Hydrocarbon Engineering Issue August 2022 by PalladianPublications

August 2022

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CONTENTS August 2022 Volume 27 Number 08 ISSN 1468-9340

03 Comment

43 Streamlined operations Luiz Soriano and Dave Winquist, Siemens Energy, USA, consider how to maximise reciprocating compressor efficiency.

05 World news 08 The secret to safety Lara Swett, American Fuel & Petrochemical Manufacturers (AFPM), USA, explains why collaboration is a top driver of safety improvements in the oil and gas industry.

12 Big data in catalysis Christoph Hauber and Tilman Sauer, hte GmbH, Germany, discuss how integrated database designs enable holistic approaches in R&D.

19 A helping hand on the road to decarbonised operations Richard Irwin, Bentley, UK, explains how improving reliability strategies and asset information reduces both downtime and carbon emissions.

25 Manage to mitigate Stephen Anderson, Daniel Walker and Andrew Jackson, Intertek, examine how to manage the quality risks associated with LNG construction projects.

31 Leading the way towards LNG safety Alec Cusick, Owens Corning, USA, details a passive approach to mitigating pool fire risk at LNG facilities.

36 Keeping your options open Klaus Brun, Elliott Group, USA, explores the different technology options for hydrogen compression.

47 Fight the surge Nabil Abu-Khader, Compressor Controls Corp. (CCC), UAE, explains the effect of a proactive recycle trip response in antisurge control.

51 Shipping’s new scene Giacomo Rispoli and Alessia Borgogna, MyRechemical, Italy, discuss the use of low-carbon methanol from waste as a new fuel to help decarbonise the shipping sector.

55 Controlling combustion for a cleaner future Keith Warren, Servomex, UK, looks at the role that combustion measurements play in controlling carbon emissions.

59 Simulating mercaptans and COS removal Prashanth Chandran, Harnoor Kaur, Nathan Hatcher, Jeffrey Weinfeld and Ralph Weiland, Optimized Gas Treating Inc., USA, detail a new model for carbonyl sulfide (COS) absorption into amines based on mass transfer rates and reaction kinetics.

65 Keeping things operating smoothly Dave Godfrey, Rotork, UK, discusses how downstream oil and gas operators can support ageing assets and reduce downtime.

69 Control valve selection for ethylene plants Matt Wagner, Emerson Automation Solutions, USA, explains why choosing the right combination of valve style, trim type, materials of construction, and digital positioner is critical for profitable operations.

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Cover photo courtesy of Elliott Group. Installation of an Elliott crack gas compressor at a Chinese petrochemical plant.

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APPLICABLE ONLY TO USA & CANADA Hydrocarbon Engineering (ISSN No: 1468-9340, USPS No: 020-998) is published monthly by Palladian Publications Ltd GBR and distributed in the USA by Asendia USA, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid New Brunswick, NJ and additional mailing offices. POSTMASTER: send address changes to HYDROCARBON ENGINEERING, 701C Ashland Ave, Folcroft PA 19032.

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CALLUM O'REILLY SENIOR EDITOR

s the former Editor of Hydrocarbon Engineering’s sister publication – LNG Industry – I always like to keep an eye on this sector of our industry, especially during times of geopolitical turmoil. In recent analysis, Wood Mackenzie described LNG as “the most compelling investment option over the next few years” across all hydrocarbons, and it’s easy to see why.1 Given the supply implications from the Russia-Ukraine conflict, LNG stands to play an essential role as a secure and reliable source of energy around the world. For a good example, just take a look at Germany, which is fast-tracking its plans for LNG terminals as it moves to diversify away from Russian energy. Four floating storage and regasification units (FSRUs) are planned, as well as two permanent onshore sites. On 4 July, Uniper received approval to start construction work on the country’s first LNG terminal in Wilhelmshaven, with the aim of commissioning in late 2022 or early 2023. In its ‘2022 World LNG Report’, the International Gas Union (IGU) praised the agility of the LNG sector as it adjusted to rapidly changing market conditions.2 Last year, global LNG trade grew by 4.5%, reaching an all-time high of 372.3 million t, on the back of a surge in LNG imports following a strong post-pandemic recovery. However, the IGU notes that this strong growth highlights the urgent need for greater investment in supply to ensure that the commodity is more affordable. IGU Secretary General, Milton Catelin, said: “As the world considers its options for navigating through unprecedented times, policymakers should consider the options that are available and the time that is required to bring new supply online. The industry needs urgent policy clarity, beyond the short-term.” In its latest ‘Gas Market Report’, the International Energy Agency (IEA) notes that natural gas’ reputation as a reliable and affordable energy source is being damaged by today’s record high gas prices, as countries around the world compete for LNG shipments.3 The report states that while there has been a recent surge in LNG investment decisions, the resulting infrastructure will not be operational until after 2025. In the short-term, LNG export capacity additions are set to slow down in the next three years due to both curtailed investment plans in the mid-2010s and construction delays during the COVID-19 pandemic. The IGU reports that, as of April 2022, 136.2 million tpy of liquefaction capacity was under construction or approved for development. Just 7.7 million tpy of that overall capacity increase is expected to come online in the second half of this year. The rest will gradually filter through between 2023 and 2027. In a world where energy security is a growing concern, it is also essential to keep the energy transition front and centre of our thoughts. LNG is a key part of the solution, alongside decarbonised, low and zero-carbon gases. The IGU’s Milton Catelin added: “Gas is the fastest attainable and sustainable long-term vehicle to get the world back onto the energy transition path, and the inherent flexibility of LNG allows [it to be delivered] almost anywhere in the world.” This issue of Hydrocarbon Engineering includes several articles exploring the LNG sector, and we’ll continue to closely monitor this essential market in the coming months. 1. 2. 3.

‘Complete ban on Russian commodity exports accelerate LNG growth and energy transition’, Wood Mackenzie, (16 June 2022). ‘2022 World LNG Report’, IGU, (6 July 2022). ‘Gas Market Report, Q3-2022’, IEA, (July 2022).

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WORLD NEWS UK | JM

and ClimeCo form alliance

ohnson Matthey (JM) and ClimeCo, a global climate solutions company, have announced that they are collaborating to accelerate the deployment of enhanced carbon capture solutions for industry. Under a Memorandum of Understanding (MoU), the two companies will help syngas producers, initially in hydrogen and methanol, to build the business case for reducing CO2 emissions from existing processes by up to 95%.

Syngas producers are responsible for approximately 70% of CO2 emissions in the chemicals sector. Jane Toogood, Catalyst Technologies Chief Executive at JM, said the collaboration would “enable industries such as chemicals and refining [...] to quickly understand the regulatory frameworks, accelerate capital decisions for decarbonisation programmes and easily deploy proven technology solutions that can have an impact today, to create a cleaner world.”

The Netherlands | Shell Chemicals Park Moerdijk

to produce more sustainable chemicals

hell Chemicals Park Moerdijk, a subsidiary of Shell plc, has announced a new investment that supports its plan to transition the chemicals park into a site able to serve the changing needs of its customers. Its customers desire more low-carbon products, as well as products made using recycled material. Shell Moerdijk will build a new pyrolysis oil upgrader unit that improves the quality of pyrolysis oil, a liquid made from hard-to-recycle plastic waste, and turns it into chemical feedstock for its

China | LNG

plants. The investment marks a first major step in transitioning the park within 10 years, by increasing the use of circular and bio-based feedstocks, growing its offer of low-carbon products, and becoming net zero through the application of hydrogen and carbon capture and storage (CCS). To achieve these ambitions, Shell intends to invest billions in Shell Moerdijk’s chemical complex over the next decade, subject to investment decisions and within existing capital allocation frameworks.

UAE | ADNOC and

TotalEnergies sign strategic partnership agreement

DNOC and TotalEnergies have signed a strategic partnership agreement to deepen their long-standing partnership and explore new opportunities for growth across the energy value chain. Under the terms of the agreement, the companies will explore opportunities to collaborate in areas of mutual interest, including in gas growth, carbon capture utilisation and storage (CCUS), and trading and product supply. This strategic partnership agreement follows the signing of the UAE-France Comprehensive Strategic Energy Partnership (CSEP), which is focused on enhancing energy security, affordability and decarbonisation, as well as progressive climate action ahead of COP28. TotalEnergies currently collaborates with ADNOC across the full value chain: offshore and onshore exploration, development and production of oil and gas, gas processing and liquefaction, product marketing, research and development (R&D), and National Talent development.

imports to decline

hina’s LNG imports are set to fall over 14% y/y to 69 million t in 2022, the largest decline since it began LNG imports, reports Wood Mackenzie. After solid growth in 2021, China’s gas and LNG demand is expected to slow down in 2022. China’s gas demand (sum of production and net imports) in 2Q22 decreased 5% y/y. The weakening gas demand was due to a confluence of factors including

economic slowdown, rising gas import prices, policy support for clean coal, and a warmer-than-usual winter. Wood Mackenzie Research Director, Miaoru Huang, said: “Gas-fired power was a major contributor to the absolute decline in volumes. In addition to the factors mentioned earlier, the sector was pressured by growth in use of renewables.”

On the supply side, domestic production increased by 4.9% y/y in the first half of the year, while pipeline imports increased by 11%. LNG imports totalled 31 million t, down 21% y/y. Huang said: “Chinese buyers have minimised their exposure to costly spot LNG. Spot purchases were muted, and reportedly, some Chinese players resold cargoes into the European market.” HYDROCARBON

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WORLD NEWS IN BRIEF 22 - 26 August 2022 ACHEMA Frankfurt, Germany www.achema.de

05 - 08 September 2022 Gastech Milan, Italy www.gastechevent.com

11 - 14 September 2022 GPA Midstream Convention San Antonio, Texas, USA gpamidstreamconvention.org

12 - 14 September 2022 LARTC Buenos Aires, Argentina worldrefiningassociation.com/event-events/lartc

13 - 15 September 2022 Turbomachinery & Pump Symposia Houston, Texas, USA tps.tamu.edu

18 - 20 October 2022 2022 AFPM Summit San Antonio, Texas, USA www.afpm.org/events

24 - 26 October 2022 Sulphur + Sulphuric Acid Conference & Exhibition The Hague, The Netherlands www.events.crugroup.com/sulphur/home

24 - 26 October 2022 8th Opportunity Crudes Conference Houston, Texas, USA www.opportunitycrudes.com

7 - 10 November 2022 ERTC Berlin, Germany worldrefiningassociation.com/event-events/ertc/

16 November 2022 Global Hydrogen Conference Virtual www.globalhydrogenreview.com/ghc22

6 - 7 December 2022 15th Annual National Aboveground Storage Tank Conference & Trade Show The Woodlands, Texas, USA www.nistm.org

August 2022

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France | Nextchem

awarded advanced basic engineering study by Storengy

aire Tecnimont S.p.A. has announced that its subsidiary, NextChem, has been awarded a contract by Storengy to carry out an advanced basic engineering study for a waste wood and solid recovered fuel conversion plant to produce biomethane. Once the project has reached the Final Investment Decision (FID) targeted by the end of 2022, and is granted the related permitting, NextChem, in association with another Maire Tecnimont Group’s subsidiary, shall act as an EPC contractor for the

methanation package of the project, which is set to be implemented in Le Havre, France. NextChem will be responsible for the engineering and cost estimating for the syngas purification, methanation unit, and methane upgrading of the plant, which will produce 11 000 tpy of renewable and low-carbon natural gas (biomethane). COMESSA will be responsible for the design and supply of the chemical reactor. The technology to be used in the plant has already been successfully applied to the Gaya pilot plant near Lyon.

Worldwide | New

refineries to increase global refining capacity

he International Energy Agency (IEA) estimates that global refining capacity decreased by 730 000 bpd in 2021 – the first decline in global refining capacity in 30 years. In the US, refining capacity has decreased by about 1.1 million bpd since the start of 2020, contributing 184 000 bpd to the global decline in 2021. Global demand for refined products dropped substantially in 2020 as a result of the COVID-19 pandemic. Less petroleum demand

and the associated lower petroleum product prices encouraged refinery closures, reducing global refining capacity, particularly in the US, Europe and Japan. However, several new refinery projects are set to come online during 2022 and 2023, increasing capacity. In its June 2022 ‘Oil Market Report’, the IEA expects net global refining capacity to expand by 1 million bpd in 2022 and by an additional 1.6 million bpd in 2023.

USA | Bayport

Polymers starts up new ethane cracker

ayport Polymers LLC has announced the start-up of commercial operations of a new ethane cracker with a production capacity of 1 million tpy of ethylene. Bayport Polymers is a 50/50 joint venture (JV) between TotalEnergies and Borealis. This project is built on the site of – and operated by – the TotalEnergies refinery in Port Arthur, Texas, US.

The ethylene produced by the cracker will be used as feedstock to supply Baystar’s existing polyethylene units, as well as a new Borstar® technology polyethylene unit currently under construction in Bayport, Texas. Bernard Pinatel, President, Refining & Chemicals, TotalEnergies, said: “This investment is in perfect alignment with our strategy to develop petrochemicals at our integrated platforms.”

here is nothing more important to US fuel refiners and petrochemical manufacturers than the safety of the people who work at the sites and live in neighbouring communities. Members of these industries invest significant resources in safety programmes and practices – all aimed at preventing process and occupational safety incidents or injury to employees; mitigating risk and impact; and coordinating with emergency responders and communities. Every person across these facilities plays a role in the American Fuel & Petrochemical Manufacturers (AFPM)’s collective mission to continually improve safety performance and risk management practices. Some of the greatest process safety improvements that have been witnessed have occurred within the last 15 years. At both refineries and petrochemical facilities, there has been a more than 50% reduction in reportable process safety events; a key reason for this is cross-industry collaboration. Efforts to formalise collaboration among the fuel refining and petrochemical industries, including launching a number of process and operational safety programmes, are making people and communities safer. In fact, over the past two decades, these industries have been ranked safest among all manufacturing sub sectors.

Safety is not proprietary The AFPM’s commitment to collaboration across industry took on a whole new level of seriousness around 2010.

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Data at the time showed that individual member companies and facilities were making good improvements to their own operational safety performance, but there was a simultaneous uptick in serious incidents that was not acceptable. Industry leaders saw the trend and wanted to turn it around. Jerry Wascom, ExxonMobil’s Americas Refining Director, reached out to AFPM to ask how to step up to better protect people. That conversation led to a paradigm shift in AFPM’s approach to safety, and it planted the seed for what has become an umbrella programme called Advancing Process Safety (APS). Jerry Wascom was a fitting person to jumpstart the effort. He was 18 when he got his first job as a refinery operator and served in a number of roles at the facility level earlier in his career. One of Jerry’s first collaborators was Jim Mahoney, then Executive Vice President of operations at Koch Industries, and a future chairman of AFPM’s board. Both men identified the existence of company and facility siloes in the safety space as a barrier to industry improvement. If facilities and process safety leaders could pool their knowledge and share how certain sites had achieved improvement and what tools were most helpful in driving results, Jerry and Jim knew that industry could take leaps forward in safety performance. Data sharing would be at the core of this new approach. This is remarkable because the tendency in competitive businesses is to keep a lot of information proprietary,

Lara Swett, American Fuel & Petrochemical Manufacturers (AFPM), USA, explains why collaboration is a top driver of safety improvements in the oil and gas industry.

Figure 1. Iconography that often

accompanies the Walk the Line programme.

however it was decided that safety needed to be the exception. If the learnings from an incident at one site could be shared, other sites would be able to proactively review the details and assess any potential vulnerability of their own. They would then be able to affect change before problems developed, preventing other possible incidents from occurring and keeping people safe – both onsite and beyond the fence line. Collaboration was and is the most powerful thing that can be done to promote safety, and trade associations such as AFPM are in the perfect position to facilitate cross-industry engagement. For refiners and petrochemical manufacturers, safety is not proprietary, but rather a core value.

