IPEN DRAFT
7 f Petroleum Refining
The petroleum refining industry converts crude oil into refined products, including liquefied
petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oils, lubricating oils, bitumen, and
feedstock for the petrochemical industry. There are 655 worldwide refineries, located in 116 countries
that collectively have a daily capacity of about 88 million barrels per day (b/d).i The composition of
petroleum (crude oil) can vary significantly depending on its source.
Petroleum refining processes that have been identified as PCDD/PCDF sources include the following: ii, iii

Stationary combustion sources, such as boilers and process heaters, generate heat and power by
burning crude oil or fuel oil.

Ca (No data)Coking units use heat to thermally crack heavy hydrocarbon streams to form lighter,
more useful distillates such as heating oils or gasoline. Traditional fluid coking units are one of the
largest vent emissions sources at a refinery, being comparable to emissions from the CCU
regenerator.

Catalytic reforming units are a series of catalytic reactors that turn naphtha into high-octane
gasoline. The catalyst accumulates carbon (coke) so that it must be regenerated. In the continuous
process, aged catalyst is continuously moved from the reactor to the regenerator where the carbon
is burned from the catalyst with hot air/steam. Chlorine or organochlorines , such as tri- or
perchloroethylene, are added to retain catalytic activity. While the catalytic reactors have no direct
process vents, the catalyst regenerators do have such vents.

(No data)Flares are compulsory safety equipment used both for safety reasons during upsets,startup, shut down, and system blow-down and for managing the disposal of waste gases from routine
operations.
PCDD/PCDF may be released to air from vent stacks and flares, captured in scrubbing systems and
released to water in treated effluents, and released in residues such as exhausted catalysts and
wastewater treatment sludge.
Emission Factors
Releases of PCDD and PCDF from petroleum refineries may occur from two broad groups of
processes – those that generate heat and power on-site and those that produce petroleum products.
The classes addressed in each group are listed below:
On-Site Power/heat generation and flares

Boilers and process heaters fueled with crude oil/pipeline oil;

Boilers and process heaters that burn fuel oil (No. 6 oil); and

Flares.
Production of petroleum products

(No data)Catalytic reforming unit (including catalyst regenerator)

