coal mine methane and coalbed methane development in the ...

COAL MINE METHANE AND COALBED METHANE 

DEVELOPMENT IN THE DONETSK REGION, 

UKRAINE 

Prepared for: 

Donetsk Regional Administration 

and 

U.S. Trade and Development Agency 

Prepared by: 

Advanced Resources International, Inc. 

Arlington, VA USA 

In association with: 

Ecometan; Donetsk Geological Company; 

Bazhanov Mine and South Donbass #3 Mine; 

May, 2008 

This report was funded by the U.S. Trade and Development Agency (USTDA), 

an agency of the U.S. Government. The opinions, findings, conclusions, or 

recommendations expressed in this document are those of the author(s) and do not necessarily 

represent the official position or policies of USTDA. USTDA makes no representation about, 

nor does it accept responsibility for, the accuracy or completeness of the information contained 

in this report. 

Mailing and Delivery Address: 1000 Wilson Boulevard, Suite 1600, Arlington, VA 22209-3901 

Phone: 703–875–4357 • Fax: 703–875–4009 • Web site: www.tda.gov • email: info@tda.gov

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The U.S. Trade and Development Agency (USTDA) 

advances economic development and U.S. commercial 

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agency funds various forms of technical assistance, 

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gives emphasis to economic sectors that may benefit from 

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Mailing and Delivery Address: 1000 Wilson Boulevard, Suite 1600, Arlington, VA 22209-3901 

Phone: 703–875–4357 • Fax: 703–875–4009 • Web site: www.tda.gov • email: info@tda.gov

Coal Mine Methane And Coalbed Methane 

Development In The Donetsk Region, Ukraine 

CONTENTS 

TASK 1 

CMM/CBM Degasification and Production Concept ..................................................................1-1 

TASK 2 

Screen Applicable Technologies – Drilling, Completion and Stimulation Design.......................2-1 

TASK 3 

Market Assessment for Produced Methane...............................................................................3-1 

TASK 4 

Preliminary Design for CMM and CBM Utilization Infrastructure ...............................................4-1 

TASK 5 

Preliminary Environmental Assessment ....................................................................................5-1 

TASK 6 

Final Cost Estimates and Economic Assessments....................................................................6-1 

TASK 7 

Project Finance and Carbon Credits..........................................................................................7-1 

TASK 8 

Developmental Impact ...............................................................................................................8-1 

i Advanced Resources International

Unit Abbreviations 

o 

C degrees Celsius 

o 

F degrees Fahrenheit 

$ United States Dollar 

$/hp dollars per horsepower 

$/in.-mi dollars per inch mile 

$/w/mo dollars per well per month 

Bcf billion (10 9 ) standard cubic feet 

Bcfd billion (10 9 ) standard cubic feet per 

day 

Bmt billion (10 9 ) metric tons 

bpd barrels per day 

Btu British thermal unit 

cc cubic centimeter 

CK matrix differential swelling factor 

cP centipoise 

D day 

dB decibel 

ft feet 

g gram 

GJ gigajoule (10 9 J) 

ha hectare 

hp horsepower 

hr hour 

in. inch 

J joule 

K permeability 

kg kilogram 

km kilometer (10 3 m) 



ABBREVIATIONS 

km 2 square kilometer 

kPa kilopascal (10 3 Pa) 

kW kilowatt (10 3 W) 

lb pound 

m meter 

m 3 cubic meter 

Ma megaannum (million years ago) 

Mcf thousand (10 3 ) standard cubic feet 

Mcfd thousand (10 3 ) standard cubic feet 

per day 

md millidarcy (10 -3 D) 

mg/L milligrams per liter 

mi mile 

MJ megajoule (10 6 J) 

mm millimeter (10 -3 m) 

MMcf million (10 6 ) standard cubic feet 

MPa megapascal (10 6 Pa) 

MW megawatt (10 6 W) 

MWh megawatt hour 

ppm parts per million 

psi(a) pounds per square inch (absolute) 

S skin 

scf standard cubic feet 

Tcf trillion (10 12 ) standard cubic feet 

Tcm trillion (10 12 ) cubic meter 

TJ terajoule (10 12 J) 

yr year 

ii Advanced Resources International

Other Abbreviations 

ARI Advanced Resources International, 

Inc. 

BAT Best Available 

Techniques/Technology 

BLM U.S. Bureau of Land Management 

BMP Best Management Practices 

Ca Calcium 

CBM Coalbed Methane 

CCGT Combined Cycle Gas Turbine 

CCP Carbon Capture Project 

CCS Carbon Capture and Storage 

CDM Clean Development Mechanism 

CER Certified Emission Reduction 

CH4 Methane 

Cl Chlorine 

CMM Coal Mine Methane 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

CO2eq CO2 Equivalent 

CSLF Carbon Sequestration Leadership 

Forum 

CTL Coal to Liquids 

DOE U.S. Department of Energy 

E&P Exploration and Production 

E.U. European Union 

ECBM Enhanced Coalbed Methane 

EGR Enhanced Gas Recovery 

EIA Environmental Impact Assessment or 

Energy Information Administration 

EIS Environmental Impact Statement 

EOR Enhanced Oil Recovery 

EPA U.S. Environmental Protection 

Agency 

ER Emission Reduction 

ETS Emissions Trading Scheme 

GHG Greenhouse Gas 

GIP Gas in Place 



GWP Global Warming Potential 

H2O Water 

H2S Hydrogen Sulfide 

HC Hydrocarbons 

HCO3 Bicarbonate 

HDPE High Density Polyethylene 

IAPs Interested and Affected Parties 

ID Inner Diameter 

IOGCC Interstate Oil and Gas Compact 

Commission 

IPCC Intergovernmental Panel on Climate 

Change 

IRR Internal Rate of Return 

MAC Multistakeholder Advisory Committee 

MDEA Methyldiethanolamine 

Mg Magnesium 

MMV Measurement, Monitoring, and 

Verification 

MPDS Maximum Practical Drilling Schedule 

N2O Nitrous Oxide 

Na Sodium 

NEPA National Environmental Policy Act 

NETL National Energy Technology 

Laboratory 

NGO Non-Governmental Organization 

NMVOCS Non-Methane Volatile Organic 

Compounds 

Nox Nitrogen Oxide 

NSCR Non-Selective Catalyst Reduction 

O3 Ozone 

OD Outer Diameter 

PEIA Preliminary Environmental Impact 

Assessment 

PM10 Particulate matter 10 microns and 

smaller 

PM2.5 Particulate matter 2.5 microns and 

smaller 

PRB Powder River Basin 

iii Advanced Resources International

RIS Regulatory Impact Statement 

RO Reverse Osmosis 

ROW Right of Way 

RST Reservoir Saturation Tool 

SAR Sodium Adsorption Ratio 

SOx Sulfur Oxide 

SRCCS Special Report on Carbon Capture 

and Storage 

TDS Total Dissolved Solids 

TEG Triethylene Glycol 

TOC Total Organic Content 

ToR Terms of Reference 



U.S. United States of America 

UIC Underground Injection Control 

USDW Underground Source of Drinking 

Water 

VL Langmuir Volume 

VOC Volatile Organic Compound 

VP Langmuir Pressure 

VSP Vertical Seismic Profile 

WHO World Health Organization 

WRI World Resources Institute 

iv Advanced Resources International

Conversions 



Except where stated, all references to coal/shale are in short tons (tons), and all references to CO2 are in 

metric tons (tonnes). 

Mass 

1 short ton (ton) = 907.1847 kilograms (kg) 

1 metric ton (tonne) = 1000 kilograms (kg) = 2204.623 pounds (lb) 

Volume 

1 cubic meter (m 3 ) = 35.3 cubic feet (ft 3 ) 

1 thousand cubic feet (Mcf) = 28.32 cubic meters (m 3 ) 

1 cubic meter (m 3 ) = 6.2898 petroleum barrels (bbl) 

1 cubic foot (ft 3 )= 7.48052 gallons (gal) 

Length / Area 

1 inch (in) = 2.54 centimeters (10 -2 m or cm) 

1 foot (ft) = 0.3048 meters (m) 

1 mile (mi) = 1609.344 meters (m) 

1 acre = 0.4047 hectare (ha) 

Pressure 

1 pound per square inch (psi) = 6.894757 kilo-Pascals (10 3 Pa or kPa) 

1 mega-Pascal (10 6 Pa or MPa) = 145.0377 pounds per square inch (psi) 

Temperature 

1 degrees Fahrenheit ( o F) = 1.8 (degrees C) + 32 

1 degrees Celsius ( o C) = (degrees F – 32)/1.8 

Density 

19.26 thousand cubic feet (Mcf) CO2 = 1 metric ton (tonne) CO2 

0.6800 kilogram (kg) CH4 = 1 cubic meter (M 3 ) CH4 

Energy 

1 million Btu (10 6 Btu) = 1.055056 giga-Joules (10 9 J or GJ) 

1.0425 thousand cubic feet (Mcf) CH4 = 1 giga-Joule (10 9 J or GJ) 

0.0288 cubic meters (m 3 ) CH4 = 1 giga-Joule (10 9 J or GJ) 

1kilowatt (kW) = 1.341022 horsepower (hp) 

1 kilowatt-hour (kWh) = 3.6 mega-Joule (10 6 J or MJ) 

266 megawatt (MW) = 1 million cubic feet (MMcf) CH4 

0.2778 megawatt-hour (MWh) = 1 giga-Joule (10 9 J or GJ) 

v Advanced Resources International

Task 1 



CMM/CBM Degasification and Production 

Concept 

Advanced Resources International



TASK 1 CONTENTS 

Task 1 - Section 1 Geologic Assessment and Estimate 

of the CMM/CBM Resource Base..............................................1-i 

1.1 Introduction......................................................................................................................1-1 

1.2 Regional Geology ............................................................................................................1-1 

1.3 Coal Geology of the Donbass Coalfield ......................................................................1-10 

1.4 Estimate of Methane Reserves in the Donbass Basin ...............................................1-13 

1.5 Methane in Associated Strata.......................................................................................1-15 

1.6 Coal Mine Methane Project Areas ................................................................................1-17 

1.7 Coalbed Methane Project Areas...................................................................................1-36 

Task 1 - Section 2 Reservoir Simulations ...............................................................2-i 

2.1 Introduction......................................................................................................................2-1 

2.2 CBM Reservoir Modeling ................................................................................................2-2 

2.3 CMM Reservoir Modeling..............................................................................................2-17 


Task 1 Summary 



Task 1 is split into two sections. The first section comprises a geologic assessment of the 

study areas, along with an estimate of the coal bed methane (CBM) and coal mine methane 

(CMM) resources of those areas. Section two details the process of performing thirty-year 

gas and water production simulations, for the two CBM leases, using COMET3, Advanced 

Resources' proprietary reservoir simulator. Estimates of potential gas and water flows were 

made from the resultant production curves. 

Under the original terms of reference (TOR), task 1 calls for a comprehensive CBM 

development plan. This was considered too broad a subject to include in one task and 

appeared to repeat large sections of other tasks. The sections reviewing the development 

plans for drilling, dewatering, gas collection, compression and transmission infrastructure can 

be found in task 2 and task 4. 





Task 1 - Section 1 



Geologic Assessment and Estimate of the 

CMM/CBM Resource Base 

Geologic Assessment and CMM/CBM Resource Base Analysis 1-i



SECTION 1 CONTENTS 

1.1 Introduction......................................................................................................................1-1 

1.2 Regional Geology ............................................................................................................1-1 

1.2.1 Regional Stratigraphy................................................................................................1-4 

1.2.2 Regional Tectonics....................................................................................................1-7 

1.3 Coal Geology of the Donbass Coalfield ......................................................................1-10 

1.4 Estimate of Methane Reserves in the Donbass Basin ...............................................1-13 

1.5 Methane in Associated Strata.......................................................................................1-15 

1.6 Coal Mine Methane Project Areas ................................................................................1-17 

1.6.1 Yuzhno-Donbasskaya #3 Mine................................................................................1-17 

1.6.1.1 Geology..........................................................................................................................1-17 

1.6.1.2 Coal Geology and Properties.........................................................................................1-18 

1.6.1.3 Coal Reserves................................................................................................................1-19 

1.6.1.4 Coal Properties ..............................................................................................................1-19 

1.6.1.5 Gas Properties ...............................................................................................................1-22 

1.6.1.6 Mine Degassing .............................................................................................................1-23 

1.6.1.7 Gas In-Place ..................................................................................................................1-24 

1.6.1.8 Estimation of Gas Reserves ..........................................................................................1-27 

1.6.2 Bazhanov Mine........................................................................................................1-29 

1.6.2.1 Geologic Structure .........................................................................................................1-29 

1.6.2.2 Coal Geology and Properties.........................................................................................1-32 

1.6.2.3 CMM Gas Composition..................................................................................................1-33 

1.6.2.4 Mine Degassing .............................................................................................................1-34 

1.6.2.5 Estimation of Gas-In-Place. ...........................................................................................1-35 

1.7 Coalbed Methane Project Areas...................................................................................1-36 

1.7.1 Grishino Andreyevskaya Area .................................................................................1-36 

1.7.1.1 Methane Reserves Estimates ........................................................................................1-36 

1.7.2 South Donbass CBM Development Area – ECOMETAN........................................1-39 

1.7.2.1 Geology..........................................................................................................................1-39 

1.7.2.2 Methane Reserves Estimate..........................................................................................1-39 

Geologic Assessment and CMM/CBM Resource Base Analysis 1-i



SECTION 1 EXHIBITS 

Exhibit 1.1 Map of Donetsk Region showing CBM Lease Areas and CMM Mines .............................1-2 

Exhibit 1.2 Location of the study area and geologic sketch map of the Donetsk Basin (from R.F. 

Sachsenhofer et al., 2002). ...............................................................................................1-3 

Exhibit 1.3 Stratigraphic column of the Dnieper-Donetsk Basin..........................................................1-5 

Exhibit 1.4 Detailed Structure Map of the Donetsk Basin ...................................................................1-9 

Exhibit 1.5 Expanded Stratigraphic Section of the Carboniferous Coal-Bearing Sequence.............1-11 

Exhibit 1.6 Coal Districts of the Donetsk Region...............................................................................1-12 

Exhibit 1.7 Estimated Total Methane In Place of the 10 Principal Mining Districts in Ukraine..........1-14 

Exhibit 1.8 Methane Reserve Concentrations in the Donbass Region .............................................1-15 

Exhibit 1.9 Coal Classification Equivalents .......................................................................................1-16 

Exhibit 1.10 Lithologic Composition of the Coal Bearing Sequence ...................................................1-19 

Exhibit 1.11 Coal Thickness, Yuzhno-Donbasskaya #3 Mine.............................................................1-20 

Exhibit 1.12 Ash Content, Yuzhno-Donbasskaya #3 Mine..................................................................1-21 

Exhibit 1.13 Sulfur and Phosphorus Content, Yuzhno-Donbasskaya #3 Mine ...................................1-21 

Exhibit 1.14 Coal Petrography, Yuzhno-Donbasskaya #3 Mine .........................................................1-22 

Exhibit 1.15 Thermal Maturity, Yuzhno-Donbasskaya #3 Mine ..........................................................1-22 

Exhibit 1.16 Gas Composition, Yuzhno-Donbasskaya #3 Mine..........................................................1-23 

Exhibit 1.17 Gas-in-Place for Specific Depths, Yuzhno-Donbasskaya #3 Mine .................................1-24 

Exhibit 1.18 Gas-in-Place of Individual Coal Beds of Yuzhno-Donbasskaya #3 Mine........................1-26 

Exhibit 1.19 Coal Production and Methane Emissions of Yuzhno-Donbasskaya #3 Mine .................1-27 

Exhibit 1.20 Coal Production and Methane Emissions at Yuzhno-Donbasskaya #3 Mine from Coal 

Seam C11 only..................................................................................................................1-28 

Exhibit 1.21 Summary Table of Fault Systems of the Bazhanov Mine ...............................................1-31 

Exhibit 1.22 Gas Composition According to Depth, Bazhanov Mine ..................................................1-33 

Exhibit 1.23 Coal Production and Methane Emissions - Bazhanov mine (2004-2005).......................1-34 

Exhibit 1.24 Coal Bed Methane Resource Estimates - Bazhanov Mine .............................................1-35 

Exhibit 1.25 The Grishino-Andreyevskaya CBM Lease Area..............................................................1-37 

Exhibit 1.26 Estimated Methane Reserves of the Grishino-Andreyevskaya Area ..............................1-38 

Exhibit 1.27 The South Donbass CBM Lease Area ............................................................................1-40 

Exhibit 1.28 Estimated Gas Reserves of the South Donbass CBM lease ..........................................1-41 

Geologic Assessment and CMM/CBM Resource Base Analysis 1-ii

1.1 Introduction 



Four separate areas are considered in this study for coal mine/coalbed methane 

(CMM/CBM) development. Two of the areas are active mine sites, the Bazhanov and the 

Yuzhno-Donbasskaya #3 mines, where CMM projects will be conducted. The remaining two 

areas are coalbed methane lease areas, one of which is held by Ecometan and the other by 

the Donetskgeologiya Company (Exhibit 1.1). This section of the report presents a general 

geologic overview of the Donbass Basin, followed by more detailed geologic and CMM/CBM 

resource assessments of the four individual areas studied. In addition to the CMM/CBM 

resources, an estimate of the amount of methane contained within the interbedded 

sandstones is also provided, as these resources are considerable and will be produced in 

conjunction with CMM/CBM. 

Geologic information for this portion of the study was supplied principally by the State 

Department of the Coal Industry of the Ministry of Fuel and Energy of Ukraine, the 

Donetskgeologiya Company, Ecometan, the Yuzhno-Donbasskaya #3 (South Donbass #3) 

and Bazhanov Mine technical staff, and U.S. Environmental Protection Agency (USEPA) and 

U.S. Geological Survey (USGS) publications. 

1.2 Regional Geology 

The Donbass Basin is the southeastern segment of the Dniepr–Donetsk Basin, a Late 

Devonian rift structure located on the southern part of the Eastern European craton (Exhibit 

1.2). The Dniepr–Donetsk Basin continues westward into the relatively shallow Pripyat 

Trough and eastward into the Karpinsky Swell encompassing a 60,000 km 2 area. The 

basement is formed by crystalline rocks of the Eastern European craton and is 

unconformably overlain by middle Devonian to Carboniferous sediments that reach a 

thickness of more than 20 km 1 . 

1 (Chekunov et al.. 1993). 

Geologic Assessment and CMM/CBM Resource Base Analysis 1-1



Exhibit 1.1 Map of Donetsk Region showing CBM Lease Areas and CMM Mines 




Exhibit 1.2 Location of the study area and geologic sketch map of the Donetsk Basin (from R.F. Sachsenhofer et al., 2002). 


1.2.1 Regional Stratigraphy 



The stratigraphy of the Dniepr-Donetsk Basin spans the Devonian to Cenozoic/ Miocene and 

is complex and variable by region (Exhibit 1.3). The basement of the Dniper- Donetsk basin 

is gneisses, granites, crystalline shales, amphibolites, and metavolcanogenic-sedimentary 

rocks of Archean and Lower Proterozoic. 

The earliest basin fill is a complex of volcanogenic and terrigenous formations with a total 

thickness of 4-5+ km of Devonian Frasnian and Famennian stages. The Frasnian stage is 

represented by three substages. Its basal part is expressed by mottled terrigenous deposits 

(alternating quartz sandstones and aleurolites with argillites). The middle part of the stage is 

15 to 120 m thick, composed principally of limestones and dolomites. The upper part 

represents the thickest package, up to 3 km or more, and is comprised of volcanogenic, 

volcanogenic-sedimentary and salt-bearing deposits. 

The Famennian stage, whose sediments unconformably lie on the Frasnian formations, is 

divided into two parts. The Lower Famennian substage is present only in localized paleodepressions 

and is composed of clay-carbonate and terrigenous deposits up to 3,500 m in 

thickness. The Upper Famennian substage is a transitional complex from Devonian to 

Carboniferous sediments. It is a thick (to 3 to 4 km) formation which includes salt-bearing 

grey and red-colored terrigenous sediments and volcanogenic deposits. 

Carboniferous deposits are present throughout the Dniper-Donetsk Basin. Paleontological 

data has made it possible to classify the section into stages, substages, and horizons. In 

contrast to the Devonian sequence, the thickness of Carboniferous section increases from 

the edges to the basin center and towards the south-eastern region, reaching 10 km thick 

and more as shown by seismic data. Formations of the Tournaisian stage and Lower Visean 

substage are established only in the graben limits. The lithological composition of the 

Carboniferous rocks is relatively uniform and lateral changes of facial and material 

composition of the section take place gradually. 

The deposits of the lower Carboniferous are represented by the Tournaisian, Visean, and 

Serpukhovian stages. The Tournaisian stage or Donetsk zones C1tb-C1td in the central and 

south-eastern parts of the depression is composed of terrigenous-carbonate marine 

formations. They are littoral-shelf carbonates with bioherms, biostromes, and barrier-reef 

massifs. 




Exhibit 1.3 Stratigraphic column of the Dnieper-Donetsk Basin 




The Visean stage, unconformably lies over Tournaisian and Upper Devonian deposits. They 

are comprised of marine terrigenous-carbonate deposits ranging from 100 to 300 m thick. 

The sediments of Upper Visean substage are present in nearly all the parts of the basin. In 

the center of the basin, their thickness reaches 800 to 1,000 m and more. The upper part of 

the section is a marine to alluvial deltaic system of aleurolites and sandstones interbedded 

with minor coal. In the deepest part of the basin, the coal interbeds disappear and grade into 

shale. 

The sediments of Serpukhovian stage lie conformably over the Upper Visean deposits. At the 

edge of the north-western portion of the basin, thickness varies from 50 to 150 m and to the 

southeast it increases to 1,500 to 2,000 m. The Serpukhovian is comprised of argillites with 

interbeds of occasional coal. 

Middle Carboniferous deposits of this section are present in Bashkirian and Moskovian 

stages. Their thickness from the edge of the basin to the axial depression zone increases in 

a uniform manner and also in the direction of the Donbass region. They resemble upper 

Visean and Serpukhovian formations in that they are dominated by fluvial marine deltaic 

sequences. The sediments of Bashkirian stage are regionally unconformable over the 

different horizons of Serpukhovian and Visean stages and in some places along the southern 

edge lie directly upon Precambrian basement. 

The lower Bashkirian substage includes a small group of sandstone and shale deposits 

overlapped with marine shaley limestones with a thickness of between 50 to 400 m. The 

upper Bashkirian is represented with cyclic, alluvial-deltaic and lagoon deposits of 

interbedded of sandstones and clays with carbonate and coal beds. Its thickness varies from 

100 to 1,500m. The shallow marine limestone layers repeat at regular intervals and may rest 

directly on top of coal seams. The Moskovian stage continues with an alluvial deltaic and 

lagoonal facies characterized by interbedded sandstones, shale, and coal. The thickness of 

this stage ranges from 150m up to 1,800m. 

The lower Serpukhonvian and the Moskovian successions are especially rich in coal 2 and 

compose the majority of the mineable coal seams in the Donbass Basin. The coal seams in 

these successions form the main focus of this report and their geology is discussed in more 

detail in Section 1.3. 

2 rd 

Geologic Controls on Coalbed Occurrence in the Donets Basin, Privalov, Zhykalyak and Panova, 3 International Methane & 

Nitrous Oxide Conference, Beijing, China. Sept.2003 




The Upper Carboniferous sequence conformably overlies the Middle Carboniferous 

sequence and is most complete in the south-eastern portions of the basin. Comprised of 

alluvial-deltaic formations with thickness 150 to 1,500 m, they are represented by alternating 

beds of sandstones and argillites with occasional carbonate beds. In contrast to the Middle 

Carboniferous sequence, the coal beds are thin or absent in the Upper Carboniferous 

formation, with the exclusion of suite C13 of the south-eastern region of the basin. 

In comparison with Carboniferous deposits, Permian deposits are less ubiquitous and have a 

less complete section. Despite their great thickness in the paleodepressions, Permian 

sediments are present only in the Asselian stage and the lower parts of Sakmarian stage. 

The thickness of Permian deposits ranges from 10 to 100 m on the northwest margin of the 

paleodepression to 2,500 to 2,700 m in the south-east in the central part of the Orchykivka 

depression. 

Triassic through Jurassic sediments sit unconformably on the Permian and Carboniferous 

formations. Primarily comprised of terrestrial deposits, the Jurassic also includes several 

marine carbonate units. 

Overlying the Jurassic system, sedimentary formations include Lower Cretaceous continental 

terrigenous deposits (up to 160 m thick), an Upper Cretaceous marine marl-carbonate (up to 

800 m thick), a Paleogene marine carbonate-silliceous-terrigenous deposit (up to 400 m 

thick), and Neogene-Quaternary terrigenous (up to 100 m thick) deposits. 

1.2.2 Regional Tectonics 

Among the paleorift structures in Eastern Europe, the Donbass Basin is the most anomalous 

segment in the Dnieper-Donetsk Basin, as it is unique in its prominent inversion of the 24 km 

thick sedimentary column by the Donbass Foldbelt (Exhibit 1.4). The foldbelt is comprised of 

WNW–ESE-striking anticlines and synclines. Major thrusts occur along the northern margin 

of the basin. Minor folds, reverse faults and rotated fault blocks occur along the southern 

boundary of the basin. The age of the compressional structures is a matter of debate; some 

consider a Permian age while others deem it to be late Cretaceous (Alpine) in age. 

The southwestern part of the Donbass Basin comprises the Krasnoarmeisk Monocline and 

the Kalmius–Torets Depression. The northeastward-dipping rocks of the Krasnoarmeisk 

Monocline parallel the Mariupol– Kursk Lineament. Towards the east, the Krasnoarmeisk 

area grades into the Kalmius–Torets Depression and represents the intersection of the 




northwestern continuation of the SE-trending South Syncline with the SW-trending 

Voltchansk synform. The eastern margin of the Kalmius–Torets Depression is located near 

Donetsk and Makeevka. 

A significant tectonic element of intrabasional architecture is WNW-ESE trending principal 

displacement zone (PDZ) consisting of a set of dextrally en echelon arranged deep 

basement faults with faults superimposed on depressions (pull-apart basins) in the 

basement. During the post-rift stage, strike-slip pulses within PDZs affected local 

depositional environments in the vicinity of the pull-apart basins and influenced on 

depositional trends across the entire basin. Major post-rift subsidence occurred during the 

Carboniferous. 

In contrast with adjacent rift sectors, the Donetsk Basin had extensive coal-forming 

environments during the interval between 290-340 Ma, periodically triggered by the interplay 

of PDZ strike-slip motions and variable rotations of the Donbass megablock. This caused 

recurrence from swampy coastal-marine plains with huge peatbogs to shallow sea 

environments and resulted in accumulation of thick (up to 14 km), paralic coal-bearing 

Carboniferous (post- Early Visean) formations containing more than 300 coal seams and 

layers. 




Exhibit 1.4 Detailed Structure Map of the Donetsk Basin 




1.3 Coal Geology of the Donbass Coalfield 

The coal-bearing series at the base of the Carboniferous sequence thins along the southwest 

edge of the Donbass flexure and the mineable coal seams are contained in an interval 

that is 400 to 500m thick. The beds are located close to one another, generally 3 to 20m 

apart. 

The middle Carboniferous and its coal seams are widespread over the Donbass region. The 

main feature of this unit is a gradual decline in the mineability of the coal seams and general 

coal-bearing series moving from the west to the east, as well as to the north. The highest 

concentration of coal seams in the C2 6 suite is found in the western parts of the basin. The 

section is 170 to 250m thick and includes up to 8 mineable layers. The upper part of the C2 5 

section is similar in nature. The total thickness of coal-bearing interval in the middle 

Carboniferous seams (C2 3 – C2 7 suites) is 1,500 to 3,000m (Exhibit 1.5). 

The total number of coal seams that are included in the Carboniferous section is about 330, 

two-thirds of which are not more than 0.45m thick. Only 130 seams are more than 0.45m 

thick. The typical thickness of individual coal seams is 0.6 to 0.8m. The presence of seams 

more than 2m thick is quite rare. There are 27 mineable seams in the middle Carboniferous 

section and 8 mineable seams in the Lower Carboniferous. The upper Carboniferous section 

has only one mineable coal seam. The coal-bearing series is irregular in thickness and 

lateral extent across the basin. The Donbass coal field has been divided into 30 coal districts 

for administrative purposes (Exhibit 1.6). 

Coal reserves of coal seams greater than 0.3m thick are 231 billion tons, for seams at depths 

of between 500 to 1,800m. All ranks of coal are found in the basin, ranging from brown coal 

to anthracite. 




Exhibit 1.5 Expanded Stratigraphic Section of the Carboniferous Coal-Bearing Sequence 




Exhibit 1.6 Coal Districts of the Donetsk Region 




1.4 Estimate of Methane Reserves in the Donbass Basin 

The thermal maturation of coal deposits in the Donbass coalfield was accompanied by the 

generation of huge quantities of methane. The amount of gas is estimated to be up to 117 

trillion m 3 (4,100 Tcf), and is thought to be one of the largest onshore gas resources in the 

world. The peculiarities of the distribution of hydrocarbon gases in Donbass are closely 

connected with specific geological conditions of gas formation that were much affected by 

different chemical, biological and tectonic factors, that occurred at different periods of time 

and in different areas. 3 

Gas-bearing areas in the Donbass Basin were formed during times of tectonic activity which 

began with inversion. A complex nature of inversion and denudation of coal seams caused 

gas migration that dominated over the gas generation processes and thus led to intensive 

gas redistribution in and changes to existing gas-bearing formations and, finally, to 

transforming it into the two current distinct patterns of vertical and areal distribution of gas in 

the formations 4 . These events, and resulting distribution of methane within the structure, are 

shared throughout many of the Carboniferous coal basins of Eastern Europe, including 

Poland and the Czech Republic. 

The amplitude of movements during the inversion process was from 4 to 11 km, with the 

coal-bearing strata exposed to shallow burial conditions. At that point, some gas was lost 

and areas of undersaturation with respect to gas were formed in the upper part of the 

section. The composition of the coal seams’ gas consists of methane, but can also contain 

some ethane, propane, nitrogen and carbon dioxide. 

Heavier hydrocarbons are mainly contained in coal seams of medium to low volatile rank. 

The gas contained in highly metamorphized anthracites and meta-anthracites mainly 

consists of nitrogen and carbon dioxide with only a small amount of methane. Coal seams 

also contain trace amounts of butane, pentane, hexane, heptane, hydrogen, helium, argon, 

neon, krypton and xenon. 

The absorptive capacity of coal increases with rank and can reach up to 20 to 25 m 3 /t of dry 

basis for high to medium volatile coals and up to 40 to 45 m 3 /t on a dry basis for higher rank 

coal. 

3 

V. Zaydenvarg, A. Ayruni, R. Glazov, A. Brizhanyov, Y. Petrova, “Complex Approaches to Methane Deposits”, Moscow, 

CNIEIUUgol, 1993 

4 

A. Brizhanyov, R. Glazov, “Specific Features of Methane Accumulations in Donetsk Basin”, Moscow, CNIEIUUgol 1987, edition 6. 




According to published estimates, the total methane resources contained in coal seams of 

0.3m or greater in thickness and located at depths between 500 to 1,800m are estimated to 

be 1,164 to 2,500 billion m 3 . Considering only the principal geologic/industrial districts, the 

methane resource is estimated to be approximately 855 billion m 3 . 5,6 as referenced in 

Exhibit 1.7. 

Geology Area 

Number of Coal Seams 

Under Analysis 

Content of Methane in Coal 

Seams, Billion m 3 

Krasnoarmeysk 33 231.5 

Donetsk-Makeyevka 59 202.1 

Central 46 84.8 

Torez-Snezhnoye 39 37.5 

Lisichnsk 25 37.5 

Lugansk 39 47.5 

Almazny-Mariyevsky 53 81.2 

Krasnodonsky 24 56.2 

Bokovo-Kyrustalsky 31 40.1 

Seleznyovsky 32 51.9 

Total: 855.3 

Exhibit 1.7 Estimated Total Methane In Place of the 10 Principal Mining Districts in Ukraine 

The concentration of the CBM resource in the SW Donbass Region is relatively high 

compared to U.S. basins, with concentrations ranging from 90 to 107 billion m 3 /km 2 . These 

estimates were made by the Donetskgeologiya Company and Raven Ridge Resources, Inc. 

(USA) (Exhibit 1.8). 

5 

B. Kosenko, “Methane Reserves of Coal Seams of Donbass”, Ukraine Coal 1980, #12. 

6 

V. Zaydenvarg, A. Ayruni, R. Glazov, A. Brizhanyov, Y. Petrova, “Complex Approaches to Methane Deposits”, Moscow, 

CNIEIUUgol, 1993 


Prospective Area 

Dobropolsk- 

Krasnoarmeys 



Area Size 

Estimate of 

Donetskgeologiya Company 

Km 2 Reserves 

Billion m 3 

Concentration 

Million m 3 /km 2 

Estimate of Raven Ridge 

Resources, Inc. (USA) 

Reserves 

Billion m 3 

Concentration 

Million m 3 /km 2 

963 76.4 79.3 101.0 104.9 

Grishino-Andreyevskaya 557 18.2 32.7 29.7 53.3 

Yuzhno-Donbass 530 57.2 107.9 58.5 110.4 

Donetsk 293 44.5 151.9 46.5 158.7 

Makeyevskaya 246 35.9 145.9 42.0 170.7 

TOTAL 2,589 232.2 89.7 277.7 107.3 

Exhibit 1.8 Methane Reserve Concentrations in the Donbass Region 

1.5 Methane in Associated Strata 

For both CMM and CBM recovery projects, the methane contained within the non-coal 

interbeds can represent a significant source of additional methane beyond the targeted coal 

seams. Therefore, it is important to consider these sources when assessing resource 

potential as well as in the development of the extraction programs. 

The current gas distribution in Donbass Basin coal seams is strongly influenced by the 

nature of the adjoining strata. Due to catagenesis, the porosity and permeability of adjacent 

sandstones has been decreased. However, natural fractures have enhanced permeability in 

the same sandstones, similar to tight gas sands in the U.S. Gas prone areas in the Donbass 

are divided into three main zones based on the vertical and areal distribution of the gas 

resource, the reservoir properties of adjoining strata, and the producible reserves. 7 , 8 , 9 , 10 

The first zone occurs in Carboniferous sediments that include coal seams ranked as long 

flame coal, gas coal and some fat coals (Exhibit 1.9). It is characterized by producible 

reserves and local gas accumulations that are connected to porous and fractured gas 

reservoirs, mainly tight gas sands. Traditionally, coal seams of South and West Donbass, 

Lisichansk, Krasnoarmeysk, Millerovsky, the Bakhmutskaya and Kalmius-Torez basins are 

included in the first zone. 

7 

A. Brizhanyov, R. Glazov, “Specific Features of Methane Accumulations in Donetsk Basin”, Moscow, 1987, edition 6. 

8 

A. Ayruni, R. Glazov, “Gas Content of Coal Mines in the USSR”, Moscow, Nedra, 1990. 

9 

V. Zaydenvarg, A. Ayruni, R. Glazov, A. Brizhanyov, Y. Petrova, “Complex Approaches to Methane Deposits”, Moscow, 1993. 

10 

V. Pudak, V. Konarev, A. Alekseysev, A. Brizhanyov, ”Donbass Methane Deposits Research and Development”, Ukraine Coal, 

1996 No. 10-11. 




The second zone is defined by the areas containing coal seams ranked as fat, coking and 

lean-coking. It is characterized by producible reserves and local hydrocarbon accumulations 

that are connected to higher porosity and permeability reservoirs where the reservoirs are 

fractured. The zone’s distinctive feature is the high levels of gas content found in the coal 

seams and surrounding strata. 11 The Donetsk-Makeyevka, Central, Seleznyovsky, Almazno- 

Mariyevsky and Krasnodon geological/industrial areas of Donbass are usually included in 

this zone. 

The third zone is associated with Carboniferous strata that contain lean ranked coals and low 

ranked anthracites. Coal seams and surrounding rock strata of this zone are characterized 

by low porosity and permeability, which limits the accumulation of hydrocarbons to localized 

areas of fracturing and fissure. The Torez-Snezhnoye and Bokovo-Khrustalny geological 

areas are located in this zone. 

Ukrainian Coal Type US Coal Type 

Long Flame, Gas High volatile, sub-bituminous 

Fat, Coking Medium volatile, bituminous 

Lean, Lean-Coking Low volatile, bituminous 

Exhibit 1.9 Coal Classification Equivalents 

Outside of the three gas-bearing areas discussed above, there is a complete absence of 

gaseous hydrocarbon accumulations. These areas are located in zones of highly metamorphized, 

high-ranked anthracitic coal. Mines in this area are not gassy and include those 

in the central and eastern parts of Bokovo-Khrustalny and Torez-Snezhnoye basins as well 

as the whole territory of Dolzhano-Rovensky geological area. 

The total methane resource of non-coal strata in the Donbass Basin is between 9,820 to 

20,820 billion m 3 , including 982 to 3,374 billion m 3 of methane and 460 billion m 3 of solution 

gas. 12 According to Ukrainian geological survey data, there are more than 30 identified gas 

fields in the Donbass Basin with an in-place resource of 180 billion m 3 , of which one-third, 60 

billion m 3 , is classified as proven reserves 13 . 

11 Opportunities for production and investment in the Donetsk Coal Basin. PEER. Sept 2000 

12 A. Brizhanyov, R. Glazov, “Specific Features of Methane Accumulations in Donetsk Basin”, Moscow, CNIEIUUgol, 1987, edition 6. 

13 Opportunities for production and investment in the Donetsk Coal Basin. PEER. Sept 2000 




1.6 Coal Mine Methane Project Areas 

1.6.1 Yuzhno-Donbasskaya #3 Mine 

Yuzhno-Donbasskaya #3 Mine is located in the Mariynsky and Volnovakha districts (rayons) 

of the Donetsk Oblast, 50 km to the southwest of the oblast capital Donetsk (Exhibit 1.1). The 

nearest towns are Dobropolye and Ugledar (6 km to the south). The latter is a large mining 

town with a population of 20,000, most of them employees of Yuzhno-Donbasskaya #1 and 

#3 mines. 

The mine’s surface facilities are adjacent to the Uglesborochnaya railroad handling point, 

connecting to Yuzhno-Donbasskaya station through a nearby rail junction. The mine receives 

its electric power supply from Kurakhovskaya Power Plant that is situated 25 km north of the 

property. 

The Yuzhno-Donbasskaya #3 mine (South-Donbass) was put into operation in 1985 with 

capacity of 2.4 million tons. The mine covers an area of approximately 10 km by 5 km or 

about 50 km 2 . The total recoverable reserves of coal are approximately 158 million tons out 

of an estimated 192 million tons in-place. Currently, the mine produces from two coal-beds: 

the C11and C10 2 at a rate of approximately 1.2 million tons per year. 

1.6.1.1 Geology 

The Yuzhno-Donbasskaya #3 mine is located in the Kalmius–Torets Depression between the 

Slozhny, Dolinny, and Vladimirsky faults and covers most of the Shyrokaya syncline. The 

synclinal axis is traced in the central part of the mine with a plunge to the northeast. The 

northern limb dips to northwest direction, the southern one in a latitudinal direction. 

The axis of the Shyrokaya syncline intersects the Krivorozhsko-Pavlovsky fault at almost 90 

degrees and plunges to the southwest. The saddle is located 1500m from the fault and 

adjoins the borders of the mine field from the southwest. 

Given the intense regional tectonic events surrounding the mine, faulting is prominent in the 

area. The dip of the coal seams varies from 5-12°, increasing up to 40-70° in the fault zones. 

Often, the coals are intensely naturally fractured in the vicinity of the fault systems. In terms 

of their morphological features the faults near the mine can be divided into following 

subgroups: 

Regional thrust faults that strike West-Northwest, with primary dips to the Northeast 

(Krivorozhsko-Pavlovsky fault, Slozhny fault); 




High-angled faults that strike to Northwest-Southeast and dip southwest (Dolinny, 

Pridolinny, Vladimirsky, and Shevchenkovsky faults); 

High-angled faults which that strike North-South (related to the Mariupol– Kursk 

Lineament); 

The Krivorozhsko-Pavlovsky fault is the primary structural feature of the area. It is a natural 

border of the mine field located at the extreme southwest part of the coal field. The fault dips 

between 40 to 60° with a throw of approximately 1,000m. Near the fault, coals are naturally 

fractured and often crumble when removed from the core barrel. 

The Slozhny fault is a major antithetic fault of the main Krivorozhsko-Pavlovsky fault. In the 

northeast part of the mine area this system forms a wide zone of intense natural fracturing. 

The amount of fault throw reaches 150m in some areas of the fault. Further to the south its 

amplitude decreases to 15m and near to the Pavlovsky crest the amplitude flattens. 

Finally, there is a group of high-angle, discordant faults that strike southeast and dip 

southwest in the southern part of the mine field 

1.6.1.2 Coal Geology and Properties 

The South Donbass coal deposits are located in a strip along the southwest outskirts of the 

Donetsk basin that borders the Ukrainian crystalline massif. The coal-bearing series of the 

lowest coal sequence is stretched along the south-west side of the Donetsk flexure and the 

recoverable coal-seams are located in a 400 to 500 m thick section. 

Middle and upper Carboniferous coal series occur throughout the territory of Donbass. The 

main characteristic feature of the sequence is a gradual decrease in the number of coalseams 

moving from the west to the east, as well as to the north. 

The entire Carboniferous sequence contains about 130 workable coal seams that vary in 

thickness between 0.45 and 2.5 m, averaging about 0.9 m. The Donbass coals usually have 

high ash yields (12 to 18%) and high sulphur contents 2.5 to 3.5% (Panov, 1999). 

Lithologically, coal interbeds are represented by alternating layers of argillites, aleurolites and 

heterogeneously-grained sandstones with rare layers of limestone. (Exhibit 1.10) The 

overburden is comprised of Mesozoic chalk-like marls and siliceous rocks 70 to 130 m thick 

covered by an additional 30 to 50m of Cenozoic (principally Neogene) clays with sandstone 

stringers. 


Rock Type 



Percentage of Rock Types in the Carboniferous Sequence 

C1 2 C1 3 C1 4 C1 5 

Aleurolites 60-70 75 60 59 

Sandstones 16-17 12 22 20 

Argillites 11-20 11 16 18 

Limestones 1.5-2.0 0.5 1.6 2.2 

Coals 0.3 1.6 0.7 0.5 

Exhibit 1.10 Lithologic Composition of the Coal Bearing Sequence 

1.6.1.3 Coal Reserves 

The thickness of the coal-bearing strata in the mine areas between the top and bottom coalbeds 

is about 420m and contains more than 60 coal beds and interbeds. A summary of the 

coal seams present in the mine area is shown in Exhibit 1.11. 

There are three principal coal beds that are exploited in the mine. The C13 coal bed is one of 

the primary pays of the mine, being a widespread and uniform bed, ranging between 0.8- 

0.95m in thickness. Another primary coal bed is the C11, which has been intensively exploited 

since the initial operation of the mine. The total area worked to date of the C11 coal seam is 

about 4.5 km 2 . The C11 coal is not uniform, however, and is divided by an interbed of argillite. 

The net thickness of the coal ranges between 1.5 to 1.7m. The coal bed C10 2 is widespread 

as a single seam in the extreme eastern part of the mine covering 16 % of the area. The 

total area of working of the coal bed C10 2 is 65,000 m 2 . 

1.6.1.4 Coal Properties 

Data on petrographic and chemical characteristics of the coal mines at the Yuzhno- 

Donbasskaya #3 mine are shown in Exhibit 1.12, Exhibit 1.13, Exhibit 1.14 and Exhibit 1.15. 


Coalbed 

C18 

C13 

Cll B 

Cll 

Cll H 

C10 2 



Net Thickness m. 

From – To 

Average 

Total Recoverable 

0.55-1.0 

0.75 

0.55-1.25 

0.8 

0.55-1.04 

0.84 

0.99-1.88 

1.56 

0.6-0.94 

0.72 

0.65-1.38 

1.0 

C10 1 - 

C10 

C6 1 

C4 3 

C4 2 

C2 

C1 1 

B5 1 

- 

0.6-1.2 

0.97 

0.55-0.88 

0.61 

0.55-1.09 

0.85 

0.55-0.74 

0.59 

0.49-0.65 

0.57 

0.35-1.2 

0.84 

0.39-0.6 

0.51 

0.45-0.55 

0.51 

0.45-0.55 

0.5 

Distance 

between coalbeds. 

m. 

Estimated Extent % 

Total Recoverable 

35 from C5 36.7 37.7 

88 53.5 5.0 

13 29.2 1.1 

- - 51.0 - 

0.7-0.85 

0.81 

0.55-1.0 

0.71 

0.45-0.64 

0.5 

0.45-0.6 

0.49 

0.62-0.74 

0.68 

0.45-0.88 

0.49 

0.39-0.5 

0.47 

0.45-0.64 

0.52 

0.4-0.65 

0.51 

0.35-1.38 

0.57 

0.0-4.0 24.8 5.5 

15 16 6 

4 - 23 

6 - 25 

78 99.8 0.03 

53 8.5 14.0 

9 68 2.5 

57 11 42.5 

19 8 50 

93 20.5 2 

Exhibit 1.11 Coal Thickness, Yuzhno-Donbasskaya #3 Mine 


Coal bed 

C13 

C11 

C10 2 

C6 1 

Ash Content 

of Coal 

1.2 - 17.3 

5.3 

1.7 -19.7 

6.0 

1.5 -10.4 

4.2 

1.5 - 22.9 

5.6 



Parameters 

from – to 

average 

Ash Content Including 

Contaminants 

1.2 - 23.0 

5.6 

1.7 - 28.6 

6.9 

1.5 - 23.6 

5.0 

1.5 - 26.3 

5.8 

Operational Measure of contamination 

51.4 45.8 

19.6 - 25.3 

21.8 

Geologic Assessment and CMM/CBM Resource Base Analysis 1-21 

14.9 

40.9 35.9 

27.0 21.2 

Exhibit 1.12 Ash Content, Yuzhno-Donbasskaya #3 Mine 

Specific Sulfur % 

from – to 

average - value 

Coal Bed Total Sulfur % Sulphate (S04) Sulphite (S03) Organic (So) Phosphorus 

C13 

C11 

C10 2 

c/ 

1.1- 4.23 

1.99 

0.7 - 2.76 

1.26 

0.91-3.62 

2.04 

0.71- 3.48 

1.9 

0.0 - 0.09 

0.03 

0.01- 0.1 

0.02 

0.0 - 0.12 

0.04 

0.01- 0.21 

0.04 

0.4-3.51 

1.23 

0.1-1.94 

0.54 

0.20-1.8 

1.0 

0.1-2.43 

1.03 

0.4 -1.0 

0.72 

0.5 - 0.9 

0.70 

0.40 - 1.2 

0.88 

0.46 -1.3 

0.86 

Exhibit 1.13 Sulfur and Phosphorus Content, Yuzhno-Donbasskaya #3 Mine 

0.001- 0.145 

0.019 

0.003 - 0.035 

0.016 

0.001- 0.248 

0.008 

0.00 - 0.970 

0.019

Coal-bed 

C13 

C11 

C10 2 

C6 1 

Coal Bed 

C13 

C11 

C10 2 

C6 1 



Material composition %, 

Min – Max 

Average 

Vitrinite Semivitrinite Inertinite Liptinite 

57 -71 

61 

56 – 76 

64 

53 – 67 

60 

55 -78 

65 

1-8 

2 

0-5 

2.1 

1-3 

2 

1-5 

2.5 


9-27 

21 

12 – 27 

18 

17 – 20 

19 

4-19 

15 

Exhibit 1.14 Coal Petrography, Yuzhno-Donbasskaya #3 Mine 

Thermal Maturity 

from – to 

average 

V daf % Ro % 

31.4-43.7 

39.3 

34.0 - 41.8 

35.7 

36.1- 42.8 

39.3 

33.9 - 44.2 

39.1 

0.59 - 0.93 

0.78 

0.56 - 0.84 

0.74 

0.79-0.79 

0.79 

0.61- 0.87 

0.75 

Exhibit 1.15 Thermal Maturity, Yuzhno-Donbasskaya #3 Mine 

10 – 26 

15 

9-20 

15 

13 – 26 

20 

11 – 25 

18 

1.6.1.5 Gas Properties 

The generalized data on all tested coal-beds is presented in Exhibit 1.16. It has been 

determined by mining operations that the upper boundary of methane gases in the mine lies 

at a depth of 170 to 200m. As one goes deeper, the concentration of methane decreases; 

for depth intervals of 400 to 1100m methane concentrations are 52.9 to 94.1 % of total gas. 

The average values range between 73.8 to 83.0 %. The content of nitrogen ranges between 

0 to 17 % and the content of carbon dioxide averages around 3.5 % and ranges between 0.1 

to 8.7 %.



Gas Composition by Depth Range. 

(%. from - to / average) 

Depths 

m He H2 CO2 CH4 C2H6 

C3H8 

and others N2 

Gas per mass 

of dry ashfree 

coal 

m 3 /ton 

400-500 - 4.1 8.3 59.1 0.1 0.0 31.2 10.5 

500-600 

600-700 

700-800 

800-900 

900-1000 

1000- 

1100 

0.0-0.74 

0.08 

0.0-0.11 

0.05 

0-0.11 

0.041. 

0.0-0.11 

0.04 

0.0-0.2 

0.06 

0.0-0.9 

0.04 

0.0-3.6 

0.37 

0.0-5.0 

0.4 

0-7.4 

0.595 

0.0-8.6 

0.42 

0.0-2.3 

0.47 

- 

0.1-8.7 

0.4 

0.1- 6.3 

2.8 

1.0-13.9 

8.0 

0.3-7.1 

3.4 

1.2-8.7 

3.0 

1.5 -17.0 

5.4 

60.3-94.1 

82.2 

52.9 - 93.5 

83.0 

57.5-92.9 

80.8 

59.2-93.4 

80.8 

61.8-93.6 

78.3 

53.5-91.3 

73.8 

0.0-0.2 

0.08 

0.0 - 0.7 

0.13 

0.0-1.8 

0.36 

0.0-3.9 

0.57 

0.0-2.6 

0.58 

0.0-2.1 

0.64 

0.0-1.4 

0.09 

0.0-0.1 

0.01 

0.0-0.4 

0.05 

0.0-1.32 

0.09 

0.0-0.8 

0.16 

0.0-0.8 

0.19 

Exhibit 1.16 Gas Composition, Yuzhno-Donbasskaya #3 Mine 

3.4-29.3 

13.6 

4.3-37.2 

12.8 

3.9-35.2 

14.3 

4.3-36.2 

14.1 

4.2-52.2 

15.0 

6.6-30.4 

18.7 

9.0-19.1 

13.5 

6.9-26.2 

15.8 

7.9-34.5 

14.3 

6.5-28.5 

15.5 

8.7-27.5 

15.3 

10.1-18. 

13.6 

Heavier hydrocarbons are found at depths starting at 500 m and below 700 m ethane 

volumes reach 1.8 to 3.9 % and the presence of propane in the gas is observed (0.8 to 

1.4%). 

The distinctive feature of coal-bed derived gases in the Yuzhno-Donbasskaya #3 mine is the 

content of helium and hydrogen. The average values of H2 range between 0.4 to 0.5 % 

(maximum 8.6%) and helium ranges between 0.04 to 0.079 %. The presence of these gases 

testifies to the activity of tectonic zones and the highest values are found near or along fault 

zones. 

1.6.1.6 Mine Degassing 

The Yuzhno-Donbasskaya #3 mine has mined the C10 2 , C11, C13 and C6 coal beds at depths 

of 585-940m. According to measurements made in 1996, the degassing of the mine 

produced 98m 3 methane per ton of coal mined. 




The concentration of methane per ton of coal mined of the C13 coal bed at depths of 550- 

700m produces 20-182 m 3 per ton. Increased methane flows were observed along the 

monoclinal fold in the southern part of the mine area. The methane emissions from mining 

the C11 coal bed are a little less than that of the C13 coal at 6-33 m 3 per ton. The coal bed 

C10 2 was mined at depths of 600-700m. Its methane emissions were 16-17 m 3 per ton of coal 

mined, much lower than that of the overlying coal-beds. 

The lower levels of methane may be due to a high daily coal production, up to 700 tons a 

day. The methane emissions from the C6 coal bed ranges from 32 to 69 m 3 per ton at depths 

of 610 to 750 m. During a slow down in the extraction rate, methane production increased 

sharply (almost twice as much) and is probably connected with high gas saturation of the 

surrounding coal seams and strata. 

From 1998 to 1999 the total volume of methane produced by the degasification system of the 

mine was 6.16 million m 3 and when the ventilation system is included, it is estimated that 39 

million m 3 was produced. 

1.6.1.7 Gas In-Place 

The gas-in-place of coal-beds and enclosed strata was measured in 20 core wells in the 

complex KII-65 (MIG-65) as well as the composition of gases (Exhibit 1.17). In one of the 

wells, the presence of natural gas in the coal-beds and enclosed strata was defined by the 

MGRI complex method and with continuous gas logging. The collective properties of 

sandstones were also defined for the determination of potential methane-bearing capacity of 

the sands. 

Depth Interval m Gas-in-Place by Coal Bed (m 3 /ton) 

C13 C11 C10 2 C6 

500 - 600 14.0 - - - 

12.6-19.1 6.9 - 21.8 20.1-30.5 

600 - 700 

16.3 

13 .7 

25.3 - 

10.2-12.4 8.5 - 21.0 9.0-11.7 10.4 - 34 .5 

700 - 800 

11.2 

14.1 

10.4 

15.6 

9.3-18.5 6.6-20.4 

6.5-15.7 

800 - 900 

13.2 

15.2 - 

12.3 

12.9-18.1 

14.8-18.4 

900 - 1000 - 

15.5 - 

16.4 

13.6-18.2 

1000 -1100 - - - 

15.2 

Exhibit 1.17 Gas-in-Place for Specific Depths, Yuzhno-Donbasskaya #3 Mine 




When drilling the area for the geologic determination of thickness and depth, coal cores were 

not taken and unfortunately, nor were gas content measurements taken. The presence of 

gas however was logged in a few intervals in the interbedded sandstones and amounts 

between 1.34 to 2.93 m 3 /m 3 were noted and were associated with water in most cases. The 

other beds of sandstones were tested together with coal-beds and their high gas capacity is 

more likely to be connected with coal seams and not with the sandstones. The high gas 

saturation of the coal-bearing series in the Yuzhno-Donbasskaya #3 mine is maintained by 

the seal provided by the Cretaceous deposits and also the thick (20 to 30 m) series of 

argillites above the limestones. 

Estimates of potential gas in place are calculated by adsorption potential of the individual 

coal beds. Overall, the gas-in-place of the coal seams average between 15 m 3 per a ton at 

450m and 20 m 3 per a ton at 600 m depth (see Exhibit 1.17). According to this data, coalbeds 

have gas content up to 20m 3 per a ton on a dry, ash-free (DAF) basis in the 600 to 

800m depth range and in the deeper horizons, only localized increases in gas content were 

observed and were connected with tectonic fractures (the coal bed C1 had a gas content of 

28.5 m 3 per ton DAF near to the Noviy fault) as wells drilled near fault zones. 

The absorptive capacity of methane of the C13 coal at a pressure of 50 atmospheres 

(corresponding to depths between 454 to 692 m) is 17 to 24 m 3 per ton. The coal bed C13 is 

characterized by quite high stable gas presence at borders of the mine. 

