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  • What options are there for CO2 capture from a SMR based hydrogen unit?

    Apr-2021

Answers


  • Morgan Rodwell, Fluor, morgan.rodwell@fluor.com

    This depends on how much of the CO2 you want to capture, and how severe of a shift reaction extent you achieve.

    - For an SMR w/ HTS only (common), the PSA tail gas contains significant carbon (as methane and CO) and is burned as fuel in the furnace.  In this scenario, removing CO2 upstream of the PSA unit can only capture 55-60% of the CO2.

    - If the SMR has a HTS and LTS, then capturing perhaps 70% of the CO2 is possible from the process stream.  However, additional fuel is burned in the furnace and all the combustion emissions are not captured.

    - The challenge with amine capture of CO2 from the process gas is that there is a significant energy cost (~2 GJ/tonne CO2) to to regenerate the solvent (usually something along the lines of an MDEA blend).

    - With some added syngas compression, a physical solvent such as Fluor Solvent can be used and will have a lower net energy cost than amine, but again this would limit capture to 55-70% of the total emissions (depending on shift configuration)  

    - If you want >90% capture in an SMR, flue gas capturing using an amine or similar solvent process is a good option.  The Fluor Econamine FG+ technology can do this at an energy cost <2.7 GJ/tonne of CO2 captured, and provides a high purity CO2 stream.  

    - You can capture CO2 from the PSA tail gas cryogenically, and Fluor offers the CO2LDSep process for this.  This can produce a relatively pure CO2 stream and can, like the process amine capture processes, a maximum of perhaps 60% of the total CO2 emissions of the plant.

     

    Jun-2021

  • Obdulio Fanti, Iadb Consultant, obduliofanti@gmail.com

    Another option is to use, as raw material to produce H2, renewable feedstock like ethanol.

    Jun-2021

  • Marcelo Tagliabue, Air Liquide, marcelo.tagliabue@airliquide.com

    Hydrogen plants are a significant source of CO2 in refineries and chemical plants. The hydrogen production plant is one of the largest emitters in a typical refinery. Therefore, CO2 capture from hydrogen plants has become a particular point of attention for refining and industrial companies such as Air Liquide, who owns and operates numerous hydrogen plants throughout the world. Air Liquide has developed a solution specifically tailored for CO2 capture from SMR plants which is called CRYOCAPŒ H2. This technology uses cryogenic purification to separate the CO2 from the PSA offgas. 

    The first step is a compression of the PSA offgas, followed by a cryogenic purification to separate the CO2 under pressure. The CO2 can be produced at very high pressure with limited recompression energy. CRYOCAPΠH2 technology also embeds membrane separation in order to simultaneously increase the CO2 capture rate and the SMR productivity (hydrogen recovery from syngas is increased). As a result, more than 97% of CO2 emissions from the syngas can be captured, while extra hydrogen production ranges from 10 to 15%.

    May-2021

  • Syed Mumtaz, Freelance Individual, ab12d@yahoo.com

    I read with interest being familiar with most of the ideas and practices discussed. Though developments are in the pipeline, in a nutshell the current state of flue gas capture technology remains amine based with considerable pretreating of flue gases to remove contaminants, cooling and compression, and then further adjustments to make it suitable for sequestration due to the physical and chemical limitations of solvents and CO2 containing systems. The alternatives of direct CO2 capture or aggregates or chemical compounding utilization, in my opinion, represent niche technologies, not really applicable to large scale industrial application in a global format at this time. This means, in my view at least, the path to desired reduction of CO2 emissions lies elsewhere: perhaps H2 based combustion or e combustion, from H2 or power produced through clean power techs which are already proven, simple to build and operate. Where fossils must be used, efforts should be directed to cut an equal amount of CO2 or capture elsewhere in the facility, so there is a balance at least from the 2050 targets perspective. Hopefully by the turn of the century, proven commercial technologies will be economical enough and available to all to further reduce the CO2 emissions from the direct combustion of fossils.   

    Apr-2021

  • Sanjiv Ratan, Zoneflow Reactor Technologies, SRatan@zoneflowtech.com

    For capture from a SMR based hydrogen unit, there are principally two CO2 containing streams - the shifted process gas and the combustion flue gas. Typically, in a hydrogen plant, the CO2 content of the shifted gas is separated (along with other components) in the PSA unit in the form of its low-pressure purge gas. The purge gas is usually utilised as primary fuel for SMR firing, which caters for the larger part of the SMR fired duty, and the remaining heat release is provided by the make-up fuel (also for firing control).

