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)

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)

Parameter

Type of unit

BAT-AEL (monthly average) (20)

mg/Nm3

Dust

New unit

10-25

Existing unit

10-50 (21)

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)

Parameter

Combustion mode

BAT-AEL

(monthly average)

mg/Nm3

Carbon monoxide, expressed as CO

Partial combustion mode

≤ 100 (23)

Parameter

BAT-AEL

(monthly average)

mg/Nm3

Dust

10-50 (24)  (25)

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)

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

Parameter

BAT-AEL

(monthly average)

mg/Nm3

SO2

5-35 (33)

Parameter

BAT-AEL

(monthly average)

mg/Nm3

SO2

35-600

Parameter

BAT-AEL

(monthly average)

mg/Nm3

Carbon monoxide, expressed as CO

≤ 100

Parameter

BAT-AEL

(hourly average) (36)

NMVOC

0,15-10 g/Nm3  (37)  (38)

Benzene (38)

< 1 mg/Nm3

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 %

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

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

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.:

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

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

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.