Gas 2023 Issue

gas 2023

OPTIMISING HYDROGEN YIELDS

ENHANCING COMPRESSOR PERFORMANCE NATURAL GAS TO AMMONIA

LNG’S TRANSITIONAL ROLE

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5 Using model-based solutions to increase LNG Rene Gonzalez

6 Hydrogen Roundtable 2023

9 Monetisation gas resources through LNG, hydrogen, and ammonia Capturing profitability in the downstream hydrocarbon processing industry’s transition to net zero emissions weights heavily on leveraging natural gas resources Rene Gonzalez 13 COS and mercaptans removal from gases Challenges with removing trace sulphur species can be better understood and resolved with a new kinetic model validated by plant data in its ability to predict COS removal Prashanth Chandran, Harnoor Kaur, Jeffrey Weinfeld and Ralph Weiland Optimized Gas Treating, Inc. 21 Future of LNG demand in Japan As oil, coal, and other energy sources decline in the energy transition to net zero, LNG demand will remain strong in the long transition to renewables Jeremy Goh Baker and O’Brien Inc. 25 Methanol from CO 2 : a technology and outlook overview Optimal capture of CO2 towards methanol production compels development of sustainable renewable solutions like green methanol Pattabhi Raman Narayanan Becht 31 Digitally enhanced reciprocating compressor performance With instant access to compressor data, improved productivity, and expert support, digital technologies are revolutionising maintenance processes James Litchfield and Philipp Wolschner Burckhardt Compression

Cover Taking a closer look at heat transfer and filtration systems in gas plants in meeting net zero specifications is necessary to meet challenges with controlling a wider range of contaminants.

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Editor Rene Gonzalez editor@petroleumtechnology.com tel: +1 713 449 5817 Managing Editor Rachel Storry rachel.storry@emap.com Graphics Peter Harper US Operations Mark Peters mark.peters@emap.com tel: +1 832 656 5341 Business Development Director Paul Mason sales@petroleumtechnology.com tel: +44 7841 699431 Managing Director Richard Watts richard.watts@emap.com Circulation Fran Havard circulation@petroleumtechnology.com ptq PETROLEUM TECHNOLOGY QUARTERLY

Using model- based solutions to increase LNG

T he market size of industrial gases is expected to surpass $147 billion by 2028. Along with this increase in the global markets for gas is the level of gas processing complexity needed by 2035, which seems to vary regionally. Much of the technical developments are emerging with liquefaction-related processes, which are discussed in more detail in this annual issue of PTQ Gas 2023 . Overall, complexity depends on several factors, such as the growth in demand for natural gas, availability of gas reserves, and technological advancements in gas processing. For at least the next 50 years, natural gas-derived products will likely be a major component of the energy mix on the road to decarbonised energy products, such as renewable fuels and solar power. This growth in demand may require more complex gas processing facilities to ensure that the gas is purified to the required quality standards in the rapid push to net-zero emissions-based products. Another factor that may drive the complexity of gas processing is the availability of gas reserves. As easily accessible reserves are depleted, companies may need to extract gas from more challenging reservoirs, such as deepwater or shale gas formations. These types of reservoirs require more advanced processing technologies to extract and refine the gas. For example, advancements in carbon capture and stor - age (CCS) technologies may require additional processing steps to capture and sequester carbon dioxide (CO 2 ) from natural gas. With more gas production coming from relatively small-scale fields, low-capital, temporary in-the-field gas processing facilities have become increasingly popular in recent years to maximise the moneti- sation of fields of all sizes, including 98% recovery of flared or vented gas. Against this backdrop, one of the most capital-intensive components in the gas industry is the liquefaction section of liquefied natural gas (LNG) plants, used to convert natural gas into LNG for transport and storage. Increasing throughput from existing liquefaction trains is a high priority for LNG producers, as it helps improve efficiency, reduce costs, and increase profits. Model-based solutions offer a prom - ising approach for achieving additional throughput from existing liquefaction trains. Some examples include advanced process control (APC) systems using math- ematical models and algorithms to optimise process operations and increase throughput. APC improves control of key process variables, such as temperature, pressure, and flow rate, which can improve the efficiency and capacity of existing liquefaction trains. APC can also help reduce process variability, especially around turbocompressors, which can improve product quality and reduce downtime. Data analytics tools can be used to analyse large amounts of data from the lique- faction process, such as sensor readings, process parameters, and operating con- ditions. By identifying patterns and trends in the data, operators can gain insights into the performance of the liquefaction process and identify opportunities for opti- misation of the capital-intensive rotating equipment. Model predictive control (MPC), a type of advanced process control that uses mathematical models to predict the behaviour of the process under different condi- tions to optimise process operations in real-time, leads to increased throughput and improved efficiency. MPC can also help optimise energy use and other resources, which can reduce operating costs. In summary, model-based solutions offer a powerful set of tools for increasing throughput from existing liquefaction trains. Using mathematical models and data analytics to optimise process operations, operators can improve efficiency, reduce costs, and increase profits in the LNG industry.