The evolution of advancing process safety What began as a conversation between Jerry and AFPM, and then Jerry, Jim and AFPM, grew to a slightly larger group of 20 company representatives from throughout the refining and petrochemical industries. The group convened for the first time in 2010, kicking off APS and cementing the industry’s culture of collaboration on safety. In subsequent meetings, the team took a more holistic look at industry process safety data, analysing it for macro trends and potential risk factors. To go from data to action required input from employees who manage safety on the ground at refineries and petrochemical sites. From there,

resources and a library of good safety practices were developed to enrich facility programmes industry-wide. In the years since that first meeting, the APS programme has been a resource for more than 200 companies. Over 3500 industry employees have directly taken part in APS programme activities and trainings. Today, APS is the umbrella for a number of sub-programmes that help refiners and petrochemical manufacturers to continuously improve their safety performance. These supporting programmes cover incident sharing, site assessments, and hazard identification tools, and present opportunities to share practices and more. The programmes include: n Walk the Line. n Process Safety Regional Networks. n Process Safety Site Assessment programme. n Hazard Identification/Practice Sharing Subgroup. n Mechanical Integrity Subgroup. n Human Reliability Subgroup. n Industry Learning and Outreach Group.

APS at work: data reveals a need to ‘Walk the Line’ If you had to guess the number one cause of serious process safety events, do you know what you would answer? Mechanical failures? Natural disasters? What about honest human mistakes? Early APS data made clear that the last point regarding human organisational performance is the answer. About one-third of safety incidents at refineries and HYDROCARBON

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petrochemical sites are due to operator error, often when ‘bleeders’ or valves are left open. More than half of serious safety events stem from similar mistakes. Without the data check, it would have been easy for APS leaders to assume that training basics were in good shape and technical or mechanical improvements should be the focal point of combined industry efforts. The numbers said otherwise, and so it was clear that more resources needed to be fed into workforce training and safety fundamentals to limit future mistakes and the potential for mistakes to cause incidents. Operational readiness lapses and very preventable line-up errors involving pipeline valves were responsible for a number of safety incidents. Based on that, it was determined that operators working during equipment commissioning, draining, and loading and unloading activities would be most likely to benefit from additional training and safety practices. AFPM took it upon itself to address the industry-wide challenge together. These efforts came to fruition in 2015 with the launch of the APS practice sharing sub-programme, ‘Walk the Line’. Jerry Forest, Senior Director of Process Safety at Celanese, led the early efforts to identify and source a pool of proven resources and practices to equip facilities, operators and front-line supervisors with a collection of trainings, exercises and tools designed to help operators be successful in their work, and reduce human error. The way it was seen was that

if incident data sharing and analysis was able to help those in the industry to spot larger problem trends, Walk the Line would use that same data to provide key solutions. At its core, Walk the Line reinforces the fundamental responsibility of every facility-level operator to know with 100% certainty that valves are in the correct position, that material in process units is where it should be, and that material will flow in the correct direction when a unit starts up. If there is any question on those points, operators need to ‘walk the line’ and check everything again. With its robust and growing shared resource library and rigorous focus on mastering the basics, Walk the Line is about practicing what you preach. AFPM espouses a safety culture where errors are reduced and every operator and front-line supervisor has the tools and training that they need to readily collaborate and mitigate operational risks. Walk the Line is the toolbox, and to date, there are over 94 practices, trainings, exercises, presentations and videos available to the programme’s participants. Each of the tools, recommendations and resources made available have been tested at actual facilities, and more than 500 safety professionals and experts have had input. These programmes work because they are operator-centric and customisable at the company and even site levels.

Collaboration beyond refining and petrochemicals The learnings gathered across APS programmes are not restricted to just the fuel and petrochemical industries. AFPM shares information with the independent government agency in charge of investigating industrial incidents to foster smoother, more effective collaboration around the shared goal of keeping people safe. Other industries and government partners are taking note of the success of AFPM’s safety programmes and are seeking to apply its good practices more broadly across the manufacturing sector. Over the course of the last year, AFPM has worked with organisations and government partners such as the American Gas Association, the American Petroleum Institute (API), the Center for Chemical Process Safety, the Chemical Safety Board, and the Occupational Safety and Health Administration (OSHA) to share good practices derived from these programmes. Beyond what the industry does to advance safety within its facilities and through APS and its supporting programmes, refiners and petrochemical manufacturers work within their local communities to increase safety in a number of ways, ranging from donating equipment to volunteering and training emergency responders.

A continual pursuit of improvement

Figure 2. Both the fuel refining and petrochemical industries have made significant improvements in safety performance.

August 2022 10 HYDROCARBON ENGINEERING

‘Process safety’ is not a status that sites achieve; it is a core value in our industries that requires every facility to commit to a continuous, daily cycle of safety improvement. Sites incorporate new tools and adopt different practices as technology improves, as sites learn from their own experiences and audits, and as information and learnings are shared by industry peers. Every refinery, petrochemical facility, and company is expected to play a part, because more can be accomplished by sharing.

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Christoph Hauber and Tilman Sauer, hte GmbH, Germany, discuss how integrated database designs enable holistic approaches in R&D.

ince the early days of the advancement of the chemical industry, catalyst development has been a tedious and repetitive task. One example of this is Alwin Mittasch, Assistant to Carl Bosch at BASF in the 1910s. He led catalyst development for the Haber-Bosch synthesis, which required 20 000 experiments and screening of over 3000 catalyst formulations until the optimal sample was found. It is hard to imagine how many resources were required to run these tests for over a decade, and how many more to handle the analog data that they produced. Fortunately, today, with help of computers, sensors and automation, laboratory experiments can be carried out in much safer, faster and more comprehensive ways. This article focuses on how a software tool can be designed holistically to generate, organise and evaluate big data for catalysis. hte GmbH has developed a fully-integrated workflow that centres around a powerful data management system. The myhte system collects data from every step of the catalyst testing workflow, such as catalyst synthesis, reactor loading, and actual testing – including online GC data, sample logistics, and product analysis. Based on the data acquired, configurable automated calculation routines generate characteristics such as conversion, yields, selectivities, or kinetic data. These results are presented in powerful and highly-flexible report formats, which enable the scientist to decide on improvements for future catalyst synthesis. In order to determine the performance of a catalyst, one needs to know its most important parameters, such as mass and heat transfer, structure, surface, and chemical composition; the raw materials used; and the chemical and mechanical stability of the carrier and of the active phase. Some of these properties can be easily measured with analytical devices, e.g. X-ray diffraction for the phase composition, or Brunauer-Emmett-Teller (BET) for characterisation of the microstructure, while others require testing under relevant conditions of the chemical process that the catalyst was designed for. This certainly makes development more complex, and many different experiments are required to ultimately obtain sufficient data to set up a kinetic model for the process, or to identify one of many different catalyst candidates with the best properties for a given task. As such, parallelisation of the reactor system has been proven to accelerate research but, as stated in the ‘Handbook of Heterogeneous Catalysis’: “the information technology (IT) systems managing these data and reducing them in such a way as to identify the best catalysts in each run are of utmost importance”.1 In order to handle all of these tasks, data input and output is structured in different inventories and data management systems, which each cover the steps that are necessary to handle the development process (e.g. chemical feeds and samples, analytical services [on and offline], catalyst synthesis, loading, and the data reporting section from generated data by test units). The following section focuses on a generic catalyst development project and how digital integration is helping with its realisation. myhte’s user and permission management system makes it possible to restrict access to each project created within the database to certain users so that information can be shared on a need-to-know basis.

Catalyst design and preparation The performance of a catalyst strongly depends on its preparation history. The choice of ingredients, various parameters of different process steps leading to the final HYDROCARBON 13

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catalyst, and its chemical composition may have a significant impact on the catalyst’s performance. Therefore, it is essential to capture and store the information mentioned above. This builds the foundation for the subsequent detection of structure-performance relationships. A new synthesis request module in the system now allows its users to design a catalyst preparation process, guide the technician through the execution, and capture all necessary preparation parameters. The system’s chemical inventory describes the ingredients of catalyst preparation along with chemical composition, purity, and mass fractions. When designing a catalyst preparation, myhte automatically calculates the necessary amounts of all ingredients based on multiple weight or molar ratios of elements, components, materials, and quantity information. Additionally, the user can pick from a set of customised process steps with different parameters and data types to describe the preparation of a precursor or the final catalyst. The recipe can then be flexibly adjusted and multiplied by using factors for ingredients, ratios, amounts, and process step parameters. This makes it possible to easily describe the preparation of a zeolite with two different organic templates, two different Si/Al ratios, and four calcination temperatures, resulting in 16 different materials that can later be tested in a parallel reactor unit. Once the recipe is ready, a synthesis request can be transmitted to the operator who is then guided through the process and can enter the actual values – such as ingredient weights and parameter values – directly in the software. For quality control purposes, differences between the specified and actual weight are displayed directly during preparation. The barcodes of all ingredients used must fit the specified ingredients, otherwise an error statement is issued to the user. This prevents ingredients from becoming mixed up. The materials created, as well as their genealogy, are then stored in a library.

Figure 1. myhte data warehouse repositories.

August 2022 14 HYDROCARBON ENGINEERING

The preparation tool is not limited to catalyst synthesis, and also covers the preparation steps for liquid feedstocks, such as filtration, drying, spiking, and mixing of different components, paving the way for further laboratory 4.0 approaches.

Material characterisation Material analysis is an important step within the evaluation process. myhte offers integrated LIMS functionality to meet this need. All newly-created materials (precursors, catalysts, etc) are identified by a unique barcode that links the material to its specific project, material type, derivate, and ancestor. Certain analyses can be requested via a barcode within the system, and the results are automatically imported and stored. Once the catalysts have been prepared, or in case commercially-available catalysts need to be tested in a fixed-bed reactor, a reactor filling design can be set up. In this step, the operator defines the necessary physical catalyst preparation steps (sorting, sieving), how a reactor is designed, and how it should be loaded (e.g. definition of single zones in the reactor, catalyst mixtures, embedding, as well as a hardware geometry description and the sealing procedure). The filling design is displayed in an interactive graphic, and changes are displayed instantly. Filling is then requested and is addressed by a technician who proceeds with the actual filling process. In addition to mass control, height is measured by a laser-controlled device, ensuring the right volume for the requested catalyst zone. The final quality check after a leakage test is the measurement and reporting of pressure drop for each reactor.

Material testing Material testing in a high throughput unit is the most time-consuming part of each project. In addition to thorough quality checks, the highly-complex laboratory units require tuning to ensure that they are fit for use for a specific type of chemical process. The experiments themselves may take weeks or even months, depending on the nature of the experimental plan and chemistry. For a material to be tested in an experimental and mostly-automated configuration, several requirements need to be met: n Test equipment needs to be safe for the designated experiment, whereby modules that monitor

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experimental parameters and automatically react at user-determined thresholds may increase the level of control. Relevant parameters need to be tracked in order to properly document the experiment. Determining whether an experiment is successful requires meaningful analysis methods. Experiments could be carried out manually, but flexible programming of an entire experiment plan guarantees reproducibility, ensures quality and control over each experimental step, and saves time for similar future tests. Experimental data needs to be recorded during an experiment, whereby the dynamic development of the experiment has to be traced in sufficiently small increments. Experimental data from different sources, e.g. sample weights, analysis results, and unit sensors, needs to be merged and correctly assigned to a common timestamp and reactor within a dataset.

nn Merged data needs to be evaluated during a running experiment. nn A feedback loop using evaluated data as a control variable for automatic process control is beneficial for simulating established industrial processes. So-called iso-conversion operation, where reactor temperatures are controlled by a control variable to maintain a constant conversion, help to simulate industrial processes. High throughput units equipped with hteControl and linked to a myhte server fulfil the above criteria. All unit-dependent operations are managed by the process automation software, and results are uploaded to the database. Raw data, e.g. from a gas chromatograph – usually one of the most important analysis methods for the evaluation of catalytic processes – is displayed in the peak assignment section in the system, where each unique peak from one chromatogram within a defined measurement time is displayed, and can be assigned to a specific component. This significantly reduces the amount of quality control required for the experiment, as all of the analytical data of one project for one detector is displayed in a single window. Retention time drifts can easily be detected by plotting retention times vs the injection time. Outliers and new or unknown peaks are marked automatically, and filtering data allows control for single reactor positions or single experiments. The same assignment methods can be used for the chromatographic analysis of offline samples. Other analytical methods that only contain single values are directly imported to the data table and linked to the barcode of the offline sample.

Figure 2. Example of reactor filling of 16 reactors with different catalyst stacks (software screenshot).

Figure 3. myhte peak assignment: each square represents one peak within a chromatogram within a series of measurements of one experiment (software screenshot).

August 2022 16 HYDROCARBON ENGINEERING

Data evaluation and reporting As an example, typical spreadsheets from one experiment in a 16-fold reactor unit running for 8 – 10 weeks contain several hundred columns and several thousand rows. With the additional information gathered from analytics and sample preparation, the complexity of big data becomes clear: the set is large in volume and has a variety of sources that are carefully calibrated, so veracity and validity are given. Velocity is one of the challenges, however, and at the end the outcome should be valuable to the stakeholders. As such, the data processing engine should be capable of working with this amount of data. It must also be able to incorporate data from different sources and to qualify, quantify, display and simplify the data to the point where a non-expert can comprehend the results at a glance. In myhte, the evaluation is script-based and the user can

LH 2

Figure 4. An example of unstructured vs structured charts: data split into different segments by reactor position or by different chemical component. choose a large number of different operations to write an algorithm that generates the output data. This includes the simple calculation of rates, conversion, yields and selectivities; creation of statistical parameters such as standard deviations, mean, or median values; interpolation of data; and more. Smart filters and the option to create customised data tables help to condense large datasets in useful key parameters. All columns can be displayed in rendered, interactive charts that help the reader to understand the uncountable data points in a structured manner.

Conclusion Catalysis development depends on a variety of multidisciplinary steps, each of which produce data that needs to be captured, related and connected in a central data

repository that is accessible by multiple users. This facilitates communication and information exchange between different members of a project team, and helps to structure development projects. Convenient access to the heterogeneous data formats that come with catalyst development helps to maintain an overview and the ability to validate all aspects within the development, testing, and evaluation programme. The system described in this article offers an all-encompassing solution that undergoes continuous development in order to extend scientific capabilities not only for catalysts but also for battery materials and electrolysis technology.

Reference 1.

‘Handbook of Heterogeneous Catalysis’, (2008), p. 63.

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Richard Irwin, Bentley, UK, explains how improving reliability strategies and asset information reduces both downtime and carbon emissions.

owntime, especially that which is unplanned, can cost companies upwards of US$500 000/h on average as a result of lost revenue, financial penalties, idle staff time, and restarting lines. As if that was not bad enough, there is also a cost to the environment. As energy providers face pressure to meet challenging sustainability

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and become leaner and more efficient in order to maintain returns and stability. Oil refineries are often the major polluters. They consume substantial amounts of energy and water to operate, produce large quantities of wastewater, release hazardous gases into the atmosphere, and generate solid waste that is difficult to treat and dispose of. Avoiding the unavoidable There are many events that can cause unplanned In the process industry, it is common practice to add downtime, ranging from equipment reliability and human unplanned downtime as a yearly cost. It is something that, error, to availability of spare parts and extraordinary while inevitable, can come at any time. While unplanned events. When one critical component of a facility shuts downtime will always impact productivity and profitability down, there is a ripple effect on everything else, including in an oil refinery or petrochemical plant, the effects often a potential shutdown of the entire facility. From a plant or have far-reaching implications that go beyond financial refinery perspective, a shutdown affects production and costs. Assets that are running inefficiently also use more has financial and safety consequences. Unseen, however, energy, cost more to run, are more likely to fail, and are the consequences on the environment as a result of therefore contribute to increased levels of carbon. While the sudden release of carbon emissions. Nowhere is this safety is critically important to the plant and the felt more than when a process failure causes gas flaring workforce, so too is the damage to the environment and during an unplanned event. the emissions that shutdowns cause. With the recent push Flaring indicates that something is not right within the for net zero emission targets, operators have had to adapt plant. Gas flaring introduces toxic pollutants such as sulfur dioxide (SO2) into the atmosphere, which can lead to environmental problems such as acid rain, as well as the generation of greenhouse gases that contribute to global climate change. In 2020, nearly 142 billion m3 of natural gas was flared, which equates to approximately 265 million t of carbon dioxide (CO2). This flaring will continue for as long as the plant is running inefficiently. Moreover, there are secondary environmental issues that are added into the equation, such as the carbon emissions as a result of Figure 1. Operators can view the status of any asset within the digital twin. additional transportation for spare parts; bringing in maintenance teams or third parties to fix the problem; the energy used from multiple start-ups; and round-the-clock maintenance. Therefore, it is more cost-effective and sustainable to run a plant as optimised and as smoothly as possible, as anything outside of these thresholds spells trouble. targets and reduce emissions, there is a growing focus on the environmental impact of unexpected shutdowns at oil and gas refineries. This article examines the implications of unplanned downtime on the environment, and how to improve this in order to help achieve net zero emissions.

