Activity

Subactivities or processes included in activity

Alkylation

All alkylation processes: hydrofluoric acid (HF), sulphuric acid (H2SO4) and solid-acid

Base oil production

Deasphalting, aromatic extraction, wax processing and lubricant oil hydrofinishing

Bitumen production

All techniques from storage to final product additives

Catalytic cracking

All types of catalytic cracking units such as fluid catalytic cracking

Catalytic reforming

Continuous, cyclic and semi-regenerative catalytic reforming

Coking

Delayed and fluid coking processes. Coke calcination

Cooling

Cooling techniques applied in refineries

Desalting

Desalting of crude oil

Combustion units for energy production

Combustion units burning refinery fuels, excluding units using only conventional or commercial fuels

Etherification

Production of chemicals (e.g. alcohols and ethers such as MTBE, ETBE and TAME) used as motor fuels additives

Gas separation

Separation of light fractions of the crude oil e.g. refinery fuel gas (RFG), liquefied petroleum gas (LPG)

Hydrogen consuming processes

Hydrocracking, hydrorefining, hydrotreatments, hydroconversion, hydroprocessing and hydrogenation processes

Hydrogen production

Partial oxidation, steam reforming, gas heated reforming and hydrogen purification

Isomerisation

Isomerisation of hydrocarbon compounds C4, C5 and C6

Natural gas plants

Natural gas (NG) processing including liquefaction of NG

Polymerisation

Polymerisation, dimerisation and condensation

Primary distillation

Atmospheric and vacuum distillation

Product treatments

Sweetening and final product treatments

Storage and handling of refinery materials

Storage, blending, loading and unloading of refinery materials

Visbreaking and other thermal conversions

Thermal treatments such as visbreaking or thermal gas oil process

Waste gas treatment

Techniques to reduce or abate emissions to air

Waste water treatment

Techniques to treat waste water prior to release

Waste management

Techniques to prevent or reduce the generation of waste

Reference document

Subject

Common Waste Water and Waste Gas Treatment/Management Systems in the Chemical Sector (CWW)

Waste water management and treatment techniques

Industrial Cooling Systems (ICS)

Cooling processes

Economics and Cross-media Effects (ECM)

Economics and cross-media effects of techniques

Emissions from Storage (EFS)

Storage, blending, loading and unloading of refinery materials

Energy Efficiency (ENE)

Energy efficiency and integrated refinery management

Large Combustion Plants (LCP)

Combustion of conventional and commercial fuels

Large Volume Inorganic Chemicals — Ammonia, Acids and Fertilisers Industries (LVIC-AAF)

Steam reforming and hydrogen purification

Large Volume Organic Chemical Industry (LVOC)

Etherification process (MTBE, ETBE and TAME production)

Waste Incineration (WI)

Waste incineration

Waste Treatment (WT)

Waste treatment

General Principles of Monitoring (MON)

Monitoring of emissions to air and water

For continuous measurements

BAT-AELs refer to monthly average values, which are the averages of all valid hourly average values measured over a period of one month

For periodic measurements

BAT-AELs refer to the average value of three spot samples of at least 30 minutes each

Activities

Unit

Oxygen reference conditions

Combustion unit using liquid or gaseous fuels with the exception of gas turbines and engines

mg/Nm3

3 % oxygen by volume

Combustion unit using solid fuels

mg/Nm3

6 % oxygen by volume

Gas turbines (including combined cycle gas turbines — CCGT) and engines

mg/Nm3

15 % oxygen by volume

Catalytic cracking process (regenerator)

mg/Nm3

3 % oxygen by volume

Waste gas sulphur recovery unit (1)

mg/Nm3

3 % oxygen by volume

Daily average

Average over a sampling period of 24 hours taken as a flow-proportional composite sample or, provided that sufficient flow stability is demonstrated, from a time-proportional sample

Yearly/Monthly average

Average of all daily averages obtained within a year/month, weighted according to the daily flows

Term used

Definition

Unit

A segment/subpart of the installation in which a specific processing operation is conducted

New unit

A unit first permitted on the site of the installation following the publication of these BAT conclusions or a complete replacement of a unit on the existing foundations of the installation following the publication of these BAT conclusions

Existing unit

A unit which is not a new unit

Process off-gas

The collected gas generated by a process which must be treated e.g. in an acid gas removal unit and a sulphur recovery unit (SRU)

Flue-gas

The exhaust gas exiting a unit after an oxidation step, generally combustion (e.g. regenerator, Claus unit)

Tail gas

Common name of the exhaust gas from an SRU (generally Claus process)

VOC

Volatile organic compounds as defined in Article 3(45) of Directive 2010/75/EU

NMVOC

VOC excluding methane

Diffuse VOC emissions

Non-channelled VOC emissions that are not released via specific emission points such as stacks. They can result from ‘area’ sources (e.g. tanks) or ‘point’ sources (e.g. pipe flanges)

NOX expressed as NO2

The sum of nitrogen oxide (NO) and nitrogen dioxide (NO2) expressed as NO2

SOX expressed as SO2

The sum of sulphur dioxide (SO2) and sulphur trioxide (SO3) expressed as SO2

H2S

Hydrogen sulphide. Carbonyl sulphide and mercaptan are not included

Hydrogen chloride expressed as HCl

All gaseous chlorides expressed as HCl

Hydrogen fluoride expressed as HF

All gaseous fluorides expressed as HF

FCC unit

Fluid catalytic cracking: a conversion process for upgrading heavy hydrocarbons, using heat and a catalyst to break larger hydrocarbon molecules into lighter molecules

SRU

Sulphur recovery unit. See definition in Section 1.20.3

Refinery fuel

Solid, liquid or gaseous combustible material from the distillation and conversion steps of the refining of crude oil.

Examples are refinery fuel gas (RFG), syngas and refinery oils, pet coke

RFG

Refinery fuel gas: off-gases from distillation or conversion units used as a fuel

Combustion unit

Unit burning refinery fuels alone or with other fuels for the production of energy at the refinery site, such as boilers (except CO boilers), furnaces, and gas turbines.

