes with lateral lengths of 700 m are proposed to be drilled and completed in the
Page 35
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longwall panel. For modeling purposes, a skin value of 2 is assumed (formation damage).
4.3.2.12 Pressure Control
For the current study, an in-mine pipeline with a surface vacuum station providing a vacuum pressure of
-13.5 kPa (2 psi) was assumed. In coal mine methane operations, low well pressure is required to
achieve maximum gas content reduction. The wells were allowed to produce for a total of five years.
4.3.3 In-Seam Gas Drainage Borehole Model Results
As noted previously, two reservoir models were created to simulate gas production for a representative
longwall panel located at the Amasra Hard Coal Mine. Each of the models was run for a period of five
years and the resulting gas production profiles, as well as the methane content of the coal seams, are
highlighted in the following sections.
4.3.3.1 Simulated Gas Production Profiles
Simulated gas production rate and cumulative gas production for an average well within the longwall
panel are shown in Figure 20 and Figure 21, respectively.
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Per-Well Gas Production Rate
Month
Figure 20: Simulated Per-Well Gas Production Rate
Per-Well Cumulative Gas Production
Month
Figure 21: Simulated Per-Well Cumulative Gas Production
4.3.3.2 Simulated Reduction of Coal Seam Gas Content
One of the benefits of pre-drainage is the reduction of methane content in the coal seams prior to
mining. Figure 22 and Figure 23 illustrate the reduction in in-situ gas content in the coal seam over time
utilizing the 2 wells per panel and 4 wells per panel spacing cases, respectively. Figure 23 illustrates the
improvement in drainage efficiency associated with the reduction in well spacing. All gas contents
represent averages from within the longwall panel area only.
Page 37
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Pressure (kPa)
Figure 22: Simulated Reduction in Gas Content Over Time - 2 Wells Per Panel Case
Pressure (kPa)
Figure 23: Simulated Reduction in Gas Content Over Time - 4 Wells Per Panel Case
Page 38
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Reduction in In-Situ Gas Content Over Time
2 Wells per Panel
4 Wells per Panel
Production
Duration
Reduction in
Gas Content*
(% Reduction)
After 6 Months
0.97
10%
After 1 Year
1.45
15%
After 2 Years
2.20
21%
After 3 Years
2.26
27%
After 5 Years
2.32
35%
* Calculated from within longwall panel area only
Production
Duration
BUM
Reduction in
Gas Content*
(% Reduction)
After 6 Months
2.12
29%
After 1 Year
3.21
42%
After 2 Years
4.36
56%
After 3 Years
4.42
63%
After 5 Years
4.49
70%
* Calculated from within longwall panel area only
Matrix Methane (m3/tonne)
Figure 24: Illustration of Reduction in Gas Content Over Time
Page 39
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4.4 Estimating Production from Horizontal Gob Boreholes
Estimated gas production from HGBs was based on the gob gas flow projections shown in Figure 25,
which represent gob gas flow rates (70% CH4) for 1000 m gob borehole configurations. HGB
performance is a function of borehole diameter, length, lining, wellhead vacuum, vertical placement
above mining seam, and lateral placement along tension zones. As illustrated in Figure 25, gob gas flow
rates typically increase as both the borehole diameter and wellhead vacuum pressure increase. Based
on a panel length of 1000 m and an average face advance rate of 6.6 m/d, a longwall panel will take 5
months to mine through. Assuming a HGB with a 121 mm borehole diameter placed on 13.5 kPa of
vacuum pressure, gob gas flow rates are estimated to be 8.4 cubic meters per minute (m3/min) (5.9
m3/min of pure CH4). If the HGB continues to produce for 3 months following the completion of the
longwall panel, total gob gas production is estimated at 2.9 Mm3 (2.1 Mm3 of pure CH4).
3(H)
Gob Gas Flow Rati: for 1000 m Horizontal Gob Borehole
Configurations (70% C'H4 )
¦ 1000 m. 96 m
n. Standard
~ 1000 m, 121 i
ram, Enhanced
~ 1000 m. 146 i
nm. Enhanced
Wellhead Vacuum Pressure (kl'a)
Figure 25: Gob Gas Flow Rate for 1000 m Gob Borehole Configurations (70% CH4)
Page 40
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5 Market Information
The primary markets available for a CMM utilization project for the Amasra Hard Coal Mine are power
generation using internal combustion engines and vehicle fuel in the form of compressed natural gas
(CNG). At this time, sales to natural gas pipelines are neither technically nor economically viable.
With respect to electricity markets, the mine's power demand is estimated to be at least 62 MW,
providing ample opportunity to offset power purchases with on-site generated electricity from CMM.
Although the CMM-based power could be used on-site, HEMA would likely remain connected to the grid
to ensure an uninterrupted supply of electricity. As of the end of 2013 the average rate of electricity for
industrial customers was EUR 0.0763/kWh (inclusive of all taxes and levies), equivalent to USD
0.1038/kWh at current exchange rates (Figure 26).
Bi-Annual Electricity Prices for Industrial Consumers in Turkey, 2008-2013
USD/kWh
0.14
0.12
0.10
0.08
0.06
0.04
0.02
0.00 r
OOCnCT^OOrHrHCvJJNfOrO
OOOtHtHtHtHtHtHtHtH
ooooooooooo
(N(N(N(N(N(N(N 150,000 MWh; a II taxes & levies included)
Range: 0.098 to 0.124 USD/kWh
Average: 0.108 USD/kWh
Figure 26: Bi-Annual Electricity Prices for Industrial Consumers in Turkey, 2008-2013
With respect to the market for transportation fuels, Turkey is known to have some of the highest
gasoline prices of any country in the world. In recent years the Turkish government has ratcheted up
the fuel tax in order to increase its revenue base; Turkey's gasoline tax is also considered one of the
highest in the world (Randall, 2014). As shown in Table 10, the current gasoline price in Turkey is $2.38/1
and the current diesel price is $2.07/1, which is equivalent to $9.00/gal and $7.82/gal, respectively (Fuel
Prices Europe, 2014).
Fuel Prices in Turkey
(16 June 2014)
EUR/I
USD/I
USD/gal
Unleaded Gasoline 1.75
2.38
9.00
Diesel 1.52
2.07
7.82
LPG 0.94
1.27
4.81
Source: http://www.fuel-prices-europe.info/index.php?sort=6
Table 10: Fuel Prices in Turkey, 16 June 2014
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6 Opportunities for Gas Use
CMM, which is essentially natural gas, is the cleanest burning and most versatile hydrocarbon energy
resource available. It can be used for power generation in either base load power plants or in combined
cycle/co-generation power plants; as a transportation fuel; as a petrochemical and fertilizer feedstock;
as fuel for energy/heating requirements in industrial applications; and for domestic and commercial
heating and cooking (Table 11).
Sector
CMM/CBM Use
Electricity Generation
Fuel for base load power
Combined cycle 1 co-generation power plants
Fertilizer Industry
Feedstock in production of ammonia and urea
Industrial
Fuel for raising steam
Fuel in furnaces and heating applications
Domestic & commercial
Heating (spaces & water)
Cooking
Transportation
Compressed natural gas vehicles
Petrochemicals
Feedstock for a variety of chemical products
(e.g. methanol)
Table 11: Potential CMM Utilization Options
As noted in the Market Information section, the primary markets available for a CMM utilization project
at the Amasra Hard Coal Mine are power generation using internal combustion engines and vehicle fuel
in the form of CNG. Given the relatively small CMM production volume, as well as the requirement for
gas upgrading, constructing a pipeline to transport the gas to demand centers would be impractical.
Based on gas supply forecasts, the mine could be capable of operating as much as 8.8 MW of electricity
capacity or produce over 1.5 million DLE per month.
Generating electricity on site is attractive, because the input CMM gas stream can be utilized as is, with
minimal processing and transportation. Additional generating sets can be installed relatively cheaply
and infrastructure for the power plant and distribution system is already planned. While the CNG
utilization option requires significant processing of the CMM gas stream to increase its methane
concentration and remove contaminants, the current high price of transportation fuel in Turkey
improves the economics of this utilization option. However, this option should be investigated more
thoroughly in the full-scale feasibility study, should the project advance to that development stage.
Page 42
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7 Economic Analysis
7.1 Development Scenario
In order to assess the economic viability of the two degasification options presented throughout this
report, it is necessary to define the project scope and development schedule. Based on the mine maps
provided by HEMA, a total of 42 longwall panels throughout 6 coal seams are scheduled to be mined in
the East Production Block over a 24-year period once the mine is up and running. The specifics for the
proposed pre-drainage and the gob gas projects are detailed in the next two sections of this report.
7.1.1 Pre-Drainage Project Development
The proposed pre-drainage project - which utilizes long, in-seam boreholes to drain gas ahead of mining
- focuses on mining of the six coal seams (EC100 through EC600) located in the East Production Block.
