You can produce hydrogen from methane or refinery fuel gas and capture the carbon dioxide CO2 which is also produced in this process. The hydrogen can be
used within the installation
exported as a product
The CO2 can be
transported by pipeline or other means and stored in permanent underground geological storage facilities
used as a product not covered in this guidance
These environmental regulators referred to as the regulators worked with industry stakeholders to develop a review of emerging techniques on which this guidance is based
Except where existing regulations apply, this guidance on emerging techniques is not a regulatory requirement but identifies best practice to address important environmental issues. The regulators expect operators to follow this guidance, or to propose an alternative approach to provide the same or greater level of protection for the environment. 1. Who this guidance is for
This guidance is for
operators when designing their plants and preparing their application for an environmental permit
regulatory staff when determining environmental permit applications
any other organisation or members of the public who want to understand how the environmental regulations and standards are being applied
This guidance covers large-scale industrial plants
producing hydrogen using methane for example, from natural gas or refinery fuel gas
capturing the CO2 produced within the process, carbon capture CC, or using post-combustion carbon capture PCC to make it ready for permanent geological storage this is known as carbon capture and storage or sequestration CCS
The guidance covers both new plants and retrofits to existing plants. It does not cover downstream permanent geological storage or using the captured CO2. Large-scale means typically greater than 100 tonnes a day of hydrogen which is around 140MW of hydrogen energy at its lower heating value. Smaller plant should use this guidance until further guidance is available. When you apply for an environmental permit for this activity, you must tell your regulator whether you are going to follow this guidance.
If not, you must propose an alternative approach which will provide the same or greater level of protection for the environment. In the UK, these installations are permitted under the
Environmental Permitting England and Wales Regulations 2016
Pollution Prevention and Control Scotland Regulations 2012
Pollution Prevention and Control Industrial Emissions Regulations NI 2013
For environmental permitting purposes, the hydrogen production plant is a Part A 1 4.2 ai inorganic chemicals activity. A CC or PCC plant is a Part A 1 6.10 a carbon capture and storage activity when the CO2 is being captured from an installation for geological storage. The existing best available techniques BAT reference documents BREFs for Large Volume Inorganic Chemicals Ammonia, Acids and Fertilisers and Refining of Mineral Oil and Gas do not include hydrogen production with CC, other than as an intermediate product for ammonia production. The large combustion plant BREF identifies carbon capture as an emerging technique but does not address all the potential environmental effects of carbon capture. Where BAT is not covered in existing BREFs or where all the potential environmental effects are not addressed, the regulator must follow Article 146 of the Industrial Emissions Directive IED. This means that your regulator must set permit conditions covering emission limit values ELVs, together with other permit conditions. These conditions must be based on the regulators own assessment of emerging techniques using the criteria listed in Annex III of the IED. They should also consult with operators before setting these conditions. The regulators consulted potential technology providers and operators when developing the review of emerging techniques on which this guidance is based. Permits must protect the environment by setting conditions to make sure operators do not breach any environmental quality standards Article 18 of the IED. Your regulator may grant a temporary derogation of BAT- associated emission levels BAT AELs for up to 9 months, on the basis that hydrogen production with carbon capture for permanent storage is testing and using an emerging technique see Article 155 of IED. You should discuss this with your regulator if this is likely to apply. Your regulator will make a decision on the emission limits and other permit conditions that will apply on a case-by-case basis. They will do this based on the elements outlined in this guidance and the most appropriate source of reference. The review of emerging techniques summarises the available evidence to support this guidance. We refer to the relevant sections of the review in this guidance. You may request advice before applying for your permit.