(No data)Coking unit

Refinery-wide wastewater treatment

Flares
PCDD/PCDF emission factors are listed in Tables X and Y. Detailed information on the derivation of these
emission factors can be found in Annex 49.1
Table X: PCDD/PCDF emission factors for petroleum refining boilers, process heaters and flares
7f
Petroleum Industry
EFAIR
µg TEQ/ TJ of fuel
burned
Classification
Boilers and process heaters firing crude
oil/pipeline
67.6 iv
Boilers and process heaters firing fuel oil (No.
6 oil)
Flares
2.7 v,vi
0.025 vii
Table Y: PCDD/PCDF emission factors for petroleum refining processes
7f Petroleum Industry
Catalytic cracking unit
(including catalyst
regenerator)
Catalytic reforming unit
(including catalyst
regenerator)
Isomerization units
(butane and naphtha)
Coking unit
Refinery-wide
wastewater treatment
1
EF AIR
g TEQ/t oil
Emission Factors
EF WATER
EF LAND
pg TEQ/L
EF PRODUCT
ND
NA
NA
NA
0.0168 viii,ix
NA
NA
NA
ND
NA
NA
NA
0.413 x
ND
NA
5 xi, xii
NA
ND
NA
ND
Hyperlink to Annex 49 containing derivation of EFs for source category.
EF RESIDUE
g TEQ/t
residue
13.61
ND
Annex 49 Complementary information to source category 7f Petroleum
Industry
Oil refineries are large scale plants, processing about a hundred thousand to several hundred
thousand barrels of crude oil a day. Because of the high capacity, many of the units operate
continuously, as opposed to processing in batches, at steady state or nearly steady state for months to
years. There are three broad categories of refining processes:
1. Separation: The oil is separated into its constituents by distillation, and some of these
components (such as the refinery gas) are further separated with chemical reactions and by
using solvents that dissolve one component of a mixture significantly better than another.
2. Conversion: The various hydrocarbons produced are then chemically altered to make them
more suitable for their intended purpose. Prior to conversion, sulfur must be removed from the
hydrocarbons because these reactions often require catalysts that are deactivated by sulfur.
3. Purification: The hydrogen sulfide gas that was extracted from the refinery gas is converted to
sulfur, which is sold in liquid form to fertiliser manufacturers.
Detailed descriptions of refinery processes can be found in the European Commission’s Integrated
Pollution Prevention and Control (IPPC) Reference Document on Best Available Techniques for Mineral
Oil and Gas Refineries.xiii
Release to Air
An EFAIR of 67.6 µg TEQ/ TJ has been reported for refinery boilers and process heaters fired with
crude oil and/or pipeline oil and an EFAIR of 4.2 µg TEQ/ TJ for those fired with fuel oil (No. 6 oil) (RTI,
2011). xiv For those fired with fuel oil, the European association of oil producers reported a somewhat
lower EFAIR of 1.24 µg TEQ/ TJ but gave no value for those fired with crude oil and/or pipeline oil
(CONCAWE, 2009). xv
For catalytic cracking units, the only PCDD/PCDF-related value found was that of < 0.016 ng
TEQ/Nm³ that was measured in two European catalytic cracking units after carbon monoxide
combustion.xvi
For catalytic reforming units, off-gas was reported to have a PCDD/PCDF concentration of 131 ng ITEQ/Nm3 [215, Jansson, 1999]).xvii The California Air Resources Board (1999) determined an EFAIR 3.04
ng TEQ/barrel for the catalytic reforming unit at one U.S. refinery.xviii Both CONCAWE (2009) and
U.S. EPA (2006) derived an EFAIR 1.52 ng TEQ/barrel for these units.xix,xx It is important to note that
U.S. EPA (2004) reports that some refineries vent off-gases from these units directly to the air.xxi
For refinery coking units, RTI (2011) derived an EFAIR of 56.2 ng TEQ/barrel (353.5 ng/m3 oil). xxii
For flares at Danish refineries, Henricksen et al. (2006) derived an EFAIR of 0.25 g TEQ/TJ of fuel.xxiii
EFAIR of 67.7 µg TEQ/ TJ for refinery boilers and process heaters that fire crude oil and/or pipeline oil, as
derived by RTI (2011).xxiv
EFAIR of 2.7 µg TEQ/ TJ for refinery boilers and process heaters that fire fuel oil (No. 6 oil), based on the
mean of the values derived by RTI (2011) and CONCAWE (2009).
EFAIR of 2.28 ng TEQ/barrel (0.0143 g TEQ/m 3 oil; 0.0168 g TEQ/t oil)2 for catalytic reforming unit
catalyst regenerators, based on the mid-point of the values presented by CARB (1999), CONCAWE
(2009) and U.S. EPA (2005).
EFAIR of 56.2 TEQ/barrel (0.353 g TEQ/m3 oil; 0.413 g TEQ/t oil) for refinery coking units, based on the
value derived by RTI (2011).
EFAIR of 0.25 g TEQ/TJ of fuel for flares at oil refineries, based on value presented by Henricksen et al.
(2006).
Release to Water
Data obtained from four U.S. refineries found PCDD/PCDF concentrations ranging from 0 to
394,000 pg TEQ/L, with a median of 2,975 pg TEQ/L in wastewater from their catalytic reforming units
(USEPA, 2004).xxv The data also include PCDD/PCDF concentrations ranging from 0 to 37.9 pg TEQ/L, with
