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production disposition analyses (e.g., oil and gas production; vented, flared andreinjected volumes of gas; and fuel gas consumption),•

accidental releases (i.e., well blow-outs and pipeline ruptures),•typical design and operating practices and their impact on the overall level ofemission control.

The amount of emissions is then assessed by applying appropriate emission factors,
empirical correlations, process simulation results, and field measurements to these data.
Some examples of detailed emission inventories that have been developed in this mannerare listed below:•

US Environmental Protection Agency (US EPA). Anthropogenic Methane Emissions
in the United States. Estimates for 1990: Report to the Congress. October 1992
(US EPA, 1993).

•

Picard, D.J., B.D. Ross, and D.W.H. Koon. A Detailed Inventory of CH4 and VOC
Emissions from Upstream Oil and Gas Operations in Alberta. ClearstoneEngineering Ltd., for the Canadian Petroleum Association, March 1992 (Picard et al.,1992).

•UK Offshore Operators Association Ltd. (1992). Methane Emissions From
Offshore Oil & Gas Exploration & Production Activities. Submitted to The Watt
Committee on Energy, 1993.

•

Norwegian Oil Industry Association - OLF. Report from OLF Environmental
Programme - Phase 2. 1993.

1.8.7 Uncertainty
Some of these studies do analyse uncertainties, but emissions estimates in general arevery uncertain. The overall magnitude of the emissions estimates that will be obtained
for some countries using the methods and assumptions outlined in this chapter is driven
by two key studies:•

Rabchuk et al. (1991) report that emissions from gas production andtransportation in the former USSR is very high, about 3 to 7 per cent of total gas
production. Recent visits to this region indicate that system construction,
maintenance, and operations may be consistent with high emissions rates (Craig,1992). However, a better quantitative evaluation is needed to validate the current
emissions estimates.

•

Barns and Edmonds (1990) report emissions from venting and flaring by region.
The emissions estimates for the OPEC countries are relatively high, and account formost of the emissions from this category. The safety concerns associated withventing, and the value of re-injecting gas into oil reservoirs to maintain reservoirpressures, would tend to render the high emissions estimates questionable.
Improved data are needed to resolve this question.

The adoption of emission factor estimates from US EPA (1992) for various regions also
adds uncertainty to the overall estimates. US oil and gas production facilities andrefineries are subject to emission control requirements. The US emission factors,
particularly for refining, may under-estimate emissions in other regions. Nevertheless,this may not be a significant global uncertainty since, if the emission factors for oil
production and oil refining were increased by a factor of 10 for the entire world, theestimate of total global emissions would only increase by about 1 to 6 Tg for 1988.

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ENERGYTABLE 1-60
USA AND CANADA - EMISSION FACTORSEmissions Type

Emission factor

Sourcekg/petajoule
Oil and Gas Production
Oil

290 - 4 670 of Oil Production

US EPA (1992)

Gas

39 590 - 104 220 of Gas Production

US EPA (1992)

Oil & Gas

2 870 - 13 920 of Oil & Gas Production

US EPA (1992)

Crude Oil Transportation and Refining
745 of Oil Tankered

API (1987)

Refining

90 - 1 400 of Oil Refined

US EPA (1992)

Storage Tanks

20 - 260 of Oil Refined

US EPA (1992)

59 660 - 116 610 of Gas Consumption

US EPA (1992)

Gas Processing..

..

Gas Pipelines..

..

Gas Distribution..

..

Transportation

Natural Gas Processing, Transport, andDistribution

TABLE 1-61
EASTERN EUROPE AND FORMER USSR - EMISSION FACTORSEmissions Type

Emission factor

Sourcekg/petajoule
Oil and Gas Production
Oil

290 - 4 670 of Oil Produced

US EPA (1992)

Gas

218 000 - 567 600 of Gas Produced

Rabchuk et al. (1991)

6 300 - 29 700 of Gas Produced

Barns and Edmonds (1990)

Oil & Gas
Crude Oil Transportation and Refining

745 of Oil Tankered

API (1987)

Refining

90 - 1 400 of Oil Refined

US EPA (1992)

Storage Tanks

20 - 260 of Oil Refined

US EPA (1992)

340 000 - 715 800 of Gas Consumption

Rabchuk et al. (1991)

Gas Processing..