For further advice from your regulator, in
England, contact the Environment Agency enquiriesenvironment-agency.gov.uk
Scotland, contact the Scottish Environment Protection Agency ppcsepa.org.uk
Wales, contact Natural Resources Wales enquiriesnaturalresourceswales.gov.uk
Northern Ireland, contact the Northern Ireland Environment Agency IPRIdaera-ni.gov.uk
2. Technique selection
When choosing hydrogen production and CC plant configuration, you should consider its overall environmental performance, including
energy efficiency
resource efficiency
CO2 capture efficiency
emissions to the environment
These are the hydrogen production methods the regulators considered when producing this guidance
steam methane reforming SMR
autothermal reforming ATR
gas heated reforming GHR
partial oxidation POX
They also considered combinations of these such as GHR plus ATR and GHR plus SMR. All of these methods will need to separate out, capture and prepare hydrogen and CO2 ready for
using hydrogen product within the installation
transporting hydrogen product for use off-site
transporting CO2 for permanent geological storage off site
These activities are outside the scope of this guidance. 3. Plant design and operation
3.1 Flexible operation
You must consider whether your hydrogen production plant may need to operate on a flexible basis to balance variations in demand from hydrogen users. You should consider whether this need for flexibility will affect the design, operation and maintenance of the plant. You should identify flexible operating scenarios where environmental performance could be affected, or where additional emissions are expected. For example, these could be as a result of rapid changes in capacity, or start-up following enforced shutdown. You should describe measures you would take to minimise the environmental impact of these scenarios, which could result in, for example
reduced CO2 capture rates
reduced energy efficiency
increased emissions to air, venting and flaring
increased effluent or wastes produced
increased risk of accidents in non-steady state conditions
3.2 Reliability and availability
You will need to identify equipment and systems that are critical in avoiding emissions. You will need to design, operate and maintain these to make sure they are reliable and available, including providing installed back-up equipment, where necessary.
You should implement a risk-based other than normal operating conditions OTNOC management plan, which identifies potential scenarios, mitigation measures, monitoring and periodic assessment. 3.3 Overall CO2 capture efficiency
You should design plant to maximise the carbon capture efficiency. As a minimum, you should achieve an overall CO2 capture rate of at least 95, although this may vary depending on the operation of the plant. You can base this on average performance over an extended period for example, a year. Overall carbon capture rate or efficiency is defined as the mass of CO2 equivalent captured for storage as a percentage of the mass of CO2 equivalent in all feed gas, including methane or refinery fuel gas or both used in combustion plant. For clarity, this is the same as the mass of carbon captured as a percentage of the mass of carbon in all feed gas.
This should be achievable for the hydrogen production and CO2 capture routes considered for new plant. You will need to provide justification if you are proposing a design CO2 capture rate of less than 95. You should consider how you would comply with future requirements for increased CO2 capture efficiency by making your plant decarbonisation ready. You should plan to allow for space and technical retrofit within the design for additional carbon capture plant. This will allow for the capture of residual emissions of CO2, for example, from combustion of any hydrogen purification residual gas. This is to future-proof the plant so you can comply with any future requirements for carbon capture ready for emissions of CO2 and the likely changes to CO2 capture efficiency required. You should note that any carbon-containing compounds as allowed by the hydrogen product specification will be emitted to the environment in downstream uses, such as combustion. You should aim to minimise these where feasible. For more detail, see the review of emerging techniques
3.4 Process CO2 capture from hydrogen product
Technology for CO2 capture from hydrogen product will typically be through absorption in a circulating solvent, with regeneration of the solvent through reducing pressure and heating to liberate CO2. You should select the solvent, process design and operating conditions that maximise energy efficiency, capture performance, and minimise the waste and effluent treatment required. Where you have considered various options, you should provide the reasoning behind this to demonstrate that your chosen option uses overall BAT.