The coal bed C11 is one of the most continuous coal-beds in the mine area. The coal bed C11 

was tested by the GKN method. At a depth of 450 m, the coal bed contains 15m 3 per ton of 

gas and 20m 3 per ton of dry gas at 600 m. The absorptive capacity for methane of the coal 

bed C11 at a depth of 600m is 20.1 to 29.0 m 3 per ton DAF at a pressure of 50 atmospheres. 

The methane content fluctuates between 6.7 - 151.8 m 3 per ton of daily mine output and 

averages 25 m 3 per ton of daily mine output. 

The presence of gas in the coal bed C10 2 and adjoining coal-beds C10 1 and C10 fluctuates 

within the range of 15 to 20 m 3 per ton DAF. The methane content of the coal bed C10 at a 

depth of 624 to 740m has a gas content of 16.8 to 17.0 m 3 per DAF ton. 

The C6 coal bed has a gas content ranging from 10-18m 3 ton DAF with an average of 15 m 3 

per ton DAF at depth of 500 m. The absorptive capacity of the C6 coal is 16.3 m 3 per ton DAF 

at a depth of 578.6m. 




The basic estimated area of the coal bed is characterized by gas presence from 15 – 20 m 3 

per ton on a dry ash-free basis. The total calculated gas-in-place reserves for all coal seams 

in the South-Donbass #3 mine are 4.8 billion m 3 . (Exhibit 1.18) 

Coal-bed 

Gas-in-Place of Coals 

(million m 3 ) 

Recoverable Resource Total 

C18 150 118 268 

C13 349 60 409 

C11 B 154 23 177 

C11 628 68 696 

C10 2 11 67 78 

C10 2H 9.4 17.4 27 

C10 1 - 281 281 

C10 - 208 208 

C6 1 589 40 629 

C4 3 61 331 392 

C4 2 493 49 542 

C2 - 256 256 

C1 1 - 394 394 

B5 1 - 510 510 

Total 2511 2356 4867 

Exhibit 1.18 Gas-in-Place of Individual Coal Beds of Yuzhno-Donbasskaya #3 Mine 




1.6.1.8 Estimation of Gas Reserves 

As part of the process of estimating the CMM reserves of the Yuzhno-Donbasskaya #3 mine 

the degasification rate for an 11 year period (1995 to 2005) was analyzed (Exhibit 1.19). 

During that period the mine produced between 1,502 to 4,301 tons of coal per day and 

yielded methane emission rates of between 22.5 to 107.8 m 3 per minute. 

The average annual relative methane abundance of the mine varied between 11.9 to 47.6 m 3 

per ton on a dry ash-free basis during this time period and its normalized value increased 

from 19.2 to 28.2 m 3 per ton. The increase in this value for the last five years is caused 

mainly by an increase in the depth of mining for coal seam C11. 

12 0 

10 0 

80 

60 

40 

20 

0 

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 

Av. Coal Prod. (tons/day) Methane Emission Rate, m3/min 

Average Methane Content, m3/ton Normalized Av. Methane Content, m3/ton 

Exhibit 1.19 Coal Production and Methane Emissions of Yuzhno-Donbasskaya #3 Mine 

At the current time, the most detailed available data on methane emissions comes from a 

limited area of the C11 coal seam. Data provided by technical staff from the mine, for a 15 

month period from October 2004 to December 2005 show that the normalized methane 

production is relatively stable at 31.1 m 3 per ton of coal per day (Exhibit 1.20). Given the 

mine’s total coal reserves at 158 million tons, the total methane resource is approximately 

4.9 Billion m 3 . This is a slightly more conservative estimate of the EPA reported reserves of 

5.9 Billion m 3 in 2001. 


5000 

4000 

3000 

2000 

1000 

0 

Coal production (tons/day)



Data provided by the Chief Engineer of the South Donbass #3 mine states that the mine 

degasification system is currently (May 2008) capturing up to 25 million m 3 /year (68,500 

m 3 /day) of over 28% quality methane. 

60 

50 

40 

30 

20 

10 

0 

Oct-04 Nov-04 Dec-04 Jan-05 Feb-05 Mar-05 Apr-05 May-05 Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 



Exhibit 1.20 Coal Production and Methane Emissions at Yuzhno-Donbasskaya #3 Mine 

from Coal Seam C11 only 


2500 

2000 

150 0 

10 0 0 

500 

0 

Average Daily Coal Production (tons/day)

1.6.2 Bazhanov Mine 



The Bazhanov mine area is located within the territory of the district of Makeyevka city in 

Donetsk Region. The area is situated on watershed of the Krivoy Torets and the Kalmius 

Rivers. The area is located on a hilly steppe plain, cut with ravines and gullies. 

Mineral resources of the mine are owned by the Makeyevugol State Coal Mining Company. 

The Bazhanov Mine is situated in the north-eastern part of the town of Makeyevka, a highly 

developed mining area which includes by-product-coking and steel industries and is also a 

favorable location with respect to coking coal consumers, including the Makeyevka, Donetsk, 

Rutchekovsk coking plants, and the Kalmius Central Washing-house situated 30 km from the 

mine. 

The mine is highly accessible to neighboring mines and centers of population by means of 

highway and asphalt roads. In the northern part of the area, there are two rail lines, the 

Yasinovataya-KrinichnayaIlovaysk and Yasinovataya- Makeyevka trunk lines. These lines 

are joined with branch lines to the Bazhanov Mine, the Yasinovataya coking plant and the 

Kirov Plant. 

The mine is supplied with electricity by means of high-voltage lines of the Donbassenergy 

System generated from the Zuevka Hydroelectric Power Station. 

The Bazhanov Mine began operations in 1957. Currently (2006), the capacity of the mine is 

0.76 million tons of coal per year and only one coal layer, the m3 seam, is being exploited. 

The area of the mine encompasses about 39 square km. 

1.6.2.1 Geologic Structure 

The mine area is located between the Burozovskaya (aka Kalininskaya) and Chaykinskaya 

flexures. Between the Burozovskoy and Chaikinskoy folds, the regional dip is 4 to 8° to the 

northeast. The Burozovskoy monocline fold near the mine is traced with exploratory wells 

along the monoclinal strike. The dip of the coal seams is gentle, averaging 4 to 15 °, but can 

reach 25-70° in region of the of monocline folds. Steep dips occur along the monocline fold 

area defined by the mine workings at the Schmidt Mine NQ3, NQ4 and Kapitalnaya Mine NQ 

1, NQ2, where the dip angle is 60 to 90°. 

The Burozovskoy monocline fold stretches from southeast to the northeast with dips of 45 to 

50° in the northwest and increasing to 70 to 75° in the southeast. The southeast fold limb is 

considered to be the up-thrown side. Vertical displacement of the fold reaches 1,200 m. To 




the south of the area, the axis of the fold is interrupted by the Frantsuzskiy fault. The steep 

eastern flank of this major fault is complicated with numerous smaller faults that include the 

Pervomayskiy fault, the Western fault NQ 1, a Branch of Western fault NQ 1, and Western 

NQ2. 

The above-described faults, in the region where the Bazhanov Mine is located, are 

subdivided into two types of fault systems based on their character: 

Bedding plane faults, which have a north-west dip, parallel to the regional rock dip 

(Frantsuzskiy fault, Western fault NQ 1 and NQ2, the Branch of Western fault NQ 1 and 

Bezymianniy fault). 

Steeply dipping down to the southeast faults that cut across regional dip (Pervomayskiy 

fault, Novo-Chaikinskiy fault). 

The characteristics of the fault systems which are located within the limits of the mine area, 

are given in Exhibit 1.21. 

The Frantsuzskiy fault can be traced to the south of the mine area. The area of the nearby 

"Chaikino" mine is well explored and investigated where the fault has a throw of 240 to 320m. 

Within the limits of the Bazhanov mine, the fault offsets reach 180m. The fault has a 

latitudinal strike with dips between 40 to 60° to the north. In the south the fault is terminated 

by the Pervomayskiy fault. 

The Western Fault NQ 1 is traced along the south-east border of the area by 27 prospecting 

wells within the limits of the Bazhanov Mine and the Butovskiy-Glubokiy site NQ2. 

The Branch of Western Fault NQ 1 is traced by five prospecting holes in the Pervomaiskiy 

fault in earlier published geological reports referred to as the Western Fault, however it 

spatially coordinates with the Pervomaiskiy fault, as revealed and investigated within the 

limits of the field of the "Chaikino" mine. 


Fault System 

Number of faults 

(from boreholes) 

Depth Range 

(m) 

Bezymianniy 22 -101.0-1185.0 

Pervomaiskiy 11 + 193.0-850.0 

Western NQ 1 27 -37.0-1335.0 

Branch of Western NQ 1 5 -590.0-789.0 



Dip azimuth 

Range / Average 

(degree) 

255-325 

295 

115 - 130 

120 

300-337 

300 

320-330 

325 

Hade 

Range / Average 

(degree) 

Thickness of Fault 

Breccia 

(m) 

Displacement 

(m) 


10 -74 

45 

40 – 75 

68 

64 – 75 

68 

Exhibit 1.21 Summary Table of Fault Systems of the Bazhanov Mine 

5 - 52 5 - 58 

15 - 44 15 - 170 

3 - 109 5 - 65 

48 – 55 5 - 30 5 - 31



The Bezymianniy Fault limits the mine area to the northwest, striking from south-west to 

north-east. In the center of the area the strike of the fault is close to N-S. Within the limits of 

the mine area, the trace of the Bezymianniy fault does not appear at the surface, but is 

exhibited as a fault gouge in corewells 3983 and 3883, with no displacement of rocks 

observed. Along the Chaikinskoy flexure fold, the strata dip 30 to 40 o to the southwest, 

increasing up to 74°. The angle of dip of system decreases from 20° to 14° and within the 

limits of the "Chaikino" mine, the fault flattens. 

1.6.2.2 Coal Geology and Properties 

The mineable coal of the Bazhanov mine is concentrated in coal-measures of the series C3 1 

and C2 7 in which 48 coal layers and interlayers are contained. The series C3 1 contains 17 

coal layers and interlayers, with only two of them workable over significant areas. The series 

C2 7 contains 31 coal seams and inter layers, including 8 seams which reach working seam 

thickness over most of the mine area. 

The total mineable reserves of the Bazhanov mine are 62,628,000 tons with working seams 

accounting for 15,824,000 tons of the total. The current mining capacity is approximately 

1,600 tons/day from 10 coal seams, although currently only the m3 seam is mined via 

longwall technique. The rank of the m3 coal is high-vol bituminous A with an average ash 

content of 8.0%, a moisture content of 0.8% and the sulfur content around 3.5%. 




1.6.2.3 CMM Gas Composition. 

The composition of gas in the coal layers is predominantly methane, with minor amounts of 

ethane, nitrogen and carbon dioxide (Exhibit 1.22). Methane concentrations in coal layers 

are on average 98+%. The high content of methane in samples testifies that all principal coal 

seams are in the methane saturated zone. 

Ethane is present almost in all samples with the contents from 0.1 up to 11.2 %. Propane 

and butane are also present in the majority of samples, ranging from 0.0 to 8.9%. The 

increased content of heavier hydrocarbons is characteristic of the mine working. Carbon 

dioxide is found in all samples at concentration less than 2.0 %. Hydrogen was detected in 

only a few samples and the concentration did not exceed 0.11 %. 

Depth, m 

800 - 900 

900 -1000 

1000 - 1100 

1100 - 1200 

Gas Composition, %: from - up to/average 

(number of determinations) 

CO2 CH4 C2H6 C3H8 + C4H10 02 N2 

0.2 - 1.3 / 0.5 

(18) 

0.2 - 1.1 / 0.4 

(14) 

0.3 - 1.9 / 0.7 

(7) 

0.3 - 0.7 / 0.4 

(7) 

80.6 - 96.2 / 

87.8 

(18) 

65.9 - 90.7 / 

81.7 

(14) 

55.7 -96.7 / 

81,,9 

(6) 

81.8 -91.5 / 

86.2 

(6) 

0.9 - 9.7 / 6.5 

(18) 

1.1 - 11.2 / 

4.6 

(5) 

0.0 - 5.1 / 2.3 

(4) 

0.2 - 5.1 / 2.0 

(7) 

0.0 -7.9 / 1.4 

(18) 

0.9 - 4.3 / 2.5 

(12) 

1.0 -7.5 / 3.1 

(4) 

3.6 - 8.9 / 6.0 

(6) 

0.3 -1.4 / 0.7 

(7) 

0.2 - 2.9 / 1.1 

(12) 

0.4 - 3.4 / 1.4 

(3) 

0.2 - 0.8 / 0.4 

(6) 

Exhibit 1.22 Gas Composition According to Depth, Bazhanov Mine 

0.9 - 9.2 / 4.9 

(18) 

3.2 - 13.0 / 

47.7 

(11) 

1.0 -7.0 / 3.1 

(4) 

3.6 - 8.9 / 6.0 

(4) 




1.6.2.4 Mine Degassing 

The Bazhanov mine is considered a dangerous mine due to rock bursts and gas explosions. 

Ventilation and underground degasification is applied by drilling of the m3 seam, and since 

1986, of the 1n H seam. Since 1963, approximately 23,000 m 3 /day of pure methane has been 

vented from seam m3. Thus, methane vented to the atmosphere during mining of seam m3 

totals 224 million m 3 . 

Detailed coal production and methane emissions data for the years 2004 and 2005 was 

provided by the mine technical staff (Exhibit 1.23). 

10 0 

90 

80 

70 

60 

50 

40 

30 

20 

10 

0 

Jan-04 Mar-04 May-04 Jul-04 Sep-04 Nov-04 Jan-05 Mar-05 May-05 Jul-05 Sep-05 Nov-05 



Exhibit 1.23 Coal Production and Methane Emissions - Bazhanov mine (2004-2005) 

Personal communication from the Director of the Bazhanov Mine Management Company 

states that in 2007, 9.9 million cubic meters of methane was extracted from the mine, with 

5.5 million cubic meters from that total used to fire the mine’s boiler. 


4000 

3500 

3000 

2500 

2000 

150 0 

10 0 0 

500 

0 

Average Daily Coal Production (tons/day)



1.6.2.5 Estimation of Gas-In-Place. 

Within the limits of the mine area, an estimation of the volume of methane contained in the 

coal seams was calculated using the following formula: 

where 

Vr=S*m*g*KB*r, 

Vr - volume of gas; 

m - thickness of a layer, m; 

g - density of coal, ton/m 3 ; 

S - the area of calculation, m 2 ; 

r - average methane content, m 3 /ton; 

KB - factor of ash- free weights. 

All coal seams in the Bazhanov mine possess gas content values greater than 10 m 3 /ton 

from tests conducted on the coal seams. Methane resources are divided into two categories, 

Category C1, reserves in the mineable coal, and Category C2 which are potential resources 

from other coal seams (Exhibit 1.24). The total gas-in-place is calculated to be 1.62 billion m 3 

for the coal reserves in the mine area. By including all the potential coals seams beyond the 

mineable reserves, the amount of coal bed methane resource increases to 3.79 billion m 3 . 

Coal 

Methane Resource 

1000 m 3 

Primary Secondary C1 C2 Totals 

1 

n1 

n1 1 +n1 0 20838 

H 

n1 

n04+n03+n02 + n01 +n0 51172 

m9 m9 1 +m9 0 +m8 1b +m8 1H 261077 

m7 

m6 3 +m6 2 

m5 1 

m8 

m6 1 +m6 0 +m6+ 

m5 4 +m5 3 

m5 2 +m5 6 +m5 H + 

m4 5 +m4 4 

m4 1 m4 3 +m4 2 +m4 0 

m3 

m4 

359473 

236955 

421069 

m2 m1 2 +m1 1 +m1 0 +m1 272628 

43858 64967 

58967 58967 

17463 68635 

49023 49023 

47928 309005 

279575 279575 

1344 360817 

93680 93680 

274601 274801 

256204 256204 

156816 156816 

2893 239848 

240207 240207 

141331 141331 

145118 145118 

21064 442133 

39550 39550 

78948 351576 

221334 221334 

Total 1623212 2170104 3793316 

Exhibit 1.24 Coal Bed Methane Resource Estimates - Bazhanov Mine 




1.7 Coalbed Methane Project Areas 

1.7.1 Grishino Andreyevskaya Area 

The Grishino Andreyevsk Area (license is granted to the Donetskgeologiya Company) 

includes a mining lease of one mine and six exploration shafts with a total area of more than 

557 km 2 (Exhibit 1.25). The area is located in the Krasnoarmeysk district of the Donetsk 

Region. Ninety-five percent of the area is used for agricultural purposes. The land is owned 

by individuals and farmers and has hard cover roads. There is a main railway line to the 

north of the area that connects the cities of Donetsk and Kiev. The closest gas pipeline is 

the Krasnoarmeysk-Selidovo line, which is located outside of the area. 

The mineral rights belong to the State with the coal seams mainly located in the Lower 

Carboniferous sediments in the western part of the area and Lower and Middle 

Carboniferous sediments in the eastern part. The complex structure of the area is caused by 

the large, transverse Kotlinsky and Yalinsky fracture thrusts and associated structures. The 

western edge of the area borders on the Krivoy Rog - Pavlovsk structure. 

1.7.1.1 Methane Reserves Estimates 

The number of mineable/completeable coal seams in the area varies from 1 to 9. The 

average gas content of the coal varies from 10 to 20 m 3 /t on a dry, ash-free basis. Experts at 

the Donetsk Region Geology Company estimate the total methane reserves of the area to be 

18.2 billion m 3 (Exhibit 1.26) and these estimates appear to be in line with the measured gas 

content data and coal thickness data. 

The gas reserves in adjoining rock beds are more difficult to estimate as only a few tests of 

the methane content have been made. In one example, taken from core-hole #3623, the 

methane content of the sandstone layer E8 3 SE4, at a depth of 120 to 140m, is about 0.43 

m 3 /m 3 . For sandstone layer E6SE6 at the depth of 230m the methane content is about 

2.2m 3 /m 3 and for sandstone layer of D1 5B SD2 at the depth of 716 to 733 m is about 2.3 m 3 /m 3 . 

These sandstone units will definitely contribute methane during both CMM and CBM 

production and therefore an estimate of the amount of methane contained within them is 

included. Assuming a porosity of 7.0%, a 56% gas saturation, an average depth of 1000m 

and an average thickness of 31m, the total amount of gas contained within the sandstones is 

approximately 40 billion m 3 . 




Exhibit 1.25 The Grishino-Andreyevskaya CBM Lease Area 


# Explored Reserves and Mining Field 



Number of 

Industrial 

Layers of 

Coal 

Total Output 

of Coal 

Layers 

(>0.3m,m) 

Gas Content 

of Coal 

Seams, m 3 /t, 

Dry Basis 

Methane 

Reserves 

(Billion 

m 3 ) 

1 Solyonovsky #1 and #2 5 4.9 10 2.2 

2 Solyonovsky #3 5 5.1 10 1.3 

3 Krasnoarmeyskaya Zapadnaya Mine #1 1 3.2 (10-20)/15 2.95 

4 Krasnoarmeyskaya Zapadnaya Mine #2-3 3 4.7 15 4.6 

5 Andreyevo-Kurakhovskaya Site 9 8.5 (10-15)/13 2.5 

6 Krasnoarmeyskaya Zapadnaya Mine #2-3 1 3.7 15 1.4 

7 Andreyevsky Yuzhny 5 7 (12-16)/14 3.2 

TOTAL 18.2 

Exhibit 1.26 Estimated Methane Reserves of the Grishino-Andreyevskaya Area 




1.7.2 South Donbass CBM Development Area – ECOMETAN 

The South Donbass CBM lease area (licensed to ECOMETAN) includes 2 mines and 7 

exploration shafts. The total area of the lease is 530 km 2 . (Exhibit 1.27) It is located mainly 

in the Marinka District of the Donetsk Oblast, with small areas of the lease stretching into the 

Velikonovosyolovka District to the west and the Volnovakha District to the south. The lease 

area has a SE-NW orientation and the largest nearby towns are Ugledar (to the south-west) 

and Marinka (to the north-east). Ninety percent of the lease area is used for agricultural 

purposes or is not cultivated, and is owned by individuals, farmers or municipal bodies. The 

large (700mm diameter) Donetsk – Mariupol pipeline runs to the east of the lease. 

1.7.2.1 Geology 

A detailed discussion of the general geology and the coal geology of the South Donbass 

area can be found in Sections 1.6.1.1 and 1.6.1.2. Coal beds in the area are found in the C1 3 

section in the Lower Carboniferous, with the section varying in thickness from 11.7 m to 18.1 

m and containing 7-16 coal seams. The coals are typically medium to low volatile bituminous 

coals. 

1.7.2.2 Methane Reserves Estimate 

The technical staff at the Donetskgeologiya Company estimates the South Donbass lease 

area reserves in the coal seams are 57.2 billion m 3 . (Exhibit 1.28) The average methane 

content of the coal varies from 6 to 22 m 3 /t (on a dry, ash free basis). The lease area is 

characterized by a large number of interbedded sandstone layers in the coal section and 

above it. Tests in mine and exploration shafts have shown abundant gas reserves in these 

sandstones. Tests from the South Donbass shafts #1, 3, 4, 6, and 12/1 resulted in gas 

content measurements of the sandstone between 0.33 to 1.57 m 3 per ton. The porosity of 

the sandstone varied between 2.6-14% and gave permeability values of 0.01-15.5 mD. 

Using these data, combined with discussions with Ukrainian experts, the gas in place in the 

interbedded sandstones is between 120 and 500 billion m 3 . 




Exhibit 1.27 The South Donbass CBM Lease Area 


Mine or Exploration Shaft 



# of Economic 

Coal Seams 

Total thickness of 

Coal Section 

(seams >0.3m) 

(m) 

Gas Content of 

Coal Seams 

(m 3 /t daf) 

Gas Reserves 

(billion m 3 ) 

South Donbass Mine #1 11 12.1 6-15 2.1 

South Donbass Mine #3 15 15.6 12.1-18.3 5.0 

South Donbass Shaft 4 16 18.1 11.1-20 7.3 

South Donbass Shaft 5 12 12.5 10-17.3 4.3 

South Donbass Shaft 6 13 14.5 12.5 8.2 

South Donbass Shaft 8-9 7 11.7 12-18 7.6 

South Donbass Shaft 12/1 13 14.2 12.1-20.8 6.7 

South Donbass Shaft 12/2 10 13.8 14.7-20 6.0 

South Donbass Shaft 13-14 12 14.9 11.4-22.1 10.0 

Total: 57.2 

Exhibit 1.28 Estimated Gas Reserves of the South Donbass CBM lease 





Task 1 - Section 2 



Reservoir Simulations 

Reservoir Simulations 2-i



SECTION 2 CONTENTS 

2.1 Introduction......................................................................................................................2-1 

2.2 CBM Reservoir Modeling ................................................................................................2-2 

2.2.1 Permeability...............................................................................................................2-3 

2.2.2 Sandstone permeability.............................................................................................2-4 

2.2.3 Langmuir Volume and Pressure ................................................................................2-4 

2.2.4 Relative Permeability.................................................................................................2-7 

2.2.4.1 Coal Relative Permeability...............................................................................................2-8 

2.2.4.2 Sandstone Relative Permeability.....................................................................................2-9 

2.2.5 Reservoir (Coal and Sand) Depth and Thickness. ..................................................2-10 

2.2.6 Well Completion and Model Construction ...............................................................2-10 

2.2.7 Porosity and Initial Water Saturation .......................................................................2-12 

2.2.8 Sorption Time ..........................................................................................................2-12 

2.2.9 Spacing....................................................................................................................2-12 

2.2.10 Simulation Results:..................................................................................................2-13 

2.3 CMM Reservoir Modeling..............................................................................................2-17 

Reservoir Simulations 2-ii



SECTION 2 EXHIBITS 

Exhibit 2.1 COMET3 Reservoir Simulation Input Data, Donetsk CBM Study .....................................2-2 

Exhibit 2.2 Natural Cleat Fracture System ..........................................................................................2-3 

Exhibit 2.3 Graph Illustrating Permeability Scale Effects in Coal Seam..............................................2-3 

Exhibit 2.4 Summary of Published Data..............................................................................................2-5 

Exhibit 2.5 Summary of Published Data (cont..)..................................................................................2-6 

Exhibit 2.6 Donetsk Basin Gas Isotherm Derived from Gas Content Data .........................................2-7 

Exhibit 2.7 Donetsk Basin Coal Relative Permeability ........................................................................2-8 

Exhibit 2.8 Donetsk Basin Sand Relative Permeability .......................................................................2-9 

Exhibit 2.9 Typical Depth and Thicknesses for Coal and Sand in a Donetsk Region well................2-10 

Exhibit 2.10 Modeled Depth and Thickness of Coal and Sand for Reservoir Simulation ...................2-11 

Exhibit 2.11 Summary of Simulation Results ......................................................................................2-13 

Exhibit 2.12 Simulation Results - Case 1 ............................................................................................2-14 




Exhibit 2.16 Tabular Type Curve Production Data..............................................................................2-16 

Reservoir Simulations 2-iii




The gas production curves developed for both the CBM and CMM portions of the study form 

the basis of the economic analyses performed in Section 6 of this report. In addition, 

estimating the gas production rates is critical in the planning and design of production 

equipment, surface facilities, and end use options. 

For the two CBM areas, Grishino-Andreyevskaya and South Donbass, thirty-year gas and 

water production simulations were performed using COMET3, Advanced Resources' 

proprietary reservoir simulator. COMET3 is a fully implicit, finite-difference simulator 

specifically designed for modeling the flow of gas and water in coal seams and 

unconventional reservoirs. 

The simulator is a triple porosity model that includes the coal matrix and coal cleat system. It 

includes two-phase (gas and water) flow that is modeled via gas/water relative permeability 

curves. COMET3 also includes gas desorption and diffusion processes that are essential for 

the accurate modeling of gas production from coal seams. 

Type wells were constructed to represent the average reservoir characteristics of each CBM 

production area. Most of the input data used to model gas recoveries were obtained from the 

geologic and reservoir property data discussed in Section 1. For those parameters that were 

not available from the study data, Advanced Resources used reservoir properties from coal 

and sandstone formations that are most analogous to the Donetsk Region, primarily Permo- 

Carboniferous local basins in neighboring countries, such as Poland and the Czech 

Republic. 

For the CMM portion of the study, detailed modeling of the rate and quality of the gas 

produced is a difficult and complex task because of the interaction between the geologic 

conditions, mine advance rates, and degasification drilling programs. Furthermore, accurate 

modeling would require detailed data on all of the strata affected in the gob area (e.g. 

permeability, gas saturation, porosity, etc.), data that are not readily available. Therefore, the 

estimate of CMM production from each mine is based on historical production rates of CMM 

produced from each mine and projected future mining plans. 

Reservoir Simulations 2-1

2.2 CBM Reservoir Modeling 



The input parameters used in the COMET3 reservoir simulation study are presented in 

Exhibit 2-1. A brief discussion of each parameter is provided below: 

Parameter Value Range 

Drainage Area 60 Ac (0.25 Km 2 ) 

Reservoir Thickness See Exhibit 2.10 

Fracture Half-Length 15 m (50ft) (skin = -4) 

Depth to Reservoir See Exhibit 2.10 

Initial Reservoir Pressure See Exhibit 2.10 

Cleat and Pore Water Saturation 100% in Coal / 44% in Sandstone 

Cleat Permeability (md) 0.1 md in Coal; 0.62 md in Sandstone 

Porosity 1% in Coal, 7.1% in Sandstone 

Pore-Vol. Compressibility 400 x 10 -6 Coal 

Cleat Spacing 2.5 cm (1in) Coal 

Langmuir Volume (Coal) 865 cf/ton (27 m 3 /tonnes) 

Langmuir Pressure (Coal) 339 psia 

Gas Content (Coal) See Exhibit 2.6 

Gas Gravity 0.60 

Reservoir Temperature Gradient 1.1 Degree (F) per 100 ft. 

Water Viscosity 0.62 cp 

Sorption Time 12 Days 

Exhibit 2.1 COMET3 Reservoir Simulation Input Data, Donetsk CBM Study 


2.2.1 Permeability 



Coal bed permeability, as it applies to CBM production, is a result of the natural cleat 

(fracture) system of the coal and consists of face cleats and butt cleats (see Exhibit 2.2). This 

natural cleat system is sometimes enhanced by natural fracturing caused by tectonic forces 

in the basin. 

C o a l 

Cleat System 

Exhibit 2.2 Natural Cleat Fracture System 

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 in the Donetsk Basin consists of measurements taken on whole core which 

were obtained from coal exploration core holes. In naturally fractured reservoirs, corederived 

permeability measurements do not necessarily provide reliable absolute permeability 

values because they only reflect the in-situ permeability and reservoir conditions over a small 

area. In general, a larger areal sampling, results in higher observed permeability values, 

(illustrated graphically in Exhibit 2.3). 

Permeability 

Core 

Kilogram 

Single Well Multi-Well 

300 Tons 

Sample Size 

50,000 Tons 

JAF02606.PPT 

Exhibit 2.3 Graph Illustrating Permeability Scale Effects in Coal Seam 




Based on extensive work conducted by numerous coal mines in the Donetsk region, the 

permeability of the coal seams appears to be low, on the order of 0.1 md. This value is 

consistent with permeability measurements derived from other Eastern European coal basins 

which generally indicate permeability values of less than 1.0 md in the coal seams. 

2.2.2 Sandstone permeability 

The Donetsk Basin is also rich in sandstone deposits that have been shown to produce gas. 

The critical reservoir parameters of porosity and permeability have been measured for these 

sandstone reservoirs throughout the basin, and have been presented in published 

literature 14 . Based on this information, an average permeability of 0.62 md was used in 

reservoir simulations. In the United States, sandstone reservoirs are considered “tight”, or 

very low permeability, if the absolute permeability is equal to or less than 0.1 md. 

Nevertheless, with average permeability of 0.62 md the sandstone reservoirs of the Donetsk 

basin can be considered relatively tight, or in the lower range of conventional natural gas 

reservoirs. 

2.2.3 Langmuir Volume and Pressure 

Langmuir volumes and pressures, measured in the laboratory for Donetsk Basin coals, were 

not available for the study. Therefore, it was necessary to construct a synthetic isotherm 

based on gas content data. Gas content has been measured in cores taken from many coal 

exploration core holes throughout the Donetsk Basin. These data have been summarized 

and are presented in Exhibit 2.4 and Exhibit 2.5. 

The gas content data was plotted as pressure versus gas content in m 3 /tonne. Pressure was 

derived by applying a pressure gradient of 0.433 psi/ft to the reported depth of each 

respective coal seam. A regression analysis was performed using the Langmuir equation: 

C = (VL x P) / (PL + P): 

(Where C is gas concentration, VL is Langmuir volume, PL is Langmuir pressure, and P is 

pressure.) 

The resulting Langmuir volume and pressure are 27 m 3 /tonne and 339 psia, respectively, 

and this synthetic isotherm was used in lieu of measured data. The isotherm derived by this 

methodology is shown in Exhibit 2.6. 

14 

Coal Mine Methane in Ukraine, Opportunities for Production and Investment in the Donetsk Coal Basin, U.S. Environmental 

Protection Agency, January 2001. 




Summary of "Coal Mine Methane in Ukraine: Opportunities for Production and Investment in the Donetsk Coal Basin" 

Power Heat Sand Permeability 

Gas 

Mine Mine Area Consumption Consumption Boiler Sand Porosity 

md 

Thickness Depth Content 

Mine No. Area Seam km2 MW/Yr Gcal Fuel min max min max Rank M Dip M Ash Moisture Sulfur M3/Tonne 

Almaznaya 1 a m5 31.7 41490 16584 Coal 8 15 0.02 1.5 HVBb,c 1 11 510 19.5 6.5 3.3 12 

1 a l1 HVBb,c 1.4 11 500 16.5 6.4 1.9 5 

1 a l3 HVBb,c 1.99 11 505 11.3 5.4 1.3 25.5 

Bazhanova 2 b m3 39 74400 Methane 4 6 0.05 0.09 HVBa 1.65 5 1200 8 0.8 3.5 20 

Belitskaya 3 a m2 80 43760 79000 Coal 6 12 0.02 1.9 HVBb 1.12 9.5 233 15.3 4.6 4.6 4.5 

3 a l8 HVBb 0.65 7 435 4.6 4.3 1.2 12.5 

Belozerskaya 4 a m5 13.7 84000 Coal 8 12 0.01 2.5 HVBc 0.9 10 260 14.8 9 3.26 5 

4 a l8 HVBa,b 2.19 615 10 6.4 1.71 15 

4 a l3 HVBb,c 2.29 890 6.8 5.1 1.87 17 

Dobropolskaya 5 a m4 50.7 37539 33340 Coal 5 16 0.03 1.8 HVBb 1 10 550 12 2.9 3.4 14 

5 a m5 HVBb 0.93 530 12.4 2.6 2.6 16 

Faschevskaya 6 b l8 26.71 34030 11071 Coal 8.2 9.5 0.01 0.02 LVB 0.75 15 450 19.1 2 2 30 

6 b l6 LVB 0.85 15 335 30.2 2 2.5 22.5 

6 b m3 LVB 0.76 14 500 15 2 2 30 

Glubokaya 7 b h10 55 73761 36150 Methane 2 6 0.01 0.03 LVB 1.43 25.5 988 12.7 1.3 3.6 32 

7 b h8 LVB 0.7 9 665 11.6 0.7 30 

7 b h6 LVB 0.92 6 570 13.4 2.8 30 

7 b h4 LVB 0.8 6 875 11 0.9 30 

Gorskaya 8 b k8 48.5 62370 42491 Coal 0.01 0.03 HVBc,b 1.8 5 950 16 4.5 4.15 16 

8 b m3 HVBc 1.4 7 900 25 8 4.5 15 

Holodnaya 9 b h10 55.56 44108 81700 Methane 3 6 0.01 0.02 LVB 1.05 11.5 750 14.3 4.1 4.2 18 

Kalinin 10 b h10 28 58969 11613 Methane 3 5 0.01 0.02 HVBa,b/MVB 1.3 20 1240 10.3 2 3.2 23.6 

Kirov 11 b l4 36 55880 14400 Coal 3 7 0.01 0.02 MVB 0.7 6 440 11.2 0.8 1.65 21 

11 b h10 LVB 0.95 7.5 260 13.1 1.2 3.5 30 

11 b l1 MVB 1.1 7 490 20 1.2 2.6 21 

Komsomolets 12 b l7 62.5 146330 71008 Coal 0.7 5.7 0.001 0.001 LVB 1.08 13 709 9.3 2.9 1.9 25 

12 b l4 LVB 1.02 16 709 10.1 3 3.2 25 

12 b l3 LVB 1.38 15 604 12.5 3 2.8 25 

Krasnorarmeyskaya 13 a d4 96 119862 42820 Coal 4.5 21 0.03 1.93 HVBa 1.7 7 645 15.1 1.3 0.9 20 

Krasnolimanskaya 14 a l3 21.4 133800 94220 Oil 4 11 0.06 0.09 HVB 2.19 8 857 12.8 4.1 3.4 20 

14 a k5 HVB 1.64 8 1000 6.5 3.8 1.93 20 

Molodogvardeyskaya 15 c k2 28 40060 12157 Coal 5.9 6.4 HVB 1.875 8 691 12 1.9 3.6 15 

15 c i3 HVB 1.45 8 664.5 13 0.9 3.3 16 

Exhibit 2.4 Summary of Published Data 15 

15 Coal Mine Methane in Ukraine, Opportunities for Production and Investment in the Donetsk Coal Basin, U.S. Environmental Protection Agency, January 2001. 




Power Heat Gas 

Mine Mine Area Consumption Consumption Boiler Thickness Depth Content 

Mine No. Area Seam km2 MW/Yr Gcal Fuel min max min max Rank M Dip M Ash Moisture Sulfur M3/Tonne 

Oktyabrsky 16 b m3 48.58 75825 26900 Coal,Methane 1 

Summary of "Coal Mine Methane in Ukraine: Opportunities for Production and Investment in the Donetsk Coal Basin" 

nd Permeabi 

Sand Porosit md 

5 10 0.01 0.2 HVBb 1.1 10 1200 5.5 28 1 20 

16 b l8 HVBb 1.5 10.5 1060 9.1 2.6 1.4 20 

Rassvet 17 b m3 29.04 9264 Coal 3 5 0.001 0.001 LVB 0.95 10.5 470 9.8 10 3.6 32 

17 b l6 LVB 0.84 14.5 355 8.2 1.3 0.7 30 

17 b l3 LVB 1.27 15 515 26.2 1.3 2.8 30 

Samsonovskaya 18 c k2 3.6 16 0.02 1.9 HVB 1.25 7 785 13.5 2 2 25 

Skochinsky 19 b h6 80 82994 15136 Coal 2 11 0.005 0.02 HVBb 1.5 12 1298 4.6 2.2 1.05 19 

Stakhanov 20 a l7 Coal 6 12 0.08 0.4 HVBb,c 1.25 10 967.5 4.7 3.2 1 15 

20 a k5 HVBb 1.15 11 907.5 4.9 1.9 1 12.8 

20 a l1 HVBb,c 1.1 9.5 912.5 7.3 2.4 2.6 13.5 

20 a l3 HVBc 1.65 8 982.5 9.4 1.9 4.4 15 

Suhodolskaya 21 c i3 58 78819 65770 Coal 4.6 6.6 HVBa 1.45 9.5 906.5 14.5 4 1.1 23.4 

Vynnitskaya 22 b l3 23600 9907 Coal 0.73 3.62 0 0.24 Anth 1 8 430 12 3.5 0.9 29 

22 b i4 Anth 0.95 10 390 11.8 2.3 3.2 29 

Yasinovskaya 23 b l6 52.7 58021 10019 Coal 3 5 0.01 0.08 MVB 1.61 8.5 606 8.6 1.4 1.52 25 

23 b l4 MVB 0.68 5 575 8.2 1 1.14 25 

23 b l2 MVB 1.01 4.5 475 15.9 1.5 2.62 25 

Yuzhnodonbasskaya #1 24 b c18 48 72200 36642 Coal 3.7 19.9 0.05 5.88 HVBc 0.8 5 355 5.5 5 0.95 6.5 

24 b c13 HVBc 0.75 4.5 480 5 6.5 1 6.5 

24 b c11 HVBc 1.3 5.5 480 6.1 6.2 1.1 10 

24 b c10 HVBc 1.075 6 480 4.9 6 2.2 7.5 

Yuzhnodonbasskaya #3 25 b c11 47 112836 65842 Coal 8 13 0.05 2.7 HVBa 1.65 9 624 6.6 6 1 13 

Zasyadko 26 b m3 215000 163972 Coal/Methane 5 11 0.02 0.03 HVBb 1.8 8.5 1175 4.8 1 2.3 23 

26 b l4 HVBb 1 10.5 726 4.3 1 0.8 19.5 

26 b l1 HVBb 1.85 14 990 9.3 0.8 3.2 21 

26 b k8 HVBb 0.9 14 950 9.2 1 1.5 20 

Zhdanovskaya 27 b l7 27.2 35600 41000 Coal 3 8 0.08 0.4 LVB 1.55 17.5 660 7.1 4.1 2.3 25 

27 b l4 LVB 1.1 18 548 13.4 3 3.1 30 

27 b l6 LVB 1.12 17 567 9.6 3.5 1.3 32.5 

27 b l3 LVB 1.3 18 470 8.1 1.4 2 27.5 

Zuyevskaya 28 b k5 20 34308 32380 Coal 2 7 0.002 0.03 LVB 1.03 19 577 9.7 7.1 1.2 32.5 

28 b k3 LVB 1.45 21.5 560 11.4 8.9 2.2 32.5 

28 b k2 LVB 1.05 22 525 13.7 9.4 2.1 27.5 

50 Years of the USSR 29 c k2 14 89800 19393 2.4 9 HVBb 1.77 30 497.5 12.3 3.9 4.4 32 

29 c i3 HVBb,a 1.18 23 680 13.6 2.9 2.8 NA 

Exhibit 2.5 Summary of Published Data (cont..) 16 

16 Coal Mine Methane in Ukraine, Opportunities for Production and Investment in the Donetsk Coal Basin, U.S. Environmental Protection Agency, January 2001. 


Gas Content (m 3 /tonne) 

25 

20 

15 

10 

5 

- 



Gas Content vs. Pressure (Depth x 0.433 psi/ft) for the Donetsk Coal Basin 

0 200 400 600 800 1000 1200 1400 1600 1800 2000 

Pressure (psia) 

Exhibit 2.6 Donetsk Basin Gas Isotherm Derived from Gas Content Data 

For the Langmuir volume, COMET3 utilizes units of standard cubic feet of gas per cubic foot 

(SCF/CF) of bulk volume for coal. Assuming a coal density of 1.6 gm/cc, the Langmuir 

volume of 27 m 3 /tonne converts to 43.2 SCF/CF. 

2.2.4 Relative Permeability 

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 starts and the pressure in the cleat system begins 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 (frac.) 

0.2 

0.1 

0 



2.2.4.1 Coal Relative Permeability 

Relative permeability data for the coal of the Donetsk basin does not exist, therefore ARI 

used a relative permeability data set derived from a production history matching effort on the 

Recopol 17 project in Poland, which we believe to be a suitable analogue for the Donetsk 

Basin. The Recopol project is a pilot project designed to determine whether CO2 can be 

sequestered in the coal seams. Because of the research nature of the project, a tremendous 

amount of reservoir data has been collected and is available for study. ARI believes that the 

Recopol data should be somewhat representative of Donbass Basin coal seams as they are 

age-equivalent and have experienced similar tectonic histories. However, ARI recognizes 

that there could be variation between the two coal basins. Exhibit 2.7 is a graph of the 

relative permeability curves that are used in the reservoir simulation. 

With 100% water occupying the pore space, the permeability is equal to the absolute 

permeability (0.1 md for this study). With the onset of water production from the coal, 

pressure is drawn down in the formation and gas begins to desorb from the coal and into its 

porous fracture network. At this early stage of production, most of the pore space is still 

1 

occupied by water, which 

enables the water phase to 

0.9 

move through the porosity more 

0.8 

easily due to the fact it’s the 

0.7 

more continuous phase. At the 

0.6 

same time, the continuous 

0.5 

water phase is offering 

0.4 

resistance to gas movement 

0.3 

through the porosity. 

0.45 0.5 0.55 0.6 0.65 0.7 0.75 0.8 0.85 0.9 0.95 1 

Water Saturation 

CH4 Water 

Exhibit 2.7 Donetsk Basin Coal Relative Permeability 

17 Development of a field experiment of ECBM in the Upper Silesian coal basin of Poland (RECOPOL) - F. van Bergen, H.J.M. 

Pagnier, L.G.H. van der Meer, F.J.G. van den Belt and P.L.A. Winthaegen, Netherlands Institute of Applied Geoscience TNO (the 

Netherlands), P. Krzystolik, Central Mining Institute (Poland) 




2.2.4.2 Sandstone Relative Permeability 

Sandstone relative permeability in the Donetsk basin is unknown. Therefore, Advanced 

Resources has used relative permeability data from a similar tight gas formation in the U.S. 

with a permeability of 0.62 md. The relative permeability curve assumed for sandstone 

reservoirs of the Donetsk basin is shown in Exhibit 2.8. 

Relative Permeability (frac.) 

1 

0.9 

0.8 

0.7 

0.6 

0.5 

0.4 

0.3 

0.2 

0.1 

0 

Donetsk Basin Sand Relative Permeability 

0.3 

0.35 

0.45 

0.6 

0.65 

0.7 

Water Saturation 

CH4 Water 

0.75 

0.8 

0.85 

0.9 

0.95 

Exhibit 2.8 Donetsk Basin Sand Relative Permeability 

Reservoir Simulations 2-9 

1



2.2.5 Reservoir (Coal and Sand) Depth and Thickness. 

Reservoir thickness and depth for the prospective coal seams and sandstones have been 

documented in the geological section and are summarized in Exhibit 2.9. The model 

assumes that six individual zones will be hydraulically fractured in the well. Because of the 

interbedded nature of the coal seams and sandstones, it was assumed that the hydraulic 

fracture would be initiated in a sand unit and grow into the overlying and underlying coal 

seams. 

Donetsk Coal Basin 

Typical Well Completion Intervals and Coal and Sand Thickness 

Gross Interval 

Net Coal Net Sand 

Top Bottom Thickness Thickness 

Stage (m) ft (m) ft (m) ft (m) ft 

1 1041 3415 1051 3448 1.02 3.3 2 6.6 

2 980 3215 1009 3310 1.22 4.0 3 9.8 

3 948 3110 955 3133 2.3 7.5 1 3.3 

4 862 2828 868 2848 1.11 3.6 15 49.2 

5 759 2490 819 2687 2.86 9.4 8 26.2 

6 741 2431 745 2444 1.48 4.9 2 6.6 

Total 9.99 32.8 31 101.7 

Exhibit 2.9 Typical Depth and Thicknesses for Coal and Sand in a Donetsk Region well 

2.2.6 Well Completion and Model Construction 

Vertical wells are projected to be drilled and completed to a depth of 1100 m (3600 ft) and 

completed in six stages using either a ball and baffle or bridge plug and tubing/packer 

technique. 

Advanced Resources has presented a forecast for coal only, as well as a forecast which 

includes both coal and sandstone reservoirs. The combined coal and sandstone production 

forecast is considered to be the most likely case as the sandstone would likely be stimulated 

even if only the coals were targeted. Note that in several CBM basins in the U.S., such as 

the Piceance and Cherokee basins, that operators routinely target both coals and associated 

sands. 

Based on typical coal and sand depth and thickness (Exhibit 2.9), a three layer model was 

constructed each for the coal and for the sandstone. Exhibit 2.10 shows the depths and 

thickness values that were used for the reservoir simulation. In Exhibit 2.10: layer 1 is an 

average of stages 5&6 from Exhibit 2.9; layer 2 is modeled as stage 4 in Exhibit 2.9; layer 3 

is an average of stages 1,2 & 3 in Exhibit 2.9. 




The gas water contact (GWC) serves as the reference point for pressure calculations in the 

model. For purposes of the Donetsk basin reservoir simulation, a GWC of 550 m (1800 ft) 

was selected, and model pressures are calculated for all layers based on a water gradient of 

9.81 kPa/m (0.433 psi/ft) from this depth at 5374 kPa (779.4 psia). 

Model 1 - Coal Only 

GWC 1,800.0 

Layer 1 2,558.4 

Layer 2 2,866.7 

Layer 3 3,278.4 

Model 2 - Sand 

GWC 1,800.0 

Layer 1 2,558.4 

Layer 2 2,866.7 

Layer 3 3,278.4 

Donetsk Coal Basin Model Construction 

Formation 

Formation 

Mid 

Formation Formation Pressure Formation 

Point 

Top Thick @ top Temp 

(ft) (m) (ft) (m) (ft) (m) (psia) (kPa) deg F deg C 

548.8 779.4 

780.0 2551.3 777.8 14.24 

874.0 2864.9 873.4 3.64 

999.5 3270.9 997.2 14.89 

4.3 1,107.8 

1.1 1,241.3 

4.5 1,419.5 

548.8 779.4 

780.0 2,551.3 

874.0 2,864.9 

999.5 3,270.9 

777.8 32.8 10.0 1,107.8 

873.4 49.2 15.0 1,241.3 

997.2 19.68 6.0 1,419.5 

Reservoir Simulations 2-11 

5374 

7638 160.5 

8558 171.6 

9787 186.4 

5374 

7638 160.5 

8558 171.6 

9787 186.4 

Exhibit 2.10 Modeled Depth and Thickness of Coal and Sand for Reservoir Simulation 

71 

77.5 

86 

71 

77.5 

86



2.2.7 Porosity and Initial Water Saturation 

In the coal seams, we used a porosity value of 1% and initial water saturation of 100%. 

Again, porosity of 1% was used in the simulations since it matches the results of reservoir 

simulation history matching carried out on the Recopol 18 project in Poland. 

Porosity estimates for the sandstone reservoir have been obtained from published data of 

the Donetsk Region 19 . Water saturation for the sandstone reservoirs has been measured in 

geophysical logs and average about 56 percent. This water saturation is higher than the 

typical residual sandstone water saturation with permeability of 0.62 md, therefore it is 

expected that initial well production will include a component of water production from the 

sandstone reservoirs. 

Wells drilled in the Donetsk basin have produced both water and gas from sandstone 

reservoirs. Based on the relative permeability curve (Exhibit 2-9) the residual water 

saturation in the Donetsk basin is assumed to be 25 percent. 

2.2.8 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, sorption time has been assumed to be 12 days. 

2.2.9 Spacing 

In consultation with Ecometan and the panel of Ukrainian experts, the decision was made to 

run reservoir simulations on a well spacing pattern of 0.25 Km 2 (60 Ac) on the South 

Donbass concession, which would allow the drilling of up to 1600 wells over their 400 km 2 

lease block. Using the same spacing pattern on the 550 km 2 Grishino-Andreyevskaya lease 

block would allow the drilling or up to 2200 wells. 

In the United States, where the natural gas industry is well developed, operators typically 

develop relatively tight sandstones (i.e., 1 md or less) on spacing patterns of 60 acres (0.25 

Km 2 ) or less. Spacing on the order of 16-32 hectares (40-80 acres) is common, with some 

operators going down to spacing as tight as 4 hectares (10 acres). 

18 

Development of a field experiment of ECBM in the Upper Silesian coal basin of Poland (RECOPOLl) - F. van Bergen, H.J.M. 

Pagnier, L.G.H. van der Meer, F.J.G. van den Belt and P.L.A. Winthaegen, Netherlands Institute of Applied Geoscience TNO (the 

Netherlands), P. Krzystolik, Central Mining Institute (Poland) 

19 

Coal Mine Methane in Ukraine, Opportunities for Production and Investment in the Donetsk Coal Basin, U.S. Environmental 

Protection Agency, January 2001. 


2.2.10 Simulation Results: 



Reservoir simulation of the geologic and engineering data of the Donetsk basin examined 

two cases. Coal fracture system absolute permeability was modeled with an absolute 

permeability value of 0.1 md on 0.25 Km 2 (60 Acre) spacing. (60 acre spacing is 

approximately 4 wells per km 2 ) Production estimates for coal only, and estimates for coal 

and sandstone units combined have been modeled. 

The two cases examined include the following: 

Coal permeability = 0.1 md, 0.25 km 2 spacing. 

Coal permeability = 0.1 md, 0.25 km 2 spacing, sandstone units included. 

Exhibit 2.11 is a summary of the cumulative gas and water that is generated by each case 

that was examined with reservoir simulation. Graphical results are presented in Exhibit 2.12 

through 2-15. 

Summary of Simulation Results 

Cumulative Cumulative 

Permeability Gas Water 

Spacing (md) Formation (mcm) (m 3 ) 

Case 1 60 Ac 0.1 Coal 1,465 

Case 2 60 Ac 0.1 / 0.67 Coal & Sand 20,883 

Exhibit 2.11 Summary of Simulation Results 

4,474 

5,985 

Exhibit 2.16 provides a tabular listing on a yearly basis of the amount of gas and water 

produced by each of the simulation cases evaluated. 

Additional reservoir simulations were run to examine a higher permeability case of 1.0 md in 

the coal, as well as the effect of larger spacing on production. The results of this sensitivity 

study are presented in Appendix A and indicate that the base case presented above and 

used in the economic analysis represents the most likely production scenario. 


(Gas (m 3 /hour), Water (m3/hour X 100) 

Gas (thousand m 3 ), Water (m 3 / 10) 

10 

9 

8 

7 

6 

5 

4 

3 

2 

1 

- 

1,000 

900 

800 

700 

600 

500 

400 

300 

200 

100 

- 



Donetsk Basin Simulation Results 

Coal Permeability = 0.1 md, 60 Acre Spacing, Coal Only 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 

Years 

Exhibit 2.12 Simulation Results - Case 1 

Gas Water 


Coal Permeability = 0.1 md, 60 Acre Spacing, Coal Only 

1 2 3 4 5 6 7 8 9 101112131415161718192021222324252627282930 

Years 


Gas Water 


(Gas (m3/hour), Water (m3/hour X 100) 

Gas (thousand m3), Water (m3 / 10) 

1,000 

900 

800 

700 

600 

500 

400 

300 

200 

100 

- 

22,000 

20,000 

18,000 

16,000 

14,000 

12,000 

10,000 

8,000 

6,000 

4,000 

2,000 

- 




Coal Permeability = 0.1 md, 60 Acre Spacing, Coal & Sandstone 

1 2 3 4 5 6 7 8 9 101112131415161718192021222324252627282930 

Years 


Gas Water 



1 2 3 4 5 6 7 8 9 101112131415161718192021222324252627282930 

Years 


Gas Water 




Case 1 

Case 2 

60 Acre, Coal K = 0.1md, Coal Only 

60 acre, Coal K = 0.1md, with Sandstone 

Cumulative Gas Cumulative Water Cum. Gas Cum.Water 

51,709 

28,142 

737,156 

37,644 

Gas Gas Water Water Gas Gas Water Water 

Year mcf dec. bbl dec. Year mcf dec. bbl dec. 

1 2,098 0.0406 1,105 0.0393 

1 296,115 0.4017 3,285 0.0873 

2 1,555 0.0301 845 0.0300 

2 129,525 0.1757 2,067 0.0549 

3 1,394 0.0270 793 0.0282 

3 71,375 0.0968 1,655 0.0440 

4 1,327 0.0257 755 0.0268 

4 44,881 0.0609 1,413 0.0375 

5 1,273 0.0246 731 0.0260 

5 30,814 0.0418 1,258 0.0334 

6 1,226 0.0237 715 0.0254 

6 22,465 0.0305 1,151 0.0306 

7 1,190 0.0230 703 0.0250 

7 17,153 0.0233 1,072 0.0285 

8 1,160 0.0224 692 0.0246 

8 13,556 0.0184 1,010 0.0268 

9 1,136 0.0220 684 0.0243 

9 11,025 0.0150 961 0.0255 

10 1,116 0.0216 676 0.0240 

10 9,172 0.0124 920 0.0244 

11 1,098 0.0212 669 0.0238 

11 7,775 0.0105 886 0.0235 

12 1,081 0.0209 663 0.0236 

12 6,696 0.0091 857 0.0228 

13 1,067 0.0206 658 0.0234 

13 5,849 0.0079 833 0.0221 

14 1,053 0.0204 653 0.0232 

14 5,170 0.0070 811 0.0216 

15 1,041 0.0201 649 0.0230 

15 4,615 0.0063 793 0.0211 

16 1,030 0.0199 645 0.0229 

16 4,156 0.0056 776 0.0206 

17 1,020 0.0197 640 0.0228 

17 3,774 0.0051 761 0.0202 

18 1,012 0.0196 637 0.0226 

18 3,453 0.0047 747 0.0199 

19 1,004 0.0194 633 0.0225 

19 3,180 0.0043 735 0.0195 

20 998 0.0193 629 0.0224 

20 2,946 0.0040 723 0.0192 

21 993 0.0192 625 0.0222 

21 2,746 0.0037 712 0.0189 

22 989 0.0191 621 0.0221 

22 2,573 0.0035 702 0.0186 

23 987 0.0191 617 0.0219 

23 2,423 0.0033 691 0.0184 

24 987 0.0191 612 0.0217 

24 2,293 0.0031 681 0.0181 

25 989 0.0191 606 0.0215 

25 2,180 0.0030 670 0.0178 

26 992 0.0192 600 0.0213 

26 2,081 0.0028 660 0.0175 

27 997 0.0193 593 0.0211 

27 1,996 0.0027 649 0.0172 

28 1,005 0.0194 586 0.0208 

28 1,923 0.0026 639 0.0170 

29 1,014 0.0196 579 0.0206 

29 1,859 0.0025 628 0.0167 

30 1,002 0.0194 559 0.0199 

30 1,767 0.0024 604 0.0161 

31 991 0.0192 541 0.0192 

31 1,679 0.0023 582 0.0155 

32 980 0.0190 523 0.0186 

32 1,596 0.0022 560 0.0149 

33 970 0.0187 505 0.0179 

33 1,517 0.0021 539 0.0143 

34 959 0.0185 488 0.0173 

34 1,442 0.0020 519 0.0138 

35 948 0.0183 472 0.0168 

35 1,370 0.0019 499 0.0133 

36 938 0.0181 456 0.0162 

36 1,302 0.0018 481 0.0128 

37 927 0.0179 441 0.0157 

37 1,238 0.0017 463 0.0123 

38 917 0.0177 426 0.0151 

38 1,176 0.0016 445 0.0118 

39 907 0.0175 412 0.0146 

39 1,118 0.0015 429 0.0114 

40 897 0.0173 398 0.0141 

40 1,063 0.0014 413 0.0110 

41 887 0.0172 384 0.0137 

41 1,010 0.0014 397 0.0106 

42 877 0.0170 372 0.0132 

42 960 0.0013 382 0.0102 

43 868 0.0168 359 0.0128 

43 912 0.0012 368 0.0098 

44 858 0.0166 347 0.0123 

44 867 0.0012 354 0.0094 

45 849 0.0164 335 0.0119 

45 824 0.0011 341 0.0091 

46 839 0.0162 324 0.0115 

46 783 0.0011 328 0.0087 

47 830 0.0160 313 0.0111 

47 744 0.0010 316 0.0084 

48 821 0.0159 303 0.0108 

48 707 0.0010 304 0.0081 

49 812 0.0157 293 0.0104 

49 672 0.0009 293 0.0078 

50 803 0.0155 283 0.0101 

50 639 0.0009 282 0.0075 

Exhibit 2.16 Tabular Type Curve Production Data 


2.3 CMM Reservoir Modeling 



For the CMM portion of the study, detailed modeling of the rate and quality of the gas 

produced is a difficult and complex task because of the interaction between the geologic 

conditions, mine advance rates, and degasification drilling programs. Furthermore, accurate 

modeling would require detailed data on all of the strata affected in the gob area (e.g. 

permeability, gas saturation, porosity, etc.), data that are not readily available. Therefore, the 

estimate of CMM production from each mine is based on historical CMM production rates for 

each mine and coal production forecasts for the life of the project. 


