Pre-Feasibility Study for Methane Drainage and Utilization at the
Pootkee Colliery, Damodar Valley
Jharkhand State, Dhanbad District, India
•s-
2
<
W
%
ppcrt^
&
T
Sponsored by:
U.S. Environmental Protection Agency, Washington, DC USA
EPA 430-R-19-013
November 2019
Prepared by:
Advanced Resources International, Inc.
i
-------
Disclaimer
This publication was developed at the request of the United States Environmental Protection Agency
(USEPA), in support of the Global Methane Initiative (GMI). In collaboration with the Coalbed Methane
Outreach Program (CMOP), Advanced Resources International, Inc. (ARI) authored this report based on
information obtained from the coal mine partner, Bharat Coking Coal Limited (BCCL), a subsidiary of the
state-owned Coal India Limited (CIL).
This report was prepared for the USEPA. This analysis uses publicly available information in combination
with information obtained through direct contact with mine personnel, equipment vendors, and project
developers. USEPA does not:
a) make any warranty or representation, expressed or implied, with respect to the accuracy,
completeness, or usefulness of the information contained in this report, or that the use of any
apparatus, method, or process disclosed in this report may not infringe upon privately owned
rights;
b) assume any liability with respect to the use of, or damages resulting from the use of, any
information, apparatus, method, or process disclosed in this report; nor
c) imply endorsement of any technology supplier, product, or process mentioned in this report.
ii
-------
Contents
Disclaimer ii
List of Exhibits iv
Acronyms/Abbreviations v
Executive Summary 1
1. Introduction 3
2. Background 4
2.1 The Indian Coal Industry 4
2.2 Coal Mine Methane in India 6
2.3 Bharat Coking Coal Limited 7
3. Mine Characteristics 8
3.1 Geographic Location 8
3.2 Geologic Location 8
3.3 Topographic and Climatic Characteristics 10
3.4 Transportation and Infrastructure Connectivity 10
3.5 Prognosticated Coal and Gas Reserves 11
4. Gas Resources 13
4.1 Overview of Gas Resources 13
4.2 Proposed Gas Drainage Approach 13
4.3 Estimating Production from In-Mine Horizontal Pre-Drainage Boreholes 13
4.3.1 Simulation Model for Gas Production 14
4.3.2 Model Preparation and Runs 15
4.3.3 Simulation Results 18
5. Market Information 19
6. Opportunities for Gas Use 22
7. Economic Analysis 23
7.1 Economic Assessment Methodology 23
7.2 Project Development Scenario 23
7.3 Mine Methane Drainage Production Forecast 26
7.4 Economic Assumptions 26
7.4.1 Physical and Financial Factors 28
7.4.2 Capital Expenditures 28
7.4.3 Operating Expenses 29
7.4.4 Economic Results 30
8. Recommendations and Next Steps 30
References 32
iii
-------
List of Exhibits
Exhibit 1: Summary of Simulation Results and Borehole Production Rates 2
Exhibit 2: Summary of Economic Results (pre-tax) 3
Exhibit 3: Coal Production in India 6
Exhibit 4: Gassy Mine Classification System of India 6
Exhibit 5: Jharia Coalfield. Pootkee Bulliary is shaded in orange and outlined in green 8
Exhibit 6: Generalized stratigraphic sequence of Jharia Coalfield adapted from that created by CMPDIL .9
Exhibit 7: Geologic Log Section of the Pootkee-Bulliary CMM Block, Jharia Coalfield 11
Exhibit 8: Seam-wise Prognosticated CBM Resource of the Considered Coal Seams, Pootkee-Bulliary
CMM Block, Jharia Coalfield 12
Exhibit 9: Example Model Layout for In-Seam Horizontal Pre-Drainage Borehole 14
Exhibit 10: Reservoir Parameters for Horizontal Pre-Drainage Borehole Simulation 15
Exhibit 11: Methane Isotherm Used in Horizontal Pre-Drainage Borehole Simulation 16
Exhibit 12: Relative Permeability Curve Used in Simulation 17
Exhibit 13: Results of Gas Content Reduction Versus Borehole Spacing Analysis in Seam XII 19
Exhibit 14: Drainage Time and Average Methane Flow Rates Versus Borehole Spacing in Seam XII 19
Exhibit 15: Jadishpur-Haldia & Bokaro-Dhamra Pipeline Project in Relation to the Pootkee Colliery.
Source: (PNGRB, 2018) 21
Exhibit 16: Conceptual Mine Layout and Development Plan for Seam XII at Pootkee Colliery 24
Exhibit 17: Pre-Mining Directional Drilling Schedule and Gathering Pipeline Laid for Seam XII 25
Exhibit 18: Methane Production Forecast for the Proposed Methane Drainage Plan for Seam XII 26
Exhibit 19: Summary of Economic Input Parameters and Assumptions 27
Exhibit 20: Summary of Economic Results (pre-tax) 30
iv
-------
Acronyms/Abbreviations
ARI Advanced Resources International, Inc.
BCCL Bharat Coking Coal Limited
Bcf Billion cubic feet
Bern Billion cubic meters
Btu/cf British thermal unit per cubic foot
CBM Coal Bed Methane
CIL Coal India, Limited
CIMFR The Central Institute of Mining and Fuel Research
CMM Coal Mine Methane
CMPDIL Central Mine Planning and Design Institute, Limited
CMOP US EPA Coalbed Methane Outreach Program
DAF Dissolved Air Flotation
DGH Directorate General of Hydrocarbons
EOGEPL Essar Oil & Gas Exploration & Production Ltd
FEED Front End Engineering and Design
FID Final Investment Decision
GAIL Gas Authority of India, Limited
GMI Global Methane Initiative
IRR Internal Rate of Return
JHBDGP Jagdishpur-Haldia and Bokaro-Dhamra Gas Pipeline
LPG Liquified Petroleum Gas
Mm3 Million Cubic Meters
Mt Million tonnes
MMcfd Million cubic feet per day
NPV Net Present Value
ONGC Oil and Natural Gas Corp.
PB Pootkee-Bulliary
PC Pootkee Colliery
PFS Pre-Feasibility Study
USEPA US Environmental Protection Agency
Tcf Trillion cubic feet
v
-------
Executive Summary
Methane is both the primary constituent of natural gas and a potent greenhouse gas (GHG) when
released to the atmosphere. Reducing emissions can yield substantial economic and environmental
benefits, and the implementation of available, cost-effective methane emission reduction opportunities
in the coal industry can lead to improved mine safety, greater mine productivity, and increased
revenues.
The U.S. Environmental Protection Agency's (USEPA) Coalbed Methane Outreach Program (CMOP)
works with coal mines in the United States to encourage the economic use of coal mine methane (CMM)
gas that is otherwise vented to the atmosphere. The work of USEPA also directly supports the goals and
objectives of the Global Methane Initiative (GMI), an international partnership of 45-member countries
and the European Commission that focuses on cost-effective, near-term methane recovery and use as a
clean energy source. These studies identify cost-effective project development opportunities through a
high-level review of gas availability, end-use options, and emission reduction potential. This study assists
mine operators in evaluating options for CMM capture and use while also presenting a preliminary
financial analysis and laying the foundation for a more detailed feasibility study that will ultimately lead
to CMM project development and GHG emission reductions.
Bharat Coking Coal Limited (BCCL), a subsidiary of the state-owned Coal India Limited (CIL) mining
company, was selected by the USEPA for a pre-feasibility study to determine the viability of a CMM
drainage project at the Pootkee Colliery in the Pootkee-Bulliary CMM block. Advanced Resources
International, Inc. (ARI) was tasked with conducting the pre-feasibility study (PFS) for the proposed
methane pre-drainage and utilization project, which is located in the northeastern section of the Jharia
Coalfield.
The principal objective of this study is to determine the feasibility of a CMM capture and utilization
project at the Pootkee Colliery. Industry experience, the geologic setting of the mine, and surface-level
population density led the research team to conclude that a horizontal drilling strategy would be most
feasible and yield the best results for the mine. The Pre-feasibility Study specifically aims, therefore, to
evaluate the technical and economic viability of utilizing long in-mine horizontal boreholes drilled into
Seam XII to drain methane in advance of mining, and to identify end-use options for the drained
methane. To conduct the study, first, a gas production model was developed to identify the optimal
spacing of boreholes and then an economic model was used to evaluate the options for CMM use.
While several potential options exist for the use of CMM at the Pootkee Colliery, onsite power
generation is the most viable option based on comparable operations and preliminary market data
provided by the mine. Given the small CMM production volume relative to surrounding CBM production
blocks, constructing a pipeline to transport the gas to demand centers would be economically
impractical. While there has been interest in compressed natural gas (CNG) for vehicle fuel, CNG at this
time is not economically feasible as it requires significant capital costs to upgrade gas quality and
compress the gas. Based on gas supply forecasts performed in association with this pre-feasibility study,
the Project could be capable of supporting as much as 2,277,600 kwh of on-site electricity on an annual
basis which is about 20% of the mine's annual consumption of 11,940,360 kwh of electricity.
For the CMM project at Pootkee Colliery, multiple reservoir models were developed to simulate long
directionally drilled in-seam boreholes placed along the longitudinal axis of future longwall panels at
1
-------
various spacings. The intent of this exercise was to determine the drainage time required to achieve the
30 percent residual gas content reduction target as a function of borehole spacing. A total of six single-
layer models were constructed in order to calculate gas production for a longwall panel located within
the project area. The models were designed to simulate production from long directionally drilled
boreholes drilled into virgin areas of Seam XII spaced according to six well spacing cases: 41.7 m, 50 m,
62.5 m, 83.3 m, 125 m, and 250 m. All boreholes are drilled into a coal block with a dip angle of 8
degrees and are assumed to be 800 m in lateral length. The models were each run for five years in order
to simulate gas production rates and in-situ gas content reduction over time for a typical longwall panel
within the study area.
The models predicted borehole gas flow rate and gas content reduction as a function of time for a five-
year period. Exhibit 1 shows results derived from the reservoir simulation models, including the drainage
time required to reduce the residual gas content by 30 percent (in years) and the average gas
production rate for each in-seam borehole configuration during that period (m3/day). The table is
designed to give project developers an idea of the drilling strategy that best fits their needs—for
example, if mine authorities wish to mine a panel as soon as possible, they will use the 41.7m spacing; if,
however, the mine wishes to tap CMM from a panel that they do not intend to mine for several years,
then they can use one of the larger spacing options.
Spacing (m)
Drainage Time
(years)
Gas Content
Reduction (%)
Average
Methane Flow
Rate (m3/day)
41.7
0.5
30
1152
50
0.6
30
1046
62.5
0.9
30
925
83.3
1.4
30
778
125
2.8
30
593
250
5.0
20.75
452
Exhibit 1: Summary of Simulation Results and Borehole Production Rates.