Based on the mine maps provided by HEMA, a total of 42 individual longwall panels are scheduled to be
mined over a 24-year period. The mining plan is to work from the upper coal seam (EC100) down to the
lower ones (EC200 - EC600). Flanking in-seam boreholes are utilized to drain gas ahead of development
galleries. Long directionally drilled boreholes cover the entire length of each panel from a single setup
location, allowing drainage of multiple mining levels.
Based on the mine development schedule provided by HEMA, boreholes were assumed to be drilled and
come on production three to five years prior to the initiation of mining activities at each panel. CMM
gas production profiles were generated for a total of four project development cases:
• Case 1: 2 wells drilled per panel; 3 years pre-drainage
• Case 2: 2 wells drilled per panel; 5 years pre-drainage
• Case 3: 4 wells drilled per panel; 3 years pre-drainage
• Case 4: 4 wells drilled per panel; 5 years pre-drainage
Depending on the development case, it is assumed drilling of wells and production of gas commences
either 36 or 60 months in advance of mining of each longwall panel. CMM production from a panel
ceases once mining of the panel begins, and the project will conclude when the last panel is mined
through; total project life is 321 and 345 months from the initiation of gas drainage for the 3- and 5-year
pre-drainage cases, respectively.
The results of the previously discussed simulations were used to derive a series of single-well type
curves, which were combined with a schedule of wells drilled to calculate a CMM production profile for
each project development case. The single well type curves used in the CMM production forecast are
shown in Figure 20 and Figure 21, and the various drilling scenarios are presented in Figure 27.
Page 43
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o
k.
a.
250
200
~ 150
a
'¦P
_TU
3
E
3
U
100
50
Case Description
1 2 wells per panel; 3 years pre-drainage
2 2 wells per panel; 5 years pre-drainage
3 4 wells per panel; 3 years pre-drainage
4 4 wells per panel; 5 years pre-drainage
Degas
Period
-60 -20 20 60 100
Month
140
180
220
260
Figure 27: Drilling Scenarios for Pre-Drainage Development
7.1.2 Gob Gas Borehole Project Development
The methane drainage approach proposed at this mine includes a large gob degasification program
involving HGBs. HGBs will be drilled into the gob area above the formation to drain gas as longwall
mining progresses. HGBs will also be drilled between the EC300 and EC400 seams due to the separation
of the seams. A total of 19 HGBs are assumed to be drilled in the East Production Block prior to the start
of mining. Upon completion, HGBs will be placed on vacuum (-13.5 kPa) once mining progresses (Figure
28). The production duration of each HGB is dependent on the length of time it takes to mine each
longwall panel, and it is assumed that each HGB continues to produce gob gas for an additional three
months after the panel is mined through. Underground, the in-seam gas collection system is assumed
to be integrated with the gob gas drainage system (i.e., combined pipelines). The development of the
HGB portion of the project is assumed to be the same for all four in-seam gas drainage cases.
i-2
-n ~
° -d
13 o
> °-
re O
1 =
- a.
20
18
16
14
12
10
8
6
4
2
0
Degas
Mining r
Period
Period
-60 -40 -20 0 20 40
60 80
Month
100 120 140 160 180
Figure 28: Drilling Scenario for Gob Gas Borehole Development
Page 44
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7.2 Gas Production Forecast
Gas production forecasts were developed using the previously established type curves (Figure 20 and
Figure 21) and drilling cases (Figure 27 and Figure 28). The CMM production forecast for each project
development case is shown in Figure 29 through Figure 32, and the gob gas forecast is presented in
Figure 33.
m
£
o
CL
rc
Case 1: 2 wells per panel; 3 years pre-drainage
30
— 25
20
15
10
Ul ro N H
H (N ^ ^ 1^
THLOcj>ror^rHLoa^m
H(NrOUliDCOCnO(N
(N(N(NN(N(N(NrOfO
Month
Figure 29: Pre-Drainage Gas Production Forecast for Case 1
Page 45
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to
E
o
o.
fO
Case 2: 2 wells per panel; 5 years pre-drainage
30
— 25
20
15
10
EC600
IEC500
IEC400
IEC300
IEC20Q
IEC100
^3 d ID H ^ rl ^
h m ¦st in N o
rl l£) rl ID H ID
(N fO tn ID W Ol
t-H U3 (£> tH
HiN^LTiNCOOHrO^
fS(N(N(N(N(NfOfOrflfO
Month
o
ts
3
T3 j-
i*
Q- o
S?
¦s HI
I Wells
Total No.
Wells:
85
N ifl to 03 ffl
Month
N(MfM(M(MfMfOfOfO(fl
Figure 30: Pre-Drainage Gas Production Forecast for Case 2
Page 46
-------
60
50
40
30
20
10
0
12
10
8
6
4
2
0
Case 3: 4 wells per panel; 3 years pre-drainage
¦ EC600
¦ EC500
¦ EC400
EC300
EC200
EC100
HNTtmNMOlH
1"» tH Ln CT1 ro [¦». iH
rsj ti- Lfi in oo ai in
r—i rH rH tH rH tH CnI
Month
^oicoNHLfiaim
rNfOLfliDCOUlOfN
(NNfSfMNNfOrO
¦ Wells
Wells:
209
THti^CTifOf^.THLncTifor^.THLOo^poir^rHLOcrvror^irHLOciro
t—ir"Jt3"Lor'--cocft
-------
¦ Wells
Case 4: 4 wells per panel; 5 years pre-drainage
¦ EC600
¦ EC500
¦ EC400
¦ EC300
¦ EC200
¦ EC100
rH <*0 tH t—I ID rH
-------
Gob Gas Forecast
u
ss
o
o
25
20
15
l Above EC400
l Above EC100
¦| 10
ro
£
rfr^omu3CTi(NLnoo
H^lsOfOlDCflNiOroH^fsO
fO'T^NCOCJlOiNm^lDNOOO
HHHHHH(N(N(N(NlN(N(NrO
Mining Month
o
V
|1
Q- o
1.2
1.0
0.8
0.6
0.4
0.2
0.0
¦ Wells
Total
No
Wells:
19
Month
m*£icnr\imK)*-t=3-r-*o
comor\icn<3-<£ir-*MO
T-i*HfMfMrslfMfMrNJrMfO
Figure 33: Gob Gas Production Forecast
Page 49
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7.3 Project Economics
7.3.1 Economic Assessment Methodology
For each of the proposed project development scenarios, discounted cash flow analyses were
performed for the upstream portion (i.e., CMM production) and the downstream portion (i.e., electricity
production or CNG production). A breakeven gas price was calculated in the upstream segment where
the present value of cash outflows is equivalent to the present value of cash inflows. The breakeven gas
price was then used in the downstream segments to calculate the fuel cost for the power plant and the
feedstock cost for the CNG station. Likewise, breakeven electricity and CNG sales prices were calculated
for the downstream segments, which can be compared to the current price of electricity or
transportation fuel (e.g., CNG or diesel) observed at the mine in order to determine the economic
feasibility of each potential CMM utilization option. The results of the analyses are presented on a pre-
tax basis and the selection of a downstream utilization option is assumed to be mutually exclusive.
7.3.2 Upstream (CMM Project) Economic Assumptions and Results
Cost estimates for goods and services required for the development of the mine associated with the
Amasra Hard Coal Mine were based on a combination of known average development costs of
analogous projects in the region and the U.S., and other publically available sources (USEPA, 2009). The
capital and operating costs used in the economic analysis are based on per well costs from oil and gas
projects rather than on an underground mining analysis, which would most likely lower the costs. A
more detailed analysis should be conducted if this project advances to the full-scale feasibility study
level. Figure 34 presents a simplified schematic diagram of the CMM project and illustrates the major
cost components for the CMM project, which include the in-seam and horizontal gob boreholes,
gathering system, surface vacuum station, compressor, and pipeline to the sales system or utilization
project. The capital cost assumptions, operating cost assumptions, and physical and financial factors
used in the evaluation of upstream economics are provided in Table 12. A more detailed discussion of
each input parameter is provided below.
Pipeline
to sales Discharge
svstem stack
Surface
vacuum
Long Horizontal
in-seam 9ob borehole
Figure 34: Simplified Schematic Diagram of CMM Project
Page 50
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CMM Supply Model Inputs
Case 12 3 4
Wells per Panel 2 2 4 4
Years of Pre-Drainage 3 5 3 5
PHYSICAL & FINANCIAL FACTORS
Royalty
%
12.5%
12.5%
12.5%
12.5%
Price Escalation
%
3.0%
3.0%
3.0%
3.0%
Cost Escalation
%
3.0%
3.0%
3.0%
3.0%
Calorific Value of Drained Gas
MJ/m 3
34.58
34.58
34.58
34.58
Calorific Value of Gob Gas
MJ/m 3
26.60
26.60
26.60
26.60
CAPEX
Drainage System
Well Cost
$/well
90,300
90,300
90,300
90,300
Surface Vacuum Station
$/w
1.34
1.34
1.34
1.34
Vacuum Pump Efficiency
W/1000m 3/d
922
922
922
922
Gathering & Delivery System
Gathering Pipe Cost
$/m
131
131
131
131
Gathering Pipe Length
m/well
354
354
144
144
Satellite Compressor Cost
$/w
1.34
1.34
1.34
1.34
Compressor Efficiency
W/1000m 3/d
922
922
922
922
Pipeline Cost
$/m
180
180
180
180
Pipeline Length
m
1,999
1,999
1,999
1,999
OPEX
Field Fuel Use (gas)
%
10%
10%
10%
10%
O&M
$/1000m 3
17.66
17.66
17.66
17.66
Table 12: Summary of Input Parameters for the Evaluation of Upstream Economics (CMM Project)
7.3.2.1 Physical an d Fin an cial Factors
Royalty: Under the new Turkish Petroleum Law (Petroleum Law No. 6491 dated May 30, 2013), oil and
gas producers are required to pay a Royalty corresponding to one eight (12.5%) of the petroleum
produced.