Task 2 



Screen Applicable Technologies - 

Drilling, Completion and Stimulation Design 

Drilling, Completion and Stimulation Design 2-i




2.1 Introduction........................................................................................................................2-1 

2.2 CBM Well Drilling, Completion and Stimulation.................................................................2-1 

2.2.1 Well Design.................................................................................................................2-3 

2.2.1.1 Drilling ................................................................................................................2-3 

2.2.1.2 Casing ................................................................................................................2-7 

2.2.1.3 Geophysical Logging and Wire Line Operations ................................................2-9 

2.2.1.4 General Cementing Design ..............................................................................2-10 

2.2.2 Stimulation................................................................................................................2-15 

2.2.3 Post Hydraulic Fracture Injection Fall-off Testing .....................................................2-25 

2.3 CMM Drainage Techniques .............................................................................................2-26 

2.3.1 Pre-Mining Degasification.........................................................................................2-28 

2.3.2 Gob Degasification ...................................................................................................2-30 

2.3.2.1 Surface Drilled Gob Wells. ...............................................................................2-30 

2.3.2.2 Cross-Measure Boreholes................................................................................2-32 

2.3.2.3 Superjacent Techniques...................................................................................2-32 

2.3.2.4 In-Mine Directionally Drilled Gob Boreholes.....................................................2-32 

2.4 Recovery of Gas from Sealed Areas ...............................................................................2-34 

2.5 Gas Collection .................................................................................................................2-34 

2.6 Methane Drainage Practices In Ukraine ..........................................................................2-36 

2.6.1 Pre-Mining Degasification.........................................................................................2-36 

2.6.1.1 Vertical Wells....................................................................................................2-36 

2.6.1.2 Underground Boreholes ...................................................................................2-36 

2.6.2 Gob Degasification ...................................................................................................2-37 

2.6.2.1 Vertical Gob Wells............................................................................................2-37 

2.6.2.2 Cross-Measure Boreholes................................................................................2-37 

2.6.3 Gas Collection ..........................................................................................................2-38 

2.7 Proposed Methane Drainage Technology for Ukraine.....................................................2-39 

2.7.1 Application of Directional Drilling for Gob Gas Recovery .........................................2-39 

2.7.1.1 Considerations for the Application of Directionally Drilled Horizontal Gob 

Boreholes .........................................................................................................2-41 

2.7.1.2 Directional Drilling Application at the Krasnolimonskaya Mine.........................2-43 

2.7.1.3 Directional Drilling Application at the Belozyorskaya Mine...............................2-45 

2.8 Directional Drilling Applications at the Bazhanov and South Donbass #3 Mines ............2-47 

Drilling, Completion and Stimulation Design 2-ii



TASK 2 EXHIBITS 

Exhibit 2.1 Ingersoll-Rand RD 20 Drill Rig ..........................................................................................2-3 

Exhibit 2.3 Donbass Basin Drill Prognosis for a Full-Field Development Well....................................2-6 

Exhibit 2.4 Pipe Specifications and Material for the 5-Spot Pilot Wells...............................................2-7 

Exhibit 2.5 Balls and Baffles of Varying Size used for Zone Isolation.................................................2-8 

Exhibit 2.6 Logging truck units.............................................................................................................2-9 

Exhibit 2.7 Guide Shoe......................................................................................................................2-12 

Exhibit 2.8 Cement Wiper Plug..........................................................................................................2-13 

Exhibit 2.9 Donbass Basin Cement Materials Required for the Five Well Pilot ................................2-14 

Exhibit 2.10 Fracture Optimization Process ........................................................................................2-16 

Exhibit 2.11 Completion Zones with Hydraulic Fracturing Stages for a Type Well in the 

Donbass Basin.................................................................................................................2-18 

Exhibit 2.12 Sand Dump, Blender and Fracturing Pumps...................................................................2-19 

Exhibit 2.13 Hydraulic Fracturing Program Design .............................................................................2-20 

Exhibit 2.14 Schematic of a Typical U.S. Hydraulic Fracturing Treatment .........................................2-21 

Exhibit 2.15 Graph of Pressure versus Time used to determine Closure Pressure............................2-22 

Exhibit 2.16 Example of a Tip Screenout ............................................................................................2-22 

Exhibit 2.17 Materials Required for Hydraulically Fracturing 5 Wells..................................................2-24 

Exhibit 2.18 Coal Degasification: Production through Utilization ........................................................2-27 

Exhibit 2.19 In-Seam Boreholes Drilled across Longwall Panels during Gateroad Development to 

Reduce the Gas Content of the Longwall Panel Prior to Mining .....................................2-28 

Exhibit 2.20 Long In-Seam Boreholes Directionally Drilled along the Longitudinal Axis of the Longwall 

Panels in Advance of Gateroad Development ................................................................2-29 

Exhibit 2.21 General Description of Gob Gas Recovery Methods ......................................................2-30 

Exhibit 2.22 Illustration of Vertical Drilled Gob Well ............................................................................2-31 

Exhibit 2.23 In-Mine Directionally Drilled Gob Boreholes placed in an Underlying Coal Seam and above 

the Mining Seam..............................................................................................................2-33 

Exhibit 2.24 Vacuum Pump - Vertical Gas Gob Well ..........................................................................2-35 

Exhibit 2.25 Gas Handling and Collection System..............................................................................2-35 

Exhibit 2.26 Boreholes Drilled Immediately in Advance of Mine Developments to Target Gas..........2-37 

Exhibit 2.27 Cross-Measure Boreholes applied from Tailgate Entry for Single Entry Retreat Longwall 

Mining as implemented in some Ukrainian Mines. ..........................................................2-38 

Exhibit 2.28 Long Hole Directional Drills .............................................................................................2-40 

Exhibit 2.29 Demonstration of Directionally Drilled Horizontal Gob Borehole planned for the 

Krasnolimonskaya Mine ..................................................................................................2-44 

Drilling, Completion and Stimulation Design 2-iii



Exhibit 2.30 Plan for the Dual Purpose Horizontal Boreholes at the Krasnolimonskaya Mine ...........2-45 

Exhibit 2.31 Horizontal Gob Boreholes Planned for the 8th Southern Longwall Panel at the 

Belozorskaya Mine ..........................................................................................................2-45 

Drilling, Completion and Stimulation Design 2-iv




This section presents the technical designs for the drilling and completion of both CBM wells 

and CMM-related wells and boreholes. The design of the CBM wells incorporates strategies for 

completing both the coal and tight gas sand reservoirs in the wellbore utilizing vertical, 

hydraulically fractured wells. For the CMM boreholes, several different drilling methods are 

examined including in-mine horizontal wells, vertical gob wells and cross-measure boreholes. 

2.2 CBM Well Drilling, Completion and Stimulation 

This section sets forth the recommended drilling, completion and stimulation designs for a 

CBM project in the Donbass Coal Basin. All relevant specifications and guidelines for the 

above procedures are provided. Specifically, this section covers: 

A preliminary CBM production well design; 

Recommended casing and cementing designs and procedures; 

Hydraulic stimulation design; 

Recommendations for artificial lift. 

The depths to the target reservoirs across the Donetsk Region vary greatly, with the deeper 

parts of the basin at 1,500+m to shallower coal seams in the 200 meter depth range. This 

section outlines a recommended well design based on an “average” coal bed methane well 

depth of about 1,100 m (3,600 ft) including a sump or “rat hole”. It is expected that 

recommendations will evolve as knowledge is acquired during development of the project. 

For example, larger size casing may be used in the down dip portion of a structure in a field 

to maximize water production and accelerate the de-watering of the reservoir. Some areas 

of the field may have more target intervals available or a higher concentration of natural 

fractures in the reservoir, thereby increasing the amount of produced water and the need for 

larger well bores. 

Drilling, Completion and Stimulation Design 2-1



The following criteria will ultimately determine the final casing size, completion type, and 

artificial lift equipment: 

Maximum depth of the productive intervals; 

Number of productive intervals completed; 

Maximum water production to draw down the reservoir; 

Reservoir pressure of each coal seams/productive intervals. 

Advanced Resources presents two well designs and completion methods for the project. 

These design and completion practices can be used interchangeably. 

The first design, recommended for the full-field development scenario, utilizes 114mm (4 ½inch) 

casing in the hole and is completed using a ball and baffle technique to hydraulically 

fracture the target intervals. This method can be used to stimulate up to 7 individual zones in 

a well with off the shelf equipment. 

The second well design utilizes a 140 mm (5 ½-inch) casing string in the hole and isolates 

the individual zones for completion with drillable composite bridge plugs. The number of 

zones completed in a well will hinge on the volume of water from each zone and the relative 

reservoir pressures between zones. This assumes there are no regulatory restrictions and 

all coal seams are gas saturated and economic to produce. 

The larger well bore is an advantage where a greater number of zones are completed or the 

water volumes require higher capacity production equipment. The larger casing provides 

added flexibility during drilling, completion, and production operations. Advanced Resources 

recommends using the 140 mm (5 ½-inch) completion for the initial 5-well pilot phase of the 

project or until more information is known about the reservoir. 


2.2.1 Well Design 



2.2.1.1 Drilling 

The depth of individual wells over the two coalbed methane license areas varies 

considerably. In both areas, the main section of coal is between 500-850 meters in depth and 

wells have been drilled in varying depths from 200 to 1,500 meters. An average target depth 

of 1,100 meters (3600 ft), including a sump or “rat-hole”, is used for design purposes. The 

sump at the bottom of the well facilitates placement of the production equipment below 

perforations. A drill rig rated to 1,400 meters (4600 ft) with a pull-back rating of at least 50 

metric tons (110,000 lbs) is recommended. Experience may allow downsizing of the rig as 

drilling becomes routine and the reservoir is better understood. A rig common to the 

Appalachian Basin is the Ingersoll-Rand RD-20 hydraulic top drive (Exhibit 2.1). The pullback 

rating is 50 metric tons (110,000 lbs). Properly configured this rig routinely drills 165 

mm (6 ½ -inch) hole to run 140 mm (5 ½-inch) casing over 1,200 meters (4,000 ft). 

Exhibit 2.1 Ingersoll-Rand RD 20 Drill Rig 

Most wells drilled in the Appalachian Basin (including many CBM wells) use compressed air 

as a carrying fluid (Note that the Appalachian Basin has some similarities to the Donetsk 

Basin as both have numerous thin seams in the stratigraphic section). Drilling “on air” 

maximizes penetration rates with rates over 30 m (100 ft) per hour achievable. A typical 

compressor package would include a primary compressor, such as a Sullair 2400kP/255 

cubic meters per minute (cmm) (350 psi /900 cubic feet per minute (cfm)) rig compressor, an 




auxiliary compressor of similar rating and a booster, for example a Joy 7900kP/66 cmm 

(1,150 psi/2,200 cfm). The compressor package is sized by the rate of circulation (velocity) 

needed to clean the hole while drilling and varies depending on the rig. A triplex rig pump 

capable of 0.5-0.8 cmm (3-5 bpm) at 6900kP (1,000 psi) and a 16 m 3 (100 bbl) steel mud pit 

with hydro-cyclone is necessary to drill on mud if water influx becomes a problem. 

Drilling with air/mist is also advantageous because it limits potential filtration damage to coal 

(mud cake), reduces loss-of-circulation problems, provides straighter holes because of less 

weight-on-bit, and is lower cost because no mud is required. However, air/mist drilling will 

not allow lifting of large volumes of water, and equipment such as bits and drill pipe can wear 

more quickly due to sand blasting effects. Selection of drill pipe diameter and compressor 

rate and horsepower are important to ensure the ability to lift cuttings. 

The hole should be started by hammering/drilling a 410 mm (16-inch) conductor pipe to 10- 

30 m (30-100 ft) or until bedrock is attained. The surface string should be drilled with a 270 

mm (10 5 /8-inch) air hammer or rotary cone bit to 61 m (200 ft) (actual depth determined by 

regulatory need or surface water flows) and 220 mm (8 5 /8-inch) casing run to the bottom. 

The intermediate casing string should be cemented and drilled out with a 190 mm (7 3 /8-inch) 

air hammer or rotary cone bit to 1,150 m (3,650 ft). The 140 mm, 740kP (5 ½-inch, 15.5 

pound per foot), K-55 casing should then be run to bottom and cemented in place over the 

coal seams. 

The given depths are assumed for the purpose of design; actual depths will be determined 

by the geophysical logs of individual wells. Dry hole drilling can require as little as 0.28 cmm 

(10 cfm) to lift cuttings to surface, whereas water influx in the well bore may require several 

hundred cfm to clean the hole and fire the air hammer. is the drilling prognosis for a pilot well 

in the project area and Exhibit 2.3 presents a drilling prognosis for a full-field development 

well. 




Donbass Basin 

DEPTH DESCRIPTION 

FT. M WELL NUMBER LEASE NAME Donbass Basin LEASE # 

0 Conductor 0 DISTRICT QUAD 

50 16" 75#, J-55 15.2 DATE 6/14/2007 COUNTY API # 

100 30.5 TARGET 3,600 ft. ELEVATION STATE Ukraine 

150 CSG SHOE hole 45.7 

200 8 5/8" 32#, K-55 10 5/8" 61 DRILLING ACTIVITY PROGNOSIS Drill Time Curve 

250 

Class G w/ 2% CaCl 76.2 Project Day Activity 

Elapsed 

Time, 

hrs. Depth 

300 

500 

91.5 

152 

- 

1 

RU, install diverter & blooie line. 

Spud & air drill 10 

0 0 

5 / 8 in. hole to 65 m. 12 65 

750 229 1 Run 8 5 / 8 in., 32 ppf, K-55, R-II Casing to 61 m. 4 65 

1000 305 2 Cement Csg & WOC. 12 65 

1050 

1100 

320 

335 

2 

3 

Nipple up csg head, BOP & Diverter 

Air drill 7 

5 65 

3 1150 351 3 

/ 8 in. hole to 450 m. 

Trip bit, rig maintenance, etc. 

29 

10 

450 

450 

1200 366 5 Air drill 7 3 / 8 in. hole from 450 - 1,120 m. 37.5 1120 

1250 381 5 Open hole geophysical logging 8 1120 

1300 396 6 TOOH, pick up casing tongs, RIH w/ csg 4 1120 

1350 

1400 

412 

427 

6 

10 

Set 5 ½ in., 15.5 ppf, K-55, R-III csg to 915 m. 

Cmt long string & WOC 

6 

36 

1120 

1100 

1450 442 13 Perforate and complete target 72 

1500 457 Metric 

1600 488 Well Type: Donbass Basin Prospect - CBM Cement: Yield circ wtr 3 m 3 

1700 518 Mud Type: Air drill 10 5/8" hole for surface casing to 65 m. Surface Casing: Class G w/ 2% CaCl 1.43 gel 0.8 m 3 

1800 549 Air drill 7 3/8" hole for long string to 1120 m. Bk circ w/19 bw, 5 bbls gel, 5 bbls spacer. Pump 11 bbls, spacer 0.8 m 3 

1900 579 14 ppg cmt. SD c/u lines, displace w/ 7.9 bbls treated water. cmt 1.75 m 3 

2000 610 Drilling Details: Bit Size: Csg Size: Grade: Depth: Prep to drill out cmt. treat wtr 1.26 m 3 

2100 640 API / Metric inches m Intermediate Casing: 

2200 671 Conductor - - 16" 75#, J-55 5 

2300 701 Surface String - 10 5/8" 8 5/8" 32#, K-55 61 

2400 732 Intermediate - - - - - 

2500 762 Long String - 7 3/8" 5 1/2" 15.5#, K-55 1,100 Production Casing: ARI Lite w/ 2% CaCl 1.95 

2600 793 Bk circ w/ 150 bw, 30 bbls gel, 10 bbls spacer. Pump 111 circ wtr 24 m 3 

2700 823 bbls, 13.6 ppg cmt. SD c/u lines, displace cmt w/ 85.7 bbls gel 4.8 m 3 

2800 854 treated water. Est. 1,000 psig surface to seat plug. spacer 1.6 m 3 

2900 884 cmt 17.7 m 3 

3000 915 treat wtr 13.70 m 3 

0 

Time (Days) 

100 

200 

300 

400 

500 

+ 

600 

700 

800 

900 

0.0 2.0 4.0 6.0 8.0 10.0 12.0 

3100 945 Size Description ID Vol Vol Yield Column Volume # Sacks Bbls BBL CMT 

3200 976 inches inches bbls/ft cu ft/ft cu ft/sk ft cu ft sk/ft xcess→ 25% 

3300 1006 Hole 10 5/8 10.625 0.1096568 0.61572 1.43 10.0 6.157 0.43057 4.31 1.10 

3400 1037 Csg 8 5/8 32 #, K-55 7.92 0.06093 0.34212 200.0 68.424 12.19 

3500 CSG SHOE PBTD 1067 An 8 5/8"x10 5/8" 0.03740 0.2100 1.43 200.0 41.997 0.14684 29.37 7.48 10.72 

3600 5 1/2" 15.5#, K-55 hole 3,600.0 1098 Hole 0 0.000 0.00 

3675 ARI Lite w/ 2% CaCl 7 3/8" 1120 Csg 0.000 0.00 

3,675 

An 0 0.000 

Hole 7 3/8 7.375 0.05283 0.32759 1.95 75.0 24.569 0.16799 12.60 4.38 

Csg 5 1/2 15.5 #, K-55 4.95 0.02380 0.13364 3,600.0 481.105 85.68 

An 5 1/2"x 7 3/8" 0.02345 0.1317 1.95 3,600.0 474.000 0.06752 243.08 84.42 110.99 

Exhibit 2.2 Donbass Basin Drill Prognosis and Cement Program for a Pilot Well 




Donbass Basin 

DEPTH DESCRIPTION 

FT. inches inches M WELL NUMBER LEASE NAME Donbass Basin LEASE # 

0 Conductor 0 DISTRICT QUAD 

50 16 75#, J-55 15.2 DATE 6/14/2007 COUNTY API # 

100 30.5 TARGET 3,600 ft. ELEVATION STATE Ukraine Job Param 

150 CSG SHOE hole 45.7 API 

200 7 5/8 20#, K-55 9 5/8 61 DRILLING ACTIVITY PROGNOSIS Drill Time Curve 16.1 bbls 

Elapsed 

Time, 

250 Class G w/ 2% CaCl 76.2 Project Day Activity 

hrs. Depth 2.4 bbls 

300 

350 

91.5 

107 

- 

1 

RU, install diverter & blooie line. 

Spud & air drill 9 

0 0 4.7 bbls 

5 / 8 in. hole to 65 m. 12 65 9.5 bbls 

400 122 1 Run 7 in.,20 ppf, K-55, R-II Casing to 61 m. 4 65 9.4 bbls 

500 152 2 Cement Csg & WOC. 12 65 bbls 

600 183 2 Nipple up csg head, BOP & Diverter 5 65 bbls 

700 213 2 Air drill 6 1/2 in. hole to 450 m. 29 450 bbls 

800 244 4 Trip bit, rig maintenance, etc. 10 450 bbls 

900 274 4 Air drill 6 1/2 in. hole from 450 - 1120 m. 37.5 1120 bbls 

1000 305 5 Open hole geophysical logging 8 1120 134.3 bbls 

1100 

1200 

335 

366 

6 

6 

TOOH, pick up casing tongs, RIH w/ csg 

Set 4 ½ in., 10.5 ppf, K-55, R-II csg to 1100 m 

4 

6 

1120 

1120 

42.9 

1.6 

bbls 

bbls 

1300 396 6 Cmt long string & WOC 36 1100 100.0 bbls 

1400 427 7 Perforate and complete target 72 57.4 bbls 

1500 457 Metric 

1600 488 Well Type: Donbass Basin Prospect - CBM Cement: Yield circ wtr 2.57 m 3 

1700 518 Mud Type: Air drill 9 5/8" hole for surface casing to 65 m. Surface Casing: Class G w/ 2% CaCl 1.43 gel 0.38 m 3 

1800 549 Air drill 6 1/2" hole for long string to 1120 m. Bk circ w/17 bw, 2.5 bbls gel, 4 bbls spacer. Pump spacer 0.75 m 3 

1900 579 12 bbls, 14 ppg cmt. SD c/u lines, drop plug, displace w/ cmt 1.51 m 3 

2000 610 Pipe Details: Bit Size: Csg Size: Grade: Depth: 8.1 bbls treated water. Prep to drill out cmt. treat wtr 1.50 m 3 

2100 640 API / Metric inches inches m Intermediate Casing: circ wtr m 3 

2200 671 Conductor - - 16 75#, J-55 5 gel m 3 

2300 701 Surface String - 9 5/8 7 5/8 20#, K-55 61 spacer m 3 

2400 732 Intermediate - - - - - cmt m 3 

2500 762 Long String - 6 1/2 4 1/2 10.5#, K-55 1,100 Production Casing: ARI Lite w/ 2% CaCl 1.95 treat wtr m 3 

2600 793 Bk circ w/ 115 bw, 35 bbls gel, 2 bbls spacer. Pump circ wtr 21.36 m 3 

2700 823 100 bbls, 13.6 ppg cmt. SD c/u lines, drop plug, displace w/ gel 6.82 m 3 

2800 854 57.5 bbls treated water. Est. 1,000 psig surface to seat plug. spacer 0.25 m 3 

2900 884 cmt 15.90 m 3 

3000 915 treat wtr 9.13 m 3 

Time (Days) 

0 

100 

200 

300 

400 

500 

+ 

600 

700 

800 

900 

0.0 2.0 4.0 6.0 8.0 10.0 12.0 

3100 945 Size Description ID Vol Vol Yield Column Volume # Sacks Bbls BBL CMT 

3200 976 inches inches bbls/ft cu ft/ft cu ft/sk ft cu ft sk/ft xcess→ 25% 

3300 1006 Hole 9 5/8 9.625 0.089987 0.50528 1.43 10.0 5.053 0.35334 3.53 0.90 

3400 1037 Csg 7 5/8 20#, K-55 6.969 0.04718 0.26489 0 200.0 52.978 9.44 

3500 CSG SHOE 1067 An 7" x 9 5/8" 0.03351 0.1882 1.43 200.0 37.634 0.13159 26.32 6.70 9.50 

3600 4 1/2 10.5#, K-55 hole PBTD 1098 Hole 0 

3675 ARI Lite w/ 2% CaCl 6 1/2 3,600 1120 Csg 0 

An 0.00000 0.0000 0 

3,675 

Hole 6 1/2 6.500 0.04104 0.23044 1.95 75.0 17.283 0.11817 8.86 3.08 

Csg 4 1/2 10.5#, K-55 4.052 0.01595 0.08955 0 3,600.0 322.380 57.41 

An 4 1/2" x 6 1/2" 0.02137 0.1200 1.95 3,600.0 431.969 0.06153 221.52 76.93 100.01 

Exhibit 2.3 Donbass Basin Drill Prognosis for a Full-Field Development Well 




2.2.1.2 Casing 

In most CBM applications, burst pressure is usually the most important factor in selecting 

casing. For example, the internal yield pressure of 114 mm, 500kP (4 ½-inch, 10.5 pound per 

foot), K-55 casing is 33,050kP (4,790 psig), compared to 140 mm, 740kP (5 ½-inch, 15.5 

ppf), K-55 casing which is 33,190kP (4,810 psig). This is an important constraint to keep in 

mind in hydraulic fracture stimulation design. However, casing capacity for artificial lift 

equipment is an equally important consideration. 

Advanced Resources recommends that the full-field development phase utilize 114 mm (4.5 

inch) casing versus the more commonly used 140 mm (5.5 inch) casing in areas of the field 

that produce less water. The primary reason for this recommendation is that smaller diameter 

casing is significantly less expensive to purchase and ship. For example 114 mm (4.5 inch) 

casing weighs 15.6 kg/m (10.5 lb/ft) which is 32% less than 140 mm (5.5 inch) casing which 

weighs 23.1 kg/m (15.5 lb/ft). Assuming an average well depth of 1,100 m (3,600 ft), a 

savings of approximately 816 metric tons (900 US short tons) of steel can be realized for 

every 100 wells drilled, resulting in significant cost savings. Drilling smaller diameter holes 

will also result in faster drilling times and further cost savings. Exhibit 2.4 lists the materials 

needed for an initial 5-well pilot project utilizing 140 mm (5.5 inch) casing. 

Donbass 5-spot Pilot Project Casing 

Requirements Units Per Well 5-well Pilot Req 

16-inch H-40, 65 ppf, ERW R2 meters 25 125 

8 5 /8-inch, 32 ppf, K-55 buttress meters 61 305 

5 ½-inch, 15.5 ppf, K-55 buttress meters 1,100 5500 

Centralizers each 18 90 

Float Shoe each 1 5 

Float Collar each 1 5 

Wiper Plugs each 1 5 

Composite Bridge Plugs each 5 25 

Exhibit 2.4 Pipe Specifications and Material for the 5-Spot Pilot Wells 

During the full-field development stage, once the long string casing arrives on site, a tally is 

taken and the joints are numbered. Utilizing the slim-hole completion method (114 mm (4.5 

inch) casing), open-hole logs should be run and the depths at which the baffles will be set 




are determined to isolate each set of perforations. The baffles are screwed into internal 

threading in the pin at the top of the particular joint of casing between the fracturing stages, 

smallest baffle (11.7 mm, 2 11 /16-inch) on bottom, to the largest open baffle (9.56 mm, 3 9 /16inch) 

at the top. 

Exhibit 2.5 Balls and Baffles of Varying Size used for Zone Isolation 

Placement is crucial since the isolation of each stage during the fracturing process depends 

on the proper depth of the baffles. The casing is then run to bottom and landed at the 

planned depth. The casing must get to the planned depth for the baffles to be in the proper 

position. For a pilot project, a slightly different approach is recommended which is to cement 

140 mm (5 ½-inch) casing in place and utilize the open and/or cased-hole logs to determine 

the depths of perforations and number of fracturing stages. Composite or cast iron bridge 

plugs run on wire line are used as opposed to ball and baffles to isolate the fracturing stages 

within the casing. 




2.2.1.3 Geophysical Logging and Wire Line Operations 

Open hole and cased hole logging, perforating, and the setting of bridge plugs, can all be 

performed using a combination electric truck unit utilized by most of the major wire line 

service companies. The geophysical logging suite (open hole) should consist of a Gamma 

Ray, Differential Temperature, Compensated Neutron Density, Caliper and Array Induction 

log. Track #1 typically shows the gamma ray, differential temperature, density caliper, and 

bit size. Track #2 records the shallow, medium and deep induction logs. Track #3 has the 

density correction and across tracks 2 and 3 runs the upper and lower gas detectors, the 

borehole temperature, neutron porosity, compensated density, density porosity, and matrix 

density curves. 

Exhibit 2.6 Logging truck units 

Coal typically reads from 1.3-1.75 g/cc on a bulk density curve although variation can occur 

due to the quality of coal. Gas detectors can also be run, which are microphones that detect 

gas entry into the open hole and can identify, along with the temperature log, intervals of 

interest. Neutron/density curve cross-over in zones containing gas are very useful in 

determining gas productive intervals. Logs in the U. S. oil and gas industry are typically run 

at 2-inch (51 mm) and 5-inch (127 mm) scales. 

Cement bond logs are run to indicate areas of poor cement quality between the pipe and 

reservoir. The bond between cement and pipe often indicate the quality of the hydraulic seal 

in the well. This is vital where isolation is important between multiple seams of the reservoir 

during stimulation and subsequent production. It also indicates the degree of isolation of the 

productive reservoir to shallow surface water (aquifers) and isolates the surface from down 

hole stimulation methods, i.e. hydraulic fracturing. 




Perforating is accomplished with disposable High Efficiency Guns (HEGs) or hollow carrier 

casing guns, which are reusable. Standard perforation diameters are 9.5 mm (0.375-inch) 

and 11.2 mm (0.44-inch) with penetration rates from 610–914 mm (24-36 inches) through 

steel and rock. It is recommended to use only premium jet charges when perforating. 

Wire line set bridge plugs should be used in 140mm (5 ½ -inch) casing between fracturing 

stages, for the pilot wells. A relatively new product, the composite bridge plug (CBP), has 

also proven effective at isolating zones in the well bore. The CBP reduces completion time 

because the body of the plug is made from carbon-graphite composite and is far easier to 

drill than traditional cast iron bridge plugs. 

2.2.1.4 General Cementing Design 

In CBM zones, formation damage is caused by invasion of the cement slurry or filtrate into 

the coal-cleat and natural fracture system, or by unintentional break down of the productive 

zone with cement. Damage caused by invasion of the cement slurry or slurry filtrate can 

often be repaired or “bypassed” when the well is hydraulically fractured. Severe damage can 

occur when the hydrostatic pressure exerted by cement exceeds the fracture gradient of a 

coal seam, causing the formation to crack and cement infiltrating the reservoir. This type of 

damage is difficult to remedy and should be avoided by reducing the hydrostatic weight of 

the cement. 

The hydrostatic slurry weight should be designed to be less than the known fracture initiation 

gradient. This will insure that the coal seams are not fractured during cementing operations. 

Slurry weight is reduced by the addition of an extender or weight reducing materials such as 

perlite, diatomaceous earth, gilsonite, or alumino-silicate spheres. Most CBM cement deigns 

incorporate a light weight cement slurry utilizing a 13.5 ppg Class A cement containing 

bentonite to improve the pumping characteristics of the slurry and calcium chloride to speed 

the setting time. 

Advanced Resources recommends Enviro-spheres as an extender to lower the density and 

prevent loss of cement to the reservoir. The cement formula should yield a slurry density of 

0.702 psi/ft and result in a good bond to pipe and sufficient compressive strength for isolation 

between zones. A generic cementing program is presented below. 

A Class A neat slurry is adequate for cementing the conductor and surface (intermediate) 

casing strings. For the production casing, the pumping characteristics can be improved by 




the addition of bentonite (1-2%) to the system and the setting time reduced with the addition 

of 2% calcium chloride. The cement slurry is preceded by a bentonite pill or other viscous 

material to clean and condition the hole. Pumped ahead of the cement slurry, the viscous 

slug will remove drill cuttings and “mud cake” on the well-bore. This practice is 

recommended to enhance the cement to pipe and pipe to reservoir bond. 

The following procedure should be used to design the cement job: 

Determine the fracture gradient of the coal formation(s). 

Determine the depth for the top-of-cement. This may be defined by local regulations. 

Advanced Resources recommends that the cement be circulated to the surface if 

possible. 

1. Using the following equation, calculate the maximum cement density that the coal 

can support. 

Maximum height of cement: Hcmt = [(FG - 0.052*ρm) * Dc], (ft) 

0.052(ρcmt - ρm) 

Where: FG = fracture gradient of the coal, psi/ft 

ρm = density of drilling mud in the hole, lbs/gal 

ρcmt = density of the cement, lbs/gal 

Dc = depth to the coal seam, ft 

2. Calculate the hydrostatic head of the tail cement to a height required to fill the 

annular space to a minimum 30 m (100 ft) inside the surface casing. A cement 

basket can be run over weak formations to prevent fall back if an intervals fracture 

gradient is borderline and may be exceeded. 

3. Determine the height of the lead cement by subtracting the head (Gcmt*Hcmt, psi) of 

the tail cement from the total amount of allowable hydrostatic head. This is the 

remaining hydrostatic column that can be supported for the lightweight lead cement. 

The appropriate density of the lead cement to support a column of desired height 

and prevent breakdown of the reservoir can then be determined. 

Head is calculated by multiplying: 

Gcmt = gradient of cement = 0.052 * ρcmt 

Hcmt = height of cement column, ft 




It is important that standard cementing equipment, such as guide shoes, wiper plugs, float 

shoes, float collars, and centralizers, be utilized in CBM cementing operations. Failure to 

use these simple and relatively inexpensive pieces of equipment can lead to many problems 

during and following the execution of cement jobs, sometimes rendering the well unusable. 

A guide shoe (Exhibit 2.7) is a short, heavy-walled attachment with a round nose and a hole 

through the bottom. Guide shoes are used on the bottom of the casing to avoid hanging on 

ledges while running in the hole. A combination of a guide shoe and a float collar can be run 

to provide redundant valves that prevent cement from U-tubing back into the casing. 

Exhibit 2.7 Guide Shoe 

Casing centralizers center the pipe in the well bore and allow a uniform cement sheath 

around the casing string. They also insure that cement scours the entire annulus and 

displaces the drilling fluid to prevent channeling of the cement. Centralizing the casing 

improves the probability of effective cement jobs and zonal isolation. 

A centralizer should be run on at least every other casing joint through the coal section. If 

internal pressure is left on the casing during the setting period, the casing will balloon slightly 

during this period. This means that when the cement is set and pressure is released, the 

casing will contract slightly and leave a small gap in the cement (micro-annulus) over the 

length of the casing. This can lead to problems when interpreting bond logs and in rare 

cases can compromise zonal isolation. 




A cement wiper plug (Exhibit 2.8) separates the cement slurry from the displacement fluid. A 

float shoe contains an internal valve which prevents backflow of cement up the casing string 

with cementing operations. The float shoe also serves as a stop for the cement wiper plug so 

that all of the cement is not inadvertently pumped out of the casing. A float collar can be 

added above the shoe as a redundant backup to prevent backflow. A cement wiper plug is 

launched from the cement head between the cement and the displacement fluid and is 

“bumped down” on the float shoe or float collar. 

Exhibit 2.8 Cement Wiper Plug 

The cement head usually consists of a cement valve above a plug carrier and a bypass on 

the manifold connected to the top of the casing. The cement is pumped through a valve 

below the plug (bypass) at the beginning of the job. Once the cement is away, the bypass is 

closed and the upper valve opened by pushing the cement plug in front of the displacement 

fluid. 

It is important to ensure the plug is not launched early preventing the cement from being fully 

displaced from the casing and leaving cement in the casing that would need to be drilled out. 

One way to ensure that the plug is not released prematurely, is to have a small hole with a 

rubber bushing at the top of the cement head. A wire is threaded through the top of the head 

and attached to the wiper plug and subsequently disappears when the plug is released. The 

amount of cement in the casing can be minimized if the plug is released early by switching to 

water to displace the plug. 




The following section is an example of a typical CBM cement design using the following 

assumptions: Hole size = 210 mm (8-3/8 inches), casing size = 140 mm (5.5 inch) OD. 

Annular volume factor = 12.2 liters/meter (0.9849 gal/ft). (Note: this will need to be reestimated 

based on actual well conditions using the open hole caliper log.) A 25% cement 

excess is commonly used to account for the fact that the open hole caliper log will usually 

read greater volume than bit size. 

Two blends will be required, the lead (above the upper most stimulated coal zone) should 

utilize an 8% bentonite by weight cement, and the tail (below the upper coal to be stimulated) 

should utilize a 4% bentonite by weight cement. A slug of 5% bentonite and water mixture 

should be pumped ahead of the cement slurry to condition the hole. Exhibit 2.9 indicates the 

quantities of materials required to cement 5 pilot project wells completed with 140 mm (5.5 

inch) casing to a depth of 1,100 m (3600 ft). 

Bentonite 

Pill 

Lead 

Cement 

Tail 

Cement Total Total 

Surface Casing Class G Class G 

Slurry Volume 1100 2,310 3,410 gals 13 m 3 

Cement required 27,000 27,000 lbs 12,250 kgs 

CaCl - 2% 540 540 lbs 245 kgs 

Bentonite required 1594 1594 lbs 725 kgs 

Water Required 1028 1,379 2,407 gals 9 m 3 

Production Casing 8% Bent. 4% Bent. 

Slurry Volume 7560 10,200 12,600 30,360 gals 115 m 3 

Cement required ~ 52,700 64,440 117,120 lbs 53,125 kgs 

CaCl ~ 1,055 1,290 2,345 lbs 1,065 kgs 

Bentonite required 10,950 4,215 2,500 17,800 lbs 8,075 kgs 

Water required 7065 2,760 3,300 13,111 gals 50 m 3 

Exhibit 2.9 Donbass Basin Cement Materials Required for the Five Well Pilot 

The calculated hydraulic gradient of the 8% bentonite cement blend is 14.7 kP/m (0.65 psi/ft), 

and the 4% cement blend is 14.25 kP/m (0.63 psi/ft). 


2.2.2 Stimulation 



Drilling and completion operations cause formation damage by exposing the reservoir to 

fluids used in the drilling process. Fluid leak-off while drilling infiltrates the reservoir matrix, 

coal-cleats and natural fracture system. Formation damage is also caused by invasion of the 

cement slurry or filtrate when casing is cemented in the well. This damage can be repaired 

by a stimulation treatment of the well. Hydraulic fracturing is the most widely used treatment 

for CBM wells today. Fracture stimulation creates a conductive path that extends orders of 

magnitude beyond the zone of invasion of cement or drill fluid. 

One key to coal bed methane (CBM) well design is the pressure required to stimulate the 

coal seams. The shallow nature of CBM reservoirs limits the casing stress due to tension 

and collapse and the internal yield pressure becomes the prominent design criteria. Fracture 

gradients in excess of 22.62 kP/m (1 psi/ft) are common in coal seams and can lead to pump 

pressures in excess of 20,700 kP (3,000 psi) during hydraulic fracture stimulation. Near wellbore 

screen out can occur rapidly when pump rates exceed 3.2 cmm (20 bpm) and can burst 

casing or surface equipment. A pre-fracture step rate test (a mini-frac) is a good practice to 

determine near well-bore tortuosity, perforation restrictions, leak-off issues, etc. that may 

cause problems. The test data and initial shut-in pressure (ISIP) provides insight into the 

treatment profile of the stimulation. Only high quality API standard casing should be used in 

these applications. 

Reservoir simulation history matching and type curve analysis techniques should be utilized 

after stimulation to determine the effective fracture half length of the hydraulic fracture 

treatment. Further reservoir simulation can then be used to begin the hydraulic fracture 

treatment optimization process. The process of hydraulic fracture treatment optimization can 

be thought of as a “feedback loop”. This optimization process is illustrated in Exhibit 2.10. 

This optimization process will likely continue for at least the first one or two years of the 

development process. 




Exhibit 2.10 Fracture Optimization Process 

A generic completion recommendation follows based on available information. These 

recommendations may be modified for the zones of interest as the perforation intervals may 

change with better understanding of the reservoir. The completion sheet reflects a 140mm 

(5 ½ -inch) cased well bore drilled to 1,100 meters (Exhibit 2.11). Composite bridge plugs 

are recommended for zone isolation in the well bores envisaged for the pilot well program. 

The interval of perforation should extend into the sandstones associated with the coal 

seams. The sandstones act as storage for gas in the reservoir and can increase the initial 

production during the dewatering period. This initial boost in gas production from the 

sandstones may enhance the economics during the high cost phase of de-watering/depressuring 

the coal seams. Homogeneous, stratified sandstones tend to fracture more easily 

than coal seams due to their physical properties and modeled hydraulic fractures tend to 

grow in length along these beds. The result can be easier fracture initiation and longer, 

higher conductivity fractures with longitudinal contact along the coal seams. This can allow 

for quicker dewatering and potentially less fines due to the filtering effect of the sand pack. 




Starting at the bottom of the well (Exhibit 2.11) the wire line truck will perforate the stage 1 

interval followed by the hydraulic fracturing job. The wire line truck would then run a 

composite bridge plug and set it above the fractured interval. The setting tool is then run out 

of the hole and the perforating guns are rigged for the perforating run. The next stage 

fracturing job follows and the jobs proceed in this manner until all hydraulic fracturing stages 

are complete. 

If the slim-hole 144 mm (4 ½ -inch) well bore design is used, the fracturing will proceed 

followed by the 69.85 mm (2 ¾-inch) frac ball and 1.6 m 3 (10 bbls) of 15% HCl displaced to 

the 68.26 mm (2 11 /16-inch) baffle at 950 m (3120 ft). The acid is used to break down the 

perforations before each stage and is very effective in cleaning perforation gun debris as well 

as calcium carbonate that may be in the reservoir. The stage 2 interval is then perforated 

followed by the fracturing job, frac-ball, and acid. This process will continue until the stages 

are completed. When finished, the rig will trip in the hole with a bit and drill and circulate out 

the balls and baffles and any sand left in the well bore, leaving a clean well bore. 


DESCRIPT DEPTH 

Conductor: 16", 

CSG SHOE hole 

8 5/8", 32# @ 200 ft 

CMT 61.0 m 



Zone 

7 3/8 in 

Zone 1 Stage 

2 jspf 521 - 547 m 7 

Zone 

2 jspf 570 - 619 m 6 

Zone 3 

notches (18) 684 - 696 m 5 

Zone 

notches (18) 737 - 755 m 4 

Zone 

notches (9) 780 - 809 m 3 

Zone 

notches (18) 841 - 851 m 2 

Zone 

2 

4 

5 

6 

7 

Cmt Top 

notches (18) 1050 - 1060 m 1 

CSG SHOE PBTD 3600 ft 1098 m 

5.5", 15.5# @ 3600 ft 

1097.6 m TD 3675 ft 1120 m 

Exhibit 2.11 Completion Zones with Hydraulic Fracturing Stages 

for a Type Well in the Donbass Basin 




The hydraulic fracturing design assumes a fracture gradient of 20.4 kPa/m (0.90 psi/ft) and 

0.1 md permeability. A 13.6 kg (30 lb) guar gel with surfactant, enzyme breakers, and 

bactericide should be added to the fluid. A simplified linear gel is assumed for design 

purposes, if warranted a cross-linked gel can be designed. A cross-linked fluid uses a lower 

gel loading 7-9 kg (15-20 lb), is highly viscous, and has better proppant transport capabilities. 

The recommended proppant is 20/40 Ottawa sand, but other sand within the same size 

range, sphericity, roundness, and crush strength can be used if available. A desired fracture 

half length of 60 m (200 ft) and 114 kg (250 lbs) of sand/foot of interval were incorporated 

into the design. Pumping equipment capable of delivering 4.8 cmm (30 bpm) at 20,700 kPa 

(3,000 psi) will require approximately 1715 kW (2,300 hydraulic horsepower) on location to 

complete the work. 

The stimulation program will require a sand dump, blender, acid and fracturing pumps 

(Exhibit 2.12) on location. Sand and acid transports will also be required. Sand is fed to the 

blender via a conveyor system and the gel and sand are mixed in a “blender” then sent to the 

inlet of the high pressure triplex pumps and then pumped down hole at high rate. 

Exhibit 2.12 Sand Dump, Blender and Fracturing Pumps 

Other methods, including under-reaming and cavitation are alternative options to hydraulic 

fracturing, but have only been successful in a few geologic settings. 




Exhibit 2.13 summarizes the 6 stages for the recommended hydraulic fracturing procedure. 

Donbass Coal Basin 

WELL NUMBER LEASE NAME LEASE # 

DISTRICT QUAD 

DATE COUNTY API # 

TARGET 1,100 m 3600 ft. ELEVATION 

COMPLETION 

Descrip Program ISIP Pad % sand/perf Conc Rate Water vol Sand # HHP Pipe 

kg kg/m 

lbs 

3 m3/min m3 tonnes Hpm ppg bpm bbls 

lbs 

Hp 

Stage 1 1050 - 1060 27% 2,948 120 - 960 4.3 51.7 29.5 369 CSG 

shots 10 88 6,500 1 - 8 27 325 65,000 364 

Stage 2 841 - 851 28% 1,512 120 - 960 4.3 43.7 22.7 369 CSG 

shots 15 78 3,333 1 - 8 27 275 50,000 364 

Stage 3 780 - 809 28% 3,093 120 - 960 4.3 70 34.0 368 CSG 

shots 11 122 6,818 1 - 8 27 440 75,000 363 

Stage 4 737 - 755 29% 1,031 120 - 720 4.3 43.7 22.7 369 CSG 

shots 22 81 2,273 1 - 6 27 275 50,000 364 

Stage 5 684 - 696 26% 2,457 120 - 720 4.3 51.7 29.5 368 CSG 

shots 12 85 5,417 1 - 6 27 325 65,000 363 

Stage 6 570 - 619 27% 1,601 120 - 600 4.3 47.7 27.2 368 CSG 

shots 17 81 3,529 1 - 5 27 300 60,000 363 

Stage 7 521 - 547 27% 1,944 120 - 600 4.3 47.7 27.2 368 CSG 

shots 14 81 4,286 1 - 5 27 300 60,000 363 

Displacement Volumes not included in totals 

TOTALS % pad 

Drilling, Completion and Stimulation Design 2-20 

lbs 

kg 

101 2,084 120 - 820 4.3 51.4 27.5 368.4 CSG 

AVGs 

CEMENT PROGRAM 

holes 28% 4,594 1 - 7 27 323 60,714 363 

Size Description ID Vol Vol Yield Column Volume # Sacks Bbls BBL CMT 

inches inches bbls/ft cu ft/ft cu ft/sk ft cu ft sk/ft xcess→ m 3 

25% 

Hole 10 5/8 10.625 0.10966 0.61572 1.43 10.0 6.157 0.43057 4.31 1.10 0.17 

Csg 8 5/8 32 #, K-55 7.92 0.03936 0.22101 200.0 44.201 7.87 1.25 m 3 / bbls 

An 8 5/8"x10 5/8" 0.2100 1.43 200.0 41.997 0.14684 29.37 7.48 1.19 1.70 

Hole 0 10.72 

Csg 0 

An 0 

Hole 7 3/8 7.375 0.05834 0.32759 1.95 75.0 24.569 0.16799 12.60 4.38 0.70 m 3 / bbls 

Csg 5 1/2 15.5 #, K-55 4.95 0.02380 0.13364 3,600.0 481.093 85.68 13.62 17.65 

An 5 1/2"x 7 3/8" 0.1317 1.95 3,600.0 474.000 0.06752 243.08 84.42 13.42 110.99 

kg/m 3 

ppg 

m3/min 

Exhibit 2.13 Hydraulic Fracturing Program Design 

Advanced Resources recommends that fracture treatments should be designed such that a 

tip screen-out occurs as the fracture treatment ends. Packing the fracture by inducing a tip 

screen-out avoids problems related to proppant settling and/or convection because the 

volume created by the fracture is completely filled with sand at the conclusion of pumping. 

Because of coal seam fracture complexity, designing for tip screen out is difficult. On one 

extreme, the fracture treatment may screen out before the entire sand volume is pumped. 

This is not necessarily a bad result and certainly not a “failure”. If, for example, 70% of the 

bpm 

m3 

bbls 

tonnes 

lbs 

Hp m 

Hp



design sand volume is pumped when the screen out occurs, the resulting fracture half length 

will be shorter than designed, but the fracture should be highly conductive and filled with 

sand. On the other extreme, the design volume of sand could be pumped with no sign of 

impending screen-out. 

An example of a tip screenout is provided in Exhibit 2.14 showing actual data from a coal 

seam fracture treatment utilizing 13.6 kg (30 lb) gel. This graph indicates the major 

components of a typical hydraulic fracture including pad, sand stages, displacement, 

instantaneous shut in pressure (ISIP), slurry and clean rate, pressure, and the portion of the 

data to analyze to determine closure pressure. Note the slight increase in pressure as the 

0.72 kg/liter (6 pounds per gallon (ppg)) stage is entering the coal seam. 

Pressure (psig) 

4000 

3500 

3000 

2500 

2000 

1500 

1000 

500 

0 

Pad: Establish breakdown of 

formation and initiation of 

fracture 

Slurry Rate 

Stage 1: 

1 ppa 

Stage 2: 

3 ppa 

Stage 3: 

5 ppa 

07:37 

07:52 

08:06 

08:21 

08:36 

08:50 

09:04 

09:19 

09:34 

09:48 

10:03 

10:17 

10:33 

10:48 

11:02 

11:17 

11:32 

11:46 

12:01 

12:16 

12:30 

12:45 

13:00 

13:15 

13:29 

13:44 

13:59 

14:13 

14:28 

14:43 

14:57 

15:12 

Time (min:sec) 

Clean or Gel Rate 

Pressure Sand Concentration 

Stage 4: 6 ppa 

Pressure Discharge Rate Suction Rate Sand Conc 


ISIP 

Exhibit 2.14 Schematic of a Typical U.S. Hydraulic Fracturing Treatment 

32 

30 

28 

26 

24 

22 

20 

for 18 

16 

14 

12 

10 

8 

6 

4 

2 

0 

Flush: Displace slurry in 

Rate (BPM), Sand Conc. (PPA) 

Analyze 

Closure 

Pressure 

pump, frac. Iron, and casing 

down to the perforations 

Exhibit 2.15 illustrates how closure pressure can be determined. After pumping ends, 

pressure will fall as fluid continues to leak off into the formation. When the fracture closes, 

the slope of the pressure decline will change. By drawing straight lines and finding the 

intersection, the closure pressure can be determined. Depending on several factors, the 

closure pressure may be obvious, subtle, or not present at all.


450 

430 

410 

390 

370 

350 

330 

310 

290 

270 

250 



59:36 

59:50 

00:05 

00:20 

00:34 

00:49 

01:03 

01:18 

01:33 

01:48 

02:02 

02:17 

02:32 


Pressure 

Determination of Closure Pressure 

02:47 

03:01 

03:16 

03:30 

03:45 

04:00 

04:14 

04:29 

04:44 

04:58 

05:13 

05:28 

05:42 

Exhibit 2.15 Graph of Pressure versus Time used to determine Closure Pressure 

Exhibit 2.16 is an example of a true tip screen out and is considered a model treatment. The 

entire 0.96 kg/liter (8 ppg) stage was completed just as the treatment screened out (box 1 on 

graph). 


4000 

3500 

3000 

2500 

2000 

1500 

1000 

500 

0 

02:24 

00:00 

19:12 

26:24 

43:12 

36:00 

45:36 

28:48 

38:24 

16:48 

19:12 

00:00 

00:00 

21:36 

07:12 

19:12 

19:12 


Pressure Discharge Rate Suction Rate Sand Conc 

Exhibit 2.16 Example of a Tip Screenout 

40:48 

38:24 

28:48 

36:00 

43:12 

48:00 

48:00 

50:24 

33:36 

24:00 

33:36 

12:00 

55:12 

16:48 

31:12 

19:12 

26:24 

48:00 

55:12 

00:00 


1 

32 

30 

28 

26 

24 

22 

20 

18 

16 

14 

12 

10 

8 

6 

4 

2 

0 

Rate (BPM), Sand Conc. (PPA)



Occasionally, it is not possible to initiate a fracture. One possible reason for this could be 

particles of formation formed during fracture initiation causing a tip screen out very early in 

the fracture treatment. If this happens, possible solutions include allowing the pressure to 

bleed off, and making another attempt to initiate the fracture, or adding additional 

perforations to the same interval and/or in adjacent intervals and attempting fracture initiation 

again. When these remedies do not result in the designed volume of sand being pumped, 

one should consider increasing the density of the gel or cross-linking the gel to increase 

viscosity. 

It is often necessary to deviate from the design during the fracture treatment. The following 

are examples of operational changes that the operator may decide during a fracture 

treatment: 

The operator may increase the rate in order to increase fracture width if a pressure 

increase looks like the treatment may prematurely screen out. 

Increasing the sand concentration during the job may be delayed if the pressure 

appears to be a limitation on the job. 

The operator may call for a flush (cut sand and displace to perfs) if he believes that a 

screen-out is imminent but a significant portion of the treatment design hasn’t been 

pumped. 

Sand concentration may be increased if pressure is not rising and the treatment is 

nearing the end. 

The final sand stage may be extended if the pressure indicates a screen out is near but 

more time is needed to reach it. 

An on-site operator may also attempt to cause a near well-bore screen out in the 

previous example by reducing the injection rate or increasing the sand concentration. 

In a situation that no tip screen out will occur one may attempt to force a near well bore 

screen out to “pack” the area behind the perforations and enhance the conductive path 

to the reservoir. 




The following assumptions were made in order to estimate the material requirements for the 

hydraulic fracturing of a 5 well program: 

Frac gradient – based on well test data 

Depth – per geophysical logs 

Gel – 3.6 kg/m 3 (30 lb/1000 gal) linear 

Straight gel base viscosity – 25 cP 

Slurry viscosity – per empirical relationship 

Pump rate = 4 cmm (25 bpm) 

Young’s modulus = 2.79 MPa (400,000 psi) 

Permeability = 0.1 md 

Sand placement +/- 4470 kg sand/m of coal (3000 lb sand/ft coal) (= to or < 2.0 gm/cc) 

Fracture treatment will be designed for pad depletion at conclusion of pumping. Pad 

volumes are approximately 25% of job volume. 

