We want to reduce the refinery’s carbon footprint, starting with SMR. What’s the best economic approach: CCUS, an alternative process, or buy in the hydrogen?Nov-2021
Vinod Vaishnav, Luberef, email@example.com
Just to correct my previous submitted answer its not DMEA solution, it is K2CO3. In Ammonia plant it is termed as GV solution. Giamaarco Vetrocoke.
Vinod Vaishnav, Luberef, firstname.lastname@example.org
How about considering an Ammonia plant set up, after PSA inlet knock out drum provide Amine section using DMEA to absorb all the CO2, only CO & CO2 will be in ppm at PSA inlet ultimately it will reduce CO2 by 90%. But it can be costly one time investment, also the removed CO2 storage & use is a challenge.
Marcelo Tagliabue, Air Liquide, email@example.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 CRYOCAP 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. CRYOCAP H2 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%.
Doug Morgan, Searles Valley Minerals, firstname.lastname@example.org
You might consider cryogenically recovering some CO, like Du Pont Syngas in laPorte used to do, and using it to perform carbonylations. The products you can make without consuming any of your hydrogen include acetic acid (DuPont Syngas), vinyl acetate (DuPont Suyngas), acetic anhydride, dimethyl carbonate, dimetyl oxalate, propionic acid, ibuprofen, methyl proionate, polyethyleneketone, glycolic acid, and pivalic acid. See Carbonylation on wikipedia.
Barry Dallum, Alternative Petroleum Technology, email@example.com
Besides the great answers given in the other responses, there are 2 low capital cost, high return processes to reduce the carbon footprint of SMR.
The first decreases hydrogen demand by replacing hydrotreating with oxitreating. Oxitreating removes sulfur from intermediate and finished product streams by the use of hydrogen peroxide with in-process constant recycle of the low cost liquid catalyst. This process operates at temperatures below 100 C and pressures around 1 atmosphere. The reaction does not generate any carbon dioxide, Because some or all of the hydrotreating is eliminated it reduces CO2 generation and further need for that carbon capture. The resultant products are the ultra-low sulfur hydrocarbon blend, and a relatively inert chemical species referred to as sulfones and water in place of hydrogen sulfide. Thus overall safety is improved besides lower operating cost. Alternative Petroleum Technology offers this process under the name SULFEX. You will still need some hydrogen for other unit operations.
The second extends the use of fuel and residual oils used to fire the boilers, furnances and heaters used in SMR. This is done by the use of emulsifiers and water. The fuels consumption is decreased by up to 30% thus reducing the carbon footprint while maintaining the same caloric output of the fuels. This process also significantly reduces nitrogen oxides, a GHG precursor, and particulates - soot. APT offers this process under the name EcoMix.
Eric Vetters, ProCorr Consulting Services, firstname.lastname@example.org
Most carbon footprint calculations require including the CO2 produced to make and transport the feedstock to the refinery. Buying hydrogen in lieu of producing it at the refinery will not be a benefit unless the purchased hydrogen source has a smaller carbon footprint than the refinery’s SMR.
Using an alternative process such as green hydrogen produced by electrolysis using renewable power would substantially reduce the carbon footprint linked to hydrogen, but may not be economic unless there are either significant subsidies or a high carbon tax. Producing incremental hydrogen in the catalytic reformer by running more feed, reducing pressure, and/or increasing octane may incrementally reduce the carbon footprint from hydrogen. Depending on how the CO2 produced is apportioned between products, purchasing hydrogen from a steam cracker operation could also reduce the carbon footprint.
The amine based systems most commonly employed for CCUS are currently limited by high capital cost and high energy required to dispose of the CO2 captured. Emerging technologies that can sequester the carbon as something like limestone may prove to be a more effective CCUS approach than the current technologies.
Beth Carter, Honeywell UOP, Beth.Carter@Honeywell.com
The steam methane reformer (SMR) is often the largest single source of CO2 emissions in a refinery. Fortunately, approximately 60% of the CO2 produced during hydrogen production is available in a contaminant-free stream with a high partial pressure of CO2, which makes the cost of carbon capture often the lowest among all the available streams in a refinery. Being both the largest source and the source with the lowest cost of carbon capture, the SMR is a prime unit to evaluate for reducing a refinery’s carbon footprint.
Several technologies are commercially available for retrofitting an existing SMR with carbon capture, including solvent processes, pressure swing adsorption (PSA) systems, membrane systems, and cryogenic processes. Optimised combinations of these technologies can significantly reduce the cost of carbon capture. The choice of carbon capture technology depends on the value of extra H2 recovery and ultra-high CO2 recovery; the required product specifications for H2 and CO2; and the availability, cost, and carbon intensity of power versus steam. Honeywell UOP’s CO2 Fractionation System for carbon capture from an SMR provides 10-20% extra H2 yield and 99+% CO2 recovery from the existing PSA tail gas in a completely power-driven process (no steam required), with a smaller required footprint compared to a solvent carbon capture system. The cost of carbon capture can typically be $20-40/t CO2, which includes operating costs, fixed costs, and annualised capital costs for the carbon capture equipment plus a credit for the additional hydrogen recovered. Financial incentives in the form of carbon tax or carbon credits exist today in many parts of the world at values higher than this, making SMR retrofit not only a technically viable option, but also a commercially viable option for starting the CO2 countdown.
Ken Chlapik, Johnson Matthey USA, email@example.com
Reducing the carbon footprint of an existing steam methane reforming (SMR) hydrogen production plant comes at a cost. There are several areas that need to be considered including:
• Carbon legislation/cost of carbon
• Carbon intensity of the hydrogen production technology
• Commercial readiness of hydrogen production and CO2 capture technology
• CO2 storage availability
While net zero targets are being set by countries and companies, the means to reach these targets is still forming. Some regions of the world are setting legislation and taxing carbon emissions which will establish a cost of carbon for the location site affecting the economics of the carbon footprint reduction. The source of carbon emissions both direct and indirect is also being addressed which impacts merchant hydrogen production as well as on site production. With merchant hydrogen, the end user loses some control over being able to remove CO2 emissions which could leave the end user liable to greater tax or indirectly paying for merchant’s CO2 emissions tax through higher hydrogen prices. The end user also loses any potential benefits/credits that could be gained by sequestering on site emissions.
Advanced reforming such as a gas heated reformer (GHR) and/or an autothermal reformer (ATR) remove the post combustion carbon emission of an SMR substantially reducing the carbon intensity of hydrogen production. They can be used to augment or replace the existing SMR. These advanced reforming technologies have been designed and operated at syngas production levels greater than existing world scale SMR hydrogen production plants, making them ready for this application. While the post-combustion carbon emissions are eliminated with advanced reforming there is still process side CO2 that needs to be captured. As discussed in the recent PTQ Q3 Q&A question What options are there for CO2 capture from a SMR based hydrogen unit?, this pre-combustion (process side) CO2 is more readily removed being at pressure and simpler in composition, with fewer contaminants and impurities using established CO2 capture technology. The CO2 captured needs a place to be stored as part of the carbon footprint reduction of the existing SMR hydrogen plant. The availability of CO2 storage to the refinery site would need to be reviewed and understood.
The above quickly reviews an approach for reducing the carbon footprint, but each facility has to be reviewed on a case-by-case basis against the short, near, and long term decarbonisation strategies. Johnson Matthey’s customers are navigating this question for their petrochemical syngas production facilities. Our Low Carbon Solutions business is conducting these types of techno economic decarbonisation studies addressing these areas as well as other areas such as company internal near term, intermediate, and long term decarbonisation targets, future hydrogen demand, site availability, and replacement of SMR hydrogen production with grass roots blue and green hydrogen capacity.
Tom Ventham, firstname.lastname@example.org, Unicat Catalyst Technologies
Improving hydrogen production is a hot topic. New peer-reviewed research helps inform refiners on categories of hydrogen technology that in fact worsen carbon footprint rather than improve it.1 The very first consideration when evaluating any environmental project is the straightforward maxim: reuse > recycle > replace. This is particularly true when it comes to large scale refinery projects. As well as generating a significant carbon debt when fabricating materials of construction (i.e. large amounts of steel and concrete) along with other carbon costs of transport, construction, and commissioning of new plant, it is well known that large scale projects take many years to implement from design stage to full operation. The window of opportunity for the world to act on carbon emissions is closing. The time to complete complex projects clearly impacts the ultimate claimed benefit of the final equipment. A better approach is to make improvements today that can be realised by hydrogen producers immediately to provide CO2 savings. Although economics arguably should not be a factor in these discussions, the question asks this and the solution we propose, which focuses on reusing existing SMR equipment, is also the most economic. Magma and Unicat have developed an advanced SMR catalyst technology that is a direct drop-in, pellet-type replacement, of the current reformer catalyst system with no changes required to loading, start-up, upset operation, normal operation, or unloading procedures. This MagCat technology reimagines SMR catalyst manufacture to deliver an optimised shape and size coupled with enhanced strength and anti-coking properties. Using MagCat in any design of SMR or primary reformer unit improves the efficiency of hydrogen production, meaning less energy input is required to produce a constant amount of hydrogen. This improvement directly translates to a reduction in CO2 emissions that can be imagined in several ways. In addition, if the desire is produce more hydrogen to support a burgeoning hydrogen economy or satisfy environmental goals of the refinery, be that processing of hydrogen-intensive biofuels or to meet higher fuel standards, MagCat provides that option by boosting hydrogen production far beyond nameplate capacity. It is this opportunity to improve the carbon footprint of your SMR unit today that should be taken seriously by all refiners who are truly committed to these goals.
1 R W Howarth, M Z Jacobson, How green is blue hydrogen?, Energy, Science & Engineering, Aug 2021. https://onlinelibrary.wiley.com/doi/full/10.1002/ese3.956
David Kelling, Haldor Topsoe Inc, email@example.com
Rather than focusing on the SMR carbon footprint, perhaps is would be better to focus on the entire refinery footprint by adding a blue hydrogen plant with over 97% carbon recovery and using the Product H2 as fuel in all of the refinery heaters. This of course requires having the ability to sequester the CO2 from the H2 plant. Topsoe Autothermal Reforming Technology (SynCor) is an industry leading technology for making Blue H2 with the lowest capex and opex for capacities in a single line up to 450 MMSCFD. Our SynCor Blue H2 plant design is able to remove 97% of the CO2 in a single amine unit in the process, which is much more economical from both an opex and capex point of view than CO2 recovery from the flue gas (post combustion).
As far as the SMR is concerned, pre-combustion CO2 removal can as mentioned be done on the process side or post-combustion removal can be added on the flue gas. These types of revamps are not particularly complicated and can significantly reduce the CO2 footprint of an existing H2 plant.
Romain Roux, Axens, Romain.Roux@Axens.com
Starting with SMR in the refinery, you will have three steps for decarbonisation:
1. Carbon capture on the SMR synthetic gas itself: amines can provide a reduction in the SMR unit’s CO2 emissions by more than 50%. Axens is proposing its Advamine technology. With more than 200 references, Advamine has recently been applied to green hydrogen production on syngas as well, but from Biogenic feedstock.
2. Retrofitting the existing SMR in order to reduce CO2 emissions: a simple revamping of the furnaces will typically provide a reduction of more than 10% of the SMR unit’s carbon intensity.
3. Carbon capture on the flue gas: Axens is currently developing a dedicated solvent based carbon capture technology – DMX – aimed at capturing CO2 at low pressures in industrial flue gases with low CO2 content. DMX will be fully demonstrated in 2022 on a steel manufacturing site. Axens is already proposing studies in order to evaluate the impact of DMX installations on decarbonisation projects.
The alternative would be to buy hydrogen (green or blue) to reduce CO2 emissions, or to develop an in-house green hydrogen project.
Blue hydrogen in general is sensitive to the effect of scale. Therefore, blue hydrogen will be economical only if the SMR unit is large, not too far from the site of consumption and when CO2 exports or valorisation are economical.
For green hydrogen, or more specifically hydrogen from electrolysis, many refineries are developing moderate-scale (tens of MW) electrolyser projects at their sites, but many projects are also based on production by a third party selling hydrogen. As this is a new market, the preferred business model as to whether to produce or buy green hydrogen has not yet been defined.