Reducing downtime: the options

Figure 2. An APM strategy is key to reducing risk, and therefore downtime.

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So what can organisations do to minimise unplanned downtime and make their processes more sustainable? Thankfully, there are many solutions driven by

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and chemical management, flow assurance, and integrity management, to energy and building management. Some vendors combine analytics with their APM offerings, while others offer separate products.

One of the most cost-effective and efficient ways to reduce downtime is to employ asset performance management (APM) strategies and processes that encompass the capabilities of data capture, integration, visualisation, and analytics – all tied together for the purpose of improving the reliability and availability of physical assets. APM uses a variety of approaches and techniques, such as condition and health monitoring, inspection management, reliability centred maintenance (RCM), risk analysis, predictive maintenance, and prescriptive analytics. APM software solutions, such as Bentley’s AssetWise Asset Reliability, provide critical information for assessing equipment criticality and risk, maintenance processes, equipment care strategies, continuous monitoring, and assessing the impact of operations on maintenance across the enterprise. APM solutions provide a more preventative and proactive guide to maintenance and reliability than reactionary fix-when-failed strategies.

Build a digital twin

Implement an asset performance management strategy

Analytical intelligence

While APM software can provide insights into equipment health and reliability, an analytical solution can provide insights and intelligence into the operational performance of the plant or facility to improve asset performance, reduce costs, and facilitate mission-critical decision making at the right time. By connecting multiple data sources together, an analytics solution can provide key functions to the user such as visualisation, reporting, alarm management, and performance dashboards using near real-time data. Its key role though, by combining the above, is to uncover hidden insights within the operation, turning raw data into intelligent information from which accurate decisions can be made. Analytical solutions can be applied to many areas – from production, corrosion

A digital twin is a virtual representation of real-world entities and processes, combining engineering and design data/models with operational and IT information. Digital twin systems transform businesses by accelerating understanding, supporting optimal decision making, and enabling effective actions to be taken quickly. As oil and gas operations become more digitalised to improve operational performance and remain competitive and more sustainable, the role of digital twin technology becomes even more important. Gartner says that by 2024, at least 90% of greenfield investments will already have comprehensive digital twin models, onsite data integration, and dynamic software configuration capabilities.1 That being said, as the need for the transition to renewable energy escalates, then the need for complex oil and gas digital twins may slip down the list of importance. Nevertheless, the benefits that a digital twin brings to any digital operation are attractive. They include: nn Enabling automated, remotely-operated, minimally-manned, highly efficient, and more sustainable assets. nn Providing access to accurate and reliable single-sourced information across the whole life cycle of the asset. nn Accessing and sharing digital twins across multiple teams, from engineering design and handover through to operations and maintenance. nn Providing facilities for training and familiarisation (‘walk the plant’) of the operation prior to onsite visits. nn Multi-discipline integration of third-party models, data, and information into one application. nn Creating a digital twin of the exact conditions of a physical asset, allowing people to review and make faster decisions. n Improving overall decision making with the addition of simulation and predictive capabilities.

Machine learning and artificial intelligence

Figure 3. Digital twins can provide multiple views of an asset, from reality meshes to 3D models, and the up-to-date information it contains.

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Machine learning and artificial intelligence (AI) techniques can also be applied to any of the above solutions to help predict equipment failures and other issues that may lead to unplanned shutdowns, therefore reducing carbon emissions and rendering the project more sustainable. This would turn unplanned downtime into planned downtime. All of the above solutions can be combined into one

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system of systems. For example, PlantSight, the joint Bentley/Siemens digital twin solution for the process industry, can integrate all engineering information (3D models, reality meshes, P&IDs, and more) from a variety of sources. The solution is able to surface operational information from Bentley’s AssetWise solutions to provide a complete, reliable, and up-to-date solution across the life cycle of the asset or project. This means that all system users are always accessing the same consistent data, and any changes are consistent across the board. As such, any downtime in a section of the operation can be viewed within a model at the click of a button; everything that is affected can be seen; and decisions can be taken to reduce the impact that it causes so that the plant is up and running sooner.

Plan for a greener future Another way of reducing emissions and becoming more sustainable is to transition to renewables, such as wind, solar, and hydrogen energy. This is a shift that we are seeing more often as companies try to match their ambitious net zero targets, as well as distance themselves from the negatives associated with hydrocarbon production. While our dependency on hydrocarbons will still be around for the next 30 – 50 years, operators have three choices: nn Carry on as we normally would – this means maintaining production while demand and prices are still high, and capitalising while the window remains open. nn Replacing hydrocarbons completely – this means replacing oil and gas production entirely and switching to renewable energy resources only for a greener and sustainable future. nn Transition from hydrocarbons to renewables – this hybrid approach implies carrying on as normal (but cutting back on core activities while reducing carbon emissions), while also investigating and investing in renewable alternatives such as carbon capture, energy storage, electrification, hydrogen projects, solar, and wind. This can be seen by the transition of many large operators – from international oil companies to integrated energy companies, such as Shell and BP. As with a plant, these new renewable assets also require APM and analytical solutions for them to operate reliably.

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Conclusion: the future does not have to appear bleak For decades now, oil and gas companies around the world have been generating large returns due to the over-reliance and demand on hydrocarbons. That reliance has made them some of the most profitable companies in the world. Considering recent events such as the COP26 summit, there is greater pressure on hydrocarbon producers to become more climate resilient, offset carbon, reduce emissions, and look at other revenue streams in renewables. While some companies have already become early adopters of renewable alternatives, many operators are looking at substantial changes to their business models. Those that continue to produce can still have a positive result when it comes to being more sustainable and climate resilient, with the help of technical and software innovation. Some of these advancements have been around for a while, but not always implemented, or information is held in siloes and ignored or unused. Companies that implement digital twin technology to help reduce unplanned downtime can be hugely differentiated from the competition as a result of combining improved safety and production with sustainable performance.

Reference 1.

CUSHING, S., and MCAVEY, R., ‘Predicts 2022: Oil and Gas — The Last Golden Era’, Gartner, (8 November 2021).

Stephen Anderson, Daniel Walker and Andrew Jackson, Intertek, examine how to manage the quality risks associated with LNG construction projects.

OVID-19 has had significant implications for construction projects and CAPEX programmes around the world. The pandemic has shown us how fragile our supply chains are and how quickly our well-laid plans can collapse. Project managers, contractors, subcontractors, labourers and suppliers have all been affected, resulting in capital project delays, loss of quality, lower efficiencies, and impacted costs.

One of the largest areas of global capital investment is the LNG market, which is emerging as the hottest sector in the energy industry. This includes soaring demand for US LNG as global trade routes are upended and some long-stalled US export projects come back on track. However, rising costs for materials and labour threaten to slow these projects, but are not likely to halt new construction. Wall Street analysts now expect HYDROCARBON 25

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four multi-billion-dollar plants to be approved in 2022, vs a previous projection of just two or three plants.1 As new LNG projects move forward, the pandemic has taught the industry to have good risk management programmes in place and to consider all eventualities, such as disruptions to the supply chain; potential insolvency and bankruptcy of suppliers and vendors; and delays in getting personnel to fabrication sites and obtaining permits. To mitigate such challenges, risk-based data analytics tools can manage quality oversight and planning of LNG project vendors and supply chains in order to minimise procurement delays. Remote video inspections (RVI) can also help to alleviate personnel shortages and access issues. Finally, to minimise costs, modular units are being fabricated on LNG projects, and specialised dimensional control techniques can help to ensure modular quality and a single weld philosophy for piping.

Customised dashboards provided through risk-based data analytics tools can be utilised to provide procurement assurance, quality control tracking/transparency (live-time quality control access), and a foundation for the inclusion of construction and operations data such as commissioning and metrology. The assurance and control findings can be viewed in a ‘virtual’ environment for a full life cycle understanding of the asset construction and operation. Intertek, a Total Quality Assurance provider to industries worldwide, is currently providing quality assurance services for many of the world’s major LNG projects. Such services help to ensure project efficiency, maximise quality, and improve safety – while minimising risk and costs. In addition to the company’s RiskAware analytical tool that provides advanced vendor and supply chain data, this article will also discuss LNG infrastructure and modular construction support (surveying, laser scanning, and dimensional control), as well as quality assurance services and RVI.

Risk-based data analytics

Figure 1. Supplier quality observation dashboard.

Figure 2. Supplier non-conformance summary dashboard.

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The RiskAware analytical tool helps global LNG equipment purchasers to minimise the total cost of quality by using the lens of data analytics to focus on high-impact quality and safety risks in their supply chain. LNG project purchasers require supplier inspection programmes to be efficient and transparent. By using risk-based data analytics to pinpoint risky areas within a quality programme, it is possible to optimise supply chain strategies. Risks arising from delays to production schedules, cost escalation and the late arrival of equipment can be mitigated through robust and proactive quality control programmes. This is complemented by vendor surveillance activities and overall assessment and monitoring of the supply chain suppliers. The programme produces optimised and integrated quality assurance and quality control (QA/QC) activities, which can be achieved most effectively by apportioning vendor inspection spend to higher-risk areas in comprehensive vendor assurance plans. RiskAware provides the data and analysis that enables implementation of risk-based vendor assurance plans that minimise LNG project total cost of quality by avoiding costly and disruptive delays, significant rework costs and non-compliance issues. The cloud-based solution identifies quality and safety risks, which helps companies to optimise their quality and inspection programmes. The programme provides a range of data analytics and reporting. Typically, this data is shown in dashboard format (see Figure 1), highlighting quality observations at hundreds of global suppliers. These observations are used to

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proactively identify issues before they become non-conformances, especially non-conformances that could cause project delays due to the need for rework, repair or replacement. In addition to proactive quality observations, Intertek uses historic and ongoing non-conformance report (NCR) counts (% rate per number of visits), which can then be analysed by country, supplier and NCR categories (see Figure 2). This analysis can be used not only as a historic data-based reference to give a high-level indication of supplier ‘risk’, but also to create risk-based vendor inspection plans.

Quality assurance of LNG modular units For new LNG construction sites receiving components that have been fabricated as single modular units or in different geographical locations, dimensional control (DC) is an essential, accurate and efficient process that will provide

Figure 3. Scanned modular units being joined together using Intertek’s single weld philosophy.

certainty for problem-free fitting, or identifying potential dimensional issues that can be dealt with prior to installation activities. The dimensional control process uses a calibrated total station survey instrument (accuracy 1/32 in.) with a built-in data capture facility to obtain the field data. The Intertek Data Integration Management Engineering System (DIMES) 3D Calculation and Cluster (Bundle Adjustment) software, supported by AutoCAD, facilitates the calculation and deliverable preparations. For LNG modular build and installation, it is important to consider the following: nn Experience shows that if the LNG plant construction philosophy is individual modular units, and a single weld philosophy is applied, this greatly increases the DC surveying scope of work. Building modular trains (as opposed to individual units) is the most cost and schedule efficient method available, and greatly condenses the amount of DC that is required. nn Different fabricators have a variance within their DC experience, knowledge, abilities, instrumentation and software. Often, DC procedures are generic rather than project specific. It is important that the fabricator understands the tolerances and the overall objectives of the project. In addition, when fabricating outside, there can be challenges with the environment including deflection issues from the sun, and temperature expansion and contractions. This should be an area that is well covered within the DC procedure. nn Do the design tolerances for fabrication, construction and installation ‘stack-up’? Do gauge tolerances match bolt-to-bolt hole design clearances? nn The layout of modular datums is very important as they must relate to the structural frame as-built so that the built errors are split out and the best-fit datums are established. It is not practical to just accept that the steelwork is good enough to reference pipe dimensions. A best-fit centre line (longitudinal and transverse) is very important in considering the global picture and not the single unit. nn Depending on the site and modularisation design, pre-installation ‘clash checks’ around the outside parameter of each module would be useful, as this may identify hard clashes or close proximity concerns during the installation stage.

RVI

Figure 4. Intertek’s smart glass RVI solution.

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The COVID-19 pandemic exacerbated the problem of placing inspection personnel into LNG project and fabrication sites. One solution to this is the use of RVI. Intertek has experience working with RVI, and works with a range of smart glasses and augmented reality (AR) technologies. These glasses have several applications, including: nn Supervision: senior inspectors can monitor technical specialists from one location via a video link to maximise their experience and product knowledge, resulting in a more streamlined inspection, and allowing materials to be expedited more efficiently. nn Witnessing: live video stream of inspection and audits are available for clients to remotely attend the

inspection, following the technical specialist and directing them through each inspection step. Clients are able to interact with the technical specialist to ask questions and visualise the experience. nn Evidence: recordings of the inspection process from the technical specialist’s perspective are available to be viewed at a later date by the client. This will allow for a more detailed visualisation of the inspection process and an invaluable enhancement of the auditing process. n Monitoring: in circumstances where the manufacturer agrees, remote inspections can be carried out with cameras positioned at the manufacturing location, with the technical specialist monitoring the activities from a remote location. This could reduce the overhead costs associated with the inspection process (such as travel costs), and would be beneficial for inspections carried out on lower criticality materials and equipment, as well as those with less inherent risk.

Figure 5. Global RVI dashboard.

RVI provides inspection coverage worldwide where travel is either not permitted, or deemed unnecessary for low-criticality and non-complex equipment. Intertek uses an enterprise-ready, agnostic mobile application, which runs on supported wearable and/or mobile devices. This has built-in security features that enable connectivity – even at low

bandwidth – to inspectors, customers and vendors all at the same time, via 3G/4G/5G or Wi-Fi. All users can access virtual rooms, share documents on screen, take photos/videos, and add annotations where necessary (see Figure 3). Hands-free wearable devices are supported and navigated using simple voice commands to control them. Inspections can be recorded where requested if participants are unable to attend in person.

Benefits of RVI technology nn Cost reduction (for auditor or inspector travel expenses). nn Improved auditor and inspector quality of life through reduced ‘burn out’ due to travel. nn Validated audit or inspection integrity: the ability to validate via a recorded or live broadcast session. nn Increased service quality through mentoring: shadow audits and inspections, witness audits, etc. nn Business continuity: audits and inspections can still take place regardless of threat (weather, terrorism, travel delays). nn Solution for clients with remote locations: potential to increase audit and inspection frequency with this approach. When working on a recent global LNG project, Intertek calculated a saving of approximately US$100 000 in travel costs due to the use of RVI technologies. This also contributed to an overall reduction of the project’s carbon footprint. Intertek tracks its global RVI usage and key performance indictors (KPIs) using RiskAware to provide clients and managers with on demand analytical data.

Conclusion There is currently tremendous worldwide investment in LNG and LNG facilities. The COVID-19 pandemic has highlighted the potential dangers and risks associated with these large

capital projects. These risks include materials, personnel and regional supply chain issues. Intertek has provided quality assurance services for many of the world’s major LNG projects. As such, the company has developed a range of quality risk mitigation tools for the efficient and successful completion of such projects. The use of data analytics is key to identifying the risks related to manufacturers, vendors and regional supply chains. Understanding and managing these risks goes a long way in ensuring that projects stay on schedule. Many LNG facilities are constructed as modular units, often coming from different geographical locations. As such, it is essential to understand dimensional tolerances and the use of the latest DC equipment and software tools. DC is an accurate and efficient process that provides certainty for problem-free fitting and identifying dimensional issues that can be dealt with prior to installation activities. Finally, the shortage of qualified personnel, travel and access issues have highlighted the need for RVI to ensure project and equipment quality. RVI and testing complete a thorough risk-based quality assurance programme that ensures LNG project efficiency, maximises quality, and improves safety, while minimising project risk and costs.

Reference 1.