For the purpose of forecasting CMM production at the mine, it is assumed that long, directionally drilled
horizontal boreholes are drilled beginning in mid-2019 with the pre-drainage period extending through
2046. Since no mine development plan was provided by BCCL, a conceptual mine layout and
development plan for Seam XII was created, with a total of 27 panels anticipated to be mined. All data
for this report and the reservoir simulations was provided by CMPDI, the Pootkee Colliery, and Bharat
Coking Coal Corporation. Based on a review of the data, and in consultation with the mine operator, it
was determined that Seam XII would be the focus of the pre-drainage program. The in-seam drilling
program for Seam XII requires a total of 50,400 m of drilling, with a total of 60 horizontal boreholes - all
of which could be drilled from just 27 borehole collars. Using this strategy, the CMM project at the
Pootkee Colliery is anticipated to reduce emissions of methane by more than 188,000 tonnes of carbon
dioxide equivalent (tC02e) over the 27-year life of the project.
Two economic scenarios were evaluated in this study. The two are differentiated by whether the mine
will absorb the operational costs of the drainage system or not. In the first scenario, a "power plant
only" scenario, the cost of the gas drainage system is considered a "sunk cost" and is absorbed by the
mining operation as an operational cost; this is because the drainage system would be installed whether
2
-------
there is a CMM power plant or not. This may be the case if the pre-drainage of methane from the
longwall panels is necessary before mining can be safely performed. It is also important to note that in
the "power plant only" scenario, the cost of gas purchased is not included. It is assumed that the mining
operation will provide the CMM for free to the power plant. Should the mining operation wish to
internalize the price of gas as a revenue and charge a fee, then the power project would need to show a
cost of gas purchased as an operating cost, which would reduce the IRR's.
In the second scenario, the "power plant and drainage system" development scenario, the cost of the
gas drainage system is not absorbed by the mine operation. This may be the case if the drainage system
is considered a part of the larger project as a whole and included in the capital expenditures of the CMM
utilization project. The gas drainage system installation scenario involves in-seam directional drilling of
horizontal pre-drainage boreholes, the installation of gas and water pipelines within the mine workings,
and associated vacuum pumps and compressors which adds to the cost of the project and decreases
returns.
The results of both economic scenarios evaluated in this study are shown in Exhibit 2. The two scenarios
result in the same quantity of gas production, so maximum power plant capacity and net C02e
reductions are the same for both project development scenarios. The IRR and payback periods differ
depending on if the mine absorbs the operational costs of the drainage system or not. The first scenario,
the "power plant only" scenario, yields the highest net present value (NPV) and internal rate of return
(IRR). The discount rate used for all NPV calculations in the results tables is 10 percent.
Development
Scenario
Max Power
Plant Capacity
(kW)
NPV-10
($,000)
IRR (%)
Payback
(years)
Net CO:e
Reductions
(tCO,e)
Power Plant (only)
260
372
18%
6.0
188,374
Power Plant and
Drainage System
260
-4,557
na
Na
188,374
Exhibit 2: Summary of Economic Results (pre-tax)
As a pre-feasibility study, this report is intended to provide an initial assessment of project feasibility.
Further site-specific analyses are required to develop a "bankable" feasibility study acceptable to project
investors, banks, and other sources of finance. However, without performing the further "bankable"
analysis required for a feasibility study, this report's analysis concludes that the most economically
feasible path going forward is to utilize CMM for power production and to have the mine capitalize the
cost of the drainage system as part of the mining operation.
1. Introduction
Methane is both the primary constituent of natural gas and a potent greenhouse gas when released to
the atmosphere. Reducing emissions can yield substantial economic and environmental benefits and the
implementation of available, cost-effective methane emission reduction opportunities in the coal
industry can lead to improved mine safety, greater mine productivity, and increased revenues. The U.S.
Environmental Protection Agency's (USEPA) Coalbed Methane Outreach Program (CMOP) is a domestic
voluntary program that works with coal mines in the U.S. to encourage the economic use of coal mine
methane (CMM) gas that is otherwise vented to the atmosphere. USEPA also directly supports the goals
3
-------
and objectives of the Global Methane Initiative (GMI), an international partnership of 45 member
countries and the European Commission, that focuses on cost-effective, near-term methane recovery
and use as a clean energy source. Under the auspices of GMI, USEPA collaborates internationally to
promote methane mitigation in the coal mine sector.
An integral element of USEPA's international outreach in support of the GMI is the development of
CMM pre-feasibility studies. These studies provide a cost-effective first step to project development and
implementation by identifying project opportunities through a high-level review of gas availability, end-
use options, and emission reduction potential. In recent years, USEPA has sponsored feasibility and pre-
feasibility studies in such countries as China, Colombia, Kazakhstan, Mongolia, Poland, Russia, Turkey
and Ukraine.
Bharat Coking Coal Limited (BCCL), a subsidiary of the state-owned Coal India Limited (CIL) mining
company, was selected by the USEPA for a pre-feasibility study to determine the viability of a CMM
drainage project at the Pootkee Colliery in the Pootkee-Bulliary CMM block. Advanced Resources
International, Inc. (ARI) was tasked with conducting the pre-feasibility study (PFS) for the proposed
methane pre-drainage and utilization project, which is located in the northeastern section of the Jharia
Coalfield.
The Pootkee Colliery is labeled as a Degree II gassy mine, the middle category in the three-tier
classification system for methane emitting mines in India.
BCCL has been mining this block since the nationalization of India's coal mines in 1972 and has
developed seams XVIII, XVII, XVI, XV, XIV, XIII, XII, XI, and XA to varying extents with the room and pillar
method of mining. The maximum depth of the bottom-most seam, II, is projected at 900 meters (m) and
considerable coal reserves remain to be mined, however prognostics of coal seam methane content
indicate the necessity of effective CMM drainage systems to access deeper seams. Seams X, IX, VIIIC,
VIIIB, VINA, VIII, VII, VI, V, IV, III, and II, which have an average cumulative thickness of 55 m, are all being
considered by the mine for CMM development. CIL and BCCL have therefore expressed an interest in
pursuing a methane pre-drainage program to mitigate safety concerns to mine operations and to utilize
CMM captured from the formation.
This PFS is intended to provide an initial assessment of project feasibility. A final investment decision
(FID) should only be determined after completion of a full feasibility study founded on additional data,
detailed cost estimates, thorough site investigations, well tests, and a possible Front-End Engineering
Design (FEED).
2. Background
2.1 The Indian Coal Industry
India is the third largest coal market in the world, where coal represented 56.2 percent of the country's
total primary energy consumption in 2017 (BP, 2018). In 2016, 62 percent of India's installed power
capacity was dependent on coal and 61.8 percent of the country's coal consumption went toward power
production, making coal the largest component of India's energy sector (MOSPI, 2018; EIA, 2016). Coal
demand in India averaged a growth rate of 6.3 percent per year over the past decade, while coal
production has fallen behind with an average 3.5 percent growth rate over the same period, leading to a
significant reliance on coal imports (BP, 2018; USEPA, 2015). However, recent regulatory reforms have
4
-------
been enacted to increase domestic coal production to reduce imports and promote national energy
security (EIA, 2016).
In 2017, as part of India's 3-Year-Action Plan (2017-2020), the country announced aggressive coal
production targets that included exploring 25 percent of its 5,100 square kilometers (km2) of untapped
coal reserves, proving the definitive existence of indicated coal reserves, constructing three critical
transportation railroads, and increasing the production of its state-owned coal producers (NITI, 2017).
Additional thought was given to spinning off state-owned CIL subsidiaries in the hope of creating
competition between state corporations, but no action has yet to be taken on this front.
India's 3-Year-Action Plan outlined that CIL, the world's largest coal producing company, was expected
to produce 1 billion tonnes (1 gigatonne, Gt) of coal annually by 2019-2020, nearly double its output
from 2015-2016. However, CIL fell well short of its original production goals in 2017-2018 due to
transportation logistics issues, inflating stockpiles and decreasing power plant coal supplies (Singh,
2018). CIL has since updated its 1 Gt production target date to 2022 and has pledged to continue
updating its mines and transportation infrastructure, but immediate power infrastructure demands
coupled with continuing coal production shortages caused India's coal imports to increase 14 percent in
2017-2018 (PTI, 2018a; Sen, 2018). The immediate future of India's coal production capabilities
therefore hinges on the ability of producers to transport coal from mines to consumers.
At the end of 2017, India's total proved reserves of coal were 97,728 Mt (ranked fifth globally), with 95
percent being anthracite or bituminous coal, and the remaining 5 percent being sub-bituminous or
lignite (BP, 2018). The majority of India's coal reserves are located in the eastern half of the country,
ranging from Andhra Pradesh, bordering the Indian Ocean, to Arunachal Pradesh in the extreme
northeast of the country (USEPA, 2015).
In 2017, India ranked second only to China in global coal production with 716 Mt of coal produced (BP,
2018). Between 1981 and 2017, India's coal production capacity increased by 586 Mt (Exhibit 3). The
country's largest coal producer, CIL, is responsible for producing over 80 percent of India's coal, with
Singareni Collieries Company Limited (SCCL) responsible for another 10 percent of production (EIA,
2016). The remaining 10 percent of coal production is met by captive producers, which represent private
industries mining coal for their own use. For decades, the Indian government portioned out coal
production blocks to private companies for their own consumption, however, in 2014 India voided these
contracts and planned to re-auction them for sale. The goal of the reform was to create a more
transparent, competitive bidding system for coal production rights, which the government hoped would
attract private investment in the coal sector and support domestic coal production (EIA, 2016). This
bidding process has continued into 2019, although response among investors was more tepid than
originally forecasted (Das, 2018). Reasons for this lack of interest range from perceived government
over-exaggeration of block values to the improving economics of renewable energy deployment in the
country.
5
-------
India Coal Production, 1981-2017
800.0
700.0
600.0
(/>
-------
company to accelerate CMM/CBM exploration with a goal of ramping up its output to a minimum of 177
million cubic feet per day (MMcfd) (5 Mm /d) of natural gas from current levels of less than 35 MMcfd (1
Mm /d) (Saikia, 2015).
According to India's Directorate General of Hydrocarbons (DGH), a large portion of the country's
prospective CBM resources have yet to be explored. In fact, exploration has only been initiated in about
half of the 26,000 km2 of potential CBM-producing areas (Saikia, 2015). CIL holds 20 percent of India's
estimated 315 Gt of coal resources, and the company has coal mines in eight states, which are
estimated to hold between 3.5 to 4 trillion cubic feet (Tcf) of CBM reserves. Furthermore, much of CIL's
acreage is gaseous and considered safe to mine only after pre-drainage of methane. Extracting
CBM/CMM before the mining of coal seams would grant CIL access to significant quantities of coal
reserves in areas of Jharkhand and West Bengal (PTI, 2013). With 81 percent of the country's
prospective CBM areas overlapping coal mining areas held by CIL, the continuing relaxation of
government regulations hampering CMM capture and utilization development could help CIL unlock up
to 100 Mt of medium grade coking coal and 1 Tcf of gas (PTI, 2013).