Price and Cost Escalation: All prices and costs are assumed to increase by 3% per annum.
Calorific Value of Gas: The drained gas is assumed to have a calorific value of 34.58 megajoules per cubic
meter (MJ/m3) (928 Btu/cf) and the gob gas is assumed to have a calorific vale of 26.60 MJ/m3 (714
Btu/cf). These numbers are based on a calorific value of 38.00 MJ/m3 (1020 Btu/cf) for pure methane
adjusted to account for lower methane concentration of the CMM gas, which is assumed to be 91% and
70% methane for drained and gob gas, respectively.
7.3.2.2 Capital Expenditures
The drainage system includes the in-seam and gob drainage wells and vacuum pumps used to bring the
drainage gas to the surface. The major input parameters and assumptions associated with the drainage
system are as follows:
Well Cost: A borehole with a lateral length of 700 m is assumed to cost $90,300 per well. This is based
on the preliminary cost estimate provided by REI Drilling for Phase I Contract Drilling (Table 13). This
estimate is based on 10,000 m of drilling and represents a cost of $129 per meter. Should the CMM
project advance beyond the pre-feasibility stage, the implementation of an in-house drilling program by
Page 51
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the mine operator should be considered as a way to reduce development costs. As the mine assumes
this responsibility, drilling costs will be reduced over the project life.
Preliminary Cost Estimate
Phase 1 - Contract Drillinq f10,000 meters)
1. Shipping (cost+15% + other fees)
$ 60,000
2. Placement fee $ 100k/mo.est. 6 months
600,000
(includes engineering, labor and equipment)
3. Meter rate/Medium drilled: 10,000 m x $50/m
500,000
4. Expendable Materials (cost +15%):
60,000
5. Travel and per diem
70,000
Est. TOTAL
US $1,290,000
Phase II - Equipment Purchase and Traininq
REl coordinate and turnkey procurement of directional drilling equipment
supplies and training. Mine operator conducts in-house program.
1. VL11000 Drill w 1 DDMS survey tool
£ 1,200,000
2. Spare Parts
200,000
3. Rods/Down hole Drilling Equipment
350,000
4. Wellhead, Drill Bits, Reaming, Fishing Supplies
75,000
5. Shipping and other fees
50,000
6. TRAINING (3 man-months)
200,000
Est. TOTAL
US $2,075,000
Table 13: Preliminary Cost Estimate for Phase I and Phase II
Surface Vacuum Station: Vacuum pumps draw gas from the wells into the gathering system. Vacuum
pump costs are a function of the gas flow rate and efficiency of the pump. To estimate the capital costs
for the vacuum pump station, a pump cost of $1.34 per Watt (W) ($1000/hp) and a pump efficiency of
922 watts per thousand cubic meters per day (W/1000m3/d) (0.035 hp/mscfd) are assumed. Total
capital cost for the surface vacuum station is estimated as the product of pump cost, pump efficiency,
and peak gas flow (i.e., $/W x W/1000m3/d x 1000m3/d).
Gathering & Delivery System Cost: The gathering system consists of the piping and associated valves and
meters necessary to get the gas from within the mine to the satellite compressor station located on the
surface, and the delivery system consists of the satellite compressor and the pipeline that connects the
compressor to the sales system leading to the utilization project. The gathering system cost is a function
of the piping length and cost per meter. For the proposed project, we assume a piping cost of $131/m
($40/ft) and roughly 30,000 m (98,000 ft) of gathering lines.
Satellite compressors are used to move gas through the pipeline connected to the end-use project.
Similar to vacuum pump costs, compression costs are a function of the gas flow rate and efficiency of
the compressor. To estimate the capital costs for the compressor, we assume a compressor cost of
$1.34/W ($1000/hp) and an efficiency of 922 W/1000m3/d (0.035 hp/mscfd). As with the vacuum pump
costs, total capital cost for the compressor is estimated as the product of compressor cost, compressor
efficiency, and peak gas flow (i.e., $/W x W/1000m3/d x 1000m3/d). The cost of the pipeline to the end-
use project is a function of the pipeline length and cost per meter. For the proposed project, we assume
a pipeline cost of $180/m ($55/ft) and length of 2,000 m (6,560 ft).
Page 52
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7.3.2.3 Operating Expenses
Field Fuel Use: For the proposed project, it is assumed that CMM is used to power the vacuum pumps
and compressors in the gathering and delivery systems. Total fuel use is assumed to be 10%, which is
deducted from the gas delivered to the end use.
Normal Operating and Maintenance Cost: The normal operating and maintenance cost associated with
the vacuum pumps and compressors is assumed to be $17.66/1000m3 ($0.50/mcf).
7.3.2.4 Upstream (CMM Project) Econ om ics
The economic results for the CMM project are summarized in Figure 35, and the pro-forma cash flows
for each of the four proposed project development cases are summarized in Figure 39 through Figure 42
in the Appendix. Based on the forecasted gas production, the breakeven cost of producing gas through
in-seam drainage boreholes is estimated to be between $64 and $91/1000 m3 ($2.33 and
$3.15/MMBtu). The results of the economic assessment indicate the lowest CMM production costs are
associated with the 2 wells drilled per panel cases, with 5 years of pre-drainage (Case 2) preferred over 3
years (Case 1).
Summary of Economic Results
CMM Supply
CMM Supply Forecast
— 40
£
m
E
300
0 5 10
Total Wells Put On Production
Wells
Years
Breakeven
per
of Pre-
Gas Price
Case
Panel
Drainage
$/1000m3
1
2
3
71.93
2
2
5
63.57
3
4
3
90.85
4
4
5
84.00
Case Description
1 2 wells per panel; 3 years pre-drainage
2 2 wells per panel; 5 years pre-drainage
3 4 wells per panel; 3 years pre-drainage
4 4 wells per panel; 5 years pre-drainage
Figure 35: Summary of Economic Results for the CMM Project
7.3.3 Downstream (Power Project) Economic Assumptions and Results
The drained methane can be used to fire internal combustion engines that drive generators to make
electricity for use at the mine or for sale to the local power grid. The major cost components for the
power project are the cost of the engine and generator, as well as costs for gas processing to remove
solids and water, and the cost of equipment for connecting to the power grid. The assumptions used to
assess the economic viability of the power project are presented in Table 14. A more detailed discussion
of each input parameter is provided below.
Page 53
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Power Supply Model Inputs
Case 12 3 4
Wells per Panel 2 2 4 4
Years of Pre-Drainage 3 5 3 5
PHYSICAL & FINANCIAL FACTORS
Generator Efficienty
%
0.35
0.35
0.35
0.35
Run Time
%
0.90
0.90
0.90
0.90
CAPEX
Power Plant
$/kW
1,300
1,300
1,300
1,300
QPEX
Power Plant O&M
$/kWh
0.02
0.02
0.02
0.02
Table 14: Summary of Input Parameters for the Evaluation of Downstream Economics (Power Project)
7.3.3.1 Physical and Financial Factors
Generator Efficiency and Run Time:
Typical electrical power efficiency is between 30% and 44% and run time generally ranges between
7,500 to 8,300 hours annually (USEPA, 2009). For the proposed power project an electrical efficiency of
35% and an annual run time of 90%, or 7,884 hours, were assumed.
7.3.3.2 Capital Expenditures
Power Plant Cost Factor: The power plant cost factor, which includes capital costs for gas pretreatment,
power generation, and electrical interconnection equipment, is assumed to be $l,300/kW.
7.3.3.3 Operating Expenses
Power Plant Operating and Maintenance Cost: The operating and maintenance costs for the power plant
are assumed to be 0.02/kWh.
7.3.3.4 Downstream (Power Project) Economics
The economic results for the power project are summarized in Figure 36, and the pro-forma cash flows
for each of the four proposed project development cases are summarized in Figure 43 through Figure 46
in the Appendix. The breakeven power sales price, inclusive of the cost of methane drainage, is
estimated to be between $0,049 and $0.056/kWh. Based on a breakeven CMM price of $64/1000m3
($2.33/MMBtu) (Case 2), the mine could generate power at a price equivalent to $0.049/kWh. A CMM-
to-power utilization project at the mine would be economically feasible if the mine currently pays a
higher price for electricity. Although power combined with CMM drainage appears to be economic,
removing the cost of mine degasification from downstream economics as a sunk cost would significantly
reduce the marginal cost of power.