‘Rising Calls for U.S. LNG Revive Stalled Export Projects, but at Higher Costs’, MarineLink, (21 April 2022), https://www.marinelink. com/news/rising-calls-us-lng-revive-stalled-export-495962

LEADING THE WAY TOWARDS LNG SAFETY Alec Cusick, Owens Corning, USA, details a passive approach to mitigating pool fire risk at LNG facilities.

he risks of a spill or fire occurring are continuous for facilities that work with or store combustible materials such as hydrocarbons and LNG. Having flammable liquids onsite means that the potential for spills and fires is always present, posing a risk to facility employees, equipment and neighbouring areas. These concerns have led to the formation of regulations and organisations that are focused on site safety, including the US Federal Energy Regulatory Commission (FERC), the Pipeline and Hazardous Materials Safety Administration (PHMSA), and the National Fire Protection Association’s standard 59A – Standard for the Production, Storage and Handling of Liquefied Natural Gas (LNG).1 By preparing for the occurrence of a spill, and having safety measures designed and installed – such as a passive spill and fire response system – safety and facility teams can help mitigate some of the risks involved in managing LNG plants.

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Priorities during LNG spills When planning mitigation strategies for spills of LNG or other hydrocarbons, there are some key objectives that should be prioritised to help avoid potential disaster. These include reducing vaporisation of spilled liquid hydrocarbons and limiting the radiant heat of any fires that occur. Should LNG or another flammable cryogenic liquid spill, the material will heat as it is exposed to the comparatively-warmer ground and air, along with solar radiation. As material warms it releases invisible, flammable vapours which can ignite when combined with a spark. Because the gas is only flammable at certain concentrations

Figure 1. Passive response systems remain in place, ready to self-deploy in the event of an LNG spill.

(approximately 5 – 15%), it can travel downwind before igniting. However, as the flammable gas that is generated can also catch fire over the spill pool, reducing the rate of vaporisation fits together with another priority – limiting thermal flux. If a fire occurs following a spill, this becomes the most significant source of heat gain for the spilled material, which increases the rate of vaporisation. Limiting heat gain back into the spilled liquid helps reduce how much fuel is available to burn. When the fire is located over the spill pit, it can allow for a self-propagating cycle to perpetuate as the fire feeds heat into the liquid. This creates more flammable gas which, in turn, feeds the fire. Standards have been established to address safety onsite and in neighbouring locations. One example is the National Fire Protection Association’s 59A, the Standard for the Production, Storage, and Handling of LNG.1 This standard can be used to establish requirements for exclusion zones around a facility, and inform site layout. Addressing regulatory requirements can be difficult and expensive when facilities have small site footprints, or when they try to expand without adding an external area. While this standard could potentially be cited as grounds for denying regulatory approval of a facility, it does account for the use of passive fire mitigation methods installed when determining how much of an exclusion area is needed. Final approval will be subject to the agency that has jurisdiction on the location.

Mitigation system considerations Should a spill and/or fire occur at an LNG or hydrocarbon storage and processing facility, there are several types of active and passive response systems that can be deployed. An appealing aspect of a passive response system is that there is no delay in its deployment, and no human or mechanical action is required to activate it. Once installed, a passive response system is intended to remain in place long-term, with minimal maintenance. Active systems, such as fire-extinguishing foams, need to be triggered in an emergency prior to activation, potentially by sensors or an employee. Additionally, many active systems may require higher levels of regular maintenance, much like a fire extinguisher needs to be checked for charge and function, and may need to be refilled or replaced. Often, passive and active response systems can be integrated, providing a combined response should a spill occur.

Implementing a passive response system

Figure 2. In the event of a pool fire, the passive pool fire suppression system works as a single unit to reduce radiant heat and flame height.

August 2022 32 HYDROCARBON ENGINEERING

A passive response system has been designed that is specifically focused on limiting radiant heat and flame height in the event of a spill and/or fire occurring. The patented system – FOAMGLAS® Pool Fire Suppressant (PFSTM) Gen 2 – is designed to

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rest within a spill pool and wait until a spill occurs before self-deploying. In the event of a spill, the system creates a non-combustible insulating cap that floats to the top of the spilled, flammable liquid, creating a barrier between the liquid and solar radiation or other heat sources. The system is comprised of a series of individual blocks of cellular glass insulation wrapped in a silicone adhesive coating and cladded in stainless steel. Once in place, the blocks are linked together using a series of metal bridges, allowing the individual elements to work as a single unit. The system is customised to meet the dimensions of individual spill pits; however, it is easy to install. The passive safety system makes use of the unique properties of cellular glass insulation. An inorganic substance, the material does not burn, spread fire, or generate smoke, and it is non-combustible. The insulation is also impermeable and non-absorbent when exposed to liquids – including hydrocarbons. Should a fire occur over the spill pit, the insulating blocks have been found to help protect the spilled liquid from the heat that has been generated, reducing vaporisation and flame height.2 Flames also pose a danger to nearby piping and equipment, especially in sites with limited space. As temperatures increase, piping that contains LNG or a similar liquid runs the risk of exploding when the liquid heats and expands into a gas. Additionally,

Figure 3. The difference in measured radiant heat flux from the capped (lower) and open (upper) spill pits.

Figure 4. Individual blocks are connected to create the floating cap.

August 2022 34 HYDROCARBON ENGINEERING

structural steel can begin to lose its strength from rapidly increasing temperatures, upon reaching about 315.56°C (600°F), and loses approximately 50% of its load bearing capacity when heated to 593.3°C (1100°F).3 This has the potential to add additional fuel to the fire if the structural elements that have been damaged are supporting spheres or other storage tanks holding volatile materials. An insulating layer in place at the top of the spill pit helps to reduce flame height and radiant heat flux. Additionally, the floating response system can be paired with other active safety measures, including fire-suppression foams. System testing was completed by Resource Protection International (RPI) on behalf of Total Oil Co. at Centro Jovellanos in Asturias, Spain.2 The examination checked for the effectiveness of vapour control and reduction in heat flux. A 4 m2 containment pit equipped with a series of radiometers at each corner was flooded with 1.5 m3 of LNG and ignited. The pit was allowed to burn for 30 minutes, and then extinguished. The heat flux ranged from 3 to 8 kW/m2. After the passive safety system was added to the pit, it was refilled and reignited. With the cap in place, thermal flux was measured below 1 kW/m2. Additionally (although this is an atypical practice), upon conclusion of the test, the pit fire was controlled enough to be extinguished by a person in the correct personal protective equipment (PPE) walking up to the edge of the pit and using a dry chemical spray. To look at the response provided in terms of the reduction in vaporisation, consider the following scenario: a containment pit measures 4.57 m x 4.57 m x 3.05 m (15 ft x 15 ft x 10 ft) with 15 cm (6 in.) concrete walls; a ground temperature of 20°C (68°F); an air temperature of 24°C (75°F); spilled LNG at -160°C (-256°F); and a heat of vaporisation of 512 kJ/kg (220 Btu/lb). In an unprotected pit, total heat gain is 32.5 kW (31 Btu/sec.) and the boil off is 3.81 kg/min (8.4 lb/min). However, if an insulating cap is in place on top of the spilled LNG then the total heat gain falls to 9.04 kW (8.6 Btu/sec.) with a boil-off rate of 1.06 kg/min (2.34 lb/min). This amounts to approximately a 72.2% reduction in heat gain and boil off, limiting the amount of fuel for a potential fire.4

Case study – the JAX LNG facility Passive safety systems such as the FOAMGLAS PFS Gen 1 and Gen 2 have been installed across a range of facilities around the globe, including in Barbados, Singapore, France, Australia, Korea and the UAE. Additionally, a system was recently selected and installed for the JAX LNG facility near Jacksonville, Florida, US. Opened in 2018, the facility has an onsite LNG storage capacity of 7.6 million l (2 million gal.), and a liquefaction capacity of 454 000 l/d (120 000 gal./d), both of which will increase when Phase II is completed later in 2022. The facility is a joint venture (JV) between Pivotal LNG – a BHE GT&S company – and NorthStar Midstream. The combination of the facility’s small site size and expanding storage and production led to regulatory considerations in the event of a spill and/or fire. To help mitigate these concerns, a passive safety system in the form

of the PFS Gen 2 system was added to a large spill containment pit onsite. “The end goal of having the safety system in place is never to use it,” said John Morrison, LNG facilities Maintenance Coordinator at JAX LNG. “The installed system functioned well – we liked what we saw with the test,” he added. To install the passive safety system, measurements were taken of the spill pit, and a design of how best to fill the space given the dimensions and obstructions – such as ladders or pipes – was determined. All of the coated and covered insulation blocks were shipped to the site, ready to be installed using the provided bridging and connection materials. On the edges of the system, metal flashing was added to help reduce gaps between the edge of the blocks and the pit wall. Sometimes a system has the opportunity to demonstrate its usefulness before it is actually required to perform. Although unintentional, installers at JAX LNG saw how well the system floated early in the installation process. When only a few rows of the blocks had been moved to the pit and connected, heavy rains left standing water in the space, which lifted and moved the blocks, providing a minor demonstration of how the whole system is designed to work in the event of an emergency. Once the entire series of blocks is installed, there is far less room for block movement other than up and down. The system is low maintenance, but it is encouraged that standing water should not remain in the spill pit and any debris that falls on top of the buoyant cap should be removed. At JAX LNG, the passive system was complemented by a foam suppression system.

Conclusion The goal of having emergency measures in place to address a spill is to never need them. However, the handling and storage of flammable liquids means that spills and fire risk must always be considered. Having passive fire mitigation systems in place provides a long-term, always-ready response if a spill should occur. Using a system such as the FOAMGLAS PFS System Gen 2 helps to address the priorities created during an emergency by rising to the top of any spilled LNG and insulating it from external heat sources. This passive approach helps to reduce the rate of vaporisation, and limits thermal flux and flame height in the event of a fire, helping to address facility safety.

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References 1.

2. 3.

‘Standard for the production, storage, and handling of liquified natural gas’, National Fire Protection Association (2019), (NFPA 59A – 2019), retrieved from https://www.nfpa. org/codes-and-standards/all-codes-and-standards/list-ofcodes-and-standards/detail?code=59A ‘Vapor & Fire Control Testing of FOAMGLAS® PFS System (Gen 2) on LNG’, Resource Protection International, (2014). Steel Solutions Center. (2022). 11.2 Steel Exposed to Fire. American Institute of Steel Construction (AISC), https://www. aisc.org/steel-solutions-center/engineering-faqs/11.2.-steelexposed-to-fire/#9370 Internal trials and calculations (2014).

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Klaus Brun, Elliott Group, USA, explores the different technology options for hydrogen compression.

he hydrogen economy is a critical part of the trend toward the decarbonisation of the energy sector. Major energy infrastructure changes are required to meet the production, transportation, storage and usage needs for a functioning hydrogen economy. This includes the need to develop compressors that are very different from the types currently used. For hydrogen to be a viable energy carrier, compressors must operate efficiently and reliably. Most importantly, they must be economically-viable.

Hydrogen compression The compression applications in the hydrogen value stream depend on the type of hydrogen. Specifically, green hydrogen from renewable energy sources is mostly produced August 2022 36 HYDROCARBON ENGINEERING

at low pressures using electrolysis, and must be compressed, whereas grey/blue/black hydrogen often exits the production process at elevated pressures and requires less compression in order to enter into the pipeline transportation stream. In the near and mid-term future, for economic reasons, it is unlikely that green hydrogen will be a significant contributor to the hydrogen economy or the initial transport, storage and distribution infrastructure. Usage infrastructure will likely rely on blue or grey hydrogen from fossil fuel source conversion. This assumption defines and limits the operating conditions for hydrogen transport to pressure levels/ratios required by pipeline and storage operations, which tend to be between 1000 – 2000 psig, with a compression ratio of 1.5 – 3.0, respectively.

Different types of commercially-available compressors can be used for industrial hydrogen compression. However, the requirement for rugged and reliable operation with large volume flows realistically limits the selection to centrifugal compressors for most pipeline transport applications. Centrifugal compressors have been used for decades for hydrogen compression, albeit for vastly different applications – mostly in the downstream refinery processes.

Compression thermodynamics There are several common metrics that are indicative of a compressor’s ability to perform a desired duty: n The compression ratio or pressure increase.

n The enthalpy difference across the machine (head), which is basically the fluid energy rise per unit mass across the machine. n The comparison of secondary performance parameters such as shaft power required or isentropic/polytropic efficiencies, which relate work input to hydraulic work. Euler’s turbomachinery equation determines a centrifugal compressor’s head or enthalpy difference, measured in energy per unit mass. It relates aerodynamics (velocity vectors) to thermodynamics (head and power). In its simplest form, Euler’s equation states that the head rise in a compressor is proportional to the angular velocity squared, multiplied by the tip radius squared of the HYDROCARBON 37

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The limit of head production in a centrifugal compressor is the mechanical limit of impeller tip speed, as well as the speed of sound of the compressed gas. The speed of sound in hydrogen is about three times higher than for methane. Therefore, if material limits can be overcome to allow for higher tip speeds, each impeller stage can produce significantly higher head per stage than current machines – in theory. An equation of state of the gas can determine volume ratio, density ratio, and volume reduction across a centrifugal compressor based on the suction and discharge conditions, which behave somewhat linearly with the pressure ratio. This provides reciprocating compressors with a slight advantage. Since they are positive displacement machines, their volume ratio across the machine is determined by the piston stroke volume displacement in the cylinder, which is driven purely by geometry. Although reciprocating compressors require fewer compression stages and can achieve high compression ratios with small machines for light gases, they are flow limited by the cylinder geometry and valve flow choking, and their specific compression power is similar to that of a centrifugal compressor. It is very important to emphasise that the power consumption per mass of gas (i.e. the head) required for a given pressure ratio is independent of the compressor type and method (except, to a small degree, for a possible difference in efficiency). In other words, a reciprocating compressor does not reduce the fundamental power consumption for hydrogen compression of a given mass flow. Finally, a basic aerodynamic blade design can determine the efficiency of a compressor, and can be optimised for any type of gas. As such, there is no reason that a centrifugal compressor cannot be designed to operate efficiently for a light gas. This has been demonstrated by Table 1. Hydrogen compression applications and expected typical pressure hundreds of centrifugal ratios compressors that operate Hydrogen compression applications Pressure (psi/bar) Expected typical efficiently in hydrogen service pressure ratios and, more specifically, in Pipeline recompression 1400/96.5 1.2 – 1.5 petrochemical and refinery Header station (electrolyser, steam reformer, 2.0 – 6.0 applications. There are many gasifier) to pipeline pressure or liquids plant other operational reasons that Fuel supply to power plant: a centrifugal compressor is preferable for hydrogen 1.5 – 3.0 - Gas turbine combustor pressure from reformer 500+/34.5+ compression, such as the 7000 – 14 000/843 – 965 10+ - Storage tank pressure avoidance of process gas contamination with lube oil, Table 2. High-speed vs low-speed compressors reduced environmental leakage, no piping pulsation or Compressors Tip speed impellers Pressure ratio No. of impellers vibrations, and lower overall Conventional compressor: 1200 fps maintenance costs. 2.5 40 (4 – 5 casings) - Electrolyser to pipeline Most hydrogen 1.3 8 (1 – 2 casings) - Pipeline recompression compression services can be 2.0 30 (3 – 4 casings) - CGT fuel gas compression achieved using either centrifugal or reciprocating High-speed compressor: 2400 fps compressors. Centrifugal 2.5 10 impellers (2 casings) - Electrolyser to pipeline compressors are head limited 1.3 2 impellers (1 casing) - Pipeline recompression and may require many stages 2.0 8 (2 casings) - CGT fuel gas compression and cases in a series for higher

compressor (assuming radial blades and no slip). It should be noted that there are no fluid properties such as density or viscosity in this equation. This means that the theoretical head rise of a compressor is identical for a light gas such as hydrogen, and a heavy gas such as carbon dioxide. Specifically, for a given centrifugal compressor geometry running at a fixed speed, the head rise of the machine is identical if the compressor runs on hydrogen or any other gas. The energy input per unit mass into these gases is independent of their density or specific gravity. However, light gases, by definition, have low densities, and therefore the energy input for a lighter gas per unit volume or volume flow (e.g. ACFM) is much lower in any compressor. Pressure ratio can be related to temperature via the isentropic relationships, and temperature is related to head by the definition of enthalpy (specific heat multiplied by absolute temperature). It can be shown algebraically that the most important explicit fluid property that thermodynamically (inversely) relates pressure ratio to head is the specific heat. The isentropic coefficient also relates head to pressure ratio, but is a weaker function. This is the fundamental difference between compression effectiveness of hydrogen vs heavy gas in centrifugal compressors. Hydrogen has a high specific heat value which results in low compression ratios. For example, the specific heat of hydrogen at room temperature is about six times higher than that of methane, which when plugged back into the isentropic relationships results in a pressure ratio several hundred times higher for methane than for hydrogen (assuming the same head from Euler’s equation). Since pressure increase is a simple function of pressure ratio, light gases result in low pressure increases in centrifugal compressors.