Ukraine, Donbass Basin - Hydraulic Fracturing Materials 

5 - Well Summary 

Coal Seam Total Water Sand Conc. Total Sand Gel Breaker Surfactant Biocide 

meters 

m 3 

kg/m 3 

tm kg L L kg 

Frac Job bbls ppg lbs lbs qts gals lbs 

Stage 1 1050 - 1060 56 120 - 960 30 200 1.39 295.90 0.95 

Perfs 10 350 1 - 8 65,000 441 1.47 73.50 2.1 

Stage 2 841 - 851 56 120 - 960 30 200 1.39 295.90 0.95 

Perfs 15 350 1 - 8 65,000 441 1.47 73.50 2.1 

Stage 3 780 - 809 72 120 - 960 34 257 1.79 380.45 1.22 

Perfs 11 450 1 - 8 75,000 567 1.89 94.50 2.7 

Stage 4 737 - 755 50 120 - 720 23 172 1.19 264.20 0.85 

Perfs 22 300 1 - 6 50,000 378 1.26 63.00 1.8 

Stage 5 684 - 696 50 120 - 720 27 172 1.19 264.20 0.85 

Perfs 12 300 1 - 6 60,000 378 1.26 63.00 1.8 

Stage 6 570 - 619 50 120 - 600 27 172 1.19 264.20 0.85 

Perfs 17 300 1 - 5 60,000 378 1.26 63.00 1.8 

Stage 7 521 - 547 50 120 - 600 27 172 1.19 264.20 0.85 

Perfs 14 300 1 - 5 60,000 378 1.26 63.00 1.8 

384 197 1,344 9 2,029 7 

Well Totals 5 1,920 987 6,721 47 10,145 33 

Contingency m 3 

384 99 672 7 1,015 5 

Contingency % 20% 10% 10% 15% 10% 15% 

TOTALS 84 

holes 

2,304 

m 

1,086 7,394 54 11,160 38 

3 

tm kg L L kg 

Exhibit 2.17 Materials Required for Hydraulically Fracturing 5 Wells 




2.2.3 Post Hydraulic Fracture Injection Fall-off Testing 

Cased-hole, post fracture well tests can be conducted in selected wells to determine the coal 

cleat permeability and effectiveness of stimulation resulting from fracturing operations. 

These results are used in the ongoing reservoir simulation studies. These studies are in turn 

used to history match gas, water, and pressure data obtained during production operations. 

The results of the reservoir simulation history matching process can then be used to make 

certain critical determinations regarding hydraulic fracture effectiveness and to perform future 

optimization studies. The methods, equipment, and procedures to be utilized in the well 

testing operations can be presented as the need arises. 

Twenty acre (8 hectare) spacing is recommended for drilling a 5-spot pilot to determine the 

de-watering requirements for full field development. Optimal well spacing for commercial 

development will likely be in the range of 16 to 65 hectares (40 to 160 acres), depending on 

the local permeability. Water intercept wells may be required in areas of high water influx. 


2.3 CMM Drainage Techniques 



Mine operators perform degasification functions in three ways: 

by reducing the gas content of virgin coal seams and other gas bearing strata prior to 

mining – pre-mining degasification (this would include the technology for drilling and 

completing CBM wells, as described in the previous section); 

by extracting gas from gob regions formed subsequent to mining – gob degasification, 

and; 

by extracting methane from sealed areas isolated after mining. CMM recovered from 

any degasification function applied underground is collected in a gathering pipeline and 

transported safely to the surface for venting to the atmosphere or use (also may be 

routed underground for dilution in the exhaust ventilation air). 

The flow rates and gas quality can vary considerably between these various degasification 

techniques. Pre-drainage wells generally produce high quality methane gas (90%+) at low to 

moderate rates. Gob gas drainage methods generally produce medium to high quality 

methane (50-80%) at relatively high rates initially, but both the quantity and quality of 

methane produced declines after several months. The important aspect of all types of 

methane produced from degasification systems is that it represents a valuable energy 

resource that can be utilized in several ways. Exhibit 2.18 depicts the different methane 

drainage techniques and their end-use options. 




Exhibit 2.18 Coal Degasification: Production through Utilization 


2.3.1 Pre-Mining Degasification 



Pre-mining degasification targets regions of un-mined coal or other gas bearing strata in 

advance of mining activity with the objective to greatly reduce the methane content of the 

mining seam, or of adjacent seams to reduce the potential for future generation of gob gas. 

Pre-mining degasification is practiced from within the mine (underground), using horizontal 

boreholes, or from the surface with vertical wells (see previous section on CBM well drilling). 

Where reservoir characteristics are favorable (e.g. where coals have sufficient permeability 

and rapid diffusion rates), coal operators can drain gas from large areas. With low 

permeability coal and/or coals with slower diffusion rates, mine operators normally begin 

drainage far in advance of mining (years). Incorporated with an underground gas gathering 

system, underground pre-mining degasification systems can recover pipeline quality gas. 

The three methods commonly used for pre-mining degasification are cross-panel boreholes, 

long in-seam directionally drilled boreholes, and hydraulically stimulated vertical wells drilled 

from the surface. The underground pre-mine degasification techniques are illustrated in 

Exhibit 2.19 and Exhibit 2.20. 

Exhibit 2.19 In-Seam Boreholes Drilled across Longwall Panels during Gateroad Development to Reduce 

the Gas Content of the Longwall Panel Prior to Mining 




Exhibit 2.20 Long In-Seam Boreholes Directionally Drilled along the Longitudinal Axis 

of the Longwall Panels in Advance of Gateroad Development 

Vertical wells drilled from surface through multiple coal seams and stimulated by hydraulic 

fracturing are utilized for the recovery of CBM on a commercial scale. In some cases, mine 

operators implement these wells to also reduce gas contents of seams that will be mined 5 to 

10 years in the future. With this technique, commercial operators work with the mines 

regarding well locations, particularly as mines are concerned about stability issues when 

mining near hydraulic fractures. Due to costs, this system of CMM drainage is not 

implemented without consideration of the economic value of the recovered gas over the 

productive life of the wells. 


2.3.2 Gob Degasification 



There are three primary methods of longwall gob degasification techniques used world-wide, 

and mine operators often adopt variations of these: surface drilled vertical or angled gob 

wells, cross-measure boreholes, and superjacent techniques (overlying galleries, or 

boreholes drilled from overlying galleries, and overlying or underlying horizontal gob 

boreholes). Exhibit 3-17 generally illustrates these practices. 

Degasification Gallery 

Direction of Mining 

Vertical Gob Wells 


Gob 

Longwall Panel 

Longwall Face 

Cross-Measure Boreholes 

Exhibit 2.21 General Description of Gob Gas Recovery Methods 

2.3.2.1 Surface Drilled Gob Wells. 

Surface drilled vertical gob wells, most predominantly used in the U.S., are drilled in advance 

of mining to diameters of up to 300 mm (12 inches) and are placed vertically above the 

mining seam. Gob wells are typically cased and cemented to a point just above the 

uppermost coal seam or gas bearing strata believed capable of liberating gas resulting from 

the longwall mining operation, and then lined with slotted casing down to just above the 

mining seam (Exhibit 2.22). Because of surface access and drill site limitations, mine 

operators implement angled or directionally drill gob wells to reach specific target zones 

above the longwall panel.



Exhibit 2.22 Illustration of Vertical Drilled Gob Well 

At some mining operations where overlying gas bearing strata of high gas content are 

present and where gob permeabilities are very high, operators can obtain excellent gas 

production rates and maintain high gas qualities with surface drilled gob wells operated 

under vacuum (Exhibit 2.24). Surface drilled gob wells are not suitable for mines developed 

under urban areas and where surface access and right-of-way are restricted. Surface drilled 

gob wells are also difficult to implement with multiple seam operations. 




2.3.2.2 Cross-Measure Boreholes 

The cross-measure technique of longwall gob degasification is the dominant method used in 

Europe (east and west) and in Russia where deep multiple coal seams are mined using the 

longwall method. Cross-measure boreholes are small diameter boreholes (75 to 100 mm in 

diameter) that are drilled at angles from gateroad entries up into overlying or down into 

underlying strata, in advance of the longwall face. In extremely gassy conditions, operators 

will place boreholes from both the headgate and tailgate entries, and surround the panel. 

Each cross-measure borehole collar is connected to an underground gas gathering pipeline 

that provides vacuum to the wellheads and routes the gas to the surface. The crossmeasure 

borehole system is particularly applicable where deep reserves are mined at 

multiple levels and where surface access or topography limits surface options (surface drilled 

gob wells). 

2.3.2.3 Superjacent Techniques 

Superjacent techniques, involving the use of drainage galleries developed in advance of 

mining in overlying or underlying strata are used at some of the deeper and gassier mining 

operations in Eastern Europe, Russia, and China. Small diameter, short boreholes, are 

drilled into overlying strata from the galleries, and/or the galleries are sealed and connected 

directly to a gas collection system operating under high vacuum. More recently, superjacent 

techniques involving in-mine directionally drilled boreholes placed over or under the mining 

seam in advance of longwall operations have been applied in Japan, China, Australia, 

Germany, and in the U.S. 

2.3.2.4 In-Mine Directionally Drilled Gob Boreholes 

This technique applies state-of-the-art, in-mine directional drilling equipment normally used to 

develop long in-seam methane drainage or exploration boreholes. In-mine gob boreholes, 

75 to 150 mm in diameter, are drilled into the strata overlying or underlying un-mined panels 

to lengths of up to 1,500 m as shown on Exhibit 2.23. Overlying boreholes are strategically 

placed: (a) into the lowest producing source seam (for pre-mining drainage) or below the 

lowest producing source seam, depending on elevation above the mining seam and the 

geomechanical characteristics of the gob, (b) to intersect the fracture zone above the rubble 

zone after the gob forms, (c) over the tension zones near the edges of the longwall panel, (d) 

over the low pressure (depends on mine ventilation system) or high elevation side of the gob, 

and (e) to remain intact following undermining and produce gob gas over the entire length of 

the borehole. 




Exhibit 2.23 In-Mine Directionally Drilled Gob Boreholes placed in an 

Underlying Coal Seam and above the Mining Seam. 

The advantages of this technique over the cross-measure method are: (a) the boreholes can 

be developed in advance of mining, away from mining activity for either advancing or 

retreating longwall systems, (b) fewer, longer boreholes can produce an effective low 

pressure zone over the gob, relative to numerous cross-measure boreholes, (c) strategic 

placement may allow borehole collars to remain intact (protected from the effects of local 

stress redistribution) and allow boreholes to remain productive after longwall mining is 

completed, and (d) the system may be more effective and less costly to implement and 

easier to operate than a system of cross-measure boreholes. 

Relative to a system employing drainage galleries, horizontal gob boreholes are less costly 

to implement, particularly if the galleries are developed specifically for degasification and 

mined in rock or in uneconomic coal seams. 

Recent work to optimize placement, performance, and integrity of these directionally drilled 

overlying gob boreholes has lead to the development of larger diameter holes, the installation 

of perforated steel casing, and careful monitoring of wellhead vacuum as a function of mining 

activity. 




2.4 Recovery of Gas from Sealed Areas 

Following longwall mining, districts comprised of a group of longwall panels, or individual 

longwall panels alone, are typically sealed from active mine workings to minimize leakage of 

mine ventilation air to non-working areas, and for other mine safety reasons (spontaneous 

combustion, etc.). Mine operators that employ an underground degasification system 

typically also collect gas from sealed areas to (a) reduce gas emissions from sealed areas 

into the ventilation air course, (b) stabilize the concentration or flow of gas from the 

underground to facilitate operation of gas movers, and (c) to increase the volume of 

recovered CMM for commercial purposes. 

Rather than installing a collection line through every seal, mine operators will typically select 

a higher elevation seal, or a seal that is adjacent to a low pressure area of the mine 

ventilation system (alongside a return entry closest to the exhaust shaft or slope). Mine 

operators will install collection lines into the waste area (or use abandoned pipelines from 

underground pre-mining or underground gob gas drainage applications) and integrate 

installation including wellhead with construction of the seal. Although not as efficient, 

collection lines may be installed after construction of seals. 

2.5 Gas Collection 

An integral component of a mine degasification system is the gas collection and transport 

infrastructure. Underground, this infrastructure serves to move CMM collected from 

degasification boreholes up to the mine surface, or to a dedicated underground dilution area. 

Underground gas collection systems are comprised of a network of pipes fitted with water 

separation and safety devices: (a) water separators that remove accumulations of water in 

low elevation areas along the pipeline or at the bottom of collection wells, (b) a pipeline 

integrity system that can sectionalize the collection system and minimize methane liberation 

into the mine ventilation system should a breech in the pipeline occur, and (c) vacuum 

pumps (typically several) that can operate for a range of recovered gas quality and volume. 

See Exhibit 2.24 and Exhibit 2.25. On the surface, gathering infrastructure extends from 

vertical in-seam gas collection wells and gob wells to compression and processing facilities. 

With most gob wells in the U.S., however, there is no transport or collection mechanism as 

the recovered gas commonly vents into the atmosphere. 




Exhibit 2.24 Vacuum Pump - Vertical Gas Gob Well 

Exhibit 2.25 Gas Handling and Collection System 




2.6 Methane Drainage Practices In Ukraine 

In the Ukraine, mine operators remove methane from gas-bearing strata before, during, and 

after longwall mining, using variations of the CMM drainage techniques presented above, 

primarily cross measure boreholes. The system of methane drainage selected depends on 

the magnitude and source of the methane emissions into the mine, the proximity of these 

sources to active mining, and the reservoir and geologic characteristics of the gas bearing 

strata. Degasification allows mines to reduce ventilation costs, minimize mining delays, and 

enhance mine safety. 

2.6.1 Pre-Mining Degasification 

2.6.1.1 Vertical Wells 

Due to costs, equipment requirements, and the low permeability characteristics of the 

mineable coals in the Ukraine, a limited amount of vertical wells have been drilled to recover 

gas from coal seams or from adjacent gas bearing strata in advance of longwall mining. 

Although limited in their application, Ukrainian mines implement this technique for dual 

purposes. By strategically placing vertical wells to reduce gas contents of active mining 

areas, e.g. longwall panels, Ukrainian mine operators can convert the same wells for gob gas 

recovery following under-mining. 

2.6.1.2 Underground Boreholes 

Although the low permeability of most coal seams in the Ukraine discourages the use of 

boreholes drilled in-seam for methane drainage, some mines use this technique and drain 

gas from outlined longwall panels, and to target gas bearing zones (in-seam and adjacent 

strata) immediately in advance of gate entry developments as shown on Exhibit 2.26. These 

boreholes are typically 30 to 50 meters in length due to the drilling technique (coring or 

rotary), drilling equipment, and drilling conditions. 




Exhibit 2.26 Boreholes Drilled Immediately in Advance of Mine Developments to Target Gas 

2.6.2 Gob Degasification 

Ukrainian mines also employ surface drilled vertical wells (drilled specifically for gob gas 

recovery) and cross-measure boreholes drilled from underground to recover gob gas 

generated by longwall mining. 

2.6.2.1 Vertical Gob Wells 

In the Ukraine, where depth, surface access, and multiple level mining permits, vertical gob 

wells are drilled to a point 3 to 20 meters above the target mining horizon. Gob wells often 

produce gas with methane concentrations of 20 to 80 percent by volume in air, depending on 

vertical placement, proximity to the mine ventilation system, surface vacuum, and wellhead 

leakage. Suspended perforated casing is typically not used due to costs and availability. 

2.6.2.2 Cross-Measure Boreholes 

The cross-measure system is the most common method of gob degasification implemented 

by longwall mines in the Ukraine. This system is preferred as it is applied at the mining level 

and can be implemented with readily available underground drilling equipment. These 

boreholes are drilled at various angles from the tailgate entry through the strata above and 

below the coal seam, depending on the source of gob gas emissions, and at an acute angle 

toward the retreating longwall face as generally shown on Exhibit 2.27. With single entry 

retreat mining systems as used in the Ukraine, cross-measure boreholes have a short 




productive life and are not very efficient (recovering about 20 percent of the total gas which 

would have been liberated by the gob into the mine ventilation system). Due to the large 

number of cross-measure boreholes, their proximity to the gateroads (part of the mine 

ventilation air circuit) and the complex system of connected pipelines, a large amount of air 

dilution can occur. In the Ukrainian mines the methane collected by the cross-measure 

boreholes can range from 30 to 80 percent methane in ventilation air by volume. 

Exhibit 2.27 Cross-Measure Boreholes applied from Tailgate Entry for Single Entry Retreat 

Longwall Mining as implemented in some Ukrainian Mines. 

2.6.3 Gas Collection 

Underground degasification boreholes are linked by a system of connected steel pipelines to 

a centralized vacuum station installed on the surface. Because mines operate at deep levels 

in the Ukraine and have limited funds for supplies and equipment, the gas collection systems 

typically have numerous leakage points; at wellheads, pipe connections, and at the vacuum 

station. This results in low methane concentrations of the recovered gas, reduced vacuum 

pressures at wellheads, lower methane recovery rates, and reduced methane drainage 

efficiency. 




2.7 Proposed Methane Drainage Technology for Ukraine 

As the majority of the coal seams mined in the Donbass Basin in the Ukraine are 

permeability constrained, and as the primary source of methane emissions in Ukrainian 

mines is adjacent gas-bearing strata that is relaxed subsequent to longwall mining, the focus 

of recent efforts to introduce western methane drainage technology to the coal industry has 

been on improving gob gas recovery. Because of multi-level mining practices where upper 

seams are mined first and due to the depth of mining (greater than 1,000 m in some cases), 

improvement efforts have emphasized underground gob gas recovery techniques rather than 

surface initiated gob wells. 

Prior efforts by the U.S. EPA’s Coal Mine Methane Outreach Program, the World Bank 

Global Environmental Fund, and others, to introduce new technology to the coal mining 

sector to improve methane drainage efficiencies and increase the utilization of the captured 

gas for methane emissions mitigation, produced technical analyses and lead to outside 

investment by parties interested in greenhouse gas credits with limited drilling technology 

transfer. Although some of the private mines in the Ukraine are investing in drilling 

technology directly, the U.S. Department Labor committed to fund a technology transfer 

program in 2005 that involved the introduction of modern underground directional drilling 

technology to provide alternatives for underground gob gas recovery. 

Under the over-sight of the Partnership for Energy and Environmental Reform (PEER), in 

2006 an underground longhole drill was built by J.H. Fletcher Company and shipped to the 

Ukraine. Directional drilling training was initiated by the U.S. based directional drilling 

contractor, REI Drilling, Inc. at the Belozerskaya Mine in early 2007. 

2.7.1 Application of Directional Drilling for Gob Gas Recovery 

Directional drilling provides the Ukrainian coal sector the ability to implement gob gas 

recovery systems that have demonstrated benefits to conventional practices such as 

conventional cross-measure boreholes as presented above. In the Ukraine, mine operators 

can implement directionally drilled horizontal gob boreholes from the current mining level as 

shown in Exhibit 2.26, or from overlying or underlying mining levels. Directional drilling 

technology provides the Ukrainian operators the ability to reach out to distances greater than 

1,000 m and steer boreholes to access gob zones from entries that remain intact following 

mining (Exhibit 2.28). This provides for (a) longer gob gas production periods, (b) improved 




methane drainage efficiencies, (c) increased gob gas recovery, and (d) improved recovered 

gas quality as fewer boreholes are required (connections to pipeline, etc.). 

Exhibit 2.28 Long Hole Directional Drills 




2.7.1.1 Considerations for the Application of Directionally Drilled Horizontal Gob 

Boreholes 

The objective of gob degasification using horizontal gob boreholes is to provide more 

immediate and independent access to overlying strata that will fracture as a result of longwall 

mining. The application enables the operator to place boreholes from non-production areas 

that are free of equipment and production related inconveniences. It also facilitates 

placement of boreholes in advance of the mining face for both advancing and retreating 

longwall systems. With this system of degasification, drainage efficiency and gas purity are 

impacted by geologic and reservoir conditions, orientation of the boreholes, size and 

spacing, borehole integrity, suction control, and mine ventilation. 

Geologic and Reservoir Conditions: Operators must consider geologic and reservoir 

characteristics of the overlying and underlying strata when implementing a program of gob 

degasification using directionally drilled gob boreholes. Specifically, the geomechanical 

characteristics of the strata, the fracture characteristics of the gob as it forms, the resulting 

gob permeability, and proximity of source seams to the mined horizon must be considered. 

Additional factors to consider include the integrity of the strata for drilling considerations, 

collected water from upper strata and drilling fluids which can inhibit gas production, 

particularly for boreholes developed to target underlying sources. Underlying directionally 

drilled gob boreholes may not produce gas until the water migrates through fractures that will 

develop during mining. Also with long directionally drilled gob boreholes, deviations in 

borehole trajectory can produce water collection areas (“U” shaped low elevation zones), that 

impede gas flow. 

Standpipe Integrity: Directionally drilled horizontal gob boreholes are susceptible to integrity 

problems, however, they are not plagued by fractures in the vicinity of the standpipe and 

collar that typically affect cross-measure boreholes. Boreholes drilled from adjacent workings 

or long horizontal gob boreholes generally originate from competent mine workings and 

stratigraphic horizons and as such, operators may recover higher quality gas with this 

technique. 

Vertical Borehole Placement: When implementing overlying horizontal gob boreholes, 

operators typically target the lowest contributing source seams and position the holes above 

the gob rubble zone to take advantage of the fracture network created by longwall mining. 

Placement in the rubble zone will cause the borehole to shear and can limit its effectiveness 




to a single low pressure point source over the longwall face, and depending on longwall face 

activity, draw air from the mine ventilation system. Placement too high above the mining 

horizon may reduce gob gas recovery efficiency but will produce gob gas with higher 

methane concentrations. Borehole elevation placement is critical but operators may 

compensate by drilling larger diameter boreholes which can be lined with perforated steel 

liner to ensure that they remain intact when undermined. 

Borehole Orientation: Longwall panel margin zones, where the overlying strata remains in 

tension after undermining, produce more gas than consolidated regions within the center of 

the gob. Horizontal gob boreholes need to target these high permeability zones to improve 

gas production rates. 

Borehole Size and Spacing: To develop a continuous low pressure zone over the gob, 

horizontal gob boreholes are developed at appropriate sizes and spacings so that borehole 

influence zones overlap slightly. If boreholes are insufficiently sized and spaced apart, gob 

gas will migrate to mine entries. If boreholes are over-designed and too close together, they 

may promote migration of mine ventilation air into the gob. 

Vacuum System Control: Although gob gas may release without vacuum pressure from 

horizontal gob boreholes (depending on gob gas volumes, pressures, and the mine 

ventilation system), connecting to gas collection lines under vacuum pressure is necessary 

for effective production. In all applications, operators should carefully monitor gas collection 

system vacuum pressures and methane concentrations to optimize gob gas recovery and 

quality by adjusting vacuum pressure. 

Mine Ventilation System: Horizontal gob borehole placement needs to take advantage of the 

gob ventilation system. Depending on the pressure difference between intake and return air 

routes, planners must consider the gas migration patterns in the gob so that boreholes 

target the most productive regions, and mitigate methane emissions into the mine ventilation 

system. 




2.7.1.2 Directional Drilling Application at the Krasnolimonskaya Mine 

The Kranolimonskaya Mine was the initial candidate site for the directional drilling technology 

transfer project managed by the Partnership for Energy and Environmental Reform (PEER.). 

As this mine implements a system of cross-measure boreholes, a plan to demonstrate more 

efficient directionally drilled horizontal gob boreholes was derived for the 9 th Southern Panel 

as shown on Exhibit 2.29. 

Three overlying horizontal gob boreholes were planned for drilling from a room constructed 

specifically for the project off of the haulageway at the end of the 9 th Southern Panel at the 

mining horizon. Longwall mining would be performed in retreat from single entry gateroads 

toward the boreholes as shown on Exhibit 2.30. Directionally drilled boreholes were planned, 

initiating at 28 degrees from horizontal and placed 10m to 20m from the tailgate entry, with 

two subsequent boreholes 50m apart as shown. 

For the 9 th Southern Panel at the Krasnolimonskaya Mine, two overlying coal seams of high 

gas content and limited permeability, approximately 37m and 70m, above the top of the 

mining seam, respectively, are the primary sources of gob gas. The horizontal gob 

boreholes were planned into the lower overlying coal seam for dual purposes (a) to reduce 

its gas content prior to mining as much as possible (to reduce its potential to contribute to 

gob gas), and (b) to subsequently recover gob gas generated from this seam and the uppermost 

seam following undermining. Geomechanical experience indicated that the integrity of 

boreholes directionally drilled into the upper coal seam may be maintained following undermining 

as the rubble zone would likely not extend above the base of the lower coal seam. 

Due to timing and other issues relating to the management of the Donbass coal sector, 

PEER elected to not implement the demonstration project at the Krasnolimonskaya Mine but 

to move it to the Belozerskaya Mine. 


Cage Shaft to 545m Level 

Haulage Way Landing 

Valve 

Diaphragm 

Fire Check Valve 

Air / Gas Discharge 

Water Sump 

Borehole Valve 

Pipeline Valve 

Pipeline Diaphragm 

Fire Check Valve 

Air Inlet 

Legend 

Degass ing Pipeline 

Ventilation Shaft to 210m Level 

Empty Car Branch 

Bypass 

K-5 Slope 



Total Degassing Pipeline Length 



Northern Haulage Way 

Skip Shaft to 545m Level 

Conv ey or Entry of K5 Sea m, Southern Slope 

Seam 

K5 

Land in g of 

Haulage Way 

Sout hern Slo pe Haulage Way 

Sou the rn Slo pe of K5 Se am 

C onv e yor Entry of K5 Seam , Southe rn Slo p e 

Haulag e Way 2n d Sta ge 

9th Southern Panel 

No. 1 Sl ope "bis " of K5 Se am 

K5 Sou the rn Slo pe , 2n d Sta ge 


Ma nwa y 

Boreholes 

Manway 

Northern Haulage of Level 545m 

M a nwa y 

Vacuum Pump Station 

Southern Haulage of Level 545m 

Haulage Way 

Pump Type: 

Capacity: 

Pump Size: 

Exhibit 2.29 Demonstration of Directionally Drilled Horizontal Gob Borehole 

planned for the Krasnolimonskaya Mine 

Length: 

Width: 

Height:



Exhibit 2.30 Plan for the Dual Purpose Horizontal Boreholes at the Krasnolimonskaya Mine 

2.7.1.3 Directional Drilling Application at the Belozyorskaya Mine 

Directional drilling training initiated at the Belozorskaya Mine in early 2007. This mine also 

implements a system of cross-measure boreholes and would benefit from more efficient 

directionally drilled horizontal gob boreholes. 

Plans were derived for three overlying horizontal gob boreholes drilled from a room 

developed off of the 8 th Tailgate Entry (single entry) located about mid-way along the length 

of the panel as shown on Exhibit 3-23. Plans were to place the boreholes 20m from the 

tailgate entry, and 50m apart thereafter. 

Exhibit 2.31 Horizontal Gob Boreholes Planned for the 8th Southern Longwall Panel 

at the Belozorskaya Mine 




Drilling initiated at the mining horizon (the L3 coal seam) with the initial target as the 

overlying upper L4 coal seam, approximately 17m above. During longwall mining, three 

overlying coal seams contribute to gob gas, the lower and upper L4 seams, and the L5 

seam, approximately 10m, 17m, and 37m above the mining horizon, respectively. Ideally, 

horizontal gob boreholes placed in the upper L4 coal could reduce the gas content of this 

seam prior to under-mining. By producing under a vacuum, the horizontal boreholes could 

draw gas up from the lower L4 seam and down from the overlying L5 seam after 

undermining, and reduce gob gas emissions into the mine. 

Because of the integrity of the strata during drilling, plans changed to target a zone 

approximately 30m above the L3 seam, or in the horizon below the contributing L5 coal 

seam. The formation above the mining seam (L3) is a mudstone of medium strength 

(uniaxial compressive strength), between the lower and upper L4 seams, a stronger siltstone, 

and between the upper L4 and L5 seams, about 7m of mudstone overlain by another 

measure of siltstone. 

Initial drilling started at a shallow angle of 5 degrees through the first measure of mudstone 

with the intent to build angle. Directional drilling was not feasible due to the water pressures 

and volumes required to drill, which eroded the formation and affected borehole stability. 

Subsequent core drilling, reaming, and installation of casing proved difficult and borehole 

stability could not be maintained, including the pitch of the borehole. A second borehole was 

attempted at an initial inclination of approximately 25 degrees. This borehole was drilled 

using core drilling techniques and identified the stable strata (and its elevation) suitable for 

directional drilling; the 12m of siltstone just under the L5 coal seam. 

The drilling approach for the horizontal gob boreholes for the Southern 8 th longwall panel was 

established following initial drilling trials and is as follows: 

Setup Angle - Established at 20 Degrees at the drilling station and is limited by the 

turning ability of the directional drilling equipment and the 12m thick stable formation 

determined to be suitable for directional drilling. 

Casing - Casing is required to stabilize the borehole through the incompetent strata 

(overlying 25 meters) and enable directional drilling downhole. 

Pilot hole - Pilot hole drilling to the competent strata at an inclination of 20 Degrees 

requires using core drilling techniques which minimizes disturbance to unstable strata, 




requires less water flow for cuttings removal and lubrication, and can be performed with 

minimal loss of directional control (pitch). 

Reaming - Reaming is required to install collar casing and stabilization casing. 

Reaming requires enlarging the 100 mm pilot hole to 185 mm in diameter using overcoring 

techniques. This technique requires little water and can use the pilot hole as a 

guide to maintain borehole trajectory. 

During the summer of 2008, mining commenced on the 8 th southern longwall panel at the 

Belozerskya mine, above which the three approximately 800m long directionally drilled holes 

were drilled. Preliminary results have been favorable, with the 3 boreholes capturing 

7 m 3 /min (350 Mcfd) of methane at a concentration of nearly 50% methane. There is a mud 

stone layer between the coal seam and the boreholes that is restricting methane flow into the 

boreholes. When mining of the longwall is completed and the mudstone is completely 

undermined in October, methane quantity and quality should improve. 

It is recommended that the Bazhanov and South Donbass #3 mines implement a 

combination of surface and in-mine degasification techniques to improve gas drainage. The 

optimum technique(s) will only be determined through experimentation with different 

methods. As a starting point, Advanced Resources would recommend implementing some 

longhole directional drilling techniques similar to the project at the Belozorskaya Mine, 

described above, because of the similar geologic and mining conditions between the mines. 

2.8 Directional Drilling Applications at the Bazhanov and South 

Donbass #3 Mines 

Coal mine operators in the Ukraine are very interested in utilizing directional drilling 

technology to augment their current methane drainage practices. Other applications of this 

technology that are of interest include the ability to explore and characterize geologic 

discontinuities significantly in advance of mining, the development of steered boreholes for 

water transfer or de-watering, and the development of directionally drilled boreholes for destressing 

and de-pressurization. 

Most coal mine operators in the Ukraine do not own or operate drilling equipment that would 

be suitable for adaptation to directional drilling. Most of the underground drills are short 

stroke. 




The following are recommendations to consider when introducing directional drilling 

technology to the Ukrainian coal mines to improve methane drainage practices. 

Drilling Equipment - Drilling equipment should be suitable for multi-level, single entry mining 

conditions. Mine entries are typically narrow (4 m wide) and mine levels are accessible by 

men and materials shafts with limited size capacity. Drilling equipment should be modular so 

that it can be disassembled on surface and reassembled underground, and unit components 

should be modular. For example, a two component directional drilling system with a 

separate drilling unit and separate electrical and hydraulic power pack would be more 

suitable. 

Drilling equipment should be flexible for multiple applications, including wireline coring. 

Equipment should have the ability to articulate above and below horizontal as much as 

possible. A drilling stroke of 2 m is satisfactory, with high thrust and torque (simultaneous) 

capability. Equipment introduced into the Ukraine should be represented by its manufacturer 

in eastern Europe and spare parts, including technical support must be available. 

Downhole Equipment - Provide downhole drilling equipment suitable for wireline coring, 

directional drilling, and rotary drilling, including reaming and over-coring. Any anticipated 

casing should be provided with the drill, including cross-over supplies to install casing with 

the drill, and to down-size to wellhead fittings, etc. Exhibit 32 shows a list of required 

equipment for underground directional drilling. 

Longhole Directional Drill Drill and Power Unit 

Drill Rods 

Downhole Motor 

Survey Tools 

Miscellaneous Items 

Non-Magnetic Drill Rods 

NQWL Drill Rods 

5/6 Stage “N” Motor 

Subs/Swivel, etc. 

Spare U-joints and Bearings 

Fishing Tools 

Downhole Survey Tool 

Ancillary Equipment and Spare Parts 

Drill Bits 

Hole Openers 

Miscellaneous Tools and Equipment 

Directional Drilling Training 

Exhibit 32 Equipment Requirements for Underground Directional Drilling 




Downhole equipment suppliers in Europe need to be advised to stock directional drilling and 

coring materials in eastern Europe to support the introduction of this technology. 

Methane Drainage Approach - A methane drainage approach incorporating new drilling 

technology must be derived after an underground inspection of current methane drainage 

practices, and following detailed discussions with mine engineering, methane drainage, 

geology, and drilling personnel. A suitable methane drainage approach involving new drilling 

technology must consider: 

the source and magnitude of the methane emissions into the mine; 

the general reservoir properties of the mined and adjacent gas bearing strata; 

the geomechanical characteristics of the coal, surrounding strata, and gob; 

past drilling experience, surface and underground, including coring; 

current and future mine plans (all mining levels); 

the capacity and integrity of the current gas gathering infrastructure. 

Discussions and interaction with the mine operators should include a local mining engineer 

that is versed in methane drainage and drilling. 

Drilling Approach - A drilling approach for methane drainage must consider the Mine’s 

experience with drilling in the coal seam and the surrounding strata. In-seam directional 

drilling will be difficult in high stress conditions, in friable coals, high ash seams interbeded 

with clays and shales, and depending on the thickness of the coal seam, the characteristics 

of the immediate roof and floor. Although stratigraphy is generally known by the Mine, 

additional characterization at specific drilling locations is recommended for any approach 

involving directionally drilled horizontal gob boreholes in adjacent strata. This can be 

accomplished by drilling an initial surveyed core hole to verify the integrity and accurately 

identify the elevation of the different measures. 

Drilling Support - The introduction of new drilling technology into the Ukraine will require 

technical support that can provide hands-on assistance if required. With directional drilling 

where high value directional instruments are used, drilling support should include tool 

recovery services (fishing). Technical services should include directional data interpretation, 

geologic interpretation, and steering tool trouble shooting, as required. 


Task 3 



Market Assessment for Produced Methane 

Market Assessment for Produced Methane 3-i




3.1 Introduction......................................................................................................................3-1 

3.2 Assessing Market Options for CMM ..............................................................................3-4 

3.2.1 CMM Gas Compositions and Volumes....................................................................................3-4 

3.2.2 Power Generation based on CMM ..........................................................................................3-5 

3.3 Assessing Market Options for CBM...............................................................................3-6 

3.3.1 Net Back Price Derivation........................................................................................................3-7 

3.3.2 CBM Gas Compositions and Volumes ....................................................................................3-7 

3.3.3 Moisture Removal ....................................................................................................................3-9 

3.3.4 Capital Cost Estimates for Compression, Processing and Transmission .............................3-11 

3.3.4.1 Gas Compression ..........................................................................................................3-12 

3.3.4.2 Triethylene Glycol (TEG) Dehydration Unit ...................................................................3-13 

3.3.4.3 Transmission and Metering............................................................................................3-14 

3.3.4.4 Total Capital Cost for Processing and Compressing Gas for Pipeline Injection............3-14 

3.3.5 Gas Sales to the European and Ukrainian Markets ..............................................................3-15 

3.3.5.1 Europe............................................................................................................................3-15 

3.3.5.2 Ukraine...........................................................................................................................3-15 

3.3.6 Electrical Generation..............................................................................................................3-15 

3.3.7 Transportation Market............................................................................................................3-16 

3.3.8 Petrochemical Market ............................................................................................................3-16 

3.3.8.1 Ammonia ........................................................................................................................3-17 

3.3.8.2 Methanol ........................................................................................................................3-17 

3.4 Summary of CBM & CMM Energy Equivalent Prices .................................................3-18 

Appendix 3.A GOST Standard 5542-87 ...............................................................................3-19 

Appendix 3.B Caterpillar Statement of Supply .....................................................................3-26 

Appendix 3.C GE 10-2 Gas Turbine Technical Bulletin........................................................3-31 

Appendix 3.D GE PCL Compressor Technical Bulletin ........................................................3-34 

Market Assessment for Produced Methane 3-ii




Exhibit 3.1: Potential Markets for Produced Methane ..........................................................................3-2 

Exhibit 3.2: CBM/CMM Production to Utilization ..................................................................................3-3 

Exhibit 3.3: Coal Mine Methane Gas Compositions and Volumes.......................................................3-4 

Exhibit 3.4: Typical arrangement for 6 generator modules ..................................................................3-5 

Exhibit 3.5: Coal Bed Methane Gas Composition ................................................................................3-7 

Exhibit 3.6: 0.25 km 2 (60 acre) Type Curve Production Forecast ........................................................3-8 

Exhibit 3.7: Wobbe Number and Higher Heaving Analysis ..................................................................3-8 

Exhibit 3.8: Donbass Development Map ..............................................................................................3-9 

Exhibit 3.9: Typical Flow Diagram – Glycol Dehydration Unit ............................................................3-10 

Exhibit 3.10: Flow Scheme - CBM to Injection into Gas Transmission Grid ........................................3-11 

Exhibit 3.11: Capital Cost Estimate GE Gas Compression System.....................................................3-12 

Exhibit 3.12: Capital Cost Estimate – ALCO TEG Dehydration Unit....................................................3-13 

Exhibit 3.13: Capital Cost Estimate – Transmission and Metering Station ..........................................3-14 

Exhibit 3.14: Summary of Capital Cost Estimate – Compression, Processing and Metering ..............3-14 

Market Assessment for Produced Methane 3-iii




Ukraine is a significant energy consumer with nearly half of its energy consumption coming 

from natural gas. It is the 6 th largest consumer of gas in the world and consumes more gas 

than Poland, the Czech Republic, Hungary and Slovakia combined 1 . Over 75 percent of 

Ukraine’s gas supply is imported from Russia and Central Asia (Turkmenistan, Uzbekistan 

and Kazakhstan) making the Ukrainian economy very vulnerable to increases in the price of 

imported gas. In 2007, Ukraine imported 63 billion cubic meters (Bcm), 2.24 Tcf, from 

Russia. 

The current (2008) price that Ukraine pays for imported gas, supplied by Gazprom, is 

US$180 per 1000 cubic meters (mcm). As of summer 2008, Russia and Ukraine were 

holding intense discussions to set prices for 2009 and future years. Russia believes 

Ukraine’s import price should rise to a “European sales price”. The “European price” refers 

to the cost of Russian gas at Germany’s eastern border and the summer 2008 price quotes 

ranged from US$335/mcm (World Gas Institute) to US$370/mcm (US Energy Information 

Agency) 2 , with predictions of a rise to US$400-500/mcm in 2009. Ukraine is hoping to 

spread the price rise over the next 3 years, but gas prices for Ukrainian domestic consumers 

(which are currently heavily subsidized) are already planned to rise by 35% in December 

2008. 3 

Given the lack of domestic gas production, the potential for coal mine methane (CMM) and 

coalbed methane (CBM) to replace existing imported fuels, as well as displace coal-fired 

power generation, is high. Exhibit 3.1 illustrates the diversity of CMM/CBM as a fuel and 

feedstock in various sectors of the economy, all of which represent potential markets for 

produced methane. 

CBM, 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. 

1 US Energy Information Agency 

2 July 2008, EIU Business Newsletters Eastern Europe, Economist Intelligence Unit Limited, New York, NY. 

3 Russian News and Information Agency, Oct 2008, http://en.rian.ru 

Market Assessment for Produced Methane 3-1



Sector CMM/CBM Use 

Electricity Generation 

Fuel for base load power 

Combined cycle / co-generation power plants 

Fertilizer Industry Feedstock in production of ammonia and urea 

Industrial 

Domestic & commercial 

Fuel for raising steam 

Fuel in furnaces and heating applications 

Heating (spaces & water) 

Cooking 

Transportation Compressed natural gas vehicles 

Petrochemicals 

Feedstock for a variety of chemical products 

(e.g. methanol) 

Exhibit 3.1: Potential Markets for Produced Methane 

The following sections characterize the most likely development scenarios for CMM and 

CBM. The two production streams are discussed separately as the gas composition and 

producing pressures for CBM and CMM are very different, which necessitates different gas 

treatment and production facilities for the two gas production streams. 




Exhibit 3.2: CBM/CMM Production to Utilization 




3.2 Assessing Market Options for CMM 

3.2.1 CMM Gas Compositions and Volumes 

The gas composition and volumes for the two CMM cases are presented in the following 

table. 

Coal Mine Methane 

Gas Composition and Volumes 

Bazhanov Mine Donbass #3 Mine 

Coal Mine Gas Coal Mine Gas 

Vol % Vol % 

CH4 39.0 CH4 36.0 

O2 12.8 O2 13.4 

N2 48.2 N2 50.6 

Annual production, 

4.4 Million cubic meters 

Annual production, 

25 Million cubic meters 

Flow, scf/hr 17,731 Flow, scf/hr 100,740 

Flow, Nm 3 /h 502 Flow, Nm 3 /h 2854 

Temperature, °F 68 Temperature, °F 68 

Pressure, psia 14.7 Pressure, psia 14.7 

Ventilation Air Ventilation Air 

Vol% Vol% 

CH4 0.6 CH4 1.0 

O2 20.9 O2 20.8 

N2 78.5 N2 78.2 

Flow, scf/hr 38,134,000 Flow, scf/hr 59,320,800 

Flow, Nm 3 /h 1,079,977 Flow, Nm 3 /h 1,680,000 

Temperature, °F 68 Temperature, °F 68 

Pressure, psia 14.7 Pressure, psia 14.7 

Exhibit 3.3: Coal Mine Methane Gas Compositions and Volumes 

As can be seen, both gas compositions contain a significant percentage of air. With the mine 

degassing systems operating under vacuum, some air enters the system through pipe 

flanges that are not 100% sealed. Better maintenance or upgrading of these systems could 

result in lower air infiltration with corresponding higher methane concentrations. 




The methane available from the Bazhanov mine is net of the total gas produced less that 

used for boiler fuel. The mine might consider diverting more gas for use in electricity 

generation and less for steam generation. Nevertheless, the following assessment is based 

on the quantities and qualities provided by the mines. 

3.2.2 Power Generation based on CMM 

Both mines have traditionally burned the CMM air / methane mixtures in boilers. As an 

alternative, power generation was considered using reciprocating engines like those 

described in a catalogue data sheets provided by Caterpillar and included in Appendix 4B of 

the Production Operations & Surface Facilities section of this report. 

Quotations for the purchase and installation of the generators were requested from both 

Caterpillar and General Electric. Caterpillar responded with a quotation included in Appendix 

3.B – p.3-26. This quote was based on CMM gas volumes capable of generating 24 MW of 

power and allowed Advanced Resources to accurately estimate costs for the purchase and 

installation of 3.3MW and 1.7MW generators at the South Donbass No.3 and Bazhanov 

mines respectively. 

Caterpillar’s quote included pricing for: 

Exhibit 3.4: Typical arrangement for 6 generator modules 

Modular containerized Caterpillar G3520C TA gaseous fuel configured generator sets 

rated at 1500 rpm, 2,000 kWe, generator voltage 11 kV continuous service. Every unit 

is equipped with complete heat recovery system and balance radiators. 

Switchgear group for island and parallel operation of electrical generators. 




Commissioning and testing of all equipment specified in the items above as indicated in 

their proposal. 

Basic training of equipment operations, and disassembly and assembly of major engine 

components for the power plant personnel. 

Prices are calculated in reference to Caterpillar pricing policy in 2008 and are valid for 

products released from their factory before 31.12.2008. 

Final estimated costs for power generation at the South Donbass No.3 and Bazhanov mines 

were used in the economic analyses shown in section 5.4 of the Project Costs and 

Economics chapter of this report. 

The results of the economic analyses show that at a 15% IRR, power could be generated at 

the South Donbass No.3 mine for US$0.044 per kWh and at the Bazhanov mine for 

US$0.049 per kWh. This power would be used to offset electric power purchases made from 

the national grid. The current (2008) price of electric power utilized at the mines (supplied to 

ARI by a panel of local Ukrainian experts) is US$0.056 per kWh. 

3.3 Assessing Market Options for CBM 

Once coal bed methane (CBM) is processed for moisture removal, it is no longer “CBM” but 

can be considered “natural gas” in every respect and can be sold as such. The calculated 

average production volume at peak well productivity, for the combined Donbass and 

Grishino-Andreyevskaya CBM lease areas, is almost 608 mNm 3 /d (21.45 MMcf/d), which is 

an industrially significant volume. 

Five possible markets for the natural gas from CBM production were researched and 

assessed: 

1. Injection of the gas into natural gas pipelines for sale into the Ukraine market; 

2. Injection of the gas into natural gas transmission pipelines for sale into European 

markets; 

3. Power generation using combined cycle gas turbines for sale of electricity to the local 

Ukraine electric grid; 

4. Production of ammonia; and 

5. Production of methanol 




Markets are assessed by calculating a final cost of gas production (per mcm) for each 

scenario and comparing that final cost to the current market price. The final cost is made up 

of a net-back price, plus a gas processing, compression and transmission cost (same for all 

scenarios) and incremental costs unique to each market. 

3.3.1 Net Back Price Derivation 

The “net-back” price is the price for the natural gas at the point at which the CBM leaves the 

gas production field and enters the compression and processing system. The “net-back” 

price is the price payable to the producer of the gas after the product is sold in the market. 

The price is net of the costs of compression, gas conditioning, transportation, and other 

related costs. For example: 

If natural gas were to be sold to a Ukrainian pipeline operation, the net-back price would be 

developed as follows: 

Sales price of natural gas to the pipeline operator or consumer 

minus transportation cost to the transmission pipeline entry point 

minus gas conditioning cost 

minus gas compression cost 

resulting in net-back price at the CBM production field 

In order to determine the most economically attractive market for utilizing the natural gas 

from CBM production, a net back price at 25% IRR for the gas was derived from the 

sensitivity analyses carried out on the economic results in Section 5. The net back price at 

25% IRR is US$350 per thousand cubic meters (mcm). 

3.3.2 CBM Gas Compositions and Volumes 

The gas composition and volumes for the CBM case are presented in Exhibit 3.5: 

Coal Bed Methane Gas Composition 

Volume % 

CH4 95.7 

C2H6 1.0 

C3H8 1.0 

N2and other inerts 2.3 

Max. Flow rate (mNm 3 /d) 607.6 

Max. Flow rate (Mmscf/d) 21.45 

Exhibit 3.5: Coal Bed Methane Gas Composition 




The volumes estimates were based on the reservoir model forecast of gas production from 

1040 wells drilled on 0.25 km 2 (60 acre) spacing (see Section 2 – Reservoir Simulation). 

mmcfd 

25 

20 

15 

10 

5 

- 

Ukraine CBM Production Profile - 1040 w ells drilled 

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 

Exhibit 3.6: 0.25 km 2 (60 acre) Type Curve Production Forecast 

Gas Water 

As can be seen from the gas composition assessment in Exhibit 3.7, the gas does not 

contain H2S or other sulfur compounds. In addition, nitrogen and inerts are anticipated to be 

in the range of 2.3%. With a Wobbe number of 48.77 Mj/m 3 the gas heat content is well 

within GOST Standard 5542-87 – Natural Fuel Gases for Industrial and Domestic Use (See 

Appendix 3.A, p.3-19). The gas is of satisfactory quality for pipeline transmission, power 

generation or industrial uses without further processing beyond moisture removal. 

Exhibit 3.7: Wobbe Number and Higher Heaving Analysis 

Market Assessment for Produced Methane 3-8 

2.5 

2.0 

1.5 

1.0 

0.5 

- 

mbpd

3.3.3 Moisture Removal 



Produced gas will be collected at each individual well and transported to a central gas 

processing plant by a series of pipelines. (Donbass example - see Exhibit 3.8) 

Exhibit 3.8: Donbass Development Map 




As discussed in Section 4.3.8, triethylene glycol (TEG) will be used to remove water from 

coal bed methane gas before it is compressed for use in other processes or injected in 

transmission pipelines. Water can cause hydrate formation which can plug pipelines, and 

cause corrosion. The TEG stream, containing about 1.1 wt % water, counter-currently 

contacts the gas in a short (three theoretical stage) contactor tower. The water which is 

absorbed dilutes the TEG somewhat, and the diluted solution must be re-concentrated 

before it can be reused in the absorber. 

Exhibit 3.9: Typical Flow Diagram – Glycol Dehydration Unit 

The diluted TEG is preheated by exchange with hot regenerator bottoms in the first lean/rich 

exchanger and then flashed in the flash tank to expel water and hydrocarbons. The solution 

is further heated by exchange with hot regenerator bottoms in the second lean/rich 

exchanger before entering the regenerator. 

The re-concentration is accomplished by distilling water out of the TEG in the regenerator. A 

sharp separation can be accomplished with a relatively short column due to the extreme 

difference in boiling points of water and TEG. TEG boils at 207 o C (404 o F). The reconcentrated 

TEG after exchange with rich TEG in the lean /rich exchangers is pumped to 

the top of the contactor thus completing the cycle. 

The reboiler which supplies stripping steam to the regenerator is direct fired with coal bed 

gas. Also, the TEG is filtered with cartridge and charcoal filters to maintain high solution 




purity and to avoid foaming. Once the gas stream is dehydrated, it can be compressed and 

transported to downstream consumers. The TEG process is well established and can be 

purchased as a packaged system and transported to Ukraine for assembly at the gas 

processing site. 

3.3.4 Capital Cost Estimates for Compression, Processing and Transmission 

All of the market scenarios listed in section 3.3 require that the natural gas be at or near 

transmission pressure which for purposes of this assessment is assumed to be 1,000 pounds 

per square inch gauge (psig) (70.3 kg/cm 2 ). Gas will be collected as described in section 

3.3.3, compressed to 1,000 psig and dehydrated in the TEG unit. The compressed and 

treated gas will then be injected into a transmission system, and subsequently sold to the 

local or European gas market, used to generate power, or used to produce petrochemicals 

such as ammonia or methanol. The basic flow scheme for the scenario of CBM being 

injected into natural gas transmission pipelines follows: 

Coal Bed 

Methane from 

Field Collection 

System 

Coal Bed 

Compression 

System 

De-hydration 

Triethylene 

Glycol (TEG) 

Gas 

Transmission 

and Metering 

Exhibit 3.10: Flow Scheme - CBM to Injection into Gas Transmission Grid 

Gas Injection in 

Transmission 

System 

In order to determine the capital cost of each component of the flow scheme, requests for 

verbal pricing were sent to specialized suppliers such as General Electric for the 

compression system and ALCO, a major provider of packaged TEG units. Each provided 

valuable capital and operating costs for their systems. In order to arrive at a total installed 

cost for each component of the flow scheme, estimates were prepared by the consultant for 

the costs to install the equipment and provide “balance of plant” systems such as buildings, 

utilities and support facilities. 




3.3.4.1 Gas Compression 

The raw gas compression system will boost the pressure of the raw CBM gas from a few 

psig to 1,000 psig. The system will include: 

GE10-2 Gas Turbine Driver (See Technical Description - Appendix 3.C, p.3-31) and 

GE PCL Pipeline Compressor with 3 to 4 stages of inter-cooling (See Technical 

Description Appendix 3.D, p.3-34). 

GE estimates about 15,000 total horsepower in 3 or 4 compressor casings required 

(depending on whether 3 or 4 inter-cooling stages are involved). Based on this, GE could 

provide a 15,000 HP (ISO rating at 60 deg. F) GE 10 gas turbine compressor train (or more 

trains if more power is required due to de-rating at higher ambient temperatures) at an 

approximate cost of $7.3 MM USD. Final equipment configurations and cost would be based 

on engineering approvals of train torsional studies required on the configuration, intercooling 

efficiencies, and gas turbine considerations at site conditions (altitude, temperature 

corrections). Exhibit 3.11 summarizes the total capital cost of the compressor installed with 

all offsite and support facilities. 

Capital Cost Estimate – GE Gas Compression System 

Technical Description of Facility 

GE PCL Pipeline Compressor 3 to 4 compressor casings 

GE10-2 Gas Turbine Driver 14,000 Horse Power 

Gas consumption at full power 110 MM Btu/hr 

Emission per turbine 362,200 lbs/hr 

25 ppm Nox Max 

25 ppm CO Max 

Cost Estimate $MM 

Equipment Cost 7.30 

Transportation 0.4 

Import Duties and Taxes 1.56 

Total Cost of Equipment Delivered to Donetsk 9.26 

Installation for turnkey solution 2.77 

Offsite and support facilities 6.02 

Total Installed Cost of Compression Plant $US18.05 MM 

Exhibit 3.11: Capital Cost Estimate GE Gas Compression System 




3.3.4.2 Triethylene Glycol (TEG) Dehydration Unit 

The capital cost estimate for the TEG was based on a verbal quote from ALCO for a 

packaged TEG unit as described in Section 4.3.8. For gas volumes of 607.6 mNm 3 /d (21.45 

MM scfd) at 1000 psig, the approximate sizing of the unit (providing maximum 

turndown/flexibility of operation etc.) would be: 

60" I.D. trayed contactor (75,000 lbs) or 36" O.D. contactor w/ structured packing 

(25,000 lbs). 

1,500,000 Btu/hr glycol re-concentrator w/ glycol/glycol exchanger 10 US gallons per 

minute circulation rate. 

The following table summarizes the Total Capital Cost TEG unit installed with all offsites and 

support facilities. 

Capital Cost Estimate – ALCO TEG Dehydration Unit 


608 mNm 3 /d (21.45 MM scfd) Unit with 60” packed Tower Package 







Offsite and support facilities 1.25 

Total Installed Cost of TEG Plant $US3.75 MM 

Exhibit 3.12: Capital Cost Estimate – ALCO TEG Dehydration Unit 




3.3.4.3 Transmission and Metering 

The capital cost estimate for the transmission and metering was based on an in-house 

estimate of the cost of a transmission line to connect to the regional grid. It was assumed 

that the national grid is within 20 kilometers. 

Capital Cost Estimate – Transmission and Metering Station 


20 kilometers of buried pipe 







Line Pipe – installed including taxes 5.00 

Total Installed Cost of Transmission and Metering $US5.40 MM 

Exhibit 3.13: Capital Cost Estimate – Transmission and Metering Station 

3.3.4.4 Total Capital Cost for Processing and Compressing Gas for Pipeline Injection 

The total capital cost for compression, processing and metering the gas for pipeline injection 

is as follows: 

Summary of Capital Cost Estimate 

CBM Compression, Processing, Metering for Injection to Pipeline 


Gas Compression $US18.05 MM 

GE PCL Pipeline Compressor 

GE 10-2 Gas Turbine Driverr 

TEG Gas Dehydration System $US3.75 MM 

608 mNm 3 /d (21.45 MM scfd) Unit with 60” packed Tower Package 

Transmission and Metering $US5.40 MM 

20 kilometers of buried pipe 

Total Installed Cost of Compression, Processing, 

Transmission and Metering 

$US27.20 MM 

Exhibit 3.14: Summary of Capital Cost Estimate – Compression, Processing and Metering 




3.3.5 Gas Sales to the European and Ukrainian Markets 

Once the CBM has been compressed and dehydrated it can be injected into transmission 

lines for sale into either the Ukrainian or European markets 

3.3.5.1 Europe 

Added to the net back price are the costs for compression, processing and metering, along 

with the transmission fees for the gas to travel approximately 1600 km to a European market 

hub. ARI estimates this total cost to be US$387/mcm. Current European market prices are 

around US$450/mcm which would result in a margin of 16% for project gas sold to the 

European market. Future European prices are projected to rise to US$500/mcm and above 

which provides good upside for this market. 

3.3.5.2 Ukraine 

Gas sold into the Ukraine market only has incremental costs of the compression, processing 

and transmission to the local grid. These costs are estimated to be US$10/mcm and result in 

a total cost of $US360/mcm for sale into the Ukrainian market. As mentioned in section 3.1, 

the price Ukraine pays for imported gas from Russia and Central Asia is likely to rise towards 

a European price within the next few years. At a market price of US$400/mcm, the margin 

for project gas sold to the Ukrainian market would be 11%. 

