11. Oil Refinery Sector - gcpc-envisgcpcenvis.nic.in/Experts/Oil Refinery Sector.pdf · OIL...
Transcript of 11. Oil Refinery Sector - gcpc-envisgcpcenvis.nic.in/Experts/Oil Refinery Sector.pdf · OIL...
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CLEANER PRODUCTION
OIL REFINERY SECTOR
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CLEANER PRODUCTION OPPURTUNITIES
IN
OIL REFINERY SECTOR
OPPURTUNITIES
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OIL REFINERY
An oil refinery or petroleum refinery
processed and refined into more useful products such as
naphtha, gasoline, diesel fuel,
gas. Oil refineries are typically large, sprawling
extensive piping running throughout, carrying streams of
processing units.
Common process units found in a refinery:
• Desalter unit washes out salt from the crude oil before it enters the atmospheric
distillation unit.
• Atmospheric distillation unit distills crude oil into fractions.
• Vacuum distillation unit further distills residual bottoms after atmospheric distillation.
• Naphtha hydrotreater unit uses
distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit.
• Catalytic reformer unit is used to conver
higher octane reformate (reformer product). The reformate has higher content of
aromatics and cyclic hydrocarbons). An important byproduct of a r
released during the catalyst reaction. The hydrogen is used either in the hydrotreater or
the hydrocracker.
• Distillate hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric
distillation.
• Fluid catalytic cracker (FCC) unit upgrades heavier fractions into lighter, more valuable
products.
• Hydrocracker unit uses hydrogen to upgrade heavier fractions into lighter, more
valuable products.
• Visbreaking unit upgrades heavy residual oils by thermally cracking them into li
more valuable reduced viscosity products.
• Merox unit treats LPG, kerosene or jet fuel by oxidizing
• Alternative processes for removing mercaptans are known, e.g.
process and caustic washing.
• Coking units (delayed coking
oils into gasoline and diesel fuel, leaving petroleum coke as a residual product.
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OIL REFINERY
petroleum refinery is an industrial process plant where
processed and refined into more useful products such as
asphalt base, heating oil, kerosene and liquefied petroleum
Oil refineries are typically large, sprawling industrial complexes with
running throughout, carrying streams of fluids between large
Common process units found in a refinery:
washes out salt from the crude oil before it enters the atmospheric
Atmospheric distillation unit distills crude oil into fractions.
unit further distills residual bottoms after atmospheric distillation.
unit uses hydrogen to desulfurize naphtha from atmospheric
distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit.
unit is used to convert the naphtha-boiling range molecules into
(reformer product). The reformate has higher content of
aromatics and cyclic hydrocarbons). An important byproduct of a reformer is hydrogen
released during the catalyst reaction. The hydrogen is used either in the hydrotreater or
Distillate hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric
(FCC) unit upgrades heavier fractions into lighter, more valuable
unit uses hydrogen to upgrade heavier fractions into lighter, more
unit upgrades heavy residual oils by thermally cracking them into li
more valuable reduced viscosity products.
unit treats LPG, kerosene or jet fuel by oxidizing mercaptans to organic
Alternative processes for removing mercaptans are known, e.g. doctor sweeten
and caustic washing.
delayed coking, fluid coker, and flexicoker) process very hea
oils into gasoline and diesel fuel, leaving petroleum coke as a residual product.
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where crude oil is
processed and refined into more useful products such as petroleum
liquefied petroleum
complexes with
between large chemical
washes out salt from the crude oil before it enters the atmospheric
unit further distills residual bottoms after atmospheric distillation.
to desulfurize naphtha from atmospheric
distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit.
boiling range molecules into
(reformer product). The reformate has higher content of
eformer is hydrogen
released during the catalyst reaction. The hydrogen is used either in the hydrotreater or
Distillate hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric
(FCC) unit upgrades heavier fractions into lighter, more valuable
unit uses hydrogen to upgrade heavier fractions into lighter, more
unit upgrades heavy residual oils by thermally cracking them into lighter,
to organic disulfides.
doctor sweetening
, fluid coker, and flexicoker) process very heavy residual
oils into gasoline and diesel fuel, leaving petroleum coke as a residual product.
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• Alkylation unit produces high
• Dimerization unit converts olefins
example, butenes can be dimerized into isooctene which may subsequently be
hydrogenated to formisooctane
• Isomerization unit converts linear molecules to higher
blending into gasoline or feed to alkylation units.
• Steam reforming unit produces hydrogen for the hydrotreater or hydrocracker.
• Liquefied gas storage vessels store propane and similar gaseous fuels at pressure
sufficient to maintain them in liquid form. These are usua
"bullets" (i.e., horizontal vessels with rounded ends).
• Storage tanks store crude oil and finished products, usually cylindrical, with some sort of
vapor emission control and surrounded by an earthen
• Amine gas treater, Claus unit
sulfide from hydro desulfurization
• Utility units such as
plants generates steam, and instrument air systems include pneumatically
operated control valves and an
• Wastewater collection and treating systems consist of
flotation (DAF) units and further treatment units such as an
to make water suitable for reuse or for disposal.
• Solvent refining units use solvent such as
aromatics from lubricating oil stock or diesel stock.