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PTQ (Petroleum Technology Quarterly) (ISSN No: 1632-363X, USPS No: 014-781) is published quarterly plus annual Catalysis edition by EMAP and is distributed in the US by SP/Asendia, 17B South Middlesex Avenue, Monroe NJ 08831. Periodicals postage paid at New Brunswick, NJ. Postmaster: send address changes to PTQ (Petroleum Technology Quarterly), 17B South Middlesex Avenue, Monroe NJ 08831. Back numbers available from the Publisherat $30 per copy inc postage.

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Gas 2023

Hydrogen Roundtable 2023

W ith the increase in hydrogen demand for refinery hydroprocessing operations, ammonia production, and as a future fuel for the transportation industry, industry experts were asked to weigh in on the most attrac- tive options for hydrogen production. Worldwide interest in green hydrogen is an important segment of many industry forums on hydrogen. However, its commercial production is still insignificant. For now, the focus is to continue improving the main source of hydrogen production. That is, from steam methane reforming (SMR) and the technology needed to significantly reduce CO 2 emissions from SMR furnaces. PTQ asked industry hydrogen experts: what are the most attractive long-term options for incorporating autothermal reforming (ATR) and/or partial oxidation (POX) to produce blue hydrogen at near-zero CO 2 emissions? Or can CO 2 emissions from SMR units be further reduced? Scott Miller, Principal Engineer, Gas Processing, Honeywell UOP/Ortloff Engineers, scott.a.miller@honeywell.com Current SMR units can reduce CO 2 emissions from on-site hydrogen production by approximately 60% through the addition of pre-combustion carbon capture to an existing SMR unit and by over 90% by adding post-combustion car- bon capture to an existing unit, which significantly reduces the process Scope 1 emissions. When designing a new unit and leveraging ATR or POX technology with carbon capture to produce hydrogen, over 98% of the CO 2 emissions from the process can be cap- tured. These technologies are, therefore, very attractive when minimising Scope 1 emissions is critical, which will be driven by policies focused on reducing the carbon intensity of hydrogen production. ATR and POX also typically benefit from economies of scale, making them the most economical way to produce lower-carbon hydrogen in large quantities as demand for hydrogen grows. Ken Chlapik, Global Market Manager, and Dominic Winch, Market Analyst, Low Carbon Solutions, Johnson Matthey, Ken.Chlapik@matthey.com and Dominic.Winch@mat- they.com The answer to this question depends on the end user’s pace, amount of Scope 1 and 2 CO 2 emissions to be addressed, capital applied, risk appetite, and CCS avail- ability of their facility. Established technologies are ready now to produce low carbon intensity syngas production on existing syngas plants as well as new grassroots produc- tion. Johnson Matthey (JM) has a portfolio of technologies that can provide low carbon intensity syngas production to different levels of quality and scale, as well as utilising CO 2- laden streams and captured CO 2 to produce chemical intermediates and other value-added fuels and products. With many operators, there is a desire to increase produc- tion along with reducing CO 2 emissions. JM’s proprietary

CleanPace solutions focus on existing SMR units. By apply- ing established JM Advanced Reforming technologies such as ATR and gas heated reforming (GHR), we can provide reductions in CO 2 emissions and create increased produc- tion in a low carbon intensity retrofit that applies estab - lished precombustion carbon capture technologies, which enable high levels (>95% removal). Over 0.5 million t/y of CO 2 emissions can be captured on typical large-scale hydrogen plants with a reduced site footprint to post-com- bustion technology solutions. The SMR-based hydrogen plant is the largest point source of CO 2 emissions on the downstream refinery, but there are a few other sources as well, in particular fired heaters. Some operators are looking beyond the SMR to address a larger portion of their CO 2 emissions by replacing existing fossil-based fuels with hydrogen. This is a much more sub- stantial CO 2 emission project requiring more capital and a new grassroots low-carbon hydrogen plant with CCS. This will be a much larger hydrogen plant than what exists for hydroprocessing of clean fuels within the refin - ery. JM’s LCH technology, which also utilises JM’s Advanced Reforming, provides a magnitude lower carbon intensity and less energy to produce this hydrogen fuel application. An example of this is the HyNET project in the UK, which, at a demo level of hydrogen energy production, is a world- scale-sized hydrogen plant in today’s market. The LCH plant is the source of the process hydrogen and hydrogen fuel in one of the largest hydrogen hubs being funded in the globe that includes a refinery, steel, and ammonia produc - tion facility to utilise the hydrogen. Future phases of this project will be at a hydrogen production scale of three times the current world scale. Other operators are focusing on monetising CO 2 -laden streams that exist within the refinery or near the facility to provide value-added chemical intermediates and fuels within and outside the refinery. JM’s low carbon inten - sity technologies, such as Precision Methanol technology, which utilises JM’s Advanced Reforming ATR technology and HyCOgen reverse water gas shift technology, can convert these streams to chemical intermediates and fuels such as SAF. All these technologies and applications can provide attractive solutions to reducing a facility’s Scope 1 and 2 CO 2 emissions. Andrew Layton, Principal Consultant, KBC, andew.lay- ton@kbc.global CO 2 emissions from SMRs can be reduced by maximising design efficiency. Compared to units from the 1980s, mod - ern units are typically at least 10% more efficient because they use a PSA to purify hydrogen instead of CO 2 scrub- bing. In addition, enhancing the design and, to a lesser extent, the catalysts has also improved SMR efficiency. While the efficiency of an existing SMR can be improved to