3.3.6 Electrical Generation 

To be used as a fuel source for a combined cycle gas turbine, CBM can be collected, 

compressed, and dehydrated in a TEG (triethylene glycol) unit. The compressed and treated 

gas can then be used to inject into a local system connecting the field with a power 

generation facility. The heat from the turbine generators is recovered in a Heat Recovery 

Steam Generator and used to drive steam turbines, operating in a combined cycle 

configuration. 

For this market assessment, the net back price of the gas was converted to an equivalent 

“net back” power price of US$0.033/kWh. Incremental costs for the estimated capital and 

operating costs of a new power station, along with wheeling fees across the Ukraine national 

electrical grid, are estimated to be a further US$0.03/kWh for a total sales price of 

US$0.063/kWh. This is greater than the current power price of US$0.057/kW, so at this time 

using project gas for electrical generation does not appear to be economic. 


3.3.7 Transportation Market 



According to the International Association for Natural Gas Vehicles (IANGV), Ukraine ranks 

10 th in the world and 2 nd in Europe with 100,000 natural gas powered vehicles (in addition to 

147 refueling stations). 4 

Use of methane in the transportation sector is a growing market segment. The advantages 

of using CNG for the powering of vehicles are as follows: 

Increase energy security by reducing imported petrol fuel. Cars would still operate on 

petrol but would also have the option of using cheaper CNG around the major centers 

until such time as the CNG is available everywhere. 

Cleaner fuel burn and lower emission thereby improving the environment. 

Employment and investment opportunities would arise from this new industry. 

An export market would be created for the gas and the car kits. 

The conversion of vehicles may be eligible for carbon tax credits, further enhancing the 

value of this new industry. 

One possible disadvantage is: 

Opposition by the existing fuel companies who may view this gas as a threat to their 

monopolies on petroleum. The sale of petroleum will be substantially reduced by 

vehicles using CNG. 

When assessing the use of the CBM from the Donbass and Grishino-Andreyevskaya lease 

areas in the production of CNG, incremental costs for transmission, and compressor capital 

and operating costs, are added to the CBM net-back price. ARI estimates a final cost price of 

US$420/mcm. With a current (2008) equivalent pump price of $620/mcm, the CNG market 

appears to be a profitable potential market. 

3.3.8 Petrochemical Market 

Methane is an important feedstock for the production of a variety of chemicals in addition to 

being a fuel source to meet onsite power and/or process heat/steam requirements for a 

number of industrial applications. Natural gas is the most economic and widely used 

feedstock for the production of ammonia and methanol. 

4 IANGV < http://www.iangv.org/ngv-statistics.html > 




3.3.8.1 Ammonia 

Worldwide, the majority of ammonia production is consumed in fertilizer production while the 

remainder is used in the production of plastics, synthetic fibers and resins, explosives, 

pharmaceuticals, and numerous other chemical compounds. In 2007, worldwide ammonia 

production was estimated at 125 million metric tons. Ukraine was seventh in production, 

representing about 3.4% of world ammonia production (USGS, 2008). 5 Ammonia production 

is very energy intensive and is estimated to consume more than 1% of all man-made power. 

Approximately 33 MMBtu (0.9 mcm) of natural gas are needed to produce 1 ton of ammonia 

in a modern production plant 6,7 . For older production plants, anywhere from 37 to 61 MMBtu 

(1-1.7 mcm) are needed. At the calculated CBM field gate price of US$350/mcm, along with 

processing and transmission costs, the base cost of the gas delivered to an ammonia 

production plant to produce 1 ton of ammonia would range between US$325-600 per ton. 

This cost does not include the actual production of the ammonia. 

The market price for ammonia produced in Ukraine has risen sharply in 2008 from an 

average of about $250 per ton in 2007 to over US$500 per ton in early 2008, before settling 

back to US$400-450 per ton in the summer 8 . Even at US$450 per ton, the margin on using 

project gas for ammonia production is likely to be small and if the ammonia production plant 

taking the gas is not utilizing the most modern technology, then using project gas for 

ammonia production would likely be uneconomic. 

3.3.8.2 Methanol 

Methane is also an ideal feedstock for methanol, a common solvent used in antifreeze, 

windshield washer fluid, and as a denaturant for ethanol. Methanol itself is also a feedstock 

for biodiesel and other chemicals such as formaldehyde, plastics, paints, and explosives. 

Current (2008) prices for methanol are about US$370 per ton 9 . Using an equivalent Btu 

conversion, this is equivalent to a gas price of $710/mcm. As with the ammonia case, close 

to 1 mcm of natural gas is used to produce a ton of methanol. Therefore the base cost of the 

project gas delivered to a methanol production plant would be about US$360/mcm. This 

price does not include the production cost of the methanol, but if there is capacity at existing 

5 U.S. Geological Survey (USGS), Mineral Commodity Summaries 2008, January 2008, Nitrogen (Fixed) – Ammonia. 

6 Economic Research Service/USDA “Impact of Rising Natural Gas Prices on U.S. Ammonia Supply” WRS-0702 

7 International Food Policy Research Institute 

8 University of Nebraska-Lincoln Extension, Institute of Agriculture and Natural Resources, Crop Watch News 

Service 

9 Methanex regional prices Oct-Dec 2008 http://www.methanex.com/products/methanolprice.html 




methanol plants to take new gas, then using project gas to produce methanol appears to be 

economic. In the likely event that a new methanol production plant would have to be built, 

the additional base price to cover capital and operating costs would make the economics of 

methanol production more marginal. 

3.4 Summary of CBM & CMM Energy Equivalent Prices 

Power 

Market IRR Base Rate Incremental 1 

CMM – Generators 

Total Market Price Margin 

South Donbass No. 3 15% $0.044/kW $0.044/kW $0.056/kW 27% 

Bazhanov 15% $0.05/kW $0.05/kW $0.056/kW 12% 

CBM - Combined Cycle 

Gas Turbines 2 

Pipeline Sales 

25% $0.033/kW 3 

Europe 25% $350/mcm $37/mcm 5 

$0.03/kW 4 $0.063/kW $0.056/kW -11% 

$387/mcm $450.00/mcm 16% 

Ukraine 25% $350/mcm $10/mcm $360/mcm $400.00/mcm 11% 

Alternative Fuel 

CNG 25% $350/mcm $70/mcm 6 

Chemical 

Ammonia 25% 

$420/mcm $620.00/mcm 5 48% 

$350/mcm See explanation 3.3.8.1 $400-450/ton 

Methanol 25% $350/mcm $10/mcm $360/mcm 8 

$710/mcm 9 

very small to 

uneconomic 

see 3.3.8.2 

1 

All incremental costs for CBM include a price for the compression, processing and transmission cost. 

2 

Evaluated on net-back price of gas at field gate. 

3 

Equivalent price based on $350/mcm 

4 

Includes estimated capital and operating costs of power plant and wheeling fees. 

5 

Assumes a transmission fee of $1.70 per MCM per 100 km for 1600 km 

6 

Includes transmission fees to station, compressor capital and operating costs 

7 

Based on a price at the pump of UAH 3.60 per liter 

8 

Delivery cost to methanol plant – does not include the cost of production. 

9 Equivalent to $370/ton 

Exhibit 5-20: Energy-Equivalent Fuel Prices for CBM and CMM Prospects 

It is evident that natural gas can be an economic fuel substitute / alternative in many sectors. 

When the environmental benefits of the fuel are factored in, the value proposition is even 

greater. 




Appendix 3.A GOST Standard 5542-87 






















Appendix 3.B Caterpillar Statement of Supply 
















Appendix 3.C GE 10-2 Gas Turbine Technical Bulletin 










Appendix 3.D GE PCL Compressor Technical Bulletin 





Task 4 



Preliminary Design for CMM, CBM and Gas 

Utilization Infrastructure 

CMM, CBM & Gas Utilzation Infrastructure 4-i




4.1 Introduction......................................................................................................................4-1 

4.2 CBM Production Operations and Surface Facilities.....................................................4-1 

4.2.1 Production Operations .............................................................................................................4-2 

4.2.2 Artificial Lift – Downhole Equipment ........................................................................................4-4 

4.2.3 Artificial Lift - Surface Equipment.............................................................................................4-9 

4.2.4 Alternative Lift Systems .........................................................................................................4-15 

4.3 CBM Surface Facilities, Piping and Treating ..............................................................4-17 

4.3.1 Surface Facilities – Piping .....................................................................................................4-17 

4.3.2 Gas Metering .........................................................................................................................4-20 

4.3.3 Water Metering ......................................................................................................................4-21 

4.3.4 Separator Vessels..................................................................................................................4-22 

4.3.5 Gas Pipeline System Design .................................................................................................4-23 

4.3.6 Water Pipeline System Design ..............................................................................................4-24 

4.3.7 Compression..........................................................................................................................4-25 

4.3.8 Dehydration............................................................................................................................4-27 

4.3.9 Power Generation..................................................................................................................4-28 

4.3.9.1 Combined Cycle Gas Turbines ......................................................................................4-28 

4.3.10 Ammonia Production..............................................................................................................4-31 

4.4 CMM Surface Facilities..................................................................................................4-33 

4.4.1 Flaring ....................................................................................................................................4-33 

4.4.1.1 Benefits of flaring ...........................................................................................................4-33 

4.4.1.2 Flare design ...................................................................................................................4-34 

4.4.2 Power Generation from Coal Mine Methane (CMM) .............................................................4-35 

4.4.3 Surface Facilities for CMM Power Project .............................................................................4-36 

4.4.3.1 Gas Processing..............................................................................................................4-37 

4.4.3.2 Gas Engine / Generator .................................................................................................4-37 

4.4.3.3 Transformer....................................................................................................................4-38 

4.4.4 Upgrading CMM to Pipeline Quality.......................................................................................4-38 

4.5 U.S. Suppliers of Equipment, Technology, and Services ..........................................4-44 

4.5.1 Drilling Companies and Equipment .......................................................................................4-44 

4.5.2 Production Equipment............................................................................................................4-46 

4.5.3 Tubulars .................................................................................................................................4-48 

4.5.4 Logging, Completion & Stimulation........................................................................................4-49 

Appendix 4.A GE Combined Cycle Gas Turbine Technical Bulletin..................................................4-50 

Appendix 4.B Caterpillar 2500 kVA Coal Seam Power Module G3520.............................................4-55 

CMM, CBM & Gas Utilzation Infrastructure 4-ii




Exhibit 4.1 Typical CBM Isotherm .......................................................................................................4-2 

Exhibit 4.2 Simulated Production Profile of a Donbass Basin CBM/Tight Gas Sand Well..................4-3 

Exhibit 4.3 Rod Pump in a Well...........................................................................................................4-5 

Exhibit 4.4 Three-tube Down-hole Pump ............................................................................................4-7 

Exhibit 4.5 Gas Anchor Assembly .......................................................................................................4-8 

Exhibit 4.6 Proposed Well Head Configuration ...................................................................................4-9 

Exhibit 4.7 Soap Box .........................................................................................................................4-10 

Exhibit 4.8 Tubing and Well-head Equipment for Five Well Pilot ......................................................4-11 

Exhibit 4.9 Pumping Unit ...................................................................................................................4-12 

Exhibit 4.10 Sucker Rod Pump Design ...............................................................................................4-13 

Exhibit 4.11 Required Pumping Unit Parts and Equipment.................................................................4-14 

Exhibit 4.12 Cutaway of an R&M Energy Systems Moyno progressive cavity pump .........................4-15 

Exhibit 4.13 Motor Driven Progressive Cavity Pump...........................................................................4-16 

Exhibit 4.14 3-inch HDPE Pipe............................................................................................................4-17 

Exhibit 4.15 102mm (4-inch) Plastic Pipe Flanged Adapter................................................................4-18 

Exhibit 4.16 Schematic Layout of Surface Equipment ........................................................................4-19 

Exhibit 4.17 Barton Meter Run and Chart ...........................................................................................4-20 

Exhibit 4.18 Halliburton Flow Meter.....................................................................................................4-21 

Exhibit 4.19 Surface Facilities Listing..................................................................................................4-22 

Exhibit 4.20 2-Phase Vertical Separator .............................................................................................4-22 

Exhibit 4.21 3-Phase Horizontal Separator, Sivalls Inc.......................................................................4-23 

Exhibit 4.22 Turbine Compressor........................................................................................................4-26 

Exhibit 4.23 Typical Flow Diagram – Glycol Dehydration Unit ............................................................4-27 

Exhibit 4.24 Flow scheme for CBM to a Combined Cycle Gas Turbine for Electric 

Power Generation............................................................................................................4-28 

Exhibit 4.25 GE Combined Cycle Gas Turbine Plant Layout ..............................................................4-30 

Exhibit 4.26 Flow scheme for CBM to Ammonia Synthesis ................................................................4-31 

Exhibit 4.27 Enclosed and open flare designs ....................................................................................4-34 

Exhibit 4.28 Generalized Surface Facilities Configuration for CMM Power Project............................4-37 

Exhibit 4.29 Field Station Separators ..................................................................................................4-40 

Exhibit 4.30 Field Station Compressor ................................................................................................4-40 

Exhibit 4.31 Block Process Diagram of CMM Upgrade Facility ..........................................................4-41 

Exhibit 4.32 SulfaTreat Vessels...........................................................................................................4-41 

Exhibit 4.33 Deoxygenation Unit .........................................................................................................4-42 

Exhibit 4.34 CO2 unit, Nitrogen Rejection Unit and Compressor ........................................................4-43 

Exhibit 4.35 Sales Gas Compression Units.........................................................................................4-43 

CMM, CBM & Gas Utilzation Infrastructure 4-iii




The following section reviews the requirements for start-up operations and surface facilities 

for both CBM and CMM operations. The two areas are discussed separately as the gas 

composition and producing pressures for CBM and CMM are very different, which 

necessitates different gas treatment and production facilities for the two gas production 

streams. 

4.2 CBM Production Operations and Surface Facilities 

One of the most challenging aspects of developing a CBM project is the initiation of 

production operations, especially during the early stages of development. Start up 

production in CBM projects can present challenges with equipment, economics, and the 

patience of the operator. Up front operating costs are high because of the large volumes of 

produced water, the frequent servicing wells and replacing of pumps, or changing out of 

artificial lift equipment as needed, with little or no gas production to offset costs. It is 

important to apply experience to the types of equipment purchased to ensure their 

compatibility with CBM operations. Coal fines and sand production are normal during well 

startup and equipment should be designed to handle these solids on the surface as well as 

down hole. 

Reservoir drawdown is a critical aspect for CBM production and interruptions to dewatering 

will delay the production of natural gas. Water influx from the reservoir surrounding the wells 

will re-charge the matrix of the coal seams interrupting the desorption process of the gas. 

The artificial lift system must then remove this water from the coal matrix to re-establish gas 

flow and flow to the wellbore. Continued down time can severely impact the economics of a 

CBM project and solutions to the production problems should be resolved during the pilot 

project before full field development proceeds. The following section provides guidelines for 

the start-up of production operations and the installation of surface facilities for CBM 

processing, compression, and transportation. 

CMM, CBM & Gas Utilzation Infrastructure 4-1

4.2.1 Production Operations 



Poor production practices in coalbed methane operations can hamper well performance and 

can affect the outlook for project economics. If bottom hole production pressures are too 

high, the desorption process can be severely hampered. Exhibit 4.1 illustrates this point. 

Note that the slope of the isotherm is much higher at lower pressure than it is at higher 

pressure. The amount of gas desorbed “per psi of pressure drop” is much higher at low 

pressure than at high pressure. In this example, if the reservoir pressure is depleted by 50%, 

only 22% of the gas is desorbed, but if reservoir pressure is depleted by 90%, 72% of the 

gas is desorbed. In other words, ultimate gas recovery is increased more than 3 fold with 

less than double the pressure depletion. 

Exhibit 4.1 Typical CBM Isotherm 

The rate at which the well bore is dewatered is an important consideration for CBM 

operations. Produced coal fines are a problem that is common in coal bed methane 

development projects in the United States and throughout the world. Once fines are 

produced within the coal seam, water and gas can carry the fines to the well-bore, where 

specialty pumps are required to handle them. Mobilized fines can also collect in the flow 

paths within the reservoir (coal seam cleat system), causing flow restrictions or damage. 




It is thought that coal fine production is sensitive to the amount or degree of pressure 

drawdown through the cleat system with respect to the gas within the coal matrix. Rapid 

dewatering can cause a large pressure differential within the reservoir and increase the 

amount of damage. A gradual drawdown is required to minimize the pressure differential at 

any particular location in the reservoir. It has been found through empirical methods that the 

initial dewatering of the well bore should be done slowly to minimize the incremental 

pressure drawdown and the resulting mobilization of fines. In the U.S., operators generally 

determine the optimum dewatering rate through experience. Advanced Resources 

recommends a plan to dewater well-bores over a period of up to 8 months, depending on the 

drawdown rate. Eventually, the bottom hole pumping pressure should be maintained at 30 

psi or less. 

The water production profile for the type well in the Donetsk Region is presented in 

Exhibit 4-2. This profile indicates that initial water production rates are 1.4 m 3 /day 

(9 bbls/day). Production from the well should be monitored to gradually draw the water level 

in the well down. 

(Gas (m3/hour), Water (m3/hour X 100) 

1,000 

900 

800 

700 

600 

500 

400 

300 

200 

100 

- 



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 

Years 

Gas Water 

Exhibit 4.2 Simulated Production Profile of a Donbass Basin CBM/Tight Gas Sand Well 




Another operational consideration is down-hole pump failure. The “cost” of a pump failure is 

not just the down time associated with pump replacement. Water saturation of the coal-cleat 

system is replenished to some degree during this downtime. As a result, the dewatering 

process can be set back by several days or even weeks for each period of downtime. The 

reliability of the pumping system is critical to the success of the pilot project. 

4.2.2 Artificial Lift – Downhole Equipment 

Three forms of artificial lift are commonly used for CBM in the United States: Electric 

Submersible Pumps (ESP), Progressing Cavity Pumps (PCP), and Sucker Rod Pumps 

(SRP). The recommended artificial lift mechanism for the Donetsk Project, at least initially, is 

a SRP with surface pumping unit and electric motor or gas powered engine. The pump 

designs that lift adequate amounts of water and fit within recommended 60 mm (2 3 /8 inch) 

tubing are available from U.S. manufacturers. A tubing pump, where the pump barrel screws 

into the bottom of the tubing, is an option for high water output where a larger pumping unit is 

employed. 

The SRP recommended for the program is sized to handle 8 cmd (50 bwpd), a rate that 

exceeds the calculated average producing rate during the first 12 months of production. This 

will allow time to draw the water level in the well down gradually and minimize coal fine 

production that can damage the reservoir permeability and cause operational problems. A 

tubing anchor is an optional piece of equipment that prevents the tubing from expanding and 

contracting, shortening the effective stroke length of the pump. The design indicates a 

motion for the pumping equipment of 1.37 (54) / 32 (1.25) / 8, which is sufficient to produce 8 

cmd (50 bwpd) and draw down the reservoir pressure. The motion of a SRP design 

indicates the stroke length in meters (inches), the plunger diameter in millimeters (inches), 

and the strokes per minute the unit will be moving. The slow speed indicated by this design 

minimizes strain on the tubing and the need to anchor it. 

SRP systems are simple to operate over a wide range of operating parameters, and are 

mechanically durable and reliable. The disadvantage of a SRP system is that they are not 

considered ideal when large amounts of sand or coal fines are encountered, but these 

problems are minimized in U.S. CBM operations by lowering the fluid level gradually, 

monitoring the pump speed and adjusting the pump level in the well bore. The down-hole 

pump should be placed well below (approximately 10 to 20 meters) the lowest perforation in 

the well once the initial frac sand production has settled. This down-hole pump placement will 

allow primary separation of the gas and water production in the well-bore, as the water will 




tend to flow down to the pump by gravity, where it will be produced up the tubing, and the 

gas will flow up the casing/tubing annulus. This primary separation will also prevent gas 

locking of the pump. 

A rod pump design consists of a down hole pump, rods and tubing in the well. Exhibit 4.3 

illustrates a typical down hole pump and well bore configuration. 

Exhibit 4.3 Rod Pump in a Well 




Many new wells go through a clean up period that precludes running pumps below the 

perforations due to the amount of frac sand, coal fines, and debris left over from drilling and 

completion operations. The pump should then initially be run above the perforations when 

excess proppant or fines are detected during completion clean up or multiple failures occur in 

the pump of a new well due to proppant and fines. A SRP run above perforations is 

susceptible to gas locking; consequently gas anchors and mud anchors can be run in 

conjunction with the pump. The initial clean-up time usually takes 2 to 6 months, depending 

on the type of completion and the reservoir. 

Gas and mud anchors are somewhat effective, but some dissolved gas can bypass these 

measures. Progressive cavity (PC) pumps can be effective in wells that continue to severely 

gas lock rod pumps over long periods of time, especially where significant solids production 

is a problem. PC pumps do not have valves, the rotor turns within a stator pushing fluids 

through the pump, and are not subject to gas locking. There are advantages to rod pumped 

CBM wells however, due to the versatility of pumping units and the variety of rod pumps 

available. A rod pump can produce in a pumped off condition which is important in the 

mature stage of a CBM field when the reservoir is drawn down to minimum pressures. 

Under the right conditions, a rod pump can produce as much as 150% of its capacity with 

gas lifting water through the pump and lightening the fluid column in the tubing. Another 

problem that frequently occurs in new wells or virgin reservoirs is gas associated within the 

water production. Gas locking will occur as dissolved gas is liberated from the water by the 

suction at the pump intake and fills the pump barrel with free gas. The free gas expands and 

contracts as the traveling valve moves up and down the barrel preventing water from 

entering the pump suction. 

Advanced Resources International recommends utilizing sucker rod pumping units and “3tube” 

down-hole insert pumps for a new project. Exhibit 4-4 illustrates the mechanics a of 

three-tube down-hole pump. 

Three-tube pumps are sometimes referred to as “trash” pumps, since they produce abrasive 

sand and coal particles with less wear. The 3-tube pump works because it uses three loosely 

fitting, telescoping tubes in place of the tight tolerance barrel and plunger used in other 

pumps. Particles can pass through the barrel tubes due to the loose tolerance of the fit. A 

standard assembly, 7.62 m (25 ft), or extended stroke assembly adding 4.6 m (15 ft) of 

length is required. The recommended pump bore is 32 mm (1¼ inches) in diameter. 


Upper Traveling 

Valve 

Pull Tube #1 

(inner) 

Pump barrel #3 

(outside) 

Plunger 

Lower Traveling 

Valve 



Exhibit 4.4 Three-tube Down-hole Pump 

Pump barrel #2 

(middle) 

Gas Anchor Dip Tube 

Barrel Stop (no-go) 

Standing Valve 

Cup Type Hold Down 

A gas anchor assembly for the casing can be used to improve the effectiveness of a SRP if 

problems with gas locking are encountered. A gas anchor, Exhibit 4.5, is compromised of a 

2 piece mud anchor, dip tube, and bull plug. Fluid enters the mud anchor through the 




perforations of the top 73 mm (2 7 /8-inch) section and travels down the annulus of the 

assembly into the 89 mm (3 ½-inch) section where it is drawn into the 25 mm (1-inch) dip 

tube and into the pump suction. The larger 89 mm (3 ½-inch) section creates more annular 

area in the assembly and therefore a lower flow velocity down the gas anchor and into the 

pump. The lower velocity allows more gas break out, creating bubbles that group together 

and rise up and out of the anchor. 

Exhibit 4.5 Gas Anchor Assembly 


4.2.3 Artificial Lift - Surface Equipment 



In this section the surface equipment necessary to produce CBM wells is described. The 

surface facilities require a well head equipped with a stuffing box, a polish rod, pumping unit, 

and a prime mover. It is recommended that a simple wellhead configuration be used. Exhibit 

4.6 illustrates the type of wellhead configuration used in the Appalachian Basin which will be 

suitable for use in Ukraine. The use of this type of simple wellhead design will be a low cost 

capital and operating alternative relative to more complex designs. Gas flows through the 

lower piping wing valve (12) to the well separator where water vapor is knocked out of the 

gas stream before proceeding to the orifice meter. Water is pumped through the upper wing 

valve (8) down the flow line to the gathering system and on to disposal. A bypass can be 

added to these wing valves to allow the water leg to be produced through the separator so 

gas from the tubing can be measured. 

1. Polish Rod 

2. Rod Clamp 

3. Stuffing Box 

4. Flow Tee 

5. Wing Valve 

6. Casing Head 

7. Intermediate Casing Head 

5 

6 

7 

3 

2 

4 

1 

11 

Exhibit 4.6 Proposed Well Head Configuration 

CMM, CBM & Gas Utilzation Infrastructure 4-9 

9 

10 

8 

12 

8. Water Production 

9. Tubing 

10. Hammer Nut 

11. Production Casing Head 

12. Gas Production



A soap box should also be considered since water does not lubricate the stuffing box and 

heat generated by the polish rod erodes the rubbers, resulting in leakage at the wellhead (the 

stuffing box must be greased regularly). The soap box clamps around the polish rod and 

contains a wick that rides against the polish rod. Motor oil or surfactant is added to the box 

regularly to lubricate the polish rod. Exhibit 4.7 illustrates a soap box and the internal parts. 

Exhibit 4.7 Soap Box 

The tubing and wellhead equipment are designed to be compatible with the casing and 

polish rod. The wellhead consists of standard equipment beginning at the top with a stuffing 

box threaded to a 51 mm (2-inch) line pipe connection to the flow tee. Water and gas 

produced up the tubing is sent through the ball valve to surface production equipment. 

In the case of the pilot well program, the bottom of the flow tee is a 60 mm (2 3 /8 inch) EUE 

thread which connects to the tubing string and is packed off at the 140 mm (5½ inch) casing 

head and held with the tubing hanger/pack off. The piping from the annulus of the 140 mm 

(5 ½ -inch) casing head has a 51 mm (2-inch) wing valve which will control the annular gas 

production sent to the separator and gas meter run. The 140 mm (5½ inch) casing is landed 

within the 220 mm (8 5/8 –inch) intermediate casing head. 




Advanced Resources recommends that 60 mm (2 3 /8 inch) tubing be run in the wells to allow 

adequate annular space in the well bore. The required tubing and well-head assembly 

components for an initial five-well pilot are shown in Exhibit 4.8. 

Tubing Units Per Well 5-Wells 

60 mm (2 3 /8in)., J-55, 4.6 lb /ft ERW R2 T&C Meters 1100 5500 

Well-head 

220x114 mm (8 5 /8in X 4 1 /2in) casing head Unit 1 5 

114x60 mm (4 1 /2in X 2 3 /8in) tubing head Unit 1 5 

60 mm (2 3 /8in) 8rnd nipple Unit 1 5 

60x33 mm (2 3 /8in X 1 5 /16in) dbl pack stuffing box Unit 1 5 

114x60 mm (4 1 /2in X 2 3 /8in) tubing anchor Unit 1 5 

Misc: tees, elbows nipples, unions, ball valves Set 1 5 

Exhibit 4.8 Tubing and Well-head Equipment for Five Well Pilot 

Initially, the pumping units will require 10 hp motors, however, after 12 to 18 months some 

wells will no longer require this much horsepower. These motors should be transferred to 

new wells and replaced with smaller ones. The motors will be sized based on the amount of 

water production from the individual wells at the time. A good average estimate is that 5-10 

hp motors will be required. The economics assume the use of 10 hp motors for the life of the 

wells. Exhibit 4.9 shows a small type pumping unit typical to the Appalachian Basin. 




Exhibit 4.9 Pumping Unit 

Advanced Resources recommends the use of the following pump jack, rods, and down hole 

pump per API nomenclature based on the rod pump design presented in Exhibit 4-10. The 

design is based on the following criteria: 

• Pump Jack: C-80D-119-64 

• Rods: 16mm ( 5 /8-inch), grade D 

• 3-Tube Insert, 32 mm (1.25 in) Bore, 7.62m (25 ft) Standard Assembly 

• 11.2 meter long mud anchor with 4 columns x 17 rows of 9.5 mm (3/8-inch) holes at top 

• 5 meter long dip tube with 4 columns x 20 rows of 9.5 mm (3/8-inch) holes at bottom 

• A tubing anchor is not recommended at 8 cmd (50 bpd) 

• A 10 hp nema D type limited slip motor (initially) 

• Unit motion: 1.37 m stroke length / 32 mm plunger / 8 strokes per minute (54 inch stroke 

length / 1.25 inch plunger / 8 SPM) 


QRod Application 

Results 

Rate (100 % Pump Eff.) 73 bbl/day 

Rate (95 Pump Eff.) 70 bbl/day 

Rod Taper, % 26.3, 73.7 

Top Rod Loading 34.9 % 

Min API Unit Rating 80-95-54 

Min Motor Size 4.2 hp 

Polished Rod Power 2.2 hp 

TVLoad 7,700 lbs 

SVLoad 

Design Inputs 

6,200 lbs 

Unit Type CWConv 

Pump Depth 3600 ft 

Target Rate 70 bbl/day 

Stroke Rate 8.0 SPM 

Surface Stroke 

Length 

54 in 

Pump diameter 1.25 in 

Tubing Size 

Anchored Tubing No 

2.375" (4.7 lb/ft) 

1.995" ID in 

Rod Type Steel Rods 

Rod Number 87 

Rod Grade D 

Default Settings 

Total Sinker Bar Weight 0 lb 

Fluid Specific Gravity 1 

Tubing Pressure 30 psi 

Casing Pressure 10 psi 

Damping Factor 0.1 

Unit Efficiency 95 

Pump Efficiency 95 

Pump Intake Pressure 10 psi 

Echometer Company 

5001 Ditto Lane 

Wichita Falls, Texas 76302 



Plots 

PPRL 8,900 lbs MPRL 5,200 lbs 

Pump Stroke Length 50.3 in Fo 1,600 lbs 

Fo/Skr 0.051 Kr 566 lb/in Kt 1,109 lb/in 

Peak GearBox Torque 67 Kin-lbs 

Counter Balance Moment 208 Kin-lbs 

Counter Balance Effect 8,200 lbs 

QRod Version 2.0 

Copyright 2004 Echometer Company. All 

Rights Reserved. 

Conditions of Use and Legal Notices 

Exhibit 4.10 Sucker Rod Pump Design 

Phone: (940) 767-4334 

Fax: (940) 723-7507 

E-Mail: info@echometer.com 




Exhibit 4.11 presents a list of materials for a 5-well pilot project that will be required for the 

pumping unit design discussed above. 

Pumping Unit Units Per Well 5-spot 

60 mm (2 3 /8-in) (32mm - 1 1 /4 in bore) 3-tube pump Unit 1 5 

16 mm ( 5 /8-in) Grade D sucker rods w/ couplings Meters 1050 5250 

Ft. 3450 17250 

Pony Rods, 0.5-3 m (1 1 /3, 2, 4, 6, 8 & 10 ft) lengths Set 1 5 

29mm x 3.35m (1 1 /8-in x 11ft) polish rod Unit 1 5 

33mm x 1.8m (1 5 /16-in x 6 ft) polish rod liner Unit 1 5 

Sucker rod guides Unit 280 1400 

29mm (1 1 /8-in) rod clamp Unit 1 5 

Pump jack CCW 80D-119-64 Unit 1 5 

10 hp 1ph 1800 rpm electric motor Unit 1 5 

10 hp electric weatherized electric control box Unit 1 5 

Belts, sheaves, electric cable and other misc. Unit 1 5 

Exhibit 4.11 Required Pumping Unit Parts and Equipment 

The pumping units specified can operate on either electricity or natural gas. Electricity is the 

most practical method for large block developments and can be tied to the installation of a 

gas-fired electrical generator. The generator can be fired using the production from the wells 

as they reach the required volumes and operating reliability. Until then, electricity can be 

purchased from a local power grid, or diesel powered generators could be utilized. A flare 

stack will be needed to burn excess gas until the reservoir is de-pressured and gas 

production is consistent. 

In a typical CBM installation, gas is produced from the casing/tubing annulus, and water is 

produced from the tubing. It is necessary to measure both the gas and water production 

streams, in addition to the well-head volumes. Gas and water meters should be installed at 

the outlets of each separator on the gas and water legs. 


4.2.4 Alternative Lift Systems 



A typical CBM development requires a variety of production capabilities from the artificial lift 

equipment. Some wells may have high permeability and high water producers which will 

require larger pumping units, PCPs or even ESPs to de-water the reservoir. Other wells may 

have fewer intervals completed or lower permeability in the reservoir and can be pumped off 

with insert SRPs and smaller pumping units. Solids production is a significant influence on 

the type of artificial lift deployed. When hydraulic fracturing is used to 

stimulate the wells, frac sand and coal fines will be a problem until the 

well cleans up and the solids production moderates. Coal fines will 

continue to migrate to the wellbore even after the initial well 

completion is cleaned up, but with the proper equipment and handling, 

fines can be produced to surface and managed. Specially designed 

PCPs and SRPs handle solids production better than ESPs, but each 

has drawbacks and advantages and individual wells must be analyzed 

to determine the best method of production. 

PCPs are an acceptable alternative, but their operations are more 

complex, and require a greater degree of training for operating 

personnel (Exhibit 4.12). The pumps must be monitored closely as 

they will fail if pumped dry. Control panels used with PCPs can shut 

the pump down based on the torque of the rod string and will prevent 

the pumps from operating dry. A down-hole pressure transducer can 

also be installed in the event that rod torque is not adequate to 

monitor fluid level in the well. It is critical that this type of pump not run 

dry since the fluid, in this case water, acts to lubricate and cool the 

pump. Without fluid moving through the pump, friction causes heat 

build up quickly and destroys the material in the stator. 

Exhibit 4.12 Cutaway of an R&M Energy Systems Moyno progressive cavity 

pump 




Exhibit 4.13 illustrates an installed PCP drive-head. The compact size of the drive-head can 

be an advantage where space is at a premium. Progressive cavity pumps are also very 

good at transporting large amounts of sand and coal fines in the produced stream and may 

be used in wells where SRPs cannot handle the solids. Control panels with variable 

frequency drives and torque sensing controls are available to manage the operation of the 

pumps and prevent premature failure. The drive head is attached directly to the well head 

and usually have feet that brace the weight of the unit. The prime mover (electric motor) is 

mounted directly to the drive head. Where gas fired engines are used, a belt and pulley 

system is employed. 

Exhibit 4.13 Motor Driven Progressive Cavity Pump 

Another artificial lift alternative, electric submersible pumps (ESPs), are used where there is 

a need to move large amounts of water from the reservoir over long periods of time. They 

require adequate monitoring of the fluid levels with little solids production and will fail in a 

very short time if pumped off. ESPs can be applied on the down dip side of the reservoir, in 

highly productive areas to intercept water influx and de-water the reservoir more efficiently. 




4.3 CBM Surface Facilities, Piping and Treating 

In this section, a preliminary design of the surface facilities required to collect, treat, and 

market the produced CBM is presented, including dehydration, compression, and 

transportation. Also provided in this section are conceptual designs of the required surface 

facilities to handle, treat, and dispose of the water produced during the dewatering phase, 

including flow-line requirements and treatment plant specifications. The sizing of the surface 

facilities is based on the modeled gas and water production streams derived from the 

reservoir simulation study. 

4.3.1 Surface Facilities – Piping 

CBM gathering systems generally utilize high density polyethylene (HDPE) piping because of 

the low operating pressures. Piping up to 150 mm (6-inch) and 2070 kPa (300 psi) is readily 

available and higher pressure pipe can be found. Black or orange HDPE pipe is transported 

in rolls from the manufacturer and can be ordered in specific lengths (Exhibit 4.14). 

Connections are made using a ceramic fusing tool which is heated with a propane torch or in 

larger installations a mobile fusing machine mounted on wheels or tracks is also available. 

Exhibit 4.14 3-inch HDPE Pipe 




Each end of the pipe is squared and heated in the hand tool to a prescribed temperature 

then fitted together and allowed to cool. Properly fused, the strength of the connection is 

equal to that of the body of the pipe. Straight joint lengths of plastic pipe can be utilized for 

low pressure header sites where many wells are connected to a central separator. Flanged 

connections are also available for plastic pipe (Exhibit 4.15) and are used for convenience or 

higher pressure applications. 

Exhibit 4.15 102mm (4-inch) Plastic Pipe Flanged Adapter 

HDPE is particularly effective for water handling since it does not corrode and is not affected 

by H2S or CO2. Care must be taken when buried though, since stones and sharp objects can 

cut the plastic. Gas is usually produced up the casing/tubing annulus, and the water pumped 

through the tubing. The annular gas is separated in order to remove any additional free 

water, and likewise, the water leg is separated in order to remove any entrained gas. It is 

necessary to measure the separated gas and water volumes in addition to the well-head 

volumes. Gas meters are necessary on the gas outlet of each separator, and water meters 

should be placed on the water outlet of each separator. 

Water disposal will likely be required, but the disposal method will depend in large part on the 

water quality and environmental considerations. There are numerous options for the 

treatment of produced water to bring the quality to a standard suitable for local agricultural 

use or surface discharge. If there is an agricultural need in the project area, beneficial use for 

the water may include crop irrigation or animal watering. One method to raise the water 

quality is to install a reverse osmosis unit, and construct a large lined pit for storage 

purposes. Water produced from the project might require treatment before it could be 




discharged into the local watershed. The capital and operational costs for surface discharge 

may need to include active treatment costs for reverse osmosis and the drilling of a disposal 

well with corresponding installation of injection facilities to dispose of the highly saline 

effluent. A complete discussion of water treatment options is presented in Section 9, 

Environmental Assessment. 

The most efficient water disposal method will be determined by the quality and quantity of 

water to be handled and local and government regulations. Local environmental factors 

should be evaluated as field development proceeds. Exhibit 4.16 is a schematic layout of the 

surface facilities proposed for an initial 5-well pilot project. 

Exhibit 4.16 Schematic Layout of Surface Equipment 


4.3.2 Gas Metering 



Advanced Resources recommends using an ITT Barton Model 202E flow recorder as they 

are reliable and used extensively in the United States natural gas industry. The initial project 

will require gas metering stations consisting of the following items: 

Barton Mechanical Orifice Meter Recorder - 5m-690kPa-65°C (200"-100 psig-150 °F) 

3-Valve 9.5mm (3/8") SS Tubing Manifold- 

2-Tap Valves for Daniels Orifice Fitting- 

Leveling Saddle for Line Size-51mm (2") 

Galvanized Pipe Meter Mount for Saddle 

Set(2) 9.5mm x 1.5m (3/8inch x 5ft) SS Tubing w/Fitting for Gage Lines 

Orifice Plates and Orifice Plate Seal Rings 

Orifice Meter Tubes 

Ancillary parts required for the meter runs include charts, a Sony orifice computer and ink 

pens. Exhibit 4.17 is a photograph of a Barton meter run below the chart recorder housing. 

The chart recorder is shown with an active chart. 

Exhibit 4.17 Barton Meter Run and Chart 

Electronic style metering is also available and should be considered when full field 

development goes forward. 


4.3.3 Water Metering 



Water meters for use in metering injected water during injection-falloff testing can also be 

used to meter water production from the project. In the Appalachian Basin, water tanks are 

generally located on each well site, and water volumes are measured by tank gauge. 

Measuring produced water is an essential part of any CBM program as the data are required 

for history matching and to diagnose down hole problems with pumps. 

Several brands of turbine flow meters are available on the market, including the flow meter 

shown in Exhibit 4.18, manufactured by Halliburton. The unit consists of two parts: a turbine 

flow meter, and a flow analyzer. The flow analyzer is designated as the Model MC-II Flow 

Analyzer, and has the capability to display instantaneous rate and display and record 

cumulative flow. The flow meter has 32mm (1¼ inch) npt pins on both sides. Careful 

attention should be paid to entering the correct flow meter calibration factors into the flow 

analyzer. 

These flow meters are suitable for rugged field usage and are equipped with batteries that 

last for five years. Extra batteries and turbine meter redress kits should also be ordered. Full 

instructions are included in each kit. Turbines Inc. is another manufacturer that provides 

reliable equipment with various recording and data transmitting capabilities including RTUs 

that report data via radio or phone modem. 

Exhibit 4.18 Halliburton Flow Meter 




Exhibit 4.19 is a listing of surface facilities materials required for the 5-well pilot project. 

Surface Facilities Units Per Well 5-spot 

610mm OD x 2.13 m (24inch x 7ft) separator w/ 51mm 

(2in) trim and base plate 

915mm OD x 3.05 m (36inch x 10ft) separator w/ 76mm 

ea n/a 1 

(3in) trim and base plate 

HDPE 3408 114mm (4.5in) OD x 80mm (3.16in) SDR-7, 

ea n/a 1 

54.2 kg/m 3 (3.384 lb/ft) meter 400 2000 

Flare stack ea n/a 1 

Industrial reverse osmosis system ea n/a 2 

Gas meter run ea n/a 8 

Water meter run ea n/a 7 

Pressure regulators ea n/a 10 

Plastic liner for evaporation/storage pits m 2 

n/a 3600 

Gas fired electric generator ea n/a 1 

Power lines, ancillary equipment meter 400 2000 

4.3.4 Separator Vessels 

Exhibit 4.19 Surface Facilities Listing 

In order to save on cost, it is recommended that separators, flare stacks and water pits be 

located at a central facility. Gas can be metered from the individual well piping at the central 

facility, but readings will be upstream of the separators and may contain water vapor. Two 

separate systems are required to move the gas and water to a central facility where each can 

be processed. Exhibit 4.20 is a two phase vertical separator common to U. S. CBM 

operations. 

Exhibit 4.20 2-Phase Vertical Separator 




In low water volume settings vertical separators are commonly used, whereas in the Western 

U. S. a horizontal orientation is the most common due to higher water production (Exhibit 

4.21). As long as the separator is efficient in separating water and gas, orientation is not 

critical in this application. 

Exhibit 4.21 3-Phase Horizontal Separator, Sivalls Inc. 

4.3.5 Gas Pipeline System Design 

The in-field pipeline gathering system requires various diameters of pipe at different intervals 

to be efficient. The first component is a series of relatively large diameter pipelines designed 

to move gas or water from the field to the central treatment facility. These large diameter 

pipelines are referred to as “trunklines”. The second component is a series of relatively small 

diameter pipelines designed to move gas or water from the wellhead to the trunkline, referred 

to as “flowlines”. Intermediate lines between the trunk and flowlines are sometimes referred 

to as “gathering lines” and are necessary as the system grows with field development. The 

large, high-pressure gas pipe line that would move the gas from the project area to a market 

is referred to as a transmission pipeline. 

In order to optimize coalbed methane production, it is necessary to maintain the lowest 

possible pressure at the wellhead. Ideally, wellhead pressure would be maintained at zero 




psi, but, because of economic and practical constraints, this is not possible. An Excel-based 

program written by Advanced Resources based on the Weymouth equation for flow of 

natural gas through pipelines can be used to determine the appropriate pipeline diameters, 

based on the length of each pipeline segment and the amount of gas flowing through each 

segment. Similarly, the optimum diameter and configuration of the gathering system can be 

determined using Advanced Resources’ Weymouth Equation Program. The result of the 

gathering system analysis for the initial wells can be extrapolated to future development as 

the field expands. 

The pipeline diameters and lengths are used to estimate the capital cost of the pipelines and 

to determine the material used such as the high-density polyethylene (HDPE) pipe. The use 

of plastic pipe is considered ideal for CBM applications for two reasons: 1) CBM production 

only requires pressure well below the maximum operating pressure of plastic pipe, and 2) 

CBM wells tend to be long lived, and buried plastic pipe will last a long time with little or no 

maintenance. Plastic pipe may be purchased for approximately $1.65/kg, plus shipping, 

trenching, laying and jointing costs. 

Assuming a field pipeline pressure of 0.7 kg/cm 2 (10 psig) at the central facility (future 

compression site with field development), the pressure will increase in the trunklines at 

greater distances from the central facility and as more gas accumulates in the pipe. In the 

U.S., CBM operators attempt to maintain wellhead pressures of 2.8 kg/cm 2 (40 psig) or less. 

Based on this, it was determined that pressures in the trunkline system should not be 

allowed to build up more than 2.1 kg/cm 2 (30 psig) at the point of maximum field production. 

This will allow for a maximum pressure of 2.8 kg/cm 2 (40 psig) at the most distant well site by 

using the appropriate pipeline diameters. It should be noted that this maximum pipeline 

pressure will exist at the most distant well sites, and only during peak field production. It 

should also be noted that the pressures in the water pipeline system are completely 

independent of the gas pipeline system. 

4.3.6 Water Pipeline System Design 

Because of the amount of water predicted by the simulation study, Advanced Resources 

recommends constructing a system of pipelines to transport the water to a central facility 

where it will be processed and disposed. The sucker rod pumping system (SRP) described 

above was designed to deliver water to the surface at a well-head pressure of 3.52 kg/cm 2 

(50 psi). The gathering system is designed to handle this pressure and there is enough 

pressure from the downhole pump to transport the water to a central facility. Topography or 




other localized factors determine the need for localized transfer pumps within a pipeline 

system and it may be necessary to install some minor pump capacity in the gathering system 

as field development progresses. 

The gathering and trunk water pipelines can be laid in the same right of way as the gas 

pipelines, resulting in considerable savings. The water pipelines will be constructed from the 

same HDPE pipe used for the gas lines. Exhibit 4.16 shows a schematic representation of 

the gas and water piping system for the 5-well pilot project. 

An Excel based program developed by Advanced Resources that calculates frictional 

pressure drop for fluid flow through pipelines can be used to determine the appropriate 

pipeline diameters based on the length of each pipeline segment and the amount of water 

flowing through each segment. Gathering pipeline diameters are determined in a manner 

similar to the one utilized to determine the gas gathering pipeline diameters detailed above. 

4.3.7 Compression 

Because of the relatively long time period required to fully develop a CBM field, designing an 

optimal gas compression system represents a significant challenge. If an operator installs 

one large compression facility at the beginning of the project capable of handling total 

anticipated gas volumes, too much capacity would go unused for too long a period of time. 

Alternatively, an operator also should not install compression on a well-by-well basis, 

because operating and maintenance costs for so many units would quickly become 

logistically difficult and operationally expensive. Therefore, compression must be installed in 

a way that will both make efficient use of total capacity, and provide for economy of scale. 

The pilot project will not require compression, but should the pilot project prove successful 

and additional wells drilled, the capacity of the gas pipeline will be exceeded. Compression 

is required to maintain the gathering system at a recommended suction pressure of about 0.7 

kg/cm 2 (10 psi) at the central gathering, which would result in a backpressure at the wellhead 

of about 2.1 kg/cm 2 (30 psi). 

Advanced Resources recommends sizing the compression to a capacity of gas representing 

1.5 years of drilling. Ultimately the number of compressors will be determined by the volume 

of gas per well, the number of wells drilled, and the timing of the drilling program. Phasing in 

the compressor capacity is the most economical way to maintain an adequate volume at the 

lowest pipeline pressures and efficiently add compression. 




The older wells in the field will decline to a stable gas production rate as drilling increases the 

number of wells and gas volumes produced into the pipeline system. Compression is sized 

to move the maximum produced volume at a reasonable pipeline pressure. Once a new gas 

field is established it is important to maintain a stable gas production rate into the pipeline 

system in order to efficiently operate the compression capacity. 

Gardner-Denver, Caterpillar, and Ariel are leading manufacturers of drivers and compression 

units in the United States. The unit(s) should maintain a low suction pressure within the field, 

on the order of 0.7-2.1 kg/cm 2 (10-30 psig), and the output required to enter the 

transmission/fuel line system. The number of stages needed for the compression will 

depend on the suction and discharge pressures required to produce the wells and compress 

the gas into the transmission line and the compression ratios of the equipment. Three and 

four stage compression is common in CBM projects in the United States due to the low 

suction pressures required to maintain CBM production and the high required pressures for 

the interstate transmission lines. Reciprocating and turbine type compression units are 

available. The gas volumes predicted with full field development make turbine compression 

attractive to the Donbass project due to its efficiency. 

Exhibit 4.22 Turbine Compressor 


4.3.8 Dehydration 



Coalbed methane produced from the Donbass project will require dehydration once full field 

development is established. A dehydration unit comprises a major part of the compression 

and treating system, and must be designed in a manner consistent with the phased 

installation of compression. As a result, the installation of dehydration units should be 

coordinated with the compression. Dehydration units range from small units for individual 

wells to units capable of handling 283 Mcmd (10 MMcfd) of water saturated gas and 

delivering outlet water equal to or less than imperial 112 kg/MMcm and larger. 

Various types of dehydration systems are available including the glycol dehydrators, i.e., 

triethylene glycol (TEG), the most popular, and diethylene glycol (DEG) as well as desiccant 

types. Some dehydrators use a mix of solvents in various concentrations of TEG and DEG. 

The glycol dehydrators are the most effective in removing water from gas, however they do 

allow some emissions of methane and volatile organic compounds (VOCs). Glycol 

dehydrators vary in size from 75 mcfd (2 MCMD) units to several mmcfd units. Desiccant 

type dehydrators are less efficient, but release less emissions in their process. A glycol 

dehydrator consists of a wet gas inlet, contacting tower, rich glycol pump, a heat exchanger, 

glycol reboiler/regenerator, and a lean glycol pump. Desiccant type dehydrators are similar 

in nature with the exception of glycol regeneration equipment. 

Exhibit 4.23 Typical Flow Diagram – Glycol Dehydration Unit 


4.3.9 Power Generation 



As discussed in the artificial lift section above, the largest power requirement of the CBM 

project will be the electric motors that drive the sucker rod pumps. CBM projects are most 

successful when operations are continuous, and this implies that a reliable electrical power 

source should be available. Relative to the size of power generation units required, either 

reciprocating or turbine driven generators are appropriate for the Donbass CBM Project 

application. 

The critical parameters to examine between reciprocating or turbine drive generator sets are 

capital cost, operating cost, and fuel efficiency. One significant factor is the capital cost and 

fuel cost of the turbine type of engine which is approximately 3.4 times and 1.14 times that of 

the reciprocating engine respectively. However, the operating cost (excluding fuel) of the 

turbine is only 22% of the reciprocating engine. 

4.3.9.1 Combined Cycle Gas Turbines 

To be used as a fuel source for a combined cycle gas turbine, CBM can be collected, 

compressed, and dehydrated in a TEG (triethylene glycol) unit. The compressed and treated 

gas can then be used to inject into a local system connecting the field with a power 

generation facility. The heat from the turbine generators is recovered in a Heat Recovery 

Steam Generator and used to drive steam turbines, operating in a combined cycle 

configuration. 

Exhibit 4.24 Flow scheme for CBM to a Combined Cycle Gas Turbine for Electric Power Generation 

Specialized suppliers for the above components include General Electric for the compression 

system, ALCO, a major provider of packaged TEG units and General Electric for the aero 

derived turbine generators. GE provided the following description of their recommended 

Combined Cycle Gas Turbine unit model MS9001E (9E): 




“The MS9001E (9E) gas turbine is GE's 50 Hz workhorse. With more than 350 units, it has 

accumulated over eight million hours of utility and industrial service, many in arduous 

climates ranging from desert heat and tropical humidity to arctic cold. 

Originally introduced in 1978 at 105 MW, the 9E has incorporated numerous component 

improvements. The latest model boasts an output of 126 MW and is capable of achieving 

more than 52 percent efficiency in combined cycle. 

Whether for simple cycle or combined cycle application, base load or peaking duty, 9E 

packages are comprehensively engineered with integrated systems that include controls, 

auxiliaries, ducts and silencing. They are designed for reliable operation and minimal 

maintenance at a competitively low installed cost. Like other GE E-class technology units, 

the Dry Low NOx combustion system is available on 9E, which can achieve NOx emissions 

under 15 ppm when burning natural gas. 

With its state-of-the-art fuel handling capabilities, the 9E accommodates a wide range of 

fuels including natural gas, light and heavy distillate oil, naphtha, crude oil and residual oil. 

Designed for dual-fuel operation, it can switch from one fuel to another while running under 

load. This flexibility, along with its extensive experience and reliability record, makes the 9E 

well-suited for Integrated Gasification Combined Cycle (IGCC) projects. 

In simple cycle, the MS9001E is a reliable, low first-cost machine for peaking service, while 

its high combined cycle efficiency gives excellent fuel savings in base load operations. Its 

compact design provides flexibility in plant layout as well as the easy addition of increments 

of power when a phased capacity expansion is required.” 

A GE technical bulletin for the Combined Cycle Gas Turbine (CCGT) is shown in Appendix 

4.A. and an example layout of a turbine plant is shown in Exhibit 4.25. 


1 

2 

FOR QUALITATIVE INDICATION ONLY 



16 

Area 10 acre 

Lx 717 ft 

A Ly 622 ft 

A 

16 

1 - Gas Turbine Package 

7 

2 - Heat Recovery Steam Generator 

3 - Steam Turbine Package 

5 - Cooling Tower 

B 

2 

1 

6 - Switchyard 

7 - Administration, Shop & Warehouse 

10 - Demineralized Water Tank 

11 - Raw Water Tank 

12 - Neutralized Water Tank 

B 

2 1 

15 - Road 

16 - Parking 

2 1 

6 

Ly 

18 - Feed Pumps 

21 - Fire Protection Tank 

C C 

1 

10 

2 

12 

3 3 

D 

21 21 

D 

15 

5 

E E 

Lx 

Thermoflow, Inc. Company: GE 

User: GE Energy 

F 

D a te : 04/27/07 

Drawing No: 

F 

1 

11 

18 

2 

3 

3 

4 

4 

Exhibit 4.25 GE Combined Cycle Gas Turbine Plant Layout 

C :\Tflow16\M YFILES\English Ukraine 

PEA C E/G T PR O 16.0 


5 

5 

6 

6 

7 

SITE PLA N 

7 

8 

8

4.3.10 Ammonia Production 



CBM from the Donbass project could be used in the production of ammonia. Ammonia is 

widely used in the production of fertilizers and in the pharmaceutical industry. After 

compression and treatment, CBM can be utilized in an ammonia synthesis plant. 

Exhibit 4.26 Flow scheme for CBM to Ammonia Synthesis 

In the production plant, the methane is reacted with steam to form hydrogen. Water and 

carbon dioxide are removed from the gas stream, while nitrogen is supplied from the air. The 

nitrogen and hydrogen react in the presence of an iron catalyst, at high temperature and 

pressure to form ammonia (the Haber process). 

Kellog Brown & Root (KBR) is a major manufacturer of ammonia production plants and 

provided information about their proprietary ammonia production process. 

“KAAPplus (KBR Advanced Ammonia Process plus) is KBR's preferred offering for new 

plants. KAAPplus combines three major features of KBR's ammonia technology: KRES, 

Purifier, and KAAP. 

The KRES (KBR Reforming Exchanger System) replaces the traditional 

primary reformer with much simpler equipment. The autothermal reformer in 

the KRES system can be operated with plain air instead of oxygen, because 

the downstream Purifier requires excess nitrogen. Therefore, an air separation 

unit is not needed for the KRES system. 

The cryogenic syngas Purifier removes the excess nitrogen, all methane, and most of the 

argon from the syngas. This provides a very clean makeup gas to the synthesis loop. 

Therefore, the required synloop purge is very small, and the synloop pressure can be 




reduced. The synloop purge is recycled to the Purifier, so a separate purge gas recovery 

unit is not needed. 

KAAP synthesis catalyst uses ruthenium as the active ingredient. KAAP 

catalyst is 10-20 times more active than traditional magnetite catalyst. KAAP 

catalyst allows lower synthesis loop pressure than is practical with magnetite 

catalyst. The low synthesis pressure allows use of a single-barrel syngas 

compressor. 