• Solvent dewaxing units remove the heavy waxy constituent’s
distillation products.
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unit produces high-octane component for gasoline blending.
olefins into higher-octane gasoline blending components. For
can be dimerized into isooctene which may subsequently be
isooctane. There are also other uses for dimerization
unit converts linear molecules to higher-octane branched molecules for
blending into gasoline or feed to alkylation units.
unit produces hydrogen for the hydrotreater or hydrocracker.
Liquefied gas storage vessels store propane and similar gaseous fuels at pressure
sufficient to maintain them in liquid form. These are usually spherical vessels or
"bullets" (i.e., horizontal vessels with rounded ends).
Storage tanks store crude oil and finished products, usually cylindrical, with some sort of
vapor emission control and surrounded by an earthen berm to contain spills.
Claus unit, and tail gas treatment convert
hydro desulfurization into elemental sulfur.
Utility units such as cooling towers circulate cooling water,
, and instrument air systems include pneumatically
and an electrical substation.
collection and treating systems consist of API separators
and further treatment units such as an activated sludge
to make water suitable for reuse or for disposal.
Solvent refining units use solvent such as cresol or furfural to remove unwanted, mainly
aromatics from lubricating oil stock or diesel stock.
Solvent dewaxing units remove the heavy waxy constituent’s petrolatum
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octane gasoline blending components. For
can be dimerized into isooctene which may subsequently be
. There are also other uses for dimerization.
octane branched molecules for
unit produces hydrogen for the hydrotreater or hydrocracker.
Liquefied gas storage vessels store propane and similar gaseous fuels at pressure
lly spherical vessels or
Storage tanks store crude oil and finished products, usually cylindrical, with some sort of
to contain spills.
reatment convert hydrogen
circulate cooling water, boiler
, and instrument air systems include pneumatically
API separators, dissolved air
activated sludge biotreater
to remove unwanted, mainly
petrolatum from vacuum
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Environmental Issues:
Potential environmental issues associated with petroleum refining include the
following:
• Air emissions
• Wastewater
• Wastes
Air Emissions
Exhaust Gases
Exhaust gas and flue gas emissions (carbon dioxide (CO2), nitrogen oxides
(NOX) and carbon monoxide (CO)) in the petroleum refining sector result
from the combustion of gas and fuel oil or diesel in turbines, boilers,
compressors and other engines for power and heat generation. Flue gas is
also generated in waste heat boilers associated with some process units
during continuous catalyst regeneration or fluid petroleum coke combustion.
Flue gas is emitted from the stack t
Unit, from the catalyst regenerator in the Fluid Catalytic Cracking Unit
(FCCU) and the Residue Catalytic Cracking Unit (RCCU), and in the sulfur
plant, possibly containing small amounts of sulfur oxides. Low
should be used to reduce nitrogen oxide emissions.
Venting and Flaring
Venting and flaring are important operational and safety measures used in
petroleum refining facilities to ensure that vapors gases are safely disposed
of. Petroleum hydrocarbons are emitted from emergency process vents and
safety valves discharges. These
be flared. Excess gas should not be vented, but instead sent to an efficient
flare gas system for disposal. Emergency venting may be acceptable under
specific conditions where flaring of the gas stream is not pos
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Environmental Issues:
Potential environmental issues associated with petroleum refining include the
Exhaust gas and flue gas emissions (carbon dioxide (CO2), nitrogen oxides
(NOX) and carbon monoxide (CO)) in the petroleum refining sector result
from the combustion of gas and fuel oil or diesel in turbines, boilers,
ompressors and other engines for power and heat generation. Flue gas is
also generated in waste heat boilers associated with some process units
during continuous catalyst regeneration or fluid petroleum coke combustion.
Flue gas is emitted from the stack to the atmosphere in the Bitumen Blowing
Unit, from the catalyst regenerator in the Fluid Catalytic Cracking Unit
(FCCU) and the Residue Catalytic Cracking Unit (RCCU), and in the sulfur
plant, possibly containing small amounts of sulfur oxides. Low-
should be used to reduce nitrogen oxide emissions.
Venting and flaring are important operational and safety measures used in
petroleum refining facilities to ensure that vapors gases are safely disposed
of. Petroleum hydrocarbons are emitted from emergency process vents and
safety valves discharges. These are collected into the blow-down network to
be flared. Excess gas should not be vented, but instead sent to an efficient
flare gas system for disposal. Emergency venting may be acceptable under
specific conditions where flaring of the gas stream is not pos
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Potential environmental issues associated with petroleum refining include the
Exhaust gas and flue gas emissions (carbon dioxide (CO2), nitrogen oxides
(NOX) and carbon monoxide (CO)) in the petroleum refining sector result
from the combustion of gas and fuel oil or diesel in turbines, boilers,
ompressors and other engines for power and heat generation. Flue gas is
also generated in waste heat boilers associated with some process units
during continuous catalyst regeneration or fluid petroleum coke combustion.