    Accordingly, the flue gas ends up with the combined CO2 from the hydrocarbon feed as well as make-up fuel.

    Such a process configuration offers three options for CO2 capture:

    1. From process gas upstream of the PSA unit
    2. From PSA purge gas
    3. From combustion flue gas

    Options 1 and 2 are pre-combustion CO2 capture alternatives but only offer partial capture (typically around two thirds of the total load) whereas option 3 can be combined with options 1 or 2 or just by itself as post-combustion capture for higher CO2 removal. Each option has its pros and cons.

    Option 1 is the simplest, most cost-effective, and most proven in terms of solvent based CO2 removal processes applied at process pressure on clean gas. It can be integrated in a new hydrogen plant as well as in a revamp project. The PSA purge gas volume reduces while its calorific value increases, which increases NOx in the flue gas. The flue gas volume reduces on account of a lower volume of purge gas as well as some make-up fuel savings in lieu of avoiding heating up the removed CO2. Accordingly, the export steam quantity also goes down.

    Option 2, though seldomly considered, may have more relevance for CO2 removal retrofits in existing hydrogen plants since it has no impact on the performance and/or adsorbent adaptation of the existing PSA unit. However, it needs pressure boosting to overcome the pressure drop and involves higher energy consumption for CO2 removal due to much lower CO2 partial pressures. In new plants, a PSA design can be optimised for higher purge pressures versus reduced H2 recovery. The effect on the material and heat balance is similar to option 1 for the same CO2 removed.

    Option 3, like any fired unit CO2 capture, suffers from limited available and/or well proven technologies, apart from the capital and energy intensity of any post-combustion capture.

    The choice and economics of CO2 capture in a SMR-based hydrogen plant are usually driven by the target percentage reduction in emissions based on any CO2 credit (for EOR or as by-product), or regulatory requirements and related credits or taxation going forward.

    Apr-2021

  • Mel Larson, Becht, mlarson@becht.com

    Most modern SMRs have a means of hydrogen purification, commonly now it is either pressure swing absorption and or a prism system. The effluent or reject stream will be rich in CO2 (40-45 mol%). This stream is the candidate to be processed further either with cryogenic or solvent systems to concentrate the CO2. The concentrated CO2 can be used for enhanced oil recovery. New technologies are being developed to consider absorption systems although not many have been taken to the commercial scale yet.   

    Apr-2021

  • Joris Mertens, KBC (A Yokogawa Company), Joris.Mertens@KBC.global

    CO2 can be captured from SMRs at different locations and using different technologies. Nearly all installations use amine solutions as the technology to capture CO2 and we are aware of one large scale cryogenic CO2 capture plant.

    In SMRs most CO2 is generated at the process side, not by burning fuel in the reformer furnace. Therefore, it is possible to capture most CO2 ‘pre-combustion’ after the shift reaction step, prior to the PSA and the furnace. This has the advantage that pressure (and therefore driving force for amine capture ) is high, which considerably reduces capital cost and plot space. However, it will not allow one to capture all CO2 generated on the unit (even if capture would be 100% efficient) because CO2 generated by the fuel of the furnace is generated after capture. Pre-combustion capture will enable capturing 5-6 tonnes of CO2 per tonne of hydrogen produced while the total CO2 emissions of the unit are at least 8 tonnes per tonne of hydrogen output.

    Post-combustion capture of the CO2 from the SMR furnace flue gas also has the advantage that it is a tail-end solution which in many cases will be easier to fit in. But it will be larger in size and require more capital investment. In short, the choice between pre- and post-combustion is the result of a trade-off between a number of advantages and disadvantages, the main ones being the investment cost and the amount of carbon captured.

    Apr-2021

  • Ulrich Koss, Petrogenium, ulrich.koss@petrogenium.com

    In a refinery, steam methane reforming (SMR) based hydrogen production represents one of the most prominent single-point sources of CO2 emissions. It consists of three consecutive process steps. In the steam reformer, a mixture of natural gas and steam is ‘reformed’, which means it is converted to syngas – a mixture of H2, CO, and CO2. The reforming reaction is strongly endothermic and consumes a lot of heat, which is provided by combusting gas in the furnace of the SMR.