The KAAPplus Ammonia Process offers lower capital costs, more 

competitive energy consumption, increased reliability, and lower maintenance 

costs. KBR has eliminated the primary reformer and simplified the synthesis 

gas compressor. These are the two pieces of equipment in an ammonia plant, 

which traditionally require the most maintenance. 

The KRES, Purifier and KAAP systems can be used in any combination, depending 

on the circumstances of a particular project.” 


4.4 CMM Surface Facilities 



CMM surface facilities are similar to CBM facilities as presented in section 4.3, Surface 

Facilities, Piping and Treating. However, in CMM operations, degasification wells can also 

be drilled from within the mine, in addition to vertical pre-mine and gob wells. The 

underground degasification boreholes are linked by a system of connected steel pipelines to 

a centralized vacuum station installed on the surface. The gas collection systems in Ukraine 

typically have numerous leakage points; at wellheads, pipe connections, and at the vacuum 

station. This results in low methane concentrations of the recovered gas, reduced vacuum 

pressures at wellheads, lower methane recovery rates, and reduced methane drainage 

efficiency. 

The ability to utilize methane produced from degasification systems has continued to grow 

due to advances in gas processing and power generation technologies. These advances 

now allow for methane in concentrations as low as 30% to 40% to be commercially utilized, 

and methods for utilizing methane in concentrations of 1% or less are currently under 

development. Once at the surface, coal mine methane can be utilized in various ways. In 

this section, methods of flaring, power generation, and cleaning-up to pipeline quality are 

discussed. 

4.4.1 Flaring 

Ideally, all CMM collected at the surface, from the mine drainage system or gob wells, would 

be utilized. In many cases though, this is not technically or economically viable and the gas 

is vented directly to the atmosphere. This constitutes a safety hazard (potential build-up of 

flammable gas), a health hazard and an environmental hazard (methane is over 20 times 

more potent than carbon dioxide as a green house gas). Flaring CMM through a controlled 

flare system with redundant safety features can significantly reduce these hazards. 1 

4.4.1.1 Benefits of flaring 

Gas flaring is a standard safety practice in many industries. For example, methane and other 

associated gases are routinely flared during processing and production of oil and gas, and 

are continuously flared from landfill collection systems. Coal mines incorporating a controlled 

flare system can minimize the potential of an unconfined deflagration occurring on surface at 

1 This section excerpted from EPA online documentation: EPA, 1999. “Conceptual design for a coal mine gob well flare”; EPA, 

2000. “Benefits of an enclosed gob well flare design for underground coal mines”. 




the gob well discharge location, brought about by natural (lightening strikes) or man-made 

sources. This would mitigate risk to the public as well as the underground mine. 

Continuous monitoring provisions, necessary with a gob well flare, can provide uninterrupted 

records of gob well performance. These can be valuable in comparing gob well production 

with underground conditions, and investigation of mine incidents such as mine fan failures, 

changes to the ventilation system, or accidents. Currently most active gob wellhead 

installations do not use continuous monitoring equipment. An installed active flare system 

can also minimize the risk of reversed flow, where intake air is supplied to the gob, which has 

occurred with some passive gob wells. 

The destruction of methane through the flaring of CMM results in a considerable 

environmental benefit, compared to venting the CMM to the atmosphere. There is also a 

potential financial benefit to coal mine and CMM operators from revenues derived from the 

sale of carbon credits generated by the methane destruction. 

4.4.1.2 Flare design 

Enclosed flare 

Open flare 

Exhibit 4.27 Enclosed and open flare designs 

Flare designs are divided between open and enclosed designs. Open flares are widely used 

at landfills, chemical plants, and refineries around the world. They have an advantage over 

enclosed flares in being simpler to design and install and requiring lower maintenance, 




therefore being lower cost. Some designs can be portable. But the visible flame associated 

with an open flare can cause local public objections, flameouts are possible in windy 

conditions and high methane destruction is not guaranteed or easily verified. 

Enclosed flares consist of a vertical, refractory lined, combustion chamber which obscures 

the flame from public view. Enclosing the flame reduces thermal radiation from the flare at 

ground level making it safe to work around. The enclosed design also reduces noise 

associated with the combustion process. Enclosed flare designs have reported methane 

destruction efficiencies of over 99% and can incorporate monitoring equipment to verify the 

destruction. To sell the generated carbon credits, a carbon credit purchaser may require this 

extra level of verification, which is much more difficult to obtain with an open flare. 

Both open and enclosed flares are designed with multiple redundant safety features. 

Protection is provided from all potential sources of ignition and from flashback or detonation 

occurring in the flare stack via an integrated passive safety system (flame arrestors, fluidic 

and liquid seals), an active positive pressure system (blower/exhauster) and a monitoring 

and control system with valve and equipment activation. 

4.4.2 Power Generation from Coal Mine Methane (CMM) 

When used for power generation, CMM is collected and transported via a pipeline gathering 

system to a gas processing plant where it is typically filtered / separated, compressed, and 

dehydrated before being fed into the engine / generator plant. As such, many of the surface 

facilities will be similar to the CBM surface facilities discussed in Section 4.3. Separation, 

compression, and dehydration are discussed in more detail in sections 4.3.4, 4.3.7, and 

4.3.8, respectively. 

As discussed in the Market Assessment section, the most likely use of CMM is power 

generation for onsite use. Generating electricity is an attractive option because most coal 

mines have significant electricity loads. Electricity is required to run nearly every piece of 

equipment including mining machines, conveyor belts, desalination plants, coal preparation 

plants, and ventilation fans. Ventilation systems in particular require large amounts of 

electricity because they run 24 hours a day, every day of the year. 

There are many technologies that can be used for stationary power generation by directly 

using pre-and post drainage gas. Based on the project parameters, it was determined that 

an engine-based system is the most attractive solution based on both capital and long-term 




operating costs. The Bazhanov Coal Mine produces 9.9 million m 3 of methane per year, and 

utilizes 5.5 million m 3 per year, leaving a net production of 4.4 million m 3 available for power 

generation. Likewise, the South Donbass No. 3 Coal Mine produces 8.8 million m 3 of 

methane per year (25 million m 3 at 35% concentration), all of which is available for power 

generation. 

The gas will be utilized in small power generators located at each mine and can be used to 

offset electric power purchases made by the mines. Together, the two mines will produce 

13.2 million m 3 per year (0.466 bcf/yr) of methane that is available for power generation. 

This is enough fuel to power a 1.7 MW facility at the Bazhanov mine and a 3.3 MW facility at 

the South Donbass No.3 mine. 

4.4.3 Surface Facilities for CMM Power Project 

Each power station consists of a gas transfer system to gather methane from gas well heads 

on the surface above underground mining operations. This system pipes gas to the suction 

pumps and gas processing plant, which are located within the power station site area. The 

gas is filtered, compressed, dehydrated, and cooled before it is fed into a manifold system 

supplying each of the gas engine units. The engine units consist of the engine, generator, 

and related equipment (e.g., circuit breaker, control system, fire fighting system, engine 

cooling heat exchangers, exhaust system, and sound attenuation baffling). 

Exhibit 4.28 illustrates a generalized setup for a CMM power project. The final, optimal 

configuration of the power station and the gas field, in terms of well locations and gas, water, 

and power reticulations will be determined in the detailed design stages of the project. 




Gas Processing Plant 

Filter / Separation 

Compression station 

Dehydration unit 

Exhaust gas 

Power Station 

Exhibit 4.28 Generalized Surface Facilities Configuration for CMM Power Project 

Heat 

consumer 

Electrical 

energy 

4.4.3.1 Gas Processing 

Filter / Separator: Gas / water separation is discussed in section 0. In addition, filters clean 

the incoming gas from minute particles of dust down to 5 microns in diameter which can 

impede the gas engine efficiency. 

Compression Station: The ambient pressure coalmine methane from the vent needs to be 

compressed for use in the gas engine. The gas compressor specified and recommended by 

Caterpillar is shown in the appendices at the end of this section. 

Dehydration Unit: Coalmine methane comes out of the ground saturated with water. 

Dehydration is discussed in detail in section 4.3.8. 

4.4.3.2 Gas Engine / Generator 

The Project will utilize the recovered methane as fuel to power Caterpillar co-generation 

units, generating 1.7 megawatts (MW) of electricity at the Bazhanov Mine and 3.3 MW at 

South Donbass No. 3. These generator sets were designed by Caterpillar for coal seam 

methane energy projects and other low-energy fuel applications. Sixty of these units have 

been successfully installed in a 120 MW coal mine methane cogeneration plant in the Shanxi 

region of China. 

The G3520 generator sets are driven by 20-cylinder, lean-burn engines operating at 1,500 

rpm and rated to produce 2,000 kW of continuous power. The engines’ lean fuel mixture is 




controlled by an electronic system designed by EDL that regulates the air/fuel ratio for 

maximum performance and minimum emissions under varying load, fuel and temperature 

conditions. 

The units are also equipped with a Caterpillar® Electronic Ignition System (EIS) that allows 

the engines to run at high load near the detonation limit. Sensors in the cylinder banks detect 

the onset of detonation and signal a microprocessor based control module that retards 

ignition timing until the detonation is corrected. If the detonation persists, the system shuts 

the engine down. The EIS also includes a built-in self-diagnostic system that can alert the 

operator to potential problems involving engine components, facilitate troubleshooting, and 

provide an engine operating record for trend analysis. 

An Electronic Control System monitors the amount of coal seam gas entering the system and 

communicates with an EDL designed Programmable Logic Controller (PLC). The PLC 

regulates the volume of coal seam and pipeline gas fueling the generator sets during peakdemand 

hours. During off-peak hours, the PLC monitors the entire system and determines 

the number of generator sets needed to use the available seam gas. Full details of the 

G3520 generator set can be found in Appendix 4.B. 

4.4.3.3 Transformer 

The electrical output of each of the units is fed to step up transformers which steps the 

generating voltage up to the higher distribution system voltage. It is then fed to a common 

high voltage busbar within the power station which connects to the local high voltage 

network. The power station and associated gas processing plant are wholly located on the 

mining lease area, occupying approximately only 20 x 50 meters. 

The electrical energy generated can be used in the coal mine to meet electricity 

requirements, while the thermal energy can be used for heating purposes on site or fed into a 

district heating system. 

4.4.4 Upgrading CMM to Pipeline Quality 

Whereas CBM is often of high enough quality to inject into transmission pipelines with 

minimal processing, CMM does not typically meet natural gas pipeline specifications 

because it contains excess contaminants in the form of nitrogen, oxygen, carbon dioxide and 




water and does not have a high enough methane content. In the U.S., pipeline quality gas 

must contain less than 0.2% oxygen, less than 3% nitrogen, less than 2% carbon dioxide and 

less than 7lbs/Mmscf of water vapor, while having a heating value of greater than 967 

Btu/scf. 2 Methane concentrations in CMM vary greatly from site to site, but typically range 

between 30-80 percent. 

Recent advances in technology have given rise to commercially available systems for 

removing the major CMM contaminants mentioned above. These systems can stand alone, 

but typically, an integrated enrichment facility is installed to remove all contaminants with a 

series of connected processes at one location. When a facility consists of components from 

more than one vendor, a single company usually takes responsibility for the design and 

performance of the entire upgrade facility. Such a “turn-key” arrangement protects the 

system owner from potential disputes over the failure of one system component. 

A good example of a CMM upgrade plant can be found at DTE Methane Resources’ Corinth 

plant in Illinois, U.S.A3 . Twenty-three (23) producing gob wells, drilled across 335 km 2 

(83,000 acres) of abandoned mine properties produce 110-170 mcmd (4-6 MMscfd) of CMM 

for processing. 

Wells are connected to individual field stations (six in total) via HDPE pipelines with the field 

stations including standard infrastructure of a suction scrubber, discharge scrubber, metering 

and a compressor driven by gas engines operating on CMM. 

2 

EPA, 2008. F.P.Carothers, H.L.Schultz. “Upgrading Coal Mine Methane to Pipeline Quality: A Report on the Commercial Status of 

System Suppliers”. 

3 

Pena, JR. DTE Energy “Coal Mine Methane Operations: DTE Methane Resources’ Corinth Plant”, U.S. Coal Mine Methane 

Conference, Sept 2007, St.Louis, Missouri, USA 




Exhibit 4.29 Field Station Separators 

Exhibit 4.30 Field Station Compressor 

The gas is transported to the central processing facility by a gathering system comprising of 

47 km (29 miles) of 20 cm (8 inch) diameter carbon steel, internally coated pipeline. The 

CMM is processed according to the block process diagram shown in Exhibit 4.31. 




Exhibit 4.31 Block Process Diagram of CMM Upgrade Facility 

The CMM at the Corinth plant contains traces of hydrogen sulfide and the sulfur is removed 

in a SulfaTreat unit to prevent corrosion of downstream equipment. The CMM is then 

compressed from pipeline to plant operating pressures using a two-stage reciprocating 

compressor. 

Exhibit 4.32 SulfaTreat Vessels 

Deoxygenation is often the first main step in the CMM upgrading process, as the CO2 

removal process is tolerant of only low levels in oxygen and too much oxygen in the nitrogen 




removal process is an explosive danger. Most gas transmission pipelines have very strict 

oxygen limits (typically less than 0.1 per cent or 1,000 parts per million). At the Corinth plant, 

the deoxygenation plant is a catalytic oxidation reactor using a platinum coated alumina. The 

reaction takes place at 340-370 degrees C (650-700 degrees F) and by-products are carbon 

dioxide and water. 

Exhibit 4.33 Deoxygenation Unit 

Several technologies are available commercially for carbon dioxide removal, including amine 

units, membrane technology and selective adsorption. The Corinth plant uses an amine unit 

which reduces the CO2 content of its CMM stream from 8% to 0.005%. 

Dehydration of CMM is the simplest part of any integrated CMM upgrading plant, but is very 

important as inadequate water removal can result in serious corrosion to delivery pipes. 

Molecular sieves (containing alumina) have a proven record and are economical to operate 

and is the technology utilized as the moisture removal unit at the Corinth plant. The unit also 

contains a layer of activated carbon to adsorb non-methane hydrocarbons. 

Nitrogen removal from the CMM is the most technically difficult process and the most 

expensive. Nitrogen rejection technologies include cryogenic technology; pressure swing 

adsorption; solvent absorption; molecular gate and membrane technologies. Cryogenic 

plants have the highest methane recovery rate (approximately 98%) of any of the 

technologies and their use has become standard practice for large-scale projects where they 

achieve economies of scale. A cryogenic nitrogen rejection unit (NRU) is used at the Corinth 




plant. (Cryogenic units tend to be less cost-effective at capacities below 140 mcmd (5 

Mmscfd) which are more typical of CMM drainage projects.) 

Exhibit 4.34 CO2 unit, Nitrogen Rejection Unit and Compressor 

The final stage in the CMM upgrade process is to compress the sales gas from the NRU. At 

the Corinth plant, this is achieved using five stages of reciprocating compressors that 

compress the gas from 4 psig to 200 psig and finally to 850 psig for injection into the sales 

gas pipeline. 

Exhibit 4.35 Sales Gas Compression Units 




4.5 U.S. Suppliers of Equipment, Technology, and Services 

4.5.1 Drilling Companies and Equipment 

Major Drilling Inc. 

Rob Newburn 

VP North American Operations 

2200 South 4000 West 

Salt Lake City, Utah 84120 

Tel: (801) 974-0645 

Fax: (801) 973-2994 

www.majordrilling.com 

REI Drilling 

Daniel Brunner 

President 

250 W Berger Lane 

Salt Lake City, Utah 84107 

Tel: 801-270-2141 

Fax: 801-281-2880 

www.reidrilling.com 

Schramm, Inc. 

Frank Gabriel 

VP / Sales 

800 E. Virginia Avenue 

West Chester, PA 19380 USA 

Tel: 610-344-3130 

Fax: 610-696-6950 

www.schramminc.com 

Union Drilling, Inc. 

Christopher Strong 

President and CEO 

4055 International Plaza 

Suite 610 

Fort Worth, Texas 76109 

Tel: 817-735-8793 

Fax: 817-546-4368 

www.uniondrilling.com 

Layne Christensen – Vibration 

Technology, Inc 

Henry Bernat, P.E. 

General Manager 

122 Dalton Street 

Shreveport, Louisiana 71106 

Tel: 318-686-0001 

Fax: 318-686-4001 

Layne Christensen - Corporate 

Headquarters 

1900 Shawnee Mission Parkway 

Mission Woods, KS 66205 

Tel: (913) 362-0510 

Fax: (913) 362-0133 

www.laynechristensen.com 

Ingersoll Rand 


IRES HOUSTON 

Shawn R. Sweet 

Regional V.P. & Branch Manager 

2210 McAllister Rd 

Houston, TX 77092 

Tel: 713-681-9221 

Parker Drilling 

Contact Sales Manager 

1401 Enclave Parkway, Suite 600 

Houston, Texas 77077 

Tel: 281-406-2000 

Fax: 281-406-2001 

www.parkerdrilling.com 

Gardner Denver, Inc. 


Pump Division Headquarters 

4747 South 83rd East Ave. 

Tulsa, OK 74145 

Tel: 918-664-1151 

www.gardnerdenver.com 



Boart Longyear - Sub-Saharan Africa 

144 Main Reef Road 

Manufacta, Roodepoort 

Gauteng, South Africa 

Tel: +27 011 761-2200 

Fax: +27 011 763-1901 

Technicoil Corporation 

John Horton 

Drilling Manager 

1510, 555 - 4th Avenue SW 

Calgary, AB T2P 3E7 

Tel: 403-509-0700 

Fax: 403-509-0701 

www.technicoilcorp.com 

Savanna Energy Services Corp. 

1800, 311 - 6th Avenue SW 

Calgary, AB T2P 3H2 

Tel: 403-503-9990 

Fax: 403-267-6749 

www.savannaenergy.com 


4.5.2 Production Equipment 

Echometer Company 

Mr. Jim McCoy 

5001 Ditto Lane, 

Wichita Falls, Texas 76302 USA 

Tel: 940 767-4334 

Fax: 940-723-7507 

www.echometer.com 

Premier Sea & Land PTE LTD (also 

echometer sales rep) 

Mr.Rob Schott. 

Manager Sales and Marketing 

1 Scotts Road # 19 –12, Shaw Centre, 

Singapore 228 208 

Tel: (65) 67347177 

www.ipsadvantage.com/int_services/pre 

mier_sea_land.htm 

Moyno (Pumping Systems) 

R&M Energy Systems 

10586 U.S. Highway 75 North 

Willis, TX 77378 

Tel: 281 765-4700 

Fax: 281 445-7491 

www.rmenergy.com 

Exterran 

US & International Operations 

11000 Corporate Centre Drive 


tel: 281-854-3000 

www.exterran.com 



Lufkin Industries, Inc. – Oilfield 

Division 

P.O. Box 849 

Lufkin, Texas 75902-0849 

Tel: 936-637-5363 

Fax: 936-633-3563 

www.lufkin.com 

Weatherford Artificial Lift Systems 

John Laine 

515 Post Oak Blvd., Suite 600 


Tel: 713-693-4112 

www.weatherford.com 

Gas Tech Engineering Corp. 

Roy Simmons 

1007 E. Admiral Blvd. 

Tulsa, Oklahoma 74120 

Tel: 918-663-8383 

Fax: 918-663-8460 

McJunkin Appalachian Oilfield Supply 

Inc. 

David Fox, III 

Executive Vice President 

P. O. Box 513, 835 Hillcrest Dr. 

Charleston, WV 25311 

Tel: 304-348-5211 

Fax: 304-348-4922 

www.mcjunkinredman.com 


EDI 

Scott Baker 

Production Manager / Sales 

100 Ayers Blvd 

Belpre, OH 45714 

Phone: (740) 401-4000 

Fax: (740) 401-4005 

www.ediplungerlift.com 

Cameron International 

Drilling & Production Systems 


4646 W Sam Houston Parkway North 

PO Box 1212 (77251-1212) 


Phone: 713-939-2211 

Fax: 713-939-2753 

www.c-a-m.com 

Harbison Fischer Mfg. Co. 


901 North Crowley Rd. 

Crowley, Texas 76036-3798 

Tel: 817-297-2211 

Fax: 817-297-4248 

www.hfpumps.com 



Ariel Corporation 


35 Blackjack Road 

Mount Vernon, OH 43050 

Tel: 740-397-0311 

Fax: 740-397-3856 

www.arielcorp.com 

National Oilwell 

Sam Pelphrey 

Rt. 321 S. Hwy 1107 

Paintsville, Kentucky 41240 

Tel: 606-789-3791 

Fax: 606-789-3128 

www.nov.com 

Dearing Compressor & Pump Co. 

3974 Simon Rd. 

P.O. Box 6044 

Youngstown, OH 44501 

Tel: 330-783-2258 

Fax: 330-783-0762 

www.dearingcomp.com 


4.5.3 Tubulars 

Aztec Tubular Products 

Rip Martin 


400 North Tarrant 

Crowley, Texas 76036 

Tel: 817-297-0110 

Fax: 817-297-1621 

www.aztectubing.com 

U.S. Steel Tubular Products, Inc. 

Steve Tate 

15660 N. Dallas Parkway 

Suite 500 

Dallas, TX 75248 

Tel: 972.386.3981 

Fax: 972.770.6444 

www.lonestarsteel.com 

Tenaris Oilfield Services 

Houston Office Sales Manager 

Gabriel Podskubka 

Tel: 713 767 4400 

Fax: 713 767 4444 

www.tenaris.com 



Kelly Pipe Co. 

Oil Country Tubular Division 

11680 Bloomfield Ave., 

P.O. Box 2827 Santa Fe Springs, CA 

90670 

Tel: 562 868-0456 

Fax: 562 863-4695 

www.kellypipe.com 

McJunkin Appalachian Oilfield Supply 

Inc. 

David Fox, III 

Executive Vice President 

P. O. Box 513, 835 Hillcrest Dr. 

Charleston, WV 25311 

Tel: 304-348-5211 

Fax: 304-348-4922 

www.mcjunkinredman.com 




4.5.4 Logging, Completion & Stimulation 

Rolligon Corporation 

Mike Dearing 

President 

6740 Hwy 30 

Anderson, Texas 77830 

Tel: 936-873-2600 

Fax: 936-873-9994 

www.rolligon.com 

Weatherford Wireline Services 


515 Post Oak Blvd., Suite 600 


Tel: 713-693-4112 

www.weatherford.com 

Schlumberger Oilfield Services 


300 Schlumberger Drive 

Sugar Land, TX 77478 

Tel: 281 285 8500 

Fax: 281 285 8548 

www.slb.com 

Haliburton Energy Services 


Halliburton Energy Services Group 

10200 Bellaire Blvd. 

Houston, TX 77072-5206 

Tel: 281-575-3000 

www.halliburton.com 

BJ Services Company 


Corporate Office 

4601 Westway Park Blvd. 


Tel: 713-462-4239 

Fax: 713-895-5420 

www.bjservices.com 

Century Geophysical Corp. 

1223 S. 71st E. Ave 

Tulsa, Oklahoma, U.S.A. 74112 

Tel: 918-838-9811 

Fax: 918-838-153 

www.century-geo.com 




Appendix 4.A GE Combined Cycle Gas Turbine Technical Bulletin 







GE Combined Cycle Gas Turbine Configuration 


GT PRO 16.0 GE Energy 

14.43 p 

59 T 

60 %RH 

3196 m 

500 ft elev. 

215 T 

13021 M 

17.62 ft^3/lb 

63719 ft^3/s 

105 T 

1876.4 M 

200 T 17.19 p 

220 T 

LTE 

17.19 p 

200 T 

1876.4 M 

1521.1 M 

38.24 M 

393.5 M 

269 

LPE 

14.29 p 

59 T 

3196 m 

IPE1 

282 T 

282 T 

305 

LPB 

55 p 

287 T 

389.7 M 

Coal Bed Gas 59.76 m 

LHV 1232742 kBTU/h 

68 T 

460 T 

414 

p[psia], T[F], M[kpph], Steam Properties: Thermoflow - STQUIK 



232 04-26-2007 14:08:46 file=C:\Tflow16\MYFILES\English Ukraine Coal Gas Bed 9E CC Plant.gtp 

IPE2 

495 

1X GE 9171E 3255 m 

4 X GT 

177.4 p 

681 T 

IPB 

568 

HPE2 

612 

170.3 p 

2067 T 

IPS1 

462.9 p 462.9 p 1928.8 p 454 p 

449 T 459 T 562 T 560 T 

1521.1 M315.7 

M 1202.3 M 315.7 M 

619 

LPS 

52.38 p 

560 T 

351.4 M 

123043 kW 

Net Power 723907 kW 

LHV Heat Rate 6812 BTU/kWh 


633 

HPE3 

IPS2 

HPB1 

GE Combined Cycle Gas Turbine Cycle Schematic 

14.95 p 

1017 T 

13021 M 

1800 p 

940 T 

1190.4 M 

HPS0 

RH1 

HPS1 

1471.1 M 400 p 940 T 

1155.4 M 462.9 p 601 T 

RH3 

74.9 %N2 

13.84 %O2 

3.173 %CO2 

7.19 %H2O 

0.9012 %Ar 

351.4 M 48.5 p 557 T 

HPS3 

0.8572 M 

1900.3 p 445.1 p 1900.3 p 1878.8 p 430.6 p 1857.4 p 416 p 1836 p 

619 T 610 T 629 T 764 T 835 T 872 T 943 T 944 T 

1202.3 M 315.7 M 1190.4 M1190.4 

M 1471.1 M1190.4 

M 1471.1 M1190.4 

M 

662 665 837 894 948 976 999 1015 

1836 p 944 T 

2 X ST = 

272069 kW 

1.116 p 

105 T 

1855.6 M 

105 T 

FW 

1015 T 

13021 M 

37.19 ft^3/lb 

134519 ft^3/s

Ambient air in 

14.43 p 

59 T 

3196 m 

60 %RH 

500 ft elev. 

4 in H2O 

14.29 p 

59 T 

3196 m 

59.4 RH 

FUEL = Coal Bed Gas 

14.7 p 

68 T 

59.76 m 

20623 LHV 

5895 kWe 

893.5 Qrej 

459.8 T 

12.41 PR 

143002 kW 

14.29 p 

59 T 

3196 m 

59.4 RH 



p[psia], T[F], M[kpph], Q[BTU/s], Steam Properties: Thermoflow - STQUIK 

GT generator power = 123043 kW 

GT Heat Rate @ gen term = 10019 BTU/kWh 

GT efficiency @ gen term = 30.72% HHV = 34.06% LHV 

GT @ 100 % rating, inferred TIT control model, CC limit 

177.4 p 

681.3 T 

2991.9 m 

GE 9171E (ID # 311) 

7.095 dp 

4 dp % 

273.3 p 

459.8 T 

59.76 m 

20856 LHV 

GT PRO 16.0 GE Energy 

232 04-26-2007 14:08:46 file=C:\Tflow16\MYFILES\English Ukraine Coal Gas Bed 9E CCPlant.gtp 

GE Combined Cycle Gas Turbine 9E GT 

170.3 p 

2066.6 T 

3052 m 

11.39 PR 

268573 kW 

203.7 m 

6.374 % airflow 

123043 kW 

10019 BTU/kWh LHV 

34.06 % LHV eff. 

100 % load 

98.6 % eff. 

14.95 p 

1017.4 T 

3255 m 

N2= 74.9 % 

O2= 13.84 % 

CO2= 3.173 % 

H2O= 7.19 % 

AR= 0.9012 % 

1653 Qrej 




Appendix 4.B Caterpillar 2500 kVA Coal Seam Power Module G3520 



































Task 5 



Preliminary Environmental Assessment 

and Socioeconomic Impacts 

Preliminary Environmental Assessment 5-i




5.1 Introduction..........................................................................................................5-1 

5.2 Regulatory Framework ........................................................................................5-2 

5.3 Potential Environmental Impacts .........................................................................5-6 

5.3.1 Construction Impacts. .............................................................................................5-6 

5.3.1.1 Aesthetics. 5-6 

5.3.1.2 Surface Disturbance. 5-7 

5.3.1.3 Water 5-8 

5.3.1.4 Noise 5-9 

5.3.1.5 Air quality. 5-9 

5.3.1.6 Disposal. 5-11 

5.3.2 Operation Impacts.................................................................................................5-11 

5.3.2.1 Production and Disposal of Water 5-11 

5.3.2.2 Additional Water Impacts 5-21 

5.3.2.3 Aesthetics 5-21 

5.3.2.4 Air quality 5-21 

5.3.2.5 Noise 5-26 

5.3.3 Closure impacts ....................................................................................................5-27 

5.4 Socioeconomic Impacts.....................................................................................5-28 

Preliminary Environmental Assessment 5-ii




Exhibit 5.1 The Environmental Impact Assessment (EIA) Process (from “Guidance on EIA 

Screening”, June 2001, European Commission) ................................................. 5-5 

Exhibit 5.2 Schematic of a Typical Well Site Layout.............................................................. 5-7 

Exhibit 5.3 EPA Nonroad Diesel Engine Emission Standards, g/kW x h (g/bhp x h)........... 5-10 

Exhibit 5.4 Maximum Allowable Discharge limits set by the World Health Organization..... 5-13 

Exhibit 5.5 WHO Specifications for Drinking Water Quality................................................. 5-14 

Exhibit 5.6 Water Disposal Costs in the Powder River Basin.............................................. 5-16 

Exhibit 5.7 DOE/Phillips Reverse Osmosis Plant for De-Ionization of Produced Water...... 5-17 

Exhibit 5.8 Well Completion Schematic of Disposal Well in the San Juan Basin ................ 5-18 

Exhibit 5.9 Well Completion Configuration for Downhole Gas/Water Separation................ 5-20 

Exhibit 5.10 EPA, E.U., and WHO Air Quality Standards and Guidelines (USEPA, 2007; EU, 

2007; WHO, 2006)............................................................................................. 5-22 

Exhibit 5.11 Estimated Uncontrolled Internal Combustion Engine Emissions associated with 

Generating Electricity from Coal Mine Methane (CMM) .................................... 5-24 

Exhibit 5.12 Tier II UK Regulations........................................................................................ 5-25 

Exhibit 5.13 Noise Levels Associated with Oil and Gas Activity (BLM, 2000) ....................... 5-26 

Exhibit 5.14 WHO Noise Level Guidelines (WHO, 1999) ...................................................... 5-27 

Preliminary Environmental Assessment 5-iii




Intensive development of coalbed methane (CBM) reservoirs in the U.S.—involving 

thousands of CBM wells—initially raised environmental concerns that threatened to seriously 

constrain operations. However, the development and application of new cost-effective 

technologies and environmentally sound planning, enabled operators to mitigate these 

concerns in most basins. Environmental conflicts—primarily the disposal of large volumes of 

produced water or the development of projects on environmentally sensitive lands—have 

occasionally slowed the pace, but not the overall extent of CBM development. 

Coalbed methane development can create a tangible environmental benefit by reducing the 

potential for global warming caused by emissions of methane from the Bazhanov and South 

Donbass #3 coal mines, while providing an additional revenue stream through carbon 

credits. Within Ukraine, the production and utilization of natural gas will have significant local 

environmental benefits. Coalbed methane (which is basically natural gas) is the cleanest 

burning and most versatile hydrocarbon energy resource available. It can be used for power 

generation, as a transportation fuel, as a chemical feedstock, or for residential heating and 

cooking. 

Potential environmental impacts for the development of CBM and coalmine methane (CMM) 

in the Donbass Basin include air and water quality impacts, as well as water quantity and 

noise issues. The Bazhanov and South Donbass #3 mines currently burn coal mine 

methane (CMM) gas streams in existing boilers. Alternative scenarios, such as the use of 

CMM to produce electricity and the pipeline injection of CBM, are evaluated. A preliminary 

environmental assessment of air, water, and noise impacts for CBM and CMM development 

is presented in this section. 

The CMM/CBM development projects will be well within compliance standards under 

applicable environmental regulations. The principal environmental issue for the proposed 

project will be the large volume of water produced by the wells, especially in their early 

stages as they are dewatering. Depending on the quality of the produced water, without 

proper control or treatment, it could impact local vegetation, soil quality, as well as the local 

population’s drinking water supply. Additional environmental concerns from CBM drilling 

include change in air quality, groundwater level, noise disturbances, and even aesthetics. 

The CMM projects are less likely to create as many environmental concerns as the CBM 

Preliminary Environmental Assessment 5-1



projects because the CMM operations to capture the gas are already in place at the two 

mines. Any additional CMM capture or end use will create a positive environmental benefit 

through the mitigation of methane emissions. 

The following section discusses the existing regulatory framework and examines the major 

environmental issues arising from CBM development. Three aspects of CBM development 

have been the particular focus of environmental conflict, in places causing either actual 

demonstrable degradation of the environment or (sometimes equally damaging) mere public 

perception of environmental harm. CBM development in sensitive regions also causes land 

use conflicts common to conventional oil and gas development. 

The primary environmental issues raised by CBM development include: 

The establishment of well sites, production facilities, and related infrastructure during 

the construction phase of CBM development project; 

Handling and treatment of drilling fluids/muds; and 

Disposal of large volumes of brackish or saline produced formation water, particularly 

during the early phases of reservoir depressurization. 

5.2 Regulatory Framework 

Since Ukraine became a sovereign state, environmental protection has been a matter of 

public policy. The Parliament, and Ministry of Environmental Protection of Ukraine, were 

established in 1991 and have been heavily involved in the creation of legislation focused on 

environmental protection. The Parliament has adopted several key environmental laws, 

including a Law on Protection of the Natural Environment (1991), a Land Code (1992), a Law 

on the Protection of Atmospheric Air (1992), a Water Code (1995), and several other 

environmental laws and regulations. The Law on Protection of the Natural Environment was 

the first and key environmental act, addressing environmental protection and rational use of 

natural resources as integral parts of the sustainable economic and social development of 

Ukraine. 

While Ukraine is not presently part of the European Union (EU), it is considered a priority 

partner county as defined in the European Neighborhood Policy (ENP). Relations between 

the EU and Ukraine are based on a Partnership and Cooperation Agreement (PCA) entered 

into by the EU and Ukraine in 1998, for a ten year period. The agreement has been 




extended to the countries that have joined the EU since 1998. Among other things, the PCA 

established a Subcommittee on Energy, Transport, Information Society, Nuclear Safety, and 

Environment with the responsibility of integrating energy markets, energy infrastructure, 

energy efficiency, energy production, transport, nuclear safety, Project Galileo, maritime 

safety, telecommunications, and the environment. 

In February 2005, a joint EU-Ukraine Neighborhood Action Plan was developed by the EU- 

Ukraine Cooperation Council. The Action Plan is based on the PCA, and calls for the 

development of a legislative framework and planning for key environmental sub-sectors; 

enhancement of administrative capabilities for permitting, enforcement, and inspections; 

implementation of the Kyoto Protocol; participation in the Joint Ukraine—EU Working Group 

on Climate Change; and active participation in trans-boundary water issues and other 

impacts, among others. 

A Memorandum of Understanding on Energy (MOU) was signed at the EU-Ukraine Summit 

in December 2005, establishing a joint strategy to integrate the Ukrainian energy market with 

the EU market. The MOU included a strategy for improving the effectiveness of safety and 

environmental standards in the coal energy sector. 

The portion of the EU-Ukraine Action Plan addressing environmental issues covers 

measures focused on preventing deterioration of the environment, as well as enhancing 

international and regional cooperation on trans-boundary environmental issues. Since then, 

Ukraine has participated in meetings addressing Danube—Black Sea water management 

issues, participated in a seminar addressing waste management issues, and resumed work 

with the Joint Ukraine—EU Working Group on Climate Change. The latter group is a global 

climate change working group, focusing on implementation of the Kyoto Protocol. Ukraine is 

progressing on preparing a national inventory of greenhouse gas emissions. 

Given the close linkage between current Ukrainian environmental policy direction and EU 

environmental directives, as addressed in the EU—Ukraine Action Plan, it appears likely that 

Ukraine will, at some point in the future, adopt EU environmental directives by policy and/or 

regulation. Therefore, EU standards have been incorporated into this review and 

assessment of potential environmental impacts. 

Analysis of World Bank and Ukrainian requirements for Environmental Assessments shows 

they are similar. As Ukraine continues to move towards a European system of 




environmental standards it is proposed that the project developers follow the EU EIA process 

if and when the proposed project moves forward. The three main stages in the EIA process 

are as follows: 

Screening – Process to determine whether or not an EIA is required. 

Scoping – Process to identify matters to be covered by the EIA, if required. 

EIS Review – Process to determine is information submitted in environmental studies is 

adequate to inform decision. 

Exhibit 5.1 illustrates the general stages of an EIA, although details and requirements for 

individual Member States (MS) may vary considerably. 




Exhibit 5.1 The Environmental Impact Assessment (EIA) Process 

(from “Guidance on EIA Screening”, June 2001, European Commission) 




5.3 Potential Environmental Impacts 

Probably the most visible aspect of oil and gas development is the drilling of the well. The 

media often associates the sight of a drilling rig with uncontrolled oil well blowouts which 

creates concern over any type of drilling activities. These fears, however, are unfounded 

with regard to CBM well drilling for several reasons. First, a “blowout” in a natural gas well 

(coalbed methane is generally 95%+ methane) does not create the surface pollution that an 

oil well would create -- the methane and associated gases simply dissipate into the 

atmosphere (or are flared) until the well is brought under control. 

Second, coalbed methane wells very rarely blowout because of the mechanism by which the 

gas is stored in the coal. In conventional gas reservoirs, free gas is held in the pore spaces 

under pressure. When a wellbore taps the reservoir, the gas flows instantaneously under its 

own pressure. In coalbed methane reservoirs, however, the gas is stored in an adsorbed 

state in the coal macerals under hydrostatic pressure. Gas production is initiated by lowering 

the hydrostatic pressure by placing the well on pump. Under these conditions, little, if any, 

gas is produced during drilling, as the wellbore is generally filled with drilling fluids and/or 

formation waters during this operation. 

In addition to the perceived impacts, other potential impacts to the environment do exist and 

can be categorized based on impacts during construction and operations. A discussion of 

the impacts during each of these phases is presented in the remainder of this section, along 

with potential mitigation actions. 

5.3.1 Construction Impacts. 

Clearly, the construction phase of the project will generate the most obvious and potentially 

the most serious impacts on the environment. This includes the engineering work that will be 

undertaken during the installation of the surface facilities and related infrastructure. This 

includes the CH4 production wells, gas gathering/processing/compression system, CH4 

pipeline, water gathering and treatment facilities, roads, powerlines, camps, and generators. 

5.3.1.1 Aesthetics. 

Each of the well sites will be approximately 1 ha (2 acres) in size and must house the drilling 

rig and associated equipment (e.g., drill pipes, casing), hydraulic fracturing equipment, and 

mud pits/settling ponds. After drilling, completing, and equipping the well, the size of the 

footprint can be reduced from 1 ha down to an area of approximately 50 m 2 . This reduced 




area would support the wellhead, pump jack, and separation/metering facilities. The 

compact and relatively unobtrusive nature of surface facilities is attested to by the fact that 

some oil and gas surface facilities are located in the center of major cities (for example, Los 

Angeles) virtually unnoticed. In the case of Los Angeles, small building facades are put 

around the facilities to disguise them. For the proposed project, the surface facilities could 

be either fenced-off or painted to help blend in with the surrounding environment. 

Exhibit 5.2 Schematic of a Typical Well Site Layout 

Construction waste (construction material, packaging, etc.) and miscellaneous waste 

(general rubbish from contractor’s camp, used oil, etc.) if not properly disposed of will create 

concerns. 

Mitigation: 

Minimize the ecological footprint of drilling rigs and associated equipment (e.g., drill 

pipes, casing, hydraulic fracturing equipment, and mud pits/settling ponds) as well as 

the wellhead, pumping equipment, and separation/metering facilities. 

All waste generated to be disposed of at designated waste disposal sites in the locality. 

5.3.1.2 Surface Disturbance. 

The establishment of the well sites, surface facilities, and related infrastructure (especially 

roads), together with the handling and treatment of drilling fluids/muds represent the main 

environmental impacts at the construction stage and are detailed below. 




The clearance of and/or disturbance to existing vegetation creates opportunities for 

increased soil erosion by winds and flash floods. 

The pipeline system used to move the methane from the field to the end-user will necessitate 

the clearance of some vegetation. The use of the existing right-of-ways (ROWs) as a route 

for the pipelines would minimize the vegetation clearance and soil erosion potential. Field 

development also entails the installation of separate pipeline systems for the low pressure 

gas gathering and water gathering. These pipelines can be buried in shallow trenches, 

keeping them out of sight. 

Mitigation: 

Pipeline route should make use of existing ROWs, to the extent possible. 

The pipeline system should be buried in shallow trenches, keeping them out of sight. 

Topsoil and vegetation should be removed carefully and restored after backfilling. 

Erosion impact due to clearing can be minimized by clearing only the areas required for 

development. 

Cleared areas should be landscaped with shortened slopes so as to guard against 

erosion. 

5.3.1.3 Water 

All engineering work (drilling, pipe laying, evaporation ponds, etc.) generates fluids that need 

to be managed properly to protect the groundwater. Such potential pollution sources may 

include oil and fuel spillages, septic tanks, solid waste disposal facilities, and storage areas 

for materials (especially any chemicals used in drilling, hydrofracturing, or gas processing). 

In the U.S., drilling fluid, mud, fraccing fluid, and cuttings are disposed of in a large plastic 

lined pit next to the well. After drilling is complete, the pit is allowed to settle, during which 

time most of the water evaporates. Any excess standing water is carefully removed by a 

water truck and added to existing water disposal and/or treatment facilities. The remaining 

mud in the pit is encapsulated with the dirt originally excavated from the pit. For the 

proposed project, a similar disposal procedure is recommended. 

Mitigation: 

Proper maintenance of the vehicles/machinery to avoid oil leaks on site. 

Particular care when working near water-courses and drainage lines. 

Minimal clearance of vegetation especially tall trees. 




Disposal of drilling fluid, mud, fraccing fluid, and cuttings in a large plastic lined pit next 

to the well. 

Avoid blocking natural waterways with construction-related debris (e.g. soil heaps, 

concrete, gravel, etc.) and so altering the natural path of overland flow. 

5.3.1.4 Noise 

The provision of surface facilities and infrastructure will require heavy machinery operating 

on the site and heavy goods vehicles moving between the site and supply centers. Noise 

impact can be reduced by restricting movements to daytime, as far as is possible, and 

ensuring that all equipment is well maintained and exhausts fitted with mufflers. Noise 

impacts are discussed further in the section on impacts in the operational phase. 

Mitigation: 

Restrict heavy machinery movements to daytime, as far as is possible. 

Ensure machinery is well maintained and all vehicles fitted with mufflers. 

5.3.1.5 Air quality. 

Dust during construction may be a potential nuisance, depending upon the wind direction. 

However, this is expected to be only a temporary nuisance, which can be managed if 

vegetation clearing is restricted to cover the area required for construction. The use of 

construction machinery may lead to some emissions from the fumes. Though the fumes 

might be minimal, to manage the situation the contractors should ensure machinery and 

vehicles used are regularly serviced and well maintained. 

Drilling operations consisting of hundreds to thousands of wells can contribute to air pollution 

if the appropriate standards are not met. In the U.S., air pollutants most regulated by 

national standards are known as the “Criteria Pollutants”, and include NOx, CO, HC 

(hydrocarbons), SOx, PM10 (particulate matter 10 microns and smaller), and PM2.5 

(particulate matter 2.5 microns and smaller). 

For the drilling rigs, regulations governing the allowable quantity of pollutants that a diesel 

engine can produce vary depending on local air emission standards as well as the size of the 

engine. Listed in Exhibit 5.3 are the EPA air emission standards for Nonroad Diesel Engines 

(EPA, 2003), broken down by engine size and pollutant. Tier 1 standards were adopted in 

1994 to be phased in from 1996 to 2000. The EPA has since adopted more stringent 




emissions standards for NOx, HC, and PM, represented by Tier 2, to be phased in from 2001 

to 2006 and Tier 3 from 2006 to 2008 (EPA, 2003). 

Mitigation: 

The impact can be minimized by restricting vegetation clearance to construction 

areas only. 

Wetting of surface roads to reduce dust. 

Maintenance and operation of heavy vehicles to be regulated. 

Engine Power Tier 

Model 

Year 

NOx HC 

NMHC + 

NOx 

CO PM 

kW < 8 Tier 1 2000 - - 10.5 (7.8) 8.0 (6.0) 1.0 (0.75) 

(hp < 11) Tier 2 2005 - - 7.5 (5.6) 8.0 (6.0) 0.80 (0.60) 

8 = kW < 19 Tier 1 2000 - - 9.5 (7.1) 6.6 (4.9) 0.80 (0.60) 

(11 = hp < 25) Tier 2 2005 - - 7.5 (5.6) 6.6 (4.9) 0.80 (0.60) 

19= kW < 37 Tier 1 1999 - - 9.5 (7.1) 5.5 (4.1) 0.80 (0.60) 

(25 = hp < 50) Tier 2 2004 - - 7.5 (5.6) 5.5 (4.1) 0.60 (0.45) 

37 = kW < 75 

(50 = hp < 100) 

Tier 1 

Tier 2 

Tier 3 

1998 

2004 

2008 

9.2 (6.9) 

- 

- 

- 

- 

- 

- 

7.5 (5.6) 

4.7 (3.5) 

- 

5.0 (3.7) 

5.0 (3.7) 

- 

0.40 (0.30) 

-* 

75 = kW < 130 

(100 = hp < 175) 

Tier 1 

Tier 2 

Tier 3 

1997 

2003 

2007 

9.2 (6.9) 

- 

- 

- 

- 

- 

- 

6.6 (4.9) 

4.0 (3.0) 

- 

5.0 (3.7) 

5.0 (3.7) 

- 

0.30 (0.22) 

-* 

130 = kW < 225 

(175 = hp < 300) 

Tier 1 

Tier 2 

Tier 3 

1996 

2003 

2006 

9.2 (6.9) 

- 

- 

1.3 (1.0) 

- 

- 

- 

6.6 (4.9) 

4.0 (3.0) 

11.4 (8.5) 

3.5 (2.6) 

3.5 (2.6) 

0.54 (0.40) 

0.20 (0.15) 

-* 

225 = kW < 450 

(300 = hp < 600) 

Tier 1 

Tier 2 

Tier 3 

1996 

2001 

2006 

9.2 (6.9) 

- 

- 

1.3 (1.0) 

- 

- 

- 

6.4 (4.8) 

4.0 (3.0) 

11.4 (8.5) 

3.5 (2.6) 

3.5 (2.6) 

0.54 (0.40) 

0.20 (0.15) 

-* 

450 = kW < 560 

(600 = hp < 750) 

Tier 1 

Tier 2 

Tier 3 

1996 

2002 

2006 

9.2 (6.9) 

- 

- 

1.3 (1.0) 

- 

- 

- 

6.4 (4.8) 

4.0 (3.0) 

11.4 (8.5) 

3.5 (2.6) 

3.5 (2.6) 

0.54 (0.40) 

0.20 (0.15) 

-* 

kW = 560 Tier 1 2000 9.2 (6.9) 1.3 (1.0) - 11.4 (8.5) 0.54 (0.40) 

(hp = 750) Tier 2 2006 - - 6.4 (4.8) 3.5 (2.6) 0.20 (0.15) 

* - Tier 3 PM standard to be proposed and adopted in the 2001 review 

Exhibit 5.3 EPA Nonroad Diesel Engine Emission Standards, g/kW x h (g/bhp x h) 




5.3.1.6 Disposal. 

Construction waste must be dealt with quickly and responsibly in order to minimize the 

ecological footprint of the project. The burying of biodegradable and burning of packaging 

(boxes and paper) is permitted, while everything else must be removed to a recognized 

waste disposal facility at an urban center. Batteries, waste oil and diesel, and any other 

waste fluids or lubricants have the potential to contaminate both surface and ground water 

supplies and should not be dumped on site. 

Mitigation: 

All waste generated, apart from biodegradable material, to be disposed of at 

designated waste disposal sites in the locality. 

All heavy plant machinery and project related equipment to be stored at designated 

sites. 

5.3.2 Operation Impacts. 

During the operational phase of the project potential environmental impacts resulting from 

the operation of generators, internal combustion engines, and compressors are of concern. 

However, the main environmental concerns relate to potential impacts to the quantity and 

quality of shallow groundwater resources in the region, and impacts from the management 

and disposal of the relatively large quantities of potentially poor quality production water. 

These impacts are potentially the most significant and are dealt with independently as they 

bisect a wide spectrum of impacts and present a number of disposal options. 

5.3.2.1 Production and Disposal of Water 

Quantity and Quality. Coalbed methane production relies on the concurrent production of 

large volumes of coal seam formation water to reduce initial reservoir pressure and initiate 

the desorption of gas from the coal reservoir. The rate of water production from a CBM well 

varies widely, depending primarily on reservoir thickness, porosity, permeability, well 

spacing, pump rates, and proximity to aquiferous sandstones or intrusions and meteoric 

recharge. CBM wells in U.S. CBM Basins can produce from 1 to 60 m 3 /day of formation 

water during the first 6 months or so, depending on permeability, pump rates, and well 

spacing. 

The water production rate for a single well in the project area, based on the simulation study, 

is estimated to average 1-2 m 3 /day/well (6-10 bbl/day/well) for the first two years of 




production. Total production from a typical CBM project involving hundreds of wells can be 

considerable and must be carefully managed to meet local environmental requirements. 

Coal seam formation water varies widely in composition. Produced water from permeable, 

shallow coal reservoirs close to meteoric recharge is often quite fresh, such as in the Powder 

River Basin or in the northernmost San Juan Basin. More commonly, however, coal seam 

formation water contains significant levels of total dissolved solids (TDS), typically 5,000 to 

20,000 ppm (or more), and requires special treatment and/or disposal under most 

environmental regulatory regimes. Based on the experience of Ecometan’s CBM drilling 

efforts, as well as data gathered from the mines, the formation water in the study area is 

highly saline, in excess of 40,000 mg/L. The TDS of the water is dependent upon the: 

depth of the coal beds, 

composition of the rocks surrounding the coal beds, 

amount of time the rock and water react, and 

origin of the water entering the coal beds. 

Trace-element concentrations in CBM water are commonly low (



The TDS of CBM water ranges from fresh (200 mg/L or ppm) to saline (170,000 mg/L) and 

varies among and within basins. It should be noted that the TDS of potable water is 500 

mg/L, stock ponds for irrigation have a TDS limit of 1,000–2,000 mg/L, and that of the 

average seawater is 35,000 mg/L. 

Water Standards. The quality of the produced water dictates how it is handled. High quality 

water can be used for beneficial purposes such as irrigation, industrial use, or drinking water. 

Poor quality water must be disposed of or treated before an applicable use is found. The 

following tables show World Health Organization (WHO) discharge standards (Exhibit 5.4) 

and WHO drinking water specifications (Exhibit 5.5). 

Property 

Maximum allowable 

Discharge 

(ppm or as specified) 

Property 

Maximum allowable 

Discharge 

(ppm or as specified) 

Temperature (oC) - Cyanide 0.1 

pH 6.5-8.5 Chromium 0.05 

Dissolved Oxygen - Cadmium 0.005 

Biological Oxygen 

Demand 

Chlorine Oxygen 

Demand 

Free & Saline Ammonia 

(as N) 

- Mercury 0.001 

- Selenium 0.01 

- Iron 0.3 

Nitrate (as N) 10 Manganese 0.1 

Total Phosphorus (as P) - Nickel - 

Color (TCU) 15 Sodium 200 

Total Coliform (n/100ml) 10 Sulfate 400 

Fecal Coliform 

(n/100ml) 

0 Chloride 600 

Arsenic 0.05 Fluoride 1.5 

Boron - 

Total Dissolved 

Solids 

Zinc 5 Oil & scum - 

Copper 1 1 

Preliminary Environmental Assessment 5-13 

1000 

Phenols 0.001 0.001 

Lead 0.05 0.05 

Exhibit 5.4 Maximum Allowable Discharge limits set by the World Health Organization

Variables 



Guideline Values 

(in mg/L where applicable) 

Variables 

Physical Requirements Toxic Substances 

Guideline Values 

(in mg/L where applicable) 

Turbidity, NTU 5 Nitrate, NO3 45 

Color, TCU 15 Fluoride, F 0.7 – 1.5 

Taste & Odor Unobjectionable Lead, Pb 0.05 

Chemical Requirements Cadmium, Cd 0.05 

Chlorine Residual, CL2 0.6 Cyanide, CN 0.01 

pH value 6.0 - 9.0 Microbiological Variables 

Total Dissolved Solids, 

TDS 

Total Hardness, as 

CaCO3 

500 

20 – 200 

Fecal Coliforms / 100 ml 

Total Coliforms / 100 ml 

Sulfate, SO4 250 Organic Constituents 

Calcium, Ca 75 Phenols 0.01 

Nitrite, NO2 

3 

Total Organic Carbon, 

TOC 

Phosphorous, PO4 0.3 Trihalomethanes, THM 100 

Chloride, CL 250 Total Pesticides 0.0005 

Sodium, Na 

200 

Poly Aromatic 

Hydrocarbons 

Preliminary Environmental Assessment 5-14 

0 

0 

8 

0.001 

Magnesium, Mg 100 Disinfection by-products 0.6 – 1 

Iron, Fe 0.3 Toluene 0.02 – 0.2 

Manganese, Mn 0.1 Chlorophyll A 0 – 5 

Ammonium, NH4 1.5 

Aluminum, Al 0.2 

Copper, Cu 1 

Zinc, Zn 5 

Exhibit 5.5 WHO Specifications for Drinking Water Quality



Water Disposal Options. Formation water TDS generally increases with longer residence 

time within the coal reservoir; low permeability and or location far from meteoric discharge 

increase residence time, thereby increasing the dissolution of even relatively insoluble solids. 

For example, coal seams far from recharge in the Central Appalachian Basin of the U.S. are 

highly saline, typically containing over 50,000 ppm of dissolved NaCl, yet water production 

rates are very low at several m 3 /day/well or less. 

In contrast, produced water in the western Raton basin, close to recharge along the outcrop 

of Vermejo from coal seams in the Sangre de Cristo Mountains, has a very low level of TDS, 

typically under 1,000 ppm, but production averages 180 m 3 /d per well with no apparent 

decline. Because of the interrelationship between coal seam hydrology, permeability, and 

water chemistry, TDS commonly is inversely related to water production rate. 

There is no established technology for reducing water production without adversely affecting 

gas production rates. Consequently, mitigation technologies have focused either on 

disposing produced water using underground injection or surface evaporation, or by surface 

treatment of produced water for disposal or utilization. 

In the U.S., produced water from CBM operations is disposed of using several different 

approaches. The most appropriate method depends on many variables, including water 

volume, TDS levels and composition, as well as on non-reservoir factors such as local 

climate, surface drainage, and environmental regulations. Water disposal technology is 

highly site specific and must be determined for each individual application. In the Powder 

River Basin of Montana and Wyoming, the most commonly used disposal options for water 

produced during CBM production include: 

Surface Discharge 

Infiltration Impoundment (or evaporation pits) 

Shallow Re-Injection 

Active Treatment Using Reverse Osmosis (RO) 




Exhibit 5.6 shows a cost analysis for each of the water disposal options in the Powder River 

Basin. Operating costs are assumed on a per barrel basis for a “typical” CBM well producing 

38 m 3 /day (average) during the first two years. Capital costs are based on an average single 

seam producing well in the Powder River. 

Water Disposal 

Water Disposal Costs 

Capital Costs/Well O&M Costs/Bbl. 