Continuous measurement

Measurement using an ‘automated measuring system’ (AMS) or a ‘continuous emission monitoring system’ (CEMS) permanently installed on site

Periodic measurement

Determination of a measurand at specified time intervals using manual or automated reference methods

Indirect monitoring of emissions to air

Estimation of the emissions concentration in the flue-gas of a pollutant obtained through an appropriate combination of measurements of surrogate parameters (such as O2 content, sulphur or nitrogen content in the feed/fuel), calculations and periodic stack measurements. The use of emission ratios based on S content in the fuel is one example of indirect monitoring. Another example of indirect monitoring is the use of PEMS

Predictive Emissions monitoring system (PEMS)

System to determine the emissions concentration of a pollutant based on its relationship with a number of characteristic continuously monitored process parameters (e.g. fuel-gas consumption, air/fuel ratio) and fuel or feed quality data (e.g. the sulphur content) of an emission source

Volatile liquid hydrocarbon compounds

Petroleum derivatives with a Reid vapour pressure (RVP) of more than 4 kPa, such as naphtha and aromatics

Recovery rate

Percentage of NMVOC recovered from the streams conveyed into a vapour recovery unit (VRU)

Technique

Description

(i)  Design techniques

a.  Pinch analysis

Methodology based on a systematic calculation of thermodynamic targets for minimising energy consumption of processes. Used as a tool for the evaluation of total systems designs

b.  Heat integration

Heat integration of process systems ensures that a substantial proportion of the heat required in various processes is provided by exchanging heat between streams to be heated and streams to be cooled

c.  Heat and power recovery

Use of energy recovery devices e.g.:

(ii)  Process control and maintenance techniques

a.  Process optimisation

Automated controlled combustion in order to lower the fuel consumption per tonne of feed processed, often combined with heat integration for improving furnace efficiency

b.  Management and reduction of steam consumption

Systematic mapping of drain valve systems in order to reduce steam consumption and optimise its use

c.  Use of energy benchmark

Participation in ranking and benchmarking activities in order to achieve continuous improvement by learning from best practice

(iii)  Energy-efficient production techniques

a.  Use of combined heat and power

System designed for the co-production (or the cogeneration) of heat (e.g. steam) and electric power from the same fuel

b.  Integrated gasification combined cycle (IGCC)

Technique whose purpose is to produce steam, hydrogen (optional) and electric power from a variety of fuel types (e.g. heavy fuel oil or coke) with a high conversion efficiency

Description

Unit

Minimum frequency

Monitoring technique

(i)  SOX, NOX, and dust emissions

Catalytic cracking

Continuous (1) (2)

Direct measurement

Combustion units

≥ 100 MW (3)

and calcining units

Continuous (1) (2)

Direct measurement (4)

Combustion units

of 50 to 100 MW (3)

Continuous (1) (2)

Direct measurement or indirect monitoring

Combustion units

< 50 MW (3)

Once a year and after significant fuel changes (5)

Direct measurement or indirect monitoring

Sulphur recovery units (SRU)

Continuous for SO2 only

Direct measurement or indirect monitoring (6)

(ii)  NH3 emissions

All units equipped with SCR or SNCR

Continuous

Direct measurement

(iii)  CO emissions

Catalytic cracking and combustion units

≥ 100 MW (3)

Continuous

Direct measurement

Other combustion units

Once every 6 months (5)

Direct measurement

(iv)  Metals emissions: Nickel (Ni), Antimony (Sb) (7), Vanadium (V)

Catalytic cracking

Once every 6 months and after significant changes to the unit (5)

Direct measurement or analysis based on metals content in the catalyst fines and in the fuel

Combustion units (8)

(v)  Polychlorinated dibenzodioxins/furans (PCDD/F) emissions

Catalytic reformer

Once a year or once a regeneration, whichever is longer

Direct measurement

Description

Minimum frequency

Monitoring of parameters linked to pollutant emissions, e.g. O2 content in flue-gas, N and S content in fuel or feed (1)

Continuous for O2 content.

For N and S content, periodic at a frequency based on significant fuel/feed changes

Parameter

BAT-AEL

z(monthly average)

mg/Nm3

Ammonia expressed as NH3

< 5 – 15 (1) (2)

Technique

Description

Applicability

(i)  Water stream integration

Reduction of process water produced at the unit level prior to discharge by the internal reuse of water streams from e.g. cooling, condensates, especially for use in crude desalting

Generally applicable for new units. For existing units, applicability may require a complete rebuilding of the unit or the installation

(ii)  Water and drainage system for segregation of contaminated water streams

Design of an industrial site to optimise water management, where each stream is treated as appropriate, by e.g. routing generated sour water (from distillation, cracking, coking units, etc.) to appropriate pretreatment, such as a stripping unit

Generally applicable for new units. For existing units, applicability may require a complete rebuilding of the unit or the installation

(iii)  Segregation of non-contaminated water streams (e.g. once-through cooling, rain water)

Design of a site in order to avoid sending non-contaminated water to general waste water treatment and to have a separate release after possible reuse for this type of stream

Generally applicable for new units.

For existing units, applicability may require a complete rebuilding of the unit or the installation

(iv)  Prevention of spillages and leaks

Practices that include the utilisation of special procedures and/or temporary equipment to maintain performances when necessary to manage special circumstances such as spills, loss of containment, etc.

Generally applicable

Technique

Description

Applicability

(i)  Removal of insoluble substances by recovering oil

See Section 1.21.2

Generally applicable

(ii)  Removal of insoluble substances by recovering suspended solids and dispersed oil

See Section 1.21.2

Generally applicable

(iii)  Removal of soluble substances including biological treatment and clarification

See Section 1.21.2

Generally applicable

Parameter

Unit

BAT-AEL

(yearly average)

Monitoring (2) frequency and analytical method (standard)

Hydrocarbon oil index (HOI)

mg/l

0,1-2,5

Daily

EN 9377- 2 (3)

Total suspended solids (TSS)

mg/l

5-25

Daily

Chemical oxygen demand (COD) (4)

mg/l

30-125

Daily

BOD5

mg/l

No BAT-AEL

Weekly

Total nitrogen (5), expressed as N

mg/l

1-25 (6)

Daily

Lead, expressed as Pb

mg/l

0,005-0,030

Quarterly

Cadmium, expressed as Cd

mg/l

0,002-0,008

Quarterly

Nickel, expressed as Ni

mg/l

0,005-0,100

Quarterly

Mercury, expressed as Hg

mg/l

0,0001-0,001

Quarterly

Vanadium

mg/l

No BAT-AEL

Quarterly

Phenol Index

mg/l

No BAT-AEL

Monthly

EN 14402

Benzene, toluene, ethyl benzene, xylene (BTEX)

mg/l

Benzene: 0,001-0,050

No BAT-AEL for T, E, X

Monthly

Technique

Description

Applicability

(i)  Sludge pretreatment

Prior to final treatment (e.g. in a fluidised bed incinerator), the sludges are dewatered and/or de-oiled (by e.g. centrifugal decanters or steam dryers) to reduce their volume and to recover oil from slop equipment