Page 54
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Summary of Economic Results
Power Supply
Power Supply Forecast
0 5 10
Generating Capacity
Wells
Years
Breakeven
per
of Pre-
Power Price
Case
Panel
Drainage
$/kWh
1
2
3
0.0526
2
2
5
0.0485
3
4
3
0.0561
4
4
5
0.0533
Description
2 wells per panel; 3 years pre-drainage
2 wells per panel; 5 years pre-drainage
4 wells per panel; 3 years pre-drainage
4 wells per panel; 5 years pre-drainage
Figure 36: Summary of Economic Results for Power Project
7.3.4 Downstream (CNG Project) Economic Assumptions and Results
The drained methane can also be used to produce compressed natural gas (CNG) for use as vehicle fuel.
However, due to the methane concentration of the comingling of pre-drainage and gob gas, upgrading
of the CMM may be necessary prior to converting the gas to CNG. The major cost component for the
CNG project is the gas upgrade facility and the CNG station. The assumptions used to assess the
economic viability of the CNG project are presented in Table 15. A more detailed discussion of each
input parameter is provided below.
Page 55
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CNG Supply Model Inputs
Case 12 3 4
Wells per Panel 2 2 4 4
Years of Pre-Drainage 3 5 3 5
PHYSICAL & FINANCIAL FACTORS
Diesel Heating Value
MJ/I
35.80
35.80
35.80
35.80
Outlet Gas Methane Cone.
%CH4
94%
94%
94%
94%
CAPEX
CNG Station Cost
$/DLE/mo
6.59
6.04
5.14
5.01
Gas Upgrade Facility
$,000
3,847
3,981
4,461
4,571
OPEX
CNG Station O&M
$/DLE
0.08
0.07
0.06
0.06
Gas Upgrade Facility O&M
Fixed
$,000/yr
300
300
300
300
Variable
$/1000m3
26.49
26.49
26.49
26.49
Table 15: Summary of Input Parameters for the Evaluation of Downstream Economics (CNG Project)
7.3.4.1 Physical and Financial Factors
Diesel Heating Value: Diesel liter equivalent (DLE) units are used to express a volume of CNG based on
the energy equivalent to a liter (I) of diesel fuel. A diesel heating value of 35.80 MJ (128,450 Btu per
gallon) was used in the CNG supply model in order to convert between gaseous and liquid fuel. This
number is derived from the lower heating value of U.S. conventional diesel as utilized in Argonne
National Laboratory's GREET model.
Outlet Gas Methane Concentration: It is assumed the CMM exiting the gas upgrading facility is 94% CH4.
7.3.4.2 Capital Expenditures
CNG Station Cost: CNG stations costs include installation and the cost of a compressor package, a dryer,
and onsite storage of CNG at 38 MPa (5500 psig). The station costs used in the CNG supply model were
modified from Johnson (2010) as shown in Figure 37, which shows CNG station costs as a function of
station size. The costs used in the economic model represent the average costs associated with transit
and refuse fleets as presented by Johnson (2010). For the proposed project development cases, CNG
station capital costs range between $5.01 and $6.59 per DLE produced per month with total capital
costs ranging between $4.9 to 7.3 million.
Gas Upgrade Facility: The gas upgrade facility consists of a pressure swing adsorption (PSA) type system
and a catalytic oxygen removal system. The PSA system is designed to remove nitrogen and carbon
dioxide down to 4% of the gas stream, which includes the requisite dehydration and compression
needed to process and discharge the gas at 900 psig. The cost of the facility is a function of the inlet gas
flow rate and the methane concentration (USEPA, 2009). For the proposed project development cases,
the gas upgrade facility costs range between $3.8 and $4.6 million.
7.3.4.3 Operating Expenses
CNG Station Operating and Maintenance Cost: Operating and maintenance costs associated with CNG
station are assumed to range between $0.06 and $0.08 per DLE produced, as shown in Figure 37
(Johnson, 2010).
Page 56
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CNG Station and O&M Costs Versus Throughput
20
o
E
a
¦—
15
o
u
55
~ 10
0.16
0.14
0.12
0.10
0.08
0.06
O
¦—
w
o
u
0.04 g
0.02
0 200 400 600 800 1000 1200
Station Size (Monthly Throughput in Thousand DGEs)
^—Station Cost O&M Cost
Source: Johnson (2010)
Figure 37: CNG Station and O&M Costs Versus Throughput (Johnson, 2010)
Gas Upgrade Facility Operating and Maintenance Cost: Operating and maintenance costs for the gas
upgrade facility assume a fixed cost of $300,000 per year in addition to a variable cost of $26.49/1000m3
of gas processed (USEPA, 2009).
7.3.4.4 Downstream (CNG Project) Economics
The economic results for the CNG project are summarized in Figure 38, and the pro-forma cash flows for
each of the four proposed project development cases are summarized in Figure 47 through Figure 50 in
the Appendix. The breakeven CNG sales price, inclusive of the cost of methane drainage, is estimated to
be between $0.22 and $0.26/DLE ($0.84 and $0.98/DGE). Due to economies of scale associated with
CNG station capacity, the optimal case for CNG production is Case 4, which produces CNG at a price
equivalent to $0.22/DLE ($0.84/DGE). A CMM-to-CNG utilization project at the mine would be
economically feasible if the mine currently pays a higher price for transportation fuel (e.g., CNG or diesel
fuel). As with the power project, CNG production combined with CMM drainage appears to be
economic and removing the cost of mine degasification from downstream economics as a sunk cost
would significantly reduce the marginal cost of CNG production.
Page 57
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Summary of Economic Results
CNG Supply
CNG Supply Forecast
E f 50
-a
> I 40
tS O
3 "o
30
13 °
5 20
0 5 10
CNG Station Throughput
Wells
Years
Breakeven
per
of Pre-
CNG Price
Case
Panel
Drainage
$/DLE
1
2
3
0.260
2
2
5
0.235
3
4
3
0.236
4
4
5
0.222
Case Description
1 2 wells per panel; 3 years pre-drainage
2 2 wells per panel; 5 years pre-drainage
3 4 wells per panel; 3 years pre-drainage
4 4 wells per panel; 5 years pre-drainage
Figure 38: Summary of Economic Results for CNG Project
8 Conclusions, Recommendations and Next Steps
As a pre-feasibility study, this document is intended to provide a high level analysis of the technical
feasibility and economics of the CMM project at the Amasra Hard Coal Mine. The analysis performed
reveals that methane drainage using longhole directional drilling in association with the development of
the Amasra Hard Coal Mine is feasible, and could provide the mine with additional benefits beyond the
sale of gas such as improved mine safety and enhanced productivity.
The focus of this study was the East Block because it will be the first block mined. However, the
proposed drainage approach should be applicable to the other coal blocks with some minor design
modifications. The most effective gas drainage program for the mine is likely to be a combination of
horizontal gob gas boreholes combined with in-seam gas drainage boreholes, both drilled from within
the mine. Due to the relatively low permeability of the coals, the drainage efficiency improves as more
wells per panel are drilled, and as drainage time increases. Based on the forecasted gas production, the
breakeven cost of producing CMM through in-seam drainage boreholes combined with HGBs is
estimated to be between $64 and $91/1000 m3 ($2.33 and $3.15/MMBtu). The results of the economic
assessment indicate the lowest CMM production costs are associated with the 2 wells drilled per panel
cases, with 5 years of pre-drainage (Case 2) preferred over 3 years (Case 1).
In terms of utilization, the power and CNG options both appear to be economically feasible. More
rigorous engineering design and costing would be needed before making a final determination of the
best available utilization option for the drained methane. As of the end of 2013 the average rate of
electricity for industrial customers was S0.1038/kWh (inclusive of all taxes and levies). When compared
to the breakeven power sales price calculated in the economic analysis, utilizing drained methane to
Page 58
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produce electricity could generate profits of between $48 and $55 per MWh of electricity produced. In
terms of transportation fuels, the current diesel price in Turkey is $2.07/1. With a breakeven CNG sales
price estimated to be between $0.22 and $0.26/DLE, utilizing drained methane to produce CNG could
generate profits of between $1.81 and $1.85 per DLE of CNG sold.
Both potential utilization options appear to be economically feasible, and removing the cost of mine
degasification from downstream economics, as a sunk cost, would reduce the marginal cost of electricity
and CNG production and improve the economics even further. Furthermore, depending on the
development approach and utilization option selected for the project, net emission reductions
associated with the destruction of drained methane are estimated to range between 2.2 million and 3.8
million tonnes of carbon dioxide equivalent (tC02e) over the 30-year project life. Should HEMA wish to
continue with the proposed drainage plan, a phased project approach is recommended. The first phase
would be to demonstrate the benefits of the proposed approach. The first steps would likely include the
following:
• On-site scoping mission and meetings with mine technical personnel.
• Develop methane drainage approach and scope of work for demonstration project including
estimated costs.
