United States Air and Radiation EPA 430-K-94-003
Environmental Protection (6202J) April 1994
Agency
REDUCING METHANE EMISSIONS
FROM COAL MINES IN RUSSIA AND UKRAINE:
THE POTENTIAL FOR COALBED METHANE
DEVELOPMENT
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REDUCING METHANE EMISSIONS
FROM COAL MINES IN RUSSIA AND UKRAINE:
THE POTENTIAL FOR COALBED METHANE
DEVELOPMENT
APRIL 1994
GLOBAL CHANGE DIVISION
U.S. ENVIRONMENTAL PROTECTION AGENCY
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Acknowledgments
This report was prepared jointly by the U.S. Environmental Protection Agency
and Raven Ridge Resources, a subcontractor to ICF Incorporated, under
Contract # 68-D2-0178. The contributing author from EPA was Dina Kruger.
Contributing authors from Raven Ridge Resources were James S. Marshall,
Raymond C. Pilcher, and Carol J. Bibler. Important contributions to this report
were provided by the staffs of the Skochinsky Mining Institute in Moscow, Russia
and the Ukrainian Gas Institute in Kiev, Ukraine, and many other Russian and
Ukrainian experts.
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SUMMARY
INTRODUCTION
This report presents an assessment of the coalbed methane resources of the Donetsk, L'vov-Volyn, and
Kuznetsk basins in Russia and Ukraine. The study was commissioned by the U.S. Environmental
Protection Agency, as part of its efforts to identify cost-effective opportunities to reduce methane
emissions to the atmosphere. The study evaluates the potential for coalbed methane development and
utilization, and its impact on the environmental and energy needs of these regions, as well as the two
republics.
This study emphasizes recovery of coalbed methane in mining areas because the methane emitted to
the atmosphere as a result of mining operations represents the loss of a valuable energy resource, and
because it is a greenhouse gas affecting the global climate.
KEY FINDINGS
Coalbed methane is an abundant domestic natural gas resource with excellent potential for
increased development and utilization in Russia and Ukraine. Coal mining operations vent
significant amounts of methane to the atmosphere.
Preliminary estimates suggest that coalbed methane resources associated with the
principal mining reserves of coal within mines of the three regions studied are between
627 billion and 1.1 trillion cubic meters. Additional methane resources are contained
in other coal reserves in the mining areas and in areas beyond the boundaries of the
mines, bringing the total estimated methane resource contained in coal seams of the
three coal basins studied to perhaps as much as 7.8 trillion cubic meters. Still further
methane resources are contained in the partings and strata surrounding the coal seams.
Large volumes of coalbed methane are liberated during coal mining operations each
year, representing a serious waste of energy. Coal mining operations within the
Commonwealth of Independent States (CIS) emit an estimated 7.2 to 10.7 billion cubic
meters of methane to the atmosphere annually. Ukraine accounts for 49 percent and
Russia for 35 percent of this total; the remaining 16 percent is emitted by other
republics. Only about 2 percent of the total methane liberated by coal mines in the CIS
is utilized.
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There appear to be many opportunities for mines in Russia and Ukraine to develop profitable
projects to expand the recovery and use of coalbed methane.
Using demonstrated technologies, such as pre-mining degasification and enhanced gob
well recovery, it appears likely that Russian and Ukrainian coal mines could recover and
use 50 percent or more of the methane currently being liberated by mining.
Additional recovery could be achieved by employing an integrated approach to methane
recovery, including drainage prior to, during, and after mining, and, where feasible
utilizing low methane concentration ventilation air as combustion air in power stations.
If such an approach were used within the active mines, 80 to 90 percent of the
methane that would be liberated and otherwise lost by mining operations could be
recovered and available for use.
There is significant potential for increased methane utilization, moreover, even without
expanding methane recovery. Currently, coal mines release approximately 78 percent
(more than 618 million cubic meters) of the medium quality methane they recover with
their existing degasification programs. Introduction of methods to improve gas quality
and use medium quality fuel in turbines or for other purposes could reduce these
emissions.
Ukraine and Russia confront difficult economic and environmental challenges related to the
transformation of the traditional state-subsidized energy industry to a more competitive
industry. Any new source of domestic energy could reduce economic burdens.
Natural gas will play an important role in the future of the energy economy of the CIS
as natural gas is significantly less expensive to produce than coal, on an energy-
equivalent basis, and is a much cleaner burning fuel.
Coalbed methane is an attractive gas resource in both Russia and Ukraine because it
is plentiful and is located in coal producing areas that have traditionally been intensely
industrialized and highly polluted.
The development of coalbed methane could make important contributions to the energy
economy of both Russia and Ukraine as well as benefiting the local and global environment.
Russia and Ukraine will likely continue reducing their dependency on low-quality hard
coal, brown coal and lignite, and coke-oven gas in order to reduce the environmental
problems use of these fuels creates. These trends will improve environmental quality
and will create opportunities for additional use of natural gas by the republics. Coalbed
methane development could assist these republics in achieving their environmental
goals and increase domestic production of clean burning energy.
Aggressive coalbed methane development and utilization would also decrease methane
emissions dramatically, which has important implications for the global climate.
Methane is a potent greenhouse gas that contributes to tropospheric ozone formation
and may contribute to stratospheric ozone depletion. Coal mines in the CIS emit
significant quantities of coalbed methane; the CIS is the second largest emitter of
methane from this source.
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Coalbed methane extracted during mining will be most valuable when used locally in
situations where high compression, enrichment, drying, or long distance transmission
is not required. Given the heavy industrialization of Russia and Ukraine's major coal
mining regions, there are numerous end-users available in the vicinity of many mines.
Coalbed methane could be used to generate both steam and electricity, displacing the
use of low-quality hard coal and lignite. Coalbed methane can also be transported by
pipelines directly to end-users, replacing coke-oven gas, or, in the case of Ukraine,
natural gas currently being imported from Russia. Displacement of hard coal, lignite and
brown coal, or coke-oven gas with coalbed methane would improve local air quality.
Increased mine productivity and safety would result from increased methane drainage,
improving the economic viability of hard coal mines of Russia and Ukraine.
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RECOMMENDATIONS
The potential for coalbed methane to help Russia and Ukraine achieve their economic,
environmental, and energy goals should be comprehensively assessed and, where
appropriate, development of the resource should be strongly encouraged.
The most feasible technologies for expanding methane recovery at coal mines in Russia
and Ukraine should be evaluated on a site-specific basis. The relationships between
expanded methane recovery and mine safety and economics should be considered in
such studies. In addition, the role that coalbed methane development could play in the
reorganization of the coal industry should be examined.
Where feasible, programs to increase the production of coalbed methane in conjunction
with mining should be implemented.
Special attention should be given to reducing the venting of medium- and high-quality
methane currently being produced by mine degasification systems in Russia and
Ukraine. Such methane represents a ready source of clean fuel that could be utilized
with additional investments.
As methane recovery expands at coal mines in Russia and Ukraine, a wide range of
utilization options, including power generation, direct uses, gas enrichment and pipeline
injection, should be evaluated and those that are most efficient, economically attractive
and environmentally beneficial should be emphasized. Opportunities to store coalbed
methane in abandoned coal mines should be examined.
The economic and environmental impacts of coalbed methane should be assessed,
including evaluation of the local economic impacts (such as job creation), land needs,
and any water disposal requirements.
Rapid development of coalbed methane will require participation by the Russian and Ukrainian
governments, international development agencies, foreign governments, and private industry.
Potential markets for methane produced by active coal mines should be assessed and
the investments required to bring this gas to market should be determined.
Implementation of some specific programs could greatly assist in the development of
coalbed methane projects in Russia and Ukraine, including:
Establishing appropriate policies to encourage the recovery and use of methane
from coal mines at the national and local level. To the extent that foreign
investment could help expedite the development of the resource, attention
could be given to the development of policies that encourage such investment.
IV
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Undertaking feasibility assessments of methane recovery and use projects at
specific sites in Russia and Ukraine, with a goal of identifying projects that
could subsequently be developed either as demonstration projects or as
commercial ventures.
Disseminating coalbed methane information to the coal mining regions of Russia
and Ukraine through the establishment of one or more Coalbed Methane
Recovery Technology Centers. These centers would facilitate information
exchange by publishing a journal, arranging meetings and technical seminars,
conducting outreach, and undertaking research and policy studies.
Developing training programs for government and industry personnel to raise
awareness of the coalbed methane resource and the available technologies for
its recovery and utilization.
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TABLE OF CONTENTS
SUMMARY i
RECOMMENDATIONS iv
LIST OF FIGURES viii
LIST OF TABLES ix
LIST OF BOXES ix
CHAPTER 1 - COALBED METHANE IN THE ENERGY ECONOMY OF THE CIS,
WITH EMPHASIS ON RUSSIA AND UKRAINE 1
1.1 INTRODUCTION 1
1.2 THE ENERGY SECTOR IN THE CIS 3
1.2.1 OVERVIEW 3
1.2.2 PRIMARY ENERGY SOURCES OF THE CIS 5
1.2.3 THE NATIONAL ENERGY STRATEGY 12
1.2.4 THE ROLE OF COALBED METHANE 13
CHAPTER 2 - COALBED METHANE RESOURCES OF RUSSIA AND UKRAINE 15
2.1 INTRODUCTION 15
2.2 COAL RESOURCES 16
2.2.1 THE DONETSK COAL BASIN 19
2.2.2 THE L'VOV-VOLYN COAL BASIN 26
2.2.3 THE KUZNETSK COAL BASIN 30
2.3 COALBED METHANE RESOURCE ESTIMATES 36
2.3.1 COALBED METHANE RESOURCES OF THE DONETSK BASIN . . 38
2.3.2 COALBED METHANE RESOURCES OF THE
L'VOV-VOLYN BASIN 38
2.3.3 COALBED METHANE RESOURCES OF THE KUZNETSK BASIN . . 40
CHAPTER 3 - COALBED METHANE RECOVERY AND UTILIZATION POTENTIAL
IN RUSSIA AND UKRAINE 42
3.1 COALBED METHANE RECOVERY 42
3.1.1 METHANE DRAINAGE METHODS 42
3.1.2 OPTIONS FOR INCREASED RECOVERY 45
3.2 COALBED METHANE UTILIZATION 46
3.2.1 DIRECT INDUSTRIAL USE OPTIONS 46
3.2.2 NATURAL GAS PIPELINE SYSTEMS 48
3.2.3 POWER GENERATION OPTIONS 48
3.2.4 VENTILATION AIR UTILIZATION OPTIONS 52
3.2.5 GAS ENRICHMENT 54
3.2.6 UNDERGROUND GAS STORAGE 55
VI
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CHAPTER 4 - CONCLUSIONS AND RECOMMENDATIONS FOR FURTHER ACTION 57
4.1 OVERVIEW 57
4.2 FOLLOW-UP TECHNICAL ASSISTANCE ACTIVITIES 58
4.2.1 TECHNICAL PRE-FEASIBILITY ASSESSMENTS 58
4.2.2 FEASIBILITY ASSESSMENTS 60
4.2.3 METHANE RECOVERY TECHNOLOGY CENTER 61
4.2.4 TRAINING 61
4.3 IMPACT ASSESSMENTS 62
4.4 REGULATORY ASSESSMENT 62
4.5 DEMONSTRATION PROJECTS 62
4.6 INVESTMENT CONSIDERATIONS 63
REFERENCES CITED 65
APPENDIX A - ENERGY FUEL PRODUCTION, TRADE, AND APPARENT CONSUMPTION
IN THE FORMER SOVIET UNION A-1
APPENDIX B - EXPLANATION OF FORMER USSR RESOURCE CLASSIFICATION AND
COAL RANK SYSTEMS B-1
VII
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LIST OF FIGURES
Figure 1. Fuel Mix of Selected Countries, 1992 2
Figure 2. Fuel Mix of Russia and Ukraine, 1992 3
Figure 3. Energy Demand by Sector, 1990 4
Figure 4. Industrial Sector Energy Sources in the USSR, 1990 4
Figure 5. Domestic Sector Energy Sources in the USSR, 1990 5
Figure 6. Transportation Sector Energy Sources in the USSR, 1990 5
Figure 7. Major Coal Basins of the Former USSR 17
Figure 8. Stratigraphic Correlation of Coal-Bearing Formations in the L'vov-Volyn,
Donetsk, and Kuznetsk Basins, CIS -. 18
Figure 9. Location of Production Associations
in the Donetsk Coal Basin, Russia and Ukraine 20
Figure 10. General Stratigraphic Section of the Coal Bearing Sequence of the Donetsk
Coal Basin, Russia and Ukraine 22
Figure 11. L'vov-Volyn Coal Basin, Ukraine 27
Figure 12. General Stratigraphic Section of the Coal Bearing Sequence of the L'vov-Volyn
Coal Basin, Ukraine 28
Figure 13. Location of Coal Production Associations and
Development of Coal-Bearing Regions in the Kuznetsk Coal Basin, Russia 31
Figure 14. General Stratigraphic Section of the Coal Bearing Sequence of the Kuznetsk
Coal Basin, Russia 32
Figure 15. Major Oil and Gas Pipelines, CIS 49
Figure B-1. Classification of Documented Reserves B-2
VIII
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LIST OF TABLES
Table 1. Natural Gas Production and Consumption in the CIS 6
Table 2. Crude Oil Production and Consumption in the CIS 8
Table 3. Hard Coal Production and Consumption in the CIS 10
Table 4. Brown Coal and Lignite Production and Consumption in the CIS 12
Table 5. Summary of Select Coal Basin Characteristics 19
Table 6. Key Characteristics of Coal Production Associations in the Donetsk
Coal Basin 23
Table 7. Methane Liberation Data From Coal Production Associations of the Donetsk
Coal Basin 25
Table 8. Key Characteristics of Mines in the L'vov-Volyn Coal Basin 29
Table 9. Methane Liberation Data From Mines of the L'vov-Volyn Coal Basin 30
Table 10. Key Characteristics of Coal Production Associations in the Kuznetsk Coal Basin . 34
Table 11. Methane Liberation Data From Coal Production Associations of the Kuznetsk
Coal Basin 35
Table 12. Summary of Estimated Methane Resources Associated With Balance Reserves
of Coal in Mines of the Donetsk, L'vov-Volyn, and Kuznetsk Coal Basins 36
Table 13. Estimated Methane Resources Associated With Coal Production Associations of
the Donetsk Coal Basin 39
Table 14. Estimated Methane Resources Associated With Mines of the
L'vov-Volyn Coal Basin 40
Table 15. Estimated Methane Resources Associated With Coal Production Associations of
the Kuznetsk Coal Basin 43
Table 16. Methane Recovery and Utilization Strategies 44
Table A-1. Energy Fuel Production, Trade, and Apparent Consumption of
Republics of the Former Soviet Union A-2
Table B-1. Comparison of Resource Classification Systems B-2
Table B-2. Comparison of U.S. and Former USSR Coal Classification Systems B-3
LIST OF BOXES
BOX 1. Methane Conditions at Selected Donetsk Coal Production Associations 24
BOX 2. Methane Conditions at Selected Kuznetsk Coal Production Associations 33
BOX 3. Thermal Drying of Coal By Use of Coalbed Methane 47
BOX 4. Generation of Electrical and Thermal Energy For Mine Use 50
BOX 5. Coalbed Methane - Fueled Desalination of Effluent Mine Waters 51
BOX 6. Refrigeration of Air for Ventilation of Deep Hot Mines in the Donbass 51
IX
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CHAPTER 1
COALBED METHANE IN
THE ENERGY ECONOMY OF THE CIS,
WITH EMPHASIS ON RUSSIA AND UKRAINE
1.1 INTRODUCTION
The former Soviet Union, now called the Commonwealth of Independent States (CIS)1, is the third
largest producer of coal in the world behind China and the United States. In 1990, an estimated 7.2
to 10.7 billion cubic meters2 (4.8 to 7.2 teragrams) of methane were emitted to the atmosphere from
coal mining operations in the CIS, which represented about 20 percent of world coal mine methane
emissions (USEPA, 1993a). Between 80 and 90 percent of these emissions were liberated by
underground mining operations, which are primarily located in the republics of Ukraine, Russia and
Kazakhstan.
Methane emissions represent the loss of a valuable energy resource and have a detrimental effect on
the earth's atmosphere. Methane is a potent greenhouse gas, second in significance only to carbon
dioxide. In addition, it tends to increase tropospheric ozone and smog formation, and may also
contribute to stratospheric ozone depletion (Kruger, 1991). Methane released by coal mines and other
activities is generally a wasted resource, opening the possibility for low cost, potentially profitable,
emission reduction opportunities. Because methane is the primary constituent of natural gas, it can be
recovered before or during coal mining operations and used as fuel for power generation or direct
industrial and residential energy needs.
Within the CIS, the republics of Russia and Ukraine account for 56 and 24 percent of the total hard coal
production (U.S. DOE EIA, 1992a), and 35 and 49 percent of the estimated methane emissions,
respectively (Zabourdyaev, 1992). Because of inefficient energy use, declining resources of hard coal,
and severe environmental problems resulting from extended mining and burning of coal, Russian and
Ukrainian officials want to reduce their republics' dependency on low grade coal and utilize more natural
gas. Increased use of natural gas would clearly help these republics meet their environmental goals
because natural gas emits less sulfur dioxide, nitrous oxide, particulates and carbon dioxide than coal
when it is burned.
'The CIS was founded on December 21, 1991, and the USSR ceased to exist on January 1, 1 992 (U.S. DOE
EIA, 1 992b). The CIS includes Armenia, Azerbaijan, Belarus, Kazakhstan, Kyrgyzstan, Moldova, Russia, Tajikistan,
Turkmenistan, Ukraine, and Uzbekistan. It does not include Latvia, Lithuania, Estonia, and Georgia, which were
part of the USSR.
2 The International System of Units (SI) and its symbols (abbreviations) are used -throughout this report.
1
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FIGURE 1. FUEL MIX OF SELECTED COUNTRIES, 1992
POLAND
HARD COAL 62%
HYDRO 1%
NUCLEAR 1%
LIGNITE
OR BROWN
COAL 14%
GAS 10%
CZECHOSLOVAKIA
GAS 19%
OIL 17%,
OIL 12%
LIGNITE OR
BROWN COAL
28%
HARD COAL
23%
HYDRO 1%
NUCLEAR
12%
FORMER USSR
GAS 45%
HARD
COAL
16%
HYDRO 5%
UCLEAR 5%
LIGNITE OR
BROWN COAL 2%
OIL 27%
GERMANY
GAS 17%
OIL 41%
HARD
LCOAL 13%
HYDRO 2%
UCLEAR
11%
LIGNITE OR
BROWN COAL 16%
JAPAN
OIL 58%
GAS 11%
HARD
COAL
15%
HYDRO
f 5%
NUCLEAR
11%
UNITED STATES
GAS 25%
OIL 41%
HARD COAL
22%
HYDRO
3%
NUCLEAR
8%
LIGNITE OR BROWN
COAL 1%
Source: U.S. DOE EIA, 1994; UNECE, 1992
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Methane contained in coal seams constitutes a new source of gas which has only in recent years been
recognized as an important energy resource. The drainage and use of methane from minable coal seams
could also increase mine safety and productivity, which is of particular importance because methane
is explosive in low concentrations in air and has been responsible for many mining accidents in the CIS
and throughout the world.
For all of these reasons, this report focuses on the potential for the republics of Russia and Ukraine to
expand the recovery of methane from the coal seams of the Donetsk, L'vov-Volyn, and Kuznetsk coal
basins. It examines the potential role of coalbed methane in the energy sectors of the Russian and
Ukrainian economies, estimates the magnitude of the coalbed methane resource in these coal basins,
outlines some promising project types, and identifies some necessary actions to encourage development
of the resource.
1.2 THE ENERGY SECTOR IN THE CIS
1.2.1 OVERVIEW
Energy Consumption and Production
Natural gas dominates the fuel mix of the CIS. It comprised 45 percent of the energy consumed in
1992 (Figure 1), followed by oil at 27 percent and coal at 18 percent. Hard coal accounted for 88
percent of the coal consumed in 1992, and lignite (including brown coal) 12 percent. It is interesting
to note that the country included in Figure 1 whose fuel mix is most similar to that of the former USSR
is the United States.
FIGURE 2: FUEL MIX OF RUSSIA
AND UKRAINE, 1992
RUSSIA
UKRAINE
GAS 46%,
HARD
COAL
15%
GAS 42%
HARD
COAL
28%
As shown in Figure 2, the fuel
mix for the republics of Russia
and Ukraine are quite similar to
the overall fuel mix of the CIS,
which is to be expected because
these republics are the
Commonwealth's largest eco-
nomic units. In Russia, natural
gas accounted for 46 percent of
total energy consumption in
1992, with oil accounting for 27
percent (U.S. DOE EIA, 1994).
Coal comprised only 18 percent
of the fuel mix; hard coal
accounted for about 83 percent
of the total energy derived from
coal, and the remainder was from
lignite. Likewise, in Ukraine
natural gas dominated the fuel mix in 1992, accounting for 42 percent of total energy consumption.
Oil represented 19 percent, and coal accounted for 29 percent, with hard coal accounting for more than
98 percent of all energy derived from coal (PlanEcon, 1993a).
. 27%
OIL 19%
Source: U.S. DOE EIA, 1994; PlanEcon, 1993a
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Although natural gas dominates the fuel mix of both Russia and Ukraine, the two republics differ greatly
in natural gas production. Russia produced 640 billion cubic meters in 1992, more than 30 percent of
which was exported to other republics and European countries. Ukraine, in contrast, produced only
21 billion cubic meters of natural gas in 1991, which satisfied less than 19 percent of its natural gas
demand, and it was forced to import an additional 90 billion cubic meters of natural gas to meet its
energy needs.
The CIS is currently the world's third largest coal producer, after the People's Republic of China and
the United States. Coal production in the USSR peaked in 1988, with total production of almost 600
million tons. Since then, however, hard coal production has declined significantly, primarily as a result
of labor disruptions, chronic equipment shortages, and difficult mining conditions. Lower coal
production has resulted in coal shortages in many parts of the CIS, which have led to lower output in
other industries (IMF, 1992).
Sectoral Energy Demand in the Former USSR
The USSR's final energy demand in 1990 was 40.1
exajoules3 (EJ) (UNECE, 1991). Sectoral end-use is
divided into three categories: industry (including
manufacturing, mining, and construction), domestic
(which includes households, agriculture, and
commercial enterprises), and transportation (includes
rail, road, water, and air)(Figure 3). In 1990, the
industrial sector used 24.3 EJ and the domestic
sector used 10.2 EJ, together accounting for 86
percent of the total energy consumed. The
transportation sector accounted for the remaining 5.5
EJ, or 14 percent of energy consumed.
