COMMISSION IMPLEMENTING DECISION
of 9 October 2014
establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council on industrial emissions, for the refining of mineral oil and gas
(notified under document C(2014) 7155)
(Text with EEA relevance)
(2014/738/EU)
Article 1
Article 2
ANNEX
BAT CONCLUSIONS FOR THE REFINING OF MINERAL OIL AND GAS
SCOPE
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 |
GENERAL CONSIDERATIONS
Averaging periods and reference conditions for emissions to air
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 |
Conversion of emissions concentration to reference oxygen level
Averaging periods and reference conditions for emissions to water
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 |
DEFINITIONS
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) |
1.1.
General BAT conclusions for the refining of mineral oil and gas
1.1.1.
Environmental management systems
Applicability
1.1.2.
Energy efficiency
Technique |
Description |
||||||||
(i) Design techniques |
|||||||||
|
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 |
||||||||
|
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 |
||||||||
|
Use of energy recovery devices e.g.:
|
||||||||
(ii) Process control and maintenance techniques |
|||||||||
|
Automated controlled combustion in order to lower the fuel consumption per tonne of feed processed, often combined with heat integration for improving furnace efficiency |
||||||||
|
Systematic mapping of drain valve systems in order to reduce steam consumption and optimise its use |
||||||||
|
Participation in ranking and benchmarking activities in order to achieve continuous improvement by learning from best practice |
||||||||
(iii) Energy-efficient production techniques |
|||||||||
|
System designed for the co-production (or the cogeneration) of heat (e.g. steam) and electric power from the same fuel |
||||||||
|
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 |
1.1.3.
Solid materials storage and handling
1.1.4.
Monitoring of emissions to air and key process parameters
Description |
Unit |
Minimum frequency |
Monitoring technique |
||
|
Catalytic cracking |
Continuous(2) (3) |
Direct measurement |
||
Combustion units ≥ 100 MW(4) and calcining units |
Continuous(2) (3) |
Direct measurement(5) |
|||
Combustion units of 50 to 100 MW(4) |
Continuous(2) (3) |
Direct measurement or indirect monitoring |
|||
Combustion units < 50 MW(4) |
Once a year and after significant fuel changes(6) |
Direct measurement or indirect monitoring |
|||
Sulphur recovery units (SRU) |
Continuous for SO2 only |
Direct measurement or indirect monitoring(7) |
|||
|
All units equipped with SCR or SNCR |
Continuous |
Direct measurement |
||
|
Catalytic cracking and combustion units ≥ 100 MW(4) |
Continuous |
Direct measurement |
||
Other combustion units |
Once every 6 months(6) |
Direct measurement |
|||
|
Catalytic cracking |
Once every 6 months and after significant changes to the unit(6) |
Direct measurement or analysis based on metals content in the catalyst fines and in the fuel |
||
Combustion units(9) |
|||||
|
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(10) |
Continuous for O2 content. For N and S content, periodic at a frequency based on significant fuel/feed changes |
Description
1.1.5.
Operation of waste gas treatment systems
Description
Parameter |
BAT-AEL z(monthly average) mg/Nm3 |
Ammonia expressed as NH3 |
< 5 – 15(11) (12) |
1.1.6.
Monitoring of emissions to water
1.1.7.
Emissions to water
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
See Section 1.21.2 |
Generally applicable |
||
|
See Section 1.21.2 |
Generally applicable |
||
|
See Section 1.21.2 |
Generally applicable |
Parameter |
Unit |
BAT-AEL (yearly average) |
Monitoring(14) frequency and analytical method (standard) |
Hydrocarbon oil index (HOI) |
mg/l |
0,1-2,5 |
Daily EN 9377- 2(15) |
Total suspended solids (TSS) |
mg/l |
5-25 |
Daily |
Chemical oxygen demand (COD)(16) |
mg/l |
30-125 |
Daily |
BOD5 |
mg/l |
No BAT-AEL |
Weekly |
Total nitrogen(17), expressed as N |
mg/l |
1-25(18) |
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 |
1.1.8.
Waste generation and management
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
1.1.9.
Noise
1.1.10.
BAT conclusions for integrated refinery management
Technique |
Description |
Applicability |
||||||||||
|
|
Applicability may be limited for existing units |
||||||||||
|
|
Applicability may be limited for existing units |
||||||||||
|
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 |
1.2.
BAT conclusions for the alkylation process
1.2.1.
Hydrofluoric acid alkylation process
Description
Applicability:
Technique |
Description |
Applicability |
||
|
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 |
||
|
The insoluble compounds produced at the first step (e.g. CaF2 or AlF3) are separated in e.g. a settlement basin |
Generally applicable |
1.2.2.
Sulphuric acid alkylation process
1.3.
BAT conclusions for base oil production processes
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
Processes based on conversion of undesired compounds via catalytic hydrogenation similar to hydrotreatment. See Section 1.20.3 (Hydrotreatment) |
Generally applicable to new units |
1.4.
BAT conclusions for the bitumen production process
Technique |
Description |
Applicability |
||
|
See Section 1.20.6 |
Generally applicable for the bitumen blowing unit |
||
|
See Section 1.20.3 |
Generally applicable for the bitumen blowing unit |
1.5.