A. Surface Discharge (16 well unit) $1,400 $0.02 

B. Infiltration Impoundment (16 well unit) $10,300 $0.06 

C. Shallow Re-Injection (96 well unit) $8,100 $0.06 

D. Active Treatment w/ Disposal of 

Residual Concentrate (96 well unit) 

-Trucking $19,600 $0.24 

-Deep Re-Injection $35,200 $0.14 

Exhibit 5.6 Water Disposal Costs in the Powder River Basin 

For comparison, the simulation study performed for the Project Area estimates an average of 

1-4 m 3 /well (6-25 bbl/day) for the first two years; however, this average will decline for 

subsequent wells as the fixed water volume in the Project Area continually drops. The 

highest water production will be in the first two years, therefore water treatment costs will be 

reduced over time, as water production rates decline. 

Reverse Osmosis. Water produced from the CBM and CMM projects will likely require 

treatment before it could be discharged into the local watershed. Treatment costs using 

reverse osmosis vary in the Powder River Basin, depending on the type of residual 

concentrate removal, whether by truck or deep re-injection. In addition to capital and 

operational costs for surface discharge, the Project Area would also incur active treatment 

costs for reverse osmosis similar to those listed above for the Powder River Basin. 

Reverse osmosis (RO) of brackish produced water involves the use of a permeable 

membrane to separate fresh product water and waste brine streams (Exhibit 5.7). Each pass 

through the membrane can half the TDS of the product water, thus the performance of an 

RO system depends on the requirements for product water chemistry. A typical CBM RO 

system in the San Juan Basin involves processing 7,000 ppm TDS sodium bicarbonate water 




to generate 400 ppm TDS product water, which could then be used for agriculture, and a 

small waste stream consisting of 100,000 ppm TDS water that would be injected in a 

conventional underground disposal well. RO systems are typically constructed from 

commercial 300m 3 /day units and are skid-mounted for portability. The principal capital costs 

for RO include the RO unit and control system and pre-treatment systems to reduce fouling 

of the membranes, which is a common operating problem. Operating costs include electricity 

to pump the water stream at high pressure across the membrane, and membrane 

maintenance to remove scale and other fouling problems. 

Exhibit 5.7 DOE/Phillips Reverse Osmosis Plant for De-Ionization of Produced Water 

Putting the water to beneficial use through reverse osmosis represents a good option. The 

cost of reverse osmosis treatment in the Project Area is estimated to be $0.82/CMw 

($0.16/Bbl). 

Underground Re-Injection. Re-injection capital costs in the Powder River Basin are 

estimated at approximately $8,100/well, based on single seam producing wells in a 96 well 

unit, with an injection rate of 238 m 3 /d, requiring 15 shallow wells. CBM produced water in 

the Powder River is fairly fresh, so shallow re-injection wells are typically only 90-300 meters 

in depth. The EPA requires that water must be re-injected to a depth at which the re-injected 

water’s salinity matches that of the aquifer into which it will be pumped. Exhibit 5.8 shows a 

typical disposal well in the San Juan Basin. ARI believes that the treatment of the produced 




water using reverse osmosis and re-injection of the high TDS stream represents a good 

water disposal option for Ukrainian CBM development projects, provided a good reservoir is 

available to insert into. Absent a good disposal zone, the water could be treated at a 

municipal waste facility. 

Exhibit 5.8 Well Completion Schematic of Disposal Well in the San Juan Basin 




Infiltration Impoundment. Water disposal by infiltration impoundment in the Powder River 

Basin has capital costs of $10,300/well. Surface evaporation, different than infiltration 

impoundments, is used in ponds to dispose a small fraction of CBM produced water in the 

San Juan and Uinta basins. Disposal of produced water in evaporation ponds is a simple 

process, involving constructing and maintaining a shallow closed pond with a large surface 

area, introducing produced water into the pond, and allowing the water to evaporate (Zimpfer 

et al., 1988). For infiltration impoundments, water is collected from production wells via lowcost 

PVC pipelines. The pond must be constructed using impermeable soils or lined with 

clay or an impermeable liner to preclude percolation, and sufficiently large to handle 

produced water during cold seasons when evaporation rates are low. Produced water must 

be free of oil, which can significantly reduce evaporation rates by forming a coating on the 

surface of the brine. Depending on brine concentration and evaporation rates, the 

accumulated salt deposits within the pond must be removed. In the San Juan Basin, this 

accumulation amounts to approximately 5 cm per 20 years of continuous operation. 

Evaporation rates can be significantly enhanced in active evaporation ponds through the use 

of a pump-and-spray system, reducing the required surface area to dispose a given volume 

of water, although at higher operating cost. 

Operating costs for both shallow re-injection and infiltration impoundment in the Powder 

River are $0.06/bbl. The costs listed above are estimations, used here only as a general 

comparison between water disposal options for the proposed project. One disadvantage of 

evaporation ponds is that they are highly visible and require large land areas, usually several 

acres in extent, which frequently generates local public concern. Environmental agencies in 

the San Juan basin and many other areas in the U.S. have effectively banned construction of 

additional evaporation facilities. Given the temperate climate of the Donetsk region, surface 

impoundment is not a viable option for Ukrain. 

Downhole Gas/Water Separation. Another water disposal option is downhole gas/water 

separation. Although it is a relatively new method of water disposal, downhole water 

separation may be economically viable under certain conditions, actually increasing gas flow 

rates and almost completely eliminating water transportation costs. Downhole gas/water 

separation would require well boreholes to be drilled deeper than originally designed in order 

to inject water into a permeable horizon below the coal seams. A pump below the coal 

seams draws water down, while allowing gas to flow to the surface; shown in Exhibit 5.9. 




Exhibit 5.9 Well Completion Configuration for Downhole Gas/Water Separation 

Downhole gas/water separation works using a “bypass tool” with a conventional insert pump 

and a gas-powered beam pumping unit that allows liquid to be lifted up the tubing, where 

small drain holes let the liquid pass down past the pump to a point below the pump intake. 

When the liquid is high enough, it will flow into the disposal zone. Costs are relatively low, as 

downhole gas/water separation uses mostly conventional equipment. This technique, 

however, requires an adequately permeable zone located below the coal that can take 

substantial volumes of fluid. At the present time, it is unknown whether such a zone exists in 

the Project Area. This aspect should be explored thoroughly during the pilot project as the 

ability to inject water directly downhole will represent a considerable capital cost savings for 

the surface facilities. 

Surface Discharge. Surface discharge is the least expensive of the water disposal options. . 

Uses for surface discharged water may include crop irrigation or animal watering, depending 




on water quality. However, these options will most likely be secondary to any beneficial use 

at the mine or in other industrial applications where potable water is not required. These 

applications include ore washing, power plant cooling, drilling/fracturing fluid, and dust 

suppression. Depending on the end-use, some degree of clean-up of the water may be 

required. 

5.3.2.2 Additional Water Impacts 

Cooling water is typically used to reduce the heat from IC engines and increase operating 

efficiency. These cooling water systems are typically closed loop systems and generate 

water only during change out. Cooling water blowdown would contain some particulate 

contamination; however, particulate contamination will be minimized if the best management 

practices cited in EU guidance are followed. 

This cooling water blowdown stream should be handled to minimize the discharge of 

suspended and dissolved solids to local receiving waters, by settling the solids and disposing 

of the settled solids separately by landfilling. No water discharges are anticipated from the 

gas turbines. 

5.3.2.3 Aesthetics 

During the pilot project and non-routine operations (i.e. start-up and shut-down) the methane 

will be flared off. This will generate heat and, at night, a clearly visible flare, which may attract 

people from the surrounding area. 

Mitigation: 

Securely fence off the area that houses the gas flare. 

Post warning signs around the gas flare site and also information about the project 

itself. 

5.3.2.4 Air quality 

Surface facilities, namely generators and engines, can affect ambient air quality in the project 

area. Since the generators in the field will be natural gas fired, they will burn much cleaner 

than a conventional diesel engine. In addition, the compressors used to compress the 

methane at the project site will also affect air quality. U.S. EPA and E.U. standards, and 

WHO air quality guidelines, as shown in Exhibit 5.10, will be used as references in this 

report. 




Emission USEPA E.U. WHO 

Nitrogen 

Dioxide 

Particles 

as PM10 

Particles 

as PM2.5 

Averaging 

Period 

Annual 

(Arithmetic 

mean) 

Annual 

(Arithmetic 

mean) 

24-hour 

Annual 

(Arithmetic 

mean) 

24-hour 

Ozone 8-hour 

Sulfur 

Oxides 

Carbon 

Monoxide 

1-hour 

Annual 

(Arithmetic 

mean) 

24-hour 

8-hour 

1-hour 

Lead Quarterly 

Average 

Standards Averaging 

Period 

0.053 ppm 

(100 

µg/m 3 ) 

Revoked 

150 µg/m 3 

15.0 µg/m 3 

35 µg/m 3 

0.08 ppm 

0.12 ppm 

0.03 ppm 

0.14 ppm 

9 ppm 

(10 

mg/m 3 ) 

35 ppm 

(40 

mg/m 3 ) 

1-hour 

24-hour 

24-hour 

1-year 

Standards Averaging 

Period 

200 µg/m 3 

40 µg/m 3 

50 µg/m 3 

40 µg/m 3 

- - 

Maximum 

daily 8hour 

mean 

1-hour 

24-hour 

Maximum 

daily 8hour 

mean 

Annual 

mean 

1-hour 

mean 

Annual 

mean 

24-hour 

mean 

Annual 

mean 

24-hour 

mean 

120 µg/m 3 8-hour 

mean 

350 µg/m 3 

125 µg/m 3 

10 mg/m 3 

1.5 µg/m 3 1-year 0.5 µg/m 3 

24-hour 

mean 

10-minute 

mean 

Guidelines 

40 µg/m 3 

200 µg/m 3 

20 µg/m 3 

50 µg/m 3 

10 µg/m 3 

25 µg/m 3 

100 µg/m 3 

20 µg/m 3 

500 µg/m 3 

- - 

- - 

Exhibit 5.10 EPA, E.U., and WHO Air Quality Standards and Guidelines 

(USEPA, 2007; EU, 2007; WHO, 2006) 

Both the use of Coal Mine Methane (CMM) for a natural gas stream, and the use of Coal Bed 

Methane (CBM) to produce electricity, will create air emissions. Air emissions have been 

evaluated for both alternative scenarios at each mine. As part of the analysis, it has been 

assumed that the methane available is the total gas produced less that used for the boiler. 

Only emissions from the new sources have been quantified, and emissions from the existing 

boilers have not been addressed. 




Emissions Associated with the Use of Coalbed Methane (CBM) for a Natural Gas Stream. 

For the production of natural gas for pipeline delivery, industrial turbine engines will be used 

to compress natural gas from the CBM production, after first dehydrating the methane gas 

mixture using Triethylene Glycol (TEG). The gas turbine drives a rotating compressor which 

pressurizes the air and mixes with the gas from the TEG unit in a compression chamber. 

The three General Electric Compression Gas Turbines proposed for this scenario are 

designed to maximize the efficiency of the turbines while reducing emissions. 

Emissions from the gas turbine units can be calculated using published emission factors and 

assuming the following: 

Only gas turbine emissions are significant and there is no leakage along the pipes, 

valves, or flanges; 

Emissions from the dehydration process via the Triethylene Glycol Unit (TEG) are 

negligible; 

There are no additional control devices associated with the gas turbines; 

The methane-air stream does not contain appreciable sulfur 

The most significant pollutants generated by the gas turbines are thermal nitrogen oxides 

(NOx) and carbon (TOC). Lesser amounts or carbon monoxide (CO) and volatile organic 

compounds (VOC) are generated along with small quantities of particulates (PM10) and 

methane. Insignificant air emissions are also anticipated from the TEG dehydration process. 

Emissions Associated with the Use of Coal Mine Methane (CMM) to Generate Electricity. To 

generate electricity, it is assumed that an internal combustion (IC) engine will be used to 

drive a generator. Emissions are based on the design specifications for a Caterpillar 

G3520C low energy, 4-stroke internal combustion gas engine. Fluctuation in pressure and 

temperature during operation affect the engine efficiency. Emissions estimates for this 

engine are based on similar sources and published emission factors reported in US EPA AP- 

42, Section 3.2, Natural Gas-fired Reciprocating Engines 1 and United Kingdom (UK) National 

Emissions Inventory Factors (NAEI) for Natural Gas Processing 2 . 

1 AP-42 Emissions Factors, Volume 1, Fifth edition, 1/96 

2 http://www.naei.org.uk/emissions/selection.php, Oct 1, 2007 


As part of the analysis, it was assumed that: 



Only the Caterpillar G3520C gas engine emissions are significant and there are no 

leaks along the pipes, valves, or flanges; 

The Caterpillar G3520C gas engine will run 8,400 hours/yr; 

There are no additional control devices associated with the Caterpillar G3520C gas 

engine; and 

The methane-air stream does not contain appreciable sulfur. 

Total uncontrolled air emissions from electricity production from CMM from the two mines are 

listed below: 

South Donbass 

#3 and Bazhanov 

Mines 

CO NOx PM10 SO24 VOC TOC Methane 

(ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) 

23.41 91.36 0.19 NA 0.60 3.14 2.46 

Exhibit 5.11 Estimated Uncontrolled Internal Combustion Engine Emissions 

associated with Generating Electricity from Coal Mine Methane (CMM) 

As shown in the table, the most significant emissions are for thermal NOx, which is produced 

as the combustion engine combusts fuel in the engine cylinders during the conversion of 

chemical to mechanical energy. Carbon monoxide is emitted at less than one-third the rate 

of NOx. VOCs, TOC, methane, and particulate matter are emitted in significantly less 

quantities. 

Emission Standards. EU emissions standards for large turbines and IC engines with net 

rated thermal inputs of 50 MW or higher are set by the EU Large Combustion Plant Directive 

(LCPD). The LCPD is implemented in member states under the Pollution Prevention and 

Control (PPC) Regulations with operators required to apply Best Available Techniques (BAT) 

to all aspects of the operation of the process. In addition, operators are required to establish 

an Environmental Management System (EMS) based on ISO14001 standards for 

compliance and annual source testing, compliance monitoring and recordkeeping to meet the 

BAT. 

For smaller combustion processes with less than 50MW thermal input, EU member states 

may establish a second tier of regulations that are subject to control under the EU PPC 

Regulations. Based on the vendor specifications of the equipment to be used for both CMM 




and CBM, each of the 12 IC engines are rated at 10 MW thermal input and each of the 3 

turbines are rated at 32 MW thermal inputs. Accordingly, these pieces of equipment at both 

mines and under both operating scenarios are considered smaller combustion sources. 

There are currently no requirement for certification or accreditation with these member state 

second tier standards by the EU. However, it is up to each member state to set the standard 

for its own country, with the Directive Limits being the minimum standard that has to be met. 

If a member state chooses to set a more stringent set of standards then it is at will to do so. 

It is likely that at some time in the future Ukraine will need to develop EU Tier II regulations 

(Exhibit 5.12) to address emissions from smaller combustion sources. While it is unknown 

how these future regulations will look, they may be similar to other similar regulations from 

current member states. As a comparison, small combustion source regulations from the UK 

Department of Environment’s Guidance Document for Gas turbines (PG-04) and IC Engines 

(PG-05) rated between 20 and 50 MW establishes the limits presented in the following table. 

Note that these regulations apply to individual pieces of equipment, whereas the emission 

calculations presented previously were aggregate emissions for multiple turbines and gas 

engines. 

CO NOx PM10 SO2 VOC 

Source (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) 

New Natural Gas Turbines run > 

100 hrs/yr 

NA 20-50 NA NA NA 

New Natural SI Lean Burn 450.00 500.00 50.00 NA 200.00 

Exhibit 5.12 Tier II UK Regulations 

Similar to the requirements for larger combustion sources, the Tier II standards establish 

Environmental Management System (EMS) standards for compliance and annual source 

testing, compliance monitoring and recordkeeping have been established in the to meet the 

BAT. 

When these regulations are compared to the individual equipment emissions, the only 

emission standard that may be exceeded would be the NOx emissions from the gas turbines. 

All other projected emissions are below the comparative regulations and are therefore 

presumed to present insignificant environmental impacts. 




Emission Control Requirements. To minimize NOx emissions from internal combustion 

engines and gas turbines, there are a variety of control techniques such as the use of dry 

NOx premix burners (DNL) and Selected Catalytic Reduction (SCR). Both the internal 

combustion and gas turbine equipment vendors have indicated that the use of the former, 

DNL, will satisfy the concentration limits directed by LCPD. 

In the DNL method, the air-fuel mixture is mixed before combustion occurs creating a 

homogenous temperature and a low burner flame which results in reduced NOx. Typically, 

as NOx is reduced, CO and VOC emissions become elevated. Operators can mitigate these 

effects effect through the use of good operational practices of the fuel and air combustion 

system. Additional technology, such as a catalytic converter, can be installed if further 

reductions are required to meet the emission limits. 

The use of NOx control technology for the internal combustion engines and gas turbines will 

bring emissions within assumed limits, based on the Tier II limits of a current EU member 

state (the UK). Therefore neither the use of CMM to generate a natural gas stream or CBM 

to generate electricity should present significant adverse environmental impacts due to the 

resulting air emissions. 

5.3.2.5 Noise 

When surface facilities are operational it is likely that noise from operations will exceed the 

public protection level of 55 decibel (dB). The compressor station operations will be the 

noise source of greatest concern. A summary of measured sound levels at oil and gas 

facilities is presented in Exhibit 5.13. 

Noise Source 

Sound Level at 50 feet 

(15 meters) 

Well Drilling 83 dBA 

Pump Jack Operation 82 dBA 

Produced Water Injection 

Facilities 

71 dBA 

Gas Compression Facilities 89 dBA 

Exhibit 5.13 Noise Levels Associated with Oil and Gas Activity (BLM, 2000) 

Exhibit 5.14 presents noise level guidelines from the World Health Organization (WHO). 

Noise impact can be reduced by using building insulation, installing inlet and exhaust 




silencers, or using special oil coolers. The amount of silencing required would depend on the 

size of the equipment and proximity to noise sensitive areas. 

Receptor 

Residential; institutional; 

educational 

One Hour LAeq (dBA) 

Daytime 

07:00-22:00 

Nighttime 

22:00-07:00 

55 45 

Industrial; commercial 70 70 

Exhibit 5.14 WHO Noise Level Guidelines (WHO, 1999) 

In addition, both the gas turbines used to generate a natural gas stream and the IC engines 

used to generate electricity will create noise as a normal part of operations. However, the 

gas turbines and IC engines are both designed with control features to attenuate noise 

levels, and should not create noise levels of significance. 

Mitigation: 

Insulate the generator(s) and fence them off from the outside. 

Provide hazard and information signs on the fence. 

5.3.3 Closure impacts 

The ideal objective for the closure of any natural resource utilization project should be the 

return of land to its pre-project state. This is not always practical since the costs involved 

could render the entire project unfeasible. It is also possible that the development could have 

some post project value. 

It is recommended that the closure plan include the removal of all infrastructure and the 

capping of all boreholes. Infrastructure includes, pipelines, gathering/distribution lines, 

powerlines, fences and all related equipment, including any obsolete or broken down 

machinery. Boreholes, in particular should be capped using proven abandonment 

procedures. If alternate uses are ever identified for some of the infrastructure then the 

closure objectives could be modified at a later stage. The formulation of the closure plan 

should be integrated into the project design process. In this respect, the final closure plan 

should be re-visited five years prior to project end. 


5.4 Socioeconomic Impacts 



The Donbass Consortium’s Mine Degasification and Utilization Project will have a positive 

impact on many aspects of the Ukrainian economy – from stimulating economic activity both 

locally and regionally, to increasing governmental tax revenues; from yielding improvements 

in the condition of the local infrastructure by improving highway, street and railway 

conditions, to making available an environmentally sound, strategic fuel product. 

Increased employment and employment stability. Many of the coal mines in the 

Donets’k region are at or near the end of their economic life. The immediate closure 

of under-performing mines without the creation of new jobs would cause serious 

economic hardships and political turmoil in the region. A large-scale mine 

degasification and methane utilization project as planned by the Donbass 

Consortium would help foster the development of new, gas-based industries. 

Improved mine economics. According to a study by the U.S. EPA (White Paper; 

Guidebook on Coalbed Methane Drainage for Underground Coal Mines, April 1999) 

the installation of methane degasification systems at gassy coalmines can improve 

overall mine economics through the following: 

Enhance coal productivity because of less frequent downtime or production 

slowdowns caused by gas at the face; 

Decrease fan operating costs because of reduced air requirements for 

methane dilution; 

Reduction of shaft size and the number of entries required in the mines; 

Increase tonnage extracted from a fixed-size reserve as a result of shifts of 

tonnage from development sections to production sections; 

Reduce water problems. 

Increased tax revenues to local and national government. The commercial 

utilization of methane creates increased tax revenues in the areas of Property Tax to 

Employment Taxes for Social Benefits, and from enhanced Profit Taxes to Retail 

Sales Tax. Many local and national government programs will be direct and indirect 

beneficiaries of the fully operational Project, receiving significant tax revenues that 

are created up- and down-stream from this Project. 

Improvements to roadways and utilities infrastructure. The Donbass Project has 

already had a positive impact on the local infrastructure, as access roads and 




utilities, particularly the electric power transmission lines, have been upgraded by the 

mines as needed for the installation and operation of the test wells. Continued direct 

investment by the Consortium in the local infrastructure as required by the Project, 

will provide similar improvements, especially to roadways. In addition, the Project 

creates indirect benefits derived from increased tax revenues, which enhance 

government budgets, and, thus, the means to improve the conditions of 

transportation systems and other municipal infrastructure. 

Improved supply of quality-controlled fuel products. The Project anticipates 

some utilization of methane gas for processing into CNG and similar products for use 

in existing systems, including motor freight transport and public buses. These 

current vehicular uses could be expanded within the local communities into other 

uses for such products, including heating systems for greenhouse agriculture, as a 

fuel for ovens at modern commercial bakeries, and many other local, small and 

medium enterprise development. 


Task 6 



Final Cost Estimates and Economic 

Assessments 

Project Cost Estimates and Economic Assessments 6-i




6.1 CBM Capital and Operating Cost Estimates ................................................................6-1 

6.1.1 Drilling, Completion and Stimulation .......................................................................6-2 

6.1.1.1 Drilling and Completion...............................................................................................6-2 

6.1.1.2 Well Stimulation ..........................................................................................................6-2 

6.1.1.3 Artificial Lift Equipment and Well Site Equipment.......................................................6-2 

6.1.1.4 Shipping of Materials, Supplies, and Equipment........................................................6-4 

6.1.1.5 Geological, Geophysical and Location Costs .............................................................6-4 

6.1.2 Surface Facilities.....................................................................................................6-4 

6.1.2.1 Gas Gathering System ...............................................................................................6-4 

6.1.2.2 Compression...............................................................................................................6-5 

6.1.2.3 Site Power Generation and Distribution .....................................................................6-5 

6.1.2.4 Water Gathering and Disposal....................................................................................6-5 

6.1.2.5 Infrastructure...............................................................................................................6-5 

6.1.3 Operating Cost Estimates .......................................................................................6-6 

6.1.3.1 Well Tending...............................................................................................................6-6 

6.1.3.2 Gas Compression and Gathering ...............................................................................6-6 

6.1.3.3 Power Generation.......................................................................................................6-7 

6.1.3.4 Water Treatment and Disposal...................................................................................6-7 

6.2 Benchmarking Analysis of Ukraine CBM Costs versus Major U.S. CBM Projects...6-8 

6.3 CBM Project Economics ..............................................................................................6-10 

6.3.1 CBM Production Analysis......................................................................................6-10 

6.3.2 CBM Financial Assumptions .................................................................................6-12 

6.3.3 CBM Economic Results ........................................................................................6-12 

6.3.4 CBM Sensitivity Analyses .....................................................................................6-14 

6.4 CMM Power Project Economics..................................................................................6-16 

6.4.1 CMM Production Analysis .....................................................................................6-16 

6.4.2 CMM Economic Assumptions ...............................................................................6-16 

6.4.3 CMM Economic Results........................................................................................6-18 

6.4.4 CMM Sensitivity Analyses.....................................................................................6-22 

6.4.5 Carbon Credit Calculation .....................................................................................6-27 

Project Cost Estimates and Economic Assessments 6-ii




Exhibit 6.1: Average Per Well Estimated Capital Cost for Donetsk region CBM Projects ...................6-1 

Exhibit 6.2: Detailed Drilling Cost Estimate ..........................................................................................6-3 

Exhibit 6.3: Operating Cost Assumptions.............................................................................................6-6 

Exhibit 6.4: Comparative Analysis of CBM Well Costs.........................................................................6-9 

Exhibit 6.5: CBM Production Profile ...................................................................................................6-11 

Exhibit 6.6: CBM Physical and Financial Assumptions ......................................................................6-12 

Exhibit 6.7: CBM Cash Flow...............................................................................................................6-13 

Exhibit 6.8: Gas Price, Operating Expenditure & Capital Expenditure Sensitivities...........................6-14 

Exhibit 6.9: CBM - Rate of Return Sensitivities ..................................................................................6-15 

Exhibit 6.10: CBM - NPV Sensitivities ..................................................................................................6-15 

Exhibit 6.11: CMM Project Estimated Costs.........................................................................................6-17 

Exhibit 6.12: CMM Power Plant Economic Models - Input Assumptions .............................................6-18 

Exhibit 6.13: South Donbass No.3 CMM Power Plant Results - Cashflow ..........................................6-19 

Exhibit 6.14: Bazhanov CMM Power Plant Results - Cashflow ...........................................................6-20 

Exhibit 6.15: Combined CMM Power Plant Results - Cashflow ...........................................................6-21 

Exhibit 6.16: South Donbass No.3 Power Plant Results – Sensitivity Analysis ...................................6-22 

Exhibit 6.17: South Donbass No.3 Power Plant - Variance in Parameter v Rate of Return ................6-23 

Exhibit 6.18: South Donbass No.3 Power Plant - Variance in Parameter v NPV (10%)......................6-23 

Exhibit 6.19: Bazhanov CMM Power Plant Results – Sensitivity Analysis...........................................6-24 

Exhibit 6.20: Bazhanov CMM Power Plant - Variance in Parameter v Rate of Return........................6-24 

Exhibit 6.21: Bazhanov CMM Power Plant - Variance in Parameter v NPV (10%) .............................6-25 

Exhibit 6.22: Combined CMM Power Plant Results – Sensitivity Analysis ..........................................6-25 

Exhibit 6.23: Combined CMM Power Plant - Variance in Parameter v Rate of Return........................6-26 

Exhibit 6.24: Combined CMM Power Plant - Variance in Parameter v NPV (10%) .............................6-26 

Exhibit 6.25: Carbon Credit Calculation – Credits Generated..............................................................6-28 

Exhibit 6.26: CMM Fired Power Generation with Carbon Credits @ $10/tonne ..................................6-29 

Exhibit 6.27: CMM Fired Power Generation with Carbon Credits @ $15/tonne ..................................6-30 

Exhibit 6.28: CMM Power Plant Economic Model Results Summary ..................................................6-31 

Project Cost Estimates and Economic Assessments 6-iii



6.1 CBM Capital and Operating Cost Estimates 

Advanced Resources has developed cost estimates for the goods and services required for 

the development of the South Donbass and Grishino-Andreyevskaya CBM license areas. 

These cost estimates are based on a combination of known local costs provided by a panel 

of Ukrainian experts and known average development costs of analogous projects in the 

U.S, with budgetary quotes provided by various suppliers, contractors and service 

companies. 

Down-hole equipment such as casing, tubing, packers, artificial lift equipment and 

specialized laboratory work will be sourced from outside Ukraine, but other items such as 

cementation and hydraulic fracturing services will be sourced from equipment and service 

companies existing in Ukraine and the eastern European region, and supplemented by new 

equipment purchases. Appropriate cost estimates for these items have been included in the 

economics presented in this section of the report. 

The capital cost envisaged for the development of a CBM prospect, assumes the drilling and 

completion of 1,040 wells, and will total approximately US$642 million. 

ARI estimates that approximately 50% of the goods and services that will be required to 

develop the projects can be sourced from Ukraine and the eastern European region. To the 

extent possible, industry standard best practices of U.S. operators will be adapted for the 

design, implementation, and operation of the development of the CBM projects, and this is 

reflected in the cost estimates and economics presented in this report. 

Average Per Well Capital Cost ($,000) 

Drilling, Completion, & Stimulation 483.51 

Compression 10.76 

Site Power Generation & Distribution 10.49 

Gas Gathering System 35.64 

Water Gathering & Disposal 16.27 

Infrastructure 60.50 

Total Capital Cost 617.17 

Exhibit 6.1: Average Per Well Estimated Capital Cost for Donetsk region CBM Projects 

Project Cost Estimates and Economic Assessments 6-1



6.1.1 Drilling, Completion and Stimulation 

The well design for the development of the CBM leases was presented in Section 3.2. The 

detailed cost estimate for this design is presented in Exhibit 6.2. The drilling, completion, and 

stimulation costs are broken into two main categories which include “intangible” and 

“tangible” cost estimates. Intangible costs include estimates for building drilling locations and 

roads, drilling, cementing, logging, coring and testing, hydraulic fracturing, and use of a 

completion rig. Tangible costs include tubing, casing, artificial lift equipment, well head 

equipment, and surface facilities such as separators and measurement equipment. 

6.1.1.1 Drilling and Completion 

The cost to drill and complete a CBM well includes the drilling rig rental including mobilization 

and contract drilling rates (charged as either footage rate or daily rate), bits, reamers, 

cementation, completion rig rental, materials such as cement and associated additives, 

casing and accessories (such as baffles, centralizers, floats and float shoes, cement baskets, 

etc.) and hydraulic fracturing and associated materials (such as sand, gel and chemical 

additives). 

The average well cost, including the items listed above, is estimated to be $483,513 for the 

CBM leases. These numbers should be taken as averages, as the well cost will be adjusted 

accordingly, for shallower or deeper well depths. Completions consider multiple coal seams 

and multiple completion intervals. Up to 7 intervals will be completed in each well. 

6.1.1.2 Well Stimulation 

A total cost of $150,000 (included in the drilling and completion estimate of $483,513 from 

Exhibit 6.1) has been estimated for the hydraulic fracture treatments per well for the Donetsk 

project. This estimate was supplied by Ukrainian experts familiar with costs in the region and 

compares well with stimulation costs in the United States which average about $125,000 and 

go as high as $200,000 for thicker and deeper San Juan Basin coal seams. 

6.1.1.3 Artificial Lift Equipment and Well Site Equipment 

Artificial lift equipment includes tubing, down hole pump, rods, surface pumping unit, etc. 

Cost estimates are based on designs presented earlier in this report. Surface facilities 

include water separator, gas separator, measurement equipment, and certain fittings and 

ancillary equipment. Costs have been included to equip each well site with this equipment. 

The artificial lift equipment and surface facilities are most likely to be sourced in the United 

States at a cost of $105,831 per well. 




ADVANCED RESOURCES INTERNATIONAL, INC. 

DATE September 2008 PROJECT NAME: Ukraine Donbass Basin 

WELL NO. One 

AFE NO: NA 

DRILLING COST ESTIMATE 

DESCRIPTION: Estimate for Average Well COUNTRY: Ukraine 

STATE Donetsk OPERATOR IUD 

PROJECT Donbass Basin PREPARED BY: Advanced Resources Intn'l, Inc. 

EXPLORATION DEVELOPMENT X RESULTS: Oil Gas X Dry ___ Exch. Rate TD 3,600 feet 

5.06 1,100 meters 

DRILLING INTANGIBLES: Quantity Units Rate Ukraine rph USD 

LOCATION, ROADS, PITS, DAMAGES: 1 per well 20,238 

102,403 грн. $20,238 

DRILLING 3600 feet 16 

294,921 грн. $58,285 

CEMENT AND CEMENTING: 127 bbl 130 

83,364 грн. $16,475 

LOGGING/MUD LOGGING: 3600 feet 8 

147,461 грн. $29,142 

CORING AND TESTING 1 Well 13,492 

68,269 грн. $13,492 

COMPLETION SERVICES (RIG) 1 Well 17,135 

86,701 грн. $17,135 

HYDRAULIC FRACTURING 

DRILLING TANGIBLES: 

CASING 

6 Treatment 25,000 

759,000 грн. $150,000 

CASING: 8 5/8 in J55 24 ppf R2 151 feet 22.26 

16,996 грн. $3,359 

CASING: 4 1/2 in M60 10.5 ppf R2 3600 feet 8.77 

159,749 грн. $31,571 

MISC CASING 1 UNIT 884 

4,472 грн. $884 

TUBING: 2 3/8 IN J55 4.6 PPF 3600 feet 4.25 

77,417 грн. $15,300 

SUCKER RODS 5/8 IN DIA 25 FT 3600 feet 3.37 

61,442 грн. $12,143 

MISC ARTIFICIAL LIFT 1 UNIT 1,686 

8,534 грн. $1,686 

PUMPING UNIT: CH80-119-64 BB w/ 4236# EC 1 UNIT 47,222 

238,941 грн. $47,222 

DOWNHOLE PUMP AND RELATED 1 UNIT 4,722 

23,894 грн. $4,722 

WELL HEAD 1 UNIT 1,012 

5,120 грн. $1,012 

GAS SEPARATOR 1 UNIT 2,361 

11,947 грн. $2,361 

WATER SEPARATOR 1 UNIT 8,567 

43,351 грн. $8,567 

DRIP 1 UNIT 3,778 

19,115 грн. $3,778 

MEASUREMENT 1 UNIT 7,421 

37,548 грн. $7,421 

MISCELANEOUS 1 UNIT 1,619 

8,192 грн. $1,619 

CRATING AND SHIPPING 1 UNIT 37,103 

187,739 грн. $37,103 

TOTAL WELL COST 2,446,576 грн. $483,513 

Exhibit 6.2: Detailed Drilling Cost Estimate 




6.1.1.4 Shipping of Materials, Supplies, and Equipment 

Many of the supplies and equipment necessary for drilling, completion, stimulation, and 

operating the Donetsk region wells may need to be imported. For the purposes of these 

economics, shipping costs for these supplies and equipment from the United States is 

estimated to cost an average of $37,103 per well. 

6.1.1.5 Geological, Geophysical and Location Costs 

Costs for the building of locations, pits and roads along with well logging services and any 

coring or testing services needed are estimated to average $49,380 per well. 

6.1.2 Surface Facilities 

Advanced Resources has estimated an average cost per well for surface facilities of 

US$133,660. This cost includes estimates for surface facilities and equipment including infield 

satellite compression, onsite power generation and distribution, the gas gathering 

system, the water gathering and disposal system, and basic infrastructure. Infrastructure cost 

includes cost estimates for offices, stores, materials storage, workshops, information 

technology, vehicles and equipment. The economics presented in this report are considered 

“field gate” economics, i.e., the price of gas delivered to either a pipeline or power plant at 

the field site. 

6.1.2.1 Gas Gathering System 

The engineering design of the gas (CBM) gathering system for the Donetsk project 

considered both high density polyethylene (HDPE) and normal carbon steel. The gas 

gathering system consists of two components that are called the trunk pipeline system and 

the lateral pipeline system. The final gas gathering system design assumes the use of HDPE 

pipe for the low pressure lateral system that will gather the gas from the well head and 

deliver it to the trunk pipeline system. 

The trunk pipeline system will be constructed from steel. It was determined that the 

combination of compression and high pressure steel would yield better economics than 

attempting to construct the trunk system from HDPE. The average per well cost of the gas 

gathering system is estimated to be $35,640. 




6.1.2.2 Compression 

In-field satellite compression will be utilized and will have two main advantages: First, in-field 

satellite compression will insure low well head pressure, a necessity for optimizing CBM 

recovery; Second, in-field compression will allow the cost savings afforded by using smaller 

diameter high pressure steel as opposed to very large diameter low pressure HDPE. The 

average per well cost of the in-field satellite compression is estimated to be $10,760. 

6.1.2.3 Site Power Generation and Distribution 

CBM operations require significant energy for operations and infrastructure. Artificial lift and 

in-field satellite compression represent the largest energy requirements, but lighting and 

electrical power is also necessary for offices, workshops, and information technology, etc. 

The average allocated per well cost of site power generation and distribution is estimated to 

be $10,490. 

6.1.2.4 Water Gathering and Disposal 

The water will be gathered by a steel pipeline system. The power required to transport the 

water will be provided by the down-hole artificial lift systems. The water will be transported to 

centrally located facilities, where it can be treated and discharged. The estimated per well 

cost for water gathering and disposal is $16,270. 

6.1.2.5 Infrastructure 

Infrastructure includes estimates for offices, stores, materials storage, workshops, 

information technology, vehicles and equipment. The estimated per well infrastructure cost is 

$60,500. 


6.1.3 Operating Cost Estimates 



The operating costs include well tending (pumping etc.), in-field compression, gas (CBM) 

gathering, on site power generation, and water gathering and disposal. The operating costs 

presented herein represent the best estimate available at this time, for use in the economic 

analysis. The major operating cost assumptions used are shown in Exhibit 6.3. 

Operating Cost Imperial 

Well Tending & Pumping $/Well/Month 1,056 $/Well/Month 1,056 

Field Compression 

$/1000m 3 

4.25 $/mcf 0.120 

Field Gathering Pipeline System $/1000m 3 

12.98 $/mcf 0.368 

Site Power Generation $/kWhr 0.009 $/kWhr 0.009 

Water Treatment & Disposal $/m 3 

Metric 

1.89 $/BBL 0.30 

Field Fuel (gas) Usage 2.93% 2.93% 

Exhibit 6.3: Operating Cost Assumptions 

6.1.3.1 Well Tending 

Well tending (sometimes referred to as well pumping) includes the normal well operation and 

maintenance costs, as well as workover operations cost. In general, the operating and 

maintenance costs associated with CBM wells are higher than conventional wells as frequent 

workovers, pump repairs and other maintenance are required in the initial stages of well 

operations. Power is also a large expense item which is covered under site power generation 

below. The well tending cost for a typical Donetsk region CBM well is estimated to be 

US$1,056 per well per month. 

6.1.3.2 Gas Compression and Gathering 

As discussed previously, it is necessary to optimize the recovery of CBM by maintaining a 

very low well head pressure at each well. Since the gas being produced is at a very low 

pressure of approximately 20 to 30 psig at the wellhead, compression will be required in 

order to transport the gas from satellite locations in the field through the field trunk pipelines 

to the field gate. It is estimated that gas will need to be compressed to the range of 350 to 

450 psig. Advanced Resources has estimated that 2.93% of the total gas stream will be 

required for compression fuel and power generation fuel. Operating cost to maintain the 

compressors is estimated to be $0.12/mcf ($4.25/Mm 3 ), and the operating cost to operate the 

gas gathering system is estimated to be $0.37/mcf ($12.98/Mm 3 ). 




6.1.3.3 Power Generation 

The operating cost to operate the combined cycle power generation station is estimated to 

be $0.009/kWhr. This operating cost estimate is in line with published values and operating 

experience. 

6.1.3.4 Water Treatment and Disposal 

This category includes the cost of maintaining the water gathering pipeline system, and the 

treatment and disposal of produced water. The cost to operate the water gathering and 

disposal system is estimated to be $0.30/bbl ($1.89/m 3 ). 




6.2 Benchmarking Analysis of Ukraine CBM Costs versus Major U.S. 

CBM Projects 

Proper planning and control of field development and operating costs are essential for any oil 

and gas venture and are particularly important in coalbed methane. First, coalbed methane 

production entails additional field facilities and costs generally not required by conventional 

gas production, such as down hole pumps, separators, and water disposal (Schraufnagel, 

1991). Second, in certain settings the coals may only support a moderate rate of gas 

production and so strict cost controls will be required to produce an economic project. 

Because of shallower depths, the capital investment costs for coalbed methane will likely be 

lower; however, the production operations and maintenance costs may be higher than for 

producing conventional gas (Kuuskraa et al., 1989). 

To provide benchmarks for the Donetsk region coalbed methane project, this section reviews 

the capital investment costs of several well-established coalbed methane basins in the U.S. 

and compares these costs to the Donetsk region project. The five U.S. basins analyzed 

include the Central Appalachian basin (Consol Energy, Equitable Resources; 3,000+ wells), 

the Uinta basin (Anadarko, ConocoPhilips; 1,000+ wells), the San Juan basin (BP, Red 

Willow, ConocoPhilips; 3,000+ wells), the Raton basin (Pioneer/Evergreen; 1,500+ wells), 

and the Warrior basin (Energen, BP; 4,000+). 

The large number of wells in each basin allows one to derive statistically significant numbers 

for the capital costs. The data sources for the benchmarking analysis include current and 

recent AFEs that Advanced Resources has generated for clients in each of these basins, 

discussions with operators who were willing to provide updated capital cost numbers, 

financial disclosures from various companies (e.g.; Annual Reports, quarterly 10K reports, 

etc.), and databases from the Energy Information Agency and the American Petroleum 

Institute. 

The primary capital investment costs for a CBM project include geological, geophysical, and 

lease acquisition outlays; well drilling, completion, and stimulation; installation of gas 

production and collection facilities; and construction of a water disposal system. Each of 

these major areas is discussed in the following subsections. Exhibit 6.4 is a tabular 

presentation of a comparative cost analysis of U.S. and Donetsk Region project costs. 




Basin 

Central San U. S. Donetsk Percent 

Basin Appalachian Uinta Juan Raton Warrior Average CBM Project Difference 

Depth (ft.) 1,900 

Geological/Geophysical 14,350 

Drilling and Completion 144,000 

Lease Equipment 1 

69,100 

Water Disposal 16,300 

Stimulation 60,000 

Total 2 

303,750 

3,000 

22,500 

462,000 

101,600 

20,900 

145,000 

752,000 

Notes: 

1. Includes compression, power generation, and gas gathering. 

2. Does not include infrastructure cost such as offices, warehouses, etc. 

COMPARATIVE ANALYSIS OF CBM WELL COSTS 

Selected U. S. Basins Compared to Donetsk Region CBM Project 

3,250 

24,300 

478,500 

96,700 

25,800 

200,000 

825,300 

Project Cost Estimates and Economic Assessments 6-9 

2,500 

21,700 

330,000 

66,600 

18,800 

65,000 

502,100 

1,900 

15,500 

280,800 

48,200 

9,220 

153,500 

507,220 

Exhibit 6.4: Comparative Analysis of CBM Well Costs 

2,510 

19,670 

339,060 

76,400 

18,200 

124,700 

578,030 

3,600 

29,142 

304,371 

56,890 

16,270 

150,000 

556,673 

43% 

48% 

-10% 

-26% 

-11% 

20% 

-4%

6.3 CBM Project Economics 



Separate economic analyses were run for CBM production and CMM production scenarios. 

For the CBM production, on the South Donbass and Grishino-Andreyevskaya lease areas, 

ARI carried out an economic and financial analysis to determine the project viability. This 

analysis utilized the operating and capital cost estimates developed previously in this section 

to determine the economics of the gas at the field gate. The CMM production from the South 

Donbass #3 and Bazhanov mines is assumed to be utilized in small power generators 

located at each mine to offset electric power purchases made by the mines. 

Each scenario has been subjected to sensitivities of capital cost, operating cost, and gas 

price. The economic assumptions, results, and sensitivity analysis are discussed below. The 

economics are presented on a pretax project basis. This is because each financial institution 

has its own internal hurdle rates for debt/equity ratios, rates of return, project risk factors, etc. 

6.3.1 CBM Production Analysis 

The field production profile for gas and water in the CBM lease areas was generated using 

the single well production profile generated from reservoir simulation studies as discussed 

earlier in Section 2. The production profile assumes that drilling will remain constant at 40 

wells per year, and that all resulting gas will be sold as it is produced, with no market 

constraints. This drilling schedule was selected because it is felt that it would be a 

reasonably achievable pace given the infrastructure and manpower availability in the area. 

The production profile for this scenario is shown in Exhibit 6.5. 

The modeled production profile peaks in year 31 at just over 22 MMcfd with a total of 1040 

wells (drilled on 0.25 km 2 spacing) producing 186 Bcf (5.3 billion m 3 ) over a period of 35 

years. 


mmcfd 

- 

25 

20 

15 

10 

5 

- 

50 

40 

30 

20 

10 



Ukraine CBM Production Profile 

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 

Drilling Schedule - # of Wells 

40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 

Gas Water 

- - - - - - - - - 

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 

Exhibit 6.5: CBM Production Profile 


2.5 

2.0 

1.5 

1.0 

0.5 

- 

mbpd

6.3.2 CBM Financial Assumptions 



Exhibit 6.6 is a table presenting the physical and financial assumptions used in the economic 

analysis. 

Physical & Financial Factors Imperial 

Calorific Value of Gas GJ/1000m 3 

36.46 Btu/Cu.Ft. 980 

Gas Price $/1000m 3 

Metric 

400 $/MMBtu 11.56 

Royalty Rate 3% 

Cost Inflation 3% 

Price Inflation 3% 

Inflation Start Year 2009 

Discounting Year 2009 

Exhibit 6.6: CBM Physical and Financial Assumptions 

The price that Ukraine currently pays for gas is between $300 and $500 per 1000 m 3 

(2008 figures based on input from a panel of Ukrainian experts) 

The base case assumes $400/1000 m3 and is sensitized +/- 30% to capture a gas price 

range from $280 to $520/1000 m3 

Using the prices above ($300 to $500 per 1000 m3) and a conversion factor of 35.3 

ft 3 /m 3 and 980 btu/ft 3 , this gas price equates to a price of $8.67 to $14.45/mmbtu. 

6.3.3 CBM Economic Results 

The net present value discounted at 10% is $239.2 million with an internal rate of return of 

33%. 

A cash flow for CBM production is presented in Exhibit 6.7. 




Exhibit 6.7: CBM Cash Flow 


6.3.4 CBM Sensitivity Analyses 



Because of the uncertainties involved in the estimate of certain parameters used in the 

economic analysis, a set of sensitivity analyses were run to examine the impact of higher or 

lower gas price, capital cost, and operating cost. Exhibit 6.8 shows the net present value 

discounted at 10% and internal rate of return for the project when gas prices, capital cost, 

and operating costs are varied from minus 30% to plus 30% from the base case described 

above. 

Gas Price Sensitivity ($/mmbtu) 

Gas 

Price 

NPV10 (USD-million) Internal Rate of Return 

$ 280 89.3 

18.24% 

$ 320 108.8 

20.08% 

$ 360 174.0 

26.41% 

$ 400 239.2 

33.03% 

$ 440 304.3 

39.87% 

$ 480 369.4 

46.90% 

$ 520 434.6 

54.07% 

Percent 

Variance 

-30% 272.0 

-20% 261.0 

-10% 250.1 

0% 239.2 

10% 228.2 

20% 217.3 

30% 206.3 

Operating Expense Sensitivity 


35.58% 

34.73% 

33.88% 

33.03% 

32.17% 

31.31% 

30.44% 

Capital Expenditure Sensitivity 

Percent 

Variance 


-30% 330.0 

59.67% 

-20% 299.7 

48.30% 

-10% 269.5 

39.69% 

0% 239.2 

33.03% 

10% 208.9 

27.78% 

20% 178.6 

23.59% 

30% 148.3 

20.19% 

Exhibit 6.8: Gas Price, Operating Expenditure & Capital Expenditure Sensitivities 

The sensitivity analyses reveal that the project is most sensitive to gas price and capital 

expenditures and is least sensitive to operating cost. This is typical of most oil and gas 

projects. When gas price is varied from $280/1000m 3 to $520/1000m 3 (-30% to +30%) the 

IRR ranges from 18.24% to 54.07%. Operating expense variance from minus 30% to plus 

30% yields an IRR range from 33.58% to 30.44%. Capital expenditure variance from minus 

30% to plus 30% yields an IRR range from 59.67% to 20.19%. These sensitivity results are 

presented graphically in Exhibit 6.9 and Exhibit 6.10. 


Rate of Return 

Net Present Value @ 10% 

60% 

55% 

50% 

45% 

40% 

35% 

30% 

25% 

20% 

450 

400 

350 

300 

250 

200 

150 

100 



Ukraine Economic Sensitivity Analysis 

Variance in Parameter vs. Rate of Return 

15% 

-30% -20% -10% 0% 10% 20% 30% 

Variance in Parameter 

Capex Opex Gas Price 

Exhibit 6.9: CBM - Rate of Return Sensitivities 

Ukraine Economic Sensitivity Analysis 

Variance in Parameter vs. Net Present Value Discounted @ 10% 

50 

-30% -20% -10% 0% 10% 20% 30% 


Capex Opex Gas Price 

Exhibit 6.10: CBM - NPV Sensitivities 




6.4 CMM Power Project Economics 

The CMM production from the Bazhanov Mine and the South Donbass No.3 Mine will be 

utilized in small power generators located at each mine and can be used to offset electric 

power purchases made by these mines. Power production at the mine sites was determined 

to be the most economic utilization option in terms of capital costs, time value of money, and 

ability to realize carbon credits. The Bazhanov Coal Mine requires 8,600 kWhr while the 

South Donbass No.3 Coal Mine requires 12,300 kWhr. CMM power project economics have 

been estimated individually for the Bazhanov and South Donbass No.3 mines and have also 

been estimated as a combined total project. 

6.4.1 CMM Production Analysis 

The Bazhanov Coal Mine produces 9.9 million m 3 of methane per year, and utilizes 5.5 

million m 3 per year, leaving a net production of 4.4 million m 3 available for power generation. 

The South Donbass No.3 Coal Mine produces 8.8 million m 3 (25 million m 3 @ 35% 

concentration) of methane per year, all of which is available for power generation. This is 

enough fuel to power a 1.7 MW facility at the Bazhanov Mine and 3.3 MW facility at the 

South Donbass #3 mine. 

The two mines combined will produce 13.2 million m 3 /year (0.466 bcf/yr) of methane that is 

available for power generation (5 MW for the purpose of the combined economics). 

Individual economics for the 1.7 MW and 3.3 MW generators – with and without carbon 

credits - are presented in the following pages, along with the economics for combined 

generation of 5 MW of power capacity. Carbon credits calculations are run using values of 

$10/tonne and $15/tonne. 

6.4.2 CMM Economic Assumptions 

Capital project costs are summarized in Exhibit 6.11. Included are costs for upgrading and 

expanding the in-mine gas drainage and ventilation systems; purchases of the power 

generators; and project development costs. Total capital project costs for the South 

Donbass mine are estimated to be just under $6 million; for the Bazhanov mine, $3.3 million; 

and for the combined project, $9.3 million. 




Ukraine CMM Capital Cost Summary (USD-thousands) 

South 

Donbass Bazhanov Total 

CMM Drainage Methane Production (million m 3 ) 8.75 4.4 13.15 

Site Power Generation (MW) 3.3 

1.7 

5.0 

In-mine Drilling and Drainage System Upgrade 

Equipment Mobilization/Set-up: 

Integration: 39 

Training: 16 

Delivery: 8 

Collection System: 22 

Site Preparation: 7 

Construction / Installation: 14 

Set-up/Commissioning: 15 

Subtotal $ 121 $ 67 

188 

Implementation/Site Establishment (Drilling)/Equipment Acquisition: 

Geological and Geophysical: 11 

Site Establishment: 7 

Drilling Equipment: 752 

Drilling Expenses: 78 

Casing and Cementing: 89 

Gas Drainage System Rehabilitation: 200 

Ventilation System Rehabilitation: 120 


22 

9 

4 

12 

4 

8 

8 

6 

4 

378 

43 

49 

110 

66 

61 

25 

12 

34 

10 

21 

23 

17 

10 

1,130 

121 

138 

310 

186 

Subtotal $ 1,255 $ 657 

1,709 

Engineering Design and Supervision: 131 

Operations and General / Administrative: 69 

Contingency: 108 

In-mine Drilling & Drainage System Upgrade Subtotal $ 1,684 $ 894 

2,578 

Power Generation and Heat Utilization (USD-thousands) 

Generators Purchase/Delivery/Set-up 

South 


Heat and Power Plants: 2,070 1,145 

3,215 

Compression and Filtration 699 

387 

1,085 


172 

482 

Contingency: 238 

132 

370 

Operating Reserve: 238 

132 

370 

Training: 83 

46 

129 

Subtotal $ 3,638 $ 2,012 

5,650 

Emissions Reduction Units (ERU's) Programme 

Programme Design and Baseline Assessment: 18 

Pre-Validation/Set-up: 4 

Evaluation/Monitoring/Validation/OH: 24 

Subtotal $ 46 $ 26 

72 

Flaring Unit 

Complete System: 120 

Installation/Commissioning: 30 


73 

38 

59 

10 

2 

13 

120 

30 

23 

204 

107 

167 

28 

7 

37 

240 

60 

45 

$ 173 $ 173 

345 

Power Generation & Heat Utilization Subtotal $ 3,857 $ 2,210 

5,995 

Project Development (USD-thousands) 

Leases, Licenses, Operating/Production Rights 

South 


Acquisition: 263 

145 

408 

Accrued Fees: 85 

47 

132 

Set-up Office/Management Systems: 34 

Financing Charges: 44 

$ 348 $ 192 

540 

Project Development Subtotal $ 426 $ 235 

661 

Combined Total Project Cost $ 5,966 $ 3,339 $ 9,306 

Exhibit 6.11: CMM Project Estimated Costs 

19 

24 

52 

69



Power plant operating costs have been figured at 8% of the capital cost annually. The 

operating cost for the degasification systems (and drilling and ventilation, etc.) was also 

figured at 8% of capital cost annually. The power price is based on the cost of mine power 

consumption that is to be offset by the generated power. Per engine manufacturer 

specifications, a generator efficiency of 36% was used and a load factor slightly less than 

96% was used. It has been assumed that the projects would start in January of 2009. These 

figures are summarized in Exhibit 6.12. 

Ukraine CMM Economic Model 

Case: Power Plant Economics South Bazhanov Combined 

Date: 39702 Donbass Mine Generation 

Economic Input Assumptions Mine 

Capital Cost 

Drilling & Drainage System Upgrade $,000 1,684 894 2,578 

Generation, Heat, and Flaring $,000 3,857 2,210 5,995 

Project Development $,000 426 235 661 

Operating Cost 

Power Plant % 8.0 

Degassification System % 8.0 

Physical & Financial Factors 

Power Sales Price $/kW 0.0559 

Generator Size MW 3.4 1.7 5.1 

Generator Efficiency - 100% Load 36% 

Run Time 96% 

Project Start Year 2009 

Project Start Month 1 

Carbon Credit Parameters 

Carbon Credit Value $/tonne 10 

Certification Fee (per mine) $,000 55 

Certification Frequency /yr 2 

Kyoto Ends in Project Year 4 

Exhibit 6.12: CMM Power Plant Economic Models - Input Assumptions 

6.4.3 CMM Economic Results 

The 35 year cash flows for the CMM power projects of the South Donbass No.3 mine, 

Bazhanov mine and combined economics are presented in Exhibit 6.13, Exhibit 6.14 and 

Exhibit 6.15. These cash flows show the escalated power price and escalated power plant 

and degasification operating costs. A discounted cash flow analysis using various discount 

rates is also presented along with the calculated internal rate of return. 




Exhibit 6.13: South Donbass No.3 CMM Power Plant Results - Cashflow 




Exhibit 6.14: Bazhanov CMM Power Plant Results - Cashflow 




Exhibit 6.15: Combined CMM Power Plant Results - Cashflow 


6.4.4 CMM Sensitivity Analyses 



Because of the inherent uncertainties in estimating the operating and capital costs of the 

power projects, and the potential price at which power could be sold, analyses were 

performed for each project to examine the sensitivity of the economics to these parameters. 

The capital and operating costs, and the power sales price, were each subjected to 

variations from minus 30% to plus 30% in 10% increments. 