..

Gas Pipelines..

..

Gas Distribution..

..

Transportation

Natural Gas Processing, Transport, andDistribution

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TABLE 1-62
WESTERN EUROPE - EMISSION FACTORSEmissions Type

Emission factor

Sourcekg/petajoule
Oil and Gas Production
Oil

290 - 4 670 of Oil Produced

US EPA (1992)

Gas

14 800 - 27 000 of Gas Produced

Schneider-Fresenius

Oil & Gas

13 000-16 000 of Gas Produced

Norwegian SPCA (1992)

3 000-8 000 of Gas Produced

Norwegian O.I.A. OLF (1993)

745 of Oil Tankered

API (1987)

2 500 of Oil Tankered

Norwegian SPCA (1992)

90 - 1 400 of Oil Refined

US EPA (1992)

et al. (1989)

Crude Oil Transportation and Refining
Transportation

Refining

20 - 260 of Oil Refined

US EPA (1992)

58 000 - 111 000 of Gas Consumption

Schneider-Fresenius et al. (1989)

Gas Processing

1 800 of Gas Processed

Norwegian SPCA (1992)

Gas Pipelines..

..

Gas Distribution..

..

Storage Tanks
Natural Gas Processing, Transport, andDistribution

TABLE 1-63
OTHER OIL EXPORTING COUNTRIES - EMISSION FACTORSEmissions Type

Emission factor

Sourcekg/petajoule
Oil and Gas Production
Oil

290 - 4 670 of Oil Produced

US EPA (1992)

Gas

39 590 - 96 000 of Gas Produced

US EPA (1992) and Barns

739 470 - 1 019 220 of Gas Produced

Barns and Edmonds (1990)

745 of Oil Tankered

API (1987)

Refining

90 - 1 400 of Oil Refined

US EPA (1992)

Storage Tanks

20 - 260 of Oil Refined

US EPA (1992)

116 610 - 340 000 of Gas Consumption

US EPA (1992 andRabchuk et al. (1991)

Gas Processing..

..

Gas Pipelines..

..

Gas Distribution..

..

and Edmonds (1990)
Oil & Gas
Crude Oil Transportation and Refining
Transportation

Natural Gas Processing, Transport, andDistribution

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ENERGYTABLE 1-64
REST OF THE WORLD - METHANE EMISSION FACTORSEmissions Type

Emission factor

Sourcekg/petajoule
Oil and Gas Production
Oil

290 - 4 670 of Oil Produced

US EPA (1992)

Gas

39 590 - 96 000 of Gas Produced

US EPA (1992) and Barns andEdmonds. (1990)

Oil & Gas

170 000 - 209 000 of Gas Produced

Barns and Edmonds (1990)

Crude Oil Transportation and Refining
Transportation
Refining

745 of Oil Tankered

API (1987)

90 - 1 400 of Oil Refined

US EPA (1992)

20 - 260 of Oil Refined

US EPA (1992)

116 610 - 340 000 of Gas Consumption

US EPA (1992 andRabchuk et al. (1991)

Gas Processing..

..

Gas Pipelines..

..

Gas Distribution..

..

Storage Tanks
Natural Gas Processing, Transport, andDistribution

1.8.8 Fugitive Emissions of Other GHGs
Methane is by far the most important greenhouse gas emitted on a fugitive basis from oil
and gas activities. However, other GHGs are clearly emitted and should be included in acomprehensive national inventory.
After methane, the most significant fugitive emissions from oil and gas activities are of
non-methane volatile organic compounds (NMVOCs). Oil and gas are largely composedof organic compounds, and releases through evaporation or leakages are likely at allstages wherever the fuels or their products come into contact with the atmosphere.
Fugitive emissions from refining, transport and distribution of oil products are a major
component of national NMVOC emissions in many countries.
The IPCC/OECD/IEA programme has not yet addressed the indirect GHGs (including
NMVOCs) in detail. However, the Joint EMEP/CORINAIR Guidebook offers both asimplified and a more detailed approach to the estimation of ozone precursors and SO2.
The relevant tables and accompanying text are summarised below.
National experts interested in including the other fugitive emissions of GHGs from oiland natural gas systems should consult the existing literature which provides detailed
emission factors and procedures for calculating emissions. Some key examples are:•