• Obtain budget approval for demonstration program.
• Meet to discuss and finalize project approach.
• Evaluate and approve drill room location and configuration and required utilities (water
supply/discharge and electricity).
• Evaluate, design and install gas collection and safety system.
Once the first phase is completed and the results are evaluated, a corporate go/no-go decision should
be made on whether or not to proceed with Phase II. The second phase would include equipment
purchase and training to implement the proposed modern methane drainage technologies in house.
Page 59
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Appendix
Simple Economics (CMM)
Input Parameters
Case 1
1
Royalty
12.5%
HE MA CMM Pre-Feasibility Study
Price Escalation
3.0%
per year
2 wells per panel; 3 years pre-drainage
Cost Escalation
3.0%
per year
Gas Price
2.64
$/MMBtu
2.04
$/Mcf
Well Cost
90.3
$,000/well
Surface Vacuum Station
1000
$/hp
Vacuum Pump Efficiency
0.035
hp/mcfd
Gathering Pipe Cost
40
$/ft
Gathering Pipe Length
950
ft/well
Satellite Compressor Cost
1000
$/hp
Compressor Efficiency
0.035
hp/mcfd
Pipeline Cost
55
$/ft
Pipeline Length
6560
ft
Field Fuel Use (gas)
10.0%
%
O&M
0.5
$/mcf
Project Cashflow
Gross
Net
Gas
Net
Operating Operating
Capital
Cum.
Net CH4
Project
Gas Prod.
Gas Prod.
Price
Revenue
Cost
Income
Cost Cashflow
Cashflow
Wells
Prod
Year
mmcf
mmcf
$/mcf
$.000
$.000
$.000
$.000
$.000
$.000
Drilled
mmcf
0
-
-
406.8
(406.8)
(406.8)
-
-
1
266.6
209.9
2.10
440.4
108.1
332.2
711.8
(379.6)
(786.4)
5
158.8
2
554.1
436.4
2.22
968.6
231.5
737.1
1,088.8
(351.7)
(1,138.1)
8
339.1
3
454.9
358.2
2.32
832.7
195.7
636.9
700.9
(64.0)
(1,202.1)
5
283.0
4
497.3
391.6
2.46
962.7
220.4
742.3
1,011.6
(269.3)
(1,471.4)
7
317.7
5
558.7
439.9
2.43
1,068.5
255.0
813.5
594.9
218.6
(1,252.8)
4
342.3
6
345.1
271.7
2.54
691.3
162.2
529.1
306.4
222.7
(1,030.1)
2
215.0
7
303.6
239.0
2.57
613.6
147.0
466.6
788.9
(322.3)
(1,352.4)
5
185.3
8
319.5
251.6
2.64
663.7
159.4
504.3
975.1
(470.8)
(1,823.1)
6
194.6
9
388.7
306.1
2.78
850.3
199.7
650.6
669.6
(19.0)
(1,842.1)
4
242.0
10
333.6
262.7
2.88
756.1
176.5
579.6
517.2
62.4
(1,779.7)
3
209.0
11-30
6,124.2
4,822.8
17,885.8
4,183.3
13,702.6
11,922.8
1,779.7
55
3,825.8
Total
10,146.1
7,990.1
3.22| 25,733.7
6,038.8
19,694.9
19,694.9
0.0
104
6,312.6
79%
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
27.0
Rate
Value
Net Income / Net Capital
1.0
10%
-
(1,275.1)
15%
-
(1,255.1)
20%
-
(1,185.0)
25%
-
(1,112.6)
30%
-
(1,049.2)
Figure 39: CMM Project Cash Flow for Case 1 (2 wells per panel; 3 years pre-drainage)
Page 60
-------
Simple Economics (CMM)
Input Parameters
Case 2
2
Royalty
12.5%
HE MA CMM Pre-Feasibility Study
Price Escalation
3.0%
per year
2 wells per panel; 5 years pre-drainage
Cost Escalation
3.0%
per year
Gas Price
2.33
1.80
$/MMBtu
$/Mcf
Well Cost
90.3
$,000/well
Surface Vacuum Station
1000
$/hp
Vacuum Pump Efficiency
0.035
hp/mcfd
Gathering Pipe Cost
40
$/ft
Gathering Pipe Length
950
ft/well
Satellite Compressor Cost
1000
$/hp
Compressor Efficiency
0.035
hp/mcfd
Pipeline Cost
55
$/ft
Pipeline Length
6560
ft
Field Fuel Use (gas)
10.0%
%
O&M
0.5
$/mcf
Project Cashflow
Gross
Net
Gas
Net
Operating Operating
Capital
Cum.
Net CH4
Project
Gas Prod.
Gas Prod.
Price
Revenue
Cost
Income
Cost Cashflow
Cashflow
Wells
Prod
Year
mmcf
mmcf
S/mcf
$.000
$.000
$.000
$.000
S.000
S.000
Drilled
mmcf
0
-
-
406.8
(406.8)
(406.8)
-
-
1
266.6
209.9
1.85
389.2
108.1
281.1
711.8
(430.8)
(837.6)
5
158.8
2
554.1
436.4
1.96
856.0
231.5
624.5
1,088.8
(464.3)
(1,301.9)
8
339.1
3
454.9
358.2
2.05
735.9
195.7
540.1
700.9
(160.8)
(1,462.7)
5
283.0
4
517.2
407.3
2.17
884.8
229.2
655.6
1,029.5
(373.8)
(1,836.5)
7
331.9
5
650.6
512.3
2.15
1,099.6
297.0
802.7
594.9
207.8
(1,628.7)
4
408.2
6
439.9
346.4
2.25
778.8
206.8
572.0
306.4
265.7
(1,363.0)
2
283.0
7
392.7
309.2
2.27
701.5
190.2
511.3
788.9
(277.6)
(1,640.6)
5
249.2
8
415.4
327.1
2.33
762.6
207.2
555.4
975.1
(419.7)
(2,060.3)
6
263.3
9
445.5
350.8
2.45
861.1
228.9
632.3
669.6
(37.3)
(2,097.6)
4
282.7
10
361.1
284.4
2.54
723.4
191.1
532.3
517.2
15.1
(2,082.6)
3
228.7
11-30
7,361.6
5,797.3
19,075.3
5,076.5
13,998.8
11,916.2
2,082.6
55
4,712.6
Total
11,859.4
9,339.3
2.88
26,868.2
7,162.1
19,706.1
19,706.1
(0.0)
104
7,540.4
81%
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
26.8
Rate
Value
Net Income / Net Capital
1.0
10%
-
(1,515.8)
15%
-
(1,482.5)
20%
-
(1,393.2)
25%
-
(1,302.7)
30%
-
(1,223.4)
Figure 40: CMM Project Cash Flow for Case 2 (2 wells per panel; 5 years pre-drainage)
Page 61
-------
Simple Economics (CMM)
Input Parameters
Case 3
3
Royalty
12.5%
HE MA CMM Pre-Feasibility Study
Price Escalation
3.0%
per year
4 wells per panel; 3 years pre-drainage
Cost Escalation
3.0%
per year
Gas Price
3.15
$/MMBtu
2.57
$/Mcf
Well Cost
90.3
$,000/well
Surface Vacuum Station
1000
$/hp
Vacuum Pump Efficiency
0.035
hp/mcfd
Gathering Pipe Cost
40
$/ft
Gathering Pipe Length
433
ft/well
Satellite Compressor Cost
1000
$/hp
Compressor Efficiency
0.035
hp/mcfd
Pipeline Cost
55
$/ft
Pipeline Length
6560
ft
Field Fuel Use (gas)
10.0%
%
O&M
0.5
$/mcf
Project Cashflow
Gross
Net
Gas
Net
Operating Operating Capital
Cum.
Net CH4
Project
Gas Prod.
Gas Prod.