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a limited extent, older and less efficient units are replaced rather than upgraded. Reconfiguring or upgrading the SMR furnace is very expensive because the steam generation, process, and flue gas heat recovery system are integrated. Furthermore, it is often necessary to generate more hydro - gen and, therefore, build a larger unit. New SMR units tend to be designed to export less steam or even no steam at all. This leads to substantial reductions of CO 2 emissions in the SMR, at least part of which is likely to be offset by steam generation elsewhere unless green electricity can generate steam. With pre-combustion carbon capture, at least 30% of the CO 2 generated will still be released. An SMR equipped with pre-combustion capture will still emit the CO2 from the fuel fired. Furthermore, the carbon in the feed that is not con - verted to CO2 in the reaction section but downstream in the PSA will not be captured. It will still leave the unit as CO2 from the furnace stack. Thus, higher capture rates require post-combustion capture, which is more expensive in terms of capital expenditures and operating costs. Finally, ATR and POX do not use separate furnace firing as SMRs do. Therefore, pre-combustion capture allows a larger percentage of CO2 to be captured. As a result, ATR/ POX units may be preferred over greenfield SMRs for pro - ducing blue hydrogen on a large scale.

Nitesh Bansal, Proposal Segment Manager, Topsoe, niba@topsoe.com There are multiple advantages of using ATR technology for blue hydrogen production: • High carbon capture is possible using ATR. Topsoe SynCOR (advanced ATR) can achieve up to 99% carbon capture using only process gas carbon capture • ATR technology can provide the scale of operation, which is the key feature for blue hydrogen production. Topsoe SynCOR (advanced ATR) can reach up to 800,000 Nm3/h hydrogen capacity in a single train • Overall levelised cost of hydrogen production (LCOH) is lower in ATR compared to SMR due to the scale-up Capex as well as lower Opex and higher carbon capture credits. This begs the question: can CO2 emissions from SMR units be further reduced? CO 2 emissions from SMR units can be reduced by 60-65% by installing process gas carbon capture. If there is a requirement to further reduce carbon capture by >90%, there are multiple options: • H 2 firing in the reformer. This will increase the overall plant size by 30% • Installing flue gas carbon capture. This is expensive from both a Capex and Opex point of view.

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Monetisation gas resources through LNG, hydrogen, and ammonia Capturing profitability in the downstream hydrocarbon processing industry’s transition to net zero emissions weights heavily on leveraging natural gas resources

Rene Gonzalez Editor, PTQ

LNG opportunities The global LNG market is expected to reach US$66.13 billion by 2027, at a CAGR of 6.92% during 2022-2027. Most capacity comes from mega-LNG facilities, while cer- tain niche margin opportunities comes from small-scale liquefied natural gas (ssLNG) operations. Overall, LNG mar - kets beyond 2023 are expected to grow and evolve as the industry matures and new technologies and applications emerge, with Qatar, Australia, and the US becoming the largest natural gas producers. Industry forecasts expect LNG demand to reach 650 to over 700 million tonnes a year by 2040. More investment in liquefaction projects is required to avoid a supply-demand gap expected to emerge by the late 2020s. Diverse new technologies to reduce emissions from gas and LNG supply chains will help consolidate its role in the energy transition. There is a growing industry focus on the development and deployment of decarbonised gases, including renewable natural gas, hydrogen, and ammonia, to deliver more sus - tainable energy security in the future. Due to well-acknowledged reasons ranging from low cost and emissions reductions, LNG from natural gas resources is rapidly taking a larger percentage of the energy mix options. For example, the IMO 2020 bunkering market (less than 0.5 wt% sulphur) has generated worldwide interest in supplying this market with LNG’s near-zero sulphur content, preferably from facilities strategically positioned to serve LNG-powered container ship bunkering operations. In remote areas, island nations, and regions where intense mining operations are occurring to supply precious metals for the electric vehicle market, small-scale facilities linked to microgrids are preferred as they require much less time for construction than mega-LNG facilities. Besides, the mega- LNG owners could be more exposed to price sensitivity with regard to long-term contracts and other tolling agreements. LNG technology enablers These bespoke developments are enabled by technological improvements at every stage across the natural gas value chain. Take, for example, one of the world’s largest oil and gas companies and a major player in the LNG industry. Shell has been exploring the potential of artificial intelligence (AI) to improve the efficiency and safety of its operations, includ - ing applications at its existing LNG plants.