FIGURE 3. ENERGY DEMAND BY SECTOR
IN THE USSR, 1990
INDUSTRY 61%
Soure*: UNECE. 1991
IESTIC 25%
TRANSPORTATION
14%
The large share of energy consumed by the industrial sector reflects the intense industrialization of
certain regions of the CIS and the low energy efficiency of the industrial sector. This inefficiency in
energy usage could be reduced through implementation of advanced technologies and transformation
of the product structure of the economy. Improving industrial energy efficiency will require major capital
expenditures, however, and will likely take several years (Bashmakov & Chupyatov, 1992).
In 1990, 50 percent of the energy used by the
industrial sector was derived from electricity and
steam, as shown in Figure 4. Direct consumption of
oil and gas accounted for 36 percent of the energy
used by the industrial sector, and solid fuel (nearly all
of which was coal) generated the remaining 14
percent. According to a UNECE (1991) forecast, by
2010, 57 percent of the energy used by the industrial
sector will be supplied by electricity and steam.
FIGURE 4. INDUSTRIAL SECTOR ENERGY
SOURCES IN THE USSR, 1990
ELECTRICITY
AND STEAM
50%
OIL AND
GAS 36%
Soure*: UNECE. 1991
COAL AND OTHER
SOLID FUELS 14%
31 EJ = approximately 1 quadrillion (1015) BTUs = 277.7 terawatts
4
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As shown in Figure 5, in 1990, 39 percent of the
domestic sector's energy came from electricity and
steam, which was derived primarily from natural gas,
but also coal, oil, and to a lesser extent, nuclear and
hydroelectric sources. Direct consumption of oil and
gas accounted for 33 percent of the domestic sector's
energy use, and solid fuels (primarily coal) comprised
the remaining 28 percent.
The transportation sector (Figure 6) is fueled primarily
by oil (88 percent); natural gas contributes one
percent to the fuel mix for a total oil and gas share of
89 percent. Electricity and steam account for 11
percent of the energy used by the transportation
sector. These proportions are not expected to change
substantially over the next twenty years (UNECE,
1991).
FIGURE 5. DOMESTIC SECTOR ENERGY
SOURCES IN THE USSR, 1990
ELECTRICITY
AND STEAM
39%
OIL AND
GAS 33%
Source: UNECE, 1081
COAL AND OTHER
SOLID FUELS 28%
FIGURE 6. TRANSPORTATION SECTOR
ENERGY SOURCES, 1990
OIL AND
GAS 89%
ELECTRICITY
AND STEAM
11%
Source: UNECE, 1891
1.2.2 PRIMARY ENERGY SOURCES OF THE
CIS
Natural Gas: The Dominant Fuel
The CIS is the largest producer, transporter,
consumer, and exporter of natural gas in the world,
producing almost 40 percent more gas than the next
largest producer, the United States. As shown in
Table 1, the CIS produced more than 778 billion cubic
meters of natural gas in 1992, which represented a
decline of 4 percent from the previous year. This is relatively stable compared to the large decline in
oil production. Natural gas production decreased between 1991 and 1992 in every republic except
Kazakhstan (up 11 percent).4
Within the CIS, Russia is the dominant natural gas producer, and in 1992, it produced more than 640
billion cubic meters of natural gas, which was more than 80 percent of total production in the CIS. Over
the last 20 years, the center of gas production has moved from the European part of Russia to western
Siberia (IEA, 1991), and currently about two-thirds of total CIS production, and 90 percent of Russian
production, comes from the Tyumen region of western Siberia. Accordingly, this region has witnessed
explosive growth in production levels during the period 1980 through 1992 (nearly 300 percent),
compared to modest growth in Uzbekistan, and declining production in Turkmenistan and Ukraine
(Sagers, 1993).
Russia's gas industry is currently controlled by GAZPROM, a government-owned company that includes
Russia, Ukraine, and Belarus as members. All other republics of the CIS, with the exception of
Turkmenistan, have expressed interest in joining and forming a joint stock company, which would form
a unified European gas distribution system extending from western Siberia to the Atlantic Ocean.
4 See Appendix A for complete energy production figures.
5
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TABLE 1. NATURAL GAS PRODUCTION AND CONSUMPTION IN THE CIS
(IN BILLION CUBIC METERS)
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
PRODUCTION
RUSSIA
462.0
503.0
544.3
589.8
615.8
640.6
642.9
640.4
UKRAINE
42.9
39.7
35.6
32.4
30.8
28.1
24.4
20.9
OTHER
138.0
143.4
147.5
147.8
149.5
146.1
143.2
117.1
TOTAL
CIS
642.9
686.1
727.4
770.0
796.1
814.8
810.5
778.4
CONSUMPTION
RUSSIA
363.4
391.8
414.3
437.2
443.7
460.7
461.0
454.4
UKRAINE
97.2
101.6
103.8
110.0
111.2
115.3
111.6
111.3
OTHER
116.1
115.7
126.5
135.9
140.2
131.0
131.6
116.8
TOTAL
CIS
576.7
609.1
644.6
683.1
695.1
707.3
709.1
682.5
Source: PlanEcon, Inc., 1992a, 1993b; U.S. DOE EIA, 1994
As discussed in the previous section, natural gas is an extremely important fuel in the CIS. Gas
consumption increased over 75 percent in the 1980's (U.S. DOE EIA, 1992b), and it provided about
45 percent of primary energy consumed in the CIS in 1992. However, natural gas consumption
decreased by 4 percent between 1991 and 1992, due to plunging economic output and rising prices
(especially outside of Russia).
The sale of natural gas currently accounts for about 40 percent of CIS hard currency earnings, with 99
billion cubic meters being exported in 1992 (PlanEcon, 1993b). Between 1991 and 1992, natural gas
exports declined slightly (5 billion cubic meters), largely as a result of declining gas consumption in
Eastern Europe and the tight gas market in Western Europe. Even at these lower levels, CIS exports
still account for about 35 percent of world natural gas exports and represent approximately 25 percent
of Europe's natural gas consumption. Russia is the CIS' largest gas exporter; in 1992, it exported more
than 31 percent of total production to other CIS republics (the largest importer being Ukraine) and
European countries. Russia's natural gas exports declined by 20 percent between 1992 and 1993,
however, largely due to decreased consumption in Ukraine and other gas-producing republics.
The former Soviet Union built a sophisticated and complex system to provide natural gas to industrial
and urban centers throughout its territory and for export. The extensive infrastructure currently
includes:
Approximately 9,000 producing wells in 200 gas and condensate fields;
300 small gas handling facilities to process gas at field sites;
6 large gas processing complexes, 4 of which are in Russia; and,
over 220,000 km of pipeline in the gas supply system of the CIS (USEPA, 1993b).
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However, a combination of rapid construction in harsh conditions, a shortfall of equipment supplies,
and conflicting incentives and policy frameworks has challenged the ability of GAZPROM to maintain
and improve the system over time. As a result, although natural gas production has so far remained
relatively stable, there is some concern about potential production levels over the next few years.
Preliminary information indicates that Russian gas production decreased about 3.6 percent between
1992 and 1993 (PlanEcon, 1993d).
Many energy specialists believe that increased use of natural gas will play an important role in pulling
the energy economy out of its slump, particularly in Russia (Oil & Gas Journal, 1992c). Natural gas
is significantly less expensive to produce, on an energy-equivalent basis, than coal because the coal
mining industry in Russia and Ukraine is hindered by inefficient mining techniques, deep mines, and
outdated or poorly maintained equipment (PlanEcon, 1992b). In addition, the CIS contains the largest
natural gas reserves in the world, with an estimated 40 percent of the world's total reserves (U.S. DOE
ElA, 1992b). Current reserve estimates are around 50 trillion cubic meters, with potential reserves
estimated to be considerably higher. Between 80 and 90 percent of these reserves are located in
Russia, with the largest fields located in the Tyumen Province of western Siberia. In addition, huge new
reserves have also been discovered in the remote Arctic regions of the Yamal Peninsula and the Barents
Sea.
There is great interest in increasing natural gas production in the CIS because of its importance within
the energy economy and its significance as an export commodity. According to Russia's "State Energy
Program for the Period up to the Year 2010", for example, the goals are to produce 860 billion cubic
meters of natural gas in 1995 and 990-1000 billion cubic meters in 2010 (FBIS, 1992a). One gas
utilization option targeted for expansion is power generation, and negotiations are underway with
several foreign companies to develop advanced technology to generate electrical power with natural
gas. In fact, much of the increase in power generation through the year 2010 is forecast to come from
new gas-fired plants, which will require additional volumes of 52 to 60 billion cubic meters annually by
the year 2000 just to meet their power and heating needs, and 110 to 120 billion cubic meters by
2010. In addition, GAZPROM officials believe that the demand for Russian gas in western Europe will
increase as supplies from Netherlands and the North Sea shelf decline (Oil & Gas Journal, 1992c).
Achieving higher gas production levels will require massive investments in the development of new
fields located in remote and difficult areas, such as the Yamal Peninsula, the Sea of Okhotsk and the
Barents Sea. Costs to develop the gas resource in the Yamal Peninsula, for example, are estimated at
$15 billion U.S. (Oil & Gas Journal, 1992c), and it is currently unclear whether these investments will
be forthcoming over the time frame necessary to meet current targets. Pipelines and processing plants
will also require upgrading and new pipelines will be necessary to link remote gas fields to consumers.
on
The CIS has a long history of oil production, and it has been the largest oil producing country in the
world since 1974, when it surpassed the United States. Oil production peaked in 1987-1988 at 624
million tons (Table 2) and has decreased every year since. In 1992, oil production was only 450 million
tons (or 72 percent) of peak production. Even at this level, however, the CIS still accounts for about
17 percent of the world's oil production (Oil & Gas Journal, 1992a).
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TABLE 2. CRUDE OIL PRODUCTION AND CONSUMPTION IN THE CIS
(IN MILLION TONS)
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
PRODUCTION
RUSSIA
542.3
561.2
569.5
568.8
552.2
516.2
461.1
395.8
UKRAINE
5.8
5.7
5.6
5.4
5.4
5.3
4.9
4.4
OTHER
47.2
47.9
49.2
50.1
49.7
49.3
49.2
49.6
TOTAL
CIS
583.0
614.8
624.3
624.3
607.3
570.8
515.2
449.8
APPARENT CONSUMPTION
RUSSIA
327.0
330.5
329.8
329.8
323.2
312.5
308.1
258.2
UKRAINE
59.9
60.3
31.3
61.1
62.0
51.0
54.6
N/A
OTHER
103.7
109.0
140.5
109.1
108.1
106.9
98.0
N/A
TOTAL
CIS
490.6
499.8
501.6
500.0
493.3
470.4
454.7
366.2
Source: PlanEcon, Inc., 1992a, 1993b, 1993d
As with natural gas, Russia is the largest oil producer in the CIS, accounting for about 90 percent of
total production in recent years. As Table 2 indicates, Russia's oil production fell from a peak of 570
million tons in 1987 to only 396 million tons in 1992. Based on preliminary data, it appears that
production for 1993 will not exceed 341 million tons (PlanEcon, 1993d).
Many factors have contributed to the rapidly declining oil production in the CIS, including:
Lack of investment capital: The most serious obstacle confronted by the CIS oil
industry has been the shortage of funds for investments and inputs in recent years
(IMF, 1992). The growth rate of investment in the oil sector declined drastically after
1987, with the actual amount of capital expenditure in 1991 at only 50 percent of the
planned level. The results of this lack of investment have been a major decline in both
new production and maintenance. According to the Russian Ministry of Economics, for
example, 62 million meters of boreholes should have been drilled in 1992, but only one-
quarter of that level was achieved (FBIS, 1993). Moreover, only 1 4 percent of existing
equipment and machinery is reported to meet world standards.
Overemphasis on short-term production targets: In many oil fields, production has been
emphasized with little regard to the overall efficiency of resource development. U.S.
experts have noted an inordinate use of reservoir damaging techniques that maximize
short-term production at the expense of overall productive potential (U.S. DOE EIA,
1992a).
Shortages of necessary equipment: The CIS oil industry also suffers from an inability
to distribute necessary supplies among the newly independent republics. The domestic
production of oil field equipment is very concentrated. Historically, more than 60
percent of all petroleum industry equipment has been manufactured in Azerbaijan, in
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factories which are now obsolete, while tubular goods have been manufactured in
Ukraine. These republics are now demanding hard currency for the equipment (Oil &
Gas Journal, 1992d), a practice which is further complicated by the fact that the prices
of oil field equipment have been freed while the price of oil remains controlled
(IMF,1992). As a result of these changes, in recent years only 60 to 70 percent of
planned supplies from domestic (inter-republic) sources have been delivered to the oil
fields, and many wells have been shut-in due to equipment shortages.
As a result of these problems, the International Monetary Fund (IMF, 1992) estimates that at the end
of 1991, 25-30 million tons of oil production was lost due to shut-in wells. In addition, it conservatively
estimates that approximately 40,000 of a total 160,000 wells were not producing. Furthermore, in the
past two years, no new oil fields have become operational.
It is unlikely that the decline in Soviet oil output can be reversed without a massive infusion of financial
and technological resources into the oil and oil service industries. Given the lack of domestic capital for
investment, the CIS is seeking assistance from various Western and other countries. The degree to
which such assistance will be forthcoming and the rate at which it will lead to increased production
is highly uncertain, however. The form it will take is also uncertain.
Oil consumption in the CIS has fallen and will continue to decline over the next few years, mainly as
a result of low or negative economic growth and the transition from subsidized to market-determined
prices. Demand could begin increasing again after 1995, however, largely as a result of increased
consumption in the transportation sector.
Hard Coal
All coal production, transportation, and distribution in the former Soviet Union was owned and operated
by the central government, with local central administrative units having responsibility for the day-to-
day management of the mines. Following the break-up of the USSR, however, management of the coal
sector has changed significantly.
Russia, for example, took control of its coal sector in 1992 and divided responsibilities between the
new Ministry of Fuel and Power and the quasi-private Russian Coal Corporation. The Fuel and Power
Ministry is responsible for drafting energy legislation, setting taxes and subsidies, and-together with
other government agencies-issuing export licenses. The Russian Coal Corporation includes a majority
of Russia's coal mines, equipment factories, and research institutes and its chief responsibility is to help
the coal production associations convert their operations to a market economy (FBIS, 1992b). In
Ukraine, much of the control of the coal sector is now in the hands of the State Committee for Coal,
which reports to the Cabinet of Ministers.
Coal accounted for 18 percent of the CIS total primary energy requirements in 1992, down from 50
percent in 1960. It is likely that coal's share of total energy consumption will decrease a little more in
the future, to be replaced largely by natural gas (U.S. DOE EIA, 1992b).
Hard coal production in the CIS is split between the European part of the country in the west (Ukraine),
with its underground bituminous coal mines, and the Asian part in the east (Siberia), where output is
divided between underground bituminous coal and low rank surface-mined coal. As shown in Appendix
A, in 1991 the republics of Russia, Ukraine, and Kazakhstan accounted for 99.5 percent of total hard
coal production in the CIS.
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In 1992, Russia produced 216 million tons and Ukraine produced 127 million tons of hard coal, down
3 percent and 1 percent, respectively, from 1991 (Table 3). Russia has traditionally exported 20 to 30
million tons of coal per year outside the CIS, including 8 to 10 million tons per year to Japan, its single
biggest customer. The majority of remaining exports have gone to Eastern European countries. The CIS
also imports a small amount of coal, mostly from Poland.
TABLE 3. HARD COAL PRODUCTION AND CONSUMPTION IN THE CIS
(IN MILLION TONS)
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
PRODUCTION
RUSSIA
254.8
263.0
267.5
273.5
268.3
257.4
222.8
215.8
UKRAINE
180.5
184.0
182.7
182.0
170.2
155.6
128.8
127.3
OTHER
134.0
140.4
144.7
144.0
138.3
130.0
128.7
124.5
TOTAL
CIS
569.3
587.4
594.9
599.5
576.8
543.0
484.5
467.6
APPARENT CONSUMPTION
RUSSIA
266.8
272.9
275.3
279.2
271.3
257.6
231.1
227.1
UKRAINE
177.6
179.7
177.1
175.0
166.1
154.5
125.4
130.4
OTHER
106.9
113.1
116.6
117.8
111.8
104.1
98.0
93.2
TOTAL
CIS
551.3
565.7
569.0
572.0
549.2
516.2
444.3
450.7
Source: PlanEcon, Inc., 1992a, 1993b, 1993d; Skochinsky 1993; Sagers 1993
1991 hard coal production total does not equal sum of parts due to differing data sources.
The sharp decline in coal production has occurred for several reasons, including labor unrest, chronic
equipment shortages, and increasingly difficult mining conditions:
Labor unrest. One of the main factors limiting coal production in recent years have been labor
problems at the coal mines. Strikes dramatically reduced coal production during the summer of
1990 and again in March and April 1991, for example, and the resulting agreements between
labor and coal production associations have contributed to further reductions in coal production
by requiring more extensive reporting of safety and health problems and shorter working hours
for the miners. A strike in the Donetsk Basin in June 1993 idled about 200 mines and spread
to other industries and regions (PlanEcon, 1993a). More recently, in Russia, back wages and
benefits for miners and unpaid subsidies for the mining industry were the reasons given for a
strike staged in September 1993 (Eastern European Energy Report, 1993).
Equipment shortages. In addition, during 1991, coal mines continued to confront serious
disruptions in equipment supply. Essential equipment such as rolled metal, pit props and long
pit timbers, mechanized complexes, ventilation pipe, shaft drainage pumps, trucks and other
equipment were not adequately supplied that year, for example, according to Moscow UGOL
(1992). Russia's shortage of coal mining equipment was highlighted by its recent decision to
allocate a portion of an IMF ($600 million USD) loan to import critical equipment and spare
parts for the coal sector. Currently, about one-third of the equipment used by Russian coal
10
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enterprises is in need of replacement while only 10 to 15 percent is at a technical level
comparable to world standards (FBIS, 1992b).
Difficult mining conditions. Mining conditions in both the western and eastern regions of the
CIS are harsh. In the west, coal lies at great depths, sometimes in excess of 1,000 meters
underground. Increasing mine depth, deteriorating equipment, and poor safety practices have
given the CIS coal sector a fatality rate almost 10 times that of the United States. The average
depth of coal mines in the CIS increased from 457 meters in 1980 to 520 meters in 1990, and
many mines are over 1000 meters deep, increasing the risk of high methane emissions. In
Siberia, moreover, conditions at surface mines are difficult due to severe winters, which require
special equipment.
The future of CIS coal production is uncertain for several reasons. First, production and transportation
costs are very high, especially as compared with natural gas. Other problems facing the coal industry
include the environmental problems associated with coal use and difficulties involved in transporting
and using coal relative to natural gas. Furthermore, coal production is heavily subsidized. In Russia, for
example, government subsidies to the industry shot up to a reported 1.3 trillion rubles per year in 1992,
representing 6 percent of the total Russian Federal budget (PlanEcon, 1993b). Because of this huge
drain on the budget, a presidential decree was signed that liberalized the prices of coal and coal
products effective July 1, 1993. At the same time, a government resolution was passed that calls for
a program of closing the most unprofitable mines. Russia's Minister of Fuels and Electric Power
announced plans to close 40 mines in 1993, which account for about half of all state subsidies going
to the coal industry. Russian coal miners protested these measures, and as a result the government
promised to continue to pay subsidies for the mining sector, use oil (rather than coal) export quotas to
pay for mine modernization, and delay mine closures until 2000 (PlanEcon, 1993d). Their closure will
leave 9.1 million tons of coal in the ground and will put roughly 47,000 miners out of work.
Ukraine also faces an uncertain future in terms of coal production. Despite an announcement by the
Cabinet of Ministers and Ukraine Gosugleprom (FBIS, 1992c) that coal production in Ukraine is
expected to increase in the future, output in the first three quarters of 1993 was down 12 percent from
the same period in 1992 (PlanEcon, 1993d). Production costs are very high in Ukraine's underground
mines, and future prospects are not promising given the difficult mining conditions. With the
combination of low state-set prices for coal and high production costs, the mines have required a large
budget subsidy for their operations for some time. As the gap between prices and production costs has
widened, the government has been spending increasing amounts of money to offset rising costs,
worsening Ukraine's enormous budget deficit (Sagers, 1993).
Brown Coal and Lignite
Eighty-eight percent of the brown coal and lignite produced in the CIS is mined in Russia (Table 4).
Historically, trade of brown coal and lignite within the republics has been negligible. In 1992, production
of brown coal and lignite in the CIS amounted to 137.3 million tons, declining 20 percent from its 1988
peak of 172.4 million tons. Because almost all of this resource is mined from open pits, the labor strife
which has affected hard coal production has had little effect. However, increased emphasis is being
placed on the environmental consequences of burning low-quality coal, which is resulting in less
demand for this low quality resource (PlanEcon, 1992a).
11
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TABLE 4. BROWN COAL AND LIGNITE PRODUCTION & CONSUMPTION
IN THE CIS (IN MILLION TONS)
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
PRODUCTION
RUSSIA
140.4
144.9
147.2
152.0
141.5
137.3
130.5
121.4
UKRAINE
8.5
9.1
9.2
9.7
10.0
10.3
9.3
6.7
OTHER
8.2
9.5
7.6
10.7
12.0
12.4
11.8
10.1
TOTAL
CIS
157.1
163.5
164.0
172.4
163.5
160.0
151.6
137.3
APPARENT CONSUMPTION
RUSSIA
140.4
144.9
147.2
152.0
141.5
137.3
130.5
117.5
UKRAINE
6.8
7.0
6.8
6.0
7.9
7.0
9.0
6.4
OTHER
8.2
9.5
8.5
10.7
12.0
12.4
11.8
9.0
TOTAL
CIS
155.4
161.4
162.5
168.7
161.4
156.7
151.3
132.9
Source: PlanEcon, Inc., 1992a, 1993b, 1993d ; Sagers, 1993
1.2.3 THE NATIONAL ENERGY STRATEGY
The republics of the former USSR collectively are the world's largest energy producers and rank second
in total energy consumption behind the United States. In addition, energy exports are the principal
source of foreign exchange earnings. As the previous sections have indicated, however, the CIS energy
sector confronts serious challenges. In recent years, the production of key energy resources has at
best been stagnant and for some resources (such as coal and oil) has actually decreased substantially.
Oil exports, which have been the country's major source of hard currency, have dropped 35 percent
from 1988 to 1991 (PlanEcon, Inc, 1992a), and coal production, which was once the highest in the
world, has fallen behind the United States and China.
The principal problems confronted by the CIS energy sector are similar to those of other countries
making the transition from planned to market economies, and they include:
Over-emphasis on short-term production targets. Traditionally, exploitation of fuel reserves has
emphasized rapid short-term expansion of production at the expense of longer term recovery
prospects. One result of this has been the eastward movement of exploitation to new, more
remote and costlier reserves, to maintain production output. As a result, existing refineries,
processing facilities, equipment suppliers, and power generating plants are inconveniently
located, increasing both transportation and production costs for coal, petroleum, natural gas,
and electricity.
Lack of flexibility^ Overall, the energy sector lacks the flexibility to respond to changing market
conditions. Energy investment is centrally allocated and does not sufficiently consider variable
conditions for different regions or individual enterprises. From a technical perspective,
12
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moreover, the storage capacity for oil and gas is inadequate to handle changes in demand,
refinery shutdowns, or pipeline bottlenecks. Electricity generating capacity is strained while
there are many delays in new construction. The existing pipeline capacity is capable of handling
the equivalent of the peak levels of the late 1980's, but the refinery capacity is down and
cannot match the load.
Subsidized energy prices. The practice of setting consumer energy prices below production
costs has led to the extremely inefficient use of energy. Russia illustrates the high energy
intensity of the CIS republics, using 70 to 100 percent more energy per unit GNP than the
United States and 250 to 300 percent more energy per unit GNP than western Europe
(Bashmakov et al, 1990). In addition, all stages of development in the mineral fuel sectorsfrom
exploration through processing and consumptioncould be improved and made more efficient
through the introduction of state-of-the-art technologies, equipment and services, as well as
the recycling of waste (Mining Annual Review, 1991).
Equipment problems. As described in previous sections, many energy production industries
must contend with outdated technology, obsolete equipment, and poor maintenance.
Clearly, substantial reforms will be necessary to improve and modernize the energy sector, and a
complete transformation will likely take several years. The current governments of the republics have
been emphasizing the changes needed in the energy sector in their reform plans. In addition to
increased energy efficiency, their goals include: emphasis on simultaneous achievement of energy and
environmental goals; enhanced nuclear safety which would include incorporating international regulatory
standards; expansion of facilities for clean, conventional thermal electricity generation; development
and utilization of clean synthetic fuels; and development of new and renewable resources (UNECE,
1991a).
The likely methods for achieving these goals will include: price liberalization (raising prices to current
world level) which would affect production, consumption, and government revenues; restructuring the
tax system to encourage investment; appointing appropriate personnel to oversee the energy industry
restructuring; initiating the privatization process in all areas of the energy sectors; reducing military
spending; and transforming military factories to serve other productive functions (Oil & Gas Journal,
1992b; Eastern European Energy Report, 1992). Increased investment in advanced technology and
equipment will also be essential to long-term success (IMF et al, 1990).
1.2.4 THE ROLE OF COALBED METHANE
Given the current condition of the energy sectors in Russia and Ukraine, and potentially other republics
of the CIS, there are likely to be many opportunities for coalbed methane to contribute to energy needs.
As mentioned previously, the CIS is a major emitter of methane from coal mining, and its coal mines
are some of the gassiest in the world.
Of course, it will not be cost-effective to completely eliminate methane emissions to the atmosphere
from coal mining. As long as coal is to be mined safely, methane will continue to be liberated to the
atmosphere in ventilation air in relatively large quantities. However, methane emissions from coal mining
can be significantly reduced through the expanded use of existing mine degasification techniques in
conjunction with programs dedicated to expanding methane utilization.
Unutilized, coalbed methane is an environmental liability because it is a potent greenhouse gas. Utilized,
it is a remarkably clean burning fuel. The burning of methane emits virtually no sulfur or ash, and only
13
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about 32 percent of the nitrogen oxides, 45 percent of the carbon dioxide, and 43 percent of the
volatile compounds emitted by coal burning (Oil & Gas Journal, 1991; U.S. EPA, 1986).
In addition, the recovery of methane will make other significant contributions to the CIS energy sector,
including:
Improved mine safety and profitability. As mentioned previously, one of the reasons for
declining coal production in Russia and Ukraine has been the increasing difficultly of mining,
particularly related to increasing mine depths. One of the principal challenges associated with
mining coal at greater depths can be higher methane concentrations, which create a safety
hazard and can greatly increase mining costs by requiring major investments in ventilation and
degasification systems. Expanded coalbed methane drainage in gassy coal mines can
frequently improve mine economics by reducing ventilation requirements and enabling the more
rapid extraction of coal.5 In addition, the sale of this recovered methane can create another
source of income for coal mines, and one which can make a substantial contribution to mine
viability. Coalbed methane drainage also reduces the potential for methane explosions and
sudden outbursts of coal and gas, improving safety conditions for miners. Improved safety
conditions would help reduce labor unrest over this issue, potentially contributing further to
improved economics.
Improved local environmental quality. In the future, the republics of the CIS intend to rely less
on low-grade hard coal and to address some the many environmental problems created by the
extensive and inefficient use of coal. As mentioned previously, coalbed methane is a clean-
burning fuel and can significantly contribute to improved local air quality where it is used to
displace the burning of poor quality coal.
An additional natural gas resource. The republics of Ukraine and Russia are both interested in
increasing natural gas use. In Ukraine, where the consumption of natural gas is far greater than
domestic production (Table 1), a comprehensive program of mine methane drainage and
utilization, combined with coalbed methane development in areas lying beyond the mines, could
supply enough energy to substantially reduce natural gas imports. Coalbed methane can play
an important role in the coal basins of Russia as well, where low-quality coal is currently being
used for many purposes.
Opportunities exist for increased recovery and utilization of methane in close conjunction with coal
mining in Russia and Ukraine6, as well as development of the coalbed methane resource independent
of mining. The technologies for producing coalbed methane, whether it is recovered in conjunction with
coal mines or produced independently, are currently well developed, although they remain to be
demonstrated in the CIS.
The following chapters of this report will describe the coalbed methane potential in selected coal basins
of Russia and Ukraine and outline potential opportunities to expand the recovery and use of this energy
resource. Suggested components of a program to encourage expanded methane recovery and
utilization from coal mines in the CIS will also be described.
5 Further study using more detailed data on mine economics and the energy economy of the CIS would be
necessary to quantify the economic benefits of increased methane recovery to mines.
6 As stated in Section 1.2.2, coal production is declining in the CIS. However, the recoverability of coalbed
methane should not be adversely affected by decreasing coal production, because in most cases methane
continues to flow into abandoned mine workings for several years after a mine is closed.
14
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CHAPTER 2
COALBED METHANE RESOURCES OF
RUSSIA AND UKRAINE
2.1 INTRODUCTION
Coalbed methane liberated during mining poses a serious threat to mine safety unless it is diluted to
non-explosive concentrations. Methane is explosive in concentrations of 5 to 15 percent in air, and in
most mines, the concentrations are maintained below one percent to ensure safety. Methane
concentrations may be reduced to safe levels by circulation of large volumes of air through the mine
workings, diluting and evacuating the methane from the mine. During mining in very gassy seams,
however, ventilation alone may be insufficient to maintain safe mining conditions. Additional methane
drainage techniques, including inseam drilling, have been developed for these purposes. These
technologies produce methane in higher concentrations before, during, and after mining and prevent
it from being emitted into the mine workings. Many of the coal seams that are mined in Russia and
Ukraine have high methane contents, and methane drainage and ventilation have been used for many
years to ensure safety.
Coalbed methane can also be a significant gas resource that may be beneficial to develop in its own
right. While various countries have long used this resource on a small scale, primarily for on-site needs
at mines, it has been only within the past decade that coalbed methane has gained widespread
recognition as a viable alternative to conventional fuels. Mining industry and government officials in
Russia and Ukraine have stated their desire to recover and utilize more coalbed methane, but funding
and technology transfer are needed in order for these countries to implement new coalbed methane
resource development projects.
The following sections of this chapter describe the available data on coal resources of Russia and
Ukraine, specifically for three coal basins within these republics: the Donetsk Coal Basin, the L'vov-
Volyn Coal Basin, and the Kuznetsk Coal Basin. The chapter also provides estimates of associated
coalbed methane resources. Most of the data on which these discussions are based were provided by
the Skochinsky Mining Institute in Lyubertsy, Russia, and by mining enterprises and research institutes
that have collected data for purposes of producing coal and maintaining mine safety. These estimates
should be considered preliminary, but mining experience in Russia and Ukraine and available data
indicate that the coalbed methane resource is large. It is clear that more detailed data collection
activities are warranted to better assess the resource and identify the most promising production
locations.
15
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2.2 COAL RESOURCES
There are four coal basins in Russia and Ukraine where hard coal is mined and which have the potential
for coalbed methane development (Figure 7). They are:
The Donetsk Basin (Donbass): located in southeastern Ukraine and western Russia;
The Kuznetsk Basin (Kuzbass) located in western Siberia;
The L'vov-Volyn Basin: located in western Ukraine, is the southeastern extension of the
Lublin Basin in Poland;
The Pechora Basin: located in northern Russia, almost entirely above the Arctic Circle.
This report will focus on the Donetsk, Kuznetsk, and L'vov-Volyn basins (the Pechora basin has not yet
been evaluated).
A stratigraphic correlation chart of coal bearing formations in three basins studied is shown in Figure
8. The L'vov-Volyn and Donetsk Coal Basins produce only from Carboniferous formations, while the
Kuznetsk Basin produces coal from both Permian and Carboniferous strata. More detailed stratigraphic
columns for each basin are shown in the following sections.
Of the three basins, the Donetsk and Kuznetsk appear to have the largest near-term potential for
coalbed methane development. Both of these regions are heavily industrialized and would have many
opportunities for coalbed methane utilization. The L'vov-Volyn region is predominantly agricultural, and
it is likely that coalbed methane use would primarily be limited to the mines. Characteristics of each
basin are summarized in Table 5 and a more detailed description of each basin is provided below.
The coal producing portion of each basin has been divided into coal production associations that are
located within, or comprise one or more of, geological-commercial regions.7 Each coal production
association contains one or more mines, and they are analogous to trade co-operatives in many
respects. The primary responsibilities of the coal production associations are:
general mine management, including procurement for the mines
achieving production targets
to address problems common to their mines, such as health and safety conditions, as
well as age and condition of the mining equipment;
negotiations with the labor force and with government agencies, and;
implementation of safety and environmental regulations.
In the following sections, data concerning coal production and methane emissions from the Kuznetsk
and Donetsk basins are presented for each coal production association. Since the L'vov-Volyn Basin
has only one coal production association, data concerning this basin are presented for each mine.
7 Geological-commercial regions comprise coal resources of similar rank and quality, and are bounded by
geological features such as folds, faults, or other geological disturbances.
16
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FIGURE 7. MAJOR COAL BASINS OF THE FORMER SOVIET UNION
L'VOV-VOLYN
BASIN
KEY TO REPUBLICS
AR: ARMENIA
AZ: AZERBAIJAN
BE: BELORUSSIA
ES : ESTONIA
QE: GEORGIA
KA:KAZAKHSTAN
Kl : KIRGHIZIA
LA: LATVIA
LI : LITHUANIA
MO: MOLDAVIA
RU: RUSSIA
TA: TADZHIKISTAN
UK: UKRAINE
UZ: UZBEKISTAN
HARD COAL BASIN (ANTHRACITE AND BITUMINOUS)
DISCUSSED IN REPORT
HARD COAL BASIN (ANTHRACITE AND BITUMINOUS)
BROWN COAL BASIN (LIGNITE)
CITY
SCALE
0 500 1000km
SOURCE: CIA, 1986
-------
FIGURE 8. STRATIGRAPHIC CORRELATION OF COAL BEARING FORMATIONS IN THE
L'VOV-VOLYN, DONETSK, AND KUZNETSK COAL BASINS,
COMMONWEALTH OF INDEPENDENT STATES
L'VOV-VOLYN COAL BASIN
DONETSK COAL BASIN
KUZNETSK COAL BASIN
cc
u
in
STAGE
FORMATION
STAGE
FORMATION
JURASSIC
TARBAGONSK
LOWER
MALTSEVSK
(NO COALS)
Z
-------
TABLE 5. SUMMARY OF SELECTED COAL BASIN CHARACTERISTICS
(1991 DATA EXCEPT WHERE OTHERWISE NOTED)
CHARACTERISTIC
DONETSK
COAL
BASIN
L'VOV-
VOLYN
COAL
BASIN
KUZ-
NETSK
COAL
BASIN
TOTAL
GENERAL CHARACTERISTICS
Basin Area ( thousand square kilometers)
Total Documented Coal Reserves (Billion Tons)"
Coal Production, (Million Tons)
Average Methane Content (mJ/T)
60
140.8
150.4
14.7
3.2
2.1
9.5
6.9
26.7
637.0
58.9
11.9
89.9
779.9
218.8
MINE DATA
Number of Mines
Number of Mines That Emit Methane
Number of Mines That Drain Methane
Number of Mines That Utilize Methane
308
211"
100
17
17
13
4
0
71
71
32
0
396
295
136
17
METHANE LIBERATION DATA
Total Methane Liberated (MmJ)
Methane Liberated From Mines With
Drainage Systems (Mm3)
Methane Captured by Drainage Systems (MmJ)
Methane Utilized (MmJ)
Specific Emissions (mj methane/ton of coal mined)
3,390.4
2,452.4
538.9
170.2
22.5
153.0
63.8
6.3
0
12.8
942.3
992.6
243.5
0
21.0
4,485.7
3,508.8
788.7
170.2
Sources: Zabourdyaev, 1992
Kozlovsky, 1 986 & 1 987
Skochinsky Mining Institute, 1993
"1990 Data
2.2.1 THE DONETSK COAL BASIN
Introduction
As shown in Figure 9, the northwestern portion of the Donetsk Coal Basin is in Ukraine, while the
southeastern portion is in Russia. Coal mining began in the basin in 1723, and as of 1991 there were
24 coal production associations operating 308 underground mines (Skochinsky, 1993). The
Carboniferous deposits contain over three hundred seams, of which one hundred seams are considered
workable. Seams vary in thickness from 0.45 to 2.5 meters, averaging 0.9 meters, and dip from
horizontal to greater than 35°. Coal mines in the Donetsk are extremely deep. Over 40 percent of the
mines have workings deeper than 700 meters, and one-third have workings deeper than 1000 meters
(FBIS, 1992d).
19
-------
ro
o
SCHEMATIC DRAWING OF THE DONBASS CARBONIFEROUS BASIN
BOUNDARY OF CARBONIFEROUS DEPOSITS
FIGURE 9. LOCATION OF PRODUCTION ASSOCIATIONS IN THE
DONETSK COAL BASIN, UKRAINE AND RUSSIA
BOUNDARY OF
COMMERCIAL DEPOSITS
EASTER
SECTION
^GREATER
/ DONBASS
KEY TO COAL PRODUCTION ASSOCIATIONS
1. PAVLOGRADUGOL
2. DOBROPOLEUGOL
3. KRASNOARMEISKUGOL
4. SELIDOVUGOL
5. DONETSKUGOL
6. MAKEEVUGOL
7. SOVETSKUGOL
8. OKTYABRUGOL
9. SHAKHTYORSKANTRATSIT
10. TOREZANTRATSIT
11., ORDZHONIKIDZEUGOL
12. ARTYOMUGOL
13. DZERZHINSKUGOL
14. LISICHANSKUGOL
15. PERVOMAISKUGOL
16. STAKHANOVUGOL
17. LUGANSKUGOL
18. KRASNODONUGOL
19. DONBASSANTRATSIT
20. ANTRATSIT
21. ROVENKIANTRATSIT
22. SVERDLOVANTRASIT
23. GUKOVUGOL
24. ROSTOVUGOL
SOUTHERN BOUNDARY OF
CARBONIFEROUS FORMATION
NOTE: Sovetskugol Coal Production Association (No. 7) has recently been
combined into Makeevugol Coal Production Association (No. 6).
0 25
*
SOURCE: KOZLOVSKY, E.. 19B6
-------
Geologic Setting
The Donetsk Coal Basin covers approximately 60,000 km2. It is located primarily in Ukraine, but
extends into Russia to the east. The basin contains Cenozoic, Mesozoic, and Paleozoic sediments with
numerous Upper Devonian, Permo-Triassic, and Jurassic igneous intrusives. The basin is a synclinorium
bounded by the Voronezh Anticline to the south and the Precambrian Ukrainian Massif to the north, and
was initially formed during the Hercynian orogeny that took place during the Carboniferous. While
mountain building was occurring, sediments that eroded from the mountains were deposited into inland
seas as huge deltas, over which coal swamps developed. This event is comparable to that of the
Appalachian orogeny, which occurred at approximately the same time in North America. Most of
Europe's mineral wealth was deposited largely as a result of the Hercynian orogeny (Dott & Batten,
1971).
The general stratigraphy of the Carboniferous coal-bearing units is shown in Figure 10. The majority
of the workable coal seams are found in sediments of the Moskovsk and Bashkirsk Series of the Middle
Carboniferous, but potentially workable coals can also be found in the Serpukhovsk Series of the Lower
Carboniferous. The total thickness of the coal-bearing strata is more than 8000 m (Nalivkin, 1960). Salt
containing evaporite layers occur in the Devonian and Permian strata deposited in the basin.
Compression associated with the latest phases of the Kimmerian and earliest phases of the Alpine
orogenies caused diapirism in the salt layers, forming domes in the northeastern part of the basin.
These domes have been mined to supply salt to the eastern part of the former Soviet Union. Oil and
gas have migrated up along the margins of these diapirs and have been trapped, making excellent
exploration targets.
Coal Reserves and Production
Total coal reserves in the Donetsk Basin, to a depth of 1800 m, are estimated at 140.8 billion tons, of
which total balance reserves8 are 108.5 billion tons (see Appendix B for comparison with western
resource classification systems). Of the total balance reserves, 35.2 billion tons are contained in the
basin's 24 coal production associations, 11.6 billion tons of which are associated with mines that are
currently active (Table 6). Industrial reserves (those designated for extraction according to mine plans)
total 8.7 billion tons. On average, Donetsk coal contains 19.2 percent ash, 6.5 percent moisture, up
to 4 percent sulfur, and has a heating value of 25.4 MJ/kg. The coal rank ranges from sub-bituminous
to anthracite, but generally is strongly caking bituminous coal.
Table 6 summarizes coal production, reserves, total methane liberated, and other key characteristics
for Donetsk Basin coal production associations. Hard coal production in the Donetsk Basin in 1991 was
150.4 million tons, of which 128.8 million tons were produced in Ukraine and 21.5 million tons in
Russia. Coal produced from the Ukrainian portion of the basin represents 93 percent of the total hard
coal production in Ukraine, which has been declining in recent years. It is likely that some of the older
and/or deeper, non-productive mines will be closed in the near future, and there are possibilities of new,
more efficient and productive mines opening up. Some of the less-productive coal production
associations are being combined with those whose production is greater. The Sovetskugol and
Makeevugol Coal Production Associations, for example, were recently merged into a single association.
8Balance reserves must meet certain criteria for seam thickness ash content. In the Donetsk Basin, these criteria
are: Brown coal: seams at least 0.6 m thick, ash content no greater than 40 percent; Long flame and gas coal and
lean caking coal: seams at least 0.45 m thick, ash content no greater than 45 percent; Lean coal and anthracite:
seams at least 0.45 m thick, ash content no greater than 40 percent (see Appendix B for a comparison of U.S.
and Russian coal classification systems).
21
-------
FIGURE 10. GENERAL STRATIGRAPHIC SECTION OF THE COAL BEARING
SEQUENCE OF THE DONETSK COAL BASIN, RUSSIA AND UKRAINE
SYSTEM
CO
O
UJ
Z
o
ffi
<
CO
UJ
or
UJ
CO
_J
Q
STAGE
CO
0
FORMATION
GORLOVSK
M
F
-j
CO
UJ
5
*
CO
CO
UJ
n
o
o
0)
6
o
o
o
(D
o
0
T"
O
LITHOLOGY
bi^
^~^_. ' ^
^-~
_._
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=
==5;
33^
gr"1-:
.-.'
^^=
I.;... .'..
^/n;;
^
-r^^_^^
~_- i =
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=^^
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r^^-
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^
COAL SEAM
THICKNESSIml
O
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6
in
d
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00
«-
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d
o
«-
o
If)
o
prr] LIMESTONE
[ I CLAYSTONE, SHALE
SANDSTONE
COAL SEAM
DISCONTINUOUS
THIN BEDDED COALS
SOURCE: Skochinsky Institute, 1992
SYSTEM
CARBONIFEROUS
SERIES
UJ
Q
Q
5
UJ
(3
H
co
BASHKIRSK
I FORMATION 1
BELOKALITVENSK
SMOLININOVSK
MOSPINSK
CO
CO
2*
Si
0
0
to
o
CO
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6
o
8
V-
10
to
LIYHOLOGY
:= -:
^;
~'"' ~
_^ ,_
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^
^=
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.
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THICKNESSIml
O
q
oj
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If)
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U)
CO
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6
If)
d
o
in
in
d
Si,
22
-------
TABLE 6. KEY CHARACTERISTICS OF COAL PRODUCTION ASSOCIATIONS IN THE DONETSK COAL BASIN (1991)
COAL PRODUCTION
ASSOCIATION
DONETSKUGOL
MAKEEVUGOL
OKTYABRUGOL
KRASNOARMEISKUGOL
KRASNQDQNUGQL
SHAKHTERSKUGOL
DONBASSANTRATSIT
LUGANSKUGOL
ARTYMOUGOL
STAKHANOVUGOL
TOREZANTRATSIT
DOBROPOLEUGOL
ORDZHONIKtDZEUGOL
PAVLOGRADUGOL
PERVOMAISKUGOL
GUKOVUGOL1
DZERZHINSKUGOL
LISICHANSKUGOL
ROSTOVUGOl'
SOVETSKUGOL
ROVENKIANTRATSIT
SELIDOVUGOL
SVERDLOVANTRATSIT
ANTRATSIT
TOTAL
AVERAGE
NUMBER OF MINES
TOTAL
27
21
12
7
14
13
13
14
10
17
21
7
12
11
8
15
9
7
31
6
8
8
11
6
308
WITH
DRAINAGE
11
18
6
4
8
6
4
8
6
5
5
4
1
1
2
2
2
5
2
0
0
0
0
0
100
COAL PRODUCTION
(MILLION TONS)
ACTIVE
MINES
15.4
8.7
5.1
7.3
6,4
4.6
5.7
6.8
5.2
5.5
6,9
5.1
4.0
11.2
2.6
7.2
2.0
2.8
14.3
2.5
6.6
5.4
5,9
3.3
150.4
MINES
WITH
DRAINAGE
9,3
8.1
3.7
5.6
5.2
3.4
1.7
3.8
3.6
2.7
0,9
3.2
0.5
0.7
1.0
0.7
1.0
2.2
0,4
0.0
0.0
0.0
o.o
0.0
57.4
BALANCE COAL RESERVES (MT)
ALL
MINES2
2340,9
1934.9
611.3
982.4
1742.8
624.1
1589.0
3644.2
523.7
1909.4
1130.3
3366.5
488.6
5048.8
1682.8
1130.3
295.0
702.9
2188,9
912.7
688.9
134.6
1024.9
470.2
35168.2
ACTIVE
MINES
1545.1
598.7
394.4
497.9
526.7
316.4
362.1
788.8
347.2
457.5
260,3
752.5
232.4
1268.1
360.9
566.9
149.9
241.2
665,7
161.0
311.4
227.2
426.4
179.6
11638.2
INDUSTRIAL
RESERVES3
1118.2
458.2
321.0
406.8
398.7
254.9
261.3
554.1
277.2
280.9
208.6
533.3
186.2
1002.9
269,2
400.7
107.8
176.5
560.4
60.6
226.7
161.4
310,7
115.9
8652.2
METHANE
LIBERATED
(Mm3)
569-2
463.8
284.4
253.2
246.2
221.7
215.9
158.7
148.0
130.2
112.9
110.4
100.9
100.2
67,4
59.1
54.2
48.7
45.4
0.0
0.0
0.0
0-0
0.0
3390.4
SPECIFIC
EMISSIONS
(mVT)
37,1
53.5
55.8
34.5
38.4
47.8
38.0
23.3
28.5
23.7
16.5
21.6
25.2
8.9
25.7
8.2
26.8
17.5
3,2
0.0
0.0
0.0
0.0
0.0
22.5
AVERAGE
METHANE
CONTENT
(mVT)
12.9
21.1
18.2
12.8
21.9
29.9
15.9
15.1
17.4
14.2
6,7
11.0
15.4
7.9
14.4
7.8
16.8
10.9
12.5
0.0
0.0
0.0
o.o
0.0
14.7
Ni
CO
1 Gukovugol and Rostovugol coat production associations are located in Russia
2 "All mines" includes both active and inactive mines
3 Industrial reserves are balance reserves designated for extraction according to mine plans
-------
Methane Liberation
Coal mines in the Donetsk Basin are some of the gassiest in the world. Of the basin's 25 coal
production associations, 19 contain mines that liberated methane in 1991 (Table 7). Nearly 3.4 billion
cubic meters of methane were liberated, with 16 percent, or 539 billion cubic meters captured by
methane drainage systems in 100 mines. Only 170 million cubic meters of this methane were used
(exclusively in boilers at the mines), thus 3.2 billion cubic meters were emitted to the atmosphere.
Methane used by the mines represents 32 percent of the total drained methane, and only 5 percent of
the total methane liberated.9
These data suggest that there are good opportunities for increased methane drainage and utilization at
Donetsk Basin mines. For example, Pochenkova, a typical mine in the Makeevugol coal production
association, drained only 20 percent of the methane it liberated in 1991, and used only about half of
the methane it drained. Conditions at some of the Donetsk coal production associations with
potentially significant project opportunities are summarized in Box 1.
BOX 1: METHANE CONDITIONS AT SELECTED DONETSK COAL PRODUCTION ASSOCIATIONS
Donetskugol is the largest coal production association in the Donetsk coal basin. In 1991, its 27 mines produced 1 5.4 million
tons of coal and liberated 569 million cubic meters of methane. Eleven mines have drainage systems in place. These mines
produced 9.3 million tons of coal and liberated 418 million cubic meters of gas, of which 110 million cubic meters (approximately
26 percent) were recovered by mine drainage systems. Only 58 percent of the drained methane (63 million cubic meters) was
used; approximately 47 million cubic meters of medium-quality gas were emitted to the atmosphere, along with 459 million
cubic meters of methane contained in ventilation air.
Makeevugol contains 21 mines, which produced 8.7 million tons of coal and liberated 464 million cubic meters of methane in
1991. Drainage systems are in place at 18 mines, which produced 8.1 million tons of coal and liberated 442 million cubic meters
of gas, of which 94 million cubic meters (approximately 21 percent) were recovered by mine drainage systems. Slightly more
than half of the drained methane (51 million cubic meters) was used; approximately 43 million cubic meters of medium-quality
gas was emitted to the atmosphere, along with 370 million cubic meters of methane contained in ventilation air.
Krasnoarmeiskugol has 7 mines which, in 1991, produced 7.3 million tons of coal and liberated 253 million cubic meters of
methane. Four mines have drainage systems in place. These mines produced 5.6 million tons of coal and liberated 220 million
cubic meters of gas, of which 71 million cubic meters (approximately 32 percent) were recovered by mine drainage systems.
None of this medium quality gas was used; it was emitted to the atmosphere, along with 182 million cubic meters of methane
contained in ventilation air.
Shakhterskugol contains 13 mines, which produced 4.6 million tons of coal and liberated 222 million cubic meters of methane
in 1991. Six mines have drainage systems in place. These mines produced 3.4 million tons of coal and liberated 198 million
cubic meters of gas, of which 63 million cubic meters (approximately 28 percent) were recovered by mine drainage systems.
Only 23 percent (less than 15 million cubic meters) was used; approximately 48 million cubic meters of medium-quality gas were
emitted to the atmosphere, along with 159 million cubic meters of methane contained in ventilation air.
Luganskugol has 14 mines which, in 1991, produced 6.8 million tons of coal and liberated 159 million cubic meters of methane.
Drainage systems are in place at 8 mines, which produced 3.8 million tons of coal and liberated 134 million cubic meters of gas,
of which 35 million cubic meters (approximately 26 percent) were recovered by mine drainage systems. None of this medium
quality gas was used; it was emitted to the atmosphere, along with 124 million cubic meters of methane contained in ventilation
air.
9 Note the distinction between "liberated" and "emitted"; liberated methane is that released from the coal,
whether or not it is utilized; emissions, in the strict sense, refer to liberated methane that has not been utilized and
therefore enters the atmosphere.
24
-------
TABLE 7. 1991 METHANE LIBERATION DATA FROM COAL PRODUCTION ASSOCIATIONS OF THE DONETSK COAL BASIN
COAL PRODUCTION
ASSOCIATION
DONETSKUGOL
MAKEEVUGOL
OKTYABRUGQl
KRASNOARMEISKUGO
KRASNODONUGOL
SHAKHTERSKUGOL
DONBASSANTRATSIT
LUGANSKUGOL
ARTYMOUGOt
STAKHANOVUGOL
TOREZANTRATSIT
DOBROPOLEUGOL
ORDZHQNIKIDZEUGOL
PAVLOGRADUGOL
PBRVOMAISKUGOL
GUKOVUGOL1
DZERZHINSKUGOU
LISICHANSKUGOL
ROSTOVUGOL1
TOTALS
NUMBER OF MINE
TOTAL
27
21
12
7
14
13
13
14
10
17
21
7
12
11
8
15
9
7
31
269
WITH
DRAINAGE
SYSTEMS
11
18
8
4
8
6
4
8
6
5
5
4
1
1
2
2
2
5
2
100
METHANE LIBERATED BY MINING (Mm3)
FROM ALL MINES
BY
VENTI-
LATION
459,1
369.6
257.7
181.9
226,5
159.0
197.7
123.6
139,7
117.6
98.1
75.2
06,4
98.0
64,5
53.1
50,3
42.9
40,7
2861,5
BY
DRAIN-
AGE
110,1
94.2
26.7
71.3
19,7
62.7
18,2
35.1
8,3
12.7
14,7
35.2
4,8
2.2
2,8
6.0
3,9
5.9
4,7
538,9
TOTAL
LIBER-
ATED
569.2
463.8
284,4
253.2
246,2
221.7
215,9
158.7
148.0
130.2
112,9
110.4
100,9
100.2
67,4
59.1
54,2
48.7
45,4
3390.4
FROM
MINES
WITH
DRAINAGE
SYSTEMS
417,8
441.7
229-3
220.2
118,3
197.5
133.9
134.3
108.3
74.8
81.1
86.6
16.1
21.6
38.5
34.5
28,5
42.8
29.8
2452,4
DRAINED
METHANE
UTILIZED
(Mm')
63.3
51.4
10,5
0.0
9.5
14.5
13,1
0.0
0.0
0.0
7,9
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0,0
170,2
METHANE
EMITTED
TO
ATMOS-
PHERE
(Mm3)
505.9
412.4
273,8
253.2
239.7
207.2
202,8
158.7
148.0
130.2
105,0
110.4
100.9
100.2
87,4
59.1
64.2
48.7
45,4
3220.2
%OF
TOTAL
LIBERATE
METHANE
DRAINED
19.3
20.3
9,4
28.2
8.0
28.3
8.4
22.1
5.6
9.7
13,0
31.9
4.5
2.2
4,2
10.1
7.3
12.1
10,3
15.9
%OF
DRAINED
METHANE
UTILIZED
57,5
54.6
39.4
0.0
48,1
23.1
72.0
0.0
0,0
0.0
53.6
0.0
0,0
0.0
0.0
0.0
0,0
0.0
o.o
31,9
% OF TOTAL
LIBERATED
METHANE
UTILIZED
11.1
11.1
3,7
0.0
3.8
6.5
6,1
0.0
0.0
0.0
7,0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0,0
5.0
% SHARE
OF TOTAL
METHANE
LIBERATED
16.8
13.7
8,4
7.5
7.3
6.5
6,4
4.7
4.4
3.8
3,3
3.3
3.0
3.0
2,0
1.7
1,6
1.4
1,3
100.0
to
01
1 Gukovugol and Rostovugol coal production associations are located in Russia
SOURCE: SKOCHINSKY MINING INSTITUTE, 1993
-------
2.2.2 THE L'VOV-VOLYN BASIN
Introduction
The L'vov-Volyn Coal Basin, located in western Ukraine, is the southeastern extension of the Lublin
Coal Basin in Poland. Coal mining began in 1954 and there is currently one coal production association,
Ukrzapadugol, operating 17 mines. The average seam thickness is 0.95 m and the depth of mining
ranges from 300 to 600 m (Kozlovsky, 1987).
Geologic Setting
The L'vov-Volyn Basin is an elongated, north-south trending asymmetrical basin (Figure 11) with
numerous northwest-southeast trending horstand graben features. The main coal-bearing horizons dip
gently to the southwest; dips average 0.5 to 1 degree, and range up to 5 to 7 degrees locally. The
depth of overburden varies from 250 m in the eastern part of the basin up to 750 m in the western
part.
The stratigraphy of the coal-bearing strata is shown in Figure 12. The main coal horizons are found in
Lower Carboniferous sediments of the Serpukhovsk Stage and Middle Carboniferous sediments of the
Bashkirsk Stage. Middle Jurassic deposits unconformably overlie these Carboniferous deposits. The
total thickness of the coal-bearing sequence varies from 400 to 1200 m (Struev, et al, 1984).
Coal Reserves and Production
Total coal reserves of the L'vov-Volyn basin are estimated at 2.1 billion tons, of which 610 million tons
are balance reserves10 (Struev et al, 1984; Kozlovsky, 1987). Balance reserves of coal contained in the
basin's mines are 193 million tons. The basin is divided into two regions (northern and southern) and
has 17 operating mines, 5 in the northern region and 12 in the southern region. Reserves of the
northern region (Novovolynsk mines) are small, and mining in this region is expected to cease soon.
One of these mines, the No. 8 Novovolynsk, has been mining non-balance reserves. In the southern
region, the No. 5 Velikomostovsk, No. 7 Velikomostovsk, and No. 9 Velikomostovsk mines are also
expected to close soon, due to depleted reserves.
Coal production in the L'vov-Volyn basin was 9.5 million tons in 1991 (Table 8); this amounts to only
7 percent of the total Ukraine production, and only 2 percent of the total coal produced in the CIS. On
average, coal of the L'vov-Volyn basin contains 5-10 percent moisture, 23-42 percent ash, 36-39
percent volatile matter, 3.3-4.5 percent sulfur, and has a heating value of 32.2-34.5 MJ/kg. The coal
is predominantly long-flame, gas, gas-fat and fat coals (all high volatile bituminous - see Appendix B
for a comparison of U.S. and Russian coal classification systems). Fifty percent of the coal produced
is used for power generation, and the remaining 50 percent is sent to the Donetsk: region and used for
coking (in many cases, this coal is mixed with Russian coal to dilute the sulfur content before
coking).
10 Balance reserves must meet certain criteria for seam thickness and ash content (see Appendix B for an
explanation of the former USSR resource classification system). Balance criteria for the L'vov-Volyn Basin were
not available, but they are presumably similar to those stated for the Donetsk Basin (Section 2.2.1) and the
Kuznetsk Basin {Section 2.2.3).
26
-------
FIGURE 11. L'VOV-VOLYN COAL BASIN, UKRAINE
KEY TO MINING CONCESSION NAMES
NORTHERN REGION
1. NO. 1 NOVOVOLYNSK
2. NO. 2 NOVOVOLYNSK
3. NO. 3 NOVOVOLYNSK
4. NO. 4 NOVOVOLYNSK
5. NO. 5 NOVOVOLYNSK
8. NO. 8 NOVOVOLYNSK
9. NO. 9 NOVOVOLYNSK
SOUTHERN REGION
10. NO. 1 VELIKOMOSTOVSK
11. NO. 2 VELIKOMOSTOVSK
12. NO. 3 VELIKOMOSTOVSK
13. NO. 4 VELIKOMOSTOVSK
14. NO. 5 VELIKOMOSTOVSK
15. NO. 6 VELIKOMOSTOVSK
16. NO. 7 VELIKOMOSTOVSK
17. NO. 8 VELIKOMOSTOVSK
18. NO. 9 VELIKOMOSTOVSK
19. NO. 10 VELIKOMOSTOVSK
20. NO. 1 CHERVONOGRADSK
21. NO. 2 CHERVONOGRADSK
VLADIMIR-VOLYNSK
BOUNDARY OF
L'VOV-VOLYN BASIN
BOUNDARY OF
MINING CONCESSION
EXPLANATION
COAL BASIN
MINING CONCESSION
. MINING CONCESSION WITH DOCUMENTED
r'J4,/ METHANE EMISSIONS FROM MINE
APPROXIMATE SCALE
5 10 15
OURCE: SILINNII, V.I., 1992
20km
BOUNDARY OF MINING CONCESSION
BOUNDARY OF L'VOV-VOLYN BASIN
27
-------
FIGURE 12. GENERAL STRATIGRAPHIC SECTION OF THE COAL BEARING
SEQUENCE, L'VOV-VOLYN COAL BASIN, UKRAINE
SYSTEM
PERMIAN
CO
D
O
cr.
UJ
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KOVSK
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THICKNESS im.i,,,)
TO 100
60-90
30-80
310
92-193
35 1 5
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90-95
13-115
40-50
LITHOLOGY
- - '. . . : »
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DESCRIPTION
SANDSTONES AND SILTSYONES WITH SOME
CLAYSTONES AND INTEROEDDED COALS.
INTER8EDDED CLAYSTONES. SILTSTONES.
SANDSTONES AND LIMESTONES
ALTERNATING CLAYSTONES. SILTSTONES AND
SANDSTONES WITH INTERBEDDED LIMESTONES
AND COAL.
SANDSTONES. SILTSTONES AND CLAYSTONES
WITH INTERBEDDED HARD COALS. SOME OF
MINABLE THICKNESS.
CLAYSTONES AND SILTSTONES WITH INTEiR-
BEDDED SANDSTONES AND COALS. AND
OCCASIONAL LIMESTONES.
CLAYSTONES AND SILTSTONES WITH INTER-
BEDDED SANDSTONE. LIMESTONE AND COALS.
CALYSTONES AND SILTSTONES WITH INTER-
PARTINGS OF COAL.
ARGILLACEOUS LIMESTONE WITH PARTINGS OF
LIMESTONES AND CLAYSTONES WITH PARTINGS
OF SANDSTONE AND SILTSTONE.
LIMESTONES ALTERNATING WITH CLAYSTONE.
1 SANDSTONES AND POROUS LIMESTONES WITH 1
CLAYSTONES PARTINGS TOWARDS BOTTOM.
CLAYSTONES AND LIMESTONES UNDERLAIN BY
SOURCE: STRUEV, ET AL, 1984
28
-------
TABLE 8. KEY CHARACTERISTICS OF MINES IN
THE L'VOV-VOLYN COAL BASIN {ALL DATA ARE FROM 1991
EXCEPT BALANCE RESERVES, WHICH ARE 1990)
MINE
#10 VELIKOMOSTOVSK
#7 VELIKOMOSTOVSK
#8 VELiKOMOSTOVSK
#2 CHERVONOGRAD
#3 VELIKOMOSTOVSK
#5 VELIKOMOSTOVSK
#4 VELIKOMOSTOVSK
#6 VELIKOMOSTOVSK
#1 CHERVONOGRAD
#9 VELIKOMOSTOVSK
#2 VELiKOMOSTOVSK
#1 VELIKOMOSTOVSK
#1 NOVOVOLYNSK
#2 NOVOVOLYNSK
#5 NOVOVOLYNSK
#8 NOVOVOLYNSK11
#9 NOVOVOLYNSK
TOTAL
AVERAGE
COAL
PRODUCTION
(THOUSAND
TONS)
1,008.50
705.18
885.86
951.92
848.63
572.32
792.78
379.60
381 .42
263.17
804.83
396.76
323.76
285.07
338.72
169.36
390.92
9,498.80
BALANCE
COAL
RESERVES
(MILLION
TONS)
29.48
10.42
2.82
31.72
24.96
4.80
9.85
15.08
18.65
3.40
7.50
7.33
6.34
11.89
3.07
0.00
5.61
192.92
METHANE
LIBERATED
(Mm3)
28.02
19.73
17.92
14.90
14.82
11.87
11.86
9.02
5.64
5.57
5.31
5.20
3.15
0.00
0.00
0.00
0.00
153.01
SPECIFIC
EMISSIONS
(m3/T)
27.8
28.0
20.2
15.7
17.5
20.7
15.0
23.8
14.8
21.2
6.6
13.1
9.7
0.0
0.0
0.0
0.0
12.8
AVERAGE
METHANE
CONTENT
(m3/T)
7.3
6.0
10.0
5.7
6.9
3.0
11.4
7.2
4.6
2.9
2.5
2.4
1.0
0.0
0.0
0.0
0.0
6.9
SOURCE: SKOCHINSKY MINING INSTITUTE (1993 AND 1991b)
Methane Liberation
The twelve mines in the southern part of the basin, together with one in the northern part, emitted 153
million cubic meters of methane in 1991 (Table 9). This amount represents only 5 percent of total coal
mining methane emissions from Ukraine. Although four of the mines have methane drainage systems,
only 6 percent of all methane liberated is captured by those drainage systems, and none is utilized.
Potentially significant project opportunities exist at several mines. No. 10 Velikomostovsk, for example,
produced more than 1 million tons of coal in 1991, and emitted 28 million cubic meters of methane to
the atmosphere. Of this, nearly 3 million cubic meters (approximately 10 percent) were medium-quality
gas recovered by mine drainage systems, and the remaining 25 million cubic meters were released in
mine ventilation air. No. 4 Velikomostovksk produced 792.8 thousand tons of coal, and emitted nearly
12 million cubic meters of methane to the atmosphere. Of this, approximately 4 million cubic meters
(35 percent) were medium-quality gas recovered by drainage systems.
11 Balance reserves have been fully exploited at this mine; non-balance reserves-are now being mined
29
-------
TABLE 9. 1991 METHANE LIBERATION DATA FROM MINES
OF THE L'VOV-VOLYN COAL BASIN (1991)
MINE
#10 VELIKOMOSTOVSK
#7 VELIKOMOSTOVSK
#8 VELfKOMOSTOVSK
#2 CHERVONOGRAD
#3 VEUKOMOSTOVSK
#5 VELIKOMOSTOVSK
#4 VELIKOMOSTOVSK
#6 VELIKOMOSTOVSK
#1 CHERVONOGRAD
#9 VELIKOMOSTOVSK
#2 VELfKOMOSTOVSK
#1 VELIKOMOSTOVSK
#1 NOVOVOLYNSK
TOTAL
METHANE LIBERATED BY MINING (Mm3)
BY
VENTILATION
25.26
19.73
17.92
12.85
14.82
11.87
7.66
8.39
5.64
5.57
5.31
5.20
3.15
143.37
BY
DRAINAGE
2.76
0.00
0.00
2.05
0.00
0.00
4.20
0.63
0.00
0.00
0.00
0.00
0.00
9.64
TOTAL
LIBERATED
28.02
19.73
17.92
14.90
14.82
11.87
11.86
9.02
5.64
5.57
5.31
5.20
3,15
153.01
PERCENT
OF TOTAL
LIBERATED
METHANE
DRAINED
10.0
0.0
0.0
13.8
0,0
0.0
35.4
7.0
O.O
0.0
0.0
0.0
0.0
6.3
PERCENT
SHARE OF
TOTAL
METHANE
LIBERATED
18.3
12.9
11.7
9.7
9.7
7.8
7,8
5.9
3.7
3.6
3.5
3.4
2.1
100.0
SOURCE: SKOCHINSKY MINING INSTITUTE (1993)
2.2.3 THE KUZNETSK BASIN
Introduction
The Kuznetsk Coal Basin, also known as the Kuzbass, is the second largest coal basin in the CIS and
is located in western Siberia. Coal mining began in the mid-nineteenth century as the Trans-Siberian
railway was being developed. Kemerovo, located in the northern end of the basin, and Novokuznetsk
in the south are important industrial centers. The basin contains 25 geological-commercial regions,
10 of which do not have active mines. As of 1991, the basin contained 71 mines operated by 6 coal
production associations {Figure 13). More than 100 seams, with an average thickness of 2.5 m., are
being mined. The thickness of the overburden of the seams mined underground ranges from 300 to
800 m (Airuni, 1991).
Geologic Setting
The Kuznetsk Basin is an asymmetrical basin which occupies a large intermontane trough, flanked
by the Salarian range to the west, the Kuznetskian Altai Mountains to the east, and the Rocky Shorias
to the south (Nalivkin, 1973). The main coal-bearing horizons (Figure 14) occur in Permian-
Carboniferous sediments deposited during Balakhonsk and Kolchuginsktime, which crop out around
the perimeter of the basin. Coal seams also occur in Jurassic sediments of the Tarbagansk Series,
which were deposited in discontinuous, fold and fault bounded synclinal features in the center of the
basin. These coal deposits are predominantly brown coal with some gas and long-flame coal deposits.
30
-------
FIGURE 13. LOCATION OF COAL PRODUCTION ASSOCIATIONS IN THE
KUZNETSK COAL BASIN IN RUSSIA
SEVEROKUZBASSUGOL
BOUNDARY OF KUZNETSK COAL BASIN
BOUNDARY OF KUZNETSK COAL BASIN
L£MNSKjKUZNETSK
LENINSKUGOL
KISELEVSKUGOL
+ KUZNETSKUGOL
PROKOPEVSKGIDROUGOL
KEY TO COAL PRODUCTION ASSOCIATIONS
SEVEROKUZBASSUGOL
SEVEROKUZBASSUGOL
KISELEVSKUGOL
Oarr
OKM CACTE COAL MME*
ACTIVE UNOetOMUNOMMEIAMOOItOUn Of MNES
APPROXIMATE SCALE
0 25 50 75 100 km
PROKOPEVSKGIDROUGOL
KUZNETSKUGOL
COUKX: SKOCMNSKV HMHO TSTTTUIt. 1SS3
ANDKOZLOVIKY. 1M7
31
-------
FIGUR
1 1 COAL LAYEF
l^°^.°l CONGLOMEF
K^:\Vva SANDSTONE
rV^I~l SILTSTONE
W/flfflL INTERBEDDE
SOURCE: BIKAOOROV.
E 14. GENERAL STRATIGRAPHIC SECTION OF COAL BEARING SEQUENCE
OF THE KUZNETSK COAL BASIN, RUSSIA
IY8TEM
JURASSIC
TRIASSIC
PERMIAN |
UJ
5
TARBAGONSK
MALTSEVSK
KOLCHUGINSK ]
UB SERIES
ERUNAKOVSK |
i
| TAYLUGANSK |
in
| GRAMOTEir
LENINSK
i
i
i
O
1
o
u>
in
| 006-089
ia
cn
390-720
IUTHOLOOIC
COMPOSITION
'it?*.
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^i
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s^
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-SS-K
w
1 NUMBER OF
WORKING LAYERS
n
TOTAL THICKNESS
OF COAL (nwton)
r*
n
1KRCENTAOE
OF COAL
2.0-3.5
cn
CN
2
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s
CO
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S F=-"^l ARGILUTE, CLAYSTONE & MUDSTONE
LATE ^^^ INTERBEDDED SILTSTONES & SANDSTONES
WM^tA INTERBEDDED SILTSTONES & SHALES
lrrrrrrl INTRUSrVES
D FINE-GRAINED SANDSTONES & SHALES
ET AL. 1980
SYSTEM
PERMIAN
| CARBONIFEROUS |
2
to
KOLCHUGINSK
KHONSK
GO
S
s
I
CO
z
BALAKHONSK
UPPER
| LOWER BALAKHONSK |
FORMATION
USKATSK
KAZANKOVO-MARKINSK j
KUZNETSK
XSJLVASn 1
?
PROMEZHUTOCHNY |
ALYKAEVSK |
| MAZUROVSK
IOSTROGSK
THICKNESS (m«t*f<)
O
01
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6
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cn
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cn
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| 70-490
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COMPOSITION
tlFU!t
s*^=
-=::-s
nm
^-.-kl^
=£s
ESS
'~ -=-
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^-~-
'/////
=^ =
;
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'n/fn
///:/*/:
?0W
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rff?**"^
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NUMBER OF
WORKING LAYERS
?
6
CD
6
cn
CO
tn
(D
IO
6
TOTAL THICKNESS
OF COAL fnwteri)
CO
CN
cn
6
6
ID
in
CN
CO
CN
(N
CNJ
r*-
6
PERCENTAQE
OF COAL
0.3-8.0
IO
6
o
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to
q
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0.3-5.0 1
o
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6
32
-------
Coal Reserves and Production
Total documented coal reserves of the Kuznetsk Basin, estimated to a depth of 1800 m, are 637
billion tons, of which 548 billion tons are balance reserves.12 Of the balance reserves, 67 billion tons
are explored reserves, and 44 billion tons are estimated reserves (Kozlovsky, 1987; CIA, 1985).
Balance reserves of coal associated with the basin's six coal production associations total 16.1 billion
tons (Table 10). Production is mostly from underground mines, but surface mines also produce hard
coal in the Kuznetsk Basin. Total coal production in 1991 was 58.9 million tons, which represents
26 percent of Russia's coal production and 12 percent of the total production of the CIS. Production
has declined in recent years, primarily due to increasingly difficult mining conditions, equipment
shortages and use of outdated equipment, and increasing labor costs. Kuznetsk Basin mines are
heavily subsidized, and it is likely that the most unprofitable mines will be closed in the near future;
however, this basin remains a key source of Russia's coal and will receive continued investment.
On average, Kuznetsk hard coal contains 10.2 percent moisture, 19.0 percent ash, less than 0.5
percent sulfur, and has a heating value of 23.2 MJ/kg. Predominantly rock coal and coking coal are
mined; at one time one-fifth of all the steam coal and one-third of all the coking coal mined in the
former USSR was mined from the Kuznetsk Basin (Kozlovsky, 1987).
Methane Liberation
In 1951, the Kuznetsk Coal Basin became the first area to utilize methane drainage systems in
underground mining in the USSR. All of the active underground mines are gassy, liberating more than
1.2 billion cubic meters in 1991 (Table 11). In spite of highly gassy conditions, only 211.9 million
cubic meters (1 7 percent) of this gas were removed by drainage systems in 32 mines. All of this gas
was then emitted to the atmosphere, as none was utilized. Conditions at some of the coal production
associations with potentially significant project opportunities are summarized in Box 2.
BOX 2: METHANE CONDITIONS AT SELECTED KUZNETSK COAL PRODUCTION ASSOCIATIONS
Kuznetskugol currently operates 20 mines, which produced 24.2 million tons of coal and emitted 588 million m3 of methane to
the atmosphere in 1991. Less than ten percent of this methane was recovered by drainage before being emitted. Only ten of
the mines have methane drainage systems in place. These ten mines produced 14.8 million tons of coal and liberated 363 cubic
meters of methane, of which 57 million m3 (approximately 16 percent) were recovered by drainage. All of this medium-quality
gas was emitted to the atmosphere, along with 531 million cubic meters contained in ventilation air.
Leninskugol currently operates 9 mines, which produced 11 million tons of coal and emitted 262 million m3 of methane to the
atmosphere in 1991. Approximately 37 percent of the total methane liberated is first recovered by drainage systems before being
emitted. Eight of the nine mines have methane drainage systems. These mines produced 10.2 million tons of coal and liberated
254 million cubic meters of methane, of which 98 million m3 (approximately 38 percent) were recovered by drainage. All of this
medium-quality gas was emitted to the atmosphere, along with 164 million cubic meters contained in ventilation air.
Belovougol contains 7 mines, which, in 1991, produced 5.8 million tons of coal and emitted 104 million m3 of methane to the
atmosphere. Approximately 31 percent of this methane was recovered by drainage before being emitted. Only three of the mines
have methane drainage systems. These three mines produced 2.8 million tons of coal and liberated 96 million cubic meters of
methane, of which 32 million m3 (approximately 33 percent) were recovered by drainage. All of this medium-quality gas was
emitted to the atmosphere, along with 72 million cubic meters contained in ventilation air.
12 Balance reserves must meet certain criteria for seam thickness and ash content (see Appendix B for an
explanation of the former USSR reserve classification system). In the Kuznetsk Basin, balance criteria are: Seams
that dip 35 degrees or less: minimum thickness of 0.7 m; Seams that dip more than 35 degrees: thickness at least
0.6 m. Coal must contain no more than 40 percent ash (regardless of seam dip angle).
33
-------
TABLE 10. KEY CHARACTERISTICS OF COAL PRODUCTION ASSOCIATIONS IN THE KUZNETSK COAL BASIN (1991)
COAL
PRODUCTION
ASSOCIATION
KUZNETSKUGOL
LENINSKUGOL
PRQKOPEVSKIDRQUGOL
BELOVOUGOL
SEVEROKUZBASSUGOL
KISELEVSKUGOL
TOTAL
AVERAGE
NO.
OF
MINES
20
9
11
7
13
10
70
COAL PRODUCTION
(MILLION TONS)
ACTIVE
MINES
24<21
10.96
6.08
5.78
7.50
4.37
58,90
MINES WITH
DRAINAGE
SYSTEMS
14.80
10.19
3.06
2.81
1.55
0.14
32.55
BALANCE COAL RESERVES
(MILLION TONS)
ALL
MINES
69857
3271.4
I63a.5
778.4
1642.3
1834.9
16145.2
ACTIVE
MINES
3531.7
1558.4
1497,8
778.4
1016.1
1572.2
9954,6
INDUSTRIAL
RESERVES
2326J
911.6
724.8
593.0
480,5
683.3
5719.9
METHANE
LIBERATED
(Mm3)
587.78
261.70
145.85
103.70
90.82
50.67
1240.52
SPECIFIC
EMISSIONS
(m'/T)
24.3
23.9
24.0
17.9
12.1
11.6
21.0
AVERAGE
METHANE
CONTENT
-------
TABLE 11. 1991 METHANE LIBERATION DATA FROM COAL PRODUCTION ASSOCIATIONS OF THE KUZNETSK COAL BASIN
COAL
PRODUCTION
ASSOCIATION
KUZNETSKUGOL
LENINSKUGOL
PROKOPEVSKIDROUGO
BELOVOUGOL
SEVEROKUZBASSUGOL
KISELEVSKUGOL
TOTAL
NUMBER OF MINES
TOTAL
20
9
11
7
13
10
71
WITH
DRAINAGE
SYSTEMS
10
8
7
3
3
1
32
% OF
MINES
WITH
DRAINAGE
SYSTEMS
50
89
64
43
23
10
45
METHANE LIBERATED (AND EMITTED,
SINCE NO METHANE IS UTILIZED)
MILLION CUBIC METERS
BY VENTI-
LATION
531,22
163.83
127.09
72.06
85.83
48.62
1028.65
BY
DRAINAGE
56,56
97.87
18.76
31.64
4.99
2.05
211.87
TOTAL
687,78
261.70
145.85
103.70
90.82
50.67
1240.52
FROM
MINES
WITH
DRAINAGE
SYSTEMS
362.66
254.29
121.62
96.13
31.43
10.88
877.01
%OF
TOTAL
LIBERATED
METHANE
THAT IS
DRAINED
9.6
28.5
12.9
30.5
5.5
4.0
17.1
% SHARE
OF
TOTAL
METHANE
LIBERATED
47.4
21.1
11.8
8.4
7.3
4.1
100
CO
CJ1
SOURCE: SKOCHINSKY MINING INSTITUTE (1993)
-------
2.3 COALBED METHANE RESOURCE ESTIMATES
Preliminary estimates suggest that the coalbed methane resources associated with balance reserves
of coal contained in mines of the Donetsk, Kuznetsk, and L'vov-Volyn Coal Basins are substantial,
ranging from 627 billion to 1.1 trillion cubic meters (Table 12). Additional methane resources are
present in non-balance coal reserves and in areas beyond the boundaries of the coal production
associations and their associated mines. According to data from the former USSR Academy of
Sciences (1990) and the Eastern Mine Safety Research Institute (1992), the total estimated coalbed
methane resource contained in just the coal seams of the three basins is greater than 7.8 trillion cubic
meters. Additional methane resources are contained in the partings and strata surrounding the coal
seams. It is estimated by the above mentioned institutions that the total coalbed methane resource
contained in the three basins is more than 52.1 trillion cubic meters.
TABLE 12. SUMMARY OF ESTIMATED METHANE RESOURCES
ASSOCIATED WITH BALANCE RESERVES OF COAL IN THE DONETSK,
L'VOV-VOLYN, AND KUZNETSK COAL BASINS
COAL
BASIN
DONETSK
L'VOV-VOLYN
KUZNETSK
TOTAL
ESTIMATED METHANE RESOURCES (BILLION mj) ASSOCIATED WITH
BALANCE RESERVES OF COAL, CALCULATED ACCORDING TO:
ALL MINES
433-788
Not Available
1 94-342
627-1131
ACTIVE
MINES
144-279
1-3
1 1 9-204
INDUSTRIAL
RESERVES13
109-209
Not Available
69-120
264-486) 1 78-329
To fully evaluate the coalbed methane development potential of each coal basin, it will be
necessary to estimate coalbed methane resources and assess what percentage is recoverable
using available technologies. This effort will require detailed information on the coal reserves,
including geologic and reservoir characteristics, which would be generated by a carefully designed
exploration program.
Such information is not currently available for the coal reserves of the Donetsk, Kuznetsk and
L'vov-Volyn basins. Thus, in this report the coalbed methane resources associated with the
balance coal reserves of these basins have been estimated based on available data using two
approaches. To reflect the uncertainties associated with preparing such estimates where data are
limited, the coalbed methane resource estimates are presented as ranges. For the low end of the
range, estimates were based on the measured methane contents of coal reserves in each basin.
The high-end estimates were developed using specific emissions (i.e., the amount of methane
liberated per ton of coal mined). These methods, and the uncertainties associated with them, are
discussed briefly below.
13 Industrial coal reserves are that portion of the balance reserves that is designated for extraction according
to the mine plans and using available technology.
36
-------
Average Methane Content Method
Under this method, resource estimates were prepared using methane content data published by the
Skochinsky Mining Institute and developed for the coal resources that are expected to be mined
through 1995 or 2000, depending upon the coal basin. The Skochinsky reports contain measured gas
contents and coal reserves of each seam slated for mining. Using this data, Raven Ridge Resources
developed an average gas content, weighted on coal reserves, for each coal production association
(or active mine, in the case of the L'vov-Volyn coal basin). Methane content values were then
multiplied by the balance coal reserves of each coal production association (or mine), to estimate
coalbed methane resources.
This method should yield reasonably accurate resource estimates because it relies on measured
methane contents. There are a variety of sources of uncertainty associated with these estimates,
however, and the data on which they are based.
First, methane content data were only reported by the Skochinsky Mining Institute for
the those coal seams that are scheduled to be mined through the year 2000. Methane
contents of other coal seams, or of the same seams in other areas of the coal
production associations not included in the mine plans, may differ. This resource
estimate could thus be inaccurate to the extent that the actual average gas content
for the entire coal basin differs from the gas content of the coals expected to be
mined over the next few years.
Second, the techniques used for measurement of lost gas (unmeasured gas that
desorbs during the time that elapses from the moment the coal sample is cut from the
seam, until the moment it is sequestered in an airtight container) were not explained
to the authors. There are many techniques used for estimating lost gas, and the
optimal technique to use in any given situation depends on the depth from which the
coal sample is taken, the pressure conditions of the reservoir, and the way in which
the methane is contained in the coals. Details concerning sampling methods and
reservoir characteristics were not available. As a result, it is not clear how accurate
the reported measured gas content data are or how they compare to gas content data
developed in the U.S.
Specific Emissions Method
The second method for estimating coalbed methane resources has been used by the Skochinsky
Mining Institute. It relies on the specific methane emissions associated with coal mining, which refers
to the volume of methane liberated per unit weight of coal mined during a given time period (in this
case, one year), commonly expressed in cubic meters per ton. Specific emissions can be calculated
for any coal production association or mine by dividing total methane liberation by coal production.
To prepare the resource estimates, the specific emissions of a given coal production association (or
mine, in the case of the L'vov-Volyn Basin) were multiplied by the balance coal reserves of that coal
production association (or mine) to yield the estimated methane resource associated with those coal
reserves.
The specific emissions method can be useful for the most preliminary of estimates. However, it can
lead to inflated resource estimates in that it includes methane contained in the entire coal bearing
package, rather than just the potential target coal seams. This method can also potentially
overestimate resources when adjacent coal seams included in the coal resource estimate are the
source of some of the methane that is emitted into the mine workings during mining. Where this
37
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occurs, the resource estimate may be "double counted" (i.e., the weighted average of the gas
liberated during mining would include the gas from the adjacent minable seams and the target seam,
but would not consider that some of the methane would be depleted from the resource).
2.3.1 COALBED METHANE RESOURCES OF THE DONETSK BASIN
The coalbed methane resources associated with the balance coal reserves of all mines in Donetsk coal
basin are estimated to range from 430 to 790 billion cubic meters. Of these resources, an estimated
140 to 280 billion cubic meters of methane are associated with the coal contained in active mining
areas and 109 to 210 billion cubic meters are associated with the basin's industrial coal reserves (i.e.,
those scheduled for mining).
Additional methane resources are associated with non-balance reserves of coal, as well as with coal
resources located beyond the boundaries of the coal production associations. According to the former
USSR Academy of Sciences (1990) the total estimated methane resources in the coal seams in the
Donetsk basin are 1.2 trillion cubic meters, and the total estimated methane resources contained in
the basin (including the coal seams, partings, and surrounding strata) are 25.4 trillion cubic meters.14
If these estimates are accurate, the coalbed methane resources contained in the coals account for
less than five percent of the total methane resources, indicating that there are potentially numerous
other types of prospective gas reservoirs within the basin including conventional stratigraphic and
structural traps. The methane resources in coal and other strata could be produced if a program of
pre-mining drainage or stand-alone development is initiated.
Table 13 summarizes the coalbed methane resource estimates prepared for different coal production
associations and types of coal resources in the Donetsk coal basin. As mentioned previously, the low
end of the ranges was estimated using the "Average Methane Content" method.15 The average
methane contents shown in Table 13 were calculated using gas content values (determined by
desorption measurements) published by the Skochinsky Mining Institute (1991 a) for each coal seam
identified for mining through the year 2000. These values were multiplied by the various types of coal
reserves (shown in Table 6) to estimate coalbed methane resources. The high end of the ranges was
estimated using the "Specific Emissions" method. To prepare these estimates, the specific methane
emissions were multiplied by the various types of coal reserves.
2.3.2 COALBED METHANE RESOURCES OF THE L'VOV-VOLYN BASIN
The coalbed methane resources associated with the balance coal reserves of all nnines in the L'vov-
Volyn coal basin are estimated to range from 1.0 billion to 3.3 billion cubic meters. Since coal
resource data for all mines and for industrial reserves were not available, methane resource estimates
could not be calculated for these categories.
Additional methane resources are associated with non-balance reserves of coal, as well as with coal
resources located beyond the boundaries of the mines ("reserve regions"). Based on average gas
contents calculated from data supplied by the Skochinsky Mining Institute (1993 and 1991b), and
coal reserve data contained in Struev et al (1984), it is estimated that these additional methane
resources may amount to 1.9 billion cubic meters of methane.
14 These are volumetric estimates, i.e, based on the area and gas content of the strata
15 The only exception is the Rostovugol Coal Production Association, whose average methane content
(12.5 cubic meters/ton) is higher than its specific emissions content (3.2 cubic meters/ton).
38
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TABLE 13. ESTIMATED METHANE RESOURCES ASSOCIATED WITH COAL
PRODUCTION ASSOCIATIONS OF THE DONETSK COAL BASIN
COAL PRODUCTION
ASSOCIATION
DONETSKUGOL
MAKEEVUGOL
OKTYABRUGOL
KRASNOARMEISKUGOL
KRASNODONUGOL
SHAKHTERSKUGOL
DON BASSANTRATSIT
LUGANSKUGOL
ARTYMOUGOL
STAKHANOVUGOL
TOREZANTRATSIT
DOBROPOLEUGOL
ORDZHONHCIDZEUGOt
PAVLOGRADUGOL
PERVOMAISKUGOL
GUKOVUGOL1
DZERZHtNSKUGOL
LISICHANSKUGOL
ROSTOVUGOL1
TOTAL
AVERAGE
AVERAGE
METHANE
CONTENT
(m3/T)
12.9
21.1
18.2
12.8
21.9
29.9
15.9
15.1
17.4
14.2
6.7
11.0
15.4
7.9
14.4
7.8
16.8
10.9
12.5
14.7
SPECIFIC
EMISSIONS
37.1
53.5
55.8
34.5
38.4
47.8
38.0
23.3
28.5
23.7
16.5
21.6
25.2
8.9
25.7
8.2
26,8
17.5
3.2
22.5
ESTIMATED METHANE RESOURCES (BILLION CUBIC
METERS) ASSOCIATED WITH BALANCE RESERVES
OF COAL
ALL MINES
30.2 - 86.9
40.8 - 103.5
11.1 - 34.1
12.6 - 33.9
38.2 - 66.9
18.7 - 29.8
25.3 - 60.4
55.0 - 84.9
9.1 - 14.9
27.1 - 45.3
7.8 - 18.7
37.0 - 72.3
7.5 - 12.3
39.9 - 44.9
24.2 - 43.3
8.9 - 9.3
5.0 - 7.9
7.7 - 12.3
7.0 - 27,4
433.1 -788.9
ACTIVE MINES
19.9 - 57.3
12.6 - 32.0
7.2 - 22.0
12.6 - 33.9
11.5 - 20.2
9.5 - 15.1
5.8 - 13.8
11.9 - 18.4
6.0 - 9.9
6.5 - 10.8
1.7 - 4.3
8.3 - 16.3
3.6 - 5.9
10.0 - 11.3
5.2 - 9.3
4.4 - 4.7
2.5 - 4.0
2.6 - 4.2
2.1 - 8.3
144.0 -278.7
INDUSTRIAL
RESERVES
14.4 - 41.5
9.7 - 24.5
5.8 - 17.9
5.2 - 14.0
8.7 - 15.3
7.6 - 12.2
4.2 - 9.9
8.4 .- 12.9
4.8 - 7.9
4.0 - 6.7
1.4 - 3.4
5.9 - 11.5
2.9 - 4.7
7.9 - 8.9
3.9 - 6.9
3.1 - 3.3
1.8 - 2.9
1.9 - 3.1
1.8 - 7.0
108.6 - 209.4
' Gukovugol and Rostovugol Coal Production Associations are located in Russia
SOURCE: SKOCHINSKY MINING INSTITUTE, 1993 AND 1991 a
Table 14 summarizes the coalbed methane resource estimates prepared for different mines in the
L'vov-Volyn Coal Basin. As mentioned previously, the low end of the range was estimated using the
"Average Methane Content" method. The average methane contents shown in Table 14 were
calculated using gas content values (determined by desorption measurements) published by the
Skochinsky Mining Institute (1991 b) for each coal seam identified for mining by the year 1995. These
values were multiplied by the balance coal reserves (shown in Table 8) to estimate coalbed methane
resources. The high end of the range was estimated using the "Specific Emissions" method. To
prepare these estimates, the specific emissions associated with each mine were multiplied by its coal
reserves.
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TABLE 14. ESTIMATED METHANE RESOURCES ASSOCIATED WITH
MINES OF THE L'VOV-VOLYN COAL BASIN (1991)
MINE
10 VELJKOMOSTOVSK
#7 VELIKOMOSTOVSK
#8 VELIKOMOSTOVSK
#2 CHERVONOGRAD
#3 VELIKOMOSTOVSK
#5 VELIKOMOSTOVSK
#4 VELIKOMOSTOVSK
#6 VELIKOMOSTOVSK
#1 CHERVONOGRAD
#9 VELIKOMOSTOVSK
#2 VELIKOMOSTOVSK
#1 VELIKOMOSTOVSK
#1 NOVOVOLYNSK
TOTAL
AVERAGE
AVERAGE
METHANE
CONTENT
(m3/T)
7.3
6.0
10.0
5.7
6.9
3.0
11.4
7.2
4.6
2.9
2.5
2.4
1.0
6.9
SPECIFIC
EMISSIONS
(m3/T)
27.8
28.0
20.2
15.7
17.5
20.7
15.0
23.8
14.8
21.2
6.6
13.1
9.7
12.8
ESTIMATEED
METHANE
RESOURCES
(Mm3)
ASSOCIATED
WITH BALANCE
RESERVES
OF COAL
215 - 820
63 - 292
28 - 57
181 - 498
1 72 - 436
14 - 99
112 - 148
109 - 359
86 - 276
10 - 72
19 - 50
18 - 96
6 - 62
1,033 -3,264
SOURCE: SKOCHINSKY MINING INSTITUTE (1993 AND 1991b)
2.3.3 COALBED METHANE RESOURCES OF THE KUZNETSK BASIN
The coalbed methane resources associated with balance coal reserves of all mines in the Kuznetsk
coal basin are estimated to range from 194 to 342 billion cubic meters. Of these resources, an
estimated 119 to 204 billion cubic meters of methane are associated with the coal contained in active
mining areas and 69 to 120 billion cubic meters are associated with the basin's industrial coal
reserves (i.e., those scheduled for mining).
Additional methane resources are associated with non-balance reserves of coal, as well as with coal
resources located beyond the boundaries of the coal production associations. According to the
Eastern Mine Safety Research Institute, the total estimated methane resources contained in coal
seams of the Kuznetsk Basin are 6.6 trillion cubic meters, and the total estimated methane resources
contained in the basin (including the coal seams, partings, and surrounding strata) are 26.7 trillion
cubic meters.16 If these estimates are accurate, the coalbed methane resources contained in the coals
of the basin account for less than 25 percent of the basin's total methane resources.
16 These are volumetric estimates, i.e., based on the gas content and area of the strata
40
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Table 15 summarizes the coalbed methane resource estimates prepared for different coal production
associations and types of coal resources in the Kuznetsk coal basin. As mentioned previously, the
low end of the ranges was estimated using the "Average Methane Content" method.17 The average
methane contents shown in Table 15 were calculated using gas content values (determined by
desorption measurements) published by the Skochinsky Mining Institute (1991c) for each coal seam
identified for mining through the year 1995. These values were multiplied by the various types of coal
reserves (shown in Table 10) to estimate coalbed methane resources. The high end of the ranges was
estimated using the "Specific Emissions" method. To prepare these estimates, the specific emissions
associated with each mine were multiplied by its coal reserves.
TABLE 15. ESTIMATED METHANE RESOURCES ASSOCIATED WITH COAL
PRODUCTION ASSOCIATIONS OF THE KUZNETSK COAL BASIN
COAL PRODUCTION
ASSOCIATION
KUZNETSKUGQi
LENINSKUGOL
PROKOPEVSKJDROUGOL
BELOVOUGOL
SEVEROKUZBASSUGOL
KISELEVSKUGOL
TOTAL
AVERAGE
AVERAGE
METHANE
CONTENT
(m3/T)
13.3
9.4
11.7
13.1
12.4
11.1
11.9
SPECIFIC
EMISSIONS
24.3
23.9
24.0
17.9
12.1
11.6
21.0
ESTIMATED METHANE RESOURCES (BILLION
CUBIC METERS) ASSOCIATED WITH BALANCE
RESERVES OF COAL
ALL MINES
93.0 - 169.8
30.8 - 78.2
19.1 - 39,2
10.2 - 13.9
1 9.9 - 20.4
20.4 - 21.3
193.9 - 342.3
ACTIVE MINES
47.0 - 85.8
14.6 - 37.3
17.5 - 36.0
10.2 - 13.9
12.3 - 12.6
17.5 - 18.2
119.4 - 203.5
INDUSTRIAL
RESERVES
30.9 - 56.5
8.6 - 21.8
8.5 - 17.4
7.8 - 10.6
5.8 - 6.0
7.6 - 7.9
69.4 -120.0
SOURCE: SKOCHINSKY MINING INSTITUTE, 1993 AND 1991c
17 The only exception is Severokuzbassugol, whose average methane content (12.4 m3) is higher than its
specific emissions (12.1 m3).
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CHAPTER 3
COALBED METHANE RECOVERY AND UTILIZATION
POTENTIAL IN RUSSIA AND UKRAINE
3.1 COALBED METHANE RECOVERY
Many opportunities for increased recovery of coalbed methane exist in Russia and Ukraine. Nearly
4.5 billion cubic meters of methane were liberated from coal mining activities in the Donetsk,
Kuznetsk, and L'vov-Volyn coal basins in 1991 (Table 5). Of the 396 mines currently operating in
these three basins, 136 mines, or 34 percent, had methane drainage systems in 1991. Drainage
systems at these mines recovered 740.7 billion cubic meters, or 17 percent, of the methane liberated
by mining, but only 170 million cubic meters (3.8 percent of total liberated) were utilized, resulting
in methane emissions of over 4.3 billion cubic meters. Methane that is currently being drained but
then vented to the atmosphere could now be used rather than wasted, and significantly more gas
could be available for utilization with an integrated approach to methane recovery in conjunction with
mining operations.
Reduction of the methane concentration in mine ventilation air for safety reasons is a prime concern
in gassy coal mines throughout the world. This can be accomplished by increasing ventilation, or by
decreasing the amount of gas liberated into the mine workings from the coals. Increased ventilation
can be achieved by increasing the size of the fans or adding additional ventilation shafts. As the
amount of methane liberated per ton of coal mined increases, the capacity of the ventilation system
must also increase. Experience elsewhere has shown that there are economic limits to the amount
of methane that can be removed by ventilation systems alone, and there are no economic benefits
to simply venting methane to the atmosphere. Expanded methane drainage can be a profitable means
of reducing the methane concentration in ventilation air, in that ventilation requirements are reduced,
coal can be more rapidly extracted, and that gas recovered by drainage is often of saleable quality.
3.1.1 METHANE DRAINAGE METHODS
There are several techniques for recovering methane in conjunction with coal mining. The optimal
choice among these methods depends on site specific conditions, including:
the thickness and depth of the targeted seam;
the amount of methane contained in the coals;
the number of mined seams;
the efficiency of the ventilation system.
Table 16 summarizes methane recovery and use options, and shows the support technologies that
are necessary to apply these techniques.
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TABLE 16. SUMMARY OF OPTIONS FOR REDUCING METHANE EMISSIONS FROM COAL MINING
Considerations
Recovery Techniques
Support
Technologies
Gas Quality
Use Options
Availability
Capital Requirements
Technical Complexity^
Applicability
Methane Reduction*
Enhanced Gob Well
Recovery
In-Mine Boreholes
Vertical Gob Wells
In-Mine Drills and/or
Basic Surface Rigs
Compressors,
Pumps, and other
support facilities
Medium Quality
(11-29MJ/m3)
(300-800 Btu/cf)
(approx. 30-80%
CH4)
On-Site Power
Generation
Gas Distribution
Systems
Industrial Use
Currently Available
Low
Low
Widely Applicable
Site Dependent
Up to 50%
Pre-Mining
Degasification
Vertical Wells
In-Mine Boreholes
In-Mine Drills and/or
Advanced Surface
Rigs
Compressors, Pumps,
and other support
facilities
High Quality
(32-37 MJ/m3)
(900- 1000 Btu/cf)
(above 90% CH4)
Chemical Feedstocks
in addition to those
uses listed for
medium quality gas
Currently Available
Medium/High
Medium/High
Technology, Finance,
and Site Dependent
» Up to 70%
Ventilation Air Utilization
Fans
Surface Fans and Ducting
Low Quality
«1% CH4; usually below
0.5%)
Combustion Air for On-
Site/Nearby Turbines and
Boilers
Requires Demonstration
Low/Medium
Medium/High
Nearby Utilization
Site Dependent
10-90% recovery
Integrated Recovery
combined strategies
All Techniques
All Technologies
Ability to Optimize Degasification
using Combined Strategies
All Qualities
All Uses
Currently Available
Medium/High
High
Technology, Finance, and Site
Dependent
80-90% recovery
w
* These reductions are acheivable at specific sites or systems
Source: U.S. EPA, 1993b
-------
Russian and Ukrainian scientists are among the early pioneers in the development of methane
drainage techniques, and tend to use pre-mining degasification and gob well recovery methods. It is
important to note that pre-mining recovery in the CIS is done just months before the seam is to be
mined, unlike in the U.S., where some mines recover methane several years in advance of mining.
Under the CIS approach, the only gas drained is that contained in the coal panel targeted for mining.
The principal methods of pre-mining recovery currently in use in the CIS are:
drainage of the seams from boreholes drilled from the surface;
drainage from in-seam boreholes drilled from within the mine workings, and;
drainage from cross-measure boreholes drilled from within the mine workings into the
strata surrounding the coal seam.
Concentrations of methane in the gas mixture drained from surface boreholes in the CIS range from
30 to 90+ percent.18 Concentrations of methane drained from in-seam and cross-measure boreholes
average 40 to 50 percent, but they fluctuate greatly and can be as low as 1.5 percent, making
utilization of this gas very difficult.
Methods used for drainage of methane from gob areas at some mines include:
boreholes drilled into the sealed gob areas from the surface;
boreholes drilled into the sealed gob areas from within the mine workings, either
vertically or laterally, and;
large diameter boreholes (up to 1 m) drilled from the surface into the roadway behind
the retreating longwall.
The methane concentrations in the gas mixture obtained with surface gob recovery range from 25
to 50 percent.
Two methods that are used less frequently in all three of the basins are lateral boreholes drilled into
the seam to be mined, and downward inclined boreholes, drilled from the entryways. Lateral
boreholes are often ineffective because of the thinness of the seams and the low permeability of the
coal, which inhibits drainage of the methane at economic or timely rates. Downward inclined
boreholes are ineffective because they fill up with water which is either produced naturally in the
course of mining, or is piped down from the surface for use in mining operations.
More detailed descriptions of the principal methane recovery techniques used in each coal basin are
presented below.
The Kuznetsk Basin: Of the 71 mines in the Kuznetsk Coal Basin, 32 have methane drainage
systems. The principal systems of drainage include the use of small diameter boreholes drilled
from the surface into the coal seam targeted for mining, and large diameter boreholes drilled
from the surface into the roadway located behind the retreating longwall. The small diameter
boreholes drilled into the coal in advance of mining provide dual service by pre-draining
methane and then being converted into gob wells after mining has passed. Portable pumping
18 Concentrations as low as 30 percent exist due to leakage of air into the wellbore, and/or leaks in the
gathering system. There is no monitoring equipment in place to shut off the system-when leaks occur.
44
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stations on the surface are connected to these wells to insure the evacuation of the gas from
the gob, and can be moved to other wells as mining progresses. The large diameter boreholes
are fitted with a manifold and fan system to remove the gas that is being produced in the gob
areas. This methane is vented to the surface, which keeps it from migrating back into the
active working face area.
In many active mines of the Kuznetsk Basin, underground drainage methods have been
insufficient to drain the quantities of methane needed to meet safe mining standards. This is
due to a pressure differential in the mines caused by the conventional ventilation systems and
booster auxiliary fans. In many mines, these systems prevent efficient flow of methane into
in-mine drainage systems, which cannot create a sufficient vacuum.
Donetsk and L'vov-Volyn Basins: Of the 269 mines in the Donetsk Coal Basin, 100 have
methane drainage systems; four of the 1 7 mines in the L'vov-Volyn Coal Basin drain methane.
Because of the depth of mining, underground drainage is the preferred methane recovery
technique used in both basins. The two most widely used methods are cross-measure
boreholes drilled from the roadways into surrounding strata and boreholes drilled from the
roadways into gob areas. Underground booster pumping stations are often used to drain the
methane from the boreholes. The methane is either discharged into the ventilation system
away from the active mining areas, or pumped to a central vertical well and piped to the
surface via surface vacuum pumps.
3.1.2 OPTIONS FOR INCREASED RECOVERY
As indicated by the discussion above, a variety of methane recovery methods are used in Russia and
Ukraine, but many mines confront technical difficulties in their application. In addition, in many cases,
necessary investment capital is not available to support the development of a fully integrated system
of methane recovery. Methane recovery could be significantly improved in Russia and Ukraine through
a variety of measures applied in the near term or over longer periods.
In the near term, basic technical improvements could increase the quality and quantity of gas
recovered. Such improvements could include:
gas quality monitoring to prevent large fluctuations in methane concentration;
repair of leaks in the in-mine and surface gas gathering systems;
modified drilling and completion techniques, including hydraulic fracturing, for both in-
mine and surface drainage wells. This could also include changing the type of material
used to cement stand pipes in place and better positioning of drainage wells.
In the longer term, an integrated approach to mine drainage could maximize the recovery of methane
and improve mine profitability and safety. This approach could include recovery of methane before,
during, and after mining, both from the surface and within the mine. Table 16 summarizes the four
main methane recovery options and indicates the potential for recovery of each.
If technical programs were instituted which included the near-term improvements suggested above,
an immediate result would be reduced fluctuation of methane concentration in the gas, thereby
increasing the options for use. If all methods of recovery were implemented and coordinated with
mining activity, as much as 80-90 percent of the methane liberated during mining could be recovered.
45
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The design of an optimal methane recovery program will be determined by many factors, including
technical considerations such as mining conditions and mine safety requirements, gas quality and
quantity, economic factors, investment considerations, regional energy needs, environmental
objectives, and time considerations. In some cases, the full range of approaches could be applicable
while in others, only one or two methods would be feasible.
3.2 COALBED METHANE UTILIZATION
Increased methane recovery will not be economically and environmentally feasible unless it is
accompanied by an aggressive program to increase methane utilization. As shown in Table 5, only
170 million cubic meters of the methane drained from mines in Russia and Ukraine in 1991 were
utilized, only at mines in the Donetsk Basin, and almost exclusively in boilers. An additional 570.5
million cubic meters was captured by drainage systems only to be vented to the atmosphere. The
venting of this recovered gas, which is suitable for use as fuel in many applications, represents a
serious waste of energy. Improved methane drainage could greatly reduce this waste by increasing
the amount and quality of coalbed methane available for utilization.
The best utilization options for methane from coal mines will vary from region to region, depending
on the quality and quantity of the gas and local energy markets. In the Donbass and the L'vov-Volyn
Basin, coalbed methane could be used as an alternative to natural gas. Ukraine is a net importer of
natural gas so any replacement of natural gas with coalbed methane would reduce its dependence
on imports. In the Kuznetsk Basin, high-quality coal is exported out of the region while low-quality
coal is consumed locally in the domestic and industrial sectors. Thus, in this region coalbed methane
use could replace this low-quality coal consumption, which would improve local air quality. The
principal utilization options are discussed in more detail below.
3.2.1 DIRECT INDUSTRIAL USE OPTIONS
The Donetsk and Kuznetsk Basins are both heavily industrialized regions, and coal is used extensively
for steam and electrical generation. The largest consumers of energy in these regions are machine
factories, petrochemical plants, metallurgical factories, and of course the coal industry. The mining,
power, and industrial complexes which dominate both regions were originally developed with an
emphasis on large-scale production, often at the expense of efficiency, profitability, and the
environment. The sheer size of these complexes makes the task of addressing economic, social, and
environmental reforms very difficult.
Coalbed methane utilization would clearly benefit these regions by helping them meet increasing
energy needs with a less polluting, local energy source. Like conventional natural gas, coalbed
methane is an environmentally acceptable fuel because when burned, it emits virtually no pollutants
such as sulfur dioxide or particulates, and it emits much less carbon dioxide than coal and oil. Some
fuels that coalbed methane could replace are brown coal, low-quality hard coal, and coke oven gas.
Specific uses will be dependent on the conditions in the vicinity of the mines, but could include:
on-site coal drying;
on-site heating of water and air;
heating of ventilation air;
substitution for coke gas, coal, or gas in local industries.
46
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Displacement of Brown Coal and Low-Quality Hard Coal
Combined heat and power generation facilities located at mine sites, as well as commercial and
residential boilers, often use low-quality hard coal or brown coal as a fuel. These fuels can be rejected
material from coal preparation plants, sub-
quality coal that a mine does not ship to a
preparation plant, or inexpensive brown
coal mined locally that has little value on
the world market. The fuels often have low
heating value, high ash and high sulfur
content. During winter months when heat
and electrical requirements are high and
atmospheric inversions are common, air
pollution generated by these facilities can
overwhelm the surrounding communities.
Coalbed methane could readily displace the
use of these low-grade coals. In the
Donetsk Basin, some of the methane that is
recovered by drainage is already used in
boilers, but in the Kuznetsk and L'vov-
Volyn Basins, none of the methane is used
after being drained from the mines. The
availability of coalbed methane may permit
conversion of existing coal-fired boilers to
gas, reducing local pollution. Any
displacement of brown coal or low-quality
hard coal use with coalbed methane would
provide environmental benefits (Box 3).
BOX 3: THERMAL DRYING OF COAL WITH
COALBEP METHANE
At many mines, drying of coal at coal preparation plants is
accomplished by using low quality coal to heat air that is
circulated through the coal to remove surface moisture. A
preparation plant visited in L'vov-Volyn used high sulfur coal
for thermal drying, and is now being required to install sulfur
removal systems on the smokestacks. The cost of the
additional equipment is high and may be prohibitive. As an
alternative, the large quantities of methane emitted from
nearby coal mines could be used for this purpose. The
circumstances described here are not unusual, and similar
situations are found in each of the basins that were studied.
Most of the coal preparation plants are owned by a coal
trading company to which the raw coal is sold. The trading
company then sells the washed coal to power plants or other
consumers, leaving only the lowest quality unwashed or
reject coal for the preparation plant to use for its energy
needs. The methane produced by the nearby coal production
associations could be used for generation of the thermal
energy requirements by direct firing of the methane, which
would have substantial local and global air quality benefits.
Displacement of Coke-Oven Gas
In 1991, an estimated 11.3 billion cubic meters of coke-oven gas were produced in the Donetsk
region. Unlike in the U.S., much of the coke gas is transported to off-site users. Information
concerning consumption by sector was unavailable. It has been estimated, however, that 10 percent
or more of the coke-oven gas is being vented or underutilized. No information on coke-oven gas
production or consumption was available for the other study regions.
The majority of coke-oven gas is produced as a by-product of the conversion of coal to coke for use
in metallurgical industries. As heavy industry in the region declines, however, coke oven gas
production will also decrease. Present consumers of coke-oven gas will need to identify alternative
gas fuels, such as coalbed methane, to meet their energy needs.
Coke-oven gas and methane recovered by coal mines can have similar calorific values. Thus, as
production of coalbed methane increases at mines, it could be transported via the existing coke-oven
gas pipelines, and over time, it may be possible to phase out the off-site transportation of coke-oven
gas and replace it with coalbed methane. It should be recognized, however, that there is a limit to
the distance that mine drainage gas of this quality can be economically transported, as compression
costs increase with distance.
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Displacement of Imported Natural Gas
In some regions, coalbed methane could displace natural gas imports, eliminating the need to
purchase or trade for natural gas. For example, methane emissions from mines in the L'vov-Volyn
Basin and Ukrainian portion of the Donetsk Basin were nearly 3.3 billion cubic meters in 1991. If the
quality of the recovered coalbed methane can be improved, this gas could displace natural gas
imported into these regions, as the infrastructure for natural gas transportation and utilization is
already in place.
3.2.2 NATURAL GAS PIPELINE SYSTEMS
Coalbed methane that is produced in sufficient quantity and quality can be transported in natural gas
pipeline systems to end-users. Several U.S. coal mines have been able to do this with methane
recovered during coal mining, and it may also be possible at some coal mines in Russia and Ukraine.
Coalbed methane drained from surface wells in advance of mining should be pipeline quality, and it
may be possible to produce pipeline-quality methane from gob wells as well.
The feasibility of this methane utilization option depends on the availability of the pipeline
infrastructure to transport the methane. In general, Russia and Ukraine have well developed pipeline
systems (Figure 15), although some regions are bypassed. The Donetsk and Kuznetsk regions are
heavily industrialized and natural gas is an important source of energy in these areas, which indicates
that the required pipeline infrastructure may already be in place. The L'vov-Volyn region, in contrast,
is less industrialized and may have a more limited infrastructure. Thus, the most attractive utilization
options may be to use recovered methane at mines or affiliated industries.
In all three regions, it will be necessary to evaluate the adequacy of existing infrastructure on a site-
specific basis during project development. The issues that should be investigated include the energy
value of the gas vs. transmission costs (i.e., the economics of compression); the proximity of the
production site to gas markets; and the life of the resource.
3.2.3 POWER GENERATION OPTIONS
Currently, there are only 17 mines in the Donetsk Basin that utilize coalbed methane, and all of them
use it in boilers at the mine site. No mines in the L'vov-Volyn or Kuznetsk regions utilize coalbed
methane. Opportunities exist for the generation of electricity and steam at mine power plants;
electrical power is used at all coal mines and thermal heat is supplied to the surrounding communities
for district heating. Currently, these mines generate the majority of their electricity and steam from
coal. Coalbed methane could displace the burning of coal which pollutes, and, in regions such as the
Donetsk Basin, is in increasingly short supply. Several power generation options are discussed below.
Converting Boilers to Intermittent Use of Gas
It may be possible to expand the use of coalbed methane in mine boilers, so that they consume only
gas or burn it intermittently with hard coal (Box 4). The idea of intermittent, rather than year-round
gas use may be particularly attractive for larger power plants in the event that there is not enough
coalbed methane to meet year-round needs. Intermittent gas use would allow the power plant to take
advantage of low summer prices for methane, while maintaining the flexibility of being able to burn
coal when gas is unavailable or more expensive. Additional benefits for plant operations would include
reduced furnace corrosion and erosion, reduced soot and slag formation, less ash disposal, reduced
need for electrostatic precipitators, and reduced NOx emissions (Fay et al, 1986).
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FIGURE 15. MAJOR OIL AND GAS PIPELINES, COMMONWEALTH OF INDEPENDENT STATES
to
EXPLANATION
OIL PIPELINE
GAS PIPELINE
CITY
MAY REPRESENT MULTIPLE LINES
SCALE
0 500 1000km
SOURCE: CIA, 1985
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BOX 4: GENERATION OF ELECTRICAL AND THERMAL ENERGY FOR MINE USE
In the Donetskugol Production Association, there is a mine that uses coalbed methane as fuel for its boiler plant. Eight years
ago, the boiler used methane exclusively, but since then the amount of methane being produced by the mine's drainage
program has decreased from 2,200 cubic meters per hour to around 800 cubic meters per hour. Presently this boiler uses
methane when it is available and switches to low quality coal when the quantity or quality of the gas is insufficient.
Although overall production of gas has decreased over the years, large amounts of gas are periodically encountered during
mining, indicating that a comprehensive methane drainage program could potentially result in higher gas production.
Furthermore, this mine is one of eleven in the coal production association that have methane drainage programs in place. Only
five of these mines use any recovered methane in their boiler plants, however; the rest rely entirely on low quality coal for
fuel. Even in the years when methane production was high, no attempt was made to fuel these other boilers with methane
due to lack of capital for investment in the required surface facilities to collect, process, and transport the gas to the boiler.
Similar situations exist in most of the coal basins in the CIS. Many mines need to heat water for space heating and
bathhouses. In addition, it is essential and to heat mine ventilation air during the winter months in many areas, particularly
in the Kuznetsk Basin. With installation of improved methane drainage systems to recover gas of reliable quantity and quality
and access the necessary capital to invest in surface equipment, methane from the coal mines could be readily used for these
purposes.
Gas Turbines
Gas turbine generators are widely used in the United States by electric utilities to provide power
during peak demand times. Gas turbines are more efficient than coal-fired generators, cost less to
install, and are available in a large range of sizes. This allows for the addition of smaller increments
of capacity to handle peak consumption, rather than investing in larger, capital intensive coal-fired
units that would be underutilized.
In addition, gas turbine exhaust is a good source of waste heat which can be utilized to generate
steam in a heat recovery boiler. When this steam is used for process or district heating, this process
is known as cogeneration. If this steam is used in a turbine generator for additional electrical power
production, the system is known as a combined cycle. If the steam were injected into the hot gases
flowing to the thermal turbine, the system would be known as a steam injected turbine (STIG). All
of these uses improve the thermal efficiency of the system.
Gas turbines fueled by coalbed methane recovered from mining gob areas have been successfully
operated in England, Australia, Germany, and China, and have undergone experimental use in the
United States (Sturgill, 1991). In most of these cases the waste heat is being recovered from the
turbine stack for use in an auxiliary thermal process. These projects range in size from about 3 to 20
MW, which can frequently supply a significant portion of the mine's electrical needs. Gassy coal
mines in Russia and Ukraine should have no problem producing similar amounts of power (Boxes 5
and 6).
The Gas Institute in Kiev, Ukraine has initiated preliminary research on development and utilization
of turbine generators fueled with methane mixtures ranging from 20-100 percent (Karp, 1992). To
date, this technology has not been used at coal mines in Russia or Ukraine, however.
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BOX 5: COALBED METHANE- FUELED DESALINATION OF EFFLUENT MINE WATERS
One potentially attractive use of coalbed methane is powering mine water desalination plants. Approximately 870
million cubic meters of saline water are pumped from the coal mines of the Donetsk Basin annually. In addition to salts,
the water contains heavy metals and lubricants used in the mining equipment. Approximately 80 percent of this volume
is discharged into the rivers and the remaining 20 percent, which is likely the least saline, is used by the mines. The
water that is discharged into the rivers is typically pumped from the mines into settling ponds to separate silt and other
suspended materials. However, these ponds are not lined, which allows seepage of water into the underlying strata.
Virtually no desalination of mine waters is performed before allowing discharge into the rivers. As a result of these
practices, fresh groundwater supplies have been contaminated and there is a shortage of fresh water in the Donetsk.
Mines in the Donetsk are investigating various water treatment and disposal options, and desalination plants represent
one potentially attractive option. Ultimately, water clean-up is likely to be the responsibility of the mining production
association, and since the mining enterprise owns the coalbed methane recovered in conjunction with mining, the use
of the methane as an energy source for an integrated desalination system may make these types of projects
economically feasible. An integrated desalination plant that discharges no saline water is very energy intensive. A
zero salt discharge system couples a reverse osmosis system with a brine distillation plant to optimize the recovery
of fresh water. This design requires both electrical and thermal energy for operation, suggesting that the feasibility
of a coalbed methane fueled cogeneration system powering an integrated desalination plant is worth investigation.
BOX 6: REFRIGERATION OF AIR FOR VENTILATION OF DEEP HOT MINES IN THE DONETSK BASIN
A problem common to many of the mines in the Donetsk Basin is the increase in heat associated with the increase in
depth of mining. As an example, the Zasyadko mine operated by the Donetskugol Production Association is currently
mining at depths of 1250 m where the temperature of the rocks is in excess of 50 degrees C. To comply with
regulations and for the workers in the mine to be able to do their job effectively, the temperature of the ventilation air
in the mine must be lowered to 30 degrees C.
A facility is currently being constructed at this mine to cool the ventilation air, using low-quality coal to generate
electricity to power the refrigeration system. This system will require three 1600 kW motors to supply 9 million kcal/hr
of cooling capacity. An alternative to the coal-fired generator would be a new efficient gas turbine, which could
generate the 4800 kW needed to power the three motors. Assuming 25 percent efficiency for the turbine, a total
of 65.4 million BTU/hr would be required, or 2067 cubic meters of pure methane per hour. Currently, 6000 cubic
meters per hour of 38 percent methane is being recovered at the mine. All of this gas is being vented from the mine
drainage system into the atmosphere. It is estimated that 5440 cubic meters per hour of this recovered methane would
be needed to power the refrigeration system.
Internal Combustion Engines
Internal combustion (1C) engines can generate electrical power utilizing medium to high-quality
coalbed methane. Typical capacities of 1C engines range from several kilowatts to several megawatts.
These sizes are much smaller than gas turbines and would be more compatible with the production
of coalbed methane from a single well. As an example, a 1 MW 1C engine would require
approximately 10,000 cubic meters of methane per day. 1C engines can use medium-quality gas (30-
80 percent methane) such as that produced by pre-mine drainage and surface gob recovery.
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Internal combustion engines are modular in design and require little specialized expertise to install and
maintain. Due to their small sizes, they can be relocated easily if the gas supply is depleted.
Previously, variations in gas quality caused some problems with the use of mine gas in 1C engines,
but with modern integrated control systems it now appears possible to accommodate these
fluctuations.
Plans have been announced to install small mobile diesel generators at two mines in the Kuznetsk
Basin, with plans to eventually install seven in this region, and a total of 30-40 annually in Russia.
These motors have been designed by the Skochinsky Institute (Serov, 1992) and are built in a
converted military factory in Russia. Presently, the design allows the use of a mixture of 10 percent
diesel and methane with concentrations ranging from 5 to 100 percent. The final design will be able
to use exclusively methane. These generators have an electrical generating capacity of 2500 kW plus
heat.
Cofirinq with Natural Gas
Cofiring is the concurrent firing of natural gas and coal in a boiler (with the gas typically providing
5 to 15 percent of the thermal input). The only modifications required to the boiler are the addition
of gas supply piping, gas igniters, and warmup guns. Cofiring with gas has many potential benefits,
including reduced sulfur dioxide emissions, greater fuel flexibility (allowing the utilization of lower
cost, lower quality coal without the affects of increased pollutants), improved plant capacity factor,
and production of saleable fly ash. Cofiring can be accomplished at very low capital costs and with
no technological risk. At some power plants in the United States, cofiring has reduced operating costs
by millions of dollars per year (Vejtasa et al, 1991; CNG, 1987). In addition, if for any reason natural
gas was no longer available, the boiler could continue to operate entirely on coal.
3.2.4 VENTILATION AIR UTILIZATION OPTIONS
Currently, there are no demonstrated uses for methane contained in mine ventilation air, due to its
low concentration. Numerous studies have examined the possibilities of purifying this gas, but with
currently available technology, the expense is prohibitive. However, as technology progresses, it may
become economically feasible to enrich the gas contained in mine ventilation air using some of the
methods discussed in Section 3.2.5.
At present, the best options for utilization of ventilation air appear to be as part of the fuel mixture
in steam boilers or gas turbine generators. The ventilation air could supply all or most of the
combustion air required, while the methane in the air would supply a portion of the needed fuel.
In order to assess the potential for use of ventilation air, the following issues should be investigated
(Energy Systems Associates, 1991):
the number of ventilation shafts, flow rates, and volume of air leaving each shaft;
the methane concentration in the ventilation air;
the distance between the ventilation shafts and the mine power plants, and;
detailed information on power plant characteristics, annual output, efficiency, and
projected power utilization.
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The feasibility of using recovered ventilation air must also be evaluated. If it is feasible, the use of
ventilation air should be considered as part of an integrated methane drainage program. It is important
to note that for this to be economic, the targeted boiler should be within about 2 km. of the source
for the ventilation air. In cases where it is not feasible for either technical or economic reasons,
integrated recovery programs should be employed to reduce the amount of methane that is liberated
by the ventilation systems. Studies indicate that with aggressive use of these three methane drainage
systems, up to 90 percent of the methane could be recovered without use of ventilation air.
Ventilation Air Use in Coal-Fired Boilers
Preliminary technical feasibility analyses have indicated that ventilation air from mines could be
transported within many types of power plants through the existing boiler air ducts and coal circuits
without modifying the stability or safety of the boiler operation (Energy Systems Associates, 1991;
Bain, 1991). Methane contained in the ventilation air would be consumed in the boiler, delivering heat
to the process. The amount of heat would depend on the concentration of methane. With typical
boiler efficiencies and air requirements, if the ventilation air contained 0.5 percent methane, it would
supply approximately 7 percent of the boiler's energy, and if the ventilation air contained 1 percent
methane would supply 14 percent of the boiler's energy.
In addition, if methane were used to generate a percentage of a boiler's energy, reducing the amount
of coal required, the results would be less coal handling, lower pulverizer power requirements and
maintenance costs, reduced furnace slagging, lower ash handling, and lower emissions of
particulates, SOx, and NOx (Pilcher et al, 1991). As coal-fired boilers are currently used at every mine
in the coal basins studied, the possibilities of utilizing ventilation air in the boilers should be
investigated.
Ventilation Air Use in Gas Turbines
The combustion air requirements of a gas turbine correlate to its generating capacity. The combustion
air required for simple cycle gas turbines is approximately 10 m3/hr of air per kilowatt of installed
turbine capacity. This calculation is based on manufacturer operating and design data for turbines in
the 1 to 100 MW size range. Slightly lower air flows are required for the more complex combined
cycle plants. This flow is about three times the flow required for steam boilers as a result of turbine
cooling requirements. The turbine temperature should be sufficient to totally combust the methane
in ventilation air, providing heat to the process.
At 0.5 percent methane, ventilation air would supply about 15 percent of the heat to the turbine.
When the ventilation air contains 1 percent methane, approximately 30 percent of the turbine energy
can be derived from this waste product. Obviously, this would significantly increase the viability of
a gas turbine operation.
Currently, there are no known turbines operating in the three specified coal regions of Russia and
Ukraine. If turbines are installed to use medium quality mine gas, the possibility of also using mine
ventilation air should be considered.
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3.2.5 GAS ENRICHMENT
Much of the 1.4 billion cubic meters of gas recovered annually by mine methane drainage systems
and then vented to the atmosphere has methane concentrations ranging from 30 to 50 percent. This
gas is not considered "pipeline quality" (more than 95 percent methane). Furthermore, its
concentration may decrease over the life of the producing well. If a more aggressive mine drainage
and gob gas recovery program is pursued in the mines presently operating, the amount of recovered
gas with methane concentrations above 50 percent could likely increase.
To the extent that pipeline quality gas is required for various uses, it may be necessary to enrich the
gas recovered by mine methane recovery systems. Current research suggests that two types of gas
enrichment technologies are best suited to small-scale applications, such as coal mines, typically
producing less than 300,000 cubic meters of gas per day. These technologies are pressure swing
adsorption and membrane gas separation.
Cost comparisons among various processes are complex and situation dependent. Because these
technologies do not have a long history, actual costs are not yet well established. However, the
following cost approximations provide general guidelines. To enrich a feed gas containing 70-80
percent methane to pipeline quality, operating costs range from approximately $0.01 /m3 to $0.04/m3
USD for pressure swing adsorption systems, and from $0.03/m3 to $0.09/ms USD for membrane gas
separation systems (Sinor, 1992; Meyer et al, 1990). The cost of enrichment of a mixture of 30-50
percent methane is not known and should be researched where such projects are considered for coal
mines. It is important to bear in mind that, because this gas would otherwise be vented to the
atmosphere, the cost of the feed gas is effectively zero, enhancing the economics.
Pressure Swing Adsorption
In this process, a molecular sieve is used to remove nitrogen or carbon dioxide from the feed gas
stream. The process proceeds in stages. The gases are separated by an adsorbent bed, which
selectively adsorbs either the unwanted gases or the hydrocarbon gas under pressure. In the second
stage, a vacuum is applied to the adsorbent bed, causing the adsorbed gas to be released. By
alternately exerting pressure and placing a vacuum on the system, timing the pressure swing to take
advantage of the rate at which the gases are selectively adsorbed, gas separation is achieved.
Presently available pressure swing systems use carbon molecular sieves. Another type of molecular
sieve, zeolites, holds promise for gas separation applications. In the past, synthetic zeolites have been
used for limited gas separation applications, and a recent research development project demonstrated
that some species of naturally occurring zeolites perform at least as well as the carbon molecular
sieve for separation of nitrogen and carbon dioxide from methane.
Membrane Gas Separation
Membrane gas separation is based on the differences in the diffusivities and solubilities of various
gases within a membrane material. The relative rate at which different gases pass through the
membrane is called the selectivity. A polymeric organic membrane system has been used for carbon
dioxide removal, and the development of a membrane system to selectively remove nitrogen from
natural gas is underway.
Membrane separation units have several features that make them attractive for gas separations.
Within the basic unit itself, there are no moving parts, membranes can be easily replaced, variations
in flow rates can be easily accommodated, and startup can be accomplished in a very short time.
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3.2.6 UNDERGROUND GAS STORAGE
Underground storage should be considered an integral part of any coalbed methane use strategy. With
storage facilities, gas can be used as demand dictates. For example, gas produced when demand is
low (such as during the summer) can be stored and used during periods of higher demand. This
strategy would also reduce the dependency on imported natural gas.
In many gas producing areas of the world, underground storage is the most common means of storing
gas to meet peak seasonal market requirements. Preferred reservoirs are porous reservoirs, including
depleted oil and gas fields as well as aqueous reservoirs. Other sites used for storage are natural and
man-made salt and rock caverns. Underground gas storage was first utilized in the United States in
1916, and today there are more than 400 storage fields with a total capacity of over 228 billion cubic
meters of gas, which is equivalent to almost half the annual U.S. gas consumption. In addition,
utilization of underground gas storage is beginning to allow capitalization of spot gas market
purchases, managing of transportation imbalances, handling of short-term standby supply needs,
enhanced oil recovery, hedging on the gas futures market, and managing of marketing and production
by producers (Thompson, 1991).
Underground gas storage could play a key role in expanding methane recovery and utilization in
Russia and Ukraine. Coalbed methane in the Donetsk Coal Basin, for example, is used only for mine-
related activities, such as heating of ventilation air and surface facilities; during the winter months,
most of the methane that is recovered is utilized, but during the summer months, much of it is
wasted. Storage facilities could help make the supply more reliable, eliminating the summer waste,
and allowing for expansion of utilization systems.
In the Kuznetsk Basin, methane is not even used at the mines. The Kuznetskugol Coal Production
Association, for example, recovered 57 million cubic meters of methane in 1991, but states that, at
any given mine, the quality and quantity of methane are not sufficiently consistent to warrant
development of utilization systems. Similar situations exist elsewhere in the Kuznetsk Basin and in
the other basins studied. In cases such as this, a mine that does not produce a sufficient methane
could join with similar mines in linking to a central gas storage facility, resulting in adequate quantities
of methane for use at the mines and perhaps beyond.
In addition to conventional storage facilities, another available option is gas storage in abandoned
hard coal mines. Two abandoned mines have been utilized for imported natural gas storage at two
locations in Belgium since the early 1980's. Criteria essential to the success of gas storage in
abandoned coal mines have been identified (Moerman, 1982) as follows:
The mine must be separated from adjacent workings by impermeable barriers.
The overburden rock must be thick enough and preferably water-bearing, to secure a
tight cap with no natural communication to the surface.
The abandoned workings must be dry, no water should be flowing into the mine.
If a selected mine meets all of these criteria, the next step in development is to identify and seal all
openings (shafts and galleries). Pipes would need to be installed through some of these seals for
future gas injection. In addition, the storage capacity of the mine and the maximum operating
pressure would have to be determined. Finally, consideration must be given to the reaction of the
rock mass to the gas, specifically, the ability of the unmined coal to adsorb any gas injected into the
mine. This phenomenon greatly enhances the ultimate storage capacity of the mine.
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The Belgian mines using this technique are described as having an impermeable Miocene clay cap
over the coal bearing strata, a water saturated zone overlying this cap, a well-understood geological
setting, and structural isolation created by faults. In addition, much of the gas stored in the Belgian
facilities is actually stored in the remaining coal through adsorption, greatly increasing the current
storage volume of the mine.
Potentially appropriate conditions for underground gas storage in mines exist in some parts of the
basins studied in Russia and Ukraine. Further evaluation would, of course, be necessary to determine
feasibility. In assessing the economic feasibility, the cost of developing facilities should be weighed
against the costs of importing and/or the transporting of natural gas, and the cost of venting valuable
coalbed methane to the atmosphere.
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CHAPTER 4
CONCLUSIONS AND RECOMMENDATIONS
FOR FURTHER ACTION
4.1 OVERVIEW
Development of coalbed methane as an integral part of the energy economies of Russia and Ukraine
will require developing and implementing comprehensive programs for resource development and
utilization. Such programs would recognize the importance of developing coalbed methane in concert
with coal extraction. As has been described in previous chapters, economic benefits to coal mining
are enhanced when methane drainage and use are improved. Many opportunities for the near-term
use of coalbed methane exist. The most likely candidates for near-term increases in coalbed methane
development are projects that will directly impact the economics of the mining industry and improve
the safety and health of miners and the surrounding community. Furthermore, regional economic
benefits, such as jobs and an increased domestic energy base, will occur as coalbed methane
recovery and use increases. As has been stated previously, coalbed methane is most valuable when
used locally by the mine from which the coalbed methane is being recovered or in nearby allied
industries. Value of the methane as a substitute for other fuels is increased when enrichment, drying,
and compression of the gas are not required. Of course, if large amounts of imported conventional
natural gas are consumed, preparation required for upgrading coalbed methane for injection into
pipelines may be a viable economic option.
There is a keen interest in coalbed methane development in both Russia and Ukraine. Agencies such
as the Ministry of Fuel and Energy of Russia and the State Coal Committee of Ukraine, numerous coal
industry research institutes, as well as several of the coal production associations of the L'vov-Volyn,
Donetsk, and Kuznetsk basins are all actively investigating opportunities to expand methane recovery
and use.19 Based on the results of this study, it is clear that the development and utilization of
coalbed methane in Russia and Ukraine, and specifically the three study regions, should be further
investigated. Mechanisms for encouraging or facilitating coalbed methane use should be evaluated,
appropriate policies and incentives should be developed, and development and utilization of coalbed
methane should be a priority in the energy sector restructuring programs of the two republics.
19 An example is the Skochinsky Mining Institute's "Methane" program, a proposed project whose goal is
development of improved techniques for coalbed methane recovery and utilization. -
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Foreign governments and international agencies, as well as foreign companies, can assist Russia and
Ukraine with this process by providing financial and technical assistance for coalbed methane
projects. Follow-up efforts to this report should be designed to inform, educate, and train the
appropriate technical experts and government personnel regarding the potential role for coalbed
methane development. Subsequent studies should evaluate the feasibility of coalbed methane
development and utilization at specific sites, ultimately leading to the implementation of
demonstration projects and/or commercial coalbed methane projects.
4.2 FOLLOW-UP TECHNICAL ASSISTANCE ACTIVITIES
4.2.1 TECHNICAL PRE-FEASIBILITY ASSESSMENTS
The first step in identifying attractive project opportunities is to prepare pre-feasibility assessments
of the applicability of several methane recovery and utilization approaches at mines and/or coal
production associations in the L'vov-Volyn, Donetsk, and Kuznetsk basins. On the recovery side, the
assessments should evaluate opportunities to expand methane recovery using pre-drainage vertical
wells, intensified in-mine drainage, and post-mining drainage using in-mine and vertical gob wells. In
assessing alternative technical approaches, the opportunity to both increase gas quantities and
improve gas quality (concentration), while at the same time decreasing the methane liberated to the
atmosphere during mining, should be evaluated. The viability of different utilization options should
also be examined. Several possible pre-feasibility assessments are detailed below.
The purpose of the pre-feasibility studies should be to examine the conditions at one or more coal
production associations or mines to determine where particular project types might be most attractive
and which types of projects would have the best applicability elsewhere in Russia and Ukraine. Based
on the results of the pre-feasibility assessments, candidate projects for more detailed feasibility
studies and development as demonstration or commercial projects could be identified.
Given the magnitude of the coal basins in Russia and Ukraine and the wide range of potential project
types, it is likely that several pre-feasibility studies could be undertaken. Depending on particular
conditions in the study areas, a wide range of projects and issues would likely be considered in
different areas. Some of the components of the pre-feasibility analyses are discussed briefly below.
Evaluation of Opportunities to Expand Methane Drainage
One of the most important issues to be examined in the pre-feasibility assessments will be the
potential to expand methane drainage, thereby increasing the amount of available fuel and reducing
methane emissions to the atmosphere. The pre-feasibility studies should examine the current methane
drainage practices employed at selected mines and evaluate the potential to expand methane
recovery, either through modifications in existing practices or introduction of new drainage
techniques.
This aspect of any pre-feasibility assessment should be undertaken by methane drainage consultants
in conjunction with in-country mining officials. Analyses would likely include a review of geologic and
other data, mining plans, methane drainage designs, and ventilation and methane drainage data. The
team would identify new methane recovery approaches that could be further evaluated and tested
during later feasibility studies.
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Evaluation of Opportunities to Expand Methane Utilization
As discussed in Chapter 3, there are many opportunities for methane utilization that should be
evaluated at the coal mines of Russia and Ukraine. These opportunities include: power generation,
chemical feedstocks, and direct use by industry and residences, as well as the use of ventilation air
as combustion air for on-site/nearby turbines and boilers.
During the pre-feasibility studies, methane utilization experts, working closely with mining officials
and other relevant local representatives (i.e., local industries, power generation facilities) would
assess the most attractive utilization opportunities in the vicinity of the selected sites. These analyses
would be conducted in conjunction with the assessment of opportunities to expand methane drainage
so as to optimize the use of as much methane liberated by the mines as possible. Based on the results
of the pre-feasibility assessments, one or more utilization options might be recommended for further
study through a feasibility assessment.
Evaluation of Gas Enrichment Opportunities
Depending upon the energy needs in the vicinity of particular mines, and the methane recovery
programs that are most feasible, it may be necessary in some areas to upgrade medium-quality
methane in order to develop uses for it.
As discussed in Section 3.2.5, two types of gas enrichment technologies may be well-suited to
enriching low-methane gas recovered by mine methane drainage systems. These technologies,
pressure-swing adsorption and membrane gas separation, have proven feasible for feed gas streams
containing 70-80 percent methane. However, the feasibility of enriching low-methane gas (30-50%
methane) has not been tested.
The need for gas enrichment should be considered as part of ongoing pre-feasibility studies, to ensure
that the most effective utilization options are identified. For sites where gas enrichment appears to
be necessary and potentially attractive, the pre-feasibility study phase would likely be followed by
preparation of a detailed feasibility study and, if warranted, a demonstration project.
Evaluation of Underground Gas Storage Opportunities
Similarly, at some sites expanded gas storage capacity may be required in order to effectively utilize
the methane that is produced by the mine. The ability to store coalbed methane can result in more
effective utilization by allowing for seasonal fluctuations in demand. Options for increasing gas
storage could include enlarging existing underground storage facilities, developing new facilities in
depleted natural gas reservoirs, and developing new facilities in abandoned mines.
Gas storage experts, working closely with local gas storage experts, should identify potential storage
sites. The need to expand gas storage in various areas should be considered during the pre-feasibility
analyses, and the most attractive gas storage options should be identified. For selected projects, the
feasibility of expanding gas storage capacity could then be evaluated in the later phases of project
development.
The technical and economic feasibility of a proposed gas storage project would need to be assessed.
One aspect of such an assessment would be a comparison of the cost of transporting natural gas
from outside the region or even outside the republic, or of using other fuels such as coal, versus the
potential benefits of expanding underground storage for coalbed methane.
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Evaluation of Water Disposal Options
When considering a coalbed methane recovery program in any region of the world, it must be
recognized that production of gas, particularly using vertical pre-drainage, often results in
coproduction of water present in the coal seams, and/or the strata adjacent to the seams. The volume
of water produced depends on the hydrogeologic characteristics of the coal-bearing formations, and
it is difficult to predict this volume when planning exploration in a new area. It is possible that coalbed
methane production in the three study regions will also result in water production, but given the
structural complexity of each of the regions, the volume of water produced could vary widely. It is
also difficult to predict the salinity of the water which may be produced, but it is likely that it will
resemble that produced by nearby coal mines.
Although it is difficult to predict how much, if any, water would be produced from coalbed methane
wells in the coal basins in Russia or Ukraine, the potential for water production and the need for
environmentally sound disposal must be an important consideration in project development.
Fortunately, there are many economically and environmentally successful water treatment and/or
disposal methods that could be applicable to the treatment of both mine water and coalbed methane
water. In cases where water quality is sufficiently high, water can be discharged to streams after
relatively simple pretreatment procedures, as is done in some coalbed methane producing regions of
the U.S. For waters of lesser quality, options include injection of saline water into wells (into
reservoirs shallower or deeper than the coal seams, depending on the circumstances); treatment of
saline water by reverse osmosis, distillation, or electrodialysis; or a combination of these methods.
These and other saline water management techniques are discussed in Wacinski et al (1992).
Historically, saline water produced from coal mines in Russia and Ukraine has been discharged into
rivers and streams with little or no treatment. Because this practice has had severe environmental and
economic consequences, programs aimed at improving management of saline mine water should be
formulated. If saline water is co-produced with coalbed methane, it would be advantageous to jointly
dispose of water produced by mines and coalbed methane wells. Some saline water treatment
systems, such as distillation plants, could be fueled by coalbed methane.
Issues related to water disposal should be considered in conjunction with the analyses undertaken
during the pre-feasibility stage related to the introduction of new methane drainage technologies. At
sites where water disposal could be required, a preliminary assessment of the most promising water
disposal options should be included in the pre-feasibility assessment. The economic and technical
feasibility of these options could then be evaluated in later stages of project development, as
warranted.
4.2.2 FEASIBILITY ASSESSMENTS
Based on the results of pre-feasibility assessments, more detailed studies that examine the technical
and economic feasibility of the most promising projects should be undertaken at selected sites. These
studies could be financed by private companies or using various U.S. government and other programs
which are available to encourage project development. The U.S. Trade and Development Agency, for
example, can finance feasibility assessments for projects that meet its criteria and are requested by
an agency of the host government.
Feasibility studies should obviously consider all issues necessary to determine if project development
is warranted. Among the important considerations will be the technical viability of the project and the
technical risks associated with the project, in terms of both the methane recovery and methane
utilization options. Further, project economics and the project's financial viability should be
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investigated. Finally, important regulatory, legal, environmental and other issues related to project
development and implementation should be examined.
In preparing feasibility studies, consultants or corporate experts should work closely with in-country
personnel from the mining community, as well as from relevant local government agencies and
industries, and national government agencies. Close cooperation will facilitate transfer of the methods
and intent of feasibility study analyses, which is an important skill to be learned as the CIS moves
toward a market economy. In addition, widespread participation during the project design and
assessment stages may help expedite the project approval and development stages for those projects
that are considered worth implementing.
4.2.3 METHANE RECOVERY TECHNOLOGY CENTERS
The establishment of one or more Coalbed Methane Recovery Technology Centers in Russia and
Ukraine could greatly contribute to the development of coalbed methane projects by addressing two
major barriers to project development in the CIS:
the lack of a CIS coalbed methane industry to serve as project partners, and;
the difficulty private companies confront with respect to gathering information about
project opportunities and identifying potential partners.
In addressing these barriers, the centers could undertake the following activities:
dissemination of information about recent accomplishments in methane recovery from
coal seams throughout the CIS, by establishing a comprehensive information collection,
publishing a technical journal and organizing seminars and workshops;
creation of a domestic industry network for information exchange and project
development, by arranging for opportunities to domestic experts to meet and exchange
information (i.e., through seminars and meetings), and;
support of the efforts of private companies to gather information and identify project
opportunities, by undertaking small research projects, arranging meetings, and
conducting important studies and investigations.
The functions of the center could be modelled after the Polish Coalbed Methane Clearinghouse, which
was established in Katowice, Poland, in 1991 by the U.S Environmental Protection Agency. The
Polish Center, which is a part of the Polish Foundation for Energy Efficiency (FEWE), has been
extremely effective in organizing a Polish coalbed methane industry and in supporting the project
development efforts of private companies.
4.2.4 TRAINING
Training programs may be necessary to educate both mining industry technical personnel and
government representatives. Technical personnel training should emphasize methane recovery,
especially pre-mine drainage from the surface, methane use, and resource assessment. Programs for
government representatives could include developing appropriate environmental and other regulatory
frameworks to ensure safe and effective implementation of methane recovery projects, legal and
economic training, training in project feasibility assessment, and training related to project approval
processes. In addition, government representatives and mine managers would likely benefit from
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training in mining economics and business management. These training programs should be developed
in conjunction with the development of the clearinghouse and other follow-up studies. Agencies
interested in providing training should work closely with appropriate Russian and Ukrainian
representatives to identify specific needs and design efficient programs.
4.3 IMPACT ASSESSMENTS
As part of the effort to further assess coalbed methane development in the three study regions, it
may be desirable to examine all potential impacts. These assessments should consider the impacts
of both expanded methane recovery at active coal mines, and coalbed methane exploitation utilizing
vertical wells in non-mining areas. They will facilitate the development of methane recovery activities
that are encouraged through this project and also those that may proceed commercially. Included in
the topics that should be considered are:
Environmental impacts - air, water, and soil quality, and natural habitats;
Socioeconomic impacts - changes in land use, employment, and economics;
Infrastructure impacts - transportation services, including pipelines.
These assessments could be prepared by international experts working closely with personnel from
the local and regional mining and government sectors. The assessments should be undertaken in a
manner that transfers the experience of preparing such impact statements to in-country personnel.
The implement and results of such assessments should be closely coordinated with the local and
national planning agencies who are developing future energy sector plans and resource development
policies.
4.4 REGULATORY ASSESSMENT
The adequacy of existing regulations, fees, and fines affecting coalbed methane development should
be evaluated. The assessment would include an examination of the structure and suitability of coalbed
methane pricing, ownership, and leasing laws. It should also include an examination of project
approval processes and permitting requirements. Environmental regulations to be evaluated include
those regarding water disposal, siting, and land rehabilitation. To accomplish these tasks, cooperation
with in-country experts will be essential as the systems in Russia and Ukraine are quite different than
in the United States. Initially, it will be important to identify potential barriers and educate local and
federal officials to the goals of the tasks.
Based on this assessment, appropriate recommendations for modifications to existing regulations, as
well as implementation of new regulations, could be made. Further, incentives for encouraging
coalbed methane development could be assessed, if it is determined that national governments want
to aggressively promote this resource.
4.5 DEMONSTRATION PROJECTS
Finally, it may be desirable to undertake demonstration projects for selected methane recovery and
utilization options, if it is determined that such projects would expedite the more rapid development
of the coalbed methane resources and effectively transfer necessary technologies. Several different
types of demonstration projects could be undertaken depending on the objectives of the international
funding agencies and national and local officials.
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Demonstration projects could be warranted, for example, for a number of technologies which are not
widely used at coal mines in other regions of the world but could be attractive in regions of the CIS.
Possible examples could include developing uses for mine ventilation air or the application of gas
enrichment technologies.
Demonstration projects might also be desirable in cases where the technologies have been applied
internationally but have not yet been used in the CIS. For these, the objective would be to effectively
transfer key technologies to in-country personnel. Some possible projects might be:
investigating various technical issues (such as appropriate completion and/or stimulation
techniques) related to methane production using vertical wells drilled in advance of
mining in a particular coal basin;
investigating the technical viability of various water disposal technologies; and/or,
investigating the technical viability of various methane utilization technologies, such as
cofiring methane with coal or the conversion of a coal-fired boiler to use methane.
Following any successful demonstration project, it is expected that widespread replication of the
project would be undertaken by the private sector. Demonstration projects should expedite project
development for those projects considered too risky or uncertain for the private sector to undertake
without some assistance. Further, demonstrations would be useful in demonstrating to the CIS
experts that certain technical options that they might be unfamiliar with or skeptical of could work
in their specific conditions. Finally, because the results of any demonstration project could be made
public, it would serve as an example to others within the CIS and internationally that various methane
recovery and use options were feasible and could generate wide interest in project development.
4.6 INVESTMENT CONSIDERATIONS
In addition to the technical requirements of project development, encouraging foreign participation
in coalbed methane development will also require resolution of issues that will affect the desirability
of investments by foreign companies. Some of these issues-such as taxation policies, repatriation
of profits, and legal frameworks for project development-are relevant to a wide range of business
opportunities in the CIS and will likely be addressed through general government initiatives to
encourage foreign investment. There are also a variety of investment issues specifically related to
coalbed methane development, however, which cannot be overlooked if the development of this
resource is to be effectively encouraged in Russia and Ukraine.
Among the critical issues specifically related to coalbed methane development are:
Ownership of the resource is presently unclear, and needs to be ascertained for both
virgin coal areas and areas where coalbed methane is being liberated as part of the
mining process.
Policies for foreign participation in resource development, in both mining and non-mining
areas, need to be developed. Presently, structures of joint ventures are not well defined,
and this must be resolved in order for investment to occur.
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Commercial incentives for coalbed methane production will be necessary to ensure
realistic pricing of the resource. Presently, coalbed methane is produced only to achieve
a reduction the amount of methane in mine ventilation air, rather than for its value as
a substitute for coal or conventional natural gas.
Permits and regulations concerning coalbed methane production are presently ill defined.
Among the matters that need to be addressed is whether the extraction of coalbed
methane falls under the jurisdiction of mining regulations, or whether it should be
subject to oil and gas industry regulations.
A number of models exist for addressing these issues related to coalbed methane development.
Poland, for example, has developed a legal and regulatory framework, as well as a system for
granting coalbed methane development concessions to foreign companies, which is successfully
encouraging development of this resource. By evaluating such existing systems, the governments of
Russia and Ukraine should be able to develop appropriate frameworks that meet their coalbed
methane development goals and encourage foreign development in the resource.
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APPENDIX A: ENERGY FUEL PRODUCTION, TRADE,
AND APPARENT CONSUMPTION OF REPUBLICS OF
THE FORMER SOVIET UNION
A-1
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TABLE A-1: ENERGY FUEL PRODUCTION, TRADE, AND APPARENT CONSUMPTION OF
REPUBLICS OF THE FORMER SOVIET UNION
NATURAL GAS (MILLION CUBIC METERS)
REPUBLIC
RUSSIA
UKRAINE
BELARUS
KAZAKHSTAN
AZERBAIJAN
GEORGIA
KYRGYZSTAN
TAJIKISTAN
TURKMENISTAN
UZBEKISTAN
TOTAL
PRODUCTION
1990 1991 1992
640,566 642,890 640,400
28,083 24,363 20,900
297 294 200
7,114 7,885 8,800
9,926 8,621 7,800
50 50 negligible
96 83 100
111 92 100
87,767 84,348 60,100
40,761 41,882 40,000
814,771 810,508 778,400
EXPORTS
1990 1991
249,766 245,764
0 0
0 0
2,846 3,154
0 0
0 0
0 0
0 0
71,900 70,000
2,900 2,900
327,412 321.818
IMPORTS
1990 1991
70,166 68,764
87,200 87,200
14,600 14,600
8,746 9,054
0 0
5,400 5,400
1,800 1,800
1,600 1,600
0 0
8,400 8,400
197,912 196,818
NET EXPORTS
1990 1991
179,600 177,000
(87,200) (87,200)
(14,600) (14,600)
(5,900) (5,900)
0 0
(5,400) (5,400)
(1,800) (1,800)
(1,600) (1,600)
71,900 70,000
(5,500) (5,500)
129,500 125,000
APPARENT CONSUMPTION
1990 1991 1992
460,966 465,890 454,400
115,283 111,563 111,300
14,897 14,894 N/A
13,014 13,785 N/A
9,926 8,621 N/A
5,450 5,450 N/A
1,896 1,883 N/A
1,711 1,692 N/A
15,867 14,348 N/A
46,261 47,382 N/A
685,271 685.508 682,500
CRUDE OIL & NGL (THOUSAND TONS)
RUSSIA
UKRAINE
BELARUS
KAZAKHSTAN
AZERBAIJAN
GEORGIA
KYRGYZSTAN
TAJIKISTAN
TURKMENISTAN
UZBEKISTAN
TOTAL
516,183 461,138 395,800
5,252 4,933 4,400
2,054 2,060 2,000
25,820 26,633 27,800
12,513 11,742 11,000
180 180 200
155 143 100
144 108 100
5,642 5,449 5,300
2,810 2,832 3,100
570,753 515,218 449,800
229,429 171,147
0 0
0 0
21,947 22,638
0 0
0 0
155 143
144 108
260 0
0 0
251,935 194,036
25,776 18,110
53,729 49,708
37,387 33,709
13,981 14,011
3,819 4,078
1,920 1,620
0 0
0 0
82 1,683
5,208 5,117
141,902 128,036
203,653 153,037
(53,729) (49,708)
(37,387) (33,709)
7,966 8,627
(3,819) (4,078)
(1,920) (1,620)
155 143
144 108
178 (1,683)
(5,208) (5,117)
110,033 66,000
312,530 308,101 258,200
58,981 54,641 N/A
39,441 35,769 N/A
17,854 18,006 N/A
16,332 15,820 N/A
2,100 1,800 N/A
0 0 N/A
0 0 N/A
5,464 7,132 N/A
8,018 7,949 N/A
460,720 449,218 366,200
HARD COAL (THOUSAND TONS)
RUSSIA
UKRAINE
KAZAKHSTAN
GEORGIA
KYRGYZSTAN
UZBEKISTAN
OTHER
TOTAL
256,800 226,600 215,800
155,500 128,800 127,300
128,000 127,000 122,900
1,000 700 400
1,600 1,500 900
200 200 200
000
543,100 484,800 467,600
52,100 38,400
20,000 14,600
53,900 53,000
300 0
1,900 1,470
600 530
300 0
130,300 108.000
52,300 46,700
18,900 13,300
12,200 8,000
900 400
2,900 2,670
3,700 3,070
12900 9340
103,800 83,480
(200) (8,300)
1,100 1,300
41,700 45,000
(600) (400)
(1,000) (1,200)
(3,100) (2,540)
(9143) (10,135
28.757 23.725
257,000 234,900 227,116
154,400 127,100 130,395
86,300 82,000 81,702
1,600 1,100 764
2,500 2,700 2,288
3,300 2,740 1,432
11,243 10,135 7,003
516,343 460,675 450.700
SOURCE: PLANECON, 1992a, 1993a, 1993b; Skochinsky, 1993; Sagers, 1993
1991 hard coal production total does not equal sum of its parts due to differing data sources.
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APPENDIX B - EXPLANATION OF FORMER USSR
RESOURCE CLASSIFICATION AND
COAL RANK SYSTEMS
B-1
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MINERAL RESOURCE CLASSIFICATION SYSTEM
The coal resource data presented in this report
pertain to documented, or explored reserves. As
in other countries, documented reserves are
categorized according to the degree of assurance
that they exist. In Russia, documented reserves
comprise degrees of assurance A, B, C1f and C2.
They are based on the degree of exploration that
has been carried out. The classification terms
used in Russia are equivalent to descriptive terms
used in the U.S., as shown in Table B-1.
FIG
INDUSTRIA
RESERVES
URE B-1 . CLASSIFICATION OF
DOCUMENTED RESERVES
DOCUMENTED
RESERVES
I
BALANCE
RESERVES
I
BAL
NONINDUSTRIAL
RESERVES
I
NON
ANCE RESERVES
TABLE B-1. COMPARISON OF RESOURCE CLASSIFICATION SYSTEMS
FORMER USSR RESERVE CLASSIFICATION SYSTEM
RESERVES
RESOURCES
CATEGORIZED BY EXTENT
OF STUDY
EXPLORED
PRELIMINARILY
ESTIMATED
PREDICTED
A
B
C, (30
percent)
C, (70
percent) &
C2
P,
P2
PS
GROUPED ACCORDING
TO ECONOMIC
SIGNIFICANCE
BALANCE
NON-
BALANCE
WESTERN
RESOURCE
CLASSIFICATION
SYSTEM
PROVEN
PROBABLE
POSSIBLE
In Russia, documented reserves are further subdivided as shown in Figure B-1. The terms used are
defined below.
Balance coal reserves: documented reserves that meet criteria related to quantity, quality,
technology, geologic conditions, and mining conditions. Criteria vary according to basin.
B-2
-------
Non-balance coal reserves: documented reserves that do not meet the balance criteria for one or
more reasons.
Industrial coal reserves: that portion of the balance reserves that is designated for extraction
according to the mine plans and using available technology.
Non-industrial coal reserves: balance reserves which are not intended for production using
available technology and production systems.
COAL RANK
In Russia, as in other countries, coal is ranked according to various parameters, including its
carbon content, volatile matter content, and heating value. Table B-2 shows the approximate
correlating descriptive terminology used in U.S. and Russia. The U.S. rank equivalents are
approximate in that the ranges of the parameters used in the former USSR (shown here) are not
identical to those used in the U.S.
TABLE B-2: COMPARISON OF U.S. & FORMER USSR COAL CLASSIFICATION SYSTEMS
RANK
LONG-FLAME
GAS
GAS-FAT
FAT
COKING
LEAN-
CAKING
LEAN
ANTHRACITE
VOLATILE MATTER
yas received percent
.>.35
2.35
27-35
27-35
18-27
14-22
8-17
> 8
HEATING VALUE
Q kcal/kg
7300-8100
7000-8600
8300-8750
8300-8750
8500-8800
8500-8800
> 8400
< 8400
CARBON CONTENT
C percent
77-83
81-87
81-87
85-88
88-91
90-93
91-94
94-97
APPROXIMATE
U.S. EQUIVALENT
HIGH VOLATILE
BITUMINOUS C
HIGH VOLATILE
BITUMINOUS B
HIGH VOLATILE
BITUMINOUS A
MEDIUM VOLATILE
BITUMINOUS
LOW VOLATILE
BITUMINOUS
ANTHRACITE
B-3
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