While recent policy changes appear favorable for state-owned CIL, the Ministry of Petroleum & Natural
Gas (MOP&NG) recently clarified that existing private operators already undertaking CBM exploration
and production projects at coal blocks allocated to them by the government would have to pursue new
licenses from the government under the Hydrocarbon Exploration and Licensing Policy (HELP). The
newly unveiled HELP calls for a composite uniform license for exploration and production of all forms of
hydrocarbons from a single asset block, hampering private companies in the short term but giving them
more freedom in developing hydrocarbon resources after getting licensed (Das, 2016). However, a
recent decision by CIL to potentially open its coal fields for CBM extraction by global, third-party
companies may facilitate the ability of private companies to execute CBM projects under the aegis of
CIL's permit without having to apply for one of their own (Sengupta, 2018).
2.3 Bharat Coking Coal Limited
Bharat Coking Coal Limited (BCCL) is a subsidiary of Coal India Limited (CIL), a state-owned coal mining
company. CIL is the largest coal producer in the world, operating in 81 mining lease areas spread across
eight provincial states, through seven wholly owned mining subsidiaries and one mine planning and
consulting company. CIL produces 84 percent of India's total coal, which accounts for 40 percent of
India's total commercial energy requirements and 76 percent of its total utilities thermal power
generating capacity (CIL, 2018). Its subsidiary, BCCL supplies 50 percent of the total prime coking coal
requirements of India's steel sector (BCCL, 2009).
BCCL is situated in the states of West Bengal and Jharkhand, with operations in the Raniganj and Jharia
Coalfields. BCCL currently holds an approximate mining lease area of 218 km2 and operates 44 mines, of
which 10 are underground, 20 are opencast, and 14 are mixed. As of 2009, BCCL reported owning a total
estimated coal reserve of 17.5 Gt and the company produced an average of 31.6 Mt annually between
2009 and 2018 (BCCL, 2009; BCCL, 2018).
7
-------
3. Mine Characteristics
3.1 Geographic Location
The Pootkee Bulliary CMM block covers an area of approximately 16 km2 and is located in the east-
central part of the Jharia Coalfield in the Damodar Valley of Jharkhand State (Exhibit 5). Mining of the
Jharia Coalfield began in the 1890's when the East India Railway extended service to the region, making
it possible to transport the coal to market—the field has since been recognized as India's largest coal
reserve and the primary source of the country's coking coal supply (IBM, 2018). The Jharia Basin extends
over 453 km2 between latitudes 23°37'N and 23°52'N and longitudes 86°06'E and 86°30'E - within this
space, the Pootkee Bulliary block exists between latitudes 23°43'17"N and 24°46'32"N and longitudes
86°20'12"E and 86°23'15"E.
MAP OF JHARIA COALFIELD
+ +
+ +++ + ±4
JHARIA^NGC-CIL)
Exhibit 5: Jharia Coalfield. Pootkee Bulliary is shaded in orange and outlined in green.
3.2 Geologic Location
The Jharia Coalfield is a sickle-shaped outlier of the Gondwana group of Permo-Carboniferous sediments
with a broad east-west major axis that plunges westward. The southern edge of the Jharia Basin is
delineated by a major fault known as the Main Boundary Fault—a large part of the basin's original
southern limb is therefore missing. Instead, south of the Main Boundary Fault are younger Permo-
Carboniferous sedimentary formations juxtaposed against Archaean metamorphic bedrock. The fault
gives the basin a half graben structure.
8
-------
The northwestern, northern, and northeastern edges of the basin are fringed by well-exposed portions
of the non-coal bearing Talchir Formation. The Barakar Formation overlays the Talchir and is well
exposed in the northern, northeastern, and southeastern regions of the basin; the Barakar contains over
40 coal seams and is the formation responsible for producing the prime coking grade coal that drew
mining interest to the region over a century ago. Atop the Barakar Formation rests the Barren Measures,
whose exposures mainly occur in the central part of the basin. This, in turn, is overlain by the coal
bearing Raniganj Formation in the southwestern corner of the basin. This sedimentary profile can be
seen in Exhibit 6.
Age
Formation
Thickness
Lit ho logy
Recent/Sub-Recent
Recent/Sub-recent
<30m
Alluvium/sandy soil, sandy
clay, gravel etc.
AA A A AAA A AAA A AAA A AAA A AAA A AAA A AAA A A A AAA A AAA A AAA A AAA A AAA A AAA A AAA A AAA A A
Tertiary
Block tectonics forming
southern boundary and other
faults
Tectonic Activities
Paleocene
Cross-folding along E-W axis;
later folding along NNE-SSW axis
from intrusion of dolerite dyke
Dolerite Dykes
Lower Cretaceous
Early folding along NW-SE axis
forming zone of depression near
Mohuda; intrusion of mica-
periodites
Mica-peridoites
Upper Permian
Raniganj Formation
<725m
Coal bearing formation
containing 24 coal seams,
micaceous sandstone, shale,
and carbonaceous shale
Middle Permian
Barren Measures Formation
375-625m
Massive sandstone traversed
with ferruginous bands
alternating with
carbonaceous shale, gray
shale, and sandstone.
Lower Permian
Barakar Formation
600-1250m
Coarse to fine grained
sandstone interspersed with
shale, carbonaceous shale,
pebbly sandstones, and
conglomerates. 18
correctable coal horizons,
but up to 51 coal seams
including splits and locals
Upper Carboniferous
Talchir Formation
250m
Coarse grained green
sandstone, greenish splintery
shale, and basal boulder beds
AA A A AAA A AAA A AAA A AAA A AAA A AAA A AAA A AAJJpQQp^QpjYjj^yA A A AAA A AAA A AAA A AAA A AAA A AAA A AAA A AAA A A
Archean
Metamorphics
Bedrock
Granite Gneisses and schists
Exhibit 6: Generalized stratigraphic sequence ofJharia Coalfield (adapted from CMPDIL data)
9
-------
The Jharia Basin is widely considered to be the northern-most remnant of a cross-folded synclinal basin,
preserved as a down-thrown block of the southern tectonic boundary fault. The Barakar Formation's
changing regional strike in Jharia Coalfield shows an arc-shaped trend that is responsible for the overall
sickle shape of the coalfield. Dip in the basin tends to be gentle and southerly except near faults where
the dip can steepen drastically. The coalfield is traversed by a number of strike, dip, and oblique slip
normal faults related to the major boundary fault to the south of the basin.
The basin is also traversed by dykes and sills of mica-peridotite and dolerite - the mica-peridotite
igneous intrusions, in places, have metamorphosed coal seams into jhama (a high ash, low volatile coal
with a high fixed carbon) and natural coke. The dolerite intrusions are confined to the western portion
of the basin and have largely left the coal seams unaffected.
The Pootkee Bulliary block, located in the central part of the Jharia Coalfield, is completely covered by
rocks of the Upper Permian Raniganj and Middle Permian Barren Measure Formation that overlay the
Lower Permian Barakar Formation. The Barren Measures is a formation of massive sandstone traversed
by ferruginous bands, grey to dark-grey shale, carbonaceous shale, and clay with ironstone bands. The
Barakar Formation is composed of feldspathic sandstones and carbonaceous shales that are traversed
by coal seams. The formations show a NW-SE strike with a south-west dip of 4° to 12°. Based off
available borehole data and geologic reports, 21 faults are interspersed through the block with throws
between 5 m and 190 m. Post-Gondwana orogeny mica-peridotite dykes and sills do intrude the area
and have affected the seams—XVIII and XIV appear to be completely pyrolitized into jhama, XIII and XII
are affected by intrusions throughout the block, and parts of XI have also been converted to jhama.
3.3 Topographic and Climatic Characteristics
The Pootkee Colliery within the block is situated directly north of the Damodar River at an elevation of
180 m (590 feet, ft) and has a humid, tropical climate. The Sendra-Bansjora ravine and Ekra Jore river
near the western boundary of the block and the Kari ravine near the south-eastern border provide the
main drainage for the block - these features ultimately drain into the Damodar River. Through the
summer months (March through June) the temperature ranges from 18° to 39°C; through the winter
months (November through January) the temperature can drop as low as 11°C at night. Average rainfall
in the area is 114 millimeters (mm) (4.5 inches, in), although, like many parts of northeastern India, the
mine experiences monsoon cycles where the majority of its rain occurs between June and September
(192 mm to 342 mm per month) and the rest of the year remains dry (5 mm to 17 mm per month). The
region is often subjected to a cyclonic storm locally referred to as "Kalbaissakhi" from April through late
May.
3.4 Transportation and Infrastructure Connectivity
The closest point of entry for a visitor to the mine would be the regional Dhanbad Airport, connected
with regular flights from Calcutta and Patna (both of which can be easily reached by international
travelers). From there, one would follow the Dhaiya Main Rd south for 15 kilometers (km) and then take
Moonidih Road for the last 5 km, a drive that takes about 50 minutes. The nearest major airport is the
Birsa Munda Airport in Ranchi, to the southwest of the mine - visitors would then need to drive 3 hours
along the NH-320 before reaching the coalfield.
The region is well connected by road and rail - the Dhanbad-Chas section of the NH-32 road runs 0.5 km
to the north of the mine and fair weather roads crisscross the coalfield. Dhanbad Railway Station on the
10
-------
Grand Chord line of the Eastern Railway is 16 km to the northeast of the mine and connects the field to
numerous major cities. A side rail-line 8 km to the northwest of the colliery connects the field to the
Bhojudih-Chandrapura railway line via Mohuda Railway station.
3.5 Prognosticated Coal and Gas Reserves
Although up to 51 coal seams occur in the Barakar Formation of the block, only 18 are persistent and
able to be correlated with each other (Exhibit 7). BCCL has been mining this block since the
nationalization of India's coal mines in 1972 and has developed seams XVIII, XVII, XVI, XV, XIII, XII, XI, XI,
X, IX, and VII to varying extents with room and pillar mining. The deepest seam, II, is projected to be 900
m deep and the cumulative thickness of the layers targeted for future mining, seams X to II, have an
average cumulative thickness of 55 m. Seams X, IX, VIIIC, VI11B, VII A, VIII (A&B), VII, V, IV, III, and II are all
being considered for CMM development.