One example of Shell using AI in its LNG operations is its partnership with technology firm C3.ai. Together, the companies have developed an AI-based predictive main - tenance system for Shell’s Prelude floating liquefied nat - ural gas (FLNG) facility, located off the coast of Western Australia. The system uses AI algorithms to analyse data from thousands of sensors throughout the facility, detecting anomalies or potential issues before they can cause serious problems. By proactively identifying and addressing main - tenance needs, the system can help to reduce downtime and improve the overall efficiency of the facility. LNG projects require complex technologies (see Figure 1 ) and related infrastructure against a moving target of constantly changing regulations. According to a report by Wood Mackenzie developed during the onset of the global pandemic in 2020, the new bar for future LNG proj- ects is around $4/MMBtu, or even lower. The report also Figure 1 World-scale LNG facilities benefit from highly automated MCHE systems to optimise compressor operations for each LNG plant’s liquefaction train Photo courtesy of Burckhardt Compression AG

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mentioned that the cost of new LNG projects had fallen due to technological advances and supplier competition. In another report by Rystad Energy in 2021, it was men- tioned that the cost of LNG projects had fallen to around $450 per ton of LNG produced, equivalent to $4.04/MMBtu based on an assumed energy content of 22.6 MJ/kg. The report stated that the cost reduction was due to the adop- tion of standardised designs, the use of modular construc- tion techniques, such as with the new ssLNG plants serving the Caribbean Basin’s maritime shipping industry, remote mining operations in northern Canada and Africa, and the application of digitalisation and automation technologies. Therefore, based on these industry reports, it can be assumed that the new bar for future LNG projects is around $4/MMBtu, or even lower. A recent PwC study noted that by 2030, if the price of LNG costs between $3 and $4 per mmBtu with oil above $90 a barrel, LNG demand will increase more than four times what it would be if LNG cost more than $9 per MMBtu, with oil between $50 and $60 a barrel. To better monetise these differentials, competitive LNG producers are well into the development of fuelling solutions of all scales and scope. For example, new crude supply tankers, cruise ships, and passenger ferries are being built to run on LNG instead of low-sulphur fuel oil. Ammonia Fertiliser production is already in short supply, leading to impending global food shortages. With the world’s popula- tion expected to reach 9 billion people by 2050, the problem is not going away soon. Natural gas is a common feedstock for the production of ammonia, which is primarily used in the production of fertilisers. Traditionally the process of produc- ing ammonia from natural gas involves three main steps: • Steam methane reforming (SMR) : The conversion of natu- ral gas into a mixture of hydrogen and carbon monoxide (CO) using steam and a catalyst carried out at high temperatures and pressures and further discussed in PTQ Gas 2023 • Gas shift reaction : In this second step, the mixture of hydrogen and CO is treated with steam and a catalyst to undergo the gas shift reaction. This reaction converts the CO into CO 2 and additional hydrogen • Haber-Bosch process : The final step involves the synthe - sis of ammonia from hydrogen and nitrogen, produced by air separation units. This process occurs at high temperatures and pressures in the presence of an iron catalyst. Benefits The process of producing ammonia from natural gas can be made highly energy-efficient, as it involves the use of waste heat and the recovery of excess energy. Throughout the global market, natural gas is widely available, and there are established infrastructure and distribution networks that make it easy to transport and use as a feedstock. The ammo- nia produced using natural gas as a feedstock is of high purity and quality, making it ideal for use in the production of fertilisers. Nevertheless there are challenges: • CO 2 impact: The production of ammonia from natural gas plants generates significant greenhouse gas emissions, which contribute to climate change