BAT conclusions for the fluid catalytic cracking process
Technique |
Description |
Applicability |
||
Process optimisation and use of promoters or additives |
||||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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(19) |
|
Existing unit/partial combustion mode |
100-400(19) |
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
See Section 1.20.1 |
For existing units, the applicability may be limited by space availability |
||
|
See Section 1.20.1 |
Generally applicable |
||
|
See Section 1.20.1 |
Applicability may be restricted |
||
|
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)(20) mg/Nm3 |
Dust |
New unit |
10-25 |
Existing unit |
10-50(21) |
Technique |
Description |
Applicability |
||
|
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) |
||
|
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 |
||
|
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 |
||
|
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(22) |
|
Existing units/partial combustion |
100-1 200(22) |
Technique |
Description |
Applicability |
||
|
See Section 1.20.5 |
Generally applicable |
||
|
See Section 1.20.5 |
Generally applicable only for full combustion mode |
||
|
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(23) |
1.6.
BAT conclusions for the catalytic reforming process
Technique |
Description |
Applicability |
||
|
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 |
||||
|
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 |
||
|
See Section 1.20.3 |
Not applicable to semi-regenerative reformers |
||
|
See Section 1.20.1 |
Not applicable to semi-regenerative reformers |
1.7.
BAT conclusions for the coking processes
Technique |
Description |
Applicability |
||
|
Systematic collection and recycling of coke fines generated during the whole coking process (drilling, handling, crushing, cooling, etc.) |
Generally applicable |
||
|
See BAT 3 |
Generally applicable |
||
|
Arrestment system for pressure relief from the coke drums |
Generally applicable |
||
|
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 |
Description
Applicability
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
See Section 1.20.1 |
Generally applicable |
Parameter |
BAT-AEL (monthly average) mg/Nm3 |
Dust |
10-50(24) (25) |
1.8.
BAT conclusions for the desalting process
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
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 |
1.9.
BAT conclusions for the combustion units
Technique |
Description |
Applicability |
||||||
(i) Selection or treatment of 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 |
||||||
|
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 |
||||||||
|
See Section 1.20.2 |
Fuel staging for mixed or liquid firing may require a specific burner design |
||||||
|
See Section 1.20.2 |
Generally applicable |
||||||
|
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 |
||||||
|
See Section 1.20.2 |
Generally applicable for gas turbines where appropriate inert diluents are available |
||||||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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(26) (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)(27) |
Parameter |
Type of combustion |
BAT-AEL (monthly average) mg/Nm3 |
NOX expressed as NO2 |
Gas firing |
30-150 for existing unit(28) |
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(29) (30) |
Technique |
Description |
Applicability |
||
(i) Selection or treatment of 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 |
||
|
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 |
||||
|
See Section 1.20.2 |
Generally applicable to all types of combustion |
||
|
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 |
||
|
See Section 1.20.1 |
For existing units, the applicability may be limited by space availability |
||
|
See Section 1.20.1 |
Generally applicable |
||
|
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 |
||
|
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(31) (32) |
5-25 for new unit < 50 MW |
Technique |
Description |
Applicability |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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 |
||
|
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(33) |
Parameter |
BAT-AEL (monthly average) mg/Nm3 |
SO2 |
35-600 |
Description
Parameter |
BAT-AEL (monthly average) mg/Nm3 |
Carbon monoxide, expressed as CO |
≤ 100 |
1.10.
BAT conclusions for the etherification process
1.11.
BAT conclusions for the isomerisation process
1.12.
BAT conclusions for the natural gas refinery
1.13.
BAT conclusions for the distillation process
Applicability
Applicability
1.14.
BAT conclusions for the products treatment process
Applicability
1.15.
BAT conclusions for storage and handling processes
Description
Applicability
Technique |
Description |
Applicability |
||
|
Oil tank cleaning is performed by workers entering the tank and removing sludge manually |
Generally applicable |
||
|
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 |
||
|
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 |
||
|
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(34) |
||
|
A continuous leak barrier under the entire bottom surface of the tank |
Generally applicable for new tanks and after an overhaul of existing tanks(34) |
||
|
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(35) |
||||||||||
Vapour recovery by:
|
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)(36) |
NMVOC |
0,15-10 g/Nm3 (37) (38) |
Benzene(38) |
< 1 mg/Nm3 |
1.16.
BAT conclusions for visbreaking and other thermal processes
1.17.
BAT conclusions for waste gas sulphur treatment
Technique |
Description |
Applicability(39) |
||
|
See Section 1.20.3 |
Generally applicable |
||
|
See Section 1.20.3 |
Generally applicable |
||
|
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(40) |
New unit: 99,5 – > 99,9 % |
Existing unit: ≥ 98,5 % |
1.18.
BAT conclusions for flares
Technique |
Description |
Applicability |
||
|
See Section 1.20.7 |
Applicable to new units. Flare gas recovery system may be retrofitted in existing units |
||
|
See Section 1.20.7 |
Generally applicable |
||
|
See Section 1.20.7 |
Applicable to new units |
||
|
See Section 1.20.7 |
Generally applicable |
1.19.
BAT conclusions for integrated emission management
Description
Table 18
BAT-associated emission levels for NO
x
emissions to air when applying BAT 57
Description
Table 19
BAT-associated emission levels for SO
2
emissions to air when applying BAT 58
GLOSSARY
1.20.
Description of techniques for the prevention and control of emissions to air
1.20.1.
Dust
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 |
1.20.2.
Nitrogen oxides (NO
X
)
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 |
1.20.3.
Sulphur oxides (SO
X
)
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 |
1.20.4.
Combined techniques (SO
x
, NO
x
and dust)
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 % |
1.20.5.
Carbon monoxide (CO)
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 |
1.20.6.
Volatile organic compounds (VOC)
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
|
||||||||
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.:
|
1.20.7.
Other techniques
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 |
1.21.
Description of techniques for the prevention and control of emissions to water
1.21.1.
Waste water pretreatment
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 |
1.21.2.
Waste water treatment
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. |