SCHEMATIC GEOLOGICAL LOG SECTION
POOTKKD-BULL!ARY CMM BLOCK, JHARIA COALFIELD
FORMATION/
SEAM NAME
LOG
COAL SEAM
THICKNESS
RANGE Cm]
PARTING
RANGE (m)
ALLUVIUM/SOIL
WTRTiaiVES
BARSHN MEASURES
BARAKAR
xvm
XVQA
xvnrop
XVII BOTTOM
XVIA
XVI COMBINED
(Spit* in XVT Top dk Bottom)
XVA
L-S
XIV
xm
xn
XI
XA
X
IX
Lr-3
L-2
vmc
vnm
VDIA^A+B}
vra
L-l
vn
v/vi
IV
m
n
hiniriv&a^
a-iS-5.75
a 10-3.90
a 15-2. S3
0.10-2.75
0.36-0.81
0.10-2. S3
3
OlIO-1.57
(LKMfcT?
ai0-0^48
a 65-12X13
a 88-7.33
&40-M8
0.9Q-&OD
a03-3.S3
0.36-8.70
ais-a.56
a 30-1.75
0.35-2,70
a 10-3.61
OL44-3.70
OS6-7.39
1.38-7.96
a35-l>W
3J21-14JT?
5,99-1537
4.20-21.23
3J55-15.74
1j6S^40
7.63-10.70
J-25
18-41
13-37
1-10
47-64
32-48
2O-60
Ml
25-36
3-11
38-76
1-13
9-35
5-23
9-46
5-30
124
4-27
7-33
2-25
035-16
1-35
5-29
10-31
l-a6
l-3fi
1-2B
23-33
13-26
Exhibit 7: Geologic Log Section of the Pootkee-Bulliary CMM Block; Jharia Coalfield
11
-------
Coal within the virgin seams is estimated at 1,116 Mt and desorption test results of seam samples taken
from the Jharia CMM block, the block to the immediate southwest of the Pootkee-Bulliary CMM block,
found that in-situ methane gas content ranged from 3.5 cubic meters per tonne (m3/t) of coal to 16 m3/t
(Exhibit 8). The coal being mined ranks from low to medium volatile bituminous coal. The minimum
recoverable gas is about 2.12 billion cubic meters (Bern), or 30 percent of the total predicted resource.
Seams
Coal Resource
In million tonnes
(Mt)
Average in-situ gas
content (daf) of the
seam M3/T
Prognosticated CBM
Resource in million
cubic meters (Mm3)
XVI11B
1.97
--
--
XV111A
2.82
--
--
XVIII
1.77
-
--
XVI IT
9.61
--
--
XVI IB
11.65
-
-
XVIT
15.62
-
-
XVICOMB
36.73
--
--
XV
35.4
--
--
XIV
18.52
-
--
XIII
16.71
--
--
XII
33.2
--
--
XI
70.48
--
--
XA
10.18
--
--
X
100.96
5.5
540.1
IX
37.77
5.6
183.4
vine
45.42
6
259.74
VIIIB
33.84
6
180.6
VINA /VIII(A+B)
50.99
6
320.88
VIII
106.86
6
641.22
VII
218.14
6
1299.42
VI
55.55
6
333.3
V and V/VI
257.6
6
1545.6
IV
110.34
6
662.04
III
110.65
6
663.9
II
70.11
6
420.66
Total
1462.89
7050.86
Exhibit 8: Seam-wise Prognosticated CBM Resource of the Considered Coal Seams,
Pootkee-Bulliary CMM Block, Jharia Coalfield
12
-------
4. Gas Resources
4.1 Overview of Gas Resources
India's CMM emissions are estimated to be 2.6 trillion cubic meters (Tcm) (DGH, 2019). As of 2019,
drainage of CMM in India is limited with no active commercial CMM recovery projects in the country.
However, there are two CMM blocks currently being developed by CIL subsidiaries in the Jharia
Coalfield, and initial research is being done on potential project sites in the Bokaro and Sohagpur
Coalfields and in the Moonidih block of Jharia Coalfield (USEPA, 2015; CMPDI-CIL, 2017). As mentioned
previously, recent legislation in 2018 has removed bureaucratic red tape from CIL's path to developing
CMM recovery projects in its coal mines. If CIL's current CMM development projects and the Pootkee
Colliery project are successful, they could be used as templates for CMM projects at future mines in the
region. In terms of India's CBM resources from virgin coal seams, estimates vary depending on coal rank,
burial depth, and geotectonic settings, with the DGH estimating that India's 44 major coal and lignite
fields contain 120 Tcf, or 3.4 Tcm, of CBM resources (USEPA, 2015). Developing a strategy to harness
these vast natural gas resources would therefore be in the government's self-interest for ensuring its
energy security and fulfilling the emissions reductions it promised in the Paris Agreement.
4.2 Proposed Gas Drainage Approach
BCCL's current plans are to deploy equipment to mine the coking quality coal of Seam XII, which is
situated at a depth ranging from 400 to 550 m. As of the preparation of this report (2019), the mining of
other seams is not planned; however, future mining is envisioned as shallower coal resources are
depleted and mining moves to deeper seams. The objectives of this pre-feasibility study are to perform
an initial assessment of the technical and economic viability of methane pre-drainage utilizing long in-
mine horizontal boreholes drilled into Seam XII to drain methane in advance of mining, and to utilize the
drained gas to generate electricity for on-site consumption.
Long, in-mine directionally drilled boreholes that can be installed from main entries, significantly in
advance of gate road developments, and drilled along the longitudinal axis of longwall panels are
recommended. Directional drilling delivers an in-seam drainage solution that reduces the number of
wellheads and potential points of air leakage into the gas drainage system and provides for longer
drainage times to further reduce residual gas contents. The gas production profiles generated for the
horizontal pre-drainage boreholes will form the basis of the economic analyses performed in Section 7
of this report. Additionally, estimating the gas production volume is critical for planning purposes and
the design of production and end-use equipment and facilities.
4.3 Estimating Production from In-Mine Horizontal Pre-Drainage Boreholes
Directionally drilled boreholes should be planned based on the time available before mining takes place
and the desired reduction in gas content prior to mining. For this study, a variety of well spacings were
examined to determine how much time is required to achieve a 30 percent reduction in gas content
prior to the mining of the seam. Multiple reservoir models were developed to simulate various
borehole spacings. Larger spacing is generally less effective compared to more closely spaced boreholes
over a given period of time, because it takes longer for the borehole drainage areas to overlap. All data
used in these models were provided by CMPDIL, the Pootkee Colliery, and BCCL. The following sections
of this report discuss the development of the gas drainage borehole models, the input parameters used
to populate the reservoir simulation models, and the simulation results.
13
-------
4.3.1 Simulation Model for Gas Production
A total of six, single-layer models were constructed in order to calculate gas production for a longwail
panel located within the project area. The models were designed to simulate production from long,
directionally drilled boreholes drilled into virgin areas of Seam XII. The six well spacing cases examined
were: 41.7 m, 50 m, 62.5 m, 83.3 m, 125 m, and 250 m. All boreholes were modeled to bedrilled into a
coal block with a dip angle of 8 degrees and are assumed to be 800 m in lateral length. The models were
each run for five years in order to simulate gas production rates and in-situ gas content reduction over
time for a typical longwail panel within the study area.
A typical longwail panel at the mine is estimated to have a face width of 250 m and a panel length of 800
m covering an aerial extent of 20 hectares (ha). The model grid setup consisted of 65 grid-blocks in the
x-direction, 41 grid-blocks in the y-direction, and one grid-block in the z-direction. Zero-flow boundaries
were created along the flanks of the borehole such that the width of the reservoir model was equal to
the borehole spacing; this was accomplished by adjusting grid block sizes to correspond with each of the
six well spacing cases. Side and top view illustrations of an example model developed to simulate the
800 m long 96 mm diameter directionally drilled boreholes are shown in Exhibit 9.
Side View
Top View
Initial Conditions
After 5 Years
Matrix Methane, scf/cuft
1.7584 2 3424 2.9263 3.5103 4.0942 4.6782 5 2621 5.8461 6.4300
Exhibit 9: Example Model Layout for In-Seam Horizontal
Pre-Drainage Borehole
14
-------
4.3.2 Model Preparation and Runs
The input data used to populate the reservoir models were obtained from the geologic and reservoir
data provided by CMPDI, the Pootkee Colliery, and BCCL. Where appropriate, supplemental geological
and reservoir data from analogous projects, such as data from the neighboring Jharia CBM block, were
also used. The input parameters used in the reservoir simulation study are presented in Exhibit 10,
followed by a brief discussion of the most important reservoir parameters.
Reservoir Simulation Parameters for Pootkee-Bulliary CMM Block
RESERVOIR PARAMETERS
Imperial
Metric
COAL SEAM
XII
XII
PANEL DIMENSIONS
LENGTH
ft
2,625
m
800
FACE
ft
820
m
250
AVERAGE COAL DEPTH
ft
1,558
m
475
DIP ANGLE OF COAL FACE
deg.
8
deg.
8
AVERAGE COAL THICKNESS
ft
10.2
m
3.1
COAL DENSITY
lb/ft3
115.2
gm/cc
1.85
PRESSURE GRADIENT
psi/ft
0.433
kPa/m3
9.80
RELATIVE PERMEABILITY
See curve
See curve
CLEAT POROSITY
%
0.5
%
0.5
CLEAT WATER SATURATION
%
100
%
100
CLEAT PERMEABILITY
md
0.5
md
0.5
INITIAL AVERAGE RESERVOIR PRESSURE
psia
689
kPa
4,753
LANGMUIR COEFFICIENTS
LANGMUIR VOLUME
ft3/ton
370
m3/tonne
11.5
LANGMUIR VOLUME
scf/ft3
21.3
3 / 3
sm /m
21.3
LANGMUIR PRESSURE
psia
270
kPa
1,863
GAS CONTENT
ft3/ton
111
m3/tonne
3.5
DESORPTION PRESSURE
psia
117
kPa
804
SORPTION TIME
days
1.5
days
1.5
CLEAT SPACING
in
2.6
cm
6.5
PORE VOLUME COMPRESSIBILITY
/psi
3.00E-06
/kPa
4.35E-07
MATRIX SHRINKAGE COMPRESSIBILITY
/psi
1.00E-06
/kPa
1.45E-07
BOREHOLE DIAMETER
in
3.8
mm
96
COMPLETION & STIMULATION
skin
+2
skin
+2
WELL OPERATION
psia
6
kPa
41
Exhibit 10: Reservoir Parameters for Horizontal Pre-Drainage Borehole Simulation
4.3.2.1 Permeability
Coal bed permeability, as it applies to production of methane from coal seams, is a result of the natural
cleat (fracture) system of the coal and consists of face cleats and butt cleats. This natural cleat system is
sometimes enhanced by natural fracturing caused by tectonic forces in the basin. The permeability
resulting from the fracture systems in the coal is called "absolute permeability" and is a critical input
parameter for reservoir simulation studies. Absolute permeability data for the coal seams in the study
area were not provided. For the current study, a permeability value of 0.5 millidarcy (md) was assumed
15
-------
based on permeability values used in previous studies performed on the Jharia CBM block (CMPDI-CIL,
2017).