o the atmosphere in the Bitumen Blowing
Unit, from the catalyst regenerator in the Fluid Catalytic Cracking Unit
(FCCU) and the Residue Catalytic Cracking Unit (RCCU), and in the sulfur
-NOX burners
Venting and flaring are important operational and safety measures used in
petroleum refining facilities to ensure that vapors gases are safely disposed
of. Petroleum hydrocarbons are emitted from emergency process vents and
down network to
be flared. Excess gas should not be vented, but instead sent to an efficient
flare gas system for disposal. Emergency venting may be acceptable under
specific conditions where flaring of the gas stream is not possible, on the
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basis of an accurate risk analysis and integrity of the system needs to be
protected. Justification for not using a gas flaring system should be fully
documented before an emergency gas venting facility is considered. Before
flaring is adopted, feasible alternatives for the use of the gas should be
evaluated and integrated into production design to the maximum extent
possible. Flaring volumes for new facilities should be estimated during the
initial commissioning period so that fixed volume fl
developed. The volumes of gas flared for all flaring events should be
recorded and reported. Continuous improvement of flaring through
implementation of best practices and new technologies should be
demonstrated.
The following pollution prevention and control measures should be
considered for gas flaring:
• Implementation of source gas reduction measures to the maximum
extent possible;
• Use of efficient flare tips, and optimization of the size and number
of burning nozzles;
• Maximizing flare combustion efficiency by controlling and optimizing
flare fuel / air / steam flow rates to ensure the correct ratio of
assist stream to flare stream;
• Minimizing flaring from purges and pilots, without compromising
safety, through measures includi
reduction devices, flare gas recovery units, inert purge gas, soft
seat valve technology where appropriate, and installation of
conservation pilots;
• Minimizing risk of pilot blow
and providing wind guards;
• Use of a reliable pilot ignition system;
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basis of an accurate risk analysis and integrity of the system needs to be
protected. Justification for not using a gas flaring system should be fully
documented before an emergency gas venting facility is considered. Before
d, feasible alternatives for the use of the gas should be
evaluated and integrated into production design to the maximum extent
possible. Flaring volumes for new facilities should be estimated during the
initial commissioning period so that fixed volume flaring targets can be
developed. The volumes of gas flared for all flaring events should be
recorded and reported. Continuous improvement of flaring through
implementation of best practices and new technologies should be
pollution prevention and control measures should be
considered for gas flaring:
Implementation of source gas reduction measures to the maximum
Use of efficient flare tips, and optimization of the size and number
of burning nozzles;
ing flare combustion efficiency by controlling and optimizing
flare fuel / air / steam flow rates to ensure the correct ratio of
assist stream to flare stream;
Minimizing flaring from purges and pilots, without compromising
safety, through measures including installation of purge gas
reduction devices, flare gas recovery units, inert purge gas, soft
seat valve technology where appropriate, and installation of
conservation pilots;
Minimizing risk of pilot blow-out by ensuring sufficient exit velocity
viding wind guards;
Use of a reliable pilot ignition system;
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basis of an accurate risk analysis and integrity of the system needs to be
protected. Justification for not using a gas flaring system should be fully
documented before an emergency gas venting facility is considered. Before
d, feasible alternatives for the use of the gas should be
evaluated and integrated into production design to the maximum extent
possible. Flaring volumes for new facilities should be estimated during the
aring targets can be
developed. The volumes of gas flared for all flaring events should be
recorded and reported. Continuous improvement of flaring through
implementation of best practices and new technologies should be
pollution prevention and control measures should be
Implementation of source gas reduction measures to the maximum
Use of efficient flare tips, and optimization of the size and number
ing flare combustion efficiency by controlling and optimizing
flare fuel / air / steam flow rates to ensure the correct ratio of
Minimizing flaring from purges and pilots, without compromising
ng installation of purge gas
reduction devices, flare gas recovery units, inert purge gas, soft
seat valve technology where appropriate, and installation of
out by ensuring sufficient exit velocity
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• Installation of high integrity instrument pressure protection
systems, where appropriate, to reduce over pressure events and
avoid or reduce flaring situations;
• Installation of knock
where appropriate;
• Minimizing liquid carry
with a suitable liquid separation system;
• Minimizing flame lift off and / or flame lick;
• Operating flare to control odor and visible smok
visible black smoke);
• Locating flare at a safe distance from local communities and the
workforce including workforce accommodation units;
• Implementation of burner maintenance and replacement programs
to ensure continuous maximum flare effic
• Metering flare gas.
To minimize flaring events as a result of equipment breakdowns and plant
upsets, plant reliability should be high (>95 percent), and provision should
be made for equipment sparing and plant turn down protocols.
Fugitive Emissions
Fugitive emissions in petroleum refining facilities are associated with vents,
leaking tubing, valves, connections, flanges, packings, open
floating roof storage tanks and pump seals, gas conveyance systems,
compressor seals, pressure relief
and loading and unloading operations of hydrocarbons. Depending on the
refinery process scheme, fugitive emissions may include:
• Hydrogen;
• Methane;
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Installation of high integrity instrument pressure protection
systems, where appropriate, to reduce over pressure events and
avoid or reduce flaring situations;
Installation of knock-out drums to prevent condensate emissions,
where appropriate;
Minimizing liquid carry-over and entrainment in the gas flare stream
with a suitable liquid separation system;
Minimizing flame lift off and / or flame lick;
Operating flare to control odor and visible smoke emissions (no
visible black smoke);
Locating flare at a safe distance from local communities and the
workforce including workforce accommodation units;
Implementation of burner maintenance and replacement programs
to ensure continuous maximum flare efficiency;
Metering flare gas.