August 2022 38 HYDROCARBON ENGINEERING

pressure ratios, while reciprocating compressors are flow limited and will require many cylinders or compressors in parallel. The choice between centrifugal and reciprocating compressors requires consideration not only of pressure/flow conditions, but also operating economics such as maintenance, reliability, and availability.

Compression applications When designing the infrastructure for the hydrogen economy, there are several obvious compression application duties. Table 1 shows the most important items with their expected pressure ratio range. Depending on the size of the hydrogen-producing source, the flow rate of these applications can vary widely. From Table 1, it is clear that most high-volume hydrogen compression applications fall into a pressure ratio range between 2.0 – 3.0. The types of compressors usually considered for hydrogen are reciprocating, screw, centrifugal barrel, centrifugal horizontally split, and integrally geared. Since both reciprocating and screw compressors are severely flow limited, they cannot be practically used for large-scale hydrogen applications. The remaining technology options all rely on proven centrifugal compressors, but use different layouts and stage arrangements. The focus here will be on centrifugal barrel compression since it shows the highest potential for large industrial-scale, reliable, and low-cost hydrogen compression.

Centrifugal compressors in hydrogen compression applications The physical properties and flammability of hydrogen poses special technical challenges for centrifugal compressors in hydrogen compression applications. Although hydrogen is processed in many industrial applications, most hydrogen compressors are found in refineries for hydrotreating, hydrogen plants, and hydrocracker applications. Within these refinery applications, feed gas, recycle, net gas, and booster compressors compress hydrogen over a wide range of pressures and flows. Other hydrogen compressors are found in gasification, electrolysis, and many chemical and petrochemical plants. Compressing hydrogen presents four major technical challenges: nn It is an extremely light gas. nn It can cause hydrogen embrittlement in ferrous alloys. nn Hydrogen molecules are very small, making sealing and containment difficult. nn There are safety issues because of its explosivity, low auto-ignition temperature, and wide flammability range. Light or low molecular weight gases are difficult to compress, and result in a low head rise per centrifugal stage in the compressor. Even at relatively high impeller tip speeds of 350 m/sec., typical pressure ratios per stage seldom exceed 1:1. For rotordynamic reasons, there are finite limits to shaft length in any compressor. Centrifugal compressors can mechanically fit a limited number of stages per casing – usually no more than 10 – 12. Additionally, the impeller and shaft material must have sufficient strength while being light enough to minimise hoop stresses at high rotational speeds.

For example, Table 2 shows a comparison of the number of impellers and cases required for the previously discussed application case (in Table 1) for conventional compressors with tip speeds of around 1200 fps vs novel, high-speed impellers operating at twice this speed. Theoretically, impellers with very high tip speeds above 2000 fps are possible by using non-metallic materials, magnetic or gas bearings, and special seals. Shaft and impeller material can include titanium alloys, continuously-wound carbon fibre, and ceramics. For example, a continuously-wound carbon fibre shaft has high torsional strength and a quarter of the density when compared to a steel shaft. Similarly, Figure 1 shows a novel, high-speed compressor impeller made from light, high-strength, directionally-wound carbon fibres that has the potential to operate at tip speeds exceeding 2000 fps. To summarise, the greatest challenges for high-speed hydrogen compression are: nn The need to utilise materials that are not commonly used for turbomachinery. nn The design of impellers that can handle very high hoop stresses. nn The utilisation of seals and bearings at speeds where they have limited operational experience. nn The use of high-speed drivers and gears for speeds beyond 50 000 rpm. Unfortunately, most of this technology is currently in the development stage, and is not practical for rugged industrial applications that require very high reliability, such as pipeline or storage service. There are some critical research gaps that must be addressed before this technology can be applied commercially. More conventional compression technologies will have to be utilised, as this technology is not ready to be deployed on an industrial scale in the foreseeable future. As a result, with currently-available impeller technology, long compression trains with many stages per casing are required if a significant hydrogen pressure rise is needed.

Figure 1. Directionally-wound carbon fibre compressor impeller.

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Hydrogen embrittlement is a metallurgical interaction between ferrous metals and hydrogen gas at certain pressures and temperatures that can lead to rapid yield strength deterioration of the base metal in the compressor. In order to prevent hydrogen embrittlement, API specification 617 limits materials in the hydrogen gas service to those with a yield strength less than 120 ksi or a hardness of less than 34 HRC. This material yield strength limits the maximum allowable speed of a given impeller. As noted, this issue can be addressed with high-head impellers, and by using alternative materials with higher strength-to-density ratios – but these technologies are not yet mature. Additionally, special surface coatings are available to

minimise exposure and direct penetration of hydrogen into the metal as shown in Figure 2. However, as a safety precaution, current design practices limit the design yield strength of the exposed alloys to below 827 MPa. This further limits the operating speed of the compressor and its pressure rise per stage. Finally, hydrogen molecules are small compared to most hydrocarbon gases, which makes casing end and inter-stage sealing challenging. Most hydrogen compressors utilise tandem dynamic dry gas seals and multiple static O-rings to minimise leakage flows. Nonetheless, hydrogen detection and scavenging is often required to minimise the risk of hydrogen exposure to the atmosphere and the associated explosive hazards.

Practical hydrogen centrifugal compression solutions Elliott developed the Flex-Op® compression arrangement to improve the head, flow, reliability, and operational flexibility capabilities of hydrogen compressors, as shown in Figure 3. This arrangement is comprised of four compressors on a single gearbox. This was originally designed for high-pressure ratio and high-flow compression, however, this arrangement has the flexibility to allow individual compressors to run in series or parallel (or both). As previously noted, hydrogen compression requires a large number of compression stages to achieve a reasonable head. With up to four casings, more than 40 impeller stages can fit into a linear footprint that traditionally only fits 10. This shrinks the linear footprint of the compressor section from upwards of 40 ft to roughly 10 ft. Flex-Op can utilise the four compressor casings in ® parallel or series, with multiple extractions and side Figure 2. Specialty Pos-e-Coat hydrogen compressor coating developed by Elliott. streams. As each rotor is connected to its own pinion via a flexible shaft coupled to the central gear, the rotor speeds can be individually-optimised for the highest aerodynamic efficiency. A barrel casing coupled with a single, multi-pinion gearbox allows the whole assembly to be powered by an electric motor with a variable frequency drive, a variable speed drive motor, a steam turbine, or a Figure 3. Flex-Op compressor arrangement with four individual centrifugal compressors mounted to a single, multi-pinion gearbox. single/two-shaft gas turbine. Figure 4 shows two of these possible arrangements. In addition to this, engagement/disengagement of individual compressors is possible for additional operational flexibility if clutch or torque converter couplings are implemented at the compressor shaft ends. The casing arrangement allows it to operate Figure 4. Flex-Op compressor arrangement with an electric motor drive with a in parallel for high throughput, or variable frequency drive or an electric motor variable speed drive. in series with intercooling August 2022 40 HYDROCARBON ENGINEERING

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between bodies for the highest pressure ratios. Finally, the arrangement provides easy access to all four compressors for maintenance and repair using a single mezzanine or platform and crane. The Flex-Op compressor arrangement offers a practical solution for most industrial hydrogen compression applications in the hydrogen transport and storage sectors. It is rugged and reliable and relies on proven and experienced industrial compression and gear technology that has been previously utilised in hundreds of hydrogen compression applications. Unlike many novel compression solutions that are currently under development for hydrogen, its arrangement components are all designed within well-known industrial operational limits and are commercially-available.

Case study: hydrogen To review the applicability of the Flex-Op arrangement, a basic case study for a typical hydrogen transportation application was analysed. The operating conditions were: nn Pressures: 365 psig inlet to 1015 psig discharge (2.78 pressure ratio). nn Flow: 240 000 kg/d. nn 100% hydrogen. The results of the study showed that this case could be handled by a Flex-Op compressor arrangement with four casings and a total of 36 impeller stages. Intercooling would be required between the second and third compressor

casing. Specifically, the resulting compressor would operate as follows: nn Speed: 15 000 rpm. nn Power: 7500 HP. nn Intercooler between body 2 and 3. nn 4 x 15MB9 casings. The low-risk Flex-Op compressor design that utilises conventional compressor and gear technology is capable of handling this operationally-challenging hydrogen compression application.

Conclusion The hydrogen economy requires the utilisation of compressors that are different to those that are currently used in industrial applications. For applications such as pipeline, storage and feed compression, hydrogen compressors that can reach compression ratios between 2.0 – 3.0 are required. There are several complex challenges that must be addressed when designing compressors for these applications, including light gas head rise, static and dynamic sealing, explosive safety, and material compatibility. There is significant technology development underway to design high-speed centrifugal compressors that are optimised for hydrogen compression, but this technology is not yet near maturity. Alternatively, a more conventional solution, such as the Flex-Op compression arrangement, can provide the required compression duties by utilising compressor and gear technologies that are proven and currently available.

Luiz Soriano and Dave Winquist, Siemens Energy, USA, consider how to maximise reciprocating compressor efficiency.

ndustrial operators are under intense pressure to reduce carbon dioxide (CO2) emissions and improve sustainability. Transitioning away from conventional energy sources to low-carbon alternatives is often viewed as the primary means of achieving these goals. However, reducing the energy required to operate equipment by increasing efficiency continues to be one of the fastest and most cost-effective means of decarbonisation. While the downstream oil and gas sector has made progress on this front, significant opportunities still exist to enhance the energy efficiency of key processes, particularly those that rely on power-intensive equipment, such as compressors. By using high-efficiency compressors, operators can reduce the total energy consumption of their plant and associated emissions. Siemens Energy recently authored an article in the May 2022 edition of Hydrocarbon Engineering which highlighted the role that compressors play in decarbonising downstream processes.1 Whereas that article focused on the use of compressors in hydrogen service, this article will go one step further by discussing important design attributes of process reciprocating compressors, and the impact that they have on energy consumption during operation.

Compressor operating requirements Process reciprocating compressors are designed according to the API 618 standard, and have historically been applied in mission-critical refinery and petrochemical processes (see Figure 1). To minimise the risk associated with unplanned shutdowns and resulting loss of revenue, many original equipment manufacturers (OEMs) and end users have prioritised metrics, such as availability/uptime and mean time between failures (MTBF), over efficiency during the design process. In today’s market, however, there is an increasing demand for compressors in green hydrogen production facilities, which have a completely different operating philosophy than a refinery. Although loss of revenue remains a top concern, most hydrogen production plants run intermittently and at partial load, for extended periods of time. For the purposes of this article, all design comparisons will be based off a reciprocating compressor in an application with the following process parameters: n Compressor model: HHE-VL process reciprocating compressor. n Application: hydrogen. n Suction pressure: 345 psig. n Discharge pressure: 1100 psig. n Suction temperature: 110˚F. n Flow: 12 000 lb/hr. n Gas: 100% dry hydrogen. n Rated power: 3430 kW. n Operation: continuous – 8000 hr/yr. 4000 hr at 100% load; 2400 hr at 75% load; 1600 hr at 50% load. HYDROCARBON 43

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Capacity control Capacity control is critical to reciprocating compressor energy efficiency as it enables end users to compress only as much hydrogen as is needed. Today, there are several capacity control systems available for process reciprocating compressors, each with different CAPEX, OPEX, and

turndown capabilities. Table 1 describes the most common systems, sorted by their potential to save energy. Improper selection of the capacity control system will ultimately impact the operator’s ability to adjust capacity and meet demand, therefore wasting energy and increasing CO2 emissions. This is particularly the case if the power for compression is not generated from a low-carbon energy source.

Operating pattern

Figure 1. API 618 process reciprocating compressor, HHE-VG class.

Deciding what type of capacity control system to use is highly contingent on the operating pattern of the compressor. The compressor unit defined in this article’s case study has two partial load scenarios. Based on this, the following capacity control systems were selected (see Figure 2): nn 75% step with fixed volume clearance pocket installed on the head end of both cylinders. When the system is active, the cylinder clearance on the head end will be increased, therefore reducing flow through the cylinder. nn 50% step with valve unloader system installed on the head end of both cylinders. When the system is active, the unloaders will open the head end of the cylinder to the suction side and compression cannot occur, as there is no volume reduction of the gas. Table 2 describes the required power for each of these operating cases. The lack of a capacity control system altogether would cause the operator to spend 50% of its annual operating time recycling the hydrogen gas through the compressor, leading to substantial wasted energy and higher CO2 emissions as a consequence. It should be noted that speed control is also an available option for capacity control. However, it is not typically used for process reciprocating compressors because the compressors operate at ‘slow speeds’. As a result, turndown capabilities are limited.

Compressor valves Valves are another critically-important attribute to consider when it comes to reciprocating compressor efficiency. Loss of pressure across the valves is one of the major sources of wasted energy during operation. Minimising losses requires engagement early in the design phase so that the OEM has a clear

Figure 2. Head end fixed volume clearance pocket.

Table 1. The most common capacity control systems available for process reciprocating compressors System

Objective

Turndown capability

Acquisition cost

Energy savings

Stepless capacity control system

Controls flow by delaying suction action

Infinite (100 – 30%)

$$$$

Variable volume clearance pockets2

Reduces flow by adding cylinder clearance

Infinite (100 – 55%)

$$$

Fixed volume clearance pockets

Reduces flow by adding cylinder clearance

Pre-defined fixed steps (100 – 55%)

Valve unloaders

Unload cylinder end by opening cylinder end to inlet side

Pre-defined fixed steps

Recycle

Recycle gas across compressor through recycle line

Infinite (100 – 0%)

No energy savings

August 2022 44 HYDROCARBON ENGINEERING

Table 2. Required power for each operating case understanding of all process conditions and operating cases, Case Required Capacity Power including during non-normal or upset scenarios. power (kW) (kg/hr) consumption (%) Once the compressor operating pattern has been Design (full) 3084 5611 100 defined, it is possible to design a valve that meets the expected performance during the normal envelope of 75% step 2315 4205 75.1 operation, while guaranteeing acceptable performance under 50% step 1533 2770 50.4 all other circumstances. There are several factors that will impact valve efficiency during operation. It is not the objective of Table 3. The impact of the different EFAs on overall power consumption this article to address them all. During the design Difference Valve EFA/end Pressure drop Power phase, however, one important task is to guarantee (%) consumption at selection (in.2) across valve proper effective flow area (EFA) of the valve. EFA is design (kW) (%) defined as “the equivalent area of the gas flow path Best fit 9.66/6.10 2.4/1.5 3084 0 through the valve if considered as a single hole/orifice”. For the reciprocating compressor in this article’s Undersized 7.90/4.62 3.6/2.5 3131 1.5 by 1 in.2 case study, Siemens Energy considered poppet style valves with three different EFAs. The impact of the 3253 5.5 Undersized 6.10/3.30 6.0/5.0 by 2 in.2 different EFAs on overall power consumption is shown in Table 3. Different valve designs can have very different EFAs. the field of motor technology over the last decade have Siemens Energy recommends the magnum valve (see Figure 3) enabled increases in overall efficiency – normally above 95% for its process reciprocating compressors in low molecular for most applications. However, there are still important weight applications, which is a poppet style valve. The decisions that must be made when it comes to the type of magnum valve has industry-leading performance and millions motor that will be used. Synchronous motors are more of operating hours in highly-demanding applications. efficient than the induction equivalent by around 1 – 2%. This difference in energy efficiency can become significant as the rated power of the compressor increases. Driver selection In North America, the industry rule-of-thumb is to apply Typically, process reciprocating compressors are driven by synchronous motors for compressors with rated power slow, fixed-speed electric motors. Several developments in

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above 1500 kW. There are other advantages to consider when using a synchronous motor, such as lower utility fees through reduced peak demand, no power factor penalty, increased system capacity, and increased voltage levels in the electrical system. For this case study, only the efficiency of the motors was considered, without any supporting power factor correction equipment, such as additional capacitor banks. While these would help to reduce OPEX associated with the induction motor, it would result in higher CAPEX. Forward-looking design decisions can help mitigate both CAPEX and OPEX of the motor selection. Regional preferences and experience of the operator with a particular motor design may also influence the selection process. With a power demand of 3085 kW at 100% load, the compressor in the case study would require a main driver nominally rated for 3430 kW per API 618 5th edition. Using this rating, an efficiency comparison of synchronous vs induction motor can be made, and was considered in this instance.