Generally applicable

(ii)  Reuse of sludge in process units

Certain types of sludge (e.g. oily sludge) can be processed in units (e.g. coking) as part of the feed due to their oil content

Applicability is restricted to sludges that can fulfil the requirements to be processed in units with appropriate treatment

Technique

Description

(i)  Spent solid catalyst management

Scheduled and safe handling of the materials used as catalyst (e.g. by contractors) in order to recover or reuse them in off-site facilities. These operations depend on the type of catalyst and process

(ii)  Removal of catalyst from slurry decant oil

Decanted oil sludge from process units (e.g. FCC unit) can contain significant concentrations of catalyst fines. These fines need to be separated prior to the reuse of decant oil as a feedstock

Technique

Description

Applicability

I.  Techniques related to plant design

(i)  limiting the number of potential emission sources

(ii)  maximising inherent process containment features

(iii)  selecting high integrity equipment

(iv)  facilitating monitoring and maintenance activities by ensuring access to potentially leaking components

Applicability may be limited for existing units

II.  Techniques related to plant installation and commissioning

(i)  well-defined procedures for construction and assembly

(ii)  robust commissioning and hand-over procedures to ensure that the plant is installed in line with the design requirements

Applicability may be limited for existing units

III.  Techniques related to plant operation

Use of a risk-based leak detection and repair (LDAR) programme in order to identify leaking components, and to repair these leaks.

See Section 1.20.6

Generally applicable

Technique

Description

Applicability

(i)  Precipitation/Neutralisation step

Precipitation (with, e.g. calcium or aluminium-based additives) or neutralisation (where the effluent is indirectly neutralised with potassium hydroxide (KOH))

Generally applicable.

Safety requirements due to the hazardous nature of hydrofluoric acid (HF) are to be considered

(ii)  Separation step

The insoluble compounds produced at the first step (e.g. CaF2 or AlF3) are separated in e.g. a settlement basin

Generally applicable

Technique

Description

Applicability

(i)  Closed process with a solvent recovery

Process where the solvent, after being used during base oil manufacturing (e.g. in extraction, dewaxing units), is recovered through distillation and stripping steps.

See Section 1.20.7

Generally applicable

(ii)  Multi-effect extraction solvent-based process

Solvent extraction process including several stages of evaporation (e.g. double or triple effect) for a lower loss of containment

Generally applicable to new units.

The use of a triple effect process may be restricted to non-fouling feed stocks

(iii)  Extraction unit processes using less hazardous substances

Design (new plants) or implement changes (into existing) so that the plant operates a solvent extraction process with the use of a less hazardous solvent: e.g. converting furfural or phenol extraction into the n-methylpyrrolidone (NMP) process

Generally applicable to new units.

Converting existing units to another solvent-based process with different physico-chemical properties may require substantial modifications

(iv)  Catalytic processes based on hydrogenation

Processes based on conversion of undesired compounds via catalytic hydrogenation similar to hydrotreatment.

See Section 1.20.3 (Hydrotreatment)

Generally applicable to new units

Technique

Description

Applicability

(i)  Thermal oxidation of gaseous overhead over 800 °C

See Section 1.20.6

Generally applicable for the bitumen blowing unit

(ii)  Wet scrubbing of gaseous overhead

See Section 1.20.3

Generally applicable for the bitumen blowing unit

Technique

Description

Applicability

Process optimisation and use of promoters or additives

(i)  Process optimisation

Combination of operating conditions or practices aimed at reducing NOX formation, e.g. lowering the excess oxygen in the flue-gas in full combustion mode, air staging of the CO boiler in partial combustion mode, provided that the CO boiler is appropriately designed

Generally applicable

(ii)  Low-NOX CO oxidation promoters

Use of a substance that selectively promotes the combustion of CO only and prevents the oxidation of the nitrogen that contains intermediates to NOX: e.g. non-platinum promoters

Applicable only in full combustion mode for the substitution of platinum-based CO promoters.

Appropriate distribution of air in the regenerator may be required to obtain the maximum benefit

(iii)  Specific additives for NOX reduction

Use of specific catalytic additives for enhancing the reduction of NO by CO

Applicable only in full combustion mode in an appropriate design and with achievable oxygen excess. The applicability of copper-based NOX reduction additives may be limited by the gas compressor capacity

Technique

Description

Applicability

(i)  Selective catalytic reduction (SCR)

See Section 1.20.2

To avoid potential fouling downstream, additional filtering might be required upstream of the SCR.

For existing units, the applicability may be limited by space availability

(ii)  Selective non-catalytic reduction (SNCR)

See Section 1.20.2

For partial combustion FCCs with CO boilers, a sufficient residence time at the appropriate temperature is required.

For full combustion FCCs without auxiliary boilers, additional fuel injection (e.g. hydrogen) may be required to match a lower temperature window

(iii)  Low temperature oxidation

See Section 1.20.2

Need for additional scrubbing capacity.

Ozone generation and the associated risk management need to be properly addressed. The applicability may be limited by the need for additional waste water treatment and related cross-media effects (e.g. nitrate emissions) and by an insufficient supply of liquid oxygen (for ozone generation).

The applicability of the technique may be limited by space availability

Parameter

Type of unit/combustion mode

BAT-AEL

(monthly average)

mg/Nm3

NOX, expressed as NO2

New unit/all combustion mode

< 30-100

Existing unit/full combustion mode

< 100-300 (1)

Existing unit/partial combustion mode

100-400 (1)

Technique

Description

Applicability

(i)  Use of an attrition-resistant catalyst

Selection of catalyst substance that is able to resist abrasion and fragmentation in order to reduce dust emissions

Generally applicable provided the activity and selectivity of the catalyst are sufficient

(ii)  Use of low sulphur feedstock (e.g. by feedstock selection or by hydrotreatment of feed)

Feedstock selection favours low sulphur feedstocks among the possible sources to be processed at the unit.

Hydrotreatment aims at reducing the sulphur, nitrogen and metal contents of the feed.

See Section 1.20.3

Requires sufficient availability of low sulphur feedstocks, hydrogen production and hydrogen sulphide (H2S) treatment capacity (e.g. amine and Claus units)

Technique

Description

Applicability

(i)  Electrostatic precipitator (ESP)

See Section 1.20.1

For existing units, the applicability may be limited by space availability

(ii)  Multistage cyclone separators

See Section 1.20.1

Generally applicable

(iii)  Third stage blowback filter

See Section 1.20.1

Applicability may be restricted

(iv)  Wet scrubbing

See Section 1.20.3

The applicability may be limited in arid areas and in the case where the by-products from treatment (including e.g. waste water with high level of salts) cannot be reused or appropriately disposed of.