4.3.2.2 Langmuir Volume and Pressure
Laboratory measured Langmuir volumes and pressures for the study area were not available. However,
Langmuir volume and pressure values from methane isotherm analyses conducted on coal samples from
Seam XII in borehole MKP-12 in conjunction with a CBM project in the Jharia block were utilized in the
current study (CMPDI-CIL, 2017). The corresponding Langmuir volume used in the reservoir simulation
models for the project area is 11.5 m3/t and the Langmuir pressure is 1,863 kilopascal (kPa). The
methane isotherm from borehole MKP-12, as reported on a dry, ash-free basis, was converted to an as-
received basis using in-situ ash and moisture contents from the Pootkee-Bulliary block. Exhibit 11
depicts the methane isotherm utilized in the horizontal pre-drainage borehole simulations.
10
9
8
7
VL: 11.5 m3/t
PL: 1,863 kPa
6
5
3.5
4
3
2
1
0
0
1000
2000
3000
4000
Pressure (kPa)
5000
6000
7000
8000
— Isotherm PB, ar • GC PB, ar
Exhibit 11: Methane Isotherm Used in Horizontal Pre-Drainage Borehole Simulation
4.3.2.3 Gas Content
No gas desorption analyses data were available for Seam XII within the study area. Based on the seam-
wise gas content data as compared to the maximum methane storage potential from the Jharia CBM
block isotherm, a gas saturation of 42 percent was calculated at Seam XII reservoir pressure. As a result,
an initial gas content value of 3.5 m3/t was used in the simulation study (Exhibit 11).
4.3.2.4 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 begins and the pressure in the cleat system starts to decline
due to the removal of water, gas is released from the coals into the cleat and natural fracture network.
The introduction of gas into the cleat system results in two-phase fluid flow (gas and water) in the pore
space, and the transport of both fluids must be considered in order to accurately model production. To
16
-------
accomplish this, relative permeability functions are used in conjunction with specific permeability to
determine the effective permeability of each fluid phase.
Relative permeability data for the coal of the project area was not available. Therefore, a relative
permeability data set was used, which is typical for coals of similar age and rank (CMPDI-CIL, 2017.
Exhibit 12 is a graph of the relative permeability curves used in the reservoir simulation of the study
area.
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
DC
/
\
\
>
\ X
KR Water
\x
KR Gas
/ N.
/
/
0.2
0.4
0.6
0.8
Saturation, Water (SW)
Exhibit 12: Relative Permeability Curve Used in Simulation
4.3.2.5 Coal Seam Depth and Thickness
Based on mine data, Seam XII ranges in depth from 400 m to 550 m with the seam averaging 3.1 m in
thickness. For modeling purposes, the depth to the top of the coal reservoir was assumed to be 475 m,
with the seam dipping an average of 8 degrees to the southwest (dip ranges from 4 to 12 degrees
throughout the study area).
4.3.2.6 Reservoir and Desorption Pressure
Initial reservoir pressure was computed using a hydrostatic pressure gradient of 9.8 kPa/m and the
midpoint depth of the coal seam. Because the coal seams are assumed to be undersaturated with
respect to gas, desorption pressure is determined in COMET3® by the point of intersection of the gas
content and isotherm. The resulting desorption pressure calculated by the model is 804 kPa compared
to an initial reservoir pressure of 4,753 kPa.
4.3.2.7 Porosity and Initial Water Saturation
Porosity is a measure of the void spaces in a material. In this case, the material is coal, and the void
space is the cleat fracture system. Since porosity values for the coal seams in the mine area were not
available, a value of 0.5 percent was used in the simulations. Porosity values for coal typically range
between 1 and 3 percent; however, the 0.5 percent porosity value was based on analog data from the
Jharia Coalfield as provided by the Central Mine Planning and Design Institute (CMPDI). The cleat and
natural fracture system in the reservoir was assumed to be 100 percent water saturated. This
assumption is consistent with drilling information and well test data from analogous coal in the region.
17
-------
4.3.2.3 Sorption Time
Sorption time is defined as the length of time required for 63 percent of the gas in a sample to be
desorbed. In this study a 1.5 day sorption time was used, which is consistent with the coals in the region.
Production rate and cumulative production forecasts are typically relatively insensitive to sorption time.
4.3.2.9 CieatSpacing
A cleat spacing of 6.5 centimeters (cm) was assumed in the simulations, which is consistent with data
from field tests conducted at a nearby CBM project. In the model, cleat spacing is only used for
calculation of diffusion coefficients for different shapes of matrix elements and it does not materially
affect the simulation results.
4.3.2.10 Borehole Spacing
As discussed previously, six borehole spacing cases were modeled: 41.7 m, 50 m, 62.5 m, 83.3 m, 125 m,
and 250 m apart.
4.3.2.11 Completion
Long in-seam boreholes with lateral lengths of 800 m will be drilled into the longwall panel. For
modeling purposes, a skin value of +2 is assumed (formation damage).
4.3.2.12 Well Operation
For the current study, an in-mine pipeline with a surface vacuum station providing a vacuum pressure of
41 kPa was assumed. In coal mine methane operations, low well pressure is required to achieve
maximum gas content reduction. The wells were projected to produce for a total of five years.
4.3.3 Simulation Results
Reservoir models were developed for 800 m in-seam boreholes for six different spacings between
boreholes: 41.7 m, 50 m, 62.5 m, 83.3 m, 125 m, and 250 m. The models simulated borehole gas flow
rate and percentage of gas content reduction over a five-year period as shown Exhibit 13. The drainage
time required to reduce the residual gas content by 30 percent, and the average gas production rate for
each in-seam borehole configuration during that period, were derived from the numerical models and
are presented in Exhibit 14. This exhibit provides the drainage times that each borehole spacing strategy
would require to decrease the in-situ methane level in a longwall panel methane saturation by 30
percent, allowing mine developers to tailor their drainage strategy depending on the amount of time
they have before commencing mining operations on that panel.
18
-------
1600
re 1400
¦o
(T^
— 1200
d)
(D
c 1000
o
(_>
¦3 800
O
Q_
% 600
400
2000
Seam XII Simulation Results
182.5
365.0
547.5
730.0 912.5 1095.0
Time (days)
1277.5
1460.0
1642.5
0
1825.0
90
80
g
c
o
u
T3
OJ
en
c
20
10
70
60
50
40
30
250 m m3/day 125 m m3/day 83.3 m m3/day 62.5 m m3/day
50 m m3/day 41.7m3/day 250 m GCR 125 m GCR
83.3 m GCR 62.5 m GCR 50 m GCR 41.7 GCR
Exhibit 13: Results of Gas Content Reduction Versus Borehole Spacing Analysis in Seam XII
Spacing
(m)
Time
(years)
Gas
Content
Reduction
(%)
Average
Methane
Flow Rate
(m3/day)
41.7
0.5
30
1152
50
0.6
30
1046
62.5
0.9
30
925
83.3
1.4
30
778
125
2.8
30
593
250
5.0
20.75
452
Exhibit 14: Drainage Time and Average Methane Flow Rates
Versus Borehole Spacing in Seam XII
5. Market Information
Presently there are no commercial-scale CMM projects in India, but the development of CMM is high on
the agenda of the Indian coal mining industry. To support the growing energy requirements of the
country, the coal mining industry in India is shifting from opencast to underground mining techniques.
However, due to safety concerns related to methane outbursts, increased production from underground
mines cannot be realized without proper degasification precautions. If captured and utilized properly,
CMM would help satisfy the demand for energy in the region while improving the local environment
through the reduction of greenhouse gas (GHG) emissions.
19
-------
India began awarding CBM blocks for exploration in 2001 and, after more than a decade, production is
beginning to come online. According to the DGH, Jharkhand has significant potential for CBM production
with 6.178 Tcf (175 Bern) of CBM resources, or 24.7 percent of India's total CBM resources, located
within the state. The Jharia Coalfield in Jharkhand has been developed and has an estimated gas
potential of 2.4 Tcf (68 Bern) (DGH, 2019). Total CBM production from India in 2016 amounted to 13.9
Bcf or 392.873 Mm3 (DGH, 2016).
The Central Institute of Mining and Fuel Research (CIMFR) estimates that demand for natural gas in
India has been increasing by 6.8 percent per year for the last decade, and natural gas consumption has
increased annually by approximately 6 percent during the same period (EIA, 2016). Coal production in
India is also struggling to keep up with the rapidly growing demand for coal causing power shortages
and blackouts throughout the country. As a result, natural gas has traditionally been used to primarily
supplement low coal supplies. However, as a cleaner and more efficient fuel than coal, natural gas has
recently made major inroads in the power, transport, fertilizer, chemicals, and petrochemical industries.
The majority of natural gas demand in 2014 came from the power sector (23 percent), the fertilizer
industry (32 percent), and for the replacement of liquified petroleum gas (LPG) for cooking oil and other
uses in the residential sector (14 percent) (EIA, 2016).
By 2022, India plans for natural gas to make up 15 percent of its primary energy consumption, up from 6
to 7 percent currently (Kar, 2018). The ability to market CMM as a viable way of feeding this increase is
dependent on the ability for pipelines to transport the gas to market—despite the 11,092 km of pipeline
that exists in the country and the 13,489 km of pipeline currently being built, pipelines continue to be
underutilized, hampering efficient operation and further expansion. A central reason behind this
underutilization is the lack of domestic natural gas production in India and the higher price of imported
gas. Increasing pipeline coverage in gas-producing regions, like Jharkhand and neighboring West Bengal,
will help improve this imbalance.
As of the beginning of 2018, there was a complete absence of pipeline infrastructure in the vicinity of
the Jharia Coalfield for transporting and marketing natural gas. Jharkhand and the cities neighboring the
mine are virgin markets devoid of natural gas or the infrastructure necessary for it. Consequently, if
CMM resources are inadequate to fuel local demand, then consumers are exposed to uncertainty in
natural gas supply. This situation was addressed by the 2016 Indian Cabinet Committee on Economic
Affairs' decision to fund 40 percent of the $1.8 billion Jagdishpur-Haldia and Bokaro-Dhamra Gas
Pipeline (JHBDPL) project, thereby expediting construction of a pipeline that would run through the
Jharia Coalfield (PIB, 2016) (Exhibit 15).