Default Emission Factors Handbook (EEATF, 1992);•

Proceedings of the TNO/EURASAP Workshop (TNO Inst. of Environmental
Sciences, 1993);•

Atmospheric Emission Inventory Guidebook (Joint EMEP/CORINAIR, 1996);•

EMEP and CORINAIR Emission Factors and Species Profiles for Organic
Compounds. (Veldt, 1991);•

US EPA's Compilation of Air Pollutant Emissions Factors (AP-42), 5th Edition 1995
(US EPA, 1995);

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Criteria Pollutant Emission Factors for the 1985 NAPAP Emissions Inventory(Stockton and Stelling, 1987).

1.8.9 Refineries
OVERVIEW
A basic refinery converts crude petroleum into a variety of sub-products. Principal
products of a refinery may include liquid fuels, coke, feedstocks and primary
petrochemicals (like ethylene). This section covers basic refineries, not the synthesis ofpetrochemicals. Chemical production is included in Chapter 2, Industrial Processes,
whether or not the actual production takes place at a refinery or in a separate plant.
Storage and handling of intermediates and products may account for between 1 to 8 percent of a country’s NMVOC emissions. There are also significant non-combustion
emissions of SO2, NOx, and CO.
Refinery Operations
Refinery operations include separation processes (distillation and gas processing),
petroleum conversion processes (cracking, coking, catalytic reforming, alkylation,polymerisation), petroleum treating processes (desulphurisation, chemical sweetening,acid gas removal, deasphalting) and blending.
Vacuum distillation, catalytic cracking, thermal cracking, sweetening, blowdown systems,
sulphur recovery and asphalt blowing have been identified as being potentially significant
sources of SO2 and NMVOCs from these sources. Storage and handling of petroleum
products will lead to NMVOC emissions.

SIMPLE METHODOLOGY FOR OZONE PRECURSORSAND SO2
A simple estimation can be made on the basis of throughput and single emission factors.
However in most cases more detailed information may be available and the more detailed
approach outlined in the Joint EMEP/CORINAIR Guidebook (1996) under SNAP code
40100 or in the following section here should be adopted. This considers the actual
processes taking place in the refinery and the throughput of crude and products. Whileemission rates will depend on the specific process and equipment in a refinery, its state ofmaintenance and the sulphur content of the crude oil, a very simple estimate can be madeon the basis of the throughput of crude oil and simple emission factors alone. The default
emission factors are shown in Table 1-65.

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ENERGYTABLE I-65
NON-COMBUSTION EMISSION FACTORS FOR PETROLEUM REFINING. SIMPLE METHODOLOGY(KG/M3 REFINERY FEEDSTOCK E.G., CRUDE OIL)
POLLUTANTEMISSION FACTOR

SOURCES

SO2(a)

0.8

Vacuum tower, catalytic cracker, fluid coking, sulphur plant, SWS,
incinerator, caustic regeneration, vents, off gases, others

NOx(a)

0.05

Catalytic cracking

CO(a)

0.08

Fluid catalytic cracker only

NMVOC(b)0.53

Fugitive and process emissions

Source :(a) EMEP/CORINAIR (1996).
(b) based on CPPI and Environment CANADA (1991).

NMVOC Emissions estimates vary widely. The proposed default value is 0.53 kg/m3 input.
Estimates range from 0.085 kg/m3 from the best West European refinery to 10 kg/m3 fora Russian refinery.
In practice it may be possible to use a more detailed approach where some of the
makeup of the refinery is known or where only some of the emission activities are
known. Some of these constituent parts are outlined below as an alternative to theabove approach.

DETAILED METHODOLOGY FOR OZONE PRECURSORSAND SO2
In the detailed methodology, emissions are calculated separately from sub processes in
the refinery. The total emissions are the sum of the emissions from each individual sub
process. The calculations should be based on plant specific data.
Fluid Catalytic Cracking (SNAP 40102)
Emission factors for a petroleum refinery which uses a fluid catalytic cracking system areshown in Table I-66.