Summary of cost and emissions reductions Considering all of the compressor design attributes discussed in this article, along with the motor design, the

difference in energy costs and CO2 emissions between a hypothetical worst and best-case compressor design scenarios can be considered. A summary of these results is presented in Table 4 (see notes at the bottom of the table). As can be seen from Table 4, the energy consumption in the best-case scenario is 23.5% lower than the worst-case scenario. This would translate into more than US$500 000 in annual monetary savings for the end user. In addition to this, a total of 2560 t of CO2 would be avoided during the same period, which is equivalent to annual CO2 emissions from 630 passenger vehicles.4

Other considerations Although the design attributes discussed in this article constitute major contributors to compressor energy efficiency, several additional factors should be addressed during the design phase which were not discussed. Among these include: nn Efficient design of the pulsation dampener system that allows for reasonable pressure drop. nn Pressure packing design that optimises leakage rates. nn Jacket and packing coolant system that ensures sufficient heat transfer during operation – without parenthesis. Minimum hardware solutions are always preferred; however, there may be specific applications where capacity control is best achieved by multiple smaller units with on/off functionality. Depending on the operational pattern intended, this could result in a configuration that is more energy efficient.

Conclusion

Figure 3. Dress-Rand magnum valve. Table 4. Summary of cost and emissions reductions

While the latest report issued by the Intergovernmental Panel on Climate Change (IPCC) indicates that real progress is being made on the fight against climate change, we are still far from the Paris Agreement target of keeping global warming under 1.5˚C by the year 2100.5 Immediate actions are required to collectively reduce CO2 footprint, including an accelerated shift towards low-carbon energy sources. Enhancing the energy efficiency of processes and equipment will also be an important contributor, providing the added benefit of lowering electricity spend.

Factor

Unit of measurement

Best case scenario

Worst case scenario

Required power for compression

kWh

20 344 800

24 672 000

Valve efficiency

100

94.5

Motor efficiency

96 synchronous

94 induction

Total power consumption

kWh

21 192 500

27 437 196

Energy cost

US$

1 517 383

1 964 503

References 1.

Demand charge

US$

142 800

205 779

Total energy cost

US$

1 660 183

2 170 282

Total CO2 emission

8689

11 249

Assumptions are as follows: - US average electricity cost for industrial use = US$0.0716/kWh3 - Average CO2 emission from non-renewable source = 0.41 kg/kWh4 - Demand charge = US$42 KVA/yr

August 2022 46 HYDROCARBON ENGINEERING

‘The Role of Compression in Downstream Decarbonisation’, Hydrocarbon Engineering, (May 2022), pp. 23 - 26. ‘Variable capacity control technology facilitates efficient operation for reciprocating compressors’, Hydrocarbon Processing, (March 2020). US Energy Information Administration, www.eia.gov US Environmental Protection Agency, www.epa.gov Sixth Assessment Report of the Intergovernmental Panel on Climate Change, Working Group II Contribution, March 2022, https:// www.ipcc.ch/report/ar6/wg2/

Nabil Abu-Khader, Compressor Controls Corp. (CCC), UAE, explains the effect of a proactive recycle trip response in antisurge control.

ompressor Controls Corp. (CCC)’s coordinates for antisurge control take into consideration the reduced flow squared, q2sr vs the reduced head, hpr or compression ratio, Rc. The distance between the operating point and the surge control line (SCL) of a centrifugal or axial compressor is called the deviation (DEV). Typically, once DEV becomes negative, antisurge controllers

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start to open antisurge valves in order to avoid going into surge. This article discusses the effect of the proactive recycle trip (RT) response, which acts on the antisurge valve even if the DEV is still positive.

The relationship between DEV and proximity to surge (Ss)

Figure 1. Antisurge control lines within a typical antisurge controller.

The proximity to surge distance is a function of compression ratio, flow rate, rotational speed, guide vane angle, as well as gas pressure, temperature, and composition. To develop the invariant coordinate space, the reduced flow squared, q2sr is normally used in the X-coordinate. As a CCC rule of thumb, if the gas composition and gas parameters remain reasonably constant, then it is possible to further simplify the Y-coordinate in the invariant coordinate space to be the compression ratio, Rc. But if the gas composition and gas parameters change dramatically, then reduced head, h pr should be used in the Y-coordinate. Within this ‘non-dimensional’ coordinate space, the angular distance between the operating point and the SLL, SS, can be calculated as per equation 1: SS = Slope OPL⁄SlopeSLL

(1)

Where:

Figure 2. An example of a running standalone compressor train.

SlopeOPL is the slope of the operating point line in the compressor map, and SlopeSLL is the slope of the surge point line in the compressor map. The variable Ss is calculated continuously in the antisurge controller. As Ss is < 1 for normal operation, and Ss is > 1 when the system is in surge, this allows for easy judgement of different compressor systems by using the same surge parameter variable. The antisurge controller continuously calculates how much the operating point deviates from SCL using the SS parameter, considering the overall control margin (b). The DEV is typically calculated by using equation 2: DEV = 1 - SS - b

Figure 3. Typical surge cycle as a result of sudden high back pressure.

August 2022 48 HYDROCARBON ENGINEERING

(2)

As a result, the DEV is positive when the operating point is to the right of the SCL. In this case, if the antisurge valve is not fully closed, the antisurge proportional-integral (PI) response should gradually close it. The DEV will have a value of zero on the SCL, and will be negative when the operating point is to the left of the SCL, causing the antisurge valve to open.

The antisurge control lines Typically, the order of the antisurge control lines in a compressor map is – from right to left – SCL, RTL, SLL, and then SOL, as shown in Figure 1. When the operating point of a compressor crosses the SCL, a PI response acts on the antisurge valve. An improper PI tuning or a higher back pressure (higher resistance) could lead to a large RT action upon crossing the RTL. This is experienced as high disturbance in the process. If the compressor experiences pressure even further back, forcing it to operate to the left of RTL, this could lead to compressor surge. In its closed-loop response, the antisurge controller will vary its output based on its PI tuning parameters as a first line of defence, and then it may use RT action as a second line of defence if the operating point crosses the RTL. RT action, which is an open-loop response, will produce a relatively larger step opening (and possibly multiple steps) to the antisurge valve, increasing the flow in the compressor. In most cases, this will cause high process disturbance. The intention of these defence lines is to protect the compressor from surge by manipulating the antisurge valve to move the operating point back to the desired surge control margin. CCC proposes the use of relatively smaller RT steps in response to the variations of DEV before (or even after) the operating point reaches the SCL.

It is important to note that there are many cases where the antisurge valve opens, even if the calculated DEV is positive. These could be being in a process limit condition, receiving a compressor stop or ESD request, or recycle-balancing with other trains in a parallel compressor network. These conditions, among others, override the DEV calculation loop, ‘forcing’ the antisurge valve to open.

Proactive recycle trip (recycle trip dSs/dt) response The normal RT response, whether there is a derivative action or not, is typically triggered when the operation point crosses RTL. An RT proactive response can be initiated based on the derivative of the proximity-to-surge variable dSs/dt (dSs). When this response is enabled, the antisurge valve will step open by a configured amount (called the RT_dSs_response) when the value of dSs/dt is greater than a configured value (referred to as the RT_dSs_level) for a specified amount of time (called the RT_dSs_delay). If both the normal RT step response and the proactive RT response are triggered simultaneously, the controller will select the larger response and add it to the antisurge valve output.

Simulation results Figure 2 shows the process to be simulated, with one centrifugal compressor in a standalone configuration. Bleed area: 216mm x 152mm Trim area: 210mm x 146mm Safe area: 190mm x 126mm

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The compressor train has its own dedicated antisurge (AS1) and performance (PF1) controllers, which control discharge at a setpoint of 85 psig. As shown in Figure 3, a sudden increase in process resistance (by closing the discharge valve [FV-105] from 75% down to 45%) caused the compressor to enter into a surge cycle (safety on condition) due to high back pressure. Both SCL and RTL acted on the antisurge valve (red trend), but this could not prevent surge in the compressor. The antisurge valve opened by more than 45% during the surge cycle, causing high process disturbance. This section will now go on to discuss how to rectify the flow in the compressor, and then activate an RT proactive response.

Inducing a proactive RT response As shown in Figure 4, closing FV-105 once more from 75% down to 45% caused the operating point of the compressor to move to the left of the compressor map. The RT proactive response was activated, causing the antisurge valve to open before the operating point reached SCL. As a result, the compressor did not go

into surge, and less process disturbance was witnessed. A couple of RT proactive steps were observed on the antisurge valve output (the red trend). To further analyse results, and to determine the dSs settings at which an appropriate proactive RT step should take place, CCC used the Fast Recorder programme. This enabled the company to capture the variations of dSs, DEV, and antisurge valve output. The history of the compressor surge events (if available) could also be used to determine the appropriate settings. The proactive RT configuration parameters used in simulation are: n n RT_dSs_delay = 0.2 sec. n n RT_dSs_enable = true. n n RT_dSs_level = 0.04. n n RT_dSs_response = 5.

It is important to note that increasing the RT_dSs_response value could lead to an unstable and oscillatory process. As shown in Figure 5, the proactive RT response was activated right after the dSs value reached RT_dSs_level = 0.04, as expected, even before reaching the SCL (the blue trend). After the first proactive RT step, and as the DEV is still positive, the controller attempted to close the antisurge valve. As the dSs value remained greater than RT_dSs_level for more than RT_dSs_delay = 0.2 sec., another proactive RT step was observed (the red trend). After the second step, the dSs value became less than the RT_dSs_level. As such, no additional steps were added. As a result of the increased flow in the compressor, and because the DEV remained positive, the antisurge Figure 4. Inducing a proactive RT response to the right of the SCL. controller slightly closed the antisurge valve very slowly, settling the operating point on the SCL.

Conclusion

Figure 5. Fast recorder trends for the proactive RT response.

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With a properly tuned proactive RT response, companies can operate both the centrifugal and axial compressors safely and away from surge. This technique also results in minimised process disturbance during sudden high back pressure situations. Caution should be taken when using this feature, as improper tuning could result in an unstable process. The use of the antisurge control lines shown in Figure 1 is still required for compressor protection from surge. These lines are required in order to absorb higher disturbances that the proactive RT response cannot handle.

Giacomo Rispoli and Alessia Borgogna, MyRechemical, Italy, discuss the use of low-carbon methanol from waste as a new fuel to help decarbonise the shipping sector.

lobal emissions related to the transport sector accounted for 7.2 billion t of carbon dioxide (CO2) in 2020. The transport sector is indeed one of the most challenging sectors to decarbonise. Nevertheless, in the last decade, a strategy identifying the most suitable approach to addressing the environmental impact of different modes of transport has been shaped. For example, the sector is expected to move towards electrical mobility in the case of cars, as electric engine technology is able to maintain a similar standard as combustion engines for small vehicles. However, this option becomes unfeasible when applied to heavy cargo transport, as electric engines are still not suitable for vehicles of this size.

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The shipping sector alone accounted for the production of approximately 825 million tpy of CO2 in 2020. The European target is to reduce the shipping sector’s greenhouse gas (GHG) emissions by at least 75% by 2050. The solution that has been chosen is fuel substitution with low-carbon methanol. As evidence of this, one of the most relevant shipping companies has just declared the addition of eight large ocean-going container vessels that are capable of being operated with low-carbon methanol. Methanol has the potential to be a sustainable alternative fuel, blended into gasoline or used directly as it is, for fuel cells. It has been definitively selected as

the most promising alternative marine transport fuel due to its following features: n It is essentially sulfur-free. n It has a high energy density, meaning that it is easily storable. n It emits a low quantity of CO2 per energy content. nn It has much less impact on marine wildlife. To be as harmful as conventional gasoline, more than 5000 times its volume would be required (see Figure 1).

The main GHG and air pollution emissions reductions are also summarised in Figure 2. A clever solution for the production of low-carbon methanol is using waste and recovering the carbon and hydrogen that would have been disposed of. Specifically, the waste-to-methanol process converts non-recyclable waste into methanol. The main pioneering aspect of this process is the link between the waste and chemical industries, which are not traditionally connected to one another. Gasification converts solid waste into syngas – a gas mixture that is Figure 1. Fatal dose of different marine fuels for fish (source: familiar to the chemical world. Tailored cleaning and Methanol Institute). purification sections allow for the management of the variable pollutants that are contained in waste in order to meet strict requirements related to chemical synthesis. A dedicated conditioning section is reserved to meet specific syngas composition requirements for methanol synthesis. The overall block scheme is depicted in Figure 3. The following section will introduce the technology in detail.

Figure 2. GHG and emissions reduction (source: Methanol Institute).

Figure 3. Block scheme of a typical waste-to-methanol process.

August 2022 52 HYDROCARBON ENGINEERING

The waste-to-methanol process High-temperature melting conversion is the core step in the process. This reactor is able to convert the

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combustible fraction of waste into syngas and, at the same time, to melt the inert fraction (which is usually not negligible in waste materials). To this end, partial oxidation occurs by means of pure oxygen in order to reach higher temperatures rather than applying air. The reactor is composed of three zones (see Figure 4): n The melting zone: where oxygen is fed by promoting the exothermic oxidating reactions which convert the solid waste into gas, thus producing the heat required to reach a temperature higher than 1600°C, allowing for the melting of the inert fraction. n The partial oxidation zone: where the balance of gasification reactions results in the further conversion of the combustible fraction, as well as a reduction in the average working temperature (600 – 800°C). n The stabilisation zone: where gas flow – once produced by the lowest zones – is further oxidised in order to increase the temperature up to 1200°C, producing valuable syngas that is free of long chain characteristics of gasification processes (TAR) and far from the thermodynamic stability condition of some harmful compounds such as dioxins. This valuable composition is freezed as it is, by means of an evaporating quench, which ensures the abrupt change of temperature from 1200°C to 90°C. The quench is the first step of the syngas cleaning section, which is supplemented by two scrubbers working under different pH conditions, promoting the precipitation of mineral matters – including the potential contaminants still entrained into gas. Electrostatic precipitators are also part of the cleaning section, and these ensure the removal of potential residual particles. A critical step is then reached, as the syngas is now cleaned but remains unsuitable for the chemical synthesis system as this requires a completely purified gas stream in order to not poison the catalysts. A tailored syngas purification section is therefore added into the scheme to achieve a very polished syngas as required by catalysts’ application. Syngas also has to be conditioned. In other words, syngas composition, in relation to the main components (i.e. hydrogen, carbon monoxide [CO],

Figure 4. Longitudinal cross-section of the high-temperature converter.

August 2022 54 HYDROCARBON ENGINEERING

and CO2) has to be modified to meet the requirement set by the stoichiometry of the methanol synthesis reaction. By way of waste gasification, a syngas with a methanol module ([H2 - CO2])/[CO + CO2]) close to 0.5 is produced. Instead, a value of 2.1 is normally applied in industrial methanol synthesis. The target value can be reached by the combination of a water gas shift – which enhances the hydrogen content by converting CO in CO2 – and CO2 removal. By applying an amine separation system, pure CO2 is recovered, ready to be further applied, or liquified and then stored. The proposed scheme allows for the production of approximately 1 t of low-carbon methanol for 2 t of waste. Compared to methanol produced by methane steam reforming, 270 kg of methane is avoided for each ton of methanol. Additionally, the waste-to-chemical system avoids the disposal of waste via landfill or incineration. By using this solution, more than half of the carbon contained in waste is converted into a new product: methanol. According to the Renewable Energy Directive, the methanol produced from waste can be categorised as advanced biofuel (if the original carbon is biogenic), or recycled carbon fuel (if the original carbon is fossil-derived). The distinction between the biogenic or fossil origin of the feedstock can be retrieved by C14 analysis applied directly to the methanol produced. Refuse-derived fuel – a product of unsorted municipal solid waste – typically contains approximately 50% biogenic carbon and 50% fossil-based carbon. Approximately 50% advanced methanol and 50% recycled carbon methanol is produced from material that is literally wasted. When continuous and green power is available at a cost of lower than €40/MWh, the methanol module can be adjusted by adding hydrogen from electrolysis, thus avoiding the shift of CO to CO2 and converting all of the carbon contained in waste into methanol. The advanced waste-to-methanol scheme has further benefits. First, the yield is doubled: from 1 t of waste, 1 t of methanol is produced. Furthermore, and most importantly, zero CO2 is produced.