Phase I of the pipeline, running 753 km from Phulpurto Dobhi, was completed in December 2018 and
work immediately began on Phase II, running 667 km from Dobhi to Bokaro, which passes within 10 km
of the Pootkee Colliery. The portion of the pipeline passing by Pootkee Colliery will have a design
capacity of 16 Mm3 natural gas per day and will connect the project to a pipeline network running
through seven cities, forty districts, and 2,600 villages in eastern India (HT, 2019). This section is due to
be finished by December 2020 and will connect the Jharia Coalfield to India's overall natural gas
infrastructure. CIL confirmed it was in talks with the Gas Authority of India Limited (GAIL), the state-
owned pipeline company operating the JHBDPL, about a possible partnership to connect and further
develop the CBM/CMM resources of the Jharia and Raniganj coalfields (HT, 2019).
20
-------
PROPOSED NOMENCLATURE OF
SECTIONS
T KANPUR
['AURAIW, .'AOL>iSHPLIR PX ] ¦ ^
RAi 3ARELI
^amgW.
(Start Point]
Jl I CD PL
jPATNAk'B I H A R
" ""VMFC_Bsi«wnl!, ®
^gazipurL
.lahabad]
MlRZAPUR
jCHHATARPURj
[ aurakgabad]
codarma!
DHAN8AD1^
il f ci sworn
Ipuruuy*
BANKURA;
HOOGHLY
JABALPUR
jHOWRAH I
C'-aib4.i 11,11^1 -b. h
ootkhe4-Co
[ SUNDARGARlT
RUURKLLA!
RAIGARH
"balaghat'
JHBDPL Project
ISUta Win Plwllin LwalW
Gas source LNG at Dhamra
RAIPUR 1- /-
.uwA'kJ . V
U»ar Pradesh • 3*3 Km
lOHAMRAl
Jhflrkihaiul
Odisha
Exhibit 15: Jadishpur-Haldia & Bokaro-Dhamra Pipeline Project in Relation to the Pootkee
Colliery. Source: (PNGRB, 2018)
India is currently the fourth largest liquefied natural gas (LNG) importer in the world and has four LNG
import terminals all located in Gujarat Province in western India: Dahej, Mundra, Hazira, and Jafrabad
(Corkhill, 2018a). There are additional projects currently being developed in Ennore, Kakinada, and
Dahmra on India's east coast, although these projects have developed at a slower pace than anticipated
and will not run at 100 percent capacity until over a year after completion (Corkhill, 2018b). None of
these terminals are close to the Jharia Coalfield, meaning that CBM/CMM would likely not directly
compete with imports of LNG.
Additionally, Essar Oil & Gas Exploration & Production Ltd (EOGEPL) signed a 15-year supply contract
with GAIL in August 2018 whereby the company would be able to monetize its entire CBM production
from the Raniganj East block at a globally competitive price (Essar, 2018). The prices that GAIL will pay
for the gas are linked to the three months' daily average price of Brent crude (Equation 5.1) and will
hypothetically feed a 20 Mm /d demand in the region with a floor price of $5.22 per million British
thermal unit (MMBtu) and a ceiling price of $13.45/MMBtu. Under this pricing scheme, the gas price in
February 2019 was $7.96/MMBtu. Four fertilizer plants and 25 municipalities have already signed
contracts to receive CBM gas from the GAIL JHBDPL. GAIL is committed to getting 100 percent usage of
21
-------
its pipeline, so CMM gas sales would be a feasible utilization option for the Pootkee-Bulliary block, which
will be evaluated in the Economic Analysis section of this report (Section 7).
Sales Price ( USD ) on GCV basis = 12.67% * Brent(n) + 0.780 + (V) (Equation 5.1)
\MMBtuJ ^ '
Where:
Brent(n) = arithmetic average price of Brent crude oil over a period of 3 months.
GCV = Gross Calorific Value
V = (-) 1.89
The state-owned Oil and Natural Gas Corp (ONGC) sold CBM from its Bokaro CBM block assets (also
located in the Jharia Coalfield) in 2018 for $5.77 to $6.12/MMBtu to private industries and GAIL
pipelines. CMM sold as low as $5.56/MMBtu to GAIL and as high as $6.12/MMBtu to Positron Energy
Pvt Ltd, a private energy company (PTI, 2018c). The prices BCCL would be selling its CMM at would likely
be within these ranges.
Jharkhand State's gross state domestic product (GSDP) expanded at a compound annual growth rate
(CAGR) of 10.8 percent from 2011 to 2018, and now represents India's 19th largest state economy with a
current GSDP of US$ 43.36 billion (IBEF, 2018). Despite the modest size of its local economy, the
Pootkee-Bulliary CMM block is located only 30 km away from the border of West Bengal, which is India's
6th largest economy with a GSDP of US$ 163.67 (IBEF, 2018). The services sector is responsible for 57
percent of West Bengal's economic output while the agricultural and industrial sectors contributing 23
and 19.8 percent each, respectively (IBEF, 2018). The state's favorable location gives it a market
advantage and it is a traditional market for eastern India, northeast India, Nepal, and Bhutan. Most
importantly West Bengal State offers great connectivity to the rest of India through a developed
network of railways, roadways, sea ports, and airports (IBEF, 2018).
Jharkhand State itself is also economically attractive given its huge mineral wealth (40 percent of India's
overall mineral wealth) and the local manufacturing and energy related industries that naturally
concentrate in mineral rich areas (IBEF, 2018). More specifically, the Pootkee Colliery is located near the
heavily developed industrial areas of Bokaro Steel City and Dhanbad - the terrain between these areas is
smooth and only has a topographic relief of 20 m between the mine and the towns, so transportation of
CMM to these markets via pipeline would be theoretically feasible.
6. Opportunities for Gas Use
Drained methane can be used to fire internal combustion engines that drive generators to make
electricity for sale to the local power grid. The quality of methane required for use in power generation
can be less than that required for pipeline injection. Internal combustion engine generators can
generate electricity using gas that has heat content as low as 300 Btu per cubic foot (Btu/cf) or about 30
percent methane. Mines can use electricity generated from recovered methane to meet their own on-
site electricity requirements and can also sell electricity generated in excess of on-site needs to utilities.
Coal mining is a very energy-intensive industry that could realize significant cost savings by generating
its own power. Nearly all equipment used in underground mining runs on electricity, including mining
22
-------
machines, conveyor belts, ventilation fans, and elevators. Drained methane can also be used as a
transportation fuel, as a petrochemical and fertilizer feedstock, as fuel for energy/heating requirements
in industrial applications, and for on-site boilers that provide hot water or space heating to mine
facilities (USEPA, 2013).
On-site power generation is typically the most economic option for methane utilization at mines around
the world because low quality gas can be used, which minimizes gas processing costs, and the gas is
used on-site, which eliminates pipeline and compression costs. Coal mines are major power consumers
with substations and transmission lines near large mining operations and accessible to CMM-based
power projects. However, there are other potential uses for drained gas in the region of the Pootkee
Colliery that could be economic if other mines in the region pooled their gas production which would
allow them to amortize the cost of the added infrastructure over a larger gas volume. One such option
would be sending the gas to the JHPDL pipeline, scheduled to be completed in 2019. This pipeline would
allow for CBM/CMM delivery to large customers in the area like FCI, Sindri, Jamshedpur, Ranchi, and the
Bokaro Steel Plant. Recent liberalizing of CBM pricing approved by the Cabinet Committee on Economic
Affairs in 2017 allows for CBM/CMM to be sold at market driven rates. It remains to be determined the
effect that the JHBDPL will have on local gas pricing; however, if the pipeline allows for the cheap
transport of natural gas to cities and townships, then marketing gas directly to consumers would be a
viable option.
BCCL is developing a similar CMM drainage project at the nearby Moonidih Mine, located just south of
Pootkee Colliery, where it intends to install pre-drainage boreholes into coal seam XVI. In September
2018, the company tendered an offer to contractors requesting bids for a degasification job of the seam
via any combination of long-hole directional drilling, surface drilling, and underlying strata drilling. The
bidder would have to collect enough gas to feed a 2-megawatt (MW) generator capable of producing at
least 1 million kilowatt-hours (kWh) of electricity per month.
7. Economic Analysis
7.1 Economic Assessment Methodology
The economic and financial performance of the proposed CMM drainage and utilization project were
evaluated using key inputs discussed in the following sections of this report. A simple discounted cash
flow model was constructed to evaluate project economics of CMM drainage and power sales. Key
performance measures that were used for evaluating the project included net present value (NPV) and
internal rate of return (IRR). The results of the analyses are presented on a pre-tax basis.
7.2 Project Development Scenario
Long directionally drilled boreholes were planned in advance of mains, gate roads, and longwall panels
using the aforementioned mining schedule presented for the Seam XII workings through the year 2046.
The spacing requirements for the in-seam boreholes were derived by comparing the time available for
gas drainage based on the mining schedule (and directional drilling schedule) with the time required to
reduce the residual gas content by 30 percent per the reservoir modeling results (Exhibit 13 and Exhibit
14).
23
-------
This pre-feasibility study assumes that directional drilling will initiate in mid-2019 in panels PB-001 and
PB-002, with mining of the panels beginning in 2020 and 2021, respectively. Based on the mining and
drilling schedule, minimal drainage time is available, and a borehole spacing of 41.7 m and 83.3 m will
be required for panels PB-001 and PB-002, respectively. Similarly, drilling at panel PB-003 will begin in
mid-2020 with mining initiated in 2022, which necessitates a borehole spacing of 83.3 m. As directional
drilling begins to outpace mining and more drainage time is available, borehole spacing increases,
minimizing annual drilling requirements during the later years. Panels PB-004 through PB-027 are
assumed to utilize borehole spacing of 125 m as shown on the drilling schedule in Exhibit 17. Overall, the
Seam XII pre-drainage drilling plan requires a total of 50,400 m of drilling, with a total of 60 horizontal
boreholes - all of which could be drilled from just 27 borehole collars.
Exhibit 17 also summarizes the projected annual gas collection pipeline requirements for the drainage
plan proposed for the Project. It is assumed that 300 m of gathering pipeline will be needed as each
panel is developed. As a result, a total of 8,100 m of gathering pipeline will be laid over the life of the
Project.