This could include, for example
maximising absorption for CO2 capture
optimising solvent regeneration to provide CO2 at high pressure, but avoiding excessive degradation of solvent
maximising heat exchange between lean and rich solvent streams
minimising solvent carryover to minimise the need for downstream removal
minimising wastes and effluent streams, while removing contaminant build-up in solvent
For more detail, see the review of emerging techniques, section 5.4. 3.5 CO2 capture for steam methane reforming
In SMR, heat for the reformer reaction is provided by external combustion in a furnace. The fuel gas can be either
methane usually from natural gas feed
refinery fuel gas
hydrogen product
a combination of these
All require post combustion capture to remove the CO2 produced from the flue gas, except where pure hydrogen product is used as the fuel. Following consultation with industry, the regulators expect that more than 95 of CO2 can be removed from the reformer flue gases. The plant could be designed in such a way that no post combustion capture is needed if both of these apply
hydrogen is used as the fuel gas for the reformer
there is in-process CO2 removal prior to hydrogen purification
You will need to justify the best overall approach, considering all environmental impacts. If post-combustion CO2 capture is needed, you should use the guidance post-combustion carbon dioxide capture emerging techniques referred to as PCC guidance. You should take account of any differences between the flue gases considered in the PCC guidance and the flue gases from the SMR reformer furnace. These differences could be, for example, oxygen and nitrogen content, potential for formation of nitrogen oxides NOx and impact of requirement for flexible operation. When optimising for environmental performance, you should consider
selecting appropriate solvents
emissions to air of solvent and associated degradation products
energy requirements
effluents and wastes
cooling requirements
pump and fan noise
flue gas pre-treatment
treated flue gas dispersion
For more detail, see the review of emerging techniques, sections 5.5 and 5.6.
3.6 CO2 capture from residual gas from hydrogen purification
You should consider how to capture CO2 produced by the combustion of residual gas, which results when hydrogen is purified. You should aim to remove this CO2 to maximise the overall carbon capture efficiency and to make sure you achieve at least 95. The residual gas may contain methane, carbon monoxide CO and CO2 as well as hydrogen, nitrogen and argon. This is normally used as a fuel gas and any carbon containing compounds will be converted to CO2. The amount of carbon-containing compounds depends on the efficiency of conversion and removal before the hydrogen purification stage. For more detail, see the review of emerging techniques, section 5.9. 3.7 Energy efficiency, process efficiency, cooling
You should choose your hydrogen production process and design your plant to maximise
energy efficiency minimise the energy needed to produce each tonne of hydrogen
process efficiency minimise the raw materials, such as methane and water, needed to produce each tonne of hydrogen
To decide on BAT, you will have to balance how you achieve these efficiencies in order to optimise the environmental and economic requirements. You must explain how you have done this and what your considerations were. This should take into account all of the chemical and physical processes within the installation boundary needed to produce hydrogen and capture carbon. Main energy users will include
air separation unit ASU for oxygen supply to ATR and POX
hydrogen compressors
CO2 compressors
hydrogen and CO2 purification
solvent recovery system
pumping or fan systems
You should consider
electrical power needs and whether you will import or generate on site
high pressure steam need and availability
maximising any residual waste heat recovery
cooling needs
cooling type and medium
You should also consider heat integration optimisation, for example, heat recovery at
higher temperatures from compression systems including the ASU, CO2 and hydrogen compression for power generation or drives
medium temperatures for solvent recovery
lower temperatures for boiler feed pre-heat
See also section 3.9 Water supply and use. You should reference the BREF documents
Industrial Cooling Systems
Energy Efficiency
For further details, see the review of emerging techniques
section 5.10
section 6.1 Table 20
3.8 Oxygen production
Oxygen is required for the ATR and POX processes. It is usually produced by an ASU, which is a relatively large energy user. You must consider heat recovery from the heat generated by the air compression system and whether you can use it within the rest of the hydrogen production process to maximise energy efficiency. We expect you to explore all opportunities for waste heat recovery as the ASU will be considered part of the installation. You should take the following into account when designing the oxygen production plant and optimise to show you are using BAT