Conclusion The waste-to-chemical process is a tailored and elegant link between the world of waste conversion and chemical or fuel production. The technologies through which it is composed are already available and commercially-proven at industrial-scale. The waste-to-chemical process is, indeed, a ready-to-build alternative solution for non-recyclable waste management. Notwithstanding the novelty of the waste-to-methanol scheme, it is already an economically-attractive solution. The income for this process comes from both feedstock (waste) and product. Furthermore, the methanol produced by this process is specially categorised, and is therefore able to access a sustainable methanol market, which ensures a significant additional remuneration. As such, it is possible to achieve a return on investment with this novel technology in a short period of time. The fusion of waste disposal and methanol production in a unique overall process allows for the reduction of emissions related to each single process. This solution is already available and sustainable – both from an industrial reliability and economic point of view. Furthermore, the waste-to-methanol scheme integrated with green hydrogen will enable the conversion of waste, the production of methanol, and the storage of renewable power – without any CO2 emissions.

Keith Warren, Servomex, UK, looks at the role that combustion measurements play in controlling carbon emissions.

ith the increasing global focus on reducing and preventing harmful emissions, particularly carbon dioxide (CO2), many industries are looking for ways to minimise the environmental impact of their operations. International action to reduce the impact of carbon emissions on climate, including the 2016 Paris Agreement, has intensified the implementation of ever more stringent environmental regulations. In response, industrial operators are increasingly adopting clean air and decarbonisation strategies designed to

meet regulatory requirements and help them achieve carbon reduction targets. Gas analysis plays an essential role in these efforts, not only by supporting the measurement of harmful emissions, but also by improving process efficiency, thereby ensuring fewer emissions are generated from the outset. Combustion efficiency is one of the key stages in any effective clean air strategy. Taking control of this important process reaction allows operators to reduce emissions of key pollutants, lower fuel consumption, and improve safety.

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In gas analysis terms, this control relies on accurate measurements of the relative concentrations of oxygen (O2) and combustibles (COe) in the reaction mixture to achieve the optimum ratio between fuel and air.

The combustion process Combustion mixes fuel with O2 (traditionally from air, though some processes use recycled flue gases combined with enriched O2 to create combustion feeds) in a fired heater, creating heat energy for use in the process. This reaction typically requires a significant amount of fuel, creates potential safety hazards, and generates environmentally-harmful emissions. Before the development of accurate combustion efficiency gas analyser technologies, fired heaters were typically run under inefficient conditions, with high excess air. This increased the level of fuel consumption, but avoided the creation of unsafe process conditions. Any excess O2 in the process also combines with nitrogen and sulfur from the fuel to produce unwanted emissions such as oxides of nitrogen (NOx) and sulfur (SOx). Accurate measurements of oxygen and combustibles, principally carbon monoxide (CO), allow the air-to-fuel ratio

to be optimally balanced, controlling the combustion reaction and reducing fuel consumption. Emissions of NOx, SOx, CO and CO2 are also reduced.

Measuring oxygen with zirconia sensing Zirconia-based sensing technology is a long-established and highly-trusted solution for O2 monitoring in combustion. It provides reliable, accurate measurements at ppm and % levels, and has a fast response to changing conditions. Servomex’s version of the zirconia sensor consists of a cell made of ceramic zirconium oxide, stabilised with an oxide of yttrium to form a lattice structure. The measure and reference sections of the cell are covered with catalytic, porous, electrically-conductive coatings that serve as electrodes on both sides of the lattice barrier between sample and reference gas volumes. At elevated temperatures, the lattice allows negatively-charged oxygen ions, formed at the catalytic electrodes, to pass at a rate that depends on the cell temperature and the difference in the O2 partial pressures of the sample gas and the reference gas. The passage of the ions generates a voltage across the electrodes. The size of this voltage is a logarithmic function of the ratio of the O2 partial pressures of the sample and reference gases. The partial pressure of the reference gas is predetermined, so the voltage produced by the cell can be used to determine the O2 content of the sample gas taken from the process.

Adding a combustibles sensor

Figure 1. Pre-combustion carbon capture.

Figure 2. Post-combustion carbon capture.

August 2022 56 HYDROCARBON ENGINEERING

A combustibles sensor can be added easily to a zirconia-based gas analyser, at a modest additional cost, to provide an all-in-one combustion control solution. Calorimetry technology – also known as thick film catalytic sensing – can be used to achieve sensitive, accurate measurements of combustibles. A sensor using this technology measures COe based on its exothermic reaction with O2 over a catalytic platinum surface, which produces CO2. The heat generated is used to determine the COe concentration. A four-quadrant bridge track is over-glazed to shield the circuit from the sample gas, and two quadrants are then coated in a platinum catalyst. These quadrants form a Wheatstone bridge circuit, with the disc mounted in a cell heated to 300˚C (572˚F) or 400˚C (752˚F). When the gas sample is added, any COe present in the sample will combust on the catalyst, heating the respective quadrant and altering the output voltage of the Wheatstone bridge. This output voltage will be directly proportional to the COe concentration, providing an accurate measurement for COe.

A combined solution for combustion control Combining both zirconia and calorimetry sensing in one compact device, Servomex’s SERVOTOUGH FluegasExact 2700 combustion analyser delivers effective measurements of both O2 and COe in flue gases. Easy to operate and maintain, it meets the most demanding needs of combustion efficiency applications in the power generation and process industries, helping to improve combustion efficiency and reduce flue gas emissions. Armed with an integral sampling system custom-designed for operation in some of the hottest and most extreme industrial environments, it is ideally suited to the control of a wide range of combustion processes, including process heaters, utility boilers, thermal crackers, incinerators and furnaces. Aspirator interlocks prevent sampling while the analyser is heating or not up to optimum temperature, while the optional Flowcube continuous flow monitoring sensor enables positive flow conditions to be validated, aiding preventative maintenance. Designed for high-temperature processes of up to 1750°C (3182°F), the FluegasExact 2700 uses an extractive measurement principle to protect both sensors from the harsh process environment, extending sensor lifespan. Typically, the zirconia sensor in the FluegasExact 2700 will operate effectively for at least seven to eight years. The analyser is designed for safe areas, Zone 2/Division 2, and ATEX Category 3 hazardous-rated locations. It also offers

both direct and remote mounting options to ensure easier, safer access for personnel, even if the desired measurement point is not freely accessible. Servomex also offers a specially-designed, sulfur-resistant thick film catalytic sensor for the FluegasExact 2700. This is operated at a higher temperature to prevent sulfur from depositing permanently on the sensor. Alongside the environmental benefits of maintaining efficient combustion reactions, the accuracy and reliability of the FluegasExact 2700 has been proven to save up to 4% of fuel costs per year. This is not only advantageous to the operator’s bottom line, but also aids their sustainability goals by reducing the consumption of non-renewable fuels.

An alternative combustion solution Tunable diode laser (TDL) technology is a more recent sensing development, and provides an even faster measurement for this application, particularly in the case of CO. TDL analysers provide an average measurement across the measurement path, rather than the single-point result produced by a zirconia analyser. This ensures a better overall picture of conditions within the fired heater. However, since TDL sensing is highly specific to the gas being measured, separate analysers are required for O2 and CO. Servomex’s SERVOTOUGH Laser 3 Plus Combustion TDL analyser, for example, can be configured to measure either O2 or CO. It can also be configured for a joint measurement of CO and methane to provide a rapid-response measurement for safety in natural gas-fired heaters and boilers.

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Figure 3. Oxyfuel combustion carbon capture.

Part of a larger strategy While combustion has been the primary focus of this article, it is important to note that it is just one part of a wider clean air strategy. Gas analysis can also be used in many applications to increase process efficiency. The more efficient the process reaction is, the fewer harmful emissions are likely to be generated. It also plays an important role in gas cleaning – the removal of harmful substances from process gases that might otherwise be emitted by the plant. Typical examples of the many gas clean-up processes include DeNOx (ammonia slip) treatment, flue gas desulfurisation, and carbon capture and storage (CCS).

A further aspect of the strategy is the monitoring of flue gas emissions. This helps to determine the process efficiency and protect the environment, and demonstrates that plant operators are complying with the necessary regulations. To ensure compliance, a continuous emissions monitoring system (CEMS) is required to measure all of the necessary components of the flue gas. This must be capable of offering the highest sensitivity and accuracy when dealing with multiple measurements for pollutants. By combining these stages into a comprehensive strategy, operators can ensure more efficient processes, support the safe removal of pollutants, and monitor the remaining emissions that are output to the atmosphere. When using a wide range of different sensing technologies to ensure the best-fit and most cost-effective solution for each application, gas analysis plays an essential role in cleaner plant and refinery operations. Additionally, it is certain that gas analysis technology will be essential to the production of current and future cleaner energy sources, helping plants and refineries to fully address the impact of their operations on the wider environment, and contribute to the creation of a world with cleaner air. For many power generation and hydrocarbon processing applications, the creation of that world will depend heavily upon maintaining and tightening the control of combustion efficiency.

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Returning live to The Hague this October

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Now in it’s 38th year, the event continues to be an essential annual forum for the global sulphur and acid community to learn, connect and do business. You can expect an expanded market outlooks agenda, including expert insights from CRU’s analysis teams on major supply and demand markets, including sulphur, sulphuric acid and phosphates, plus additional industry updates from key players from across the supply chain.

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Prashanth Chandran, Harnoor Kaur, Nathan Hatcher, Jeffrey Weinfeld and Ralph Weiland, Optimized Gas Treating Inc., USA, detail a new model for carbonyl sulfide (COS) absorption into amines based on mass transfer rates and reaction kinetics.

atural gas, refinery gas and hydrocarbon liquid streams such as propane (LPG) need to be cleaned of carbon dioxide (CO2), hydrogen sulfide (H2S) and other sulfides such as carbonyl sulfide (COS) and mercaptans (RSH). Failure to adequately do so will cause LPG, for example, to fail a copper-strip test. Even LPG that passes the copper strip test can fail later in the presence of water if there is residual COS, because of the gradual hydrolysis of COS to CO2 and H2S. This article discusses a new model for COS absorption into amines based on mass transfer rates and reaction kinetics. This is the first time that any commercial HYDROCARBON 59

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software has been able to accurately simulate COS removal from gas streams. Amines have excellent H2S removal characteristics, but they are notoriously poor solvents for other trace sulfur species that are less acidic, such as COS and mercaptans. Until now, no simulator has been able to model COS and mercaptans adequately. For mercaptans, the basic problem appears to be insufficient, inaccurate phase equilibrium data. Almost all of the public domain mercaptans solubility data is academic in origin and this may explain the paucity of mercaptans data. Very few academic institutions welcome researchers who deal with mercaptans – academia is generally ill-equipped to handle them safely and risks fogging up campuses. Good-quality data is hard to come by. For COS, one of the main issues has been that simulators have ignored its reactive nature in aqueous amine solutions, treating its chemistry in an over-simplified way as a purely physically-dissolved, non-reacting solute. COS absorption rate is thus wrongly computed because the calculations fail to account for the absorption rate enhancement that

Table 1. Typical lean loadings of H2S and CO2 Loading

MEA

DGA®

DEA

MDEA

MDEA + Pip

H2S

0.01

0.005

0.001

CO2

0.1

0.08

0.001

0.1

results from the chemical reactions of COS with the amine.

Reactions The reactions of H2S and CO2 in aqueous amines are well-known and require no discussion in this article. RSH merely dissociates in aqueous media, as seen in reaction 1. However, to describe the decomposition of COS in water just by the reaction COS + H2O → CO2 + H2S is a deceptive oversimplification. The reaction mechanisms and kinetics of COS in amines are more complex than that, and although well-described in literature1, they still deserve a brief portrayal in this discussion. COS reacts in aqueous solutions first to form thiocarbonate (reaction 2), which further hydrolyses to bicarbonate and bisulfide (reaction 3): RSH ⇌ H+ + RSCOS + H2O ⇌ H+ + HCO2SHCO2 S- + H2O → H+ + HCO-3 + HS-

(1) (2) (3)

The combined form of reactions 2 and 3, along with other speciation reactions of CO2 and H2S, is equivalent to the overall simplified hydrolysis of COS to CO2 and H2S that has already been mentioned. Reactions 2 and 3 are very slow unless there is a base in the solution to catalyse the reactions. In the presence of amines, it is postulated that COS reacts by a base-catalysed mechanism according to: COS + Am + H2O ⇌ AmH+ + HCO2SHCO2S- + Am + H2O → AmH+ + HCO-3 + HS-

(4) (5)

In addition to these reactions, COS forms thiocarbamate with primary and secondary amines via a zwitterion mechanism: COS + Am + H2O ⇌ AmH+ COS- + OHAmH+ COS- + B → AmCOS- (thiocarbamate) + BH+

Figure 1. Absorber COS concentration profiles for various amines.

Figure 2. Absorber MeSH concentration profiles for various amines.

August 2022 60 HYDROCARBON ENGINEERING

(6) (7)

Reaction 6 represents the zwitterion formation, and reaction 7 describes its deprotonation reaction. Any base, B, present in solution deprotonates the zwitterion. These reactions are responsible for quite significant COS absorption into primary and secondary amines, but do not occur with tertiary amines. Reaction 4 is known to be equilibrium-limited. The rate of reverse reaction is observed to be practically zero for reaction 5, indicating that for any amine, COS will completely hydrolyse to CO2 and H2S in the fullness of time. Reaction 1 is a simple dissociation reaction involving a single hydrogen ion and, as such, is known to be essentially instantaneous. Thus, it is always at equilibrium. The problem with RSH is that it is an extremely weak acid so that even a low level of acidification of the solvent will drive reaction 1 back towards formation of molecular RSH, which has a very low physical solubility in water. Significant acidification can be witnessed even with a modest amount of dissolved CO2 or H2S. In regenerative caustic solutions,

the CO2 and H2S spend the caustic from its intended purpose of RSH removal. 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. This is not the case for mercaptans beyond MeSH, however, because they are very weak acids and are easily displaced by co-absorbed CO2 and H2S. Recently, Optimized Gas Treating Inc. (OGT) finished developing a COS absorption model which regards COS as a rigorous mass transfer rate-controlled component and incorporates it along with its reaction kinetics into the OGT|ProTreat® simulator. The results of the model were validated against some 20 proprietary sets of field-performance data for various amine systems, and showed that the model accurately simulates COS removal in amine absorbers, for the first time. What follows is a case study showing: nn Mass-transfer and reaction-rate control in the COS removal model. nn A comparison between various amines’ performance in a simple absorber. nn The effect of a solvent’s acid gas loading on the relative removal of COS vs mercaptans.

Figure 3. Absorber H2S and MeSH concentration profiles for DEA.

Case study This case study involves the simulated performance of a simple 20-tray absorber using MEA, DGA, DEA, MDEA and piperazine-activated MDEA (referred to as MDEA + Pip), all at the same 3M molar strength and circulation rate. Unfortunately, the numerous sets of commercial performance data used to validate the model are proprietary to various operating companies so that nothing can be revealed. Instead, the case study involves a hypothetical feed gas of methane at 300 psig with 5 mol% CO2 and 2 mol% H2S, containing 500 ppmv of COS and 100 ppmv each of MeSH, EtSH, PrSH and BuSH. Making comparisons between amines on the basis of the same low CO2 and H2S loadings for all of them seems unreasonable given that MEA, for example, rarely has a lean CO2 loading below 0.1 mole per mole, whereas MDEA commonly has a lean CO2 loading in the vicinity of 0.002. Therefore, to make comparisons more equitable, the lean solvent loadings shown in Table 1 were taken as typical for the amines shown.

COS removal Figure 1 shows how COS concentration in the gas varies across the height of the absorber. The most effective solvent is MEA because it is the most alkaline primary amine and forms thiocarbamate with COS faster than any of the others. DGA is a very close second while DEA

Figure 4. Effect of CO2 and H2S lean loading on DEA absorber performance for COS and MeSH removal.