Price
Revenue
Cost
Income Cost Cashflow
Cashflow
Wells
Prod
Year
mmcf
mmcf
S/mcf
$.000
$.000
$.000 $.000
$.000
$.000
Drilled
mmcf
0
-
-
425.7
(425.7)
(425.7)
-
-
1
375.7
295.9
2.50
740.4
152.4
588.0 1,075.3
(487.3)
(912.9)
9
237.0
2
812.0
639.5
2.65
1,693.0
339.2
1,353.8 1,826.9
(473.2)
(1,386.1)
16
523.9
3
683.1
537.9
2.77
1,491.4
293.9
1,197.5 1,293.7
(96.2)
(1,482.3)
11
446.6
4
734.7
578.6
2.93
1,696.5
325.6
1,370.9 1,575.6
(204.6)
(1,686.9)
13
487.8
5
816.1
642.7
2.90
1,861.9
372.5
1,489.3 1,247.7
241.6
(1,445.3)
10
526.8
6
466.8
367.6
3.03
1,115.5
219.5
896.0 514.1
382.0
(1,063.3)
4
302.3
7
406.2
319.9
3.06
979.4
196.7
782.7 1,191.3
(408.6)
(1,472.0)
9
258.9
8
467.0
367.8
3.15
1,157.2
233.0
924.2 1,636.1
(711.9)
(2,183.9)
12
300.3
9
596.3
469.6
3.31
1,555.7
306.3
1,249.4 1,123.4
125.9
(2,058.0)
8
390.8
10
507.5
399.6
3.43
1,372.0
268.5
1,103.5 1,012.5
91.0
(1,967.0)
7
333.6
11-30
9,158.5
7,212.3
31,855.4
6,248.0
25,607.3 23,640.4
1,967.0
129
6,000.3
Total
15,024.0
11,831.4
3.85| 45,518.3
8,955.7
36,562.7 36,562.7
(0.0)
228
9,808.2
83%
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
-
Rate
Value
Net Income / Net Capital
1.0
10%
-
(1,477.5)
15%
-
(1,445.8)
20%
-
(1,362.3)
25%
-
(1,279.1)
30%
-
(1,207.2)
Figure 41: CMM Project Cash Flow for Case 3 (4 wells per panel; 3 years pre-drainage)
Page 62
-------
Simple Economics (CMM)
Input Parameters
Case 4
4
Royalty
12.5%
HE MA CMM Pre-Feasibility Study
Price Escalation
3.0%
per year
4 wells per panel; 5 years pre-drainage
Cost Escalation
3.0%
per year
Gas Price
2.91
$/MMBtu
2.38
$/Mcf
Well Cost
90.3
$,000/well
Surface Vacuum Station
1000
$/hp
Vacuum Pump Efficiency
0.035
hp/mcfd
Gathering Pipe Cost
40
$/ft
Gathering Pipe Length
433
ft/well
Satellite Compressor Cost
1000
$/hp
Compressor Efficiency
0.035
hp/mcfd
Pipeline Cost
55
$/ft
Pipeline Length
6560
ft
Field Fuel Use (gas)
10.0%
%
O&M
0.5
$/mcf
Project Cashflow
Gross
Net
Gas
Net
Operating Operating Capital
Cum.
Net CH4
Project
Gas Prod.
Gas Prod.
Price
Revenue
Cost
Income Cost Cashflow
Cashflow
Wells
Prod
Year
mmcf
mmcf
S/mcf
$.000
$.000
$.000 $.000
$.000
$.000
Drilled
mmcf
0
-
-
425.7
(425.7)
(425.7)
-
-
1
375.7
295.9
2.31
684.5
152.4
532.1 1,075.3
(543.1)
(968.8)
9
237.0
2
812.0
639.5
2.45
1,565.2
339.2
1,226.0 1,826.9
(601.0)
(1,569.8)
16
523.9
3
683.1
537.9
2.56
1,378.9
293.9
1,084.9 1,293.7
(208.8)
(1,778.5)
11
446.6
4
737.8
581.0
2.71
1,575.2
327.0
1,248.2 1,589.4
(341.2)
(2,119.7)
13
490.1
5
887.4
698.8
2.68
1,871.6
405.1
1,466.6 1,247.7
218.9
(1,900.9)
10
577.9
6
553.7
436.1
2.81
1,223.5
260.3
963.1 514.1
449.1
(1,451.8)
4
364.6
7
482.8
380.2
2.83
1,076.2
233.8
842.4 1,191.3
(348.9)
(1,800.8)
9
313.8
8
546.8
430.6
2.91
1,252.4
272.7
979.7 1,636.1
(656.4)
(2,457.2)
12
357.4
9
647.3
509.7
3.06
1,561.4
332.5
1,228.8 1,123.4
105.4
(2,351.8)
8
427.3
10
534.6
421.0
3.17
1,336.4
282.9
1,053.5 1,012.5
41.0
(2,310.8)
7
353.0
11-30
10,219.9
8,048.1
32,960.8
7,013.4
25,947.4 23,636.5
2,310.8
129
6,760.8
Total
16,481.2
12,978.9
3.58| 46,486.0
9,913.3
36,572.7 36,572.7
(0.0)
228
10,852.5
84%
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
26.9
Rate
Value
Net Income / Net Capital
1.0
10%
-
(1,758.0)
15%
-
(1,710.3)
20%
-
(1,604.0)
25%
-
(1,499.5)
30%
-
(1,409.0)
Figure 42: CMM Project Cash Flow for Case 4 (4 wells per panel; 5 years pre-drainage)
Page 63
-------
Simple Economics (Power)
Input Parameters
Case 1
Power Sales Price
0.0526
$/kWh
HEM A CMM P re-Feasibility Study
Generator Size
5.3
MW
2 wells per panel; 3 years pre-drainage
Power Plant Cost Factor
1300
$/kW
Generator Efficiency
0.35
Run Time
90%
Price Escalation
3.0%
Cost Escalation
3.0%
Power Plant O&M
0.02
$/kWh
Fuel Cost Switch
1
Project Cashflow
Generator
Sales
Fuel
Operating
Operating Capital
Cum.
Delivered
Generator
Project
Output
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
MWh
$/kWh
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
MW
0
-
0.0526
-
-
-
6,877.3
(6,877.3)
(6,877.3)
-
-
1
16,614.1
0.0542
900.3
440.4
342.3
117.7
117.7
(6,759.6)
158.8
2.1
2
35,479.3
0.0558
1,980.2
968.6
752.8
258.9
258.9
(6,500.8)
339.1
4.5
3
29,612.1
0.0575
1,702.3
832.7
647.2
222.5
222.5
(6,278.3)
283.0
3.8
4
33,238.9
0.0592
1,968.2
962.7
748.2
257.3
257.3
(6,021.0)
317.7
4.2
5
35,818.8
0.0610
2,184.6
1,068.5
830.5
285.6
285.6
(5,735.4)
342.3
4.5
6
22,499.9
0.0628
1,413.4
691.3
537.3
184.8
184.8
(5,550.7)
215.0
2.9
7
19,388.4
0.0647
1,254.5
613.6
476.9
164.0
164.0
(5,386.7)
185.3
2.5
8
20,359.8
0.0666
1,356.9
663.7
515.8
177.4
177.4
(5,209.3)
194.6
2.6
9
25,325.2
0.0686
1,738.4
850.3
660.9
227.2
227.2
(4,982.1)
242.0
3.2
10
21,865.0
0.0707
1,545.9
756.1
587.7
202.1
202.1
(4,780.0)
209.0
2.8
11-30
400,293.5
36,567.1
17,885.8
13,901.2
4,780.0
4,780.0
3,825.8
50.8
Total
660,494.9
0.0797
52,611.8
25,733.7
20,000.8
6,877.3 6,877.3
0.0
6,312.6 | 5.3
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
27.0
Rate
Value
Net Income / Net Capital
1.0
10%
-
(4,738.6)
15%
-
(5,427.2)
20%
-
(5,803.7)
25%
-
(6,032.1)
30%
-
(6,183.0)
Figure 43: Power Project Cash Flow for Case 1 (2 wells per panel; 3 years pre-drainage)
Page 64
-------
Simple Economics (Power)
Input Parameters
Case 2
Power Sales Price
0.0485
$/kWh
HEM A CMM P re-Feasibility Study
Generator Size
6.0
MW
2 wells per panel; 5 years pre-drainage
Power Plant Cost Factor
1300
$/kW
Generator Efficiency
0.35
Run Time
90%
Price Escalation
3.0%
Cost Escalation
3.0%
Power Plant O&M
0.02
$/kWh
Fuel Cost Switch
1
Project Cashflow
Generator
Sales
Fuel
Operating
Operating Capital
Cum.
Delivered
Generator
Project
Output
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
MWh
$/kWh
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
MW
0
-
0.0485
-
-
-
7,743.4
(7,743.4)
(7,743.4)
-
-
1
16,614.1
0.0500
830.2
389.2
342.3
98.7
98.7
(7,644.7)
158.8
2.1
2
35,479.3
0.0515
1,826.0
856.0
752.8
217.2
217.2
(7,427.5)
339.1
4.5
3
29,612.1
0.0530
1,569.7
735.9
647.2
186.7
186.7
(7,240.8)
283.0
3.8
4
34,731.3
0.0546
1,896.3
884.8
781.8
229.7
229.7
(7,011.1)
331.9
4.4
5
42,709.1
0.0562
2,401.9
1,099.6
990.2
312.0
312.0
(6,699.1)
408.2
5.4
6
29,608.1
0.0579
1,715.1
778.8
707.1
229.2
229.2
(6,469.9)
283.0
3.8
7
26,069.9
0.0597
1,555.4
701.5
641.3
212.7
212.7
(6,257.2)
249.2
3.3
8
27,550.1
0.0615
1,693.0
762.6
698.0
232.5
232.5
(6,024.7)
263.3
3.5
9
29,579.6
0.0633
1,872.3
861.1
771.9
239.2
239.2
(5,785.5)
282.7
3.8
10
23,928.1
0.0652
1,560.0
723.4
643.1
193.5
193.5
(5,592.0)
228.7
3.0
11-30
493,078.0
41,970.7
19,075.3
17,303.3
5,592.0
5,592.0
4,712.6
62.5
Total
788,959.7
0.0746
58,890.6
26,868.2
24,279.0
7,743.4 7,743.4
(0.0)
7,540.4 | 6.0
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
-
Rate
Value
Net Income / Net Capital
1.0
10%
-
(5,511.3)
15%
-
(6,270.5)
20%
-
(6,677.1)
25%
-
(6,919.8)
30%
-
(7,077.9)
Figure 44: Power Project Cash Flow for Case 2 (2 wells per panel; 5 years pre-drainage)
Page 65
-------
Simple Economics (Power)
Input Parameters
Case 3
Power Sales Price
0.0561
$/kWh
HEM A CMM P re-Feasibility Study
Generator Size
8.2
MW
4 wells per panel; 3 years pre-drainage
Power Plant Cost Factor
1300
$/kW
Generator Efficiency
0.35
Run Time
90%
Price Escalation
3.0%
Cost Escalation
3.0%
Power Plant O&M
0.02
$/kWh
Fuel Cost Switch
1
Project Cashflow
Generator
Sales
Fuel
Operating
Operating Capital
Cum.