overall energy consumption depends on the design of the ASU and its air compressor
energy required will be a balance between oxygen purity, oxygen pressure needed to supply the hydrogen production process and energy needed to purify the hydrogen
higher oxygen purity will increase the energy required for oxygen production, but reduce the amount needed for hydrogen purification to remove residual argon and nitrogen
co-production of argon and nitrogen can be used for export or on site
heat energy needed to dry and purify the compressed air
options to increase the compressor exit temperature to improve options for heat recovery should be explored, balanced with compressor design and higher power requirement. safe and reliable operation of both the ASU and hydrogen production plant where heat integration is used
high availability of oxygen supply and backup supply or liquid storage is important to avoid potential environmental impacts of emergency or frequent shutdown and start-up of the plant
For further details, see the review of emerging techniques, section 5.12. 3.9 Water supply and use
Water supply and its efficient use is an important aspect of BAT in hydrogen production plant. The quality of the water supply will determine the pre-treatment needed before it can be used as a
raw material in hydrogen production
heat transfer medium
cooling medium
Water is consumed in the process as part of the hydrogen product. Your choice of hydrogen production method will determine the ratio of hydrogen product that comes from water compared with that which comes from methane, or refinery fuel gas, or both. For further details see Water consumption process in Table 20 of the review of emerging techniques. You should
minimise the amount of water you use
segregate, treat and reuse water where possible
choose a cooling method that takes account of the temperature impact on process performance, energy efficiency and environmental impact on the receiving medium
For refineries, you should also comply with BAT conclusion 11 emissions to water from the BAT conclusions BATC for refining of mineral oil and gas. 3.10 Water treatment
Water and steam are used in the process. Water is condensed both from steam systems and from process cooling. In most cases, this water can be reused without being treated. However, some water will need to be removed to avoid the build-up of contaminants. You will need to treat it in an effluent treatment system before releasing it into the environment. You should decide how much water to treat and how to treat it before it is
reused
released to surface water or sewage undertaker
disposed of
You should identify how much contaminant, such as methanol and ammonia, needs to be removed and design the treatment process accordingly. You should identify any emissions to air or wastes that may result from the water treatment process, for example, emission of CO2 from deaeration of boiler feed water. You should use the following references to choose the most appropriate treatments
BREF and BATC for common waste water and waste gas treatmentmanagement systems in the chemical sector
BREF and BATC for refining of mineral oil and gas
For discharges to water, you should refer to the guidance Surface water pollution risk assessment for your environmental permit.
For further details on water treatment for re-use, see the emerging techniques review, section 5.13. 3.11 Feed gas quality and treatment
Your choice of supply of methane-containing feed gas will determine the type of gas treatment processes you will need prior to the main conversion reactions., It will also determine whether you will need to remove inert gases at the hydrogen purification stage. If you use refinery fuel gas as your feed gas supply, where possible, you should remove contaminants such as sulphur and mercury in existing upstream refinery processes, taking account of BAT across the refinery installation. You will need to take account of the possible range of gas composition so that you can design your processes to minimise the overall environmental impact, including substances such as
sulphur S, typically as H2S
nitrogen N2
CO2
mercury
other hydrocarbons
You will need to design your gas treatment and downstream processes in order to
minimise solid wastes for example, catalyst for recycling or disposal
minimise sulphur dioxide SO2 emissions to air where feed gas is combusted
maximise overall process reaction and energy efficiency
minimise emissions to air associated with the removal of nitrogen or other inerts