a mean of 3.5 pg TEQ/L, in the final effluent of nine refineries. At one refinery, stormwater run-off was
identified as the source of 50 percent of PCDD/PCDF in the final effluent with coke pond and clean canal
forebay as the source of 45 percent. Karras (1998) reported a PCDD/PCDF concentration of 7.86 pg
TEQ/L in the wastewater effluent of a U.S. refinery. xxvi
EFWATER of 5 pg TEQ/L, based on the value presented by Karras (1998) and the mean of the values
reported by U.S. EPA (2004).
Release in Residues
Data describing PCDD/PCDF concentrations in the final wastewater treatment sludge of
refineries were not available. However, PCDD/PCDF concentrations ranging from 3 to 356 ng TEQ/kg,
with a median of 13.61 ng TEQ/kg were measured in sludge generated by oil and solids removal (API)
separators at catalytic reforming units (USEPA, 2004).xxvii
Refinery boilers and process heaters may produce fly ash and bottom ash as residues, but there is no
information on their PCDD/PCDF content, generation rates and fate. Spent catalyst generated is around
20-25 tons per year for a 5-million-tons-per-year refinery. Spent catalyst is typically regenerated and
catalyst fines from that process are likely to be captured by abatement systems. With dry abatement
systems, the catalyst fines become a discrete residue; if wet, the fines accumulate in wastewater
treatment sludge.
EF RESIDUE of 13.61 ng TEQ/kg for sludge from API separator of catalytic reforming unit, based on value
determined by U.S. EPA (2004).
TOOLKIT 2005
2
1 barrel of oil = 0.159 m3 of oil ; 1 barrel of oil = 0.136 tonnes of oil.
6.7.3
Petroleum Industry
Crude oil is a mixture of many different hydrocarbons and small amounts of impurities. The
composition of crude oil can vary significantly depending on its source. Petroleum refineries are a
complex system of multiple operations and the operations used at a given refinery depend upon
the properties of the crude oil to be refined and the desired products.
Within the petroleum refining industry, only one potential source for PCDD/PCDF has been reported
until now: re-generation of the catalyst used during catalytic cracking of the larger hydrocarbon
molecules into smaller, lighter molecules (Beard et al. 1993).
Feedstock to catalytic reforming processes is usually low octane naphtha. Catalytic hydro-reforming
uses platinum-based catalysts. In the continuous process, aged catalyst is continuously removed
from the bottom of the reactor and sent to a regenerator where the carbon is burned from the
catalyst with hot air/steam. Trace quantities of a promoter, normally organochlorines, such as tri- or
perchloroethylene, are added to retain catalytic activity. Moisture is removed and the regenerated
catalyst is returned to the first reformer bed. In the cyclic or semi-regenerative units, the
regeneration of the catalyst is discontinuous as well as the resulting emissions. In this process,
PCDD/PCDF have been detected.
PCDD/PCDF may be emitted to air or captured in scrubbing systems and transferred to effluents.
Ultimate releases will depend on the pollution controls and handling of residues. No emission
factors can be given at this time due to lack of data. For this subcategory measured data are
urgently needed.
Presently, the only PCDD/PCDF generated from the flaring of the gases released from the petroleum
industry can be quantified. The same emission factor as listed in Chapter 6.3.3 - Landfill/Biogas
Combustion will be used. The emission factor to air in Table 65 is given per TJ and per cubic meter.
Table 65:
Emission factors for flaring of gases
Emission Factor - g TEQ/TJ
of Gas Burned
Air
8
Classification
µ
Flares
6.7.3.1
Emission Factor - g TEQ/m3
of Gas Burned
Air
0.0003
µ
Release to Air
Presently, only emissions to air can be estimated by applying the same emission factor as for
burning and flaring of landfill and biogas. The emissions from the reactivation of the catalyst cannot
yet be quantified.
6.7.3.2
Release to Water
The amount of wastewater generated in the catalytic reforming process is around 190 kg/t of
feedstock. The wastewater contains high levels of oil, suspended solids. Emissions of
PCDD/PCDF to water may occur upon discharge of the wastewater. However, no data are available
at present. Any discharge of wastewater should be noted.
6.7.3.3
Releases in Residues
Spent catalyst fines may be generated from the fine particle abatement systems. Spent catalyst
generated is around 20-25 tons per year for a 5-million-tons-per-year refinery. Typically, spent
catalyst is sent back for recycling or regeneration.
From the wastewater treatment, sludge can be generated. There are no PCDD/PCDF concentrations
available at present; however, concentrations of pyrene and benzo[a]pyrene in the low mg/kg range
have been detected (BREF 2000b).
i
Petroleum Online. Overview. http://www.petroleumonline.com/content/overview.asp?mod=8
RTI International, 2011. Emission Estimation Protocol for Petroleum Refineries. Version 2.1.1