Delivered
Generator
Project
Output
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
MWh
$/kWh
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
MW
0
-
0.0561
-
-
-
10,706.3
(10,706.3)
(10,706.3)
-
-
1
24,802
0.0578
1,434.3
740.4
510.9
183.0
183.0
(10,523.4)
237.0
3.1
2
54,816
0.0596
3,265.1
1,693.0
1,163.1
409.1
409.1
(10,114.3)
523.9
7.0
3
46,723
0.0614
2,866.6
1,491.4
1,021.1
354.0
354.0
(9,760.2)
446.6
5.9
4
51,043
0.0632
3,225.5
1,696.5
1,149.0
380.0
380.0
(9,380.3)
487.8
6.5
5
55,124
0.0651
3,587.9
1,861.9
1,278.1
448.0
448.0
(8,932.3)
526.8
7.0
6
31,626
0.0670
2,120.2
1,115.5
755.3
249.5
249.5
(8,682.8)
302.3
4.0
7
27,086
0.0691
1,870.3
979.4
666.2
224.7
224.7
(8,458.1)
258.9
3.4
8
31,422
0.0711
2,234.9
1,157.2
796.1
281.6
281.6
(8,176.5)
300.3
4.0
9
40,886
0.0733
2,995.2
1,555.7
1,066.9
372.6
372.6
(7,803.9)
390.8
5.2
10
34,902
0.0755
2,633.6
1,372.0
938.1
323.4
323.4
(7,480.4)
333.6
4.4
11-30
627,812
61,100.9
31,855.4
21,765.1
7,480.4
7,480.4
6,000.3
79.6
Total
1,026,242
0.0851
87,334.6
45,518.3
31,109.9
10,706.3 10,706.3
(0.0)
9,808.2
8.2
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
-
Rate
Value
Net Income / Net Capital
1.0
10%
-
(7,382.5)
15%
-
(8,457.3)
20%
-
(9,043.8)
25%
-
(9,398.7)
30%
-
(9,632.5)
Figure 45: Power Project Cash Flow for Case 3 (4 wells per panel; 3 years pre-drainage)
Page 66
-------
Simple Economics (Power)
Input Parameters
Case 4
Power Sales Price
0.0533
$/kWh
HEM A CMM P re-Feasibility Study
Generator Size
8.8
MW
4 wells per panel; 5 years pre-drainage
Power Plant Cost Factor
1300
$/kW
Generator Efficiency
0.35
Run Time
90%
Price Escalation
3.0%
Cost Escalation
3.0%
Power Plant O&M
0.02
$/kWh
Fuel Cost Switch
1
Project Cashflow
Generator
Sales
Fuel
Operating
Operating Capital
Cum.
Delivered
Generator
Project
Output
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
MWh
$/kWh
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
MW
0
-
0.0533
-
-
-
11,430.3
(11,430.3)
(11,430.3)
-
-
1
24,802
0.0549
1,362.3
684.5
510.9
166.8
166.8
(11,263.5)
237.0
3.1
2
54,816
0.0566
3,101.2
1,565.2
1,163.1
372.9
372.9
(10,890.6)
523.9
7.0
3
46,723
0.0583
2,722.6
1,378.9
1,021.1
322.6
322.6
(10,568.0)
446.6
5.9
4
51,277
0.0600
3,077.6
1,575.2
1,154.3
348.2
348.2
(10,219.8)
490.1
6.5
5
60,467
0.0618
3,738.0
1,871.6
1,402.0
464.5
464.5
(9,755.4)
577.9
7.7
6
38,148
0.0637
2,429.0
1,223.5
911.0
294.6
294.6
(9,460.8)
364.6
4.8
7
32,828
0.0656
2,153.0
1,076.2
807.5
269.3
269.3
(9,191.5)
313.8
4.2
8
37,399
0.0676
2,526.4
1,252.4
947.5
326.5
326.5
(8,865.0)
357.4
4.7
9
44,712
0.0696
3,111.0
1,561.4
1,166.8
382.9
382.9
(8,482.1)
427.3
5.7
10
36,939
0.0717
2,647.3
1,336.4
992.9
318.1
318.1
(8,164.1)
353.0
4.7
11-30
707,392
65,805.0
32,960.8
24,680.1
8,164.1
8,164.1
6,760.8
89.7
Total
1,135,503
0.0816
92,673.4
46,486.0
34,757.1
11,430.3 11,430.3
0.0
10,852.5 | 8.8
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
29.0
Rate
Value
Net Income / Net Capital
1.0
10%
-
(8,034.8)
15%
-
(9,168.1)
20%
-
(9,779.3)
25%
-
(10,145.5)
30%
-
(10,384.8)
Figure 46: Power Project Cash Flow for Case 4 (4 wells per panel; 5 years pre-drainage)
Page 67
-------
Simple Economics (CNG)
Input Parameters
Case 1
CNG Price
0.98
$/DGE
HEM A CMM Pre-Feasibility Study
Diesel Heating Value
128450
Btu/gal
2 wells per panel; 3 years pre-drainage
CNG Station Cost
19.76
$/DGE/mo
CNG Station O&M
0.23
$/DGE
CNG Station Size
248.0
10A3 DGE/mo
Outlet Gas Methane Cone.
94°/t
%CH4
Gob Gas Upgrade Facility
3847
$,000
Gob Gas Upgrade Facility O&M
Fixed
300
$, 000/yr
Variable
0.75
$/Mcf
Price Escalation
3.0°/t
Cost Escalation
3.0°/t
Fuel Cost Switch
1
Project Cashflow
CNG
CNG
Fuel
Operating Operating Capital
Cum.
Deli\ered
Station
Project
Volume
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
10A3 DGE
S/DGE
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
10^ DGE/mo
0
-
0.98
8,745.9
(8,745.9)
(8,745.9)
-
-
1
1,185.3
1.01
1,201.4
440.4
705.1
55.9
55.9
(8,690.0)
149.3
98.8
2
2,531.1
1.04
2,642.5
968.6
1,189.6
484.4
484.4
(8,205.6)
318.7
210.9
3
2,112.5
1.08
2,271.7
832.7
1,076.9
362.2
362.2
(7,843.4)
266.0
176.0
4
2,371.3
1.11
2,626.4
962.7
1,203.7
460.1
460.1
(7,383.3)
298.6
197.6
5
2,555.3
1.14
2,915.2
1,068.5
1,309.0
537.7
537.7
(6,845.6)
321.8
212.9
6
1,605.2
1.18
1,886.2
691.3
980.1
214.7
214.7
(6,631.0)
202.1
133.8
7
1,383.2
1.21
1,674.1
613.6
920.9
139.5
139.5
(6,491.4)
174.2
115.3
8
1,452.5
1.25
1,810.7
663.7
977.1
170.0
170.0
(6,321.5)
182.9
121.0
9
1,806.7
1.28
2,319.9
850.3
1,156.3
313.2
313.2
(6,008.3)
227.5
150.6
10
1,559.9
1.32
2,063.0
756.1
1,083.4
223.4
223.4
(5,784.8)
196.4
130.0
11-30
28,557.0
48,797.4
17,885.8
25,126.7
5,784.8
5,784.8
3,596.2
2,379.8
Total
47,119.9
1.49
70,208.4
25,733.7
35,728.8
8,745.9 8,745.9
0.0
5,933.9
248.0
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
22.1
Rate
Value
Net Income / Net Capital
1.0
10%
-
(5,780.7)
15%
-
(6,693.0)
20%
-
(7,205.0)
25%
-
(7,522.0)
30%
-
(7,735.4)
Figure 47: CNG Project Cash Flow for Case 1 (2 wells per panel; 3 years pre-drainage)
Page 68
-------
Simple Economics (CNG)
Input Parameters
Case 2
CNG Price
0.89
$/DGE
HEM A CMM Pre-Feasibility Study
Diesel Heating Value
128450
Btu/gal
2 wells per panel; 5 years pre-drainage
CNG Station Cost
19.17
$/DGE/mo
CNG Station O&M
0.22
$/DGE
CNG Station Size
279.2
10A3 DGE/mo
Outlet Gas Methane Cone.