You should consider removing sulphur compounds by hydrogenation and using catalyst adsorbent to avoid SO2 emissions from combustion and catalyst poisoning. You should consider removing other hydrocarbons by pre-reforming to avoid carbon deposition on catalysts. You should consider the impact a pre-reforming step will have on the downstream reforming stage for an SMR. You may be able to optimise the energy efficiency and minimise NOx emissions to air due to reduced gas fired reformer furnace duty. You will need to consider the impact on steam balance for the plant. You should remove mercury to avoid catalyst poisoning and other downstream contamination. Any CO2 in the feed gas will be removed along with the CO2 produced in the process. You should include this in the overall CO2 balance and capture efficiency monitoring and reporting. 3.12 Reforming and CO shift
Hydrogen is produced in the reforming and CO shift stages of the plant. You should convert methane to hydrogen, CO and CO2 in the reforming stage, while minimising unreacted methane. You should optimise CO conversion to CO2 considering the overall CO2 capture requirement and the impact on downstream processing stages to meet the hydrogen product specification. 3.13. Reforming
You should select, design and operate the reformer reaction in order to
reduce the risk of carbon deposition on catalyst, which would result in reduced reaction efficiency
minimise catalyst change frequency and the need for recycling or waste disposal
If you choose ATR or POX technologies, carbon formation may be more likely due to the reducing atmosphere. You should choose operating parameters to minimise this risk. 3.14 CO shift
You should select, design and operate CO shift reaction in order to
maximise energy efficiency through, for example, heat integration with the overall hydrogen production and CO2 capture processes
minimise the duration of start-up operations and associated emissions to air from flaring
minimise the production of wastes for recycling or disposal
You should consider a single step CO shift process rather than a more conventional high temperature or low temperature shift process, with isothermal conditions achieved through reactor cooling with recovery of heat. By using this option, it may allow you to
increase overall heat integration and efficient use of recovered heat, as long as sufficient conversion of CO to CO2 is achieved
avoid using chromium catalyst needed for high temperature shift, therefore minimising hazardous waste
reduce the potential for catalyst damage, methanation reactions, and Fischer-Tropsch reactions
reduce the potential for the production of methanol which would condense out with water downstream and need to be treated by effluent treatment
consider the cost and environmental benefits of an isothermal reactor against a more complex multi-tube boiling water-cooled reactor
Refer to BREF for large volume inorganic chemicals ammonia, acids and fertilisers section 2.4.14 Isothermal Shift Conversion. 3.15 Catalyst selection
When you choose which catalysts to use, you should consider the overall environmental performance, including, for example
any required pre-treatment to avoid poisoning, to minimise waste and associated treatment
preventing any dust emissions, where applicable
the ability to recover or recycle the solids or metals from the spent catalyst waste
handling spent catalyst for environmentally safe recovery, recycling or disposal
3.16 Hydrogen product
You will need to purify and compress hydrogen so that it is fit for purpose after it is separated from the CO2 in the CO2 capture stage. You should take account of hydrogen purification requirements. These will depend on
the hydrogen product quality specification
impurities in the hydrogen following reforming, CO shift and CO2 capture steps
The impurities may include
CO, which is not converted to CO2 in the reforming or CO shift sections
CO2, which is not removed in the CO2 capture section
methane, which is not converted to CO in the reforming section
nitrogen and argon inert gases present in feed gas or oxygen supply
water the hydrogen is saturated with water following CO2 capture
You should consider pressure swing adsorption PSA to remove impurities from the hydrogen. Treating residual gas containing the impurities is considered in section 3.6 CO2 capture from residual gas from hydrogen purification. You should consider whether methanation to convert CO into methane is appropriate, depending on the specification of hydrogen, to make sure hydrogen is fit for purpose. You should consider the impact on overall energy efficiency and the need for further treatment of hydrogen purification off-gas streams. You should design the overall process to minimise the power required for compression to achieve the pressure required by the user.