For existing units, the applicability may be limited by space availability

Parameter

Type of unit

BAT-AEL (monthly average) (1)

mg/Nm3

Dust

New unit

10-25

Existing unit

10-50 (2)

Technique

Description

Applicability

(i)  Use of SOX reducing catalyst additives

Use of a substance that transfers the sulphur associated with coke from the regenerator back to the reactor.

See description in 1.20.3

Applicability may be restricted by regenerator conditions design.

Requires appropriate hydrogen sulphide abatement capacity (e.g. SRU)

(ii)  Use of low sulphur feedstock (e.g. by feedstock selection or by hydrotreatment of the feed)

Feedstock selection favours low sulphur feedstocks among the possible sources to be processed at the unit.

Hydrotreatment aims at reducing the sulphur, nitrogen and metal contents of the feed.

See description in 1.20.3

Requires sufficient availability of low sulphur feedstocks, hydrogen production and hydrogen sulphide (H2S) treatment capacity (e.g. amine and Claus units)

Techniques

Description

Applicability

(i)  Non-regenerative scrubbing

Wet scrubbing or seawater scrubbing.

See Section 1.20.3

The applicability may be limited in arid areas and in the case where the by-products from treatment (including e.g. waste water with high level of salts) cannot be reused or appropriately disposed of.

For existing units, the applicability may be limited by space availability

(ii)  Regenerative scrubbing

Use of a specific SOX absorbing reagent (e.g. absorbing solution) which generally enables the recovery of sulphur as a by-product during a regenerating cycle where the reagent is reused.

See Section 1.20.3

The applicability is limited to the case where regenerated by-products can be sold.

For existing units, the applicability may be limited by the existing sulphur recovery capacity as well as by space availability

Parameter

Type of units/mode

BAT-AEL

(monthly average)

mg/Nm3

SO2

New units

≤ 300

Existing units/full combustion

< 100-800 (1)

Existing units/partial combustion

100-1 200  (1)

Technique

Description

Applicability

(i)  Combustion operation control

See Section 1.20.5

Generally applicable

(ii)  Catalysts with carbon monoxide (CO) oxidation promoters

See Section 1.20.5

Generally applicable only for full combustion mode

(iii)  Carbon monoxide (CO) boiler

See Section 1.20.5

Generally applicable only for partial combustion mode

Parameter

Combustion mode

BAT-AEL

(monthly average)

mg/Nm3

Carbon monoxide, expressed as CO

Partial combustion mode

≤ 100 (1)

Technique

Description

Applicability

(i)  Choice of the catalyst promoter

Use of catalyst promoter in order to minimise polychlorinated dibenzodioxins/furans (PCDD/F) formation during regeneration.

See Section 1.20.7

Generally applicable

(ii)  Treatment of the regeneration flue-gas

a.  Regeneration gas recycling loop with adsorption bed

Waste gas from the regeneration step is treated to remove chlorinated compounds (e.g. dioxins)

Generally applicable to new units.

For existing units the applicability may depend on the current regeneration unit design

b.  Wet scrubbing

See Section 1.20.3

Not applicable to semi-regenerative reformers

c.  Electrostatic precipitator (ESP)

See Section 1.20.1

Not applicable to semi-regenerative reformers

Technique

Description

Applicability

(i)  Collection and recycling of coke fines

Systematic collection and recycling of coke fines generated during the whole coking process (drilling, handling, crushing, cooling, etc.)

Generally applicable

(ii)  Handling and storage of coke according to BAT 3

See BAT 3

Generally applicable

(iii)  Use of a closed blowdown system

Arrestment system for pressure relief from the coke drums

Generally applicable

(iv)  Recovery of gas (including the venting prior to the drum being opened to atmosphere) as a component of refinery fuel gas (RFG)

Carrying venting from the coke drum to the gas compressor to recover as RFG, rather than flaring.

For the flexicoking process, a conversion step (to convert the carbonyl sulphide (COS) into H2S) is needed prior to treating the gas from the coking unit

For existing units, the applicability of the techniques may be limited by space availability

Technique

Description

Applicability

(i)  Non-regenerative scrubbing

Wet scrubbing or seawater scrubbing.

See Section 1.20.3

The applicability may be limited in arid areas and in the case where the by-products from treatment (including e.g. waste water with high level of salts) cannot be reused or appropriately disposed of.

For existing units, the applicability may be limited by space availability

(ii)  Regenerative scrubbing

Use of a specific SOX absorbing reagent (e.g. absorbing solution) which generally enables the recovery of sulphur as a by-product during a regenerating cycle where the reagent is reused.

See Section 1.20.3

The applicability is limited to the case where regenerated by-products can be sold.

For existing units, the applicability may be limited by the existing sulphur recovery capacity as well as by space availability

Technique

Description

Applicability

(i)  Electrostatic precipitator (ESP)

See Section 1.20.1

For existing units, the applicability may be limited by space availability.

For graphite and anode coke calcining production, the applicability may be restricted due to the high resistivity of the coke particles

(ii)  Multistage cyclone separators

See Section 1.20.1

Generally applicable

Parameter

BAT-AEL

(monthly average)

mg/Nm3

Dust

10-50 (1) (2)

Technique

Description

Applicability

(i)  Recycling water and optimisation of the desalting process

An ensemble of good desalting practices aiming at increasing the efficiency of the desalter and reducing wash water usage e.g. using low shear mixing devices, low water pressure. It includes the management of key parameters for washing (e.g. good mixing) and separation (e.g. pH, density, viscosity, electric field potential for coalescence) steps

Generally applicable

(ii)  Multistage desalter

Multistage desalters operate with water addition and dehydration, repeated through two stages or more for achieving a better efficiency in the separation and therefore less corrosion in further processes

Applicable for new units

(iii)  Additional separation step

An additional enhanced oil/water and solid/water separation designed for reducing the charge of oil to the waste water treatment plant and recycling it to the process. This includes, e.g. settling drum, the use of optimum interface level controllers

Generally applicable

Technique

Description

Applicability

(i)  Selection or treatment of fuel

(a)  Use of gas to replace liquid fuel

Gas generally contains less nitrogen than liquid and its combustion leads to a lower level of NOX emissions.

See Section 1.20.3

The applicability may be limited by the constraints associated with the availability of low sulphur gas fuels, which may be impacted by the energy policy of the Member State

(b)  Use of low nitrogen refinery fuel oil (RFO) e.g. by RFO selection or by hydrotreatment of RFO

Refinery fuel oil selection favours low nitrogen liquid fuels among the possible sources to be used at the unit.