To minimize flaring events as a result of equipment breakdowns and plant
upsets, plant reliability should be high (>95 percent), and provision should
be made for equipment sparing and plant turn down protocols.
Fugitive emissions in petroleum refining facilities are associated with vents,
leaking tubing, valves, connections, flanges, packings, open
floating roof storage tanks and pump seals, gas conveyance systems,
compressor seals, pressure relief valves, tanks or open pits / containments,
and loading and unloading operations of hydrocarbons. Depending on the
refinery process scheme, fugitive emissions may include:
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Installation of high integrity instrument pressure protection
systems, where appropriate, to reduce over pressure events and
prevent condensate emissions,
over and entrainment in the gas flare stream
e emissions (no
Locating flare at a safe distance from local communities and the
Implementation of burner maintenance and replacement programs
To minimize flaring events as a result of equipment breakdowns and plant
upsets, plant reliability should be high (>95 percent), and provision should
Fugitive emissions in petroleum refining facilities are associated with vents,
leaking tubing, valves, connections, flanges, packings, open-ended lines,
floating roof storage tanks and pump seals, gas conveyance systems,
valves, tanks or open pits / containments,
and loading and unloading operations of hydrocarbons. Depending on the
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• Volatile organic compounds (VOCs), (e.g. ethane, ethylene,
propylene, butanes, butylenes, pentanes, pentenes, C6
benzene, toluene, xylenes, phenol, and C9 aromatics);
• Polycyclic aromatic hydrocarbons (PAHs) and other semi volatile
organic compounds;
• Inorganic gases, including hydrofluoric aci
alkylation, hydrogen sulfide, ammonia, carbon dioxide, carbon
monoxide, sulfur dioxide and sulfur trioxide from sulfuric acid
regeneration in the sulfuric acid alkylation process, NOX, methyl tert
butyl ether (MTBE), ethyl tertiary
ether (TAME), methanol, and ethanol.
The main sources of concern include VOC emissions from cone roof storage
tanks during loading and due to out
hydrocarbons through the floating roof seal
fugitive emissions from flanges and/or valves and machinery seals; VOC
emissions from blending tanks, valves, pumps and mixing operations; and
VOC emissions from oily sewage and wastewater treatment systems.
Nitrogen from bitumen storage tanks may also be emitted, possibly
containing hydrocarbons and sulfur compounds in the form of aerosols.
Other potential fugitive emission sources include the Vapor Recovery Unit
vents and gas emission from caustic oxidation.
Recommendations to prevent and control fugitive emissions include
the following:
• Based on review of Process and Instrumentation Diagrams (P&IDs),
identify streams and equipment (e.g. from pipes, valves, seals, tanks
and other infrastructure components) likely to lead t
emissions and prioritize their monitoring with vapor detection
equipment followed by maintenance or replacement of components as
needed;
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Volatile organic compounds (VOCs), (e.g. ethane, ethylene,
propylene, butanes, butylenes, pentanes, pentenes, C6
benzene, toluene, xylenes, phenol, and C9 aromatics);
Polycyclic aromatic hydrocarbons (PAHs) and other semi volatile
organic compounds;
Inorganic gases, including hydrofluoric acid from hydrogen fluoride
alkylation, hydrogen sulfide, ammonia, carbon dioxide, carbon
monoxide, sulfur dioxide and sulfur trioxide from sulfuric acid
regeneration in the sulfuric acid alkylation process, NOX, methyl tert
butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), t
ether (TAME), methanol, and ethanol.
The main sources of concern include VOC emissions from cone roof storage
tanks during loading and due to out-breathing; fugitive emissions of
hydrocarbons through the floating roof seals of floating roof storage tanks;
fugitive emissions from flanges and/or valves and machinery seals; VOC
emissions from blending tanks, valves, pumps and mixing operations; and
VOC emissions from oily sewage and wastewater treatment systems.
bitumen storage tanks may also be emitted, possibly
containing hydrocarbons and sulfur compounds in the form of aerosols.
Other potential fugitive emission sources include the Vapor Recovery Unit
vents and gas emission from caustic oxidation.
ns to prevent and control fugitive emissions include
Based on review of Process and Instrumentation Diagrams (P&IDs),
identify streams and equipment (e.g. from pipes, valves, seals, tanks
and other infrastructure components) likely to lead to fugitive VOC
emissions and prioritize their monitoring with vapor detection
equipment followed by maintenance or replacement of components as
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Volatile organic compounds (VOCs), (e.g. ethane, ethylene, propane,
propylene, butanes, butylenes, pentanes, pentenes, C6-C9 alkylate,
Polycyclic aromatic hydrocarbons (PAHs) and other semi volatile
d from hydrogen fluoride
alkylation, hydrogen sulfide, ammonia, carbon dioxide, carbon
monoxide, sulfur dioxide and sulfur trioxide from sulfuric acid
regeneration in the sulfuric acid alkylation process, NOX, methyl tert-
butyl ether (ETBE), t-amylmethyl
The main sources of concern include VOC emissions from cone roof storage
breathing; fugitive emissions of
s of floating roof storage tanks;
fugitive emissions from flanges and/or valves and machinery seals; VOC
emissions from blending tanks, valves, pumps and mixing operations; and
VOC emissions from oily sewage and wastewater treatment systems.
bitumen storage tanks may also be emitted, possibly
containing hydrocarbons and sulfur compounds in the form of aerosols.