• Safety considerations : The Haber-Bosch process is car- ried out at high temperatures and pressures and can pose safety risks if not properly managed • Market volatility : The cost of natural gas can be volatile, impacting the cost-effectiveness of ammonia production. Alternatives As the world continues to seek sustainable solutions to meet the growing demand for fertilisers and other ammonia-based products, the industry will need to address these bespoke challenges and find ways to improve the sustainability of ammonia production from natural gas plants. Utilising refin - ery byproducts could serve as a supplement or alternative to ammonia production from natural gas. Refineries produce a variety of byproducts, such as the hydrogen and nitrogen used as inputs for the ammonia production process. By producing ammonia as a co-product, refineries can cre - ate additional revenue streams from these byproducts to fur- ther mitigate risks associated with fluctuations in oil prices and demand, with the following benefits and challenges: • Lower carbon footprint : Producing ammonia by the Haber-Bosch process using natural gas is energy-intensive and produces a significant amount of CO2 . However, pro- ducing ammonia from refinery byproducts can have a lower carbon footprint, as it utilises existing infrastructure and can potentially reduce emissions • Capital investment : Producing ammonia requires sig- nificant capital investment in equipment and infrastructure, which can be a barrier for some refineries. Additionally, the cost of retrofitting existing refineries to produce ammonia can be high • Safety considerations : Ammonia is a hazardous gas that requires specialised handling and storage. Refineries must ensure they have the appropriate safety protocols in place to mitigate the risk of accidents • Competition from traditional producers : Traditional ammonia producers, such as chemical companies and fer- tiliser manufacturers, may have a competitive advantage over refineries with their experience and expertise in pro - ducing ammonia. While the production of ammonia by petroleum refineries is a relatively new concept, some refineries have already begun producing ammonia as a co-product. US-based Phillips 66 recently started producing ammonia as a co-product at its Ponca City, Oklahoma, refinery. Chevron Phillips Chemical operates a petroleum refinery in Borger, Texas, that produces about 1,000 tons per day of ammonia. The refinery uses a proprietary process called Aromax to produce high-purity benzene, which is then used as a feedstock for the ammonia production process. This method of producing ammonia allows Chevron Phillips to use a waste stream from the refinery as a feedstock, reduc - ing waste and creating an additional revenue stream. Flint Hills Resources operates a petroleum refinery in Rosemount, Minnesota, that produces about 1,000 tons per day of ammonia. The refinery uses a process called Kellogg Ammonia Technology (KAT), which utilises natural gas as a feedstock. The KAT process is energy-efficient and pro - duces high-purity ammonia, sold primarily to the agricultural

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sector. Brazilian state-owned oil company Petrobras oper- ates a petroleum refinery in Rio Grande do Sul, Brazil, that produces about 1,500 tons per day of ammonia using the KAT process. As the demand for ammonia-based prod - ucts continues to increase, more refineries may explore the opportunities and benefits of producing ammonia. Hydrogen Despite the interest in blue hydrogen production from auto - thermal reforming and partial oxidation (ATR/PO) to produce blue hydrogen, steam methane reforming (SMR) is still the primary method of producing hydrogen (i.e., grey hydrogen) for refinery operations. However, the reaction is not always efficient, and several factors can affect the yield of hydrogen. However, increasing the yield of hydrogen from SMR units may be achievable with the following strategies: • Increasing the steam-to-carbon ratio (S/C) : The S/C ratio is the amount of steam required to react with one unit of car - bon in the methane. Increasing the S/C ratio can increase the yield of hydrogen by shifting the equilibrium towards hydro - gen production. However, the S/C ratio cannot be increased beyond a certain point, as it can lead to carbon deposition on the catalyst, reducing its effectiveness • Catalyst selection : The choice of catalyst used in SMR reactors can significantly affect hydrogen yields. Nickel- based catalysts are commonly used in SMRs. However, other catalysts, such as ruthenium and iridium, have shown higher hydrogen yields. The catalyst’s activity and selectivity depend on its structure, composition, and preparation method. One of the main advantages of using ruthenium and iridium catalysts in SMR is that they are highly selective, meaning they promote the desired reaction while minimising unwanted byproducts. Additionally, these catalysts have a long lifespan and can be used repeatedly, making them cost- effective and efficient catalysts for SMR processes. SMR challenges However, some challenges are associated with using ruthe - nium and iridium catalysts in SMR. These metals are expen - sive, about $6,250 per kg for iridium and about $16,500 for ruthenium. They are mainly found in the Norilsk region of Russia and, to a lesser extent, in South Africa, Zimbabwe, and Canada, which can increase the overall cost of the SMR process. Iridium may be somewhat more accessible. The largest iridium reserves are located in the Bushveld Igneous Complex in South Africa. Other countries with sig - nificant reserves include Russia, Canada, and the US state of Montana’s Stillwater Complex. Additionally, they can be sensitive to impurities and con - taminants in the reactant gas stream, which can degrade their performance and reduce their lifespan. Despite these chal - lenges, the use of ruthenium and iridium catalysts in SMR is a promising approach to increasing hydrogen yields in refinery processes. Ongoing research is focused on improving cata - lytic efficiency and reducing the cost of these catalysts to make them more widely accessible for industrial uses. Temperature and pressure are critical parameters that affect the SMR reaction’s equilibrium position. Increasing the reaction temperature and pressure can increase the yield