Hydrotreatment aims at reducing the sulphur, nitrogen and metal contents of the fuel.

See Section 1.20.3

Applicability is limited by the availability of low nitrogen liquid fuels, hydrogen production and hydrogen sulphide (H2S) treatment capacity (e.g. amine and Claus units)

(ii)  Combustion modifications

(a)  Staged combustion:

See Section 1.20.2

Fuel staging for mixed or liquid firing may require a specific burner design

(b)  Optimisation of combustion

See Section 1.20.2

Generally applicable

(c)  Flue-gas recirculation

See Section 1.20.2

Applicable through the use of specific burners with internal recirculation of the flue-gas.

The applicability may be restricted to retrofitting external flue-gas recirculation to units with a forced/induced draught mode of operation

(d)  Diluent injection

See Section 1.20.2

Generally applicable for gas turbines where appropriate inert diluents are available

(e)  Use of low-NOX burners (LNB)

See Section 1.20.2

Generally applicable for new units taking into account, the fuel-specific limitation (e.g. for heavy oil).

For existing units, applicability may be restricted by the complexity caused by site-specific conditions e.g. furnaces design, surrounding devices.

In very specific cases, substantial modifications may be required.

The applicability may be restricted for furnaces in the delayed coking process, due to possible coke generation in the furnaces.

In gas turbines, the applicability is restricted to low hydrogen content fuels (generally < 10 %)

Technique

Description

Applicability

(i)  Selective catalytic reduction (SCR)

See Section 1.20.2

Generally applicable for new units.

For existing units, the applicability may be constrained due to the requirements for significant space and optimal reactant injection

(ii)  Selective non-catalytic reduction (SNCR)

See Section 1.20.2

Generally applicable for new units.

For existing units, the applicability may be constrained by the requirement for the temperature window and the residence time to be reached by reactant injection

(iii)  Low temperature oxidation

See Section 1.20.2

The applicability may be limited by the need for additional scrubbing capacity and by the fact that ozone generation and the associated risk management need to be properly addressed.

The applicability may be limited by the need for additional waste water treatment and related cross-media effects (e.g. nitrate emissions) and by an insufficient supply of liquid oxygen (for ozone generation).

For existing units, the applicability of the technique may be limited by space availability

(iv)  SNOX combined technique

See Section 1.20.4

Applicable only for high flue-gas (e.g. > 800 000 Nm3/h) flow and when combined NOX and SOX abatement is needed

Parameter

Type of equipment

BAT-AEL (1)

(monthly average)

mg/Nm3 at 15 % O2

NOX expressed as NO2

Gas turbine (including combined cycle gas turbine — CCGT) and integrated gasification combined cycle turbine (IGCC))

40-120

(existing turbine)

20-50

(new turbine) (2)

Parameter

Type of combustion

BAT-AEL

(monthly average)

mg/Nm3

NOX expressed as NO2

Gas firing

30-150

for existing unit (1)

30-100

for new unit

Parameter

Type of combustion

BAT-AEL

(monthly average)

mg/Nm3

NOX expressed as NO2

Multi-fuel fired combustion unit

30-300

for existing unit (1) (2)

Technique

Description

Applicability

(i)  Selection or treatment of fuel

(a)  Use of gas to replace liquid fuel

Gas instead of liquid combustion leads to lower level of dust emissions

See Section 1.20.3

The applicability may be limited by the constraints associated with the availability of low sulphur fuels such as natural gas, which may be impacted by the energy policy of the Member State

(b)  Use of low sulphur refinery fuel oil (RFO) e.g. by RFO selection or by hydrotreatment of RFO

Refinery fuel oil selection favours low sulphur liquid fuels among the possible sources to be used at the unit.

Hydrotreatment aims at reducing the sulphur, nitrogen and metal contents of the fuel.

See Section 1.20.3

The applicability may be limited by the availability of low sulphur liquid fuels, hydrogen production and the hydrogen sulphide (H2S) treatment capacity (e.g. amine and Claus units)

(ii)  Combustion modifications

(a)  Optimisation of combustion

See Section 1.20.2

Generally applicable to all types of combustion

(b)  Atomisation of liquid fuel

Use of high pressure to reduce the droplet size of liquid fuel.

Recent optimal burner designs generally include steam atomisation

Generally applicable to liquid fuel firing

Technique

Description

Applicability

(i)  Electrostatic precipitator (ESP)

See Section 1.20.1

For existing units, the applicability may be limited by space availability

(ii)  Third stage blowback filter

See Section 1.20.1

Generally applicable

(iii)  Wet scrubbing

See Section 1.20.3

The applicability may be limited in arid areas and in the case where the by-products from treatment (including e.g. waste water with a high level of salt) cannot be reused or appropriately disposed of. For existing units, the applicability of the technique may be limited by space availability

(iv)  Centrifugal washers

See Section 1.20.1

Generally applicable

Parameter

Type of combustion

BAT-AEL

(monthly average)

mg/Nm3

Dust

Multi-fuel firing

5-50

for existing unit (1) (2)

5-25

for new unit < 50 MW

Technique

Description

Applicability

(i)  Use of gas to replace liquid fuel

See Section 1.20.3

The applicability may be limited by the constraints associated with the availability of low sulphur fuels such as natural gas, which may be impacted by the energy policy of the Member State

(ii)  Treatment of refinery fuel gas (RFG)

Residual H2S concentration in RFG depends on the treatment process parameter, e.g. the amine-scrubbing pressure.

See Section 1.20.3

For low calorific gas containing carbonyl sulphide (COS) e.g. from coking units, a converter may be required prior to H2S removal

(iii)  Use of low sulphur refinery fuel oil (RFO) e.g. by RFO selection or by hydrotreatment of RFO

Refinery fuel oil selection favours low sulphur liquid fuels among the possible sources to be used at the unit.

Hydrotreatment aims at reducing the sulphur, nitrogen and metal contents of the fuel.

See Section 1.20.3

The applicability is limited by the availability of low sulphur liquid fuels, hydrogen production and the hydrogen sulphide (H2S) treatment capacity (e.g. amine and Claus units)

Technique

Description

Applicability

(i)  Non-regenerative scrubbing

Wet scrubbing or seawater scrubbing.

See Section 1.20.3

The applicability may be limited in arid areas and in the case where the by-products from treatment (including e.g. waste water with high level of salts) cannot be reused or appropriately disposed of.