Exhibit 16: Conceptual Mine Layout and Development Plan for Seam XII at Pootkee Colliery
N
0
24
-------
Panel
Year
Drilled
Year
Mined
Drainage
Time
(years)
Borehole
Spacing
(m)
Boreholes
Per Panel
Meters
Drilled
Gathering
Pipeline Laid
(m)
PB-001 2020
2019.5
2020
0.5
41.7
6
5040
300
PB-002 2021
2019.5
2021
1.5
83.3
3
2520
300
PB-003 2022
2020.5
2022
1.5
83.3
3
2520
300
PB-004 2023
2020
2023
3
125
2
1680
300
PB-005 2024
2021
2024
3
125
2
1680
300
PB-006 2025
2022
2025
3
125
2
1680
300
PB-007 2026
2023
2026
3
125
2
1680
300
PB-008 2027
2024
2027
3
125
2
1680
300
PB-009 2028
2025
2028
3
125
2
1680
300
PB-010 2029
2026
2029
3
125
2
1680
300
PB-011 2030
2027
2030
3
125
2
1680
300
PB-012 2031
2028
2031
3
125
2
1680
300
PB-013 2032
2029
2032
3
125
2
1680
300
PB-014 2033
2030
2033
3
125
2
1680
300
PB-015 2034
2031
2034
3
125
2
1680
300
PB-016 2035
2032
2035
3
125
2
1680
300
PB-017 2036
2033
2036
3
125
2
1680
300
PB-018 2037
2034
2037
3
125
2
1680
300
PB-019 2038
2035
2038
3
125
2
1680
300
PB-020 2039
2036
2039
3
125
2
1680
300
PB-0212040
2037
2040
3
125
2
1680
300
PB-022 2041
2038
2041
3
125
2
1680
300
PB-023 2042
2039
2042
3
125
2
1680
300
PB-024 2043
2040
2043
3
125
2
1680
300
PB-025 2044
2041
2044
3
125
2
1680
300
PB-026 2045
2042
2045
3
125
2
1680
300
PB-027 2046
2043
2046
3
125
2
1680
300
TOTAL
60
50400
8100
Exhibit 17: P re-Mining Directional Drilling Schedule and Gathering Pipeline Laid for Seam XII
25
-------
7.3 Mine Methane Drainage Production Forecast
Gas production rates were derived for each in-seam borehole by considering the implementation
schedule and the borehole spacing and denoting the corresponding gas production from the methane
flow rate prediction curves presented in Exhibit 13. Exhibit 18 presents the annual methane production
forecast from degasification of the Mine using the recommended methane drainage plan over the 27
year period between 2019 and 2045. The forecast predicts recovery of an average of 0.6 Mm" of
methane per year.
Annual Methane Production Forcast
0.8
0.7 —
0.6
"e
c 0.5
,o
~ 0.4
O
S
| 0.3 ¦
I
0.1 —
0.0 ™
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Exhibit 18: Methane Production Forecast for the Proposed Methane Drainage Plan for Seam XII
7.4 Economic Assumptions
Cost estimates were developed for goods and services required for the development of a CMM project
at the Pootkee Colliery. These estimates were based on a combination of known average development
costs of analogous projects in the region, and other publicly available sources. All economic results are
presented on a pre-tax basis. The input parameters and assumptions used in the economic analysis are
summarized in Exhibit 19. A more detailed discussion of each input parameter is provided below.
26
-------
PHYSICAL & FINANCIAL FACTORS
Units
Value
Royalty
%
10
Price Escalation
%
3
Cost Escalation
%
3
Heating Value of Drained Gas
Btu/cf
928
Electricity Price
$/kWh
0.071
Generator Efficiency
%
35
Run Time
%
85
Global Warming Potential of CH4
tC02e
25
C02 from Combustion of 1 ton CH4
tco2
2.75
CAPITAL EXPENDITURES
Units
Value
Drainage System
In-Seam Drilling Cost
$/ft
40
In-Seam Drilling Length
ft
165,312
Surface Vacuum Station
$/hp
1000
Vacuum Pump Efficiency
hp/Mcfd
0.035
Gathering & Delivery System
Gathering Pipe Cost
$/ft
40
Gathering Pipe Length
ft
26,568
Contingency Fee (capex)
%
10
Power Plant
$/kW
1300
Development Fee
%
15
OPERATING EXPENSES
Units
Value
Field Fuel Use (gas)
%
5
Drainage System O&M
$/Mcf
0.1
Water Treatment/Disposal
$/Bbl
0.05
Power Plant O&M
$/kWh
0.03
Contingency Fee (opex)
%
10
Exhibit 19: Summary of Economic Input Parameters and Assumptions.
27
-------
7.4.1 Physical and Financial Factors
Royalty
Under the permission granted by the Government of India (Gol) to BCCL, royalty at prevailing rates at
par with payments required to be made for natural gas and as revised from time to time is to be paid by
BCCL which at present are set at 10%.
Price and Cost Escalation
All prices and costs are assumed to increase by 3 percent per annum based on analogous projects in the
region.
Heating Value of Drained Gas
The drained gas is assumed to have a heating value of 928 Btu/cf. This is based on a heating value of
1,020 Btu/cf for pure methane adjusted to account for lower methane concentration of the CMM gas,
which is assumed to be 91 percent for drained gas in the Pootkee Colliery area.
Electricity Price
According to the most recent data available (2017-18), BCCL's average purchase price for electricity was
$0.071/kWh (BCCL Annual Report 2017-18).
Generator Efficiency and Run Time
Typical electrical power efficiency is between 30 percent and 44 percent and run time generally ranges
between 7,500 to 8,300 hours annually (USEPA, 2011). For the proposed power project an electrical
efficiency of 35 percent and an annual run time of 85 percent, or 7,446 hours, were assumed.
Global Warming Potential of Methane
A global warming potential of 25 is used. This value is from the Intergovernmental Panel on Climate
Change Fourth Assessment Report (IPCC, 2013).
Carbon Dioxide from Combustion of Methane
Combustion of methane generates carbon dioxide (C02). Estimating emission reductions from CMM
projects must account for the release of C02 from combustion when calculating net C02 emission
reductions. For each ton of CH4 combusted, 2.75 tC02 is emitted, resulting in a net emission reduction of
22.25 tC02e per ton of CH4 destroyed.
7.4.2 Capital Expenditures
Capital expenditures include the cost of horizontal pre-drainage boreholes, as well as surface facilities
and vacuum pumps used to bring the drainage gas to the surface. The drained methane can be used to
fuel internal combustion engines that drive generators to make electricity for use at the mine or for sale
to the local power grid. The major cost components for the power project are the cost of the engine and
generator, as well as costs for gas processing to remove solids and water, and the cost of equipment for
connecting to the power grid. The major input parameters and assumptions associated with the project
are as follows:
Borehole Cost
In-seam borehole costs are estimated at $40 per foot ($131/m) with a total of 165,312 ft (50,387m)
drilled.
28
-------
Surface Vacuum Station
Vacuum pumps draw gas from the wells into the gathering system. Vacuum pump costs are a function of
the gas flow rate and efficiency of the pump. To estimate the capital costs for the vacuum station, a
pump cost of $1000 per horsepower (hp) and a pump efficiency of 0.035 hp per thousand standard
cubic feet per day (Mscfd) are assumed. Total capital cost for the surface vacuum station is estimated as
the product of pump cost, pump efficiency, and peak gas flow (i.e., $/hp x hp/Mscfd x Mscfd).
The gathering system consists of the piping and associated valves and meters necessary to get the gas
from within the mine to the satellite compressor station located on the surface. The major input
parameters and assumptions associated with the gathering system are as follows:
Gathering System Cost
The gathering system cost is a function of the piping length and cost per foot. For the proposed project,
we assume a piping cost of $40/ft ($131/m) and 26,568 ft (8,100 m) of gathering lines.
The delivery system consists of the satellite compressor and the pipeline that connects the compressor
to the sales system leading to the utilization project. We assume the power plant is located within the
mine area resulting in a delivery system cost of zero.
Power Plant Cost Factor
The power plant cost factor, which includes capital costs for gas pretreatment, power generation
(including combustion engines), and electrical interconnection equipment, is assumed to be $1,300 per
kilowatt (kW).
CAP EX Contingency Fee
A 10 percent contingency is fee is added for unforeseen additional costs.
Development Fee
A fee is included to account for the cost of project development including staff costs, equipment, office
space, transportation, and other resources necessary to plan and develop the project. The fee is
estimated at 15 percent of the cost of the power plant based on experience in the field.
7.4.3 Operating Expenses
Fuel Use
For the proposed project, it is assumed that CMM is used to power the vacuum pumps and compressors
in the gathering and delivery systems. Total fuel use is assumed to be 5 percent, which is deducted from
the gas delivered to the end use.
Drainage System Operating and Maintenance Costs
Operating and maintenance costs for vacuum pumps and compressors associated with in-mine
horizontal pre-drainage boreholes are assumed to be $0.10/Mscf.
Water Treatment/Disposal
The cost associated with water treatment and disposal is $0.05/Bbl.
Power Plant Operating and Maintenance Cost
The operating and maintenance costs for the power plant are assumed to be $0.03/kWh.
29
-------
OPEX Contingency Fee
A 10% contingency is fee is added for unforeseen additional costs.
7.4.4 Economic Results
There are two different economic scenarios evaluated in this study as shown in Exhibit 20. The two are
differentiated by whether the mine will absorb the operational costs of the drainage system or not. The
first scenario is the power plant only scenario and in this project scenario, the costs of the gas drainage
system will be absorbed by the mining operation as operational costs. Higher NPV and IRR values are
present in the power plant only scenario because of this cost absorption. It is also important to note that
in the power plant only scenario, the cost of gas purchased is not included. It is assumed that the mining
operation will provide the CMM for free to the power plant. Should the mining operation wish to
internalize the price of gas as a revenue and charge a fee, then the power project would need to show a
cost of gas purchased as an operating cost, which would likely reduce the IRR's.
In the second scenario, the gas drainage system costs are not absorbed by the mine operation. The gas
drainage system involves in-seam directional drilling of horizontal pre-drainage boreholes, which adds to
the cost of the project and decreases returns. Max power plant capacity and net C02e reductions are the
same for both project scenarios because those values are largely reliant on the quantity of gas
production, which is the same for the different project scenarios because the same two development
scenarios are used to calculate results from the two economic scenarios. The discount rate used for all
NPV calculations in the results tables is 10 percent.
Development
Scenario
Max Power
Plant Capacity
(kW)
NPV-10
($,000)
IRR (%)
Payback
(years)
Net C02e
Reductions
(tC02e)
Power Plant (only)
260
372
18%
6.0
188,374
Power Plant and
Drainage System
260
-4,557
na
na
188,374
Exhibit 20: Summary of Economic Results (pre-tax)
8. Recommendations and Next Steps
As a pre-feasibility study, this document is intended to provide a high-level analysis of the technical
feasibility and economics of the CMM project at the Pootkee Colliery. The project as proposed will use
long in-mine horizontal boreholes to drain methane in advance of mining, and to utilize the drained gas
to generate electricity for on-site consumption. The analysis performed reveals that methane drainage
using long in-mine horizontal boreholes is feasible and could provide the mine with additional benefits
beyond the sale of gas or power, such as improved mine safety and enhanced productivity.