94°/t
%CH4
Gob Gas Upgrade Facility
3981
$,000
Gob Gas Upgrade Facility O&M
Fixed
300
$, 000/yr
Variable
0.75
$/Mcf
Price Escalation
3.0°/t
Cost Escalation
3.0°/t
Fuel Cost Switch
1
Project Cashflow
CNG
CNG
Fuel
Operating Operating Capital
Cum.
Deli\ered
Station
Project
Volume
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
10A3 DGE
S/DGE
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
10^ DGE/mo
0
-
0.89
9,332.3
(9,332.3)
(9,332.3)
-
-
1
1,185.3
0.92
1,086.6
389.2
688.3
9.1
9.1
(9,323.2)
149.3
98.8
2
2,531.1
0.94
2,389.9
856.0
1,152.5
381.4
381.4
(8,941.8)
318.7
210.9
3
2,112.5
0.97
2,054.6
735.9
1,045.0
273.7
273.7
(8,668.1)
266.0
176.0
4
2,477.7
1.00
2,482.0
884.8
1,204.1
393.1
393.1
(8,275.0)
312.0
206.5
5
3,046.9
1.03
3,143.7
1,099.6
1,445.2
598.9
598.9
(7,676.1)
383.7
253.9
6
2,112.3
1.06
2,244.8
778.8
1,141.8
324.1
324.1
(7,351.9)
266.0
176.0
7
1,859.8
1.09
2,035.8
701.5
1,079.6
254.7
254.7
(7,097.2)
234.2
155.0
8
1,965.4
1.13
2,215.9
762.6
1,153.6
299.8
299.8
(6,797.4)
247.5
163.8
9
2,110.2
1.16
2,450.6
861.1
1,246.8
342.6
342.6
(6,454.8)
265.7
175.9
10
1,707.0
1.20
2,041.8
723.4
1,115.9
202.5
202.5
(6,252.3)
215.0
142.3
11-30
35,176.3
54,933.6
19,075.3
29,606.0
6,252.3
6,252.3
4,429.8
2,931.4
Total
56,284.6
1.37
77,079.3
26,868.2
40,878.7
9,332.3 9,332.3
0.0
7,088.0
279.2
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
22.1
Rate
Value
Net Income / Net Capital
1.0
10%
-
(6,244.9)
15%
-
(7,257.1)
20%
-
(7,822.3)
25%
-
(8,167.8)
30%
-
(8,396.3)
Figure 48: CNG Project Cash Flow for Case 2 (2 wells per panel; 5 years pre-drainage)
Page 69
-------
Simple Economics (CNG)
Input Parameters
Case 3
CNG Price
0.89
$/DGE
HEM A CMM Pre-Feasibility Study
Diesel Heating Value
128450
Btu/gal
4 wells per panel; 3 years pre-drainage
CNG Station Cost
17.87
$/DGE/mo
CNG Station O&M
0.17
$/DGE
CNG Station Size
386.0
10A3 DGE/mo
Outlet Gas Methane Cone.
94°/t
%CH4
Gob Gas Upgrade Facility
4461
$,000
Gob Gas Upgrade Facility O&M
Fixed
300
$, 000/yr
Variable
0.75
$/Mcf
Price Escalation
3.0°/t
Cost Escalation
3.0°/t
Fuel Cost Switch
1
Project Cashflow
CNG
CNG
Fuel
Operating Operating Capital
Cum.
Deli\ered
Station
Project
Volume
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
10A3 DGE
S/DGE
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
10^ DGE/mo
0
-
0.89
11,360.0
(11,360.0)
(11,360.0)
-
-
1
1,769.4
0.92
1,627.9
740.4
796.2
91.3
91.3
(11,268.7)
222.8
147.4
2
3,910.6
0.95
3,705.9
1,693.0
1,427.4
585.5
585.5
(10,683.1)
492.5
325.9
3
3,333.3
0.98
3,253.5
1,491.4
1,301.6
460.6
460.6
(10,222.6)
419.8
277.8
4
3,641.4
1.01
3,660.9
1,696.5
1,433.3
531.1
531.1
(9,691.5)
458.6
303.4
5
3,932.5
1.04
4,072.3
1,861.9
1,566.6
643.8
643.8
(9,047.7)
495.2
327.7
6
2,256.2
1.07
2,406.5
1,115.5
1,078.4
212.5
212.5
(8,835.1)
284.1
188.0
7
1,932.3
1.10
2,122.8
979.4
1,004.3
139.1
139.1
(8,696.0)
243.3
161.0
8
2,241.7
1.13
2,536.6
1,157.2
1,139.2
240.2
240.2
(8,455.8)
282.3
186.8
9
2,916.8
1.17
3,399.6
1,555.7
1,408.9
435.0
435.0
(8,020.8)
367.3
243.1
10
2,489.9
1.20
2,989.1
1,372.0
1,297.8
319.3
319.3
(7,701.5)
313.6
207.5
11-30
44,788.3
69,349.1
31,855.4
29,792.2
7,701.5
7,701.5
5,640.3
3,732.4
Total
73,212.4
1.35
99,124.2
45,518.3
42,245.9
11,360.0 11,360.0
0.0
9,219.7
386.0
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
22.4
Rate
Value
Net Income / Net Capital
1.0
10%
-
(7,609.1)
15%
-
(8,787.7)
20%
-
(9,442.2)
25%
-
(9,843.4)
30%
-
(10,110.9)
Figure 49: CNG Project Cash Flow for Case 3 (4 wells per panel; 3 years pre-drainage)
Page 70
-------
Simple Economics (CNG)
Input Parameters
Case 4
CNG Price
0.84
$/DGE
HEM A CMM Pre-Feasibility Study
Diesel Heating Value
128450
Btu/gal
4 wells per panel; 5 years pre-drainage
CNG Station Cost
17.66
$/DGE/mo
CNG Station O&M
0.16
$/DGE
CNG Station Size
412.1
10A3 DGE/mo
Outlet Gas Methane Cone.
94°/t
%CH4
Gob Gas Upgrade Facility
4571
$,000
Gob Gas Upgrade Facility O&M
Fixed
300
$, 000/yr
Variable
0.75
$/Mcf
Price Escalation
3.0°/t
Cost Escalation
3.0°/t
Fuel Cost Switch
1
Project Cashflow
CNG
CNG
Fuel
Operating Operating Capital
Cum.
Deli\ered
Station
Project
Volume
Price
Revenue
Cost
Cost
Income Cost
Cashflow
Cashflow
CH4
Sizing
Year
10A3 DGE
S/DGE
$.000
$.000
$.000
$.000 $.000
$.000
$.000
mmcf
10^ DGE/mo
0
-
0.84
11,848.5
(11,848.5)
(11,848.5)
-
-
1
1,769.4
0.87
1,531.8
684.5
777.9
69.4
69.4
(11,779.2)
222.8
147.4
2
3,910.6
0.89
3,487.1
1,565.2
1,385.7
536.2
536.2
(11,243.0)
492.5
325.9
3
3,333.3
0.92
3,061.4
1,378.9
1,265.0
417.6
417.6
(10,825.4)
419.8
277.8
4
3,658.1
0.95
3,460.6
1,575.2
1,397.0
488.4
488.4
(10,336.9)
460.7
304.8
5
4,313.7
0.97
4,203.2
1,871.6
1,634.5
697.1
697.1
(9,639.8)
543.2
359.5
6
2,721.5
1.00
2,731.3
1,223.5
1,194.3
313.5
313.5
(9,326.3)
342.7
226.8
7
2,342.0
1.03
2,420.9
1,076.2
1,110.1
234.7
234.7
(9,091.6)
294.9
195.2
8
2,668.1
1.06
2,840.8
1,252.4
1,249.6
338.7
338.7
(8,752.8)
336.0
222.3
9
3,189.8
1.10
3,498.2
1,561.4
1,462.3
474.5
474.5
(8,278.3)
401.7
265.8
10
2,635.2
1.13
2,976.7
1,336.4
1,314.4
326.0
326.0
(7,952.3)
331.9
219.6
11-30
50,465.5
73,994.4
32,960.8
33,081.3
7,952.3
7,952.3
6,355.2
4,205.5
Total
81,007.1
1.29 | 104,206.5
46,486.0
45,872.1
11,848.5 11,848.5
(0.0)
10,201.3
412.1
Present Value Table
Economic Parameters
Net
Internal Rate of Return
0.0%
Discount
Present
Payback Year
22.0
Rate
Value
Net Income / Net Capital
1.0
10%
-
(7,885.9)
15%
-
(9,164.1)
20%
-
(9,877.3)
25%
-
(10,313.1)
30%
-
(10,601.3)
Figure 50: CNG Project Cash Flow for Case 4 (4 wells per panel; 5 years pre-drainage)
Page 71
-------
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Yilmaz, M. (2010). The Hydrogeological Report ofAmasra Harccoal Basin.
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