For existing units, the applicability of the technique may be limited by space availability

(ii)  Regenerative scrubbing

Use of a specific SOX absorbing reagent (e.g. absorbing solution) which generally enables the recovery of sulphur as a by-product during a regenerating cycle where the reagent is reused.

See Section 1.20.3

The applicability is limited to the case where regenerated by-products can be sold.

Retrofitting to existing units may be limited by the existing sulphur recovery capacity.

For existing units, the applicability of the technique may be limited by space availability

(iii)  SNOX combined technique

See Section 1.20.4

Applicable only for high flue-gas (e.g. > 800 000 Nm3/h) flow and when combined NOX and SOX abatement is required

Parameter

BAT-AEL

(monthly average)

mg/Nm3

SO2

5-35 (1)

Parameter

BAT-AEL

(monthly average)

mg/Nm3

SO2

35-600

Parameter

BAT-AEL

(monthly average)

mg/Nm3

Carbon monoxide, expressed as CO

≤ 100

Technique

Description

Applicability

(i)  Manual crude oil tank cleaning

Oil tank cleaning is performed by workers entering the tank and removing sludge manually

Generally applicable

(ii)  Use of a closed-loop system

For internal inspections, tanks are periodically emptied, cleaned and rendered gas-free. This cleaning includes dissolving the tank bottom. Closed-loop systems that can be combined with end-of-pipe mobile abatement techniques prevent or reduce VOC emissions

The applicability may be limited by e.g. the type of residues, tank roof construction or tank materials

Technique

Description

Applicability

(i)  Maintenance programme including corrosion monitoring, prevention and control

A management system including leak detection and operational controls to prevent overfilling, inventory control and risk-based inspection procedures on tanks at intervals to prove their integrity, and maintenance to improve tank containment. It also includes a system response to spill consequences to act before spills can reach the groundwater. To be especially reinforced during maintenance periods

Generally applicable

(ii)  Double bottomed tanks

A second impervious bottom that provides a measure of protection against releases from the first material

Generally applicable for new tanks and after overhaul of existing tanks (1)

(iii)  Impervious membrane liners

A continuous leak barrier under the entire bottom surface of the tank

Generally applicable for new tanks and after an overhaul of existing tanks (1)

(iv)  Sufficient tank farm bund containment

A tank farm bund is designed to contain large spills potentially caused by a shell rupture or overfilling (for both environmental and safety reasons). Size and associated building rules are generally defined by local regulations

Generally applicable

Technique

Description

Applicability (1)

Vapour recovery by:

(i)  Condensation

(ii)  Absorption

(iii)  Adsorption

(iv)  Membrane separation

(v)  Hybrid systems

See Section 1.20.6

Generally applicable to loading/unloading operations where annual throughput is > 5 000 m3/yr. Not applicable to loading/unloading operations for sea-going vessels with an annual throughput < 1 million m3/yr

Parameter

BAT-AEL

(hourly average) (1)

NMVOC

0,15-10 g/Nm3 (2) (3)

Benzene (3)

< 1 mg/Nm3

Technique

Description

Applicability (1)

(i)  Acid gas removal e.g. by amine treating

See Section 1.20.3

Generally applicable

(ii)  Sulphur recovery unit (SRU), e.g. by Claus process

See Section 1.20.3

Generally applicable

(iii)  Tail gas treatment unit (TGTU)

See Section 1.20.3

For retrofitting existing SRU, the applicability may be limited by the SRU size and configuration of the units and the type of sulphur recovery process already in place

BAT-associated environmental performance level (monthly average)

Acid gas removal

Achieve hydrogen sulphides (H2S) removal in the treated RFG in order to meet gas firing BAT-AEL for BAT 36

Sulphur recovery efficiency (1)

New unit: 99,5 – > 99,9 %

Existing unit: ≥ 98,5 %

Technique

Description

Applicability

(i)  Correct plant design

See Section 1.20.7

Applicable to new units.

Flare gas recovery system may be retrofitted in existing units

(ii)  Plant management

See Section 1.20.7

Generally applicable

(iii)  Correct flaring devices design

See Section 1.20.7

Applicable to new units

(iv)  Monitoring and reporting

See Section 1.20.7

Generally applicable

Technique

Description

Electrostatic precipitator (ESP)

Electrostatic precipitators operate such that particles are charged and separated under the influence of an electrical field. Electrostatic precipitators are capable of operating under a wide range of conditions.

Abatement efficiency may depend on the number of fields, residence time (size), catalyst properties and upstream particles removal devices.

At FCC units, 3-field ESPs and 4-field ESPs are commonly used.

ESPs may be used on a dry mode or with ammonia injection to improve the particle collection.

For the calcining of green coke, the ESP capture efficiency may be reduced due to the difficulty for coke particles to be electrically charged

Multistage cyclone separators

Cyclonic collection device or system installed following the two stages of cyclones. Generally known as a third stage separator, common configuration consists of a single vessel containing many conventional cyclones or improved swirl-tube technology. For FCC, performance mainly depends on the particle concentration and size distribution of the catalyst fines downstream of the regenerator internal cyclones

Centrifugal washers

Centrifugal washers combine the cyclone principle and an intensive contact with water e.g. venturi washer

Third stage blowback filter

Reverse flow (blowback) ceramic or sintered metal filters where, after retention at the surface as a cake, the solids are dislodged by initiating a reverse flow. The dislodged solids are then purged from the filter system

Technique

Description

Combustion modifications

Staged combustion

Flue-gas recirculation

Reinjection of waste gas from the furnace into the flame to reduce the oxygen content and therefore the temperature of the flame.

Special burners using the internal recirculation of combustion gases to cool the root of the flames and reduce the oxygen content in the hottest part of the flames

Use of low-NOX burners (LNB)

The technique (including ultra-low-NOX burners) is based on the principles of reducing peak flame temperatures, delaying but completing the combustion and increasing the heat transfer (increased emissivity of the flame). It may be associated with a modified design of the furnace combustion chamber. The design of ultra-low-NOX burners (ULNB) includes combustion staging (air/fuel) and flue-gas recirculation. Dry low-NOX burners (DLNB) are used for gas turbines

Optimisation of combustion

Based on permanent monitoring of appropriate combustion parameters (e.g. O2, CO content, fuel to air (or oxygen) ratio, unburnt components), the technique uses control technology for achieving the best combustion conditions

Diluent injection

Inert diluents, e.g. flue-gas, steam, water, nitrogen added to combustion equipment reduce the flame temperature and consequently the concentration of NOX in the flue-gases

Selective catalytic reduction (SCR)

The technique is based on the reduction of NOX to nitrogen in a catalytic bed by reaction with ammonia (in general aqueous solution) at an optimum operating temperature of around 300-450 °C.