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lags behind, and MDEA (and piperazine-promoted MDEA) are the least effective for removing COS. These results are pretty much in line with the pKa values of these amines and, of course, COS forms only the thiocarbonate with MDEA. The particular promoted MDEA formulation used here is 2.6 molar MDEA + 0.4 molar piperazine which is rather a low concentration (30 and 3.3 wt%, respectively) and not truly representative of promoted MDEA used commercially (closer to 38 and 7 wt%). However, as far as COS is concerned, absorber performance is only weakly

Table 2. Comparison between legacy and kinetic models for COS* DEA

MDEA

Model

CO2

H2S

CO2

H2S

COS

Legacy (equilibrium)

0.8

523†

1.7‡

3.9

508†

Kinetic (reaction rate)

0.8

189

1.7‡

3.9

405

* Treated gas concentrations in ppmv † CO2 and H2S removal concentrates COS above its 500 ppmv inlet value. CO2 and H2S lean loadings are 0.01 and 0.001, respectively ‡ Concentration in mole %

affected by the details of the formulation. Piperazine mixed with MDEA is ineffective and does not appear to improve COS removal beyond what MDEA alone can do. Even 3.3 wt% piperazine alone will reduce COS to 385 ppmv, but CO2 and H2S absorption swamp the piperazine, consuming it all shortly after it enters the column and thereby reducing its effectiveness for COS removal. Obviously, when there are multiple acid gases and multiple reactive solvent components, care must be taken when interpreting results because acid gas loadings can be much higher with respect to one amine than the other in a solvent blend. MEA shows an almost 80% COS removal efficiency vs only about 20% for MDEA and the promoted MDEA solvents. MDEA is a tertiary amine and cannot form thiocarbamate. Piperazine is a thiocarbamate former; however, in the presence of substantial amounts of CO2 (as it is when total CO2 loading is 0.1) it is nearly fully reacted to the carbamate and dicarbamate forms, and so has little or no residual-free amine remaining to form thiocarbamate. In fact, piperazine carbamate gives a solution with sufficiently higher viscosity than MDEA to result in the slightly poorer performance of promoted vs generic MDEA.

Mercaptans removal Figure 2 shows a plot of methyl mercaptan concentration vs tray number in the absorber. Plots for EtSH, PrSH and BuSH are similar. It should be emphasised that a direct comparison between amines in terms of mercaptans removal should not be inferred from this plot because, for example, amine concentrations and lean solvent acid gas loadings may or may not be representative of the conditions for a particular case. Valid comparisons can be made using only full recycle flowsheets where reboiler duty and other parameters of the process are known. As is usually the case with maxima and minima, the maxima in MeSH concentrations in Figure 2 are the result of competing effects. H2S is a much stronger acid than mercaptan. As the solvent flows down the column and H2S is absorbed, it pushes the mercaptan out of solution and back into the gas phase. Mercaptan is reabsorbed further up the column where almost all of the H2S has already been absorbed by now, and therefore has little effect on mercaptan removal. This absorption/desorption cycle is illustrated in Figure 3, where H2S and MeSH concentration profiles are compared for DEA. As the H2S concentration in the gas approaches equilibrium with the solvent, i.e. the lean loading limits the ability of the solvent to absorb H2S, the MeSH starts to absorb. Below that level in the column, MeSH is actually being stripped from the solvent, driven out by H2S absorption. Evidence for this is found in the crossing of the actual and equilibrium MeSH partial pressure curves.

Effect of acid gas loading Figure 5. CO2 and COS partial pressure profiles across DEA and MDEA absorbers.

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Solvent CO2 and H2S loadings are reported to have a significantly-negative effect on COS and mercaptans removal. Figure 4 shows how CO2 loading at various fixed H2S loadings and H2S loading at various CO2 loadings

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affect the COS and MeSH removal performance of the DEA absorber. CO2 loading has a markedly greater effect on performance compared with H2S. The reason is that CO2 reacts with two molecules of DEA, forming the carbamate and the protonated form of DEA, whereas H2S absorption consumes only a single DEA molecule. So, compared with H2S, CO2 removes twice the amount of DEA from being able to react with COS to form thiocarbamate. The entering raw gas contains 500 ppmv COS and 100 ppmv MeSH. When the lean amine acid gas loadings are quite low – at 0.001 each – COS is removed to 150 ppmv, and MeSH to about 8 ppmv. At a small CO2 loading value of 0.01, the treated gas increases to nearly 200 ppmv COS and 25 ppmv MeSH. Again, H2S loading has a lesser effect on both COS and MeSH removal than the same loading of CO2 because of unfavourable CO2 reaction stoichiometry.

Legacy vs reaction model for COS Table 2 compares ProTreat’s predictions using a new model for COS absorption (‘kinetic’ in table) with an example of what has been the only type of simulation commercially available until now (‘legacy’ in table). The legacy and kinetic models produce essentially identical predictions of CO2 and H2S removal, as one might expect. However, the legacy model predicts that 2% of the COS is removed by DEA and 3.3% by MDEA. On the other hand, the kinetic model predicts the removal of 65% and 23% by DEA and MDEA, respectively. Users of legacy simulators have complained for years that predicted COS removal has been far from observations. That disparity has now been rectified – ProTreat’s Kinetic Model predictions conform well to field measurements.

As illustrated in Figure 5, the kinetic model shows that CO2 and COS approach final outlet values in the DEA absorber quite differently. The gentler decrease in COS partial pressure reflects the much slower reaction kinetics of COS. In DEA, CO2 falls rapidly from 5 mol% to a few ppmv, whereas the same 20 trays only take COS from 500 ppmv to 189 ppmv. But relative to MDEA, both CO2 and COS decrease more rapidly simply because DEA reacts with both the carbamate and thiocarbamate reactions, respectively. MDEA does not. In a typical amine absorber, COS absorption is mass transfer rate-limited. This is supported by the present cases where the COS equilibrium partial pressures are almost zero. As such, although the driving force for absorption remains high, the absorption rate is slow. COS can not be properly simulated using only its physical (Henry’s Law equilibrium) solubility, as evidenced by the legacy predictions. COS reacts with primary and secondary amines at rates that enhance its absorption and therefore significantly affect the ability of any absorber to remove it from the inlet gas. Similarly, mercaptans must be modelled as mass transfer rate-limited components, too, because they dissociate in amines and the amines act as sinks for the released hydrogen ions – the dissociation reaction enhances mass transfer. For meaningful results, it is imperative that the latest version (7.0) of OGT|ProTreat’s rigorous mass transfer rate-based simulator is used to simulate COS and mercaptans removal in gas treating.

Reference 1.

VAIDYA, P. D. and KENIG, E. Y., ‘Kinetics of carbonyl sulfide reaction with alkanolamines: a review’, Chem. Eng. J., 148, 207 – 211, (2009).

Dave Godfrey, Rotork, UK, discusses how downstream oil and gas operators can support ageing assets and reduce downtime.

efineries and associated downstream applications are complex systems that require specialist equipment to run smoothly and to support continuously high production demands. A key element within this is flow control. Actuators control the valves that allow oil and gas to be produced, transported, stored, refined and sold. Effective flow control provides high degrees of reliability, repeatability, accuracy, safety and efficiency. Actuators are seen in a diverse range of applications within oil and gas, stretching from wellheads to tank farms, and pipelines to refineries. They provide day-to-day flow control and safety functions in these challenging environments. Actuators are therefore a common sight on downstream sites such as refineries. The exact role that they play can differ, depending on customer requirements. For example, thousands of Rotork IQ3 intelligent electric actuators control a variety of gate, ball and butterfly valves to manage the flow of crude oil at a refinery and petrochemical site on the island of Zhoushan, near Shanghai, China. This site refines

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oil and manufactures ethylene. Control networks are often required onsite because of the number of actuators installed. These are communication networks that transmit information between devices. A project to provide flow control at a Turkish refinery (creating products such as petrol, naphtha, aviation fuel, kerosene and diesel) has over 900 IQ3 actuators from Rotork onsite. They were installed to automate valves that were previously manually operated. The actuators in different areas of the refinery are monitored and controlled by Rotork’s PakscanTM control network. Electrification is emerging as a major theme in the race to net zero, and can play an important role in the reduction of emissions within oil and gas operations. This is a sector – regardless of which stream an application sits under – that is under increasing scrutiny to reduce damaging emissions and to transform in order to remain as an important factor within the energy transition. Oil and gas operations will remain important for many years to come; the electrification of processes within it (such as flow control) is an obvious way to reduce

environmental impact. Electric actuators are increasingly chosen within oil and gas because they do not release emissions during operation, compared to more traditional forms of flow control (especially pneumatic actuators) that can vent methane or other damaging gases into the atmosphere. Another critical role played by actuators in downstream actuators is safety provision. Emergency shutdown (ESD) or fail-safe requirements are often key considerations for plant managers when they choose what form of flow control they need. Safety functionality allows for operations to quickly stop the flow of oil or gas. Continued flow in downstream applications can have safety, financial and reputational consequences. Appropriate safety/shutdown systems provided by an actuator means that impacts are reduced or nullified and the flow of gas or oil can be safely controlled. For example, the Karbala Refinery in Iraq, due to begin operation this year, will produce petrol, gas oil, fuel oil, jet fuel and asphalt. IQ3 actuators were ordered to support the reliable, efficient and safe operation of the refinery. This includes the provision of an ESD function. The actuators are certified for safety applications (SIL2/3). Another actuator that is often specified for safety functions are spring-return actuators. These can be seen in all streams of oil and gas operations, but most commonly in midstream applications such as pipelines. These fluid-powered actuators are a simple and reliable option. They are ideal for remote or hazardous environments. In remote or extreme conditions (such as pipelines and unmanned sites), the additional possibility of environmental impacts must be considered, as considerations of safety and shutdown are just as important here as they are in a refinery.

The importance of holistic maintenance plans to prevent downtime It is clear how important effective flow control is within downstream oil and gas applications. Sites rely on actuators working effectively every day. The availability of flow control assets should always be a focus for plant managers; uptime is key in achieving productivity and profitability. Sites only run efficiently, without costly downtime, if assets are continually available. When assets are unexpectedly unavailable and a site suffers downtime, the impacts include poor performance, reduced yield, poor quality, financial losses and reputational damage. These impacts can occur even if assets are unavailable for only a short period of time. A holistic asset maintenance Figure 2. An asset management system gathers performance data for analysis. plan is therefore essential

Figure 1. IQ3 actuators from Rotork onsite at a Chinese refinery.

August 2022 66 HYDROCARBON ENGINEERING

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if downtime is to be minimised. It is a critical consideration for long-term reliability and viability of continuing downstream applications. Site operators must choose an appropriate asset management plan that considers the entirety of a site for the long-term, including the total cost of ownership of an asset – from newly-purchased to the end of life. The cost of not having a holistic maintenance plan can be high: if an asset breaks and there are no plans in place to fix it, then large amounts of money may be spent to get a site working again. An asset management system with a fixed cost means that service budgets will be stable, without costly unplanned work for the replacement of assets. A programme such as Rotork’s Lifetime Management looks at the entire life cycle of an asset (and the management of its potential obsolescence) and how this will impact the entire site. This system can increase uptime and eliminate unexpected maintenance costs.

Obsolescence management Sites with flow control equipment require support to guide them through periods of change. As assets age, obsolescence becomes a concern. They must be carefully managed and plans should be made for the end of their life cycle. Over time, a decline in performance or an increase in the risk of operational failure is likely. Appropriate day-to-day maintenance plans are essential, but operators must plan beyond the functional life of an asset and have obsolescence plans in place that will ensure continued production and a reduction in downtime. The problems surrounding ageing flow control equipment are traditionally managed by spares and reactive maintenance. To ensure continued operation and effective performance, operators may need to consider updating technology to future-proof their sites. Critical obsolescence planning must be worked on in conjunction with flow control asset specialists. An asset such as an actuator may have a life cycle of many decades. Spares for an ageing actuator often become increasingly difficult to source as supply chains undergo disruption and as technology and safety standards evolve. Other relevant factors in operators’ decision making may include regulatory compliance, up-to-date health and safety standards, budget issues, and struggles to continue with current maintenance or spares programmes. Proactive engagement in future-proofing sites, understanding the

importance of obsolescence management, and managing the life cycle stage of assets will result in budget predictability, improved performance and reduced downtime.

Technological innovation Technological innovations can manage obsolescence concerns. Lifetime Management from Rotork has now been enhanced by the launch of IQ3 SET, offering backwards compatibility to the 1960s. The use of IQ3 SET is appropriate for legacy actuators on sites that have non-integral starters. The feature option works with and supports the features of older actuators (such as A-Range actuators, amongst the first electric actuators on the market which can still be found on sites across the world today) with easy integration into existing plant architecture. This maintains and keeps actuators up-to-date and allows customers to focus on operational goals, without concerns about imminent obsolescence or the need to deal with constant spares updates or last time buy pressures. Use of IQ3 SET ensures predictable maintenance within budget, improved performance and increased uptime. It future-proofs plants with these actuators without affecting the plant infrastructure, as it is compatible with existing site cabling and control systems (there is no need for new cabling costs). Upgrading to up-to-date technology to overcome obsolescence issues in this way allows for minimal interruption to production, and reduced downtime. As it is part of an existing product range, a full and comprehensive knowledge of service and maintenance already exists. For all oil and gas operations, this confidence of continuing production and management of obsolescence concerns is extremely valuable. There are other different steps that site operators can take to ensure continued production. Unwanted interruption on downstream sites such as tank farms can be damaging to operators. This is likely to occur on sites with unreliable power supplies. To allow valves to operate, and production to continue for as long as possible, operators may choose a battery-operated actuator that can ensure continued operation until power is restored. Rotork’s Shutdown Battery is part of the IQT part-turn range of intelligent electric actuators. If power is lost, it can continue to function through an Uninterruptable Power Supply (UPS). This allows for continued use until battery charge is depleted. This is another example of how innovation in flow control technology can assist operators in the essential task of reducing the potential time that assets can be offline for. The Shutdown Battery can conversely be used to stop flow when required, in order to prevent safety or environmental damage. It can also be set as fail-close, stopping the process safely after interruption to power.

Conclusion

Figure 3. IQ3 SET from Rotork.

August 2022 68 HYDROCARBON ENGINEERING

Management of obsolescence is an important consideration for oil and gas operators who wish to maintain efficient operation/production and minimise instances of downtime. In downstream applications, work in refineries is in high demand and operators know that maintaining high levels of uptime is essential. Flow control asset obsolescence concerns can be managed in a variety of ways, including upgrading to the latest technology to reduce asset unavailability and to conform to up-to-date safety standards.

Matt Wagner, Emerson Automation Solutions, USA, explains why choosing the right combination of valve style, trim type, materials of construction, and digital positioner is critical for profitable operations.

thylene is one of the most mass-produced petrochemicals in the world. It is typically formed by steam cracking naptha or natural gas liquids, and once isolated and refined, it is sold as an intermediate to feed a wide variety of petrochemical processes. Most of the ethylene produced is used in various forms of plastics, but the hydrocarbon is also used to produce specialty chemical products, including antifreeze, insulation, adhesives, paints, and more. There are five major licensors of ethylene plants, but the overall process is similar among designs, and all are very dependent upon control valves in order to operate efficiently

and reliably. This article will focus on the critical valves throughout the ethylene process and highlight key selection criteria necessary to ensure consistent and reliable performance.

The ethylene process The ethylene plant can be divided into the front end ‘warm section’ and a back end ‘cold section’ (see Figure 1). The warm section starts with a cracking furnace where naptha or natural gas is mixed with steam in a very specific ratio, with the mixture then subjected to very high temperatures. This fractures the hydrocarbon into a number of components (ethylene, propylene, acetylene, etc). The gas is quickly quenched to stop HYDROCARBON 69

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products. The most critical valve here is the quench tower level valve (#7). If naptha is the feedstock, then oil is often used as the heat transfer fluid in this tower, and it tends to fill with carbon particles. This subjects the valve to a very erosive slurry – a punishing application. Hardened trims, such as Alloy 6 or ceramics, as well as sealed metal bearings, are used to protect the valve internals and lengthen service life. Environmental packing is still required, and most operating units employ diagnostic positioners to sense and indicate developