TSU Internship Report
IPCC NGGIP / IGES
National GHG Emission
Factors in Former Soviet
Union Countries

Prepared by Olga Gassan-zade,March 2004

TABLE OF CONTENTS
LIST OF ACRONYMS, ABBREVIATIONS, AND UNITS ............................................................................................. 3
1
Introduction............................................................................................................................................... 42
National Circumstances in Russia, Ukraine, and Kazakhstan................................................................. 5
2.1 General information about the region and its GHG emissions ................................................................ 5
2.2 Institutional Background and Previous Related Activities ...................................................................... 63
CO2 Emissions from Stationary Combustion of Fossil Fuels ................................................................... 8
3.1 IPCC methodology based on the revised 1996 IPCC Guidelines and Good Practice Guidance Report(GPG2000)..................................................................................................................................................... 9
3.2 National net calorific values and carbon emission factors (specific carbon content of fuels) ............... 10
3.2.1 National values: Kazakhstan [4], [8].............................................................................................. 10
Emission factor estimation methodology ........................................................................................... 12
A. Determination of carbon emission factors for solid and liquid fuels ........................................ 12
B. Determination of carbon emission factors for gaseous fuels .................................................... 14
3.2.2 National values: Russia [16, 17, 18] .............................................................................................. 15
Solid fuels........................................................................................................................................... 16
Natural Gas........................................................................................................................................ 18
Liquid Fuels ....................................................................................................................................... 19
3.2.3 National values: Ukraine................................................................................................................ 19
3.3 Carbon Oxidation Factors...................................................................................................................... 25
3.3.1 National values: Russia:................................................................................................................. 26
3.3.2 National values: Ukraine:............................................................................................................... 26
3.3.3 National values: Kazakhstan .......................................................................................................... 27
3.4 EMISSIONS FROM COKE GAS COMBUSTION ............................................................................................ 29
Continuous emissions: ............................................................................................................................ 30
Discontinuous emissions:........................................................................................................................ 30
Emissions from storage and handling of raw materials and products ..................................................... 30
Oven charging......................................................................................................................................... 30
Oven door and frame seal leakage .......................................................................................................... 30
Coke pushing .......................................................................................................................................... 30
Ascension pipe leakage........................................................................................................................... 30
Coke cooling ........................................................................................................................................... 30
Charging holes leakage ........................................................................................................................... 30
Coke oven firing ..................................................................................................................................... 30
Methodology........................................................................................................................................... 31
Standard methodology ....................................................................................................................... 31
IPCC methodology ............................................................................................................................. 31
Instrumental measurements................................................................................................................ 31
4
CO2 Emissions from Mobile Combustion of Fossil Fuels ...................................................................... 34
5
Fugitive Emissions from Gas Systems................................................................................................... 36
6
Fugitive Emissions from Coal Mining Activities ................................................................................... 38
6.1 IPCC Methodology................................................................................................................................ 38
6.2 UKRAINE ................................................................................................................................................ 39
6.2.1 Underground mining ...................................................................................................................... 39
Methane Emissions from Gassy Mines .............................................................................................. 40
Methane Emissions from Non-Gassy Mines...................................................................................... 41
6.2.2 Surface mining .............................................................................................................................. 41
6.2.3 Post-Mining Emissions ................................................................................................................. 41
6.2.4 Utilization of Coal-Mining Methane (CMM) ............................................................................... 42
6.2.5 Emission factor estimation............................................................................................................ 42
6.3 KAZAKHSTAN [34].................................................................................................................................. 45
6.3.1 Underground Coal Mining ............................................................................................................. 45
6.3.2 Surface Mining............................................................................................................................... 46
6.3.3 Post-Mining Emissions .................................................................................................................. 47
7
СО2 emissions from Cement Manufacture.............................................................................................. 49
Bibliography..................................................................................................................................................... 522

LIST OF ACRONYMS, ABBREVIATIONS, AND UNITSCORINAIR

NCV
CEF
NGGIP
OECD
RAO UESRTPP
UNFCCCUS AID
US EPA
USSR

CO-oRdination d'INformation Environnementale (AIR), Workprogramme aimed at gathering and organising information on air
pollutant emissions in the European Union
Carbon Emission Factor (also specific carbon content, t C/TJ)
Greenhouse Gas
Former Soviet Union
International Energy Agency
Intergovernmental Panel on Climate Change
Kazakh Scientific Research Institute for the Monitoring of Environment
and Climate
Net Calorific Value of Fuel (TJ or GJ per natural unit)
Carbon Emission Factor, tC/TJ
National Greenhouse Gas Inventories Program
Organization for Economic Cooperation and Development
Russian Joint Stock Company Unified Energy System of Russia
Thermal Power Plant
United Nations Framework Convention on Climate Change
United States Agency for International Development
United States Environmental Protection Agency
The Union of Soviet Socialist Republics

Chemical Symbols
CH4
CO
CO2
N2O
NMVOC
NOx
SO2

MethaneCarbon monoxide
Carbon dioxide
Nitrous oxide
non-methane volatile organic compounds
nitrogen oxides
sulphur dioxide

Units
Gg
mln m3
ths t
TJ
GJ
tce
toe
mln t

gigagram
million cubic meter
thousand tonne
terajoulegigajoule
ton of coal equivalent
ton of oil equivalentmillion metric tonne

EF
GHG
FSU
IEA
IPCC
KazNIIMOSK

3

1

INTRODUCTION

Russia, Ukraine, and Kazakhstan are the three largest republics of the Former Soviet
Union and the three biggest emitters of greenhouse gases. They are also the only countries of theFormer Soviet Union that either currently are in Annex B of the Kyoto Protocol, like Ukraine andRussia, or expressed their desire to join Annex B and be bound by emission limitations, like
Kazakhstan. Precise estimation of the emissions of these three countries is therefore an important
issue, which has been the focus of attention of local researchers and other Annex I governments.
With the help of many donor agencies and national governments, a significant level ofactivity related to the development of greenhouse gas inventories has been carried out in Russia,
Ukraine, and Kazakhstan starting as early as 1996. While earlier activities have been mostly
reflected in 1996 Revised IPCC Guidelines and 2000 Good Practice Guidance, more recent
activities have not been systematically presented to IPCC NGGIP and therefore has not been madeknown to wider international inventory community.
The aim of this report is to provide an overview of the inventory-related research carriedout in the Former Soviet Union countries over the last 5-6 years, and highlight achievement in
adopting IPCC methodologies, improving inventory quality, and establishing local emission factors.
We also hope that some of the information presented here can serve as input to the IPCC Emission
Factor Database and consequently the revision of the 1996 Revised IPCC Guidelines, potentiallyalso serving as a point of reference for the improvement of the national inventories in these andother countries in the region and beyond.
The focus of this research is on Russia, Ukraine, and Kazakhstan, since these are thecountries of the Former Soviet Union countries where most of the independent inventory work has
been carried out to date. The scope of the paper is mostly limited to major key source categories,
such as the IPCC energy sector, but other sectors are considered as well to highlight the progressthat has been achieved there. Such limitation of both geographic and sectoral scope is explained by
the interest of researchers and funders to large greenhouse gas sources and contributors, as well as
the desire to improve the quality of the inventories cost-efficiently through addressing the mostsignificant of those sources.
The paper is divided into 5 main sections. It begins with an introduction about theinstitutional background on inventory development and inventory-related research in Russia,
Ukraine, and Kazakhstan. We then examine specific emission factors that were developed by local
specialists for the purposes of inventory development on the national and sectoral levels. Four
major areas are considered: CO2 emissions from stationary combustion, mobile combustion, CO2
emissions from coke gas combustion, fugitive emissions, and CO2 emissions from cement
manufacture.

4

2

NATIONAL CIRCUMSTANCES IN RUSSIA, UKRAINE, AND KAZAKHSTAN

2.1 General information about the region and its GHG emissions
Russia, Ukraine, and Kazakhstan are the three largest republics of the Former Soviet Union,
accounting for 90% of its territory and population, as well as for the majority of its industrial output.
After significant industrial decline following the break-up of the USSR, the economies of all three
countries became dominated by exports of natural and mineral resources. In Russia alone, oil,natural gas, metals, and timber account for more than 80% of exports. Kazakhstan's economy issimilarly heavily based on the extraction and processing of natural resources, mostly oil and gas, aswell as other minerals and metals. In addition Kazakhstan is a large agricultural producer,
specializing in livestock and grain. Likewise, Ukrainian economy is also export-oriented, withmetals and agricultural products (grains) accounting for the majority of exports.
Table 2.1 Key statistical information on Russia, Ukraine, and Kazakhstan
Total area, sq
Industrial
Country Name
Population*km
growth,% *Russia144,978,573
17,075,200
5.2
Ukraine48,396,470
603,700
14.2
Kazakhstan
16,741,519
2,717,300
11.4*2002 data, World Resources Institute

Per capita GDP,
$US*
8,300
4,200
5,900

Russia, Ukraine, and Kazakhstan were collectively responsible for 4,230 MtCO2 emissions
in 1990. Although their emissions drastically reduced since the fall of the Soviet Union in 1991,
Ukraine and Russia, the two current Annex I countries, still accounted for about 37% of Annex I
emissions in 1998, the last year when UNFCCC data is available for both of the countries.
In its base year, 1990, Ukraine emitted 919 MtCO2, and in the latest year available, 1998,
Ukraine’s emissions were approximately half of that at 455 MtCO2. [1] In the period between 1990
and 1998, six key source categories of GHG emissions were identified for Ukraine. [2] They are:
CO2 emissions from fuel combustion, fugitive emissions from natural gas and oil, fugitive
emissions from coal mining and handling, CH4 emissions from livestock enteric fermentation, CO2
emissions from mineral products, and CH4 emissions from solid waste disposal. The first three
categories accounted for approximately 90% of the total throughout the indicated period, with CO2emissions from fuel combustion being responsible for 73 and 68 percent in 1990 and 1998
respectively. Fugitive emissions from natural gas and oil and fugitive emissions from coal mining
and handling made up 14 and 6 percent respectively in 1998 and 8 and 4 percent in 1990.
Russian GHG emissions in 1990 were the second largest among Annex I countries after theUS, at about 3,040 MtCO2. Since then Russian GHG emissions have fallen sharply, totaling 1,877
MtCO2 in 1999. Similarly to Ukraine, in Russia, combustion of primary and secondary fossil fuelsaccounted for 77.6% of all GHG emissions in 1999. Main sources of methane emissions in Russia
in 1999 were transportation and distribution of oil and gas (57%), waste (13%) and coal mining(10%). Overall, methane made up about 15% of all GHG emissions in Russia in 1999. [3]5Kazakhstan does not have a formal base year yet as it has not negotiated a target. However,
it is expected that 1992 will be accepted as a base year. In 1992 the total emission of all greenhousegases in Kazakhstan amounted over 372.2 Mt of CO2-equivalent (361.8 MtCO2 discounting
sequestration by forests). The most important source of the GHG emissions in Kazakhstan is theenergy sector, accounting for 315.3 MtCO2 or 84.7% of the total CO2-equivalent emissions. In theenergy category, emissions from the fuel combustion amount to about 93% and about 7% are madeup by fugitive emissions generated at the fuel mining, transporting and processing. Emissions fromthe industrial processes category (emissions not related to the fuel combustion in the industry) madeup 4.6% of the total GHG emissions. In 2001, the latest year available for Kazakhstan, total GHG
emissions were at the level of 154.7 Mt CO2, of which 122.5 (or 79.2%) were contributed by theenergy sector category. The second and third largest GHG sources in CO2 equivalent wereagriculture (10.3%) and industrial processes (8.4%).[4]2.2 Institutional Background and Previous Related Activities
Russia, Ukraine, and Kazakhstan all have different institutional backgrounds with regards
to the compilation of the greenhouse gas inventories.
In Russia, the federal agency formally responsible for development of Russian National
Communications and the compilation of the national inventories is the Russian Federal Service for
Hydrometeorology and Environmental Monitoring (Roshydromet). Roshydromet periodicallycompiles national greenhouse gas emission data based on the reference approach and has mostrecently (2002) submitted Third National Communication of the Russian Federation to the
UNFCCC Secretariat.
In addition, several regional and sectoral inventories have been developed:- 7 Russian regions have compiled their greenhouse gas inventories with support of the Moscowbased Center for Energy Efficiency (CENEf). Although a small percentage of the overall
number of all Russian region, they were chosen on the basis of their representativeness,potential weight in GHG emissions, and comparative size.
- RAO «Unified Energy System of Russia», the largest energy producer in Russia, carries out
annual inventories for its big heat and power plants.
- Gazprom, Russian gas monopolist, which extracts more than 90% of total gas production in the
country, has carried out activities to estimate its corporate fugitive emissions.
- The inventory of greenhouse gas emissions from coal mining and handling in Russia wascarried out by the Russian Methane Centre (Kemerovo).
- The International Forestry Institute (Moscow) has undertaken an analysis of carbon emission
and sinks in the Russian forest sector based on the official forest inventories data and its own
specific studies.
In Ukraine, there is currently no single agency responsible for the development of the national
inventory. Although general support for the inventory preparation was designated to the Institute ofEnergy of the Ukrainian Academy of Sciences, actual annual compilation of the inventories
suffered from lack of budgetary support from the government.
Ukraine’s First National Communication to UNFCCC was completed in 1999 with supportof the Ministry of Environment of Ukraine and included annual inventories for the period of 19911998. The 1990 Inventory was prepared under the U.S. Country Study Program. Experts from sixorganizations were involved in this study: the Institute of Energy of the National Academy of6

Sciences of Ukraine (energy), the State Committee on Forestry (land-use and forestry), the Ministryof Environment and Natural Resources (general coordination, waste), the State Committee on
Statistics (activity data), the National Academy of Agriculture (agriculture), and the Agency for
Rational Energy Use and Ecology (compilation of results and preparation of the final report).
Since 2000, no coordinated effort has been carried out on the national level. However, withthe help of various donor agencies, individual inventory initiatives have been carried out:
- Partnership of Economic and Environmental Reform (PEER) developed a bottom-up inventoryof CH4 emissions of all mines in Ukraine was developed (1999-2001).
- Canada-Ukraine Environmental Cooperation Program (CUECP, 1999-2003) analyzed GHG
emissions from coke combustion production at a pilot facility and compiled the inventory forwhole energy sector .
- Climate Change Initiative (CCI) developed inventories for key sources such as energy andaluminium industry.
- Agency for Rational Energy Use and Ecology (ARENA-ECO) compiled greenhouse gas
inventories for district heating sector and cement production.
- Center for Clean Air Policy (CCAP) developed pilot inventories for two Ukrainian regions.
Only two of these initiatives (power sector inventory by CCI and coal-bed methane inventories byPEER) undertook development of the national emission factors.
In Kazakhstan, the agency responsible for the development of the national inventories is
Kazakh Scientific Research Institute for the Monitoring of Environment and Climate(KazNIIMOSK). With the support from the government of Kazakhstan, KazNIIMOSK has been
compiling the national inventories of greenhouse gases (GHG) on an annual basis since 1999.
Currently the inventory exists for the year 1990, 1992, 1994, 1999-2001. In addition, KazNIIMOSK
undertook a number of in-depth studies of greenhouse emissions and possibility of their mitigationfrom individual sectors:- Kazakhstan GHG Mitigation Assessment (Climate Change Country Study), 1996
- Kazakhstan GHG Emissions Modeling- Kazakhstani Regional GHG Emissions Inventory Project (Almaty region), 2001
- Kazakhstani GHG Emissions inventory from Coal Mining and Road Transportation, 2002
Currently, a study of fugitive emissions from oil and gas industry is being carried out by
KazNIIMOSK and will be available next year.

7

3

CO2 EMISSIONS FROM STATIONARY COMBUSTION OF FOSSIL FUELSHeat and power generation are estimated to be largest contributors of GHG in Russia,
Ukraine, and Kazakhstan. Because of their magnitude of their emissions and the strategic
importance of heat and power sector for the countries concerned, efforts were undertaken in each of
the countries to improve the quality of GHG emission estimation from stationary fossil fuelcombustion.
In Russia, electricity generation monopoly RAO UESR has developed a corporate
inventory of GHG emissions, which included estimation of carbon emission factors for the fuels
burnt at the company facility (coal, heavy oil, gas). Similarly, in Ukraine, US Agency forInternational Development (US AIID) has sponsored inventory of the largest thermal power plants,
which also included estimation of national carbon emission factors and oxidation coefficients. Only
coals were examined in the Ukrainian study as coal is the only locally produced fossil fuel.
Kazakhstan has developed emission factors for locally used fuels as part of the regional GHG
inventory in the Almaty region. However, since the regional research was coordinated by the sameagency that compiles the national inventories, research outputs covered the majority of the fuels
used in the country.
For the benefit of the inventory community and for the further reference to inventoryrelated research in the region, we are preserving original methodologies, as well as originalterminologies wherever possible. With that note, it needs to be said that there is a variation between
how certain terms and concepts are used from study to study. Widely used oil-based fuel known in
Russia as ‘mazut’ is translated by various authors as heating oil, heavy oil, residual fuel oil, or
simply transcribed as mazut. Large power plants that use fossil fuels are either translated as‘thermal power plants’ or ‘heat and power plants,’ both terms being very close to what they arecalled in Russian. In the source literature Net Calorific Values (NCV) are more commonly referred
to as Low Heating Values (LHV), since it is closer to the Russian terminology. For the same reason,oxidation factor is sometimes referred to as unoxidation factor (in Russian ‘non-combustion
coefficient’). Additionally, heat calculations in the Former Soviet Union are carried out in calories,
which is reflected in the methodologies described below.
The majority of the emission factors described in this section are calculated on the basis offuel documentation rather then on the basis of direct measurements. Fuels are categorized into
certain ‘grades’ in accordance to classifications stipulated in relevant state standards. State
standards also prescribe what methodologies are to be used for calculating fuel qualities and / oremissions from various processes for the purposes of national accounting. These nationallymandated methodologies are referred to as ‘normative’ throughout the text.

8

3.1 IPCC methodology based on the revised 1996 IPCC Guidelines and Good Practice Guidance
Report (GPG2000)
The methodology for estimation of CO2 emissions from stationary combustion of fossil fuels
recommended by 1996 IPCC Guidelines [5] is based on the following equation:
Cr = Q x NCV x EF x (1-Sf) x F(1)

Where:
Cr
Q
NCV
EF
Sf
F

is quantity of carbon released and attributed to fuel combustion (multiplied by 44/12 forCO2)is quantity of fuel delivered to or consumed by the activity (sector) expressed in naturalunits
is net calorific value of fuel (TJ/natural unit)
is carbon emission factor (more precisely, the specific carbon content, t C/TJ)
is carbon storage factor, that is the fraction of carbon delivered which remains unoxidised
after use of the fuel either in a product manufactured from it or because the use does not
involve deliberate oxidation of the carbon content.
is the oxidation factor, the fraction of carbon which is oxidised during combustion.

Of these values, quantity of fuel delivered and consumed is the basic variable that determines thevolume of greenhouse gas emissions in the country in a given year. Net calorific values of the fuels,
carbon emission factors, and oxidation factors tend to vary less from year to year. Basic (default)
values for net calorific values of the fuels and carbon emission factors are provided by IPCC
methodology. However, in order to improve the accuracy of national emission estimates, IPCC
recommends to determine appropriate national or local values.
Although IPCC Guidelines do not offer country-specific carbon emission factors, the Reference
Manual (Volume III of the 1996 Guidelines) suggests some country-specific assessment of net
calorific values, as these tend to vary greatly from one coal-mining region to another, and includes
values for Russia, Ukraine, and Kazakhstan. In 2000 Good Practice Guidance [6] these values were
up-dated slightly.
The carbon emission factors for coals presented in 1996 IPCC Guidelines and 2000 Good PracticeGuidance are mostly based on international assessments:
Energy Balances of OECD Countries, and Energy Statistics and balances of Non-OECD Countries,
OECD/IEA, Paris, 1998.1
OECD/IEA (1993), Energy Statistics and Balances of Non-OECD Countries: 1990-1991.
International Energy Agency, OECD, Paris, France

1

A note is made that for the Former Soviet Union and the Yugoslav Republics 1996 numbers were used.
These appear to be identical to the 1993 numbers cited below.

9

Table 3.1. Net Calorific Values and Emission Factors for Solid Fuels as Found in the 1996 IPCC
Guidelines [7]Solid Fuels

Net Calorific Value (GJ/t)(moisture free basis)
Anthracite
Close to 29 GJ/t
Coking coal
Typically between 26 - 29 GJ/t
Other bituminous coal*
Between 24 - 29 GJ/t
Sub bituminous coal
Varies considerably with quality.
Lignite7 - 17 GJ/t.
Peat
Typically about 17-20 GJ/t
Patent fuelVaries depending on the type of patent fuel.
Brown coal briquettes
Accordingly to the quality of brown coal employed.
Coke oven coke (hard coke) Typically 28 - 29 GJ/t
Gas coke
Little information, assumed similar to hard coke.

Carbon Emission Factor(tC/TJ)
26.8 tC/TJ
25.8 tC/TJ
25.8 tC/TJ
26.2 tC/TJ
27.6 tC/TJ
28.9 tC/TJ
25.8 tC/TJ (default value)
25.8 tC/TJ (default value)
29.5 tC/TJ
29.5 tC/TJ* It is stipulated that the much lower figures for calorific values cited in the IPCC Guidelines probably reflect values forunprocessed coal containing non-combustible materials.

Table 3.2. National Net Calorific Values from 2000 Good Practice Guidance
NCV, GJ/t

Kazakhstan

RussiaUkraineOIL
Crude Oil
NGL
Refinery Feedst.
COAL

42.08
41.91
-

42.08
-

42.08
-

18.58
18.58
18.58

18.58
25.12
18.58

21.59
21.59

Coking Coal
Production
Imports
Exports

Other Bituminous Coal and Anthracite
Production
Imports
Exports

18.58
18.58
18.58

18.58
18.58
18.58

21.59
25.54
21.59

NCV, GJ/t

Kazakhstan

RussiaUkraine

14.65
18.58
18.58

14.65
14.65

14.65
14.65
14.65

25.12
-

20.1
25.12

29.31
25.12

Sub-Bituminous Coal
Production
Imports
Exports
LigniteProduction
Imports
Exports
OTHER FUELSBKBCoke Oven Coke
Gas Coke-

Since each coal-mining basin bears different types of coals, the systems for gradation andclassification of coal is different in each of the coal-mining countries, although certain typology
remains constant. In Russia, Ukraine, and Kazakhstan special efforts have been made to develop
local carbon emission factors for the local coal types.
3.2 National net calorific values and carbon emission factors (specific carbon content of fuels)
3.2.1 National values: Kazakhstan [4], [8]Kazakhstan has developed by far the most comprehensive approach to estimating national
greenhouse gas emissions for fuel combustion and has developed local factors for a variety of local
fuels.
The data on consumption of fuel is submitted to the Statistics Agency of Kazakhstan in statisticalreporting form #1-TEB. The form is submitted by all the economic entities that supply or consumefuel and employ more then 20 people, regardless of their activity type. The form lists 25 types offuel, which do not directly correspondent to IPCC fuel types. KazNIIMOSK therefore developed aconversion table to match fuels used in Kazakhstan with fuel categories provided by IPCC.

10

Methodology note:
In its annual inventories estimated under the Reference approach, Kazakhstan modified the basic
equation in the IPCC Guidelines:
Fuel burned = (Production) + Imports - Exports ± Stock Change(2)

to include estimates of the fuel lost
Fuel burned = (Production) + Imports - Exports ± Stock Change - Fuel Lost,(3)

where the fuel lost was defined as fuel that has been produced but not consumed due to losses indelivery, transport, accidents, etc. The information on the quantities of the lost fuel is submitted by
Kazakh economic entities to the Statistics Agency of Kazakhstan along with regular information on
the quantities of consumed and stockpiled fuel, as part of the regular statistics. Therefore the eachenterprise reports three major values related to fuel consumption: the amounts of fuel consumed,
stockpiled, and lost. Aggregated data on fuel lost collected by the Kazakhstan Statistical Agency isthen used to estimated total quantity of fuel lost under the reference approach. In 2001, fuel lost
made up 0 to 5% of each fuel type consumed by the Kazakh economy.[4]Table 3.3. Correspondence between IPCC and Kazakh fuel types [4]
IPCC fuels
IPCC fuel category
Crude oil
Gasoline
Jet kerosene
Other Kerosene
Gas and diesel oil
Residual fuel oil
LPG
Shale oil
LubricantsPetroleum coke
Other types of fuelCoking coalSub-bituminous coalLigniteCoke
Coke oven gas
Blast furnace gas
Natural gas
Biomass

Kazakh fuel category

Kazakh fuels
Net Calorific Value
GJ/t

Crude oil
Gas condensate
Aviation Gasoline
Vehicle gasoline
Gasoline-like jet fuelKerosene-like jet fuelKerosene for lighting and otherpurposes
Diesel fuelDomestic furnace fuelMotor fuel for slow diesel
vehiclesHeating oil (mazut)
Navy mazut (oil)Liquefied propane and butane
Liquefied carbohydrate gases
Oil and shale bitumen
Spent lubricants (other lubricants)
Petroleum and shale coke
Other types of fuelKaraganda coking coal
Hard coalLignite (brown coal)
Hard-coal coke and half coke
Coke oven gas
Blast furnace gas
Natural gas
Heating wood

Carbon Emission
Factor, tС/ТJ40.12CS

20.31CS

44.21CS

19.13CS

43.32CS

19,78CS

44.75D

19.6D

43.02CS
42.54CS

19.98CS
20.29CS

42.34CS

20.22CS

41.15CS

20.84CS

47.31D

17.2D

40.19D
40.19D
31.0D
29.309D
24.01CS
17.62PS
15.73PS
25.12D16.73PS
4.19PS
34.78CS
10.22CS

22D
20D
27.5D
20D
24.89CS
25.58PS
25.15PS
29.5D
13D
66D
15.04CS
29.48CS

11

Notes:D – IPCC default;
CS – country specific data;
PS – plant specific data.

For heating oil, diesel fuel, sub-bituminous coal, and lignite uniform national net caloric values andcarbon emission factors were calculated based on weighted averages of the consumption of fuelgrades within one fuel sub-type from the national energy balance.2 Disaggregated emission factors
for individual fuel sub-types are shown in Table 3.4. Since these are weighted average fuel, they are
year-specific and are up-dated by KazNIIMOSK on the annual basis.
Table 3.4. Averaged national net calorific values and carbon emission factors (2001 inventory)

Fuel category
Heating oil
Diesel fuelSub bituminous coalLigniteNet Calorific Value
GJ/t
41.15
43,00
17,62
15,73

Carbon Emission Factor
tС/ТJ
20.84
19,99
25,58
25,15

Emission factor estimation methodology
National net calorific value and carbon emission factors for various types of fuel used in
Kazakhstan were drawn from a variety of sources. The values for crude oil, gasoline, jet kerosene,diesel oil, heating oil, coal, and natural gas were calculated by the researchers of Kazakh Scientific
Research Institute of Electric Power Industry (KazNIPIenergoprom). The values for coke oven andblast furnace gases were provided by Karaganda-based coal-mining company Ispat-Karmet. The net
calorific values that were calculated were compared with the national averages put together on thebasis of the data collected by the Statistic Agency of Kazakhstan.
A. Determination of carbon emission factors for solid and liquid fuels
The so-called Mendeleev's equation was used to define the carbon emission factors for solid andliquid fuels. The equation is used in thermal power plant engineering and connects the net calorificvalue and the composition of fuel:Qdaf = 81*C + 300*H - 26*(O - S) - j*(9H+ W), kcal/kg 3(4)

Where:Qdaf
j
C, H, Ois net calorific value of fuel (on dry and ash-free basis),
is a conversion factor used to express the result in kcal/kg and equals 5.83,
is the content of carbon, hydrogen and oxygen respectively in operational mass offuel, %,

2

To improve accuracy of the emission data, the inventory compliers also calculated weighted averages ofnational net calorific values and carbon emission factors of heating oil, diesel fuel, sub-bituminous coal, andlignite for major economic sectors. Because of their marginal value to the outside researchers, these values are
not presented in this report.
3
Another way of expressing the Mendeleev’s formula is: Qdaf=339.5*C+1256*H-25.8(9H+W)-109(O-S)
Qн = 34,013 С + 125,6 Н – 10,9(О – S) – 2,512(9H + W) MJ/kg ,

12

S
W

is the sulfur content in dry mass of fuel, %,is the total amount of moisture in the operational mass of fuel, %.

Based on this equation, the specific carbon content of fuel per energy unit was determined as:
C = 29,46 – 176,76*a / Qdaf, tC/TJ,(5)

Where:Qdaf
is the net calorific value per working mass, kcal/kg,a
is a factor describing the composition of the fuel working mass and determined as:
a = 41*H – 4.3*(O - S) -W,
where H, O, S, and W are respectively hydrogen, oxygen, sulfur and moisture contents working
mass of fuel, %.
According to the results of calculations made for fuels used in Almaty region the a/Q ratio wasdetermined as 0.02-0.03 for coal and 0.05 for low-sulfur residual fuel oil.
The results of carbon emission factors calculation for fossil and liquid fuels are presented in Table
3.5. The table also indicates original sources of the data, a quick summary of which is provided
below:- statistical reporting data from energy enterprises for 1999 – 2000,- data on chemical analysis of Karaganda concentrate coal (obtained based on the analysis
carried out by KazNIPIenergoprom as a part of ecological audit Heat and Power Plant #1
belonging to Closed Joint Stock Company Almaty Power Consolidated (APC) conducted in1997) [9],- state standards and technical conditions for different types of fuel (references) [10-14],- data from KaragandaGIPROSHAKHT institute,- data from reference books [15].
Table 3.5. Carbon emission factors for fuels used in Almaty region
Net Calorific Value
Fuel description

kcal/kg

TJ/ths t
TJ/mln m3aa/Q

CarbonEmissionfactor,tC/TJ

CarbonOxidation
factorData source

Solid Fuels
Coal origin

Coal Type

1. Karaganda

Concentrate

2. Karaganda
3. Karaganda
4. Karaganda
5.
Ekibastuz(whole basin)
6. Ekibastuz I
group
7. Ekibastuz II
group

ConcentrateMiddlings
Regular

5441

22.8

146.3

0.0269

24.71

0.985

3880
5090

16.26
21.33

83.5
110.1

0.02150.0216

25.66
25.64

0.985
0.985

Ecological audit of APC's
HPP-1, 1999 (Chemical
analysis of averaged coalsample)Reporting data of APC's
HPP-1 for 2000
Normative method
Normative method

Regular

4000

16.76

85.2

0.0213

25.69

0.98

Normative method

Regular

4150

17.39

91.4

0.022

25.57

0.98

Regular

3480

14.58

80.9

0.0233

25.35

0.98

5730

24.01

148.2

0.0259

24.89

0.985

State standard OU 654
RK 01 6 1945.101-97
State standard OU 654
RK 01 6 1945.101-97

13

8. Kuu-Chekinsk

Regular

3910

16.38

78.5

0.0201

25.91

0.98

Normative method
Reporting data APC's
HPP-3 for 1999
Data from Karaganda
GIPROSHAKHT
institute

9. Kuu-Chekinsk

Regular

4449

18.64

88.4

0.0199

25.95

0.98

10.Maykunensk
11. Borlinsk
12. Shubarkol

Regular
Regular
Regular

3768
3850
4750

15.79
16.13
19.9

94.3
0.025
126.3 0.0328
87.2 0.0184
Liquid Fuels

25.04
23.66
26.21

0.985
0.985
0.985

Fuel type
13. Residual fueloil I-100
14. Residual fueloil I-100
15. Residual fueloil I-40

Description
Lowsulfur
Lowsulfur
Lowsulfur

9869

41.35

478.7

0.0485

20.89

0.995

Reporting data of APC's
HPP-1 for 2000

9770

40.94

478.7

0.049

20.8

0.995

State standard 1058599

9821

41.15

478.7

0.0487

20.84

0.995

State standard 1058599

Fuel type

Description

16. Wood

Domestic

2440

10.22

29.48

0.98

Normalizing method

17. Natural gas

BukharaUral
pipeline

8175

34.25

15.03

0.995

Reporting data of APC's
HPP-1 for2000

Other Fuels-0.3

0.0001

B. Determination of carbon emission factors for gaseous fuels
The natural gas is supplied to Kazakhstan from the neighboring Uzbekistan by a gas-pipeline. To
estimate the carbon emission factor of the supplied natural gas, its physical properties were
calculated based on the existing reference data. The percentage composition of the mixture gases
from Bukhara-Ural pipeline was taken from reference book [15]. Physical gas properties were
calculated in accordance with State Standard #30319.3-96.[14]. Based on the calculation of thephysical properties, corresponding carbon content in the gas mass and specific carbon content per
thermal unit were derived. Table 3.6 contains the results of calculations for natural gas. The fractionof carbon oxidized was determined as 99.5 % in accordance with the reference data.

14

Table 3.6. Physical properties of the natural gas from Bukhara-Ural pipeline.
mi,
mg,
g,
Share of element, %Compound Vi, % i, kg/m3 g, kg/m3
kg/mole kg/mole (share)
C
H
N
94.9
0.6682 0.6341 16.043
15.225 0.899 67.303 22.5903
CH4
C2H6
C3H8
i-C4H10n-C4H10i-C5H12n-C5H12
C6H14
C7H16
C8C18
C9H20
C10H22
N2
H2S
CO2

3.2
0.4
0.1
0.1
0.9
0.4
100

1.26011.86412.49562.48803.17403.14703.89804.75505.81205.03000.73001.16491.4311
1.83930.04030.00750.0025-00.00320.01050.00740.705430.07044.09758.12058.12072.14672.14686.172100.198
114.224128.250
142.27628.01634.08044.011

0.962
0.176
0.058
0.072
0.252
0
0.176
16.922

0.057
0.011
0.004
0.004
0.015
0
0.010

5
4.56670.86370.29240.37450.291073.6919

1.14950.19330.06130.07540.958
25.0281.4862
1.4862O

Qmin kcal/m3
Qmin i Qmin g

-

7980

7573.020.75830.7583

14300
20670
27236
34400
34400
38540
38540
5200
-

457.60
82.68
27.24
34.40
8174.94

Qming converted to MJ/m3
34.25

Number of atoms
Molecular mass

17.0851.039212.47014.23524.23520.01800.25150.00800.1283Specific hydrocarbon emission, converted into 0.0045
CH4, %
2.6646CO2 emission factor, kg/kg
0.730
Specific carbon content, kg/kg
3
0.515
Specific carbon content, kg/m
15.03
Carbon emissions factor, t C/TJ

3.2.2 National values: Russia [16, 17, 18]
National emission factors in Russia were developed as part of the corporate GHG
Emissions Inventory of the Russian Joint Stock Company Unified Energy System of Russia (RAO
UESR), Russia’s electric power generation monopoly and one of the world’s largest utility
companies. RAO UESR’s inventory of greenhouse gas emissions encompasses almost entire
thermal power sector of Russia. RAO UESR's emissions constitute about 30% of total Russian CO2emissions, accounting for about 89% of Russia’s fuel consumption in the thermal power industry.
The inventory covered emissions from 357 thermal power plants (TPPs) and boilers owned by 77
regional energy companies that make up RAO UESR. The GHG emissions inventory completed in
1999 originally covered years 1990 to 1997 and included calculation of fuel specific emission
factors. Currently the factors that were developed in 1999 are being used to calculate the company’s
annual corporate greenhouse gas emissions, and to estimate greenhouse gas emissions fromindividual facilities.
RAO UESR calculated the national and local fuel-specific CO2 emission factors for three
types of fuel: coal, residual fuel oil (also known as “heavy oil” or “mazut”) and natural gas. It is
important to note that RAO UESR’s emission factors were developed for the purposes of corporate

15

GHG accounting and only later on independent efforts were made to adopt them in accordance with
IPCC methodology to the national inventory needs. The company’s goal was to obtain one CO2
emission factor for each fuel category (solid, liquid, gaseous), which would already include
correction for unoxidation and which could be used as a single multiplier when calculatingconsequent annual inventories. We present RAO UESR’s methodology in its original form, alongwith derived national carbon emission factors.
Solid fuels
To identify the CO2 emission factors for the country as a whole, RAO UESR gathered
experimental and reference data for each type of solid fuel that constituted more than 1% of the fuelbalance in the power and heat sector. This definition mostly limited the scope of study to themajority of coals combusted at RAO UESR facilities. In addition to coal, some power plants use
other types of solid fuel (e.g., peat and bark), but their share in the fuel balance of the company isnegligible.
The Russian power and heat sector combusts about 160-200 types of fossil coals and related
products. During the time period covered by the inventory (1990–1997), RAO UESR burned coalfrom eight major coal-producing basins located in the Russian Federation and Kazakhstan4. These
include coals from the Kuznetsky (20%–25%), Kansko-Achinsky (18%–19%), Ekibastuzsky (16%–19%) basins; eastern Siberia (~15%) and the Far East (~10%); as well as coals from the Donetsky(4%–5%), Pechorsky (~4%), and the Podmoskovny (1%–2%) basins. Each basin contains one ormore mines, and each mine produces coals of varying grade, thus the characteristics of coal may
differ significantly even within one basin. For example, currently there are 68 coal mines and 16
open-pit mines operating in the Kuznetsky coal basin. Different grades of coal have slightly
different characteristics of carbon content, heat power and ash.
To estimate its corporate CO2 emissions from coal combustion, RAO UESR calculated one
aggregate average CO2 emission factor for each of the eight coal basins (i.e. coal-mining regions),
based on the weighted averages emission factors of coal grades produced within the basins. The
CO2 emissions from each grade of coal combusted depend on the particular qualities of that grade,the characteristics of the power plant in which it is burned, and the completeness of combustion(fraction of carbon oxidized). To calculate the CO2 emission factors for the different grades of coal,
the following general equation was used: 5

EFCO2 =

44 daf 7000
⋅ C ⋅ daf ⋅ ε ,
12
Q

(6)

where

EFCO2

specified emission factor, tCO2/tce (ton of coal equivalent),

44/12
Cdaf
Qdaf
7000

factor for recalculation of carbon emissions into CO2 emissions (tCO2/tC),
carbon content of coal on dry and ash-free basis, %net calorific value of coal on dry and ash-free basis, kcal/kg,
conversion factor for recalculation in coal equivalent (ce) units:
kcal/kg ce: 1 kg ce=7000 kcal

4

It is estimated that the coal burnt at RAO UESR facilities makes up 20% of the total coal consumption in
Russia. [17]5This methodology is consistent with international approach, as for example in EMEP/CORINAIR Emission
Inventory Guidebook [18]. However, IPCC Guidelines suggest accounting for incomplete carbon oxidization
separately.

16

εfraction of carbon oxidized, %.

RAO UESR applied different factors for Cdaf and Qdaf to each grade of coal and each basin. These
values for each of the analyzed grades of coal were taken from the reference book Energy Fuel of
USSR [15].
Different carbon oxidation factors were used for each basin, although distinction between
different grades within each basin was not made. The basic information for calculating carbon
oxidation factors was taken from the 3-Tech statistical reporting form submitted by the inventoried
utilities.
An example of the calculation of a CO2 emission factor for a particular coal basin is shownin Tables 3.7 and 3.8.
Table 3.7. Example: Chemical characteristics of ‘DR’ grade coal from the Kuznetsky basin
Coal grade6
Moisture content
Ash content
Net calorific value‘DR’ grade coal
11.5%
18.0%
7310 kcal/kg

Chemical characteristics (in dry, ash-free state of fuel):
Carbon content
Hydrogen content
Nitrogen content
Oxygen content
Sulfur content
Source: [17] with reference to [15]

77.7%
5.5%
2.6%
13.7%
0.5%

Table 3.8. CO2 emission factors for coals from the Kuznetsky basin ([17] with reference to [15])MineKuznetsky

YuzhnayaSevernaya
Kiselevskaya
Dalnie Gory
Im. V. N. Volkova
Boutovskaya
Krasnokamenskaya
Im. V. V.Vakhrusheva
6

Kcal/kg

CO2 emission
factor,t CO2/tce

Carbonemissionfactor,t C/TJ

7 310
7 620
8 130
7 760
8 120
8 120
7 900
8 230
7 760
7 870
7 660
7 750
7 850
8 170
8 080
8 190

2.634
2.621
2.693
2.673
2.744
2.697
2.658
2.673
2.673
2.668
2.678
2.676
2.642
2.693
2.678
2.705

24.5
24.4
25.1
24.9
25.5
25.1
24.7
24.9
24.9
24.8
24.9
24.9
24.6
25.1
24.9
25.2

Coal grade

Cidaf ,

Qidaf ,

(Russian abbreviation)%

DR, DSSh
GR, GMSSh, GSSh
SS2SSSSh, SS2SSR
SS1SSSSh, SS1SSRTOMSSh, TSSch, TR
K, SS, promproduct
K, SS, prompr. + otsev SS
K, KZh, SS, shlam
SS1SSSSh
SS1SSR
SS1SSR
SS1SSR
SS1SSR
SS2SSR
SS2SSSSh
SS2SSR

77.7
80.5
88.0
83.5
89.5
88.0
84.5
88.4
83.5
84.5
82.6
83.5
83.5
88.4
87.0
89.0

Also sometimes referred to as coal mark following Russian terminology.

17

Yagunovskaya
Shushtalepskaya

SS2SSRTRSSROK1
SSROKP

88.0
90.0
86.9
79.9

8 130
8 160
7 920
6 930

2.693
2.746
2.729
2.860

25.1
25.6
25.4
26.6

The emission factors for each of the basins were derived from specific emission factors foreach of the coal grades produced within the basin. The aggregate emission factor for a basin was
obtained as a weighted average of the emission factors for all the coal grades produced within thebasin. Appropriate weighting coefficients were calculated based on the share of the production ofeach coal grade in the total volume of coal production within a basin in 1990.
Table 3.9. Averaged carbon emission factors for various coal-mining regions [18]Kuznetsk coal-mining basin
Kansk-Achnisk coal-mining basin
Ekibasutuesk coal-mining basin
Eastern Syberia
Far East
Donetsk coal-mining basin
Pechorsky coal-mining basin
Moscow region coal-mining
basin

Carbon EF, tC/TJ
25.05
26.74
25.80
25.88
25.40
24.61
25.29
25.92

CO2 EF, tCO2/thousand tce
2.692
2.874
2.773
2.781
2.730
2.645
2.718
2.758

In a similar way, RAO UESR calculated an aggregate emission factor for all of the coalconsumed by the Russian power sector (so-called ‘energy coal’). For this purpose, each of theemission factors for eight coal mining basins were averaged, taking into account the share of theconsumption of coal from each basin in the total volume of coal consumption in the sector in 1990.7
Natural Gas
Natural gas is delivered to the power plants from different gas deposits, each of which hasdifferent physical and chemical properties. Therefore, as in the case of solid fuel, RAO UESR
derived an average carbon dioxide emission factor by calculating an average value for all gases
combusted at the plants. The data on gas composition (CH4, C2H6, etc.) and heat of combustion
were taken from [15].
The Adopted Guidelines [19] stress that that the coefficients for natural gas are also always
almost the same, since most of Russia is supplied with West Siberian gas. Insignificant differences
are observed for carbon emission factors for gas from gas pipelines Central Asia – Center andSaratov – Moscow, while Orenburg gas is quite different.
The carbon oxidation factor for natural gas combustion was assumed to be 100%, based on
the nearly complete combustion of gas at large thermal power plants [21]. The Adopted Guidelines
recommend using oxidation factor of 0.999.
The analysis of the facility level emissions performed by RAO UESR in 2002-3 showedthat even upon close examination the variation of the emission factors from natural gas combustion
7

Note: Averaged emission factors for the basins were derived based on production data, while the nationalemission factor is based on the consumption data.

18

was small (1.62, 1.61, 1.63 for three facilities examined) and correlated well with the originallycalculated value.
Table 3.10. Average Carbon Emission Factors from gas supplied to large power plants in Russia (withcorrection for carbon oxidation factor)
CEF, tC/TJ
CO2 EF, tCO2/thousand tce
Average for all pipelines other 14.95
1.608
then those indicated below. Gas
from Western Syberia
Central Asia – Center pipeline
15.11
1.625
Saratov – Moscow pipeline
14.86
1.599
Orenburg – Alexander Gai 16.01
1.722
pipeline
Moscow TransGas (closed cicle)
14.93
1.606

Liquid Fuels
The guidelines indicate that according to RAO UES data, the characteristics of the heating
oil used by large power plants in Russia are almost identical (although they are somewhat different
from those given in IPCC Guidelines because the mazut used in Russia is largely characterized byhigh sulphur content. The initial data on carbon content and the lowest heat value for high-sulfuric
residual oil (mazut) combusted at the power plants were taken from [21]. In addition to residual oil,some plants located in, for example, the eastern part of Russia, combust diesel fuel and petroleum
coke. But because the share of these fuels is insignificant, they were not considered separately in
the inventory. As in the case of gaseous fuels, carbon oxidation was assumed to be 100%, based on
the assumption that combustion of liquid fuel at large thermal power plants is almost complete [21].
The average CO2 emission factors calculated as a weighted average for each type of fuel(solid, liquid, gaseous) are presented in Table 3.11. Final Carbon emission factors that wereobtained by RAO UES were recalculated and presented without discounting for partial oxidation.
This was done because fuel combusted at large electric power plants is oxidized much better thenon average in Russia.
Table 3.11. Comparison of RAO UESR and IPCC default carbon emission factors forcoal, residual fuel oil, and gas (without adjustment for incomplete combustion)

Coal
Gas
Residual fuel oil

RAO UESRCO2 emission factor Carbon emission
tCO2/thousand tce factor, tC/TJ
2.76
25.68
1.608
14.95
2.28
21.11

IPCC
Carbon emission
factor, tC/TJ

26.2
15.3
21.1

3.2.3 National values: Ukraine

19

The majority of the work on the national inventories in Ukraine was done through theactivities of technical assistance agencies of the US and Canada, implemented for the most part by
the Institute of Energy of the Ukrainian Academy of Sciences. A Canadian study [27] examined thenational system for collecting information on the fuels consumed, while a study sponsored by US
Agency for International Development (US AID) examined more closely GHG from the energy
sector [28].
As in other countries, information on the fuels consumed by the Ukrainian economy iscollected by the national statistics system. Since the Soviet times, the main task of collecting suchinformation was to facilitate the setting of sectoral fuel use quotas. Because of that, the national
statistics on fuel consumption is organized on the principle of the ministerial hierarchy. Therefore,
neither sectoral division nor nomenclature of fuels of national statistics coincide with IPCC
categories and fuel types. For example, in the category “Road transportation” natural gas is used asengine fuel and for heating. Additionally, the nomenclature of consumed fuel include the fuel types,
which are not described by the IPCC methodology, for example, stove fuel, engine fuel etc.8
As part of the effort to improve inventory system in Ukraine, an algorithm was develop tomatch Ukrainian fuel categories with IPCC fuel categories (Table 3.12).
Table 3.12.Correspondence between Ukrainian fuel types and IPCC fuels [27]
IPCC fuel types
Ukrainian fuel types
IPCC fuel types
Ukrainian fuel types
LIQUID FUELSOLID FUEL
Primary fuel products
Primary fuel products
Crude OilOil including
Anthracite
Coal
condensed gas
Coking Coal
Orimulsion
Other Bit. Coal
Natural Gas Liquids Liquid natural gas
Sub-bit. Coal
Gasoline
Gasoline
LigniteJet Kerosene
Oil Shale
Oil shale
Other Kerosene
Kerosene
Peat
Peat briquettes
Shale OilPeat (nominal damp)
Gas / Diesel Oil
Diesel fuelSecondary fuel products
Residual Fuel Oil
Residual fuel oil
BKB & Patent Fuel Coal briquettes
Bunker fuelCoke Oven/Gas
Coke and coke breeze
LPG
Coke
EthaneGASEOUS FUEL
NaphthaNaphthaNatural Gas (dry)Natural gas
BitumenPetroleum bitumen
Blust furnace gas
Lubricants
Lubricants
Coke gas
Coke gas
Petroleum Coke
Petroleum coke
BIOMASS
Refinery Feedstocks Refinery feedstocks
Solid Biomass
Fuel wood
Liquid Biomass
Other Oil
Stove fuelEngine fuelGas turbine fuelWaste oil products
Gas Biomass
Other types of fuelA separate effort was also undertaken to improve the information on GHG emissions frompower generation. In 2000-2001, the US AID together with the Ministry of Fuel and Energy of
Ukraine and the Institute of Energy of the Ukrainian Academy of Sciences have carried out a study
8

At the times of the Soviet Union, fuel nomenclature included hundreds of fuel grades. After a series ofrevisions since 1991, as of 1999, the Ukrainian fuel consumption statistics include 32 economic sectors andsubsectors and 26 types of fuel.

20

on development of national emission factors on large thermal power plants in Ukraine [17]. The
local carbon emission factors for specific types of fuel have been developed using data from thedirectories [15, 29] which provide detailed information on the elemental composition and heat valueof a fuel used for most of the Ukrainian coal-mines and coal-dressing mills. The local carbon
emission factors have been found for the following types of Ukrainian coal: anthracite, lean coaland jointly for gas and candle coal. These are the coals that are supplied to electricity enterprises
operated by the Ministry of Fuel and Energy of Ukraine.
The methodology for estimating the emission factor kC was based on the equation:kC =C daf 1000
, kg/GJ or Mg/TJ,⋅
100 Qidaf

where

Cdaf
Qidaf

(7)

is carbon contained in the combustible mass of fuel, %;is low heat value of the combustible mass of fuel, MJ/kg.

The carbon oxidation factor ε characterizes the efficiency of fuel carbon combustion. As
chemically analyzed, carbon accounts for most combustible materials in light ash and slag.
Therefore, an indicator of heat losses due to combustible loss may be used to find a local carbon
oxidation factor for a boiler. A value of heat loss for all of the fuels used for a boiler was found in[4] by:⎛C esc ⎞ r QC⎟⎟ A r K Q d SF ,%,q 4 = ⎜⎜ a sl C sl + a esc
C100−
Qi ( SF )
esc ⎠
⎝
where
asl , aвesc
Csl , Cesc
Аr
QC
Qri(SF)
KQ
dSF

(8)

is fuel ash shared in slag and escape;is combustible matters contained in slag and escape, %;is ash content in combustible mass of fuel, %;is heat value of 1 kg of carbon which is 32.657 MJ/kg;
is low heat value of combustible mass of solid fuel, MJ/kg;
is correction factor counting added heat to furnace with fuel, air and steam;is solid fuel shared (for heat) in total fuel burned in boiler; i.e. heat release of solid
fuel shared in total heat release of the whole fuel burned in boiler (solid, liquid andgaseous fuels).

The heat loss of solid fuel due to a combustible loss is found as:

q 4 ( SF ) = q 4 d ( SF ) .

(9)The specific quantity of unburned carbon is 1000⋅q4(SF)/(100·QC), kg/GJ. On the other hand,the carbon emission factor is a specific quantity of carbon in fuel. Then, the local carbon oxidation
factor for a boiler may be found by:

ε = 1−

1000q 4 ( SF )
100QC

⋅

1
.
kC

(10)

Statistical reporting form #3-tech "Report on Thermal Power Plant Operation. Performance
Parameters," which is submitted to the energy association (=company) that the enterprise is part ofand to the Ministry of Fuel and Energy, provides information on the total heat loss due to21

incomplete combustion of fuel. For the enterprises with dust-and-coal boilers that are lacking
information on heat losses due to combustible losses, the value of Q4(SF) was assumed as that in datafrom [29]. According to [30], the correction factor KQ for the Ukrainian Thermal Power Plants isvirtually adequate to 1.
In their reports, the thermal power enterprises do not provide information on the chemical(elemental) composition of the fuel, as this would require technological analysis of the fuel.
Therefore, the study assessed the local carbon emission factors for specific types of fuel based on
the data from the directories [15, 29], which provide detailed information on the elemental
composition and heat value of fuel used for most of the Ukrainian coal-mines and coal-dressing
mills.
The carbon emission factors for mayor Ukrainian coal types was determined using data on
the coal which is produced and processed by mines and dressing mills of Ukraine. The number ofmines surveyed varied as there is a degree of specialization in the types of coal that the mines
produce. Tables 3.14, 3.15, and 3.16 summarizes the data on the carbon content, low heat value andan emission factor for each of the coal sources in Ukraine. The study recommends to use theaveraged value for all of the coal sources as the national carbon emission factor. Summary of thenational emission factors and their comparison with IPCC default emission factors is presented inTable 3.13.
Net calorific values (also known as Low Heating Value, LHV) of coals are determined by
the molecular analysis of fuels and depends not only on carbon, hydrogen, and oxygen content incoal but also on ash and water content. Low Heating Values and Ash Content of coal used in 1999
and 2000 at some Ukrainian TPPs are shown in the Table 17. LHV increased greatly and ash
content of coal consumed by the Ukrainian coal-fired power plants was reduced in 2002 incomparison with 1999, and it had a positive effect on the efficiency of boilers and power units.
Table 3.13. Difference between national emission factors and IPCC emission factors

Anthracite:
Lean coal:
Gas coal and candle coal:National
Number of sources Standard IPCC emission
Difference, %emission
examineddeviation factor, tC/TJ
factor, tC/TJ
32 mines and
28.16
0.44
26.8
6.56
dressing mills
19 mines and
26.05
0.41
26.8
2.29
dressing mills
45 mines and
25.19
0. 26
25.8
0.5
dressing mills

22

Table 3.14. Gas Coal and Candle Coal Characteristics
Enterprises

Type

Ukraina CM
Ukraina CM
Kurakhiv CM
Mine No 105
Hirnyk Mine
Pryvilnyanska CM
60 Yr. Sov. Ukr. Mine
Trudivska Mine
Abakumov Mine
Chelyuskintsi Mine
Lenin Mine
Karbonit Mine
Hirska CM
Dimitrov Mine
Central Mine
Central Mine
Novodruzheska Mine
Kreminna CM
Kreminna CM
Bilorichensk CM
Slovyanoserbsk CM
Mikhailivska CM
Komsomol Ukrainy CM
Rossiya CM
Krasnoarmiysk CM
Pioner CM
Ternivska Mine
Pershotravneva Mine
Dniprovska Mine
Pavlograd Mine
Samara Mine
CPSU 26 Congress Mine
Yuvileina Mine
Novovolynsk Mine No 1
Novovolynsk Mine No 4
Novovolynsk Mine No 3
Novovolynsk Mine No 5
Novovolynsk Mine No 6
Novovolynsk Mine No 7
Novovolynsk Mine No 9
Novovolynsk Mine No 1
Novovolynsk Mine No 4
Chervonograd CM
CPSU 25 Congress Mine
USSR 60 YR. MineD, screenings
D, concentrateD, concentrateD, concentrate
DMSSH
DSSH
DR
DSSH
GSSH
GR
GR
GR
G, screenings
GSSH
GR
GSSH
GR
GSSH
G, concentrateG, screenings
G, concentrate
G, concentrate
G, pp
G, screenings
G, concentrate
G, slag
GR
GR
GR
GR
GR
GR
GR
М
М
R
R
R
R
R
SSH
SSH
SSH
R
R

Mean valueStandard deviation

Qidaf
Cdaf
%
MJ/kg
74.2 29.60
78.5 31.07
76.0 29.85
76.8 30.61
76.4 29.89
74.7 29.52
74.6 29.68
75.4 30.14
77.9 30.65
77.0 30.61
77.6 31.15
79.1 31.95
76.1 30.14
81.2 32.66
81.6 32.62
81.8 32.82
78.2 31.15
74.7 29.64
77.7 30.90
77.8 31.07
78.6 31.28
81.5 32.82
76.0 30.40
77.8 31.11
80.1 32.24
76.5 30.44
77.1 30.40
80.5 32.66
77.3 30.06
78.0 30.48
75.2 29.64
80.7 32.22
81.4 32.36
79.90 31.44
77.80 30.86
79.00 31.19
78.80 31.02
79.90 31.15
79.10 30.90
79.40 31.32
79.80 31.53
77.80 30.79
79.90 31.15
81.50 32.78
80.40 32.26

kc
kg/GJ
25.07
25.27
25.46
25.09
25.56
25.30
25.13
25.02
25.42
25.16
24.91
24.76
25.25
24.86
25.02
24.92
25.10
25.20
25.15
25.04
25.13
24.83
25.00
25.01
24.84
25.13
25.36
24.65
25.72
25.59
25.37
25.05
25.15
25.41
25.21
25.33
25.40
25.65
25.60
25.35
25.31
25.27
25.65
24.86
24.92
25.19
0.26

23

Table 3.15.Ukrainian Anthracite Characteristics
Enterprises

Type

Khrustalska Mine
Prapor Komunizmu
Concentrating Mill (CM)
Prapor Komunizmu CM
Miusinska CM
Miusinska CM
Izvestiya CM
Novopavlovska CM
Novopavlovska CM
Dzerzhinsky Mine No 2
Frunze Mine No 31-32
Rovenki CM
Rovenki CM
50 Years Sov. Ukr Mine
Lisova Mine
Mine No 3-bis
Snizhnyanska CM
Thorez CM
Thorez CM
Krasnaya Zvezda CM
Krasnayz Zvezda CM
Volodarsky Mine
Mine No 69
Krasnjpartizanska CM
Vakhrushev CM
Khrustalska CM
Komendantska CM
Yanivska CM
Central CM
Central CM
Partizan CM
Mayak CM
Mayak CM

АRSH
АSH

Cdaf
Qidaf
kc
%
MJ/kg kg/GJ
91.0 32.82 27.73
92.2 32.99 27.95

А, slagАSHА, slag
А, slagАSHА, slag
АRSH
АRSH
АSH
А, slag
АSH
АRSH
АRSH
АSH
АSH
А, slag
АSH
А, pp
АRSH
АRSH
АSH
АSH
АSH
А,pp
А,pp
АSH
А, slag
А, slagАSHА, slag

91.2
93.6
90.7
91.9
94.1
92.0
93.8
93.7
95.0
93.4
89.8
91.9
92.0
93.1
94.0
90.5
94.9
93.5
94.1
94.1
92.9
93.9
91.3
91.4
90.6
94.7
92.6
91.3
92.6
91.2

Mean valueStandard deviation

32.11
33.29
31.48
32.76
32.87
32.66
32.91
33.29
33.03
32.62
32.03
33.91
33.66
32.53
33.66
31.99
34.00
33.29
33.49
33.16
33.09
32.91
33.43
32.41
32.22
32.96
32.49
33.33
32.53
32.36

28.40
28.12
28.81
28.05
28.63
28.17
28.50
28.15
28.76
28.63
28.04
27.10
27.33
28.62
27.93
28.29
27.91
28.09
28.10
28.38
28.07
28.53
27.31
28.20
28.12
28.73
28.50
27.39
28.47
28.18

Table 3.16. Lean Coal Characteristics
Enterprises

Type

Komisarivska Mine
Fashivska Mine
Kosior Mine
Ukraina Mine
Nikanor Mine
Zhitomir Mine
Komunarska Mine
Rassvet Mine No 5/7
VZhSR 60 Years 3/4
Pravda Mine No 12/16
Pravda Mine No 20
Krasnaya Zvezda 20
Krasnaya Zvezda 8
Krasny Oktyabr Mine
Olkhovatska Mine
Vergelivska Mine
Annenska Mine
Mospinska CM

ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
ТR
Т,
conce
ntrateТ,
conce
ntrateKindrativska CM
Mean valueStandard deviation

Cdaf
Qidaf
kc
%
MJ/kg kg/GJ
88.5 33.66 26.29
89.5 33.47 26.74
88.7 33.45 26.52
84.4 32.87 25.68
89.0 34.49 25.80
91.8 35.09 26.16
90.8 34.25 26.51
91.3 34.83 26.21
88.9 34.00 26.15
87.0 33.78 25.75
87.0 33.82 25.72
88.4 34.83 25.38
85.1 33.45 25.44
88.9 34.28 25.93
90.5 33.70 26.85
89.7 34.46 26.03
86.0 33.54 25.64
89.9 34.58 26.00
90.9

34.67

26.22
26.05
0.41

28.16
0.44

Table 3.17. Low Heating Values and Ash Content on Ukrainian TPP
1999
2002
Coal
Power Plant
Low Heating
Ash
Low Heating
Ash
type
Value, MJ/kg
Content, %Value, MJ/kg
Content, %Kryvorizka TPP
L
17.20340.40
21.22729.80
Prydniprivska TPP
A
19.62330.70
22.651
23.00
Zaporizka TPP
G+C
15.86638.26
19.494
26.96
Slovianska TPP
A
17.66833.99
21.91423.08
Starobeshivska TPP
A+L
18.30835.10
21.34425.74
Burshtynska TPP
G+С
17.97828.50
19.03328.50
Dobrotvirska TPP
G+С
16.54634.29
20.231
26.97
Ladyzhynska TPP
G+С
13.81244.60
18.05326.41
Vuhlehirska TPP
G+С
20.64925.03
20.503
26.18
Zmiyvska TPP
А+L
18.46834.90
21.516
24.46
Trypilska TPP
А+L
17.11537.20
21.181
26.20
A – anthracite, L – lean coal (like semi-anthracite), G – gas coal (like bituminous coal), С – candle coal(like bituminous and sub-bituminous coals)

243.3 Carbon Oxidation Factors
The amount of carbon that may remain unoxidised from combustion activities can vary
for many reasons, including type of fuel consumed, type of combustion technology, age of theequipment, and operation and maintenance practices. 1996 Guidelines and 2000 GPG
recommend using default assumptions suggested both for the Reference Approach and the Tier 2
approach: 2 per cent of carbon in fuel consumed is unoxidised for coal, 1 per cent for oil-derived
fuels, 0.5 per cent for natural gas and 1 per cent for peat used for electricity generation.
Table 3.18. Default IPCC values(a)

FRACTION OF CARBON

Coal
Oil and Oil Products
Gas
Peat for electricity generation(b)OXIDISED

0.98
0.99
0.995
0.99

(a)This figure is a global average but varies for different types ofcoal, and can be as low as 0.91.
(b)The fraction for peat used in households may be much lower.

These assumptions are
based on 1984 study [31] andslightly adjusted based on theinformation from OECD Coal
Industry Advisory Board andBritish Coal (see text box below).

The IPCC Guidelines recognize that either detailed information on the type of technology
in which the fuel is combusted or information on which sector is consuming the fuel is requiredfor correct application of the oxidation factors. Therefore, although at the time of compilation of
the Guidelines more up-dated information on oxidation factor was available, only approximate
estimates were given, and national experts were encouraged to vary this assumption if they had
better data. Consequently the experts in Russia, Ukraine, and Kazakhstan made their own
assessments of the carbon oxidation factors for their research purposes, which are presented in thesubsections 3.3.1-3 below.
•

•

•

•

Marland and Rotty: For natural gas, less than 1 per cent of the carbon is unoxidised during combustion andremains as soot in the burner, stack, or in the environment. For oil 1.5% ±1% passes through the burners and isdeposited in the environment without being oxidised. This estimate is based on 1976 US statistics of emissions ofhydrocarbons and total suspended particulates. For coal 1% ±1% of carbon supplied to furnaces is discharged
unoxidised, primarily in the ash.
Australia: Unoxidised carbon from electric power stations in Australia averaged about 1 per cent. Test resultsfrom stoker-fired industrial boilers, however, were higher, with unoxidised carbon amounting to 1 to 12 per cent of
total carbon with coals containing from 8 to 23 per cent ash. As average values, 2 per cent carbon loss was
suggested for best practices, 5 per cent carbon loss for average practices, and 10 per cent carbon loss for worst
practices. In those cases when coal is used in the commercial or residential sectors, carbon losses would be on
the order of 5 to 10 per cent (Summers, 1993).
British Coal: Percentage of unburnt carbon for different coal combustion technologies:
Pulverised Coal
1.6%
Travelling Grate Stoker
2.7-5.4%
Underfeed Stoker
4.0-6.6%
Domestic Open Fire
0.6-1.2%
10
Shallow Bed AFBC
Up to 4.0%
10
PFBC/CFBC
3.0%
10
AFBC = Advanced Fluidised Bed Combustion
CFBC = Circulating Fluidised Bed Combustion
PFBC = Pressurised Fluidised Bed Combustion
Evaluations at natural gas-fired boiler installations indicate that combustion efficiency is often
99.9 per cent at units reasonably well-maintained.
Source: !996 Revised IPCC Guidelines: Reference Manual25

3.3.1 National values: Russia:
When RAO UESR developed its carbon emission factors for its corporate inventory, they
discounted their emission factor values to account for the fraction of carbon unoxidized
characteristic for their facilities. In this report we separate these two values mostly because on
average in Russia fuels are combusted with much lower efficiency than at large electric power
plants.
Fuel oxidation factors are rather high at the power plants of RAO UESR. For its
inventories RAO UESR has developed internal carbon oxidation factor for coal, which equals
0.984. This value was based on the survey power plants, in accordance with the combustion
efficiency they indicate on their internal reporting forms. The interim calculation factor (q4) was
determined only for those power plants which burned only one fuel type, in order to avoid
distortions in the calculations. Gas and heavy oil combustion at large power plants is very
efficient and fraction of un-oxidized carbon is considered to be negligible. The fraction ofunoxidized mazut has also not been studied specifically in Russia - it is assumed that the mazut
burned at the power plants is combusted almost entirely. The experts estimate that the fraction offuel unoxidized is 1% for gas and 0.5% for mazut, which is supported by international data (i.e.
IPCC default factors).
Thus the oxidation factors for large power plants are
Gas
0.999
Heating oil (mazut)
0.995
Energy Coal
0.984
According to RAO UES data, fuel other then coal, gas, or mazut is used only at one or two out of
370 large power-plants in Russia.
Because RAO UESR consumes only about 1/3 of the national fuel consumption volume,
it is recommended [19] that the IPCC default oxidation factors when carrying out greenhouse gas
emission estimation under the Reference Approach. If the technology type is known (as forexample for project level GHG emission assessment or for sectoral/entity level emission
estimation), [19] gives the oxidation factor for coal combustion in small boilers as 0.91, and forlarge enterprises (but not power plants) as 0.96, although it is not clear whether this are based on
country-specific research or on international estimates.

3.3.2 National values: Ukraine:
The values of carbon oxidation factor have been calculated in [28] using data from thestatistical reporting on the quality of fuels consumed (3-tech format). For the enterprises whichlack information on heat losses due to combustible losses, the value of combustible loss q4(SF) (seeFormula 9) was assumed as it is in [29]. Tables 19 and 20 show local oxidation factors for the
dust-and-coal power plants for 1990 and 1999.
IPCC default oxidation factor for all the types of solid fuel is 0.98. From the results of ananalysis of working parameters of the boilers in use at the Ukrainian electricity enterprises, thevalues of the local carbon oxidation factor were found for 1999 to vary from 0.741 (for Luhansk
TPP) to 0.997 (for Vuhlehirsk TPP). Because of the lack of information on heat losses for 1990,
the values of q4(SF) were taken from the directory [21] that are shown in Table 20.

26

With coal and mazut or natural gas burned together, the heat losses due to combustibleloss q4(SF) are growing [29]. For the boilers with liquid slag removal that burn anthracite or leancoal, the q4(SF) losses are 6.4%. For the boilers with liquid slag removal that burn gas or candle
coal, the q4(SF) losses are 0.7%. For the boilers with solid slag removal, combustible loss q4(SF) is
2.4%. This should be considered for finding greenhouse gas emissions from individual power
units and TPPs.
Table3. 19. Values of Heat Losses (%) Due to Combustible Loss
Fuels
Slag Removal
solid
liquidAnthracite
6.0
4.0
Lean coal
2.0
1.5
Bituminous coal
1.5
0.5

3.3.3 National values: Kazakhstan
Carbon oxidation factors for crude oil, gasoline, jet kerosene, diesel oil, heating oil, coal,and natural gas used when compiling the national inventories in Kazakhstan were calculated by
the Kazakh Scientific Research Institute for the Energy Industry (KazNIPIenergoprom) based ob
reference data from thermal power engineering manuals and state standards.
Fraction of carbon oxidized in boiler-houses was determined as a sum of mechanicallyand chemically incomplete fuel combustion. Coal in Almaty region is mainly combusted in theform of slag in chamber furnaces with dry-ash removal. The value of chemically incomplete
combustion for this type of combustion was assumed to be zero. The mechanically incomplete
combustion is defined by fuel underburnings left in cinder, fall-through and carryover. According
to reference data the fractions of carbon oxidized in coal-slack boiler are:
- 98.5 % for Ekibastuz coal combustion,- 99.0 % for Karaganda coal combustion.
Table 3.5 in section 3.2.1 contains the reference values that were taken for other types of coal.
For combustion of natural gas and residual fuel oil the fraction of carbon oxidised wasdetermined by chemically incomplete fuel combustion. According to reference data it amounts to99.5 %.

27

Table 3.20. Local Carbon Oxidation/Emission Factors for Coal in 1990
Company, enterpriseBase Fuel
Factors
Heat
Losses Oxida emiss.t/Т
q4(SF) % tionJ
Vinnytsyaenergo
Vibbytsya PTM
G/M
Ladyzhin TPP
G+D
0.70 0.991
25.19
Khmelnitsky PPEM
G/M
Chernivtsi OPM
G/M
Dniproenergo
Dniprodzerzhinsk CHP
G/M
Zaporizzhya TPP
G+D,G/M
0.70 0.991
25.19
Kirovograd CHP
G/M
Kryvy Rih TPP
Т+А
2.40 0.972
26.67
Кryvy Rih CHP
G/МPrydniprovska TPP
А+Т
6.40 0.930
27.38
Donbasenergo
Vuhlehirsk TPP
G+D,G/M
0.70 0.991
25.19
Donbasenergo ERP
G/M
Zuyiv TPP-2
G+D
0.70 0.991
25.19
Кramatorsk CHP
А
6.40 0.930
28.16
Кurakhiv TPP
G+D
2.10 0.974
25.19
Lisichansk CHP
G/М
Luhansk CHP
А+Т
6.40 0.930
27.38
Мyronivka TPP
А+Т
6.40 0.930
27.38
Мyronivka TPP
G+D
0.70 0.991
25.19
Severodonets CHP
G/М
Slovyansk TPP
А, G/М
6.40 0.930
28.16
Starobeshiv TPP
А+Т
6.40 0.930
27.38
Кyivenergo
Bila Tserkva CHP
G/М
Darnitsa CHP
А, G/М
6.40 0.930
28.16
Zhitomir PEM
G/МKyiv PTM
G/МКyiv CHP-5
G/М
Kyiv CHP-6
GМТrypillya TPP
А, G/М
6.40 0.930
28.16
Uman PEM
G/М
Cherkasy CHP
G+D,G/M
0.70 0.991
25.19
Chernihiv CHP
А, G/М
6.40 0.930
28.16
КrymenergoКamysh-Burun CHP
А
6.40 0.930
28.16
Saki PTM
G/М
Sevastopol CHP
G/М
Simferopol CHP
G/М
Lvivenergo
Burshtyn TPP
G+D
0.70 0.991
25.19
Dobrotvir TPP
G+D
2.10 0.974
25.19
Transcarpathian OPEM
G/МIvano-Frankivsk OPEM
G/МKalush CHP
G+D
0.70 0.991
25.19
Lviv PTM
G/М
Lviv CHP-2
G/М
Odesaenergo
Mykolaiv CHPА
6.40 0.930
28.16
Odesa CHP
G/М
Оdesa PTM
G/МKherson PTM
G/М
Kharkivenergo
Zmiyiv TPP
А+Т
6.40 0.930
27.95
Kremenchuk CHP
G/М
Okhtyrka PTM-2
G/М
Poltave PEM Pivdenne
G/МSumy PTM
А, G/М
6.40 0.930
28.16
Kharkiv TPP-2
А
6.40 0.930
28.16
Kharkiv CHP-5
G/М
Kharkiv PТМ
G/М

Table 3.21. Local Carbon Oxidation/Emission Factors for Coal in
1999
Base
Heat
Company, enterprise
Factors
Fuel
Losses oxidat emiss.t/Т
q4(SF)%
ion
J
Dniproenergo
Zaporizzhya TPP
G+D
0.78 0.990
25.19
Кryvy Rih TPP
Т+А
5.82 0.933
26.67
Prydniprovska TPP
А+Т
10.33 0.887
27.38
Donbasenergo
Zuyiv TPP
G+D
0.72 0.991
25.19
Kurakhiv TPP
G+D
3.22 0.961
25.19
Luhansk TPP
А+Т
23.62 0.741
27.38
Slovyansk TPP
А+Т
8.52 0.907
27.38
Starobeshiv TPP
А+Т
7.53 0.918
27.38
Zakhidenergo
Burshtyn TPP
G+D
1.41 0.983
25.19
Dobrotvir TPP
G+D
2.25 0.973
25.19
Ladyzhin TPP
G+D
1.24 0.985
25.19
Tsentrenergo
Vuhlehirsk TPP
G+D
0.25 0.997
25.19
Zmiyiv TPP
А+Т
10.58 0.884
27.38
Тrypillya TPP
А+Т
17.35 0.810
27.38
Vinnytsyaoblenergo
Vinnytsya PTM
Donetskoblenergo
Myronivka TPP
Zakarpattyaoblenergo
Transkarpathian OPEM
Kyivenergo
Кyiv CHP-5
Kyiv CHP-6
Kyiv Boiler HousesКrymenergo
Kamysh-Burun CHP
Crimean NPP Boiler
Saki Heat Networks
Saki Boiler Houses
Simferopol CHP
Оdesaoblenergo
Odesa PTM
PoltavaoblenergoКremenchuk CHP
Poltava PEM Pivdenne
Prykarpattyaoblenergo
Ivano-Frankivsk OPEM
Sevastopolmiskenergo
Sevastopol CHP
Cherkasyoblenergo
Chigiryn PS
Uman CHP
Chernivtsioblenergo
Chernivtsi PEM
OthersDniprodzerzhinsk CHP
ESKHAR (CHP-2)
Кryvy Rih CHP
Lisichansk CHPMykolaiv CHP
Odesa CHP
Severodonetsk CHP
Kharkiv CHP-5
Kharkiv Heat Networks
Kherson CHP
Cherkasy CHP

G/M
G+D

0.70

0.991

25.19

4.80

0.948

28.16

0.98

0.988

25.19

G/М
G/М
G/М
G/М
А+Т
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G/М
G+D

28

3.4 EMISSIONS FROM COKE GAS COMBUSTION
GHG emissions from coke gas combustion were examined in detail in a single pilot study
in Ukraine [32]. It was carried out at ZaporizhKoks coking plant in the city of Zaporizhzhia,
Ukriane as part of the outreach and capacity building activities of Canada-Ukraine Environmental
Cooperation Program. The study estimated plant’s CO2 emissions in 2000 and estimated process
emission factors. Emission factors were estimated using three methods: IPCC methodology,
methods based on standards and direct measurements.
Table 3.22. Comparison between IPCC, Ukrainian state standard, and measured emission factors.
MethodDeviation from default emission
Emission factor, t С/TJ
factor, %
13
0
IPCC9
Standards
12.73-2
Measurements
13.63
5

The Zaporozhye Coke Plant includes several process sections: coal preparation, coking, byproduct recovery, benzene production, de-sulfurization, sodium rodanite production, tar extraction,coke furnaces. Four coke ovens batteries and 14 coke ovens make up the core of Zaporizhkoks
production capacity. Besides, there are several facilities that are not directly involve in the
manufacturing process but which ensure the operation of the plant.
The coking at the plant is produced by heating fine dispersed10 coal batch to 950-1050oС atchamber-type ovens in the absence of oxygen. The time between loading and discharge of coke isusually between 16 and 22 hours. The process results in the release of 320 to 340 m3 of coking gas
per tonne of coal mix.
Table 3.23. The characteristics of Zaporizhkoks coke oven batteries
Coke ovenStart of theVolume of theHeatingbattery
operationchamber, m3
systemnumber
1-bis
1980
41.6
bottom
2-bis
1982
41.6
bottom
5
1983
21.6
side
6
1984
21.6
side

Number of
ovens
65
65
61
61

Dimensions of
the coking
chamber, m
16x7x4.1
16x7x4.1
14x4.3x4.1
14x4.3x4.1

After cooling and purification, the coke oven gas is transported to heat the coke ovens andto be used at other plant facilities. Coke ovens consume up to 50 % of the coke oven gas produced
at the plant. Other facilities that use the gas (1 to 4 %) include coke furnaces, tar extraction, benzene
production, sulfur production, repair shop, and coal defrosting facility. The latter consumes up 1 %of the coke oven gas in the winter period.

9

CORINAIR emission factor for coke oven gas combustion in coke oven furnaces 42-56 g/GJ (based on
CORINAIR 90 data).
From 1996 IPCC guidelines, for coke oven gas net calorific value 37.5 GJ/t (background paper), 17.5
MJ/m3, emission factor 13 tC/TJ (IPCC), 11 (background paper).
From GPG coke oven gas Net Calorific value for Ukraine is 25.12.
1075-80 % fraction smaller than 3 mm

29

Table 3.24. Composition of raw coke oven gas
Components of coke oven gas
H2
CH4
CO
CnHm
CO2
Ν2
О2

Concentration [Vol.-%]Winnacker 1982, from
Ukrainian study
CORINAIR58 - 65
57.6
24 - 29
25.3
4.6 - 6.8
6.8
2-4
2.3
1.5 - 2.5
2.5
4.5
1.2

Emissions during coking operations are caused by the charging of the coal into the ovens,
the oven/door leakage during the coking period, and by pushing the coke out of the ovens. Gas
combustion in the flues between the ovens, which produces the heat, necessary for the coking
process, is the major source of greenhouse gas emissions.
At the ZaporizhKoks facility, GHG emissions from a number of the sources at the facilty’s
coke plant were analyzed on several levels. GHG emissions during coke manufacturing can be
distinguished into continuous or controlled sources and discontinuous or uncontrolled sources (seetext box below). “Controlled” emissions of GHG occur when coke oven gas is combusted forvarious purposes during the manufacturing process. Estimation of missions from these sources israther simple, as it is possible to both measure and calculate GHG emissions with sufficientaccuracy. The main and continuous sources of GHG emissions in coke manufacturing are stacks(ascension pipes) that remove the flue gases formed during the combustion of coke oven gas. In
addition to coke oven batteries, coke oven gas at ZaporizhKoks is combusted at: benzene
production, coke furnaces, defrost facility (in the winter), ammonium sulphate drying, forge shop,
flaring of access gas.
The basic sources of uncontrolled GHG emissions to atmosphere are the coke ovenbatteries. During one hour there are 4 to 6 operations of charging and discharging the ovens, during
which there are inevitable escapes of GHG gases. Sources of such uncontrolled emissions at thecoke plant include by the charging of the coal into the ovens, coke discharging, coke quenching,leakage at the doors, pouring gates, and coke ramp. Estimation of GHG emission from uncontrolled
sources is more complicated, since it is determined by particular conditions of the plant components,
i.e. a composition of the coal mixture, technological parameters of the manufacturing process,duration and conditions of the operation of the equipment and other specific characteristic. The
GHG emissions from uncontrolled sources are periodical and their volumes are considerably lessthan that from the controlled sources.
Continuous emissions:
Discontinuous emissions:
Emissions from storage and handling ofOven charging
raw materials and products
Oven door and frame seal leakage
Coke pushing
Ascension pipe leakage
Coke coolingCharging holes leakage
Coke oven firing
Vent systems in gas treatment plant
Desulphurisation plant

30

Methodology
The emissions were calculated with three methods:•••

Calorific balance method as stipulated by the State Standard (normative method);
IPCC methodology
Direct measurement

Standard methodology
The normative method establishes the mass of fuel combustion products combustion offuel of given composition, in this case the coke oven gas:

M CO2 = 10 4 ⋅ Va ⋅ V0 ⋅ VCO2 ⋅ ρ CO2 ⋅ 10 −9 ,

(11)

where
- annual volume of combusted coke oven gas, thousand m3,
VaV0- volume of dry combustion products from combustion of 1 m3 of coke oven gas, equals
3.9 nm3/nm3 (when excess air coefficient is equal to 1),
VCO2 - maximum concentration of CO2 in combustion products, 10.5 %,

ρ CO
104
10-9

2

- CO2 density, 1,96 kg/m3,- conversion factor from parts to mg,- conversion factor from mg to tonnes.

IPCC methodology
The calorific value of the fuel in 2000 varied from 3950 to 4239 Kcal/m3 (according theZaporizhkoks JSC data). For the purposes of study, an average value of 4100 Kcal/m3 wasassumed. Default emission factor of 13 tC/TJ was used.
Instrumental measurements
The measurements of the GHG emissions were carried out with the use of different
methods and equipment, such as: the gas composition analysers «Testo-33», «Testo-350»(Germany), ЕΝЕRАС (USA), in which electrochemical cells are used as sensors. Measurement
error for O2(CO2) is ±0.2 %. Additionally, traditional analytical measurements were performed(gas chromatography and chemical method). Gas sampling was carried out in accordance with theprocedures prescribed by the State Standards (ГОСТ). The samples were taken during the normal
operating cycle of the equipment and with average coking period. The number of consecutive
samples taken from each source with each device was not less than five. The simultaneity of
taking measurements by different methods was ensured. The samples were collected over a
period of not less than 20 minutes. The results of the measurements were averaged for each of thesamples and further averaged for each of the analytical devices.
CO2 emissions were calculated based on the measurements of in-situ concentrations of in
the flue gas. For continuous emission sources, CO2 emissions were estimated in relation to theannual consumption of coke gas by plant. For discontinuous emission sources, cumulativeemission time per year was estimated; CO2 emissions were determined in relation to in-situ CO2
concentration in the flue gas and per-second flue gas emissions from the source. The following
formulas were applied:31

Continuous emission sources:ms
M CO2 = 10 ⋅ VCO⋅ ρ ⋅ α ⋅ K T ⋅ V0 ⋅ Va ⋅ 10 −3
2

(12)

ms
VCO
2

- measured concentration of CO2 in combustion products, %,ρ COα- CO2 density, 1,96 kg/m3,

2- access air factor, equals 1 under standard conditions,- temperature coefficient- volume of dry combustion products from combustion of 1 m3 of coke oven gas, equals
3.9 nm3/nm3 (when excess air coefficient is equal to 1),- annual volume of combusted coke oven gas, thousand m3,

KT
V0
Va

Discontinuous emission sourcesms
M CO2 = 10 4 ⋅ VCO⋅ ρ ⋅ W ⋅ T ⋅ 3600 ⋅ 10 −92(13)M CO2 - mass of emitted CO2
ms
VCO
2

- measured concentration of CO2 in combustion products, %,ρ COα- CO2 density, 1,96 kg/m3,

W
T
104
10-9

2

- access air factor, equals 1 under standard conditions,- spending of air-gas mixture,- time,- conversion factor from parts to mg,- conversion factor from mg to tonnes.

Table 3.25. Comparison of results for 3 methods for each estimated source
CO2 Emissions
Normative method,
IPCC,
Source of emission
thousand t
GgСО2
Coke oven battery #1-bis, stack
110.3
112.49Coke oven battery #2-bis, stack
126.65129.07
Coke oven battery #5, stack
66.9
68.2
Coke oven battery #6, stack
67.3
68.79
Pitch coke battery, stack
14.8
15.03
Tar extractor, stack
13.1
13.31
Defrosting facility, stack
6.3
6.34
Benzene production, stack
25.17
25.63
Sulfate production, stack
3.06
3.15
Forge shop, stack
3.1
3.52
Gas release rig
34.4
35.13
Total
471.5
480.7

Measurement
115.3
131.9
75.2
73.2
16.3
14.3
6.9
29.2
3.7
3.9
34.4 (calc.)
504.3

As can be seen from the table above, measured CO2 emissions exceeded calculated estimations
by 5 to 7 %, and for certain sources by up to 12.5 %. Taking into account actual fluctuations in
the composition of the coke gas, CO2 emissions exceeded calculated estimations by as much as
22 %.

32

CO2 emissions from coke oven gas combustion and estimated emission factors are
summarized in Tables 3.26 and 3.27.
Table 3.26. Coke oven gas combustion and estimated emission factors at ZaporizhKoks plant
Coke oven
Coke oven
Coke oven Coke ovenUnitbattery #1battery #2-bis battery #5
battery # 6
bis
Fuel consumption
ths m3/year
13752015774183360
84079
Coke producedt/year629775723896405572404970,9
Coke gas produced
ths m 3/year
918850Gas delivered toths m3/year
consumers
СО2 emissions
t/year116039132795,575659,2
73652,3Emission factortСО2/t of coke
0.184
0.183
0.186
0.181
*including pitch coke battery

Total
4627002164213,9932045*344566398146
0.184

Table 3.27. Coke oven gas combustion and estimated emission factors at ZaporizhKoks plant
Tar
Ammonium
Pitch coke
Defrosting Benzene
RepairGas
Parameter
Unit
extracto
sulfatebattery
facility production
shop release rigrdryingConsumption of fuel thous. m3/year
18382
16255
7752
31322
3835
4292
42941
Product output
t/year
43908
95760
32470
8805,5
Coke gas produced thous. m3/year
13195
Gas delivered tothous. m3/year
consumers
Emission of СО2t/year
16300
14300
6900
29200
3700
3900
34400
Specific emission oft.СО2/t.product.
0.37
0.15
0.9
0.42
СО2 per unit ofproduct

The study presents analysis of CO2 emissions from coke oven gas combustion at one
coking facility. It is not clear what conditions at other Ukrainian coke producers are and whether
the conditions described at this plant are representative for the Ukrainian coking industry.
Literature [18] indicates that emissions decrease with the increase of the size of the ovens, as
large ovens increase batch size and reduce the number of chargings and pushings, thereby
reducing associated emissions. Emissions are also reduced by constant coking conditions,cleaning, and a low-leakage door construction e. g. with gas sealings. Therefore more research isneeded on the prevailing coking technology in Ukraine and likely emissions if they have been
estimated. It would be also recommendable to estimate emissions of other pollutants from cokeovens, particularly CO, CH4, NOx, N2O, NMVOC.

33

4

CO2 EMISSIONS FROM MOBILE COMBUSTION OF FOSSIL FUELS

Only one country undertook a detailed analysis of CO2 emissions from mobile sources.
Kazakhstan as part of the regional GHG inventory project in Almaty region conducted analysis of
GHG emissions from the transportation sector, which among other included analysis of carbon
emission factors from fossil fuels used in vehicles in Kazakhstan.
Table 4.1 presents emission factors and other parameters used to convert combusted fuelinto CO2 emissions for this inventory. They were estimated by experts from
"KazNIPIenergoprom" and the Kazakh Research Designing Institute of Energy Industry forgasoline, diesel, liquefied petroleum gas (LPG), and compressed national gas (CNG) using
following information:- state standards for different fuel types,- statistical data,- data on several oil and gas deposits.
Table 4.1. Factors for CO2 emissions estimation from road transport
Fuel typeNet calorific value,
Carbon emission
TJ/unitfactor, t C/TJ
Gasoline
44.21
19.13
Diesel
43.02
19.98
LPG
47.17
17.91
CNG
34.25
15.03

Fraction of carbon
oxidized
0.995
0.995
0.99
0.995

Emission factors for non-CO2 gases were calculated for different vehicle types and fueltypes based on Russian Guidelines for estimation of road transport emissions to be used in
calculation of city air pollution [35]. Division of the fleet by types of vehicles were made byexperts from the Transport Research Institute that take into account recommendations from the
IPCC Guidelines:
Passenger cars

vehicles with rated gross weight less than 3500 kg designed to carry 12 or
fewer passengers
Light-duty trucks vehicles with rated gross weight less than 3500 kg designed forand minibuses
transportation of cargo or up to 16 passengers or which are equipped withspecial features for off-road operation. They include most pickup trucks,
passenger and cargo vans, four-wheel drive vehicles, and derivatives ofthese
Heavy-duty trucks manufacturer's gross vehicle weight rating exceeding 3500 kg. These
include large pickups, vans and trucks using pickup and van chassis, aswell as large heavy-duty trucks, which have gross vehicle weights morethan 7 tons
Buses
all buses except minibuses
The road fleet was not divided by the emission control technology type as all vehicles wereassumed to have no emissions controls. In support of this assumption, the share of vehicles
equipped with emission control technologies is negligible. Additionally, these vehicles are34

currently not separately registered in statistics. Table 2.9 presents the calculated emission factors
for non-CO2 gases. N2O emissions factors were taken from the IPCC Guidelines as default.
Table 4.2: Emission factors for CO2 and non-CO2 gases (CH4, N2O, CO, NOx, NMVOC) from roadtransport in Kazakhstan
Units
NOx

CH4

Gasoline passenger cars
g/km
1.80
0.023
g/kg of fuel
19.23
1.25
g/MJ
0.439
0.006
Diesel passenger cars
g/km
1.30
0.022
g/kg of fuel
14.59
1.25
g/MJ
0.342
0.006
Light-duty gasoline trucks and minibuses
g/km
2.90
0.047
g/kg of fuel
15.49
1.25
g/MJ
0.354
0.006
Heavy-duty gasoline trucks
g/km
5.20
0.05
g/kg of fuel
25.79
1.25
g/MJ
0.589
0.006
Heavy-duty diesel trucks
g/km
7.70
0.071
g/kg of fuel
27.16
1.25
g/MJ
0.637
0.006
Heavy-duty LPG trucks
g/km
2.6
0.047
g/kg of fuel
16.76
1.25
g/MJ
0.345
0.006
Gasoline buses
g/km
5.3
0.065
g/kg of fuel
20.45
1.25
g/MJ
0.467
0.006
Diesel buses
g/km
8
0.073
g/kg of fuel
27.43
1.25
g/MJ
0.644
0.006

Emission factors
NMVOC CO
N2O

CO2

SO2

2.1
22.44
0.512

19
203
4.636

0.1

291.56
3115
71.13

0.187
2
0.046

0.25
2.81
0.066

2
22.4
0.527

0.6

281.56
3160
74.14

0.891
10
0.235

11.5
61.43
1.403

69.4
370.7
8.466

0.1

583.13
3115
71.13

0.374
2
0.046

13.4
66.47
1.518

75
372.0
8.496

0.1

627.98
3115
71.13

0.403
2
0.046

6
21.16
0.497

8.5
30.0
0.703

0.6

895.86
3160
74.14

2.835
10
0.235

1.3
8.38
0.173

39
251.5
5.179

0.6

414.43
2672
55.04

0
0
0

13.4
51.70
1.181

97.6
376.5
8.599

0.1

807.41
3115
71.13

0.518
2
0.046

6.5
22.29
0.523

8.8
30.2
0.708

0.6

921.46
3160
74.14

2.916
10
0.235

35

5

FUGITIVE EMISSIONS FROM GAS SYSTEMS

Fugitive emissions from gas systems were systematically estimated mostly only in Russia.
There are four studies that estimate fugitive emissions from gas systems in Russia:
1. Two governmental studies – the Second National Communication and the RussianFederation Climate Change Country Study.
2. A study conducted by Gazprom and EPA that provides estimates of methane emissions
from compressor stations (Methane Leak Management at Selected Natural Gas Pipelines
Compressor Stations in Russia, referenced in [36])3. A study conducted by Gazprom and Ruhrgas that provides estimates for all segmentsthat Gazprom controls – “Estimating Methane Releases from Natural Gas Production
and Transmission in Russia” (Rurhgas and Gazprom study [37]).
The Second National Communication and the Russian Federation Climate Change Country
Study present estimates for the whole natural gas sector. In 1996-1997, under the U.S.
Country Studies Program and with assistance from the United States, Russia prepared a 6volume report about Russia’s climate change mitigation and adaptation policies – the RussianFederation Climate Change Country Study, published by Russian Federal Service for
Hydrometereology and Environmental Monitoring in 1997. The Country Study also provides
information about GHG emissions, including methane emissions from the natural gas sector.
The Country Study is the foundation for all government documents about climate change
mitigation policies in Russia. Most of the information for the National Communications wascollected under the Country Study. Because of budget constraints, the same small group of
experts participated in preparing the Country Study and the National Communications. The
Second National Communication (SNC) repeats the results of the first one and, therefore, thisreport describes only the SNC (Interagency Commission of the Russian Federation on
Climate Change 1998).
EPA and Gazprom conducted a number of measurements in preparation for implementing
a larger project under a GEF grant. EPA and Gazprom introduced more detailed methodsof estimating emissions and began developing activity and emission factors. Theirmeasurements cover only a small number of components. At the same time, the study
provided accurate component counts and described the methodology it used.
Ruhrgas and Gazprom conducted measurements at compressor stations, pipelines, and gas
processing plants. They extrapolated results to the whole natural gas sector. Gazprom andRuhrgas do not provide detailed descriptions of the components covered and do not develop
any activity or emission factors. Although their estimates of leaks from compressor stations
are close to EPA and Gazprom estimates, more information is needed to understand how
Ruhrgas and Gazprom derived these results. The uncertainty of results is also very high.
None of the studies presents statistical estimates of uncertainties, thus methane emissions
estimates are evaluated to have +/- 50 percent certainty: More measurements should be
conducted to come up with solid numbers concerning uncertainties.

36

Table 5.1. CH4 Emission Estimates from Different Segments of the Russian Natural Gas Sector
1990
1995
Country Study
Gazprom/EPA
Production
Processing Transmission(includes
StorageCompressor
maintenance Transmission
Stations
and flaring) Distribution Leaks Only

1997
Gazprom/Ruhrgas
Transmission
Production
Compressor stations
andPipeprocessing
lines Intentional Leaks

Emissions(million tones CH4)
Emissions(billion m 3)
Gas production(billion m 3)

3.1 - 7.5

6.2 - 13.6

1.48

0.22

0.85

0.74 - 1.2

1.6

4.19 - 10.13

8.37- 18.36

2

0.3

1.15

1 - 1.6

2.1

559.5

540

% from production

0.71 - 1.72

0.36

0.06

0.21

0.57 – 0.69

589.5
1.42 - 3.11

Sources: Russian Federal Service for Hydrometereology and Environmental Monitoring (1997b); [37]Table 5.2. Methane Emissions from the Whole Russian Sector
1990
Emissions(million tones CH4)
Emissions(billion m 3)
Gas production(billion m 3)
% from gas
production

1994

1997
Ruhrgas/Gazprom

SNC

CS

SNC

CS

16.0

16.0

15.2

11.5

4

21.6

21.6

20.5

15.5

5.4

589.5

589.5

570.5

570.5

540

3.7

3.7

3.6

2.7

1

SNC – The Second National Communication; CS – Country Study

37

6

FUGITIVE EMISSIONS FROM COAL MINING ACTIVITIES

Research into coal mining and coal bed methane emissions in Russia has been
supported mostly through the international activities of the Coalbed Methane Outreach
Program of the US Environmental Protection Agency. Although relevant activities wereconducted in all three countries, this report presents only the results of the activities
conducted in Ukraine and Kazakhstan, as the results of research carried out in Russia were notavailable at the time of preparation of this report.
6.1 IPCC Methodology
The general methodology for estimating methane emissions from coal-mining
activities is based on the accounting for all methane releases triggered by human activities
during the coal fuel cycle from the point of extraction to the point of utilization. Thus IPCC
Guidelines stipulate that methane emission estimates in the category of fugitive emissions
from coal mining and handling should be developed for three principal sources of methane
emissions: underground mines, surface mines, and post-mining activities:
Total emissions=

Emissions from underground mining+ Emissions from surface mines+ Post-mining emissions- Utilized and flared methane

The IPCC methodology describes three levels (Tiers 1-3) of precision in estimating
fugitive emissions from coal-mining activities. For Tiers 1 and 2 the estimation is made basedon the coal production data and a default global average (Tier 1) or national/regional (Tier 2)
emission factor. For the emissions from underground mining activities in the Former Soviet
Union region, IPCC recommends global average emission factors of 17.8 – 22.2 m3/tonne.
The estimation under Tier 3 is made based on the actual emission information obtained basedon the measurements in the mines.
However, since emission factors can vary significantly from basin to basin and evenfrom coal seam to coal seam depending on coal and geological characteristics, 11 it issuggested that countries estimate their national EF based on the coal characteristics in theircoal-mining regions. It is also recommended therefore that a database of relevant emission
factors is established to help other countries find matching mining conditions. In this section
11

Coal ranks - a measure of the degree of coalification (depends on geological history),
higher rank coals tend to have greater adsorptive capacities and therefore contain more gas.
Mining methods - there are two main underground mining methods: room and pillar andlongwall mining. The longwall process causes more caving and fracturing in the roof strata above thecoal seam that was mined than the room and pillar method. Correspondingly, greater volumes ofmethane are released per tonne of coal.
Permeability and diffusion rate - influence how quickly the gas can migrate through the coaland into mine workings. After the coal is mined utilizing the longwall method of extraction, the strata
overlying the mined coal caves in, causing a formation of highly fractured area, which increases thepermeability of the methane containing strata and facilitates the release of methane,38we would try to suggest Tier 2 country-specific emission factors for Ukraine and Kazakhstan
based on the Tier 3 emission information. According to the Reference Manual of the 1996
Revised IPCC Guidelines, both countries are among the 10 leading producers of coal in theworld.
6.2 UKRAINEThe inventories of fugitive emissions from coal-mining related activities weredeveloped for 1990-2001 with the assistance from the US EPA, and with the support of the
Ministry of Fuel and Energy of Ukraine, The Ministry of Labor Safety and Social Policy of
Ukraine, Makeyevka Mine Safety Institute, coal mine associations, and independent coalmines. A separate study was carried out in 2002 by the Donetsk Expert and Technical Centerof the Gosnadzorohrantruda (State Committee on Labor Safety) to quantify methane
emissions from the coal during post-mining activities. [ ]Ukraine has two major coal basins: the Donetsk Basin and the Lviv-Volyn Basin.
These basins contain both bituminous and sub-bituminous coal resources. The Donetsk Basinin the East of the country is Ukraine’s largest coal reserve, with a correspondingly large
number of mines. The Lviv-Volyn Basin, located in the western part of Ukraine, currently has
only 14 active mines, all of which are underground. As of January 1, 2002, there were 286
mines in Ukraine, 12 of them only 184 mines had industrial capacity and only 177 mines(underground and surface) produced coal in 2001.
Over 93.4% of the industrial coal reserves in Ukraine come from the depth of above
1,200 m depth, and 57% from above 600 m. The average depth of mining in Ukraine iscurrently 585 m. Approximately 44% of the mines are working at the depth over 600 m andproduce about 40% of the overall coal production. More than 21% of the mines are deeper
than 900 m, and some mines are deeper than 1,200 m. The raw coal ash content of the
produced coal is 37.2% on average through the coal industry. It varies from 20% to 54% atparticular mines. The moisture content of the raw coal is from 4% to 8%. The temperature at
the mine operating level can reach 42–52°C. The temperature of the rock strata is estimated to
be growing every year by 0.1–1.0°C due to the increasing depth of mining. All undergroundcoal mines in Ukraine use the longwall method of mining.
There are currently only three active surface mines in Ukraine and all of them arelocated in the western part of the Donetsk Basin. These surface mines produce peat, lignite,and sub-bituminous coals that have low methane content.
6.2.1 Underground mining
All Ukraine underground coal mines are required to monitor the methane
concentrations in the air at various locations in the mine workings. They are also required tomeasure the methane content of the coal being mined. If the methane content of coal exceeds
5m3 per tonne, the mine is categorizes as gassy and is obligated to report methane-related data
to the regional departments of the Ministry of Labor Safety and Social Policy of Ukraine.
Other indicators for the determination of reporting include concentration of methane andparticulates in the mining areas, historical frequency of methane outbursts, and various otherfactors. For different purposes, methane data are also reported to the mining associations and
12organized in 174 administrative units that include 48 structural units including 18 state holding
companies, 7 production associations, and 22 independent mines.

39the regional inspectorates of the Ministry of Ecology and Natural Resources. The methane
emissions reported by the mines include the data on the methane contained in the exhaust
ventilation air, the methane liberated by the mine degasification systems, as well as theamount of utilized methane.
Methane Emissions from Gassy Mines
The majority of Ukrainian mines are categorized as gassy. At some mines, the natural
gas content of the coal seams can exceed 35 m3 per tonne of dry ash free coal.13 There areseveral different technological processes designed to remove methane from the undergroundmining areas. These processes are the main source of methane emissions from undergroundmines and include ventilation systems and several degasification techniques. Methane
measurements are performed in both degasification and ventilation systems. Direct
measurements are applied to monitor two factors: methane concentration and gas mixture
flow rate. On the basis of these measurements, the total amount of emissions is calculated.
185 Ukrainian mines reported their methane emissions in 2000. This number also includes themines in the different phases of closure process, which continue their reporting until physicalclosure.
Ventilation Systems. Underground ventilation systems are installed in the mines forsafety reasons and consist of large fans that blow fresh air from the surface through theworking areas of a mine and remove the methane. The device used to measure methane
content in the ventilation air of Ukrainian mines is a model AMT-3 automatic meteringsystem. It includes a methane sensor, an alarm unit, a signal transmission system, and plotters.
Should methane content exceed the allowed limit, the alarm unit, which is installed in mineworkings, emits an electric impulse, cutting power supply to the mine working area. The
plotters continuously indicate volumetric percentage of methane in the air. The methane
sensor is based on the thermocatalytic principle. The metering range is 0 to 25 percent, with amargin of error of 0.2 percent and a time lag of 60 seconds. Additional methane content
analyses are performed by taking mine air samples and measuring the methane concentration
in a laboratory.
Degasification Systems. Mine degasification or drainage systems drain the gas fromcoal seams before, during, and after mining, depending on the particular needs of the mine.
There are three types of degasification techniques: vertical wells drilled from the surface,underground horizontal boreholes drilled along the mined coal seam, and cross-measureboreholes drilled through the coal seam and surrounding rock. Cross-measure boreholes aremost common in Ukrainian mines. They are used to degasify the overlying and underlying
strata of the mined coal seam. Cross-measure boreholes often produce gas with methane
content between 30 and 80 percent and their drainage efficiency averages 20 percent.
Additionally horizontal boreholes (typically 30 to 50 meters long) are drilled inside the mine
to drain methane from unmined areas of blocked-out longwall panels. Degasification wells
and boreholes are linked to a centralized vacuum pump or a compressor station by a system ofconnected pipelines. Since mines operate at very deep levels in Ukraine and have little funds
13

For the year 2000, the coal production from mines classified as gassy represented 82.4% of the total
underground coal production as compared to 69.6% in 1999. The significant increases in both total coalproduction and CMM emissions are due to the increase in the number of mines classified as gassy. In
1999, there were 164 gassy mines compared with 185 gassy mines in 2000.

40

to properly maintain their facilities, the drainage system often has multiple leakage points,
resulting in lower methane content in the gas stream.
To measure methane concentration in gas-air mixture captured by the degasification
system, Ukrainian underground mines employ model TP-2301 or GIAM-14 automatic gas
analyzers at the vacuum pump stations. The first analyzer meters the thermal conductivity
variation, and the second analyzer meters the optical density of the gas. Continuous readings
are plotted in the range of 0 to 100 percent. If methane concentration drops below a set limit(typically 35%), an alarm signal is initiated to automatically shut off the gas supply to theconsumer. The metering error is less than ±5 percent for a TP-2301 analyzer, and ±2 percent
for a GIAM-14 analyzer. The gas flow rate is calculated on the basis of the pressure
difference on diaphragms installed in the degasification system pipelines. Differential
manometers are calibrated to indicate the flow rate in cubic meters per hour, while other flow
meters are used to measure the pressure difference. Alternatively, ShI-12 portableinterferometers are used to measure methane content in mine workings by taking air samples
by hand.
Methane Emissions from Non-Gassy Mines
Between 1990 and 2000, 18 to 32 percent of Ukrainian mines did not exceed safety
standards and therefore were not required to report the emissions data. For the purposes ofthis inventory, a conservative approach based on the safety limit of the coal methane content
was used to estimate methane emissions from these mines, which is consistent with IPCC
Good Practice Guidelines. The maximum allowable methane content by the Ukrainian safety
standard is 5 m3 per tonne. Based on this, emissions factor of 3.4 kg of CH4 per tonne of coalproduced was derived. Since the mines have incentive to inflate the concentrations of methane
measured to be classified as gassy (i.e. dangerous), this estimate is strongly on theconservative side.
6.2.2 Surface mining
There are currently six surface mines in the western section of the Donbass Basin.
Only three mines, which mine brown coal, are active. The other three mines are in the processof closure and produce only small amounts of coal (two to three thousand tonnes per year) for
local needs. The coal produced by the surface mines is of a low rank that has minor methane
content; consequently, the mines do not report their methane emissions. In order to determine
methane emissions from surface mines, based on expert estimates and taking into account therange of 0.3 to 2.0 m3/tonne recommended in 1996 IPCC Guidelines, an emission factor of
1.4 m3/tonne (0.938 kg/tonne) was applied.14
6.2.3 Post-Mining Emissions
Post-mining activities such as processing, storage, and transportation also produce
methane emissions; however, these emissions are not reported. Therefore, a separate study
was carried out in 2001 by the Donetsk Expert and Technical Center of theGosnadzorohrantruda (State Committee on Labor Safety) to estimate Ukraine methane
emissions from post-mining activities in Ukraine. The methane emissions from coal aftermining by each particular mine were calculated taking into account the following factors:
14

Good Practice Guidance recommends applying a conservative value of 1.5 m3/tonne.

41

Ie=f (Am Xn Xr; Ts Tu W AC H H0 Vdaf), where
Ie - methane emissions, m3;
Am - amount of coal delivered to the surface, t;
Xn - natural gas content of the coal seam, m3/t dry and ash free;
Xr - remaining gas content of the coal, m3/t daf;
Ts - storage time of coal on the surface after mining, days (minutes);
Tu - storage underground after mining, hours;
W - coal moisture, before cleaning, %;AC - coal ash content, before cleaning, %;H - depth of mining, m;
H0 - depth of the upper level of methane gas zone, m;
Vdaf- volatility, %.

The amount of methane released from the coal after mining can be determined basedon the data about each mine and the characteristics of coal it produces. The statistic methods
were used to average this information for each individual mine and coal seam. The initial data
gathered from the mines consisted of over a thousand factors. The research was heavily basedon the historic data collected over the last 20–25 years to determine the natural methane
content of the industrial coal seams. The information about industrial coal seams volatility
was obtained from the technical tests of coal. Most of the data was double-checked with themines. The transportation and storage time was assumed to be 5 days, after that methane
emissions were discounted. Crushing of coal was also discounted.
The study arrives at an estimate of 200.89 million m3, or 136.4 Gg in total methane
emissions from post-mining activities in 2001. Taking into account total coal production forthat year, 82.49 million tonnes, an emission factor of 2.44 m3 /tonne was derived.15
6.2.4 Utilization of Coal-Mining Methane (CMM)
Of all CMM liberated by coal mines, approximately 12.4% is currently extracted throughdegasification systems, and only 3.5% is utilized. Forty-five mines in Ukraine useddegasification systems in 2000, and only 12 mines utilized methane for their needs: 7 mines
use methane as a substitute for coal in hot water boilers, one mine uses methane as fuel forcars and trucks, several use methane for power generation at diesel electric generators.
6.2.5 Emission factor estimation
In analyzing the results of the study, it appears that the general trend of the methane emissions
is in balance with the general trend of the coal production. Compared to previous estimates of
Ukrainian methane emissions from coal mines (First National Communication), the inventory
indicates slightly lower values (5% less 1990 and 8% for 1998). This difference is because
IPCC Tier 1 methodology was applied for the purposes of the First National Communication.
The later estimates, however, appear to be more precise as they are derived from a
combination of actual and calculated data.

15

1996 Revised IPCC Guidelines recommend methane emission factor of 0.2 to 4.0 m3 per tonne.

42The country specific emission factor that can be derived from the inventory, 16.55 m3/tonne
on average between 1990 and 2001 is close to the lower edge of the range recommended as
IPCC default value for Former Soviet Union region (17.8 – 22.2 m3/tonne).
Figure 6.1. Methane Emissions from Ukrainian mines 1990-2001
Methane Emissions from Ukrainian mines 1990-2001
120.00%100.00%T otal ventilation
80.00%
T otal degasification
60.00%

T otal methane fr om gassy mines
total coal pr oduction fr om gassy
mines

40.00%
20.00%

00

99

98

97

96

95

94

01
20

20

19

19

19

19

19

19

92

91

93
19

19

19

19

90

0.00%

43

Table 6.1. Methane Emissions and Emission Factors from Ukrainian Mines, 1990-1991
Gassy Mines (Measured Emissions)

Year

Total
ventilation
m3

Total
degasific
ation, m3

1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001

1,946.46
1,839.30
1,771.09
1,455.83
1,402.95
1,114.91
1,110.01
1,069.66
1,049.02
1034.03
1,211.60
997.28403.73344.52302.75252.21207.29183.68129.60142.45190.27174.31
177.79182.15Total
methane
from
gassy
mines
2350.192183.822073.84
1708.04
1610.24
1298.59
1239.61
1212.111239.29
1208.34
1389.39
1179.42

Total
methanelessutilization
2251.732089.98
2013.84
1660.851545.71238.04
1206.92
1173.52
1182.66
1154.66
1339.81088.09

Total coalproduction
from
gassy
mines
0.04
106.08
0.04
87.76
0.03
87.74
0.03
76.88
0.04
63.45
0.05
56.23
0.03
48.58
0.03
51.7
0.05
51.92
0.04
55.56
0.04
65.3
0.08
65.48
averagesd
confidence interval

Share ofmethaneutilized

Non-Gassy Mines

Emissionfactortotal

Emissionfactorlessutilization

22.15488
24.88423.6362
22.21696
25.37809
23.09426
25.51688
23.44507
23.86922
21.74838
21.27703
18.01191
22.93607
2.080238
0.037656

21.22672
23.81472
22.95236
21.60315
24.36091
22.01743
24.84397
22.69865
22.77851
20.78222
20.51761
16.61714
22.01778
2.181828
0.039495

Coal
produced

mln raw
tonnes
49.44
40.69
40.08
34.73
28.33
25.08
21.5
22.77
22.85
24.32
13.91
17

44

CH4
emittedm3
167.85138.14136.06117.89
96.19
85.15
72.99
77.3
77.57
82.55
47.29
57.72

Total undergroundmines coalproduction andmethane emissions
Total
Total
coal
methaneproducedemittedmln rawm3
tonnes155.52
2,419.58
128.452,228.12
127.81
2,149.90
111.6
1,778.74
91.78
1,641.89
81.31
1,323.19
70.07
1,279.91
74.47
1,250.82
74.77
1,260.23
79.87
1,237.21
79.21
1,387.09
82.49
1,145.81

National
emissionfactor
15.557999
17.3462047
16.8210625
15.9385305
17.8894095
16.2733981
18.2661624
16.7962938
16.8547546
15.4902967
17.5115516
13.8902897
16.5529961
1.21191648
0.02193791

6.3 KAZAKHSTAN [34]Kazakhstan is the third largest producer of coal in Former Soviet Union region after
Russia and Ukraine and ranks the eighth among the world producers. On per capita basis,
Kazakhstan takes first place in the Former Soviet Union with coal production of 4.5 t/per capita,
which is 3 times higher than in Russia and Ukraine. There are about 100 coal deposits in
Kazakhstan with geological reserves estimated at 176.7 billion tonnes. However only 40 of thedeposits have been explored and the estimated production reserves amount to 34.1 billion tonnes.
Kazakhstan produces either sub-bituminous coals or lignite from both surface andunderground mines. Ekibastuz, Kuuchekinsky and Borlinsky coal deposits are sub-bituminous of
low quality (high ash, sulfur content, and low heat content). These are mainly used at power
plants to produce electricity and heat. The Shubarkol, Karaganda and Maykyuben coal deposits
are of high quality and used mainly as a fuel in industrial and residential sectors.
The largest coal basins, Karaganda and Ekibastuz, are responsible for about 95 % of thetotal coal production in Kazakhstan. The main coal deposits are located throughout the central
part of the country, which is geographically convenient for coal transportation throughout thecountry. Nevertheless, transportation difficulties occur due to the low scale of development andcarrying capacity of the railway system.
Kazakhstan mines are aggregated into several coal producing associations (enterprises),of which three are the largest.
6.3.1 Underground Coal Mining
Underground mining is present only in the Karaganda basin, which is the largest coalmining region in Kazakhstan. These coals have relatively high ash content and are difficult towash. In 1990, 26 underground mines operated in Kazakhstan. By 1995, with many inefficientand unprofitable mines closed. Of the 12 mines remaining in 1995, only eight were still operatingin 2001 and four have nearly stopped production.
Mines in the Karaganda basin are considered to be very "gassy" with a high methane
content. The coal is mined at the depth of 650-700 m and production of 1 tonne of coal isaccompanied by release of about 33 m3 methane to the mine. Thus special attention is paid tolower the methane content in the mines and provide for its utilization. Surface wells are widelyused in the basin to provide degasification of the strata. The level of methane utilization is very
low although some portion of methane is recovered and used as fuel for heating. About 10-12
million m3 is recovered and combusted in 3-4 boiler installations. In addition, a portion of
methane emissions have been flared since 1999.
For safety reasons methane emissions from mine ventilation and degasification systems aremeasured and recorded, therefore a detailed Tier 3 methodology, as recommended by Revised
IPCC Guidelines was applied. However, because of the restructuring of the mining inventory,
only the data from operating underground mines were analyzed. "Ispat-Karmet" JSC that operates
the eight remaining mines was contacted for information. Total emissions from undergroundmines were estimated as the sum of the methane emissions measured from each mine’s
ventilation and degasification systems. The amount of methane utilized for internal purposes wasthen subtracted from the total to estimate the amount flared.

45

6.3.2 Surface Mining
Surface coal mining in Kazakhstan occurs throughout the country and accounts for an
increasing share of total coal production -- from 73% in 1990 to 89% in 2000. There are
numerous coal basins in Kazakhstan suitable for surface mining, but only a few are currently
exploited.
Ekibastuz basin is the center of the surface coal mining industry in Kazakhstan and has
been exploited since 1955. The main deposit contains about 7 billion tons of coal with over 75
billion m3 of methane embedded. Coal is produced at 3 open pit mines. Ekibastuz coal ischaracterized by high content of ash, sulfur, and mineral gangu. The Ekibastuz basin open pit
mines are the largest in Kazakhstan, responsible for 75-85% of the total surface coal productionin the Republic.
There are a number of small open pit coal mines located in different regions of
Kazakhstan that account for the remaining 15-25% of surface coal production, these include: one
open pit mine at Shubarcolskoe deposit producing high-quality coals, Borlinskoe deposit
producing low-quality sub-bituminous coal, two open pits producing low quality coals at
Kuuchekinskoe deposit north of Karaganda city, one open pit mine at Maykyubensky basin, andLowili deposit with a large seam of lignite with high ash and low sulfur content.
Surface mines in Kazakhstan are considered to be very gassy for open mining pattern.
Special efforts are therefore made to remove methane by blowing air through the tunnels,
resulting in roughly 70% of methane escaping to the atmosphere in the form of ventilation air.
Methane emissions from open pit mines were estimated separately for big mines and thenumerous small mines. The Tier II methodology was applied to estimate the CH4 emissions fromthe three largest open pit mines in the Ekibastuz basin. Experts from two coal-producing
enterprises operating the mines were contacted to obtain additional data.
Table 6.2. Data used for methane emissions estimation from surface coal mining16
Coal Production, million t
In-situ gas content
Severny mine
Bogatyr mine
Vostochny mine for Bogatyr, m3 CH4/t
Years
1990
15.0
37.0
20.9
9
1991
14.5
34.8
22.8
9
1992
13.9
32.7
21.7
9
1993
13.4
30.5
21.1
9
1994
12.9
28.3
19.3
9
1995
12.4
26.1
19.9
9
1996
11.8
24.0
17.0
9
1997
11.3
21.8
14.8
9.1
1998
15.1
21.4
10.9
8.6
1999
10.7
17.1
11.1
9.2
2000
12.7
23.1
16.0
9.2

Data on the in-situ gas content obtained for the "Bogatyr" open pit mine for 1997-2000
were applied as the in-situ gas content for the 1990-1996 period. The in-situ gas content of the“Vostochny” was assumed to be equal to that of "Bogatyr" as these two mines have a similar
methane bearing capacity (about 8-12 m3 per ton) as they are located in the same deposit close to16

1990-2000 coal production data were available only for "Vostochny" mine. For "Severny" and "Bogatyr"mines 1997-2000 production data were interpolated to 1990-1996 period.

46

each other and have similar coal characteristics and mining conditions. According to expert
judgment at the "Severny" mine, coal is produced in the methane-free strata (above 200 m) thus
CH4 emissions from this mine are negligible.
The number of open pit mines is rather high and not all submitted the requested data.
Methane emissions from the rest of the open pit coal mines were estimated using the Tier I
methodology. Coal production from these mines was defined as the difference between total coalproduction in Kazakhstan minus the coal production by the "Ispat-Karmet" underground minesand by the "Bogatyr", "Vostochny" and "Severny" open pit mines. The emission factor was takenfrom the Revised IPCC Guidelines (Tier I).
Emissions from the surrounding strata were assumed to be negligible, as the surrounding
strata consists mostly of sand and rocks.
6.3.3 Post-Mining Emissions
A national emission factor equal to 1 m3 of CH4 per ton of coal produced was used toestimate post-mining emissions from underground mines, based on the expert assessment of"Ispat-Karmet" JSC. This value reflects the normative emissions in accordance with "Guidelines
for designing of ventilation systems at coal mines" and "Handbook for designing of coal-mining
buildings and processing plants with highly explosive and fire-risk conditions". Post-mining
emissions from surface mining were assumed to be negligible. No estimates were made of theemissions from abandoned mines because of data availability issues.
Based on actual measurements from underground mines and activity data combined forsurface mines, overall methane emissions from coal-mining activities in Kazakhstan were
estimated. The inventory compilers estimated overall uncertainty as ±20%.
Figure 6.2. Trends in Underground Coal Production and CMM Emissions in Kazakhstan, 1990-2000
Trends in Underground Coal Production and CMM Emissions in
Kazakhstan, 1990-2000
120.00%100.00%80.00%
Underground coal production
Degasif ication

60.00%

V entilation
Total

40.00%
20.00%

99

98

97

00
20

19

19

19

95

96
19

19

94
19

93
19

92
19

91
19

19

90

0.00%

47

Table 6.3. Data used for methane emissions estimation from surface coal mining17

Years

1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000

Measured methane emissions,mln m3

Total Coal
Production, mln t

Underground Coal
Production, mln t

Degasifi
cationVentilation

131.44130.38126.54111.88104.63
83.36
76.83
72.59
69.71
58.20
74.87

35.31
36.91
34.40
31.10
29.14
23.30
15.10
12.90
9.20
7.30
8.20

189.84200.83179.97162.96148.31115.80
55.40
48.20
42.60
27.20
41.00

983.66914.75915.52957.82678.12671.37408.00347.45303.45227.32286.23

Total
1173.501115.58
1095.491120.78826.43787.17463.40395.65346.05254.52327.23averageSD

Emissionfactor forunderground coal
33.23
30.22
31.85
36.04
28.36
33.78
30.69
30.67
37.61
34.87
39.91
33.38
3.33

Methaneutilized
and/orflared,mln m3
9.09
11.16
11.30
13.25
5.74
6.10
3.60
4.03
10.70
11.60
12.50

EF forunderground coal lessmethaneutilization
32.98
29.92
31.52
35.61
28.16
33.52
30.45
30.36
36.45
33.28
38.38
32.78
2.96

17

Calculated methane emissions,mln m3
Surface Surface
Postmines,
mines,
miningTier II
Tier I,
activities
521.2846.43
35.31
519.0042.67
36.91
488.9047.75
34.40
463.9431.63
31.10
428.1930.04
29.13
414.243.34
23.30
369.1617.76
15.10
331.4323.60
12.90
282.2426.21
9.19
257.0724.03
7.30
356.43
29.76
8.19

Total
Emitted
Methane, m3
1767.43
1703.00
1655.24
1634.211308.06
1221.94861.84759.57653.00531.31
709.13

1990-2000 coal production data were available only for "Vostochny" mine. For "Severny" and "Bogatyr" mines 1997-2000 production data were interpolated
to 1990-1996 period.

48

National
emissionfactor, m3
13.45
13.06
13.08
14.61
12.50
14.66
11.22
10.46
9.37
9.13
9.47
11.91
1.98

7

СО2 EMISSIONS FROM CEMENT MANUFACTURE

GHG emissions are generated by the calcination process, which is the chemicaltransformation of input materials into cement, and the combustion of fuels to generate theheat necessary for calcinations to occur. In 2002, Ukrainian Agency for Rational Energy Use
and Ecology conducted an inventory of GHG emissions from cement manufacturing sector,
which among other included CO2 emissions from chemical processes during clinker
production. [43]As background, СО2 is produced during clinker production, an intermediate productfrom which cement is made. In the temperature range of 820-9070C СаСО3 from lime
decomposes into СаО and СО2, the latter being a byproduct of the reaction. Silica, aluminum,and iron oxides react with СаО to mineralize the clinker and form calcium silicate. The
clinker, the end product of the baking process, is a system of artificial minerals: 3СаО · SiО2,2СаО · SiО2, 3СаО · Аl2О3 and 2СаО · Fе2О3, which contains intermediate products from theunfinished reactions, as well as various admixtures of inactive ballast compounds.
Since clinker consists of different artificial minerals and based on the fraction of eachmineral in clinker, the СО2 inventory factors for the calcination process might be specified byusing the atomic mass of each chemical components of the minerals. In general, the СО2
estimation factor for calcination is specified based on the information related to clinker
production, using the following formulacl
K CO= 0.785∑ δ i ξ i ,2(13)

where,

K cocl 2СО2 emission factors for calcination process, t CO2/t clinker

0.785
i

ratio of molecular weight of СО2 and СаО, relative units
index of artificial mineral, that contained in clinker
content of CaO in i-mineral, relative units
content of each artificial mineral in clinker, relative units.

δiξiThe СаО content in each artificial mineral contained in the clinker is estimatedbased on the molecular weight of each element contained in artificial mineral and themolecular weight of the whole artificial mineral.

δi =N i μ CaO

μi

,

(14)

where,

δi

Ni

μCaO
μi

content of CaO in i-mineral, relative units

number of CaO molecules in each artificial mineral, units
molecular weight of CaO, kg/mole
molecular weight of each artificial mineral, contained in a clinker, kg/moleTo establish national СО2 emission factors for each type of cement produced in
Ukraine, Arena-ECO used reference data on cement quality from state standards, using
formula (41). The factors are expressed in ton of СО2 per one ton of clinker are presented inTable 7.1 below.

49

Table 7.1. СО2 emission factor by cement types produced in Ukraine
CementSub-types

Clinker
content incement,%Artificial mineralin clinker

Cement for common construction purposes
Portland cement
95-1003СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3

Portland cementwith slag

65-94

Portland cement80-943СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3

Portland cementwith ash ejection

80-943СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3

Portland cement
limestone

80-94

Cement forasbestos cement
products

80-94

Composite
cement

65-94

Fast-hardening
cement90

Road cement

95-100Slag Portland
cement20-64

Pozzolan cement

45-79

Composite
cement20-643СаО SiO2++3СаО Al2O3
2CaO SiO2++4СаО Al2O3Fe2O3

3СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3
3СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3
3СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3
3СаО SiO2++3CaO Al2O3
2CaO SiO2++4CaO Al2O3Fe2O3
3СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3
3СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3
3СаО SiO2
3СаО Al2O3
3СаО Al2O3++4СаО Al2O3Fe2O3
Al2O3
MgO
3СаО SiO2
2CaO SiO2
3CaO Al2O3

Mineralogicalcomposition ofclinker (% ofweight)CaO
content
in clinker,
%

40-65
15-40
5-15
10-20
0-65

46.9792.51

0.369 -

43.8716.87

0.344-

46.97-

0.369-

46.9792.51

0.369-

46.9792.51

0.369-

46.979.51

0.369-

46.9792.51

0.369-

60.74

0.477

46.9792.51

0.369-

46.9792.51

0.369-

33
40-65
15-40
5-15
10-20
40-65
15-40
5-15
10-20
40-65
15-40
5-15
10-20
40-65
15-40
5-15
10-20
40-65
15-40
5-15
10-20
0-65
35
40-65
15-40
5-15
10-20
40-65
15-40
5-15
10-20
Not standard

CO2 emission
factor,tCO2/t clinker

Sources[45,48]0.726[45,48]0.132[45,44][45,44]0.726[45,44]0.726[44,48]0.726[45,44]
0.726

[48]

[45,44]0.726[45,44,48]
0.726

45.74

0.359

[46,48]8
Not standard
5
5
40-65
15-40
5-15

46.9792.51

0.369-[44,45]
0.726

50

4CaO Al2O3 Fe2O3

Cement types for
cementation
without forming

20-64

Sulfate-resistant cements
Sulfate-resistant100
Portland cement

Sulfate-resistant
blendedPortland cement

80-90

Sulfate-resistant
Slag Portland
cement20-50

Pozzolan
Portland cement

20-40

Oil-well Portland cement
Oil-well Portland 100
cement without
additives
Oil-well Portland
cement with normal
requirements atwater cement rati

100

Oil-well blended

80-94

Oil-well Portland

30-89

cement with special
additives that
control cement
dough density

Alumina cement
Alumina cement

Gypsum andalumina
expandingcement3СаО SiO2
2CaO SiO2
3CaO Al2O3
4CaO Al2O3 Fe2O3

10-20
40-65
15-40
5-15
10-20

46.9792.51

0.369-[44,45]0.726

3СаО SiO2
3CaO Al2O3
3СаО Al2O3++4СаО Al2O3Fe2O3
Al2O3
MgO
3СаО SiO2
3CaO Al2O3
3СаО Al2O3++4СаО Al2O3Fe2O3
Al2O3
MgO
3СаО SiO2
3CaO Al2O3
3СаО Al2O3++4СаО Al2O3Fe2O3
Al2O3
MgO
3СаО SiO2
3CaO Al2O3
3СаО Al2O3++4СаО Al2O3Fe2O3
Al2O3
MgO

0-50
0-5
0-22

51.37

0.403

[46,48]Not standard
522
55
Not standard
8
Not standard

60.96

0.478

[46,48]

56.48

0.443

[46,48]

56.48

0.443

[46]

3СаО SiO2
3CaO Al2O3
3CaO Al2O3++4СаО Al2O3Fe2O3

Not standard
3
22

68.32

0.536

[47, 48]

3СаО SiO2
3CaO Al2O3
3CaO Al2O3+4СаО
Al2O3 Fe2O3
3СаО SiO2
3CaO Al2O3
3CaO Al2O3+
4CaO Al2O3 Fe2O3

48-65
3-8
24
Not standard
5
22

68.32

0.536

[47, 48]

3СаО SiO2
3CaO Al2O3
3CaO Al2O3+

Not standard
5
22

68.32

0.536

[47, 48]5
5
Not standard
8
Not standard
5
5

49.6965.33

0.390-[47]
0.513

4CaO Al2O3 Fe2O3

100

СаО Al2O3,
12СаО 7 Al2O3
СаО 2 Al2O3
2СаО Al2O3 SiO2,
FeO

40

0.314

70

СаО Al2O3,
12СаО 7 Al2O3
СаО 2 Al2O3
2СаО Al2O3 SiO2
FeO

40

0.314

[48,49][50][48,49][50]

51

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