Final ICR Version – Corrected. Submitted to: Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711.
https://refineryicr.rti.org/Portals/0/Emission_Estimation_Protocol_for_Petroleum_Refineries.pdf
iii
Jacobs Consultancy, 2002. Water Pollution Prevention Opportunities in Petroleum Refineries. Ecology Publication
No.02-07-017. Prepared For The Washington State Department of Ecology.
http://www.ecy.wa.gov/biblio/0207017.html
iv
RTI, 2011
v
RTI, 2011
vi
CONCAWE, 2009. Air pollutant emission estimation methods for E-PRTR reporting by refineries. report no. 1/09.
http://www.concawe.org/DocShareNoFrame/docs/1/EDOPDOPBINDNJFDIPKBJJOEGVEVCBG9Y9YBD73BDCGA3/CE
net/docs/DLS/Rpt_09-1-2009-00893-01-E.pdf
vii
Henriksen, T.C., Illerup, J.B. & Nielsen, O.-K. 2006: Dioxin Air Emission Inventory 1990-2004. National
Environmental Research Institute, Denmark. 90 pp. – NERI Technical report no 602. Available at:
http://www.dmu.dk/Pub/FR602.pdf (12-09-2009).
viii
CARB, 1999 CARB. (1999) Determination of emissions from the No. 3 reformer as Tosco Refining Company San
Francisco Area Refinery at Avon. Project No. C-96-0396. Engineering and Laboratory Branch, Monitoring and
Laboratory Division.
ix
U.S. Environmental Protection Agency, 2006. The inventory of sources and environmental releases of dioxin-like
compounds in the United States: the year 2000 update. Draft report EPA/600/p-03/002A. Research Triangle Park
NC: US Environmental Protection Agency (http://www.epa.gov/ncea/pdfs/dioxin/2k-update/)
Also used by CONCAWE, 2009.
ii
x
RTI, 2011.
Karras, G. 1998. On the Hook for Zero Dioxin; Report No. 98-2; Communities for a Better Environment: San
Francisco, CA, 1998
xii
U.S. EPA, 2004. Technical support document for the 2004 effluent guidelines program plan. United States.
Environmental Protection Agency. Office of Water, United States. Environmental Protection Agency. Office of
Science and Technology. Engineering and Analysis Division, Washington, DC.
xiii
European Commission, 2003. Integrated Pollution Prevention and Control (IPPC) Reference Document on Best
Available Techniques for Mineral Oil and Gas Refineries. February 2003
xiv
RTI International, 2011. Emission Estimation Protocol for Petroleum Refineries. Version 2.1.1
Final ICR Version – Corrected. Submitted to: Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711.
xv
CONCAWE, 2009. Air pollutant emission estimation methods for E-PRTR reporting by refineries. report no. 1/09.
http://www.concawe.org/DocShareNoFrame/docs/1/EDOPDOPBINDNJFDIPKBJJOEGVEVCBG9Y9YBD73BDCGA3/CE
net/docs/DLS/Rpt_09-1-2009-00893-01-E.pdf
xvi
European Commission, 2003. Integrated Pollution Prevention and Control (IPPC) Reference Document on Best
Available Techniques for Mineral Oil and Gas Refineries. February 2003
xvii
Jansson, B., 1999. Preem and Scanraff refineries in Sweden. Technical information. Swedish Environmental
Protection Agency. In European Commission, 2003. Integrated Pollution Prevention and Control (IPPC) Reference
Document on Best Available Techniques for Mineral Oil and Gas Refineries. February 2003.
xviii
CARB, 1999 CARB. (1999) Determination of emissions from the No. 3 reformer as Tosco Refining Company San
Francisco Area Refinery at Avon. Project No. C-96-0396. Engineering and Laboratory Branch, Monitoring and
Laboratory Division.
xix
U.S. Environmental Protection Agency, 2006. An Inventory of Sources and Environmental Releases of Dioxin-Like
Compounds in the United States for the Years 1987, 1995, and 2000. EPA/600/P-03/002F. November 2006.
Washington, D.C.
xx
U.S. Environmental Protection Agency, 2006.
xxi
U.S. EPA, 2004. Technical support document for the 2004 effluent guidelines program plan. United States.
Environmental Protection Agency. Office of Water, United States. Environmental Protection Agency. Office of
Science and Technology. Engineering and Analysis Division, Washington, DC.
xxii
RTI, 2011.
xxiii
Henriksen, T.C., Illerup, J.B. & Nielsen, O.-K. 2006: Dioxin Air Emission Inventory 1990-2004. National
Environmental Research Institute, Denmark. 90 pp. – NERI Technical report no 602. Available at:
http://www.dmu.dk/Pub/FR602.pdf (12-09-2009).
xxiv
RTI, 2011.
xxv
U.S. EPA, 2004. Technical support document for the 2004 effluent guidelines program plan. United States.
Environmental Protection Agency. Office of Water, United States. Environmental Protection Agency. Office of
Science and Technology. Engineering and Analysis Division, Washington, DC.
xxvi
Karras, G. 1998. On the Hook for Zero Dioxin; Report No. 98-2; Communities for a Better Environment: San
Francisco, CA, 1998
xxvii
U.S. EPA, 2004. Technical support document for the 2004 effluent guidelines program plan. United States.
Environmental Protection Agency. Office of Water, United States. Environmental Protection Agency. Office of
Science and Technology. Engineering and Analysis Division, Washington, DC.
xi