See section 3.7 energy efficiency, process efficiency, cooling. 3.17 CO2 product
You should design the process to meet the required CO2 quality specification, temperature and pressure as required for transport to permanent geological storage. You should design the overall process to minimise the power required for compression to achieve the pressure required by the user. You should maximise recovery of waste heat from compression. See section 3.7 energy efficiency, process efficiency, cooling. 4. Emissions to air
You should eliminate, minimise or reduce any emissions to air that could cause pollution. You should make sure that your process emissions can comply with all ELVs which are required under the relevant BATC. You should carry out a risk assessment, including detailed air quality modelling, to assess the impact of these emissions. 4.1 Combustion processes
You should maximise energy efficiency and heat integration so you minimise the need for combustion processes, resultant CO2 and other combustion products. You should maximise the capture of CO2 from combustion processes, taking account of the overall carbon capture requirement. If you decide that carbon capture from a combustion process is not appropriate, you must justify your decision based on BAT. You must identify and minimise the continuous and periodic emissions of combustion products to air. You should consider NOx abatement techniques where the combustion of hydrogen-rich gas with the potential for higher flame temperatures will increase thermal NOx formation, including
burner design
flue gas recirculation
heat exchange with fuel or air
You should consider whether abatement of any of these emissions is required to comply with relevant BAT AELs or local air quality standards, for example, for NOx. Where relevant, you should consider the following abatement techniques
selective catalytic reduction SCR
selective non-catalytic reduction SNCR
You should consider
the overall impact of using residual gas from the hydrogen purification process as a supplementary fuel for fired equipment to balance overall heat requirements, while considering the impact of the additional emissions of combustion products to air
for SMR, the requirement for post-combustion carbon capture for the reformer furnace emissions to air and any pre-treatment of combustion gases needed see the PCC guidance
for ATR, whether the relatively smaller additional heat need can be supplied by combustion of hydrogen-rich residual gas or combustion of hydrogen product
for POX, the process is usually energy-balanced or produces excess heat and so combustion processes may not be needed
the impact on emissions to air due to variability in fuel gas composition or any need to switch between fuel gas sources, for example, at start-up when residual PSA gas for fuel is not available and some feed gas may need to be combusted
You could consider using excess oxygen, where available, to support oxy-combustion, in order to remove the source of nitrogen and therefore limit thermal NOx formation. Fuel NOx may form from nitrogen in the residual gas from the PSA.
There is limited experience of using oxygen, especially for hydrogen-rich gases and any such proposal would need to be fully justified with supporting data. You should design combustion processes to comply with required emissions limit values ELVs from the existing sources of statutorily applicable emission limits and BAT AELs, including the following
Medium Combustion Plant Directive
Industrial Emissions Directive Chapter III Annex V ELVs
BAT AELs identified in the Large combustion plant BREF and BATC
Refining of Mineral Oil and Gas
Large Volume Inorganic Chemicals Ammonia, Acids and Fertilisers
Common Waste Water and Waste Gas TreatmentManagement Systems in the Chemical Sector
You should consider the
type of combustion equipment
fuels proposed to be combusted
net rated thermal inputs
BAT for control of emissions
conclusions of an environmental risk assessment, considering the dispersion of pollutants into air and the sensitivity of the relevant receptors
4.2 Post combustion capture plant
Refer to the PCC guidance section 3.3 Features to control and minimise atmospheric and other emissions. 4.3 Flaring and venting
You must design and operate your plant to minimise the need for continuous or intermittent flaring or venting of gases, whether for operational or safety reasons, including
methane or refinery fuel gas
hydrogen
CO2
This should include
flaring rather than venting, where emissions cannot be eliminated and where practicable, to minimise emissions of higher global warming potential gases such as methane and hydrogen
plant design to maximise equipment availability and reliability see section 3.2 Reliability and availability
avoiding routine flaring for waste gas destruction
managing production of off-gas and balance against requirements for fuel gas using advanced process control, for example
using procedures to define operations, including start-up and shutdown, maintenance work and cleaning
using commissioning and handover procedures to ensure that the plant is installed in line with the design requirements
using return-to-service procedures to ensure that the plant is recommissioned and handed over in line with the operational requirements
designing flaring devices to enable smokeless and reliable operations, and to ensure an efficient combustion of excess gases when flaring under other than normal operations
monitoring and reporting of gas sent to flaring and associated parameters of combustion
You must minimise emissions under start-up, shutdown, and abnormal operations. This can be achieved by
using a flare gas recovery system with adequate capacity
routing gas that would be flared to alternative users
using high integrity relief valves
other measures to limit flaring to abnormal operation
If your activity is part of a refineries installation, you should refer to BAT conclusions 55 and 56 in BATC for the Refining of Mineral Oil and Gas. You should quantify and assess harm from other routine venting and purging requirements, identifying any pollutants that are expected to be present, including, for example
CO2
hydrogen
CO
methane
ammonia vapour
methanol vapour
Requirements for continuous venting during normal operations may include, for example
Requirements for intermittent venting may include, for example
5. Emissions to water
You must identify and eliminate, minimise, recycle or treat any emissions to water that could cause pollution. You should carry out a risk assessment, including detailed modelling, where appropriate, to assess the impact of these emissions. For discharges to water, you should refer to the guidance Surface water pollution risk assessment for your environmental permit.