As the analysis shows, pre-drainage using long, directionally drilled horizontal boreholes can effectively
lower the residual gas content of coal seams prior to future mining. As proposed in this study, the CMM
project at the Pootkee Colliery is anticipated to reduce emissions of methane by more than 188,000
tonnes of carbon dioxide equivalent (tC02e) over the 27-year life of the project.
30
-------
The next step in proceeding forward is a full feasibility study, which, at a minimum, should be prepared
before any investment decision is made. To prepare a full feasibility study, USEPA recommends the
following next steps:
• Conduct a detailed engineering study, conduct additional monitoring of gas drainage and
ventilation to provide a robust data set on which to evaluate project feasibility and identify
important data gaps with respect to gas drainage and mine ventilation data and address;
• Secure additional geologic data to develop a more accurate gas resource assessment;
• Further refine the reservoir simulation and gas production forecast based on newly available or
revised data;
• Contact drilling contractors to obtain estimates of drilling costs for directional drilled boreholes;
• Conduct additional market research and investigate more thoroughly all utilization options
including power production to confirm the economic and technical feasibility of CMM-to-power
and the viability of alternatives and their competitiveness with power generation;
• Conduct outreach to suppliers of equipment and services and compile equipment pricing, terms
of sales and product specifications;
• Scope out engineering and construction requirements for the CMM plant;
• Develop a detailed project development and implementation schedule and determine internal
costs for project development;
• Refine the financial analysis and develop a detailed project-specific model sufficient for internal
or external financing entities.
31
-------
References
Abdi, B. (2018, April 25). First growth in India's natural gas production in 6 years. Retrieved from The
Economic Times: https://energv.economictimes.indiatimes.com/news/oil-and-gas/first-growth-in-
indias-natural-gas-production-in-six-years/63904860
BCCL. (2009). About BCCL. Retrieved from BCCL: http://www.bcclweb.in/7page id=43
BCCL. (2018). Annual Reports and Accounts 2017-2018. Retrieved from BCCL:
https://www.coalindia.in/Portals/13/PDF/BCCL ANNUAL REPORj _ J./ . 18 gdf
BP. (2018). BP Statistical Review of World Energy. Retrieved from BP:
https://www.bp.com/en/elobal/corporate/energy-economics/statistical-review-of-world-enerev.html
CMPDI-CIL. (2017, March 9-10). International Workshop on Best Practices in Methane Drainage and Use
in Coal Mines. Retrieved from UNECE:
https://www.unece.ore/fileadmin/DAM/enerev/imaees/CMM/Librarv/Ranchi/CMPDI%E2%80%99s role
in development of CBM-CMM in India - Shekhar Saran.pptx
CMPDI-CIL. (2017, December). Project Feasibility Report of Jharia CMM/CBM Block. Confidential.
Corkhill, M. (2018, Oct 3)a. LNG in India- in with the new. Retrieved from LNG World Shipping:
https://www.lneworldshippine.com/news/view,Ine-in-india-in-with-the-new 54423.htm
Corkhill, M. (2018, Oct 31)b. Indian subcontinent ramps up LNG import capacity, retrieved from LNG
World Shipping: https://www.lneworldshippine.com/news/view,indian-subcontinent-ramps-up-lne-
import-capacity 55721.htm
EIA. (2016, June 14). Country Analysis Brief. Retrieved from India:
https://www.eia.eov/beta/international/analysis.cfm?iso=IND
EIA (2019, September 9). India Coal Production. Retrieved from India:
https://www.eia.eov/beta/international/countrv.php?iso=lND
Das, A. K. (2016, August 12). Mining Weekly. Retrieved from Hydrocarbon policy requires private Indian
CBM firms to apply for new licences: http://www.miningweekly.com/article/hydrocarbon-policy-
requires-private-indian-cbm-firms-to-apply-for-new-licences-2016-08-12
Das, A. K. (2018, December 20). India's Coal Ministry Extends Timelines for Ongoing Coal Block Auction.
Retrieved from Mining Weekly: http://www.minineweeklv.com/article/indias-coal-ministry-extends-
timelines-for-oneoine-coal-block-auction-2018-12-20
DGH. (2016). India's Hydrocarbon Outlook: 2015-2016, A Report on Exploration and Production
Activities. Retrieved from DGH: http://dehindia.eov.in/assets/downloads/ar/2015-16.pdf
DGH. (2019). Coal Bed Methane. Retrieved from Central Mine Planning and Design Institute:
https://www.cmpdi.co.in/cbm.php
DGMS, Director General of Mines Safety. (2015). Statistics of Mines in India, Volume 1- Coal, retrieved
from Indian Ministry of Labor and Employment:
http://www.dems.eov.in/writereaddata/UploadFile/Coal 2015.pdf
32
-------
Essar. (2018, August 9). Essar signs GSPA with GAIL for Offtake of entire production from Raniganj East
CBM Block, retrieved from Essar: https://www.essar.com/essar-signs-gspa-with-gail-for-offtake-of-
entire-production-from-ranigani-east-cbm-block/.
IBEF. (2018, May). West Bengal, Culturally Artistic. Retrieved from IBEF:
https://www.ibef.org/download/West-Bengal-Mav-20181.pdf
IBEF. (2018, August), India Brand Equity Foundation. (2018, November). Jharkhand, the Mining Base of
India. Retrieved from IBEF: https://www.ibef.org/uploads/states/infogrphics/large/iharkhand-
infographic-nov-2018.pdf
IBM, India Bureau of Mines. (2018, March). India Minerals Yearbook 2017, Part 3: Mineral Reviews, Coal
and Lignite. Retrieved from Indian Bureau of Mines:
http://ibm.nic.in/writereaddata/files/01092019132010Coal2017.pdf
Loh, T. (2016, April 25). India's Energy Minister Wants to Cut Coal Imports to Nothing. Retrieved from
Bloomberg: https://www.bloomberg.com/news/articles/2016-04-25/india-s-energy-minister-wants-to-
cut-coal-imports-to-nothing
Kar, S. K. (2018, May 07). Grid Development Key to India's Natural Gas Market Growth. Retrieved from
Oil and Gas Journal: https://www.ogi.com/articles/print/volume-116/issue-5/transportation/grid-
development-key-to-india-s-natural-gas-market-growth.html
MOSPI- Ministry of Statistics and Programme Implementation. (2018). Energy Statistics. Retrieved from
MOSPI: http://mospi.nic.in/sites/default/files/publication reports/Energy Statistics 2018.pdf
NITI. (2017). India Three Year Action Agenda, 2017-18 to 2019-20. Retrieved from NITI Aayog:
http://niti.gov.in/writereaddata/files/coop/lndiaActionPlan.pdf
PIB. (2016, Sept. 21). Cabinet approves Capital Grant to GAIL for development of Gas Infrastructure in
Eastern part of the country. Retrieved from PIB:
http://pib.nic.in/newsite/PrintRelease.aspx?relid=150960
PNGRB. (2018, March). Final Terms & Conditions for Acceptance of Central Government Authorization
for laying, building, operating or expanding the Jagdishpur-Haldia Natural Gas Pipeline with an extension
from Bokaro to Dhamra of PNGRB (Authorizing Entities to Lay, Build, Operate or Expand Natural Gas
Pipelines) Regulations, 2008, and in pursuance of the Policy Directive issued to PNGRB by the Ministry of
Petroleum & Natural Gas under Section 42 of the PNGRB Act, 2006. Retrieved from PNGRB:
http://www.pngrb.gov.in/pdf/ngp/Govt-Authorizati BPL-03022018.pdf
PTI. (2013, December 19). Live Mint. Retrieved from Govt allows Coal India to produce gas from coal bed
methane: http://www.livemint.com/Politics/ballk7ueHCFbvpOzkClggO/Govt-allows-Coal-lndia-to-
produce-gas-from-coal-bed-methane.html
PTI. (2016, December 5). The Indian Express. Retrieved from PM Narendra Modi asks Indian energy
companies to become MNCs: http://indianexpress.com/article/india/pm-narendra-modi-asks-indian-
energy-companies-to-become-mncs-4411326/
33
-------
PTI. (2018, August 12)a. Ground Realities Force Coal India to Push Back Production Target. Retrieved
from the Economic Times: https://economictimes.indiatimes.com/industry/indl-eoods/svs/metalS"
mining/ground-realities-force-coal-india-to-push-back-production-target/articleshow/65375810.cms
PTI. (2018, April 12)b. Govt Relaxes Rules for Coal India to Ease Coal-bed Methane Extraction. Retried
from the Business Standard: https://www.business-standard.com/article/economv-policv/govt-relaxes-
rules-for-coal-india-to-ease-coal-bed-methane-extraction-118041100770 l.html
PTI. (2018, Jun, 17)c. ONGC sells CBM gas at $5.77-6.12 /MMBtu, retrieved from the Economic Times:
https://economictimes.indiatimes.com/industrv/energy/oil-gas/ongc-sells-cbm-gas-at-5-77-6-12-
/mmbtu/articleshow/64620760.cms
Saikia, S. P. (2015, July 23). Coal India to Speed Up Coal Bed Methane Exploration. Retrieved from
Financial Express: http://www.financialexpress.com/market/commodities/coal-india-to-speed-up-coal-
bed-methane-exploration/105780/
Sen, Sesa. (2018, July 22). Pledge to Cut Coal Imports Turning a Dud. Accessed from the New India
Express: http://www.newindianexpress.com/business/2018/iul/22/pledge-to-cut-coal-imports-turning-
a-dud-1846683.html
Sengupta, Debjoy. (2018, Aug 01). Coal India May Invite Global Firms to Extract Coal Bed Methane.
Retrieved from the Economic Times: https://economictimes.indiatimes.com/industry/indl-
goods/svs/metals-mining/coal-india-mav-invite-global-firms-to-extract-coal-bed-
methane/articleshow/65224545.cms
Singh, Rajesh. (2018, April 2). Coal India's Production, Shipments Rise to a Record in March. Retrieved
from Bloomberg: https://www.bloombergquint.com/business/coal-india-s-production-shipments-rise-
to-a-record-in-march#gs.QxHP3Npa
USEPA. (2013, September). Global Mitigation of Non-C02 Greenhouse Gases: 2010-2030. Retrieved
from United States Environmental Protection Agency: https://www.epa.gov/global-mitigation-non-co2-
greenhouse-gases/global-mitigation-non-co2-ghgs-report-download-report
USEPA. (2015). EPA CMOP CMM Country Profiles. Retrieved from EPA: https://www.epa.gov/cmop/coal-
mine-methane-country-profiles
34
------- |