Other potential fugitive emission sources include the Vapor Recovery Unit
ns to prevent and control fugitive emissions include
Based on review of Process and Instrumentation Diagrams (P&IDs),
identify streams and equipment (e.g. from pipes, valves, seals, tanks
o fugitive VOC
emissions and prioritize their monitoring with vapor detection
equipment followed by maintenance or replacement of components as
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• The selection of appropriate valves, flanges, fittings, seals, and
packings should be based on their cap
fugitive emissions;
• Hydrocarbon vapors should be either contained or routed back to the
process system, where the pressure level allows;
• Use of vent gas scrubbers should be considered to remove oil and
other oxidation products
bitumen production);
• Incineration of gas should be conducted at high temperature
(approximately 800 °C) to ensure complete destruction of minor
components (e.g. H2S, aldehydes, organic acids and phenolic
components) and minimize emissions and odor impacts;
• Emissions from hydrofluoric acid (HF) alkylation plant vents should
collected and neutralized for HF removal in a scrubber before being
sent to flare;
• Naphtha, gasoline, methanol / ethanol, and MTBE / ETBE /
loading / unloading stations should be provided with vapor recovery
units.
Sulfur Oxides
Sulfur oxides (SOx) and hydrogen sulfide may be emitted from boilers,
heaters, and other process equipment, based on the sulfur content of the
processed crude oil. Sulfur dioxide and sulfur trioxide may be emitted from
sulfuric acid regeneration in the sulfuric acid alkylation process. Sulfur
dioxide in refinery waste gases may have pre
levels of 1500 -7500 milligrams per cubic meter (mg/m
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The selection of appropriate valves, flanges, fittings, seals, and
packings should be based on their capacity to reduce gas leaks and
Hydrocarbon vapors should be either contained or routed back to the
process system, where the pressure level allows;
Use of vent gas scrubbers should be considered to remove oil and
other oxidation products from overhead vapors in specific units (e.g.
bitumen production);
Incineration of gas should be conducted at high temperature
(approximately 800 °C) to ensure complete destruction of minor
components (e.g. H2S, aldehydes, organic acids and phenolic
nents) and minimize emissions and odor impacts;
Emissions from hydrofluoric acid (HF) alkylation plant vents should
collected and neutralized for HF removal in a scrubber before being
Naphtha, gasoline, methanol / ethanol, and MTBE / ETBE /
loading / unloading stations should be provided with vapor recovery
Sulfur oxides (SOx) and hydrogen sulfide may be emitted from boilers,
heaters, and other process equipment, based on the sulfur content of the
l. Sulfur dioxide and sulfur trioxide may be emitted from
sulfuric acid regeneration in the sulfuric acid alkylation process. Sulfur
dioxide in refinery waste gases may have pre-abatement concentration
7500 milligrams per cubic meter (mg/m3)2.
9 | P a g e
The selection of appropriate valves, flanges, fittings, seals, and
acity to reduce gas leaks and
Hydrocarbon vapors should be either contained or routed back to the
Use of vent gas scrubbers should be considered to remove oil and
from overhead vapors in specific units (e.g.
Incineration of gas should be conducted at high temperature
(approximately 800 °C) to ensure complete destruction of minor
components (e.g. H2S, aldehydes, organic acids and phenolic
Emissions from hydrofluoric acid (HF) alkylation plant vents should
collected and neutralized for HF removal in a scrubber before being
Naphtha, gasoline, methanol / ethanol, and MTBE / ETBE / TAME
loading / unloading stations should be provided with vapor recovery
Sulfur oxides (SOx) and hydrogen sulfide may be emitted from boilers,
heaters, and other process equipment, based on the sulfur content of the
l. Sulfur dioxide and sulfur trioxide may be emitted from
sulfuric acid regeneration in the sulfuric acid alkylation process. Sulfur
abatement concentration
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Recommended pollution prevention and minimization measures
include the following:
• Minimize SOX emissions through desulfurization of fuels, to the extent
feasible, or by directing the use of high
with SOX emission controls;
• Recover sulfur from tail gases using high efficiency sulfur recovery
units (e.g. Claus units)
• Install mist precipitators (e.g. electrostatic precipitators or brink
demisters ) to remove sulfuric acid mist;
• Install scrubbers with caustic soda sol
alkylation unit absorption towers.
Particulate Matter
Particulate emissions from refinery units are associated with flue gas from
furnaces; catalyst fines emitted from fluidized catalytic the handling of coke;
and fines and ash generated during incineration of sludges. Particulates may
contain metals (e.g. vanadium, nickels). Measures to control particulate may
also contribute to control of metal emissions from petroleum refining.