5.1 Effluent treatment discharges
You should identify continuous and periodic effluent streams from the process and determine whether effluent treatment is required. These streams may include process condensate containing contaminants, which may need treatment before discharge, for example
methanol
ammonia
CO2
amines
degradation products
You should treat water for reuse as far as possible. See section 3.10 Water treatment. You should refer to the appropriate BREF and BATC where available if the installation is considered to be part of a refinery or a chemicals installation
Refining of Mineral Oil and Gas
Common Waste Gas Management and Treatment Systems in the Chemical Sector
Large Volume Inorganic Chemicals Ammonia, Acids and Fertilisers
6. Waste
You must eliminate or minimise wastes and treat, where appropriate. You should consider how to deal with the following wastes that may be generated.
6.1 Liquid wastes
Liquid wastes such as
demineralised water production reject stream
amine solvent for example, from bleed or feed replacement
dehydration solvent for example, in case of tri-ethylene glycol dehydration
amine reclaimer residue
6.2 Solid wastes
Solid wastes such as
depleted catalyst material hydrogenation, reforming, CO shift
spent adsorbent materials gas treatment, dehydration, hydrogen purification
solids from amine filtration
soot POX process
7. Monitoring
The main purpose of monitoring is to demonstrate compliance with the permit and show that emissions from the process are not causing harm to the environment. You must also carry out monitoring to show that resources are being used efficiently. This includes
energy and resource efficiency
carbon capture efficiency
verifying that the CO2 product is suitable for safe transport and storage
hydrogen product quality
verifying when applicable compliance with low carbon hydrogen standards
Your permit application should include a monitoring plan for both a commissioning phase and routine operation. During the commissioning phase, you will need to assess monitoring results and optimise the operation of the process. You will need to report on your commissioning phase monitoring results, your assessment of them and any changes you want to make to the operation. Its likely you will need to do more extensive monitoring during the commissioning phase than during routine operation. As these production techniques for hydrogen with CCS are emerging techniques, you will need to develop monitoring methods and standards. You should include proposals for this in your permit application. Complying with ELVs in your permit will provide the necessary protection for the environment, by monitoring emissions at authorised release points. You must also show that you are managing the process to prevent or minimise the formation of solvent degradation products. Where degradation products are formed and may be released, you must reduce these and any solvent emissions to the appropriate level. This process control monitoring will also be part of the permit conditions. 7.1 Monitoring point source emissions to air
You should provide a monitoring plan for monitoring emissions to air, based on expected pollutants such as
ammonia
amine compounds
SO2
NOx
CO
methane
hydrogen
You should do this using appropriate methods and measuring techniques. Emissions of methane and hydrogen should be eliminated or minimised due to their global warming potential. Your monitoring should consider, for example
NOx and CO emissions from combustion
SO2 emissions from combustion where the fuel source contains sulphur
ammonia emissions where SCR or SNCR is used
amine or amine degradation products and other volatile solvent emissions, where relevant
methane and hydrogen slip from any combustion processes
any other sources of methane or hydrogen emissions
For combustion plant, your monitoring plan should demonstrate compliance with the applicable emission limits described in section 4.1 Combustion processes. Where you are using post-combustion CO2 capture, for example, using amine solvent, your plan should include monitoring relevant emissions such as
ammonia
volatile components of the capture solvent
likely degradation products such as nitrosamines and nitramines
Specific pollutants arising from post-combustion capture may be monitored by continuous emissions monitors, if they are available, or by periodic extractive sampling. Where aerosol formation is expected, the sampling must be isokinetic. 7.2 Monitoring emissions to water
You must monitor emissions to water based on expected impurities for example, ammonia, amine compounds, methanol, CO2 using appropriate methods and measuring techniques. You should use monitoring standards for discharges to water following
BATC for common waste water and waste gas treatmentmanagement system in the chemical sector
BATC for the refining of mineral oil and gas
7.3 Monitoring standards
The person who carries out your monitoring must be competent and work to recognised standards such as the Environment Agencys monitoring certification scheme MCERTS. MCERTS sets the monitoring standards you should meet. The Environment Agency recommends that you use the MCERTS scheme, where applicable. You can use another certified monitoring standard, but you must provide evidence that it is equivalent to the MCERTS standards. There are no prescriptive BAT requirements for how to carry out monitoring. Monitoring methods need to be flexible to meet specific site or operational conditions. You must use a laboratory accredited by the United Kingdom Accreditation Service UKAS to carry out analysis for your monitoring.