of hydrogen. However, these conditions can also promote undesirable side reactions, such as carbon deposition and methanation. Therefore, optimal temperature and pressure conditions must be carefully selected to maximise hydrogen production while minimising the formation of byproducts. Along with hydrogen and CO, the SMR reaction produces CO2, which is why there is so much interest in producing blue and green hydrogen, albeit still at insignificant levels (for green hydrogen), to benefit commercial refinery opera - tions. Removing CO2 from the reaction mixture can shift the equilibrium towards hydrogen production. Several methods, such as absorption, adsorption, and membrane separation, can be used to remove CO2 from the reaction mixture. The choice of method depends on the operating conditions and the desired purity of the hydrogen product. Long-term hydrogen alternatives Autothermal reforming (ATR) has emerged as a viable alter - native to SMR. ATR combines partial oxidation and steam reforming of hydrocarbons. The partial oxidation of hydro - carbons provides the energy required for the endothermic steam reforming reaction, resulting in higher energy effi - ciency. This leads to lower overall energy consumption and a higher yield of hydrogen per unit of feedstock. The ATR process has lower operating costs compared to SMR. ATR requires less steam than SMR, reducing the cost of steam production. Furthermore, ATR can use a wider range of hydrocarbon feedstocks, including natural gas, liq - uid petroleum gas, and naphtha, which can be cheaper than methane. This flexibility in feedstock choice can lead to cost savings for the process. The crucial advantage of ATR is that it produces fewer CO2 emissions than SMR. The partial oxidation of hydrocar - bons in ATR produces less CO2 than the complete oxidation of hydrocarbons in SMR. Carbon capture and storage (CCS) technology can also further reduce CO2 emissions in ATR. Hydrogen produced through ATR has a higher purity than that produced through SMR. This is because ATR produces less CO than SMR. CO is a common impurity in hydrogen pro - duced through SMR, and its removal requires additional pro - cesses. The high purity of hydrogen produced through ATR reduces the need for additional purification steps, reducing costs and improving process efficiency. By most standards, ATR is a highly scalable process that can be easily adjusted to meet the changing demands of hydrogen production. The process can be easily modified to increase or decrease hydrogen production, depending on the market demand. Conclusion Natural gas will continue to play a dominant role in supply - ing the world’s municipal heating requirements and power grids. In parallel, increasing volumes of natural gas produc - tion will be monetised through LNG, hydrogen, and ammonia production. All three products serve the fuels markets, but their potential commercialisation seems to be accelerating in areas benefiting the agricultural industry (fertiliser), pet - rochemical feedstocks (ethane to ethylene), and increasing needs for hydrogen in refinery operations for the production of near-zero sulphur products.

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COS and mercaptans removal from gases

Challenges with removing trace sulphur species can be better understood and resolved with a new kinetic model validated by plant data in its ability to predict COS removal

Prashanth Chandran, Harnoor Kaur, Jeffrey Weinfeld and Ralph Weiland Optimized Gas Treating, Inc.

G as and liquid hydrocarbon streams from refineries and gas plants must be well cleaned of sulphur com- pounds such as H 2 S, COS, and mercaptans (RSH), dictated mainly by environmental concerns. LPG can be sub- tle because although a copper strip test may indicate accept- able sulphur content today, COS slowly reverts to H 2 S and CO 2 in the presence of water, so the same test administered tomorrow may fail. This contribution offers a new model for COS absorption into alkaline solvents based on mass transfer rates enhanced by reaction kinetics – the first time commercial software has had the ability to simulate this aspect of COS absorption accurately. As part of the reported work, a compilation of plant performance test data on mercaptans removal is also presented. It shows plenty of room for improvement in reli- ability and accuracy of simulation tools. Amines are excellent solvents for H 2 S, but, by and large, they are horrible for removing other less acidic, trace sulphur species such as COS and mercaptans. Until now, no simula- tor has been able to model COS and mercaptans adequately. With mercaptans, the basic problem seems to be insuffi - cient, inaccurate phase-equilibrium data. Almost all the pub- lic domain mercaptans solubility data are academic in origin, which may explain why there is so little of it. Very few academic institutions welcome researchers who handle mercaptans – academia is generally ill equipped to handle them safely and therefore avoids the risk associated with their malodorous and toxic nature. Good-quality data in the range of commercial interest are hard to come by. For COS, one of the main issues has been that simulators have ignored its reactive nature in aqueous amine solu- tions, treating its chemistry in an over-simplified way as a purely physically dissolved, non-reacting solute. The COS absorption rate is thus wrongly computed because the calculations fail to account for significant absorption rate enhancement that results from the chemical reactions of COS with non-tertiary amines. Reactions of COS and mercaptans Reaction kinetics of H 2 S and CO 2 in aqueous amines are too well known to benefit from further discussion here. RSH merely dissociates in aqueous media. But to describe the decomposition of COS in water just by the reaction COS + H 2 O → CO 2 + H 2S is deceptively oversimplified. The reaction