Exhibit 6.16, Exhibit 6.19 and Exhibit 6.22 are tabular presentations of the sensitivity 

analyses carried out. The variation in the parameter is shown in the left column, and the 

resulting net present value discounted at 10% and rate of return are presented in the middle 

and right columns respectively. 

South Donbass Mine 

Power Price Sensitivity ($/kW) 

Power NPV10 NPV10 (USD-million) Internal Rate of Return 

Price (USD thousands) 

$ 0.0392 1,917 

12.8% 

$ 0.0448 3,766 

15.2% 

$ 0.0503 5,615 

17.5% 

$ 0.0559 7,463 

19.7% 

$ 0.0615 9,312 

21.8% 

$ 0.0671 11,160 

23.8% 

$ 0.0727 13,009 

25.8% 


Prercent NPV10 NPV10 (USD-million) Internal Rate of Return 

Variance (USD thousands) 

70% 9,085 

21.6% 

80% 8,544 

21.0% 

90% 8,004 

20.3% 

100% 7,463 

19.7% 

110% 6,922 

19.0% 

120% 6,382 

18.3% 

130% 5,841 

17.7% 




70% 9,148 

25.6% 

80% 8,586 

23.2% 

90% 8,025 

21.3% 

100% 7,463 

19.7% 

110% 6,902 

18.3% 

120% 6,340 

17.1% 

130% 5,778 

16.1% 

Exhibit 6.16: South Donbass No.3 Power Plant Results – Sensitivity Analysis 

The sensitivity analyses reveal that the power projects are most sensitive to power price 

variability and capital expenditures and less sensitive to changes in operating cost. This is 

consistent with most oil and gas project economics. The sensitivity results are presented 

graphically in Exhibits 5.17, 5.18, 5.20, 5.21, 5.23 and 5.24. 




26% 

24% 

22% 

20% 

18% 

16% 

14% 



South Donbass Ukraine #3 Mine - Power Plant Economics 


12% 

-30% -20% -10% 0% 10% 20% 30% 


Capex Opex Power Price 

Exhibit 6.17: South Donbass No.3 Power Plant - Variance in Parameter v Rate of Return 

14000 

12000 

10000 

8000 

6000 

4000 

2000 

South Donbass Ukraine #3 Mine - Power Plant Economics 


0 

-30% -20% -10% 0% 10% 20% 30% 



Exhibit 6.18: South Donbass No.3 Power Plant - Variance in Parameter v NPV (10%) 



24% 

22% 

20% 

18% 

16% 

14% 

12% 



Bazhanov Mine 

Power Price Sensitivity ($/kW ) 

Power NPV10 NPV10 (USD-million) Internal Rate of Return 


$ 0.0392 342 

10.9% 

$ 0.0448 1,272 

13.2% 

$ 0.0503 2,201 

15.4% 

$ 0.0559 3,131 

17.5% 

$ 0.0615 4,060 

19.4% 

$ 0.0671 4,990 

21.3% 

$ 0.0727 5,919 

23.2% 




70% 4,037 

19.5% 

80% 3,735 

18.8% 

90% 3,433 

18.1% 

100% 3,131 

17.5% 

110% 2,828 

16.8% 

120% 2,526 

16.1% 

130% 2,224 

15.4% 




70% 4,074 

22.8% 

80% 3,759 

20.7% 

90% 3,445 

18.9% 

100% 3,131 

17.5% 

110% 2,816 

16.2% 

120% 2,502 

15.2% 

130% 2,188 

14.3% 

Exhibit 6.19: Bazhanov CMM Power Plant Results – Sensitivity Analysis 

Bazhanov Ukraine Mine - Power Plant Economics 


10% 

-30% -20% -10% 0% 10% 20% 30% 



Exhibit 6.20: Bazhanov CMM Power Plant - Variance in Parameter v Rate of Return 



6000 

5000 

4000 

3000 

2000 

1000 



Bazhanov Ukraine Mine - Power Plant Economics 


0 

-30% -20% -10% 0% 10% 20% 30% 

Variance in Parameter Capex Opex Power Price 

Exhibit 6.21: Bazhanov CMM Power Plant - Variance in Parameter v NPV (10%) 

Total Two M ines 

P ow er Price Se ns it iv ity ( $/kW ) 

Power NP V1 0 NPV10 (USD-million ) Inte rna l Ra te of Retu rn 


$ 0.0392 2,393 

12.3% 

$ 0.0448 5,172 

14.7% 

$ 0.0503 7,950 

16.9% 

$ 0.0559 10,728 

19.0% 

$ 0.0615 13,506 

21.1% 

$ 0.0671 16,284 

23.1% 

$ 0.0727 19,062 

25.1% 


Prercent NP V1 0 NPV10 (USD-million ) Inte rna l Ra te of Retu rn 


70% 13,236 

21.0% 

80% 12,400 

20.4% 

90% 11,564 

19.7% 

100% 10,728 

19.0% 

110% 9,892 

18.4% 

120% 9,056 

17.7% 

130% 8,219 

17.0% 


Prercent NPV10 NPV10 ( USD-million ) Internal Rate of Return 


70% 13,336 

24.8% 

80% 12,466 

22.5% 

90% 11,597 

20.6% 

100% 10,728 

19.0% 

110% 9,859 

17.7% 

120% 8,989 

16.6% 

130% 8,120 

15.6% 

Exhibit 6.22: Combined CMM Power Plant Results – Sensitivity Analysis 




26% 

24% 

22% 

20% 

18% 

16% 

14% 



Ukraine Combined Mine - Power Plant Economics 


12% 

-30% -20% -10% 0% 10% 20% 30% 



Exhibit 6.23: Combined CMM Power Plant - Variance in Parameter v Rate of Return 

20000 

18000 

16000 

14000 

12000 

10000 

8000 

6000 

4000 

2000 

Ukraine Combined Mine - Power Plant Economics 


0 

-30% -20% -10% 0% 10% 20% 30% 



Exhibit 6.24: Combined CMM Power Plant - Variance in Parameter v NPV (10%) 


6.4.5 Carbon Credit Calculation 



Baseline emissions consist of 0.464 Bcf of methane, (187,000 tonnes CO2 equivalent), and 

the CO2 that would be generated by 5 MW of coal fired generation capacity displaced once 

the CMM fired reciprocating engine generators begin producing electricity. These base line 

emissions will be offset by the CO2 that will be produced by flaring the gas or burning the gas 

as fuel in the reciprocating engines. 

When the power generators are not running, the gas will be flared. Exhibit 6.25 shows that in 

the first two project years, 162,514 tonnes of CO2 credit are generated, and after that, 

206,224 tonnes are generated annually. After project year 4, no credits are generated as the 

first commitment period of the Kyoto Protocol ends after 2012. 

Cash flow analyses for CMM power production with carbon credits at $10/tonne and 

$15/tonne are shown in Exhibit 6.26 and Exhibit 6.27. 

A summary of the cash flow analyses for CMM power production, with and without carbon, 

credits ($10/tonne) is shown in Exhibit 6.28. With carbon credits ($10/tonne), the combined 

CMM power project has a net present value of $10 million and an internal rate of return (at 

10%) of 28.9%. 




Exhibit 6.25: Carbon Credit Calculation – Credits Generated 




Exhibit 6.26: CMM Fired Power Generation with Carbon Credits @ $10/tonne 




Exhibit 6.27: CMM Fired Power Generation with Carbon Credits @ $15/tonne 




Economic Results 

South Donbass Bazhanov Combined 

Mine Mine Generation 

(USD, thousands) 

Power Generation without Carbon Credits 

Discounted Net Present Value @ 10% 7,463 3,131 10,728 

Discounted Net Present Value @ 15% 2,309 667 3,082 

Discounted Net Present Value @ 20% (118) (487) (514) 

Discounted Net Present Value @ 30% (2,192) (1,461) (3,578) 



Internal Rate of Return 19.7% 17.5% 19.0% 

Power Generation with Carbon Credits ($10/tonne) 





Discounted Net Present Value @ 40% (1,002) (960) (1,739) 



Power Generation with Carbon Credits ($15 tonne) 





Discounted Net Present Value @ 40% 336 (287) 272 



Exhibit 6.28: CMM Power Plant Economic Model Results Summary 


Task 7 



Project Finance and Carbon Credits 

Project Finance and Carbon Credits 7-i




7.1 Introduction........................................................................................................7-4 

7.2 Project Finance..................................................................................................7-4 

7.3 Carbon Finance..................................................................................................7-5 

7.4 General Background – Kyoto Protocol............................................................7-7 

7.4.1 Objectives and Principles of the UNFCCC. .............................................................. 7-8 

7.4.2 Kyoto Emission Reduction Targets .......................................................................... 7-9 

7.4.3 When Did the Kyoto Protocol Come into Force?.................................................... 7-10 

7.4.4 The European Union (EU) and the Kyoto Protocol................................................. 7-11 

7.4.5 International Emissions Trading ............................................................................. 7-11 

7.4.6 Joint Implementation and the Clean Development Mechanism ............................. 7-12 

7.4.7 General Fundamentals for JI Projects .................................................................... 7-12 

7.4.7.1 Project Identification......................................................................................7-12 

7.4.7.2 Project Design and Assessment ...................................................................7-13 

7.4.8 Implications for Ukraine.......................................................................................... 7-15 

7.5 Validation/Determination and Verification Methodology .............................7-16 

7.5.1 ACM0008 Methodology.......................................................................................... 7-16 

7.6 Consideration of Prices of Carbon Credit Units ...........................................7-17 

7.7 Project Risk Reduction Support.....................................................................7-19 

7.8 Examples of Integrated Project Financing ....................................................7-20 

7.8.1 Sample Project ....................................................................................................... 7-20 

7.8.1.1 Capital Expenditure.......................................................................................7-20 

7.8.1.2 Project Finance .............................................................................................7-22 

7.8.1.3 Example OPIC Loan Terms ..........................................................................7-22 

7.8.1.4 Carbon Finance.............................................................................................7-22 

7.9 Project Implementation and Management.....................................................7-23 

7.9.1 Management Structure........................................................................................... 7-24 

7.10 References .......................................................................................................7-26 

Project Finance and Carbon Credits 7-ii




Exhibit 7.1: Carbon Market at a Glance, Volumes and Values in 2005-06.............................7-6 

Exhibit 7.2: Countries included in Annex B to the Kyoto Protocol and their emissions 

targets................................................................................................................7-10 

Exhibit 7.3: Observed Prices for Project-based Transactions in 2005 & 2006 

(Carpoor and Ambrosi, 2007) ............................................................................7-18 

Exhibit 7.4 Project Costs– Consolidation of Sources and Uses ..........................................7-21 

Exhibit 7.5: Senior Management Chart.................................................................................7-25 

Exhibit 7.6: Production Management Chart..........................................................................7-25 

Project Finance and Carbon Credits 7-iii




To secure project financing for CMM/CBM projects in emerging market countries such as 

Ukraine, a project developer or investor (Project Sponsor) must demonstrate the potential 

project's technical and financial viability, usually through the combination of pre-feasibility 

studies, full feasibility studies, technology assessments, and pilot installations. These 

analyses can be financed by the project developer or investors, although some financial 

support may be available. Project financing options include direct project investment in the 

form of capital and in-kind contributions (equity and equity financing) and loans (debt); and a 

type of structured trade financing (carbon finance), which may provide a revenue stream 

based on mitigated carbon emissions. Many funding and investment sources, particularly 

Multilateral Development Banks (MDBs) and International Development Funds, emphasize 

sustainable development, environmental protection, and climate change mitigation as 

important components of projects they will finance. Another critical component of project 

financing is reducing the project or financial risk through completion guarantees and risk 

insurance. CMM/CBM projects are attractive because they can support all of these aspects 

of financing, while meeting the development and investment objectives of the sponsors. 

7.2 Project Finance 

Project Finance is the financing of ‘Greenfield’ and expansion projects based upon a nonrecourse 

or limited recourse financial structure, where project debt and equity used to 

finance the project are paid back from the cash-flow generated by the project. Project 

finance for emerging market countries usually includes medium-term (8- to 10-year) debt 

facilities that rely primarily on the project's cash flow for repayment, with the project's assets, 

rights, and interests held as secondary security or collateral. 

CMM/CBM projects are ideally suited for structured Project Finance, whereby specific 

revenue streams are anticipated from the sale of electricity and heat or the sale of gas for 

market distribution. Such Project Finance contemplates an aggregate total project costs, 

which when fully invested the project will operate and generate income for the sale of a 

specific product or commodity, such as electricity or gas. The loan and interest are repaid 

from the cash flow after operating expenses and before any equity distributions to the Project 

Sponsors; and the net income dividends are distributed to the Sponsors to repay the equity 

contributions and to provide a return-on-investment. 

Project Finance and Carbon Credits 7-4

7.3 Carbon Finance 



Certain CMM utilization projects are capable of offering economic returns that are sufficient 

to attract investors and lenders. However, many CMM projects generate only marginal 

dividends from the usual sources of primary revenue, and often need supplemental 

incentives to enhance the projects as attractive investment opportunities. Carbon Finance, or 

the so-called Carbon Credits derived from such financing, may be particularly useful for 

improving the cash flow of projects that are otherwise economically marginal and unattractive 

to investors. Thus, with world Carbon Credit pricing now ranging from $3 to $25 per ton of 

CO2 equivalent (CO2eq) or more, income from the sale of Carbon Credits can add 

substantially to a project's balance sheet. 

The sale of Emission Reduction Units (ERUs) generated by Joint Implementation (JI) 

projects or Certified Emission Reductions (CERs) generated by Clean Development 

Mechanism (CDM) projects can offer project developers an attractive supplemental revenue 

stream; where neither the primary revenue stream nor the Carbon Credit revenues, 

individually, are adequate to provide the level of funding necessary for project development 

and implementation. However, the combined revenues will provide acceptable investment 

returns and, thus, the integrated project financing allows the project to occur 

The role and value of Carbon Finance, or the production and selling of emission reductions, 

in energy development projects have increased significantly during the last several years. 

European governments have been purchasing Carbon Credits in developing countries, and 

this practice has expanded with full ratification of the Kyoto protocol. The main buyers of 

Carbon Credits are: 

(i) European private buyers with interest in the European Union (EU) Emissions Trading 

Scheme (ETS); 

(ii) government buyers with Kyoto compliance commitments; 

(iii) Japanese and U.S. companies with voluntary commitments; 

(iv) U.S. multinational corporations with operations in Japan or Europe; and 

(v) power retailers and large consumers in Australia. 

The development of the mine degasification and methane utilization project for the Donetsk 

Region of Ukraine (the “Project”) has the potential to earn Carbon Credits for verified capture 

of CMM that is presently not utilized, and from Coal Bed Methane (CBM) from coal seams 

that may eventually be mined; additional Carbon Credits might be earned where the CMM 

utilization involves a clean energy source that will displace other fuels such as coal. 




A considerable number of organizations have been involved in creating and defining the 

various markets for carbon trading, and new carbon funds continue to emerge; 

demonstrating the vitality of the current global carbon market. Markets have been created by 

governments, others by multilateral institutions, and still others by private-sector businesses. 

As shown in Exhibit 7.1, the overall volumes and financial values transacted on the carbon 

markets are growing, with both volume and value experiencing significant increases from 

2005 to 2006. The overall value of the carbon market in 2006 was an estimated US$ 30 

billion, representing a three-fold increase over the previous year. 

Sellers of emission reductions already have many potential buyers. As activity in the carbon 

market continues to increase, so should liquidity, as additional buyers such as London-based 

financial institutions and other private (e.g., banks and carbon funds) and public sector 

buyers look to invest in the carbon market. 

Exhibit 7.1: Carbon Market at a Glance, Volumes and Values in 2005-06 




7.4 General Background – Kyoto Protocol 

The official and most accurate information concerning the comprehensive description of the 

Kyoto Protocol is described at the United Nations Framework Convention on Climate Change 

website (http://unfccc.int), which is continually updated, indicating the current and most 

recent approval issued by the various units of the United Nations Organization. This section 

intends to summarize some of these key aspects; and, at the risk that some important data 

may be omitted, it is recommended to review the full depth of information from the official 

sources at the relevant websites of the United Nations. 

In 1992, more than 180 countries participating in the "Earth Summit", in Rio de Janeiro, 

adopted the United Nations Framework Convention on Climate Change (UNFCCC). The 

UNFCCC is a legal framework that enables Parties to the Convention to start the process of 

stabilizing greenhouse gases (GHG) in the atmosphere. Parties to the UNFCCC have been 

meeting every year since 1994 to implement and define this framework. At the third meeting 

of the Parties, COP 3, the Kyoto Protocol was adopted and set legally binding GHG 

reductions for industrialized countries, or so called Annex I Parties. 

The Kyoto Protocol entered into force on 16 February 2005, the 19 th day after at least 55 

countries ratified the treaty, representing the minimum required 55% of the Annex I countries' 

1990 emissions levels.. In time for the first compliance period (2008- 2012), Annex I Parties 

will have to encourage or regulate private companies and individuals to reduce GHG 

emissions. Most of these reductions will occur within the borders of each Annex I country, 

but the Kyoto Protocol identifies mechanisms by which credit can be received for GHG 

reduction projects in non-Annex I countries. 

The United Nations Convention on Climate Change (UNFCCC) sets an overall framework for 

intergovernmental efforts to tackle the challenge posed by climate change. It recognizes that 

the climate system is a shared resource whose stability can be affected by industrial and 

other emissions of carbon dioxide and other heat-trapping gases. The UNFCCC was the first 

international measure to address the problem; adopted in May 1992, and came into force in 

March 1994. It obliges all its signatories to establish national programs for reducing 

greenhouse gas emissions and to submit regular reports, and demands that the 

industrialized signatory countries, as opposed to developing countries, stabilize their 

greenhouse gas emissions at 1990 levels by the year 2000. This goal, however, is nonbinding. 




By differentiating between industrialized (Annex I countries) and countries with Economies in 

Transition (EIT), and developing countries (non-Annex I countries), the UNFCCC recognizes 

that industrialized countries are responsible for most of the global greenhouse gas 

emissions, and have the institutional and financial capacities for reducing them. The Parties 

meet annually to review progress and discuss further measures, and a number of global 

monitoring and reporting mechanisms are in place to keep track of greenhouse gas 

emissions. 

From around the world, 191 countries have joined the international treaty that sets general 

goals and rules for confronting climate change. Under the Convention, governments: 

Gather and share information on greenhouse gas emissions, national policies, and best 

practices; 

Launch national strategies for addressing greenhouse emissions and adapting to 

expected impacts, including the provision of financial and technological support to 

developing countries; and 

Cooperate in preparing for adaptation to the impacts of climate change. 

7.4.1 Objectives and Principles of the UNFCCC. 

It was already recognized in 1994 that the initial UNFCCC commitments would not be 

enough to halt the global increase in greenhouse gas emissions. On 11 December 1997, 

governments took a further step and adopted a protocol to the UNFCCC in the Japanese 

town of Kyoto. Building on the UNFCCC framework, the Kyoto Protocol sets legally binding 

limits on greenhouse gas emissions in industrialized countries, and envisages innovative 

market-based implementation mechanisms aimed at keeping the cost of curbing emissions 

low. 

The Protocol's major feature is that it has mandatory targets on greenhouse-gas emissions 

for the world's leading economies, which have accepted it. These targets range from -8 

percent (-8%) to +10 percent (+10%) of the countries' individual 1990 emissions levels "with 

a view to reducing their overall emissions of such gases by at least 5.2 percent (5.2%) below 

existing 1990 levels in the commitment period of 2008 to 2012". In almost all cases, even 

those set at +10% of 1990 levels, the limits call for significant reductions in currently 

projected emissions. (Exhibit 7.2) Future mandatory targets are expected to be established 

for "commitment periods" subsequent to 2012. These are to be negotiated well in advance of 

the periods concerned. 




The targets cover emissions of the six main greenhouse gases, namely: 

Carbon dioxide (CO2); 

Methane (CH4); 

Nitrous oxide (N2O); 

Hydrofluorocarbons (HFCs); 

Perfluorocarbons (PFCs); and 

Sulphur hexafluoride (SF6). 

7.4.2 Kyoto Emission Reduction Targets 

Under the Kyoto Protocol, industrialized countries are required to reduce the emissions of six 

greenhouse gases (CO2, which is the most important one) on average by 5.2 % below the 

1990 levels during the first "commitment period" from 2008 to 2012. There are no emission 

targets for developing countries. 

A five-year commitment period was chosen, rather than a single target year, to smooth-out 

annual fluctuations in emissions due to uncontrollable factors such as weather. International 

negotiations on a second commitment period under the Kyoto Protocol, subsequent to 2012 

began in 2005. The six gases are to be combined in a "basket", with reductions in individual 

gases translated into "CO2 equivalents" that are then added up to produce a single figure. 

Each country’s emissions target must be achieved by the period 2008-2012. It will be 

calculated as an average over the five years. Cuts in the three most important gases: carbon 

dioxide (CO2), methane (CH4), and nitrous oxide (N2O) - will be measured against a base 

year of 1990 (with exceptions for some countries with economies in transition). Cuts in three 

long-lived industrial gases: hydro fluorocarbons (HFCs), perfluorocarbons (PFCs), and 

sulphur hexafluoride (SF6), can be measured against either a 1990 or a 1995 baseline. (A 

major group of industrial gases, chlorofluorocarbons, or CFCs, are dealt with under the 1987 

Montreal Protocol on Substances that Deplete the Ozone Layer). 




Target (1990* - 2008/2012) 

EU-15** Bulgaria, Czech Republic, Estonia, Latvia, Liechtenstein, Lithuania, 

Monaco, Romania,Slovakia,Slovenia, Switzerland 

US*** 

Canada, Hungary, Japan, Poland 

Croatia 

New Zealand, Russian Federation, Ukraine 

Norway 

Australia 

Iceland 

* Some EITs have a baseline other than 1990. 

** The EU’s 15 member States will redistribute their targets among themselves, taking 

advantage of a scheme under the Protocol known as a “bubble”. The EU has already 

reached agreement on how its targets will be redistributed. 

*** The US has indicated its intention not to ratify the Kyoto Protocol. 

Note: Although they are listed in the Convention’s Annex I, Belarus and Turkey are not 

included in the Protocol’s Annex B as they were not Parties to the Convention when the 

Protocol was adopted. 

Upon entry into force, Kazakhstan, which has declared that it wishes to be bound by the 

commitments of Annex I Parties under the Convention, will become an Annex I Party 

under the Protocol. As it had not made this declaration when the Protocol was adopted, 

Kazakhstan does not have an emissions target listed for it in Annex B. 

Exhibit 7.2: Countries included in Annex B to the Kyoto Protocol and their emissions targets 

7.4.3 When Did the Kyoto Protocol Come into Force? 

Project Finance and Carbon Credits 7-10 

-8% 

-7% 

-6% 

-5% 

0% 

+1% 

+8% 

+10% 

The commitment became legally binding once the Kyoto Protocol entered into force. The 

rules for entry into force demanded that a minimum of 55 Parties to the UNFCCC ratify the 

Protocol, and that those include industrialized countries (Annex I countries) accounting for at 

least 55% of the CO2 emissions in 1990. 

Thus far, more than 174 countries have ratified the Kyoto Protocol, so the first threshold has 

been attained. The Annex I countries among them represent nearly 62% of the CO2 

emissions, so the second threshold has also been attained and the Kyoto Protocol entered 

into force in February 2005. The ratification by Russia, which is responsible for 17.4% of the 

global 1990 CO2 emissions, made it possible for the Protocol's entry into force. The United 

States, which is responsible for 36.1%, and thus is the world’s largest CO2 polluter, withdrew 

from the Kyoto Protocol in early 2001.



7.4.4 The European Union (EU) and the Kyoto Protocol 

On 31 May 2002, the European Union (EU) and all its Member States ratified the Kyoto 

Protocol. Under the Kyoto Protocol, the EU committed itself to reducing its greenhouse 

gases emissions by 8% during the first commitment period from 2008 to 2012. This target is 

shared between the Member States under a legally binding burden-sharing agreement, 

which sets individual emissions targets for each Member State. 

Ten new member states joined the EU in May 2004, all of which have ratified the Kyoto 

Protocol, and have their own Kyoto targets of between 6% and 8%. Cyprus and Malta are 

treated as developing countries in the Kyoto Protocol and so do not have emission targets. 

The EU's 8% target only refers to the previous 15 Member States, and this did not change 

after enlargement. The EU is at the forefront of international efforts to combat climate 

change; and played a key role in the development of the two major treaties addressing the 

issue – the United Nations Framework Convention on Climate Change (UNFCCC), and the 

resulting Kyoto Protocol. 

The Kyoto Protocol envisages three market-based "flexible mechanisms": International 

Emissions Trading, Joint Implementation (JI), and the Clean Development Mechanism 

(CDM). These are to allow industrialized countries to meet their targets through trading 

emission allowances between themselves and by gaining credits for emission-curbing 

projects abroad. 

Joint Implementation refers to projects in countries that also have emission targets, and the 

Clean Development Mechanism refers to projects in developing countries with no targets. 

The rationale behind these three mechanisms is that greenhouse gas emissions are a global 

problem and that the place where reductions are achieved is of less importance. In this way, 

reductions can be made where costs are lowest, at least in the initial phase of combating 

climate change. Detailed rules and supervisory structures have been set up to ensure that 

these mechanisms are not abused. 

7.4.5 International Emissions Trading 

The Kyoto Protocol sets a limit on total emissions by the world's major economies, the Annex 

I countries. These industrialized countries have emissions targets they must meet. The 

Protocol allows countries that have spare emissions units (emissions permitted, but not 

"used") to sell this excess capacity to countries that have exceeded their targets. Countries 

not meeting their commitments will be able to "buy" compliance. The limits on GHG 




emissions set by the Kyoto Protocol are a method of assigning commercially tradable value 

to the earth's shared atmosphere. 

7.4.6 Joint Implementation and the Clean Development Mechanism 

Under the Kyoto Protocol, Joint Implementation (JI) and Clean Development Mechanism 

(CDM) will allow industrialized countries to achieve part of their emission reduction 

commitments by conducting emission-reducing projects abroad and counting the reductions 

achieved toward their own commitments. A condition for the issue of credits in respect of the 

reductions achieved is that the projects result in real, measurable, and long-term climate 

change benefits. 

Under Joint Implementation, industrialized countries (Annex I countries) may implement a 

project that reduces emissions (e.g., an energy efficiency scheme) in the territory of another 

Annex I country, and count the resulting Emission Reduction Units (ERUs) against its own 

target. 

Under the Clean Development Mechanism, Annex I countries may implement projects in 

developing countries (non-Annex I countries) that reduce emissions and use the resulting 

Certified Emission Reductions (CERs) to help meet their own targets. The CDM also aims to 

help non-Annex I countries achieve sustainable development and contribute to the ultimate 

objective of the Convention. 

7.4.7 General Fundamentals for JI Projects 

The project cycle for a JI project commences with the idea of developing the project as a JI 

project and with a first rough assessment of the amount of GHG emission reductions that the 

proposed project could generate. If the first screening of the GHG emission reductions of the 

project is positive, the next step is a feasibility assessment. During this stage, the project 

proponent will establish contact with the national Designated Focal Point for JI or if this has 

not been appointed, the Ministry with responsibility for JI, and discuss the idea of developing 

the proposed project as a JI project. This includes an assessment of the applicable and 

relevant international and national regulations and policies. 

7.4.7.1 Project Identification 

A project developer identifies a project that is located in an Annex I country; and a Project 

Idea Note (PIN) is completed. The project developer approaches the relevant JI Focal Point 

and/or promotion agency from both the investor and host counties to confirm eligibility to take 




part in JI and to request support for the project. At this point, it is suggested that a request is 

made to the relevant agency of the host government for a Letter of Endorsement (LoE) for 

the project. Although this is not a requirement, buyers often require a LoE from the host 

country authorities before they will consider entering into contractual negotiations. 

7.4.7.2 Project Design and Assessment 

The project cycle for Second Track JI projects can analytically be split into two phases. The 

first one is the Project Design Phase, which refers to all activities prior to the construction or 

start of any of the project activities. The second phase is the Project Operation Phase, which 

refers to the phase during which the project starts operations. The latter is the point in time 

from which emission reductions can be generated. 

The main task of the project developer during the project design phase is to prepare all the 

required documentation for developing a JI project, which is also referred to as the Project 

Design Document (PDD). The next step will be to hire an Independent Entity for the 

determination of the proposed JI project. Once the project is operational, the main task of 

the project proponent is to monitor project performance and to report the results to an 

Independent Entity. The Independent Entity is responsible for: 

making the PDD publicly available, 

determining whether the PDD meets JI requirements, and 

summarizing stakeholder comments and taking into account stakeholder comments. 

The Independent Entity is then responsible for making the determination report, the 

stakeholder comment summary, and the report on how the stakeholder comments were 

taken into account, publicly available. 

Project Design Phase: 

Project Formulation and Design. Full project documentation needs to be prepared, 

including a Project Design Document (PDD). The PDD contains a description of the 

project; the basis for determining the emissions that would occur without the project (the 

baseline), hence identifying the additionality case; and plans for monitoring the 

reductions. JI Second Track projects may follow the same process as CDM projects 

with regard to methodologies to assess the additionality and baseline. Furthermore 

documentation on analysis of environmental impacts of the project activity must be 

provided, and if necessary, an environmental impact assessment undertaken in 

accordance with procedures as required by the host Country. 




National Approval. Approval is confirmed through the host country issuing a Letter of 

Approval (LoA). This confirms the country’s approval for the transfer of carbon credits 

called Emission Reduction Units (ERUs). A LoA will need to be issued by the investor 

nation government to authorize the project as a JI project. 

Determination. The PDD, in particular the approach to baseline setting and the 

calculations, needs to be submitted to a third party, termed an Accredited Independent 

Entity (AIE), for determination. The Accredited Independent Entity makes the PDD 

publicly available through the Secretariat for 30 days, and receives comments. Based 

on the comments provided by the stakeholders, the Accredited Independent Entity will 

determine whether the project is eligible under JI. 

Project Operations Phase: 

Implementation. The project is implemented in the host country according to the 

specifications outlined in the PDD. 

Monitoring. The project developer monitors the project to identify the emission 

reductions. Based on the monitoring results, the GHG emission reductions resulting 

from the JI project activity can be calculated. Monitoring reports are issued to the AIE. 

Ex-post determination. Project developer submits the monitoring results to Accredited 

Independent Entity. The project developer has to contract an Accredited Independent 

Entity for ex-post determination of the monitoring results and the subsequent Emission 

Reductions Units as a result of the operation of the JI project. 

Possible review by the JI Supervisory Committee. Once the Accredited Independent 

Entity has submitted the verification report to the JI Supervisory Committee (JISC), 

there is a possibility that a review of the determination report by JISC may be 

requested. This can only happen when a Party or three members of the JISC request 

such review. In case there is a request for review of the verification report, the following 

will occur: 

• The JISC will decide at its next meeting or within 30 days of the request being 

made, whether a request has merit and whether to proceed with the review. 

• If a review is deemed necessary, the JISC will review the decision of the 

Independent Entity. 

• JISC informs the project proponent of the outcome of the review and makes it 

decision and reasoning publicly available. 




Issuance of ERUs. For JI projects, ERUs will be issued by the host country. Under the 

present rules of the JI mechanism, emission reductions can be claimed only for the first 

commitment period 2008-2012. 

7.4.8 Implications for Ukraine 

Ukraine is an Annex I party to the Kyoto Protocol, and projects have the potential to earn 

ERUs (carbon credits) under the JI mechanism. There is an approved procedure by the 

Government of Ukraine as indicated in the resolutions for Consideration, Approval, and 

Implementation of Projects aimed at Anthropogenic Emissions reduction or Greenhouse Gas 

Absorption Increase pursuant to the Kyoto Protocol to the United Nations Framework 

Convention on Climate Change (995_001). The key resolutions applicable to the proposed 

project are the following; 

Order № 341 dated 17 th of July 2006 by the Ministry of Environmental Protection of 

Ukraine, and 

Order № 342 dated 17 th of July 2006 by the Ministry of Environmental Protection of 

Ukraine. 

The Government of Ukraine demonstrates a significant experience in the handling of JI 

projects considering the short period of existence of the JI process in Europe, and has 

received a rating of B- by Point Carbon, a carbon markets consultancy, based on a relative 

scale of CDM and JI countries for CDM/JI project participants. Ukraine has already filed a 

PDD with a similar project for another coal mine located in the same region of Donetsk– the 

Zasyadko Mine. 

There are several JI projects underway in Ukraine. As a producer of carbon credits, Ukraine 

accounted for 21% of the ERU supply traded through 2003-2006; closely followed by Russia 

and Bulgaria, which account for 19% and 18% of volumes supplied, respectively (Carpoor 

and Ambrosi, 2007). Ukraine is second only to Russia in terms of the number of expected 

ERUs in the JI pipeline to be delivered over 2008-2012. 




7.5 Validation/Determination and Verification Methodology 

Joint Implementation projects can be validated and verified using an existing methodology 

approved for CDM projects. These methodologies cover a wide variety of sectors from 

renewable energy and energy efficiency, to animal waste and biofuels. The methodology 

that is most relevant to the Project is ACM0008, which is presented below along with the 

general applicability criteria, as found in the appropriate UNFCCC methodology 

documentation. 

7.5.1 ACM0008 Methodology 

“Consolidated baseline methodology for coal bed methane and coal mine methane capture 

and use for power (electrical or motive) and heat and/or destruction by flaring.” This 

methodology applies to project activities that involve the use of any of the following extraction 

activities: 

Surface drainage wells to capture CBM associated with mining activities; 

Underground boreholes in the mine to capture pre mining CMM; 

Surface goaf (gob) wells, underground boreholes, gas drainage galleries or other goaf 

(gob) gas capture techniques, including gas from sealed areas, to capture post mining 

CMM; and 

Ventilation CMM that would normally be vented. 

This methodology applies to CMM capture, utilization, and destruction project activities at a 

working coal mine, where the baseline is the partial or total atmospheric release of the 

methane and the project activities include the following method to treat the gas captured: 

The methane is captured and destroyed through flaring; and/or 

The methane is captured and destroyed through utilization to produce electricity, motive 

power, and/or thermal energy; emission reductions may or may not be claimed for 

displacing or avoiding energy from other sources; 

The remaining share of the methane, to be diluted for safety reasons, may still be 

vented; and/or 

All the CBM or CMM captured by the project should either be used or destroyed, and 

cannot be vented. 




The methodology applies to both new and existing mining activities. The methodology does 

not apply to project activities with any of the following features: 

Operate in open cast mines; 

Capture methane from abandoned/decommissioned coalmines; 

Capture/use of virgin coal-bed methane, e.g. methane of high quality extracted from 

coal seams independently of any mining activities; or 

Use CO2 or any other fluid/gas to enhance CBM drainage before mining takes place. 

7.6 Consideration of Prices of Carbon Credit Units 

The Project Developer must decide when and how to sell the projected ERUs from the 

proposed project. There are various terms and conditions that may be considered in 

Emission Reductions Purchase Agreements (ERPA), which address the pricing of current 

issuances of ERUs, as well as the forward pricing for “to be delivered” ERUs. These 

modalities include negotiated fixed prices, and the use of sophisticated indexed prices based 

on certain events related to the actual production of the carbon credit and the quality that can 

be demonstrated to continue to maintain a certain level of ERUs from the project. 

Generally, ERUs have been discounted compared to Certified Emission Reductions (CERs) 

due to sovereign risks associated with rules and procedures for project approval by host 

country governments, which are necessary but are yet to be enacted; and many JI 

transactions have been structured with up-front financing of up to 25% of the ERPA value. 

Like any other commodity, there are many factors to be considered for assessing market 

prices for Carbon Credits; with policy and regulatory issues, and market fundamentals 

playing key roles. Therefore, to analyze and forecast market and price developments, one 

must have an understanding of the role and potential impact of policy choices. This means 

that Carbon Market participants need to monitor and assess relevant issues, such as the 

National Allocation Plans (NAPs), and the future status of the Kyoto Protocol. 

There are several prediction models for future carbon units that are proprietary to various 

international banks and traders, such as JP Morgan, World Bank, Societé Generale, and 

others. Estimating the value of future revenue streams from Carbon Credits will undoubtedly 

be an important step in evaluating alternative project development scenarios. 

While predicting the future of the Carbon Market is outside the scope of the present study, 

the information inferred from these predictive models, as well as reputable resources should 

be taken into consideration when making future project-related decisions. At this stage in the 




project development scheme it is perhaps most appropriate to look at current market prices 

as a benchmark for what the project might generate from ERU sales. 

The World Bank reports the ranges of prices for carbon commodities for 2005 and 2006 

(Exhibit 7.3), differentiated by types of carbon credits currently offered in the emerging global 

carbon markets: pre-CERs (i.e., credits verified but not issued); CERs (i.e., credits issued); 

Emission Reduction Units (ERUs, from Joint Implementation projects); and secondary CERs 

(i.e., transactions where the seller is not the original owner or issuer of the credits). While 

prices for all carbon commodities have increased year-over-year, so, too, is the volatility of 

the Carbon Market. In 2006, the weighted average price for ERUs was $8.70, which is a 

45% increase over 2005 levels. 

Exhibit 7.3: Observed Prices for Project-based Transactions in 2005 & 2006 

(Carpoor and Ambrosi, 2007) 

Based on interviews with companies who specialize in the trading of carbon credits on the 

relevant European markets, the pricing for ERUs can be estimated in relation to the 

European Emission Trading Scheme (EU ETS) and the reputable market quotes for prices of 

an ERU-type of carbon credit, known as a EUA. The trading companies indicate that the 

range of ERU pricing will be approximately €8 to €12 below the market EUA prices. 




One such daily quotation, the Point Carbon “EUA OTC Assessment” tracks forward 

deliveries of EUR/t (European Union Reduction per ton), and is considered a reliable index 

on which to base pricing for ERUs produced in Ukraine under appropriate Joint 

Implementation projects. 

According to the Point Carbon EUA OTC Assessment for December 2008 deliveries, the 

EUR/t price is approximately €25.00; and, thus, an ERU price based on the relationship to 

the EUA index, would be in the range of approximately €13 to €17 per ERU. 

For purposes of this analysis, additional reduction was made to the indexed price for ERUs, 

to allow for fees to be paid to market traders for negotiation of transactions with end 

users/purchasers of the ERUs. A price of €10 (approximately $15) was used to calculate the 

potential revenue from the sale of ERU s from the proposed project. 

Depending on the structure of the Emissions Reduction Purchase Agreement (ERPA) the 

actual price received by the Project Developer might vary substantially; and the Project 

Developers can expect to obtain purchase agreements for their ERUs ranging anywhere 

between $15 and $25 depending on the level of risk that needs to be taken by the buyer. 

The range in prices can be attributed to competition for large-scale JI projects. 

To make rational selling decisions for production of the Project ERUs, the Project Developers 

and their due–diligence team should continue to gather more information from entities like 

the World Bank and other key institutions, and more importantly, from large emitters and 

others, including carbon market trading companies. 

7.7 Project Risk Reduction Support 

Certain U.S. institutions offer assistance to reduce the risks that domestic companies may 

face when exporting their products or services abroad. For example, in addition to structured 

trade finance mechanisms, the Export Import Bank of the United States (Eximbank) can 

provide working capital guarantees and credit insurance. It also offers certain specialty 

financial products to companies that export environmental goods to foreign companies that 

are unable to obtain traditional financial support. Similarly, the Overseas Private Investment 

Corporation (OPIC) helps U.S. businesses mitigate risks inherent in doing business 

overseas. As highlighted previously, OPIC provides a range of finance resources, such as 

loans and loan guarantees. In addition, it offers financial products specifically designed to 

reduce export risk, such as Political Risk Insurance in emerging markets where political 

drivers are developing or uncertain. 




7.8 Examples of Integrated Project Financing 

A varied selection of finance and revenue sources are available to CMM/CBM project 

developers in developing countries and countries of transition. Through engagement of 

different sources at appropriate stages, funding can be secured for all phases of the project 

development cycle, from pre-feasibility studies to technical specification development to 

pilot/demonstration activities and full to implementation. International financial organizations, 

such as those named above, can contribute to the project development process in several 

ways: some financing sources may provide risk-reduction products to mitigate a technology 

or a service provider's concerns about entering foreign markets; others provide loans and 

similar financial assistance for projects that offer environmental benefits and contribute to 

sustainable development and poverty alleviation; and some specialized funding sources will 

purchase carbon credits and thereby supplement a project's cash flow. 

Thus, by combining equity investment, support-grant funding, and debt financing, all of which 

are available from a variety of sources, project developers can support CMM/CBM recovery 

and utilization projects, even large-scale initiatives, covering every stage of development and 

implementation. 

7.8.1 Sample Project 

The financing strategy for the CMM Project is based on other successfully financed CMM 

projects, using a similar Project Finance structure. For the proposed Ukraine CMM project, 

we outline a financing strategy using a direct loan from OPIC, private equity contributions 

from the Project Sponsors, and carbon finance through the sale of ERUs. The equity/equityfinancing 

from the Project Sponsors will be in the form of direct capital contributions, as well 

as contributions of equipment and services. 

7.8.1.1 Capital Expenditure 

The total costs for the CMM-I Project, which includes significant amounts of equipment and 

services from U.S. companies, is just over US$ 9 million. The U.S. portion will mainly cover 

engineering and technical services, equipment purchases, and technology transfers. 

Of the total costs, approximately US$ 6.5 million (nearly 70%) may be for goods and services 

supplied from U.S. companies. An 8-year loan of 6 million USD will be requested from OPIC, 

representing approximately 65% of the total project costs. The breakdown of the project 

costs, inclusive of the in-country costs, is shown in Exhibit 7.4. 


USES 



Uses Statement (Capitalized Costs in U.S. Dollars) (000s) 

Pre- 

Implementation 

Year 1 Year 2 

Engineering & Design 220 511 0 731 

Construction 0 41 0 41 

Equipment 0 3770 2030 5800 

Development; Acquisition; Operating Rights; 420 120 0 540 

Working Capital / Operating Reserve 0 370 0 370 

Project Contingency Costs 0 167 0 167 

Financing Fees 10 59 0 69 

Set-up Office/Management Systems 6 46 0 52 

Training 0 134 20 154 

ERU-PDD/Validation 5 67 0 72 

Geological-Technical Services 17 0 0 17 

Drilling, Drainage Systems Rehabilitation 0 970 323 1293 

SOURCES 

Project Finance and Carbon Credits 7-21 

Year 

N 

Total 

TOTAL 678 6255 2373 0 9306 

Sources Statement (Project Funding in U.S. Dollars) (000s) 

Pre- 

Implementation 

Year 1 Year 2 Year N Total 

Debt 

OPIC Loan 0 4800 1200 6000 

Equity 3306 

U.S. Cash 208 1365 1133 2706 

U.S. Non-Cash 270 0 0 270 

Non-U.S. Cash 100 50 0 150 

Non-U.S. Non-Cash 100 40 40 180 

TOTAL 678 6255 2373 9306 

Exhibit 7.4 Project Costs– Consolidation of Sources and Uses



7.8.1.2 Project Finance 

Approximately US$ 6 million in senior OPIC debt financing will be placed, by means of a 

direct loan, or loan guarantee, or a combined direct/guaranteed loan. The OPIC financing 

will be used to acquire equipment, components, systems, technology transfers, and services, 

plus the construction, power plant installations, commissioning, and certification. In addition, 

the Project Sponsors will have a combined investment in the Project of US$ 3.3 million. 

All accounting and related fiscal operations associated with the Project will be according to 

International Accounting standards, and management record keeping and reporting will be 

executed using modern systems and accepted best practices. 

7.8.1.3 Example OPIC Loan Terms 

The OPIC-supported loan will most-likely be structured for an 8-year term total term, with a 1year 

grace period. The loan will most-likely propose an interest rate that combines a 

guaranty fee and base interest charge for a total rate of approximately 8.5% (to be fixed at 

the time of commitment), with a principal and interest amortization over a 7-year schedule. 

7.8.1.4 Carbon Finance 

Over the lifetime of the project (35 years), the Project would recover 0.462 Billion cubic 

meters (Bcm) of gas, which would be used to generate electricity. The Project is likely to 

receive a favorable Letter of Approval from the Government of Ukraine; subject to the Project 

Developer filing the proper documentation and validation required by the Joint 

Implementation Supervisory Committee (JISC), utilizing an existing and approved 

methodology. In this case, the most appropriate methodology, which is already approved for 

Clean Development Mechanism (CDM) is the ACM0008, and is directly applicable to Joint 

Implementation (JI) countries such as Ukraine. 

It is estimated that the project will produce approximately 737,476 Emission Reduction Units 

(ERUs) annually; and it can be estimated reasonably that such ERUs may be traded 

between $10 to $15 per unit, depending on the risk-tolerance/risk-reward that the Project 

Sponsor may decide to choose each year from 2008 through 2012, and for the life of the 

project. It is possible, although unlikely, that certain operational risk factors may reduce the 

aggregated monitoring of the gas to below the level indicated above; however, given the 

proven technology and best practices that are planned to be used in the Project, there is a 

high level of confidence that the down time on this operation can be reduced to a minimum. 




The current Kyoto Protocol only permits generation of revenues from the ERUs produced by 

the Project through 2012; however, there are solid arguments and forward-thinking political 

will by the industrialized countries to extend the Kyoto Protocol well beyond 2012. 

Assuming carbon credits at $10.00/ERU – which is consistent with the weighted average 

price received for project-based ERUs in 2006 – over the first 5-year commitment period of 

the Kyoto Protocol about US$7.4 million from methane capture is potentially available to 

enhance project economics. There is considerable variability of observed prices for projectbased 

transactions as discussed earlier in this section. In 2006, the price of ERUs that were 

issued ranged between $6.60 and $12.40 per tonne CO2e. 

7.9 Project Implementation and Management 

The mine degasification and methane utilization project for the Donets’k Region of Ukraine 

was conceived based on utilizing modern and appropriate technology, which is available 

from a variety of sources, especially U.S. manufacturers and suppliers. There are significant 

reasons for choosing equipment, technology transfers, and related services from the United 

States: 

(i) the available ‘state-of-art’ technology; 

(ii) the sensitivity to conditions in Ukraine and the flexibility toward problem solving that 

has been exhibited by the engineers and other professionals from the U.S.; 

(iii) the probability of available major components of second-hand equipment for the 

project; 

(iv) the availability of favorable, U.S. government-supported financing. 

Any Contract of Sale between the equipment suppliers and the Project Sponsor is subject to 

final acceptable terms and conditions and approved financing; and will be based upon 

delivery of new-equipment, plus related technology transfers and services, with the option for 

including suitable used equipment, subject to availability. 

The aggregate value of U.S. equipment, technology transfers, and services for the proposed 

Project is estimated to be approximately US $6.5 million, with a combination of new and used 

equipment and system components, including shipping and related costs. A partial list of 

targeted U.S. suppliers is included in Section 9. 


7.9.1 Management Structure 



The operations for methane recovery/extraction and for gas utilization (heat/electricity 

production) will be managed by Project Sponsor stakeholders, consisting of a team of 

technical experts and senior managers from the Ukrainian and American participants. The 

Project Management Team will be supported by a cadre of professionals, all with particular 

expertise in their fields, most of whom have experience working on similar projects in Ukraine 

or other countries of the region. Exhibit 7.5 and Exhibit 7.6 illustrate proposed organizational 

charts for senior management and production management, respectively. 

At each mine, it is proposed that a full-time Operations Manager and a Senior Engineer be 

responsible for supervising the Crew Leaders, Equipment Operators, Equipment 

Technicians, and related support personnel. 

The Manager and Engineer will be assisted by junior petroleum and process engineers on an 

as-needed basis, particularly as crews prepare the drilling areas and for the installation of 

degasification piping and equipment. 

The Power Generation plant at each mine will be managed by the Plant Supervisor who 

oversees the various production managers, and who will be responsible for coordinating the 

engineers with the equipment operators and mechanics. The general production personnel 

will be under the immediate direction of the shift/crew leaders, with the latter reporting to the 

corresponding production manager. 


Gas Production 

Manager 

Shift Manager 

Emission 

Reduction Units 

Manager 



Project Sponsor 

Managing Director 


Gas Production / Utilization Manager 

Methane Recovery / Heat and Power 

Generating 

Exhibit 7.5: Senior Management Chart 


Technical Supervisor 

Safety Manager 

Facilities 

Manager 

Exhibit 7.6: Production Management Chart 

Chief Financial 

Officer 

Shift Manager 

Heat/Power 

Production 

Manager 


7.10 References 



Carpoor, K. and P. Ambrosi (2007). State and Trends of the Carbon Market 2007. Funded 

by the World Bank Institute – CF Assist, in cooperation with the International Emissions 

Trading Association, May. 


Task 8 



Developmental Impact 

Developmental Impact 8-i




8.1 Introduction........................................................................................................8-1 

8.2 Infrastructure Improvements............................................................................8-1 

8.3 Technology Transfer .........................................................................................8-2 

8.4 Productivity Enhancement ...............................................................................8-2 

8.5 Employment Benefits ........................................................................................8-4 

Developmental Impact 8-ii




Exhibit 8.1: Methane downtime versus coal production on a longwall panel 

(Mutmansky and Wang 1998)..............................................................................8-3 

Developmental Impact 8-iii




Coal mine methane and coal bed methane development in the Donetsk region has the 

potential to have a positive impact on many aspects of the regional and national economy. 

The most important impact at this time, would be to increase Ukrainian energy security by 

reducing the reliance on imported foreign gas. CBM/CMM investment could also stimulate 

economic activity across a broad range of sectors, increase local and regional government 

tax revenues, generate revenues from carbon credits, lead to improvements in local 

infrastructure and increase direct, and indirect, employment opportunities. 

Potential impacts can be split into three main categories – direct, indirect and induced. 

Direct impacts consist of employment and purchases of goods and services in the region 

resulting directly from: 

CBM drilling and associated activities such as leasing, road and drilling site preparation, 

surface facilities construction and pipeline construction. 

CMM drainage upgrades in mine and at surface, power station construction 

Indirect (inter-industry) impacts consist of goods and services purchased by the firms 

supplying inputs consumed in the direct activity. For example, raw materials bought by the 

companies who produce drill pipe, vehicles purchased by surveying crews or legal services 

retained by leasing companies. Induced impacts consist of household purchases of goods 

and services in the region by employees of the direct and indirect employers. 

8.2 Infrastructure Improvements 

Construction of new access roads to well sites, with associated upgrading of existing 

roadways, has the potential to improve communications in the mainly rural areas of the 

Project. In addition, the Project creates indirect benefits, derived from increased tax 

revenues, which enhance local government budgets, and thus, the means to improve the 

conditions of local transportation systems and other municipal infrastructure. 

Electricity generation from the proposed CMM projects at the South Donbass No.3 and 

Bazhanov mines, could, in the future lead to sales into the local grid and subsequent 

upgrading of the electrical power transmission lines. 

Developmental Impact 8-1

8.3 Technology Transfer 



Prior efforts by the U.S. EPA’s Coal Mine Methane Outreach Program, the World Bank 

Global Environmental Fund, and others, to introduce new technology to the Ukrainian coal 

mining sector to improve methane drainage efficiencies and increase the utilization of the 

captured gas for methane emissions mitigation, produced technical analyses and lead to 

outside investment by parties interested in greenhouse gas credits with limited drilling 

technology transfer. Although some of the private mines in the Ukraine are investing in 

drilling technology directly, the U.S. Department Labor committed to fund a technology 

transfer program in 2005 that involved the introduction of modern underground directional 

drilling technology to provide alternatives for underground gob gas recovery. 

With the over-sight of the Partnership for Energy and Environmental Reform (PEER), in 2006 

an underground longhole drill was built by J.H. Fletcher Company and shipped to the 

Ukraine. Directional drilling training was initiated by the U.S. based directional drilling 

contractor, REI Drilling, Inc. at the Belozerskaya Mine in early 2007. 

Similar in-mine degasification improvements are envisioned for use in the South Donbass 

No.3 and Bazhanov mines to enhance current CMM flow rates. The introduction of new 

drilling technology into the Ukraine will require technical support that can provide hands-on 

assistance if required. With directional drilling, where high value directional instruments are 

used, drilling support should include tool recovery services (fishing). Technical services 

should include directional data interpretation, geologic interpretation, and steering tool 

trouble shooting, as required. 

8.4 Productivity Enhancement 

Enhanced CMM recovery from the South Donbass No.3 and Bazhanov mines through new 

directional drilling techniques or gob gas recovery methods could lead to a number of mine 

productivity enhancements. Pre-drained coal seams would result in lower methane 

concentrations at the coal face and throughout the mines, leading to safer working conditions 

for miners with less chance of “gas outs” or mine explosions. Ukraine has one of the highest 

coal miner death rates in the world (7 per million tones mined 1 ) and since independence in 

1991, approximately 4,700 miners have died, at an average of over 200 a year. 2 

1 www.world-nuclear.org. 2008. Appendix 1 The Hazards of Using Energy. 

2 www.businessukraine.com.ua (Nov 26, 2007) 




Lower methane concentrations at the coal face also mean that savings can be made in the 

ventilation system. The volume of air drawn into the mine to dilute methane could be 

reduced, leading to energy and operating cost savings when running the ventilation fans. Air 

velocities across the coal face would also be lower, reducing dust problems and improving 

miner’s working conditions. It is also possible that as ventilation air volumes decrease, so 

could the size and number of the development entries that transport those volumes, giving 

up-front development cost savings and increasing production reserve sizes. 

When methane levels in the mine go over a specified safety limit, the production process 

must stop. These downtimes can be reduced by lowering coal face methane concentrations, 

through pre-mining methane drainage and gob drainage. Exhibit 8.1 shows an example of 

the correlation between downtime, caused by high methane concentrations at the coal face, 

and its effect on coal production rates. 

Exhibit 8.1: Methane downtime versus coal production on 

a longwall panel (Mutmansky and Wang 3 1998) 

While lowering methane concentrations, pre-mining drainage also lowers the water content 

of the coal, further reducing the downtime of a mine and increasing its productivity. 

3 US EPA. 1999. “White Paper: Guidebook on Coalbed Methane Drainage for Underground Coal Mines” 


8.5 Employment Benefits 



The main source of employment in the Project area is the coal industry. Many of the mines 

in the region have been in operation for over 50 years and are at or near to the end of their 

economic life. The introduction of CBM/CMM and associated industries into the local 

economies would provide a needed diversification of the employment base in the region. 

As well as direct employment in the drilling and operating companies, jobs are created by 

firms involved in: leasing; surveying; road building; site preparation and construction; logging; 

financial services; legal services; vehicle supply; catering, retail and hotels. 

A study by the University of Alabama Center for Business and Economic Research on the 

impact of the CBM industry in the Black Warrior coal fields of the Black Warrior Basin, 

Alabama, estimated that at the height of the drilling boom in 1991, 13,000 people were 

employed, directly and indirectly, in CBM related activities. After drilling activity had peaked, 

6,700 jobs were estimated to be associated with the production of 109 Bcf of coalbed 

methane. A 1991 study by the New Mexico Energy Department estimated additional direct 

employment of 1,000 people in one county, associated with the production of 131 Bcf of 

CBM. 4 

A further study by the Sam Walton College of Business at the University of Arkansas (2006) 

on the economic impact of a new gas play in the Arkoma Basin, Arkansas, estimated that 

over four years, 9,700 (full time equivalent) jobs would be created in 10 counties, with $3.8 

billion direct expenditures from the gas industry and $358 million in state and local taxes 

generated. 

4 U.S. EPA “The Environmental and Economic Benefits of Coalbed Methane Development in the Appalachian 

Region” April 1994

coal mine methane and coalbed methane development in the ...

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