You should also refer to the JRC Reference Report on Monitoring for IED Installations. 7.4 Monitoring CO2 capture performance
You should clearly identify how you will monitor the CO2 capture performance of the plant. The regulators expect you to monitor CO2 capture performance according to standards that are recognised under the UK ETS. Measurements required to monitor CO2 emissions to atmosphere may, for example, include directly measuring the flow and composition of fuel gas to combustion systems. This, together with measuring the following, will allow monitoring of the CO2 capture rate and CO2 quality considering any impurities that could impact downstream systems
flow and composition of feed gas
hydrogen product including methane content where applicable
CO2 product streams
You will need to include
CO2 equivalent mass balance
CO2 equivalent in feed gas
total capture efficiency CO2 equivalent captured as a mass percentage of CO2 equivalent in feed gas
CO2 equivalent released to the environment
CO2 quality
7.5 Monitoring process performance
You should identify the main requirements for monitoring process operations where these ultimately impact on environmental performance, including, for example, for the CO2 capture system
amine system performance, including monitoring of amine solvent quality such as amine concentration
pH and presence of degradation or corrosion products
amine temperatures
amine and wash water circulation rates
rich and lean amine CO2 loading
stripper reboiler steam rates
You should monitor energy efficiency in the hydrogen production and CO2 capture processes by measuring feed and product gas flows and electrical power consumption to calculate overall energy consumption. You should monitor the quality of the hydrogen product to ensure it is fit for purpose. Requirements for process performance monitoring, either online or offline, will also be a condition of the permit.
8. Unplanned emissions and accidents
You should propose a leak detection and repair LDAR programme that is appropriate for the fluids and their composition. This should use industry best practice to manage releases, including from joints, flanges, seals and glands. You should include how you will use LDAR to eliminate or reduce fugitive emissions of methane and hydrogen due to their global warming potential. Your hazard assessment and mitigation for the plant must consider the risks of accidental releases to the environment. This should also consider the actual composition of the liquids, gases and vapours that could be released from the plant after an extended period of operation. 9. Noise and odour
You need to consider sources that have high potential for noise and vibration. In particular, CO2 and hydrogen compression, pumping and fan noise could be significant additional sources. Once youve identified the main sources and transmission pathways, you should consider using common noise and vibration abatement techniques and mitigation at source, wherever possible. For example
embankments to screen the source of noise
enclosure of noisy plant or components in sound-absorbing structures
anti-vibration supports and interconnections for equipment
orientation and location of noise-emitting machinery
changing the frequency of the sound
Please refer to Noise and vibration management environmental permits. Handling, storing and using some amines may result in odour emissions, so you should always use best practice containment methods. Where there is increased risk that odour from activities will cause pollution beyond the site boundary, you will need to send an odour management plan with your permit application. In England, Wales and Northern Ireland please refer to Environmental permitting H4 odour management. In Scotland refer to Odour guidance 2010.