TABLE I-66
NON-COMBUSTION EMISSION FACTORS FOR REFINERIES(FLUID CATALYTIC CRACKING KG/M3 OIL TREATED IN THE FLUID CATALYTIC CRACKER)
EMISSION FACTOREMISSION FACTOR(VALUE)(RANGE)SO2

1.4

0.286-1.505

NOx

0.2

0.107-0.416

CO

39.2

NA

NMVOC

0.6

NA

POLLUTANT

Source: US EPA (1985a, 1995).

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No emission factors are currently available for cracking of coal to fluid products.
Sulphur recovery plants (SNAP 40103)
Sulphur recovery is the conversion of hydrogen sulphide to elemental sulphur. Emission
factors are based on the amount of elemental sulphur produced and are shown in
Table I-67.
TABLE I-67
NON-COMBUSTION EMISSION FACTORS FOR
REFINERIES AND SULPHUR RECOVERY PLANTS.
(KG/TONNE SULPHUR)
POLLUTANTEMISSION FACTOR

SO2

139

Source : US EPA (1993b).

Storage and handling (SNAP 40104)
Emissions of NMVOC result from evaporation from tanks during storage, displacement ofvapour during volume changes, loading and unloading and spillages. Storage may occur at
a refinery or at separate locations. Emissions depend on the type and state of the tanks.
Emission factors are suggested in Table I-68. Where nothing is known the highest factor
should be used. The activity statistic is the crude oil throughput of the refineries.
TABLE I-68
NON-COMBUSTION EMISSION FACTORS FOR REFINERIES(STORAGE AND HANDLING. G/KG OIL THROUGHPUT)
CONDITIONEMISSION FACTOR•

Majority of volatile products are stored in floating roof tanks withsecondary seals

0.2•

Majority of volatile products are stored in floating roof tanks with
only primary seals

0.7•

Majority of volatile products are stored in fixed roof tanks

4.9

Source : EMEP/CORINAIR (1996).

These emissions are intended to account for evaporative losses during storage and thedisplacement losses resulting from the loading and unloading of storage tanks.
Emissions from this source may be higher in countries with a warm climate.

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1.9

Further WorkAt the end of the Experts’ Meeting on GHG Emissions from Fuel Combustion (Abingdon,
29-30 March 1996), experts were asked to identify areas for future work on emissions
from energy. The subsequent list was then prioritised into short/medium-term activities
and longer-term activities.
Short to Medium term (1-3 years):1.

Perform sensitivity analysis to assess importance of emission factors for various
sectors.

2.

Critically assess key emission factors found during sensitivity analysis, and key
calorific values and activity data.

3.

Enhance the EDGAR emission factors that feed into the Tier I methodology withinformation from US country studies and from other sources.

4.

Critically compare IPCC emission factors and methodology with US EPA (1995) and
CORINAIR.

5.

Perform a literature search on emission factors:•••

Mobile sources in developing countries
N2O (all sources)
Biomass (especially fuelwood)6.

Perform more research on emission factors for developing countries, including
emission factors for biomass.

7.

Enhance the section on fugitive emissions: coal mines (CH4), oil & gas industry (CH4
and NMVOC).

8.

Analyse double counting with Industrial Processes section of IPCC Guidelines. Reevaluate the default carbon stored values provided in the Guidelines, including thefate of carbon stored in petroleum products.

9.

Add a category for non-fuel energy related emissions, such as from geothermalenergy, CH4 from flooding to create reservoirs, etc.

10. Evaluate the adequacy of guidelines.
11. Compare the results obtained by using Tier 1 and Tier 2 calculations for the nonCO2 gases.
12. Investigate the possibility of reporting inventories and background information on
the Internet.
Long term:
1.

Develop/update software to support computation and reporting of both the Tier I
and Tier 2 approaches.

2.

Enhance reliability of biomass consumption figures.

3.

Perform statistical analysis of data reported, and validate results with globallymeasured concentrations of all direct greenhouse gases.

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