One or two layers of catalyst may be applied. A higher NOX reduction is achieved with the use of higher amounts of catalyst (two layers)

Selective non-catalytic reduction (SNCR)

The technique is based on the reduction of NOX to nitrogen by reaction with ammonia or urea at a high temperature.

The operating temperature window must be maintained between 900 °C and 1 050  °C for optimal reaction

Low temperature NOX oxidation

The low temperature oxidation process injects ozone into a flue-gas stream at optimal temperatures below 150 °C, to oxidise insoluble NO and NO2 to highly soluble N2O5. The N2O5 is removed in a wet scrubber by forming dilute nitric acid waste water that can be used in plant processes or neutralised for release and may need additional nitrogen removal

Technique

Description

Treatment of refinery fuel gas (RFG)

Some refinery fuel gases may be sulphur-free at source (e.g. from catalytic reforming and isomerisation processes) but most other processes produce sulphur-containing gases (e.g. off-gases from the visbreaker, hydrotreater or catalytic cracking units). These gas streams require an appropriate treatment for gas desulphurisation (e.g. by acid gas removal — see below — to remove H2S) before being released to the refinery fuel gas system

Refinery fuel oil (RFO) desulphurisation by hydrotreatment

In addition to selection of low-sulphur crude, fuel desulphurisation is achieved by the hydrotreatment process (see below) where hydrogenation reactions take place and lead to a reduction in sulphur content

Use of gas to replace liquid fuel

Decrease the use of liquid refinery fuel (generally heavy fuel oil containing sulphur, nitrogen, metals, etc.) by replacing it with on-site Liquefied Petroleum Gas (LPG) or refinery fuel gas (RFG) or by externally supplied gaseous fuel (e.g. natural gas) with a low level of sulphur and other undesirable substances. At the individual combustion unit level, under multi-fuel firing, a minimum level of liquid firing is necessary to ensure flame stability

Use of SOX reducing catalysts additives

Use of a substance (e.g. metallic oxides catalyst) that transfers the sulphur associated with coke from the regenerator back to the reactor. It operates most efficiently in full combustion mode rather than in deep partial-combustion mode.

NB: SOX reducing catalysts additives might have a detrimental effect on dust emissions by increasing catalyst losses due to attrition, and on NOX emissions by participating in CO promotion, together with the oxidation of SO2 to SO3

Hydrotreatment

Based on hydrogenation reactions, hydrotreatment aims mainly at producing low-sulphur fuels (e.g. 10 ppm gasoline and diesel) and optimising the process configuration (heavy residue conversion and middle distillate production). It reduces the sulphur, nitrogen and metal content of the feed. As hydrogen is required, sufficient production capacity is needed. As the technique transfer sulphur from the feed to hydrogen sulphide (H2S) in the process gas, treatment capacity (e.g. amine and Claus units) is also a possible bottleneck

Acid gas removal e.g. by amine treating

Separation of acid gas (mainly hydrogen sulphide) from the fuel gases by dissolving it in a chemical solvent (absorption). The commonly used solvents are amines. This is generally the first step treatment needed before elemental sulphur can be recovered in the SRU

Sulphur recovery unit (SRU)

Specific unit that generally consists of a Claus process for sulphur removal of hydrogen sulphide (H2S)-rich gas streams from amine treating units and sour water strippers.

SRU is generally followed by a tail gas treatment unit (TGTU) for remaining H2S removal

Tail gas treatment unit (TGTU)

A family of techniques, additional to the SRU in order to enhance the removal of sulphur compounds. They can be divided into four categories according to the principles applied:

Wet scrubbing

In the wet scrubbing process, gaseous compounds are dissolved in a suitable liquid (water or alkaline solution). Simultaneous removal of solid and gaseous compounds may be achieved. Downstream of the wet scrubber, the flue-gases are saturated with water and a separation of the droplets is required before discharging the flue-gases. The resulting liquid has to be treated by a waste water process and the insoluble matter is collected by sedimentation or filtration

According to the type of scrubbing solution, it can be:

According to the contact method, the various techniques may require e.g.:

Where scrubbers are mainly intended for SOX removal, a suitable design is needed to also efficiently remove dust.

The typical indicative SOx removal efficiency is in the range 85-98 %.

Non-regenerative scrubbing

Sodium or magnesium-based solution is used as alkaline reagent to absorb SOX generally as sulphates. Techniques are based on e.g.:

Seawater scrubbing

A specific type of non-regenerative scrubbing using the alkalinity of the seawater as solvent. Generally requires an upstream abatement of dust

Regenerative scrubbing

Use of specific SOX absorbing reagent (e.g. absorbing solution) that generally enables the recovery of sulphur as a by-product during a regenerating cycle where the reagent is reused

Technique

Description

Wet scrubbing

See Section 1.20.3

SNOX combined technique

Combined technique to remove SOX, NOX and dust where a first dust removal stage (ESP) takes place followed by some specific catalytic processes. The sulphur compounds are recovered as commercial-grade concentrated sulphuric acid, while NOX is reduced to N2.

Overall SOX removal is in the range: 94-96,6 %.

Overall NOX removal is in the range: 87-90 %

Technique

Description

Combustion operation control

The increase in CO emissions due to the application of combustion modifications (primary techniques) for the reduction of NOX emissions can be limited by a careful control of the operational parameters

Catalysts with carbon monoxide (CO) oxidation promoters

Use of a substance which selectively promotes the oxidation of CO into CO2 (combustion)

Carbon monoxide (CO) boiler

Specific post-combustion device where CO present in the flue-gas is consumed downstream of the catalyst regenerator to recover the energy

It is usually used only with partial-combustion FCC units

▼C1

Technique

Description

▼B

Vapour recovery

Volatile organic compounds emissions from loading and unloading operations of most volatile products, especially crude oil and lighter products, can be abated by various techniques e.g.:

—Absorption: the vapour molecules dissolve in a suitable absorption liquid (e.g. glycols or mineral oil fractions such as kerosene or reformate). The loaded scrubbing solution is desorbed by reheating in a further step. The desorbed gases must either be condensed, further processed, and incinerated or re-absorbed in an appropriate stream (e.g. of the product being recovered)

—Adsorption: the vapour molecules are retained by activate sites on the surface of adsorbent solid materials, e.g. activated carbon (AC) or zeolite. The adsorbent is periodically regenerated. The resulting desorbate is then absorbed in a circulating stream of the product being recovered in a downstream wash column. Residual gas from wash column is sent to further treatment

—Membrane gas separation: the vapour molecules are processed through selective membranes to separate the vapour/air mixture into a hydrocarbon-enriched phase (permeate), which is subsequently condensed or absorbed, and a hydrocarbon-depleted phase (retentate).