Recommended pollution prevention and mini
include the following:
1. Install cyclones, electrostatic precipitators, bag filters, and/or wet
scrubbers to reduce emissions of particulates from point sources. A
combination of these techniques may achieve >99 percent abatement of
particulate matter;
2. Implement particulate emission reduction techniques during coke
handling, including:
• Store coke in bulk under enclosed shelters
• Keep coke constantly wet
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Recommended pollution prevention and minimization measures
Minimize SOX emissions through desulfurization of fuels, to the extent
feasible, or by directing the use of high-sulfur fuels to units equipped
controls;
Recover sulfur from tail gases using high efficiency sulfur recovery
units (e.g. Claus units)3
Install mist precipitators (e.g. electrostatic precipitators or brink
demisters ) to remove sulfuric acid mist;
Install scrubbers with caustic soda solution to treat flue gases from the
alkylation unit absorption towers.
Particulate emissions from refinery units are associated with flue gas from
furnaces; catalyst fines emitted from fluidized catalytic the handling of coke;
and ash generated during incineration of sludges. Particulates may
contain metals (e.g. vanadium, nickels). Measures to control particulate may
also contribute to control of metal emissions from petroleum refining.
Recommended pollution prevention and minimization measures
Install cyclones, electrostatic precipitators, bag filters, and/or wet
scrubbers to reduce emissions of particulates from point sources. A
combination of these techniques may achieve >99 percent abatement of
Implement particulate emission reduction techniques during coke
Store coke in bulk under enclosed shelters
Keep coke constantly wet
10 | P a g e
Recommended pollution prevention and minimization measures
Minimize SOX emissions through desulfurization of fuels, to the extent
sulfur fuels to units equipped
Recover sulfur from tail gases using high efficiency sulfur recovery
Install mist precipitators (e.g. electrostatic precipitators or brink
ution to treat flue gases from the
Particulate emissions from refinery units are associated with flue gas from
furnaces; catalyst fines emitted from fluidized catalytic the handling of coke;
and ash generated during incineration of sludges. Particulates may
contain metals (e.g. vanadium, nickels). Measures to control particulate may
also contribute to control of metal emissions from petroleum refining.
mization measures
Install cyclones, electrostatic precipitators, bag filters, and/or wet
scrubbers to reduce emissions of particulates from point sources. A
combination of these techniques may achieve >99 percent abatement of
Implement particulate emission reduction techniques during coke
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• Cut coke in a crusher and convey it to an intermediate storage silo
(hydrobins)
• Spray the coke with a fine layer of oil, to stick the dust fines to the
coke
• Use covered and conveyor belts with extraction systems to maintain
negative pressure
• Use aspiration systems to extract and collect coke dust
• Pneumatically convey the fines collected from th
fitted with exit air filters, and recycle the collected fines to storage.
Greenhouse Gases (GHGs)
Carbon dioxide (CO2) may be produced in significant amounts during
petroleum refining from combustion processes (e.g. electric power
production), flares, and hydrogen plants. Carbon dioxide and other gases
(e.g. nitrogen oxides and carbon cracking regeneration units and other
catalyst based processes; monoxide) may be discharged to atmosphere
during in-situ catalyst regeneration of noble
maximize energy efficiency and design facilities (e.g. opportunities for
efficiency improvements in utilities, fired heaters, process optimization, heat
exchangers, motor and motor applications) to minimize energy use. The
overall objective should be to reduce air emissions and evaluate cost
effective options for reducing emissions that are technically feasible.
Wastewater
Industrial Process Wastewater
The largest volume effluents in petroleum refining include “sour” process
water and non-oily/non-sour but highly alkaline process water. Sour water is
generated from desalting, topping, vacuum distillation, pretreating, light and
middle distillate hydrodes
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Cut coke in a crusher and convey it to an intermediate storage silo
coke with a fine layer of oil, to stick the dust fines to the
Use covered and conveyor belts with extraction systems to maintain
Use aspiration systems to extract and collect coke dust
Pneumatically convey the fines collected from the cyclones into a silo
fitted with exit air filters, and recycle the collected fines to storage.
Greenhouse Gases (GHGs)
Carbon dioxide (CO2) may be produced in significant amounts during
petroleum refining from combustion processes (e.g. electric power
roduction), flares, and hydrogen plants. Carbon dioxide and other gases
(e.g. nitrogen oxides and carbon cracking regeneration units and other
catalyst based processes; monoxide) may be discharged to atmosphere
situ catalyst regeneration of noble metals. Operators should aim to
maximize energy efficiency and design facilities (e.g. opportunities for
efficiency improvements in utilities, fired heaters, process optimization, heat
exchangers, motor and motor applications) to minimize energy use. The
overall objective should be to reduce air emissions and evaluate cost
effective options for reducing emissions that are technically feasible.
Industrial Process Wastewater
The largest volume effluents in petroleum refining include “sour” process
sour but highly alkaline process water. Sour water is
generated from desalting, topping, vacuum distillation, pretreating, light and
middle distillate hydrodesulphurization, hydrocracking, catalytic cracking,
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Cut coke in a crusher and convey it to an intermediate storage silo
coke with a fine layer of oil, to stick the dust fines to the
Use covered and conveyor belts with extraction systems to maintain
e cyclones into a silo
fitted with exit air filters, and recycle the collected fines to storage.