mechanisms and kinetics of COS in amines are much more complex than that and can benefit from a brief explanation: RSH ⇌ H + + RS – (1) COS + H 2 O ⇌ H + + HCO 2 S – (2) HCO 2 S – + H 2 O � H + + HCO₃ – + HS – (3) Reaction (1) is a simple dissociation involving a single hydrogen ion and, as such, is known to be essentially instan- taneous. Thus, it is always at equilibrium. The limitation with RSH is that it is an extremely weak acid, so even a low level of acidification of the solvent will drive Reaction (1) back towards the formation of molecular RSH, and mercaptans have very low physical solubility in water. Significant acidifi - cation can be had even with a modest amount of dissolved CO 2 or H 2 S. In regenerative caustic solutions, the CO 2 and H 2 S spend the caustic from its intended purpose of RSH removal. The significance of these effects is discussed in the next section by looking at the vapour-phase profile of mer - captans in a typical absorber. COS reacts in aqueous solutions first to form thiocarbon - ate Reaction (2), which further hydrolyses to bicarbonate and bisulphide Reaction (3). The combined form of Reactions (2) and (3) along with other speciation reactions of CO 2 and H 2 S is equivalent to the overall simplified hydrolysis of COS to CO 2 and H 2 S already mentioned. Reactions (2) and (3) are very slow unless a base is present in the solution to catalyse them. In the presence of amines, it is postulated that COS reacts by a base-catalysed mechanism according to: COS + Am + H 2 O ⇌ AmH + + HCO 2 S – (4) HCO 2 S – + Am + H 2 O � AmH + + HCO₃ - + HS – (5) In addition to these reactions, COS forms thiocarba- mate with primary and secondary amines via a zwitterion mechanism: COS + AmH + ⇌ AmH + COS – (6) AmH + COS – + B � AmCOS – (thiocarbamate) + BH + (7) Reaction (6) represents zwitterion formation (AmH + in Reaction (6) stands for the primary or secondary amine with at least one mobile hydrogen). Reaction (7) describes the zwitterion’s deprotonation to thiocarbamate, AmCOS – .

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140.1 F

140.3 F

Hydrogen sulphide (V) 0.8

ppmv

Hydrogen sulphide (V) 3.9

ppmv

Sweet outlet-1

Sweet outlet

Carbon dioxide (V) 30.0 ppmv Carbonyl sulphide (V) 189.1 ppmv Carbon dioxide (V) 0.0092 lbmol/hr Carbonyl sulphide (V) 0.0578 lbmol/hr

Carbon dioxide (V) 1.72 mol% Carbonyl sulphide (V) 405.3 ppmv Carbon dioxide (V) 5.3525 lbmol/hr Carbonyl sulphide (V) 0.1262 lbmol/hr

Lean amine-1

Lean amine

MDEA absorber

DEA absorber

130.0 F

Hydrogen sulphide (V) 2

mol%

Hydrogen sulphide (V) 2

mol%

Carbon dioxide (V) mol% Carbonyl sulphide (V) 496 ppm mol Carbon dioxide (V) 16.3438 lbmol/hr Carbonyl sulphide (V) 0.1634 lbmol/hr 5

Sour inlet

Rich amine-1

Rich amine

Figure 1 Absorber case study comparing COS pick-up in MDEA vs DEA

Any base, B, present in solution deprotonates the zwitter- ion. These reactions are responsible for quite significant COS absorption rates into primary and secondary amines, but they do not occur with tertiary amines. Reaction (4) is known to be equilibrium limited. The rate of the reverse reaction is observed to be practically zero for Reaction (5), thus indicat- ing that, for any amine, COS will completely hydrolyse to CO2 and H 2S in the fullness of time. Thiocarbamate formation is significantly limited by the rate of deprotonation, Reaction (7). In fact, for several amines, the COS absorption rate is almost completely determined by the rate of deprotonation. This is unlike CO2 , where the zwitterion deprotonation rate has much less influence on the overall conversion. As a result of these factors, the COS-amine reaction rate is much slower than amine-CO2 . Nevertheless, COS reaction rates are significant enough for a substantial fraction of the COS in a typical feed gas to be removed by primary and secondary amines. However, such is not the case for mercaptans beyond MeSH because they are very weak acids and easily displaced by co-absorbed CO2 and H 2S. Recently, we finished developing a COS absorption model that treats COS as a rigorous mass transfer rate- controlled component and incorporates it along with its reaction kinetics into the OGT ProTreat simulator. The model results were validated against some 20 proprietary sets of field-performance data for various amine systems. They showed the model accurately simulates COS removal in amine absorbers for the first time. What follows is a case study showing: Comparison of absorber outlet concentrations as predicted by the Legacy vs Kinetic Model for the absorber models shown in Figure 1

• Mass-transfer and reaction-rate control in the COS removal model • A comparison between various amines’ performance for COS removal in a simple absorber • Comparison between simulation and actual plant perfor - mance in RSH removal • Summary of literature renditions of VLE in RSH-amine systems. Because of the role played by reaction kinetics, differ- ent types of amines (primary, secondary, tertiary) have quite different COS removal effectiveness. For mercaptans removal, on the other hand, it is mainly the pKa of the amine that determines RSH removal – kinetics plays no role at all. Therefore, it makes sense to treat COS and mercaptans removal in separate ways. Case studies The following case studies elucidate the absorption mecha- nism of COS and mercaptans in typical absorbers: COS Figure 1 shows the simulation of two simple absorbers, one using a 3M solution of DEA and the other using MDEA at the same molar strength and circulation rate. In both cases, the feed gas is 5 mol% CO2 and 2 mol% H 2S; 500 ppmv of COS was assigned to the inlet gas. Callouts attached to the gas streams show the gas analyses. For MDEA and DEA respectively, the CO2 removal effi - ciency is about 67% and 99% compared with 23% and 65% for COS. As expected, amines do not remove COS as effectively as CO2, although a significant amount of pick- up is seen. In addition, DEA, a secondary amine, reacts much faster with COS by forming thiocarbamate via the zwitterion mechanism. This leads to almost three times greater efficiency than MDEA which, as a tertiary amine, cannot form thiocarbamate. Table 1 compares predictions using our new model for COS absorption (‘Kinetic’ in table) with what has been the only type of simulation commercially available until now (‘Legacy’ in table). The Legacy and Kinetic Models give identical predictions of CO2 and H 2S removal, as one might expect. However, the Legacy Model predicts that

DEA

MDEA

Model

CO 2

H 2 S COS

CO 2 H 2 S COS

ppmv

mol%

ppmv

Legacy (equilibrium) Kinetic (reaction rate)

30 30

0.8 0.8

523† 189

1.7 3.9 508†

1.7 3.9 405 † Removal of CO2 and H 2S concentrates COS above its 500 ppmv inlet value

Table 1

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9 7 3 5 1

COS

DEA MDEA

15 17 19 13 11

1 , 500

50 , 000

100 , 000

150 , 000

500

1 , 000

Partial pressure , Pa

Figure 2 CO 2 and COS partial pressure in absorbers

2% of the COS is removed by DEA and 3.3% by MDEA, whereas the Kinetic Model predicts the removal of 65% and 23% by DEA and MDEA, respectively. Figure 2 shows how the Kinetic Model predicts that CO 2 and COS approach final outlet values in the DEA absorber. The gentler decrease in COS partial pressure reflects the much slower reaction kinetics of COS compared with CO2 . In DEA, CO 2 falls rapidly from 5 mol% to a few ppmv, whereas the same 20 trays only take COS from 500 ppmv to 189 ppmv. However, relative to MDEA, both CO 2 and COS decrease rap- idly simply because DEA reacts with both. MDEA does not. COS is severely mass transfer rate limited in a typical amine absorber. It cannot be properly simulated using only its physical (Henry’s Law) solubility in the amine, even aug - mented with salting-in and salting-out corrections. COS reacts with primary and secondary amines at rates that greatly affect its absorption and therefore affect the ability of any absorber to remove it from the inlet gas. Mercaptans The deprotonation of mercaptans into mercaptide ion is known to be instantaneous, leading to huge enhancement factors and hardly any liquid-side resistance to absorption. Therefore, unlike COS, absorption of mercaptans in aqueous amines is almost always VLE limited. However, being a much

weaker acid than CO2 and H 2S, mercaptans have much lower chemical solubility in the basic amine solutions. So, even any low to moderate amounts of H2 S and CO 2 stronger acids dis- solved in the solvent severely impair the ability of the solvent to remove the mercaptans from feed gases efficiently. Figure 3 shows the vapour phase ethyl mercaptan con - tent along with the total acid gas loading of the solvent in a typical absorber that treats a feed containing 10 mol% CO 2 , 2 mol% H 2S and 100 ppmv of ethyl mercaptan using 30 wt% DEA. The absorption profile of the mercaptan in vapour can be split into two zones. The top part of the absorber is actively removing mercaptans from the gas, but as we go down the column, the vapour phase mercaptan content decreases. This indicates that the absorbed mer- captan in the liquid phase is getting stripped back into the vapour. This reversal in the profile can be attributed to the increased bulk acid gas loading in the liquid. As previously discussed, the bulk acid gases, being stronger than mer - captans, start neutralising the mercaptide ions back into free mercaptans, which get salted out of the vapour. The plot shows that with the increase in the solvent circulation rate, as seen from the increasing L/G ratio, the bulge in the vapour phase mercaptan content moves down the column corresponding to the shift in the loading profile. In all three cases, the critical point of mercaptan removal occurs around

9 7 3 5 1

20 L/G 30 L/G 25 L/G

15 17 19 13 11

0.1

0.2

0.3

0.4

0.5

0.2

0.3

0.4

0.5

0.6

0.7

Liquid loading CO + HS

EtSH Vapour content , lbmol/hr

Figure 3 Vapour phase ethyl mercaptan content and liquid phase total acid gas loading in absorber trays. The different curves denote varying liquid to gas ratio in the units of US gal/min of solvent and MMSCFD of feed gas

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