    In the downstream reactor, the water gas shift (WGS) reaction converts CO and steam contained in the syngas to additional H2 and CO2. Third, a pressure swing adsorption (PSA) is used to separate a pure H2 product from the converted syngas. The PSA accumulates all other components in an off-gas stream, consisting mainly of CO2 but also containing unconverted CH4, CO, and some H2. This gas is added to the fuel to the SMR burners. Thus, all carbon contained ultimately ends up as CO2 in the SMR flue gas. The aim is to upgrade this ‘grey’ H2 production a to a ‘blue’ one, by adding carbon capture.

    A first option is to add post-combustion CO2 capture in the SMR flue gas path. This solution is successfully applied to fertilizer production, where natural gas is converted into H2, then ammonia, and ultimately urea. For converting all ammonia into urea, more CO2 is needed and can be extracted from the syngas. To close this gap, a handful of these plants source additional CO2, extracting it from the flue gas of their SMRs using amine post-combustion capture technology. Oxygen and NOx present in the flue gas require amine technology specifically adapted to such service, to keep emissions, corrosion, and amine degradation under control. Most references use Mitsubishi’s KS-1 technology. Other technologies available are BASF´s OASE blue, Aker’s CleanCarbon, DOW’s UCARSOL FGC3000, Fluor´s Econamine FG or Shell´s Cansolv. All consume considerable amounts of steam. Amine degradation and emission control so far have been a persistent problem and a relevant cost factor.

    A second option is to add a compact amine wash between WGS and PSA. Such syngas amine wash selectively extracts all CO2 upstream of the PSA, yielding a pure CO2 stream and a CO2-free PSA off-gas. Here, the well-referenced ‘working horses’ of gas clean-up are applied, among them BASF´s aMDEA, Dow´s UCARSOL, etc. This strategy is far more economical and easier to operate than the above post-combustion capture. The downside is that only the ‘low hanging fruits’, the CO2 in the syngas, are captured. This is whilst the CO2 generated in the SMR firing remains emitted, delimiting the capture rate to 60%. Higher rates are possible if the SMR is converted to H2-firing. However, such a strategy will massively derate the SMR´s capacity, as it must produce the H2 fuel additionally to the H2 product.

    Small-scale, electrically heated SMR (eSMR) technology exists, offering a hybrid between natural gas and electricity. Future large-scale eSMRs, implemented together with the syngas amine wash, boost the capture rate but require an alternative outlet for the PSA off-gas.

    A third option is to apply oxy-firing, which basically means replacing N2 in the combustion air by recirculated CO2. Doing so, the flue gas will largely consist of CO2 and water. After water condensing, the CO2 remaining is purified and compressed. The principle is simple but requires an air separation unit (ASU), a quite sophisticated tail gas treatment, and a substantial revision of the SMR firing and safety concepts. To keep the combustion temperature reasonably low, the amount of CO2 internally recirculated is 4-5 times larger than the amount finally captured.

    Other (non-SMR):

    If a new, large-scale blue H2 production is planned, a different concept can be applied: in such a case, an ATR- solution is considered the optimum. Here, the SMR is replaced by a high pressure O2-driven autothermal reformer (HP ATR), which does not require external firing. The converted syngas of this system offers a high CO2 concentration at a high pressure. CO2 extraction can be accomplished very efficiently not only by the ‘working horse’ amines but also using a simple cold methanol absorption/flashing loop. ATR technology is available from ThyssenKrupp Industrial Solutions, Air Liquide, Haldor Topsoe, and others. It requires an ASU to produce the O2 for the ATR.

    A newcomer among the technologies for the CO2 emission-free production of H2 from natural gas is the production of ‘turquoise’ H2 by means of methane pyrolysis. Here, the natural gas is directly de-composed to H2 and carbon black solids, where the latter can be used as a feedstock in tyre production or in any other industry consuming carbon black. The technology is being developed by BASF, Linde, and ThyssenKrupp Industrial Solutions, but it is not yet fully commercial.

    Apr-2021

  • Elena Petriaeva, BASF OASE Gas Treatment Excellence, elena.petriaeva@basf.com

    To meet the emission reduction targets required by 2050 under the Climate Change Act, energy sources will need to shift to an almost entirely carbon-free energy. That points to a larger role for hydrogen, which can be produced in low-carbon ways from electricity or with carbon capture and storage (CCS).

    Syngas, a mixture of hydrogen and carbon monoxide (H2 and CO), is produced on a large scale via steam reforming of natural gas and water. In the steam reforming process, carbon dioxide (CO2) is produced as a by-product and emitted from two different sources: as part of flue gas and as part of process gas.