—Two-stage refrigeration/condensation: by cooling of the vapour/gas mixture the vapour molecules condense and are separated as a liquid. As the humidity leads to the icing-up of the heat exchanger, a two-stage condensation process providing for alternate operation is required.

—Hybrid systems: combinations of available techniques

NB  Absorption and adsorption processes cannot notably reduce methane emissions.

Vapour destruction

Destruction of VOCs can be achieved through e.g. thermal oxidation (incineration) or catalytic oxidation when recovery is not easily feasible. Safety requirements (e.g. flame arrestors) are needed to prevent explosion.

Thermal oxidation occurs typically in single chamber, refractory-lined oxidisers equipped with gas burner and a stack. If gasoline is present, heat exchanger efficiency is limited and preheat temperatures are maintained below 180 °C to reduce ignition risk. Operating temperatures range from 760 °C to 870 °C and residence times are typically 1 second. When a specific incinerator is not available for this purpose, an existing furnace may be used to provide the required temperature and residence times.

Catalytic oxidation requires a catalyst to accelerate the rate of oxidation by adsorbing the oxygen and the VOCs on its surface The catalyst enables the oxidation reaction to occur at lower temperature than required by thermal oxidation: typically ranging from 320 °C to 540 °C. A first preheating step (electrically or with gas) takes place to reach a temperature necessary to initiate the VOCs catalytic oxidation. An oxidation step occurs when the air is passed through a bed of solid catalysts

LDAR (leak detection and repair) programme

An LDAR (leak detection and repair) programme is a structured approach to reduce fugitive VOC emissions by detection and subsequent repair or replacement of leaking components. Currently, sniffing (described by EN 15446) and optical gas imaging methods are available for the identification of the leaks.

Sniffing method: The first step is the detection using hand-held VOC analysers measuring the concentration adjacent to the equipment (e.g. by using flame ionisation or photo-ionisation). The second step consists of bagging the component to carry out a direct measurement at the source of emission. This second step is sometimes replaced by mathematical correlation curves derived from statistical results obtained from a large number of previous measurements made on similar components.

Optical gas imaging methods: Optical imaging uses small lightweight hand-held cameras which enable the visualisation of gas leaks in real time, so that they appear as 'smoke' on a video recorder together with the normal image of the component concerned to easily and rapidly locate significant VOC leaks. Active systems produce an image with a back-scattered infrared laser light reflected on the component and its surroundings. Passive systems are based on the natural infrared radiation of the equipment and its surroundings

VOC diffuse emissions monitoring

Full screening and quantification of site emissions can be undertaken with an appropriate combination of complementary methods, e.g. Solar occultation flux (SOF) or differential absorption lidar (DIAL) campaigns. These results can be used for trend evaluation in time, cross checking and updating/validation of the ongoing LDAR programme.

Solar occultation flux (SOF): The technique is based on the recording and spectrometric Fourier Transform analysis of a broadband infrared or ultraviolet/visible sunlight spectrum along a given geographical itinerary, crossing the wind direction and cutting through VOC plumes.

Differential absorption LIDAR (DIAL): DIAL is a laser-based technique using differential adsorption LIDAR (light detection and ranging) which is the optical analogue of sonic radio wave-based RADAR. The technique relies on the back-scattering of laser beam pulses by atmospheric aerosols, and the analysis of spectral properties of the returned light collected with a telescope

High-integrity equipment

High-integrity equipment includes e.g.:

▼C1

Technique

Description

▼B

Techniques to prevent or reduce emissions from flaring

Correct plant design: includes sufficient flare gas recovery system capacity, the use of high-integrity relief valves and other measures to use flaring only as a safety system for other than normal operations (start-up, shutdown, emergency).

Plant management: includes organisational and control measures to reduce flaring events by balancing RFG system, using advanced process control, etc.

Flaring devices design: includes height, pressure, assistance by steam, air or gas, type of flare tips, etc. It aims at enabling smokeless and reliable operations and ensuring an efficient combustion of excess gases when flaring from non-routine operations.

Monitoring and reporting: Continuous monitoring (measurements of gas flow and estimations of other parameters) of gas sent to flaring and associated parameters of combustion (e.g. flow gas mixture and heat content, ratio of assistance, velocity, purge gas flow rate, pollutant emissions). Reporting of flaring events makes it possible to use flaring ratio as a requirement included in the EMS and to prevent future events.

Visual remote monitoring of the flare can also be carried out by using colour TV monitors during flare events

Choice of the catalyst promoter to avoid dioxins formation

During the regeneration of the reformer catalyst, organic chloride is generally needed for effective reforming catalyst performance (to re-establish the proper chloride balance in the catalyst and to assure the correct dispersion of the metals). The choice of the appropriate chlorinated compound will have an influence on the possibility of emissions of dioxins and furans

Solvent recovery for base oil production processes

The solvent recovery unit consists of a distillation step where the solvents are recovered from the oil stream and a stripping step (with steam or an inert gas) in a fractionator.

The solvents used may be a mixture (DiMe) of 1,2-dichloroethane (DCE) and dichloromethane (DCM).

In wax-processing units, solvent recovery (e.g. for DCE) is carried out using two systems: one for the deoiled wax and another one for the soft wax. Both consist of heat-integrated flashdrums and a vacuum stripper. Streams from the dewaxed oil and waxes product are stripped for removal of traces of solvents

▼C1

Technique

Description

▼B

Pretreatment of sour water streams before reuse or treatment

Send generated sour water (e.g. from distillation, cracking, coking units) to appropriate pretreatment (e.g. stripper unit)

Pretreatment of other waste water streams prior to treatment

To maintain treatment performance, appropriate pretreatment may be required

▼C1

Technique

Description

▼B

Removal of insoluble substances by recovering oil.

These techniques generally include:

Removal of insoluble substances by recovering suspended solid and dispersed oil

These techniques generally include:

Removal of soluble substances including biological treatment and clarification

Biological treatment techniques may include:

One of the most commonly used suspended bed system in refineries WWTP is the activated sludge process. Fixed bed systems may include a biofilter or trickling filter

Additional treatment step

A specific waste water treatment intended to complement the previous treatment steps e.g. for further reducing nitrogen or carbon compounds. Generally used where specific local requirements for water preservation exist.