Carbon dioxide (CO2) may be produced in significant amounts during
petroleum refining from combustion processes (e.g. electric power
roduction), flares, and hydrogen plants. Carbon dioxide and other gases
(e.g. nitrogen oxides and carbon cracking regeneration units and other
catalyst based processes; monoxide) may be discharged to atmosphere
metals. Operators should aim to
maximize energy efficiency and design facilities (e.g. opportunities for
efficiency improvements in utilities, fired heaters, process optimization, heat
exchangers, motor and motor applications) to minimize energy use. The
overall objective should be to reduce air emissions and evaluate cost-
effective options for reducing emissions that are technically feasible.
The largest volume effluents in petroleum refining include “sour” process
sour but highly alkaline process water. Sour water is
generated from desalting, topping, vacuum distillation, pretreating, light and
ulphurization, hydrocracking, catalytic cracking,
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coking, Visbreaking / thermal cracking. Sour water may be contaminated
with hydrocarbons, hydrogen sulfide, ammonia, organic sulfur compounds,
organic acids, and phenol. Process water is treated in the sour
unit (SWS) to remove hydrocarbons, hydrogen sulfide, ammonia and other
compounds, before recycling for internal process uses, or final treatment and
disposal through an onsite wastewater treatment unit. Non
but highly alkaline process water has the potential to cause Waste Water
Treatment Plant upsets. Boiler blowdown and demineralization plant reject
streams in particular, if incorrectly neutralized, have the potential to extract
phenolics from the oil phase into the water p
emulsions in the WWTP
Wastes
Hazardous Wastes: Spent Catalysts
Spent catalysts result from several process units in petroleum refining
including the pretreating and catalytic reformer; light and middle distillate
hydrodesulphurization; the hydrocracker; fluid catalytic cracking (FCCU);
residue catalytic cracking (RCCU); MTBE/ETBE and TAME production;
butanes isomerization; the dienes hydrogenation and butylenes
hydroisomerization unit; sulfuric acid regeneration; selective catalytic
hydrodesulphurization; and the sulfur and hydrogen plants. Spent catalysts
may contain molybdenum, nickel, cobalt, platinum, palladium, vanadium
iron, copper and silica and/or alumina, as carriers.
Recommended management strategies for catalysts include th
following:
• Use long life catalysts and regeneration to extend the catalyst life
cycle;
• Use appropriate on
submerging pyrophoric spent catalysts in water during temporary
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coking, Visbreaking / thermal cracking. Sour water may be contaminated
with hydrocarbons, hydrogen sulfide, ammonia, organic sulfur compounds,
organic acids, and phenol. Process water is treated in the sour water stripper
unit (SWS) to remove hydrocarbons, hydrogen sulfide, ammonia and other
compounds, before recycling for internal process uses, or final treatment and
disposal through an onsite wastewater treatment unit. Non-oily / non
ne process water has the potential to cause Waste Water
Treatment Plant upsets. Boiler blowdown and demineralization plant reject
streams in particular, if incorrectly neutralized, have the potential to extract
phenolics from the oil phase into the water phase, as well as cause
Hazardous Wastes: Spent Catalysts
Spent catalysts result from several process units in petroleum refining
including the pretreating and catalytic reformer; light and middle distillate
on; the hydrocracker; fluid catalytic cracking (FCCU);
residue catalytic cracking (RCCU); MTBE/ETBE and TAME production;
butanes isomerization; the dienes hydrogenation and butylenes
hydroisomerization unit; sulfuric acid regeneration; selective catalytic
hydrodesulphurization; and the sulfur and hydrogen plants. Spent catalysts
may contain molybdenum, nickel, cobalt, platinum, palladium, vanadium
iron, copper and silica and/or alumina, as carriers.
Recommended management strategies for catalysts include th
Use long life catalysts and regeneration to extend the catalyst life
Use appropriate on-site storage and handling methods, (e.g.,
submerging pyrophoric spent catalysts in water during temporary
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coking, Visbreaking / thermal cracking. Sour water may be contaminated
with hydrocarbons, hydrogen sulfide, ammonia, organic sulfur compounds,
water stripper
unit (SWS) to remove hydrocarbons, hydrogen sulfide, ammonia and other
compounds, before recycling for internal process uses, or final treatment and
oily / non-sour
ne process water has the potential to cause Waste Water
Treatment Plant upsets. Boiler blowdown and demineralization plant reject
streams in particular, if incorrectly neutralized, have the potential to extract
hase, as well as cause
Spent catalysts result from several process units in petroleum refining
including the pretreating and catalytic reformer; light and middle distillate
on; the hydrocracker; fluid catalytic cracking (FCCU);
residue catalytic cracking (RCCU); MTBE/ETBE and TAME production;
butanes isomerization; the dienes hydrogenation and butylenes
hydroisomerization unit; sulfuric acid regeneration; selective catalytic
hydrodesulphurization; and the sulfur and hydrogen plants. Spent catalysts
may contain molybdenum, nickel, cobalt, platinum, palladium, vanadium
Recommended management strategies for catalysts include the
Use long life catalysts and regeneration to extend the catalyst life
site storage and handling methods, (e.g.,
submerging pyrophoric spent catalysts in water during temporary
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storage and transport until they can reach
treatment to avoid uncontrolled exothermic reactions);
• Return spent catalysts to the manufacturer for regeneration or
recovery, or transport to other off
handling, heavy or precious metals recovery / recycl
disposal
Other Hazardous Wastes
In addition to spent catalysts, industry hazardous waste may include
solvents, filters, mineral spirits, used sweetening, spent amines for CO2,
hydrogen sulfide (H2S) and carbonyl sulfide (COS) removal, activated
carbon filters and oily sludge from oil / water separators, tank bottoms, and
spent or used operational and maintenance fluids (e.g. oils and test liquids).
Other hazardous wastes, including contaminated sludges, sludge from jet
water pump circuit purificat
alumina from hydrofluoric (HF) alkylation, may be generated from crude oil
storage tanks, desalting and topping, coking, propane, propylene, butanes
streams dryers, and butanes isomerization .
Recommended industry
hazardous waste include the following:
• Send oily sludges from crude oil storage tanks and the desalter to
the delayed coking drum, where applicable, to recover the
hydrocarbons;
• Ensure excessive cracking is not condu
to prevent production of an unstable fuel oil, resulting in increased
sludge and sediment formation during storage;
• Maximize recovery of oil from oily wastewaters and sludges.
Minimize losses of oil to the effluent system. Oil
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storage and transport until they can reach the final point of
treatment to avoid uncontrolled exothermic reactions);
Return spent catalysts to the manufacturer for regeneration or
recovery, or transport to other off-site management companies for
handling, heavy or precious metals recovery / recycl
Other Hazardous Wastes
In addition to spent catalysts, industry hazardous waste may include
solvents, filters, mineral spirits, used sweetening, spent amines for CO2,
hydrogen sulfide (H2S) and carbonyl sulfide (COS) removal, activated
arbon filters and oily sludge from oil / water separators, tank bottoms, and
spent or used operational and maintenance fluids (e.g. oils and test liquids).
Other hazardous wastes, including contaminated sludges, sludge from jet
water pump circuit purification, exhausted molecular sieves, and exhausted
alumina from hydrofluoric (HF) alkylation, may be generated from crude oil
storage tanks, desalting and topping, coking, propane, propylene, butanes
streams dryers, and butanes isomerization .
stry-specific management strategies for
hazardous waste include the following:
Send oily sludges from crude oil storage tanks and the desalter to
the delayed coking drum, where applicable, to recover the
Ensure excessive cracking is not conducted in the Visbreaking unit
to prevent production of an unstable fuel oil, resulting in increased
sludge and sediment formation during storage;
Maximize recovery of oil from oily wastewaters and sludges.
Minimize losses of oil to the effluent system. Oil can be recovered
13 | P a g e
the final point of
treatment to avoid uncontrolled exothermic reactions);
Return spent catalysts to the manufacturer for regeneration or
site management companies for
handling, heavy or precious metals recovery / recycling, and
In addition to spent catalysts, industry hazardous waste may include
solvents, filters, mineral spirits, used sweetening, spent amines for CO2,
hydrogen sulfide (H2S) and carbonyl sulfide (COS) removal, activated
arbon filters and oily sludge from oil / water separators, tank bottoms, and
spent or used operational and maintenance fluids (e.g. oils and test liquids).
Other hazardous wastes, including contaminated sludges, sludge from jet
ion, exhausted molecular sieves, and exhausted
alumina from hydrofluoric (HF) alkylation, may be generated from crude oil
storage tanks, desalting and topping, coking, propane, propylene, butanes
specific management strategies for
Send oily sludges from crude oil storage tanks and the desalter to
the delayed coking drum, where applicable, to recover the
cted in the Visbreaking unit
to prevent production of an unstable fuel oil, resulting in increased
Maximize recovery of oil from oily wastewaters and sludges.
can be recovered
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from slops using separation techniques (e.g. gravity separators and
centrifuges);
• Sludge treatment may include land application (bioremediation), or
solvent extraction followed by combustion of the residue and / or
use in asphalt, where fe
require stabilization prior to disposal to reduce the leachability of
toxic metals.
Non-hazardous Wastes
Hydrofluoric acid alkylation produces neutralization sludges which may
contain calcium fluoride, calcium
fluoride, magnesium hydroxide and magnesium carbonate. After drying and
compression, they may be marketed for steel mills use or landfilled.
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from slops using separation techniques (e.g. gravity separators and
Sludge treatment may include land application (bioremediation), or
solvent extraction followed by combustion of the residue and / or
use in asphalt, where feasible. In some cases, the residue may
require stabilization prior to disposal to reduce the leachability of
Hydrofluoric acid alkylation produces neutralization sludges which may
contain calcium fluoride, calcium hydroxide, calcium carbonate, magnesium
fluoride, magnesium hydroxide and magnesium carbonate. After drying and
compression, they may be marketed for steel mills use or landfilled.
14 | P a g e
from slops using separation techniques (e.g. gravity separators and
Sludge treatment may include land application (bioremediation), or
solvent extraction followed by combustion of the residue and / or
asible. In some cases, the residue may
require stabilization prior to disposal to reduce the leachability of
Hydrofluoric acid alkylation produces neutralization sludges which may
hydroxide, calcium carbonate, magnesium
fluoride, magnesium hydroxide and magnesium carbonate. After drying and
compression, they may be marketed for steel mills use or landfilled.