    BASF’s OASE white is a proven amine scrubbing technology for deep CO2 removal from syngas and offers great energy efficiency and robust operation, achieving the minimum targeted process gas CO2 capture rate of up to 99.97 mass%. The treated syngas can be further separated into H2 and CO to be used as a key raw material for various products. OASE white technology has been successfully applied in many world scale ammonia plants, syngas plants for petrochemicals, and others such as steel production (see Figure 1).

    Moving forward, the use of pure hydrogen (H2) can support cleaner fuel for vehicles, whereas the high purity CO2 captured by OASE white can support direct carbon capture and utilisation (CCU) to manufacture chemical products on a commercial scale. CCS is also possible.

    For flue gas carbon capture, OASE blue technology was developed specifically as an optimised post-combustion capture technology with low energy consumption, low solvent losses, and a highly flexible operating range.

    A core task for the design of carbon capture technology is to reduce solvent loss by reason of economic efficiency and environmental friendliness. The development programme of BASF with OASE blue for flue gas CO2 emissions capture and OASE white for process gas CO2 emissions capture is demonstrating that, by combining two effective technologies, the target of lowest CO2 footprint overall is possible.

    Apr-2021

  • Clément Salais, Axens, clement.salais@axens.net

    In a typical steam methane reforming (SMR) unit designed to produce high purity hydrogen, methane reacts with steam in a dedicated heater to produce a converted syngas which, after CO shift, contains mainly hydrogen and CO2. The syngas is then purified through a PSA to produce hydrogen at 99.9% purity and a purge gas that contains CO2, CO, and some hydrogen. This purge gas is routed back as a fuel to the SMR furnace. The SMR furnace produces a flue gas containing all of the CO2 emitted by the SMR unit.

    There are two main locations at which CO2 can be captured: either the converted syngas identified as location A or the flue gas identified as location B in Figure 1. CO2 absorption from syngas is much more favourable as it is at high pressure and there is consequently a large driving force to absorb CO2. The syngas is quite pure and does not contain any oxygen but it contains only part of the CO2 emitted by the SMR unit (up to 60% depending on the scheme and operating conditions).

    Adversely, the flue gas contains all of the CO2 emitted by the SMR and up to 90% of the CO2 emitted can be absorbed there. But the flue gas conditions are harsh: low pressure, high temperature, and a few per cent O2 in the gas.

    In terms of technology, a typical amine based acid gas removal unit with activated MDEA can be used to absorb all of the CO2 in syngas (up to 99%). Steam energy consumption can be reduced to about 1 GJ/t of CO2 with an optimised process scheme which avoids about 57% of the CO2 emissions of the SMR unit. The avoided CO2 readily takes into consideration emissions of CO2 due to energy consumption in the carbon capture unit. This gives a better insight into the amount of CO2 that is effectively recovered in the overall process.

    CO2 emissions of a SMR unit can be significantly reduced by installing mature technology such as Advamine EnergizedMDEA technology which is licensed by Axens for syngas.

    On the other hand, solvent based post-combustion carbon capture processes that are required to capture the CO2 in flue gas are much more energy demanding. The steam energy consumption of a first generation carbon capture process such as a MEA solvent based process is up to 3.7 GJ/t of CO2. The amount of CO2 avoided is, as a consequence, only 67% considering the additional CO2 emitted to regenerate the solvent. Post-combustion carbon capture from flue gas enables further reduction of CO2 emissions from the SMR unit but requires the development of new solvents and new processes to be more energy effective.

    Axens is currently developing, with IFP Energies  nouvelles, a new process for post-combustion carbon capture called the DMX process that is much less energy intensive than first generation processes. It is a solvent based technology but with a new solvent that has specific demixing capabilities under certain conditions of pressure and temperature. The energy consumption of the DMX process can be reduced to 2.3-2.9 GJ/t CO2 compared to the 3.7 GJ/t CO2 of the MEA process, leading to further reduction of CO2 emissions from the SMR unit as the CO2 avoided increases to 72% (see Table 1).

    Its performance is proven at laboratory scale but needs to be demonstrated industrially in order to be ready for commercialisation. This demonstration is in progress through the 3D Project funded by the European Union (H2020 - Grant Agreement N°838031). It includes the construction of a demonstration unit at the ArcelorMittal Steel Mill in Dunkirk, France which is already in progress. Operation of the unit will begin in early 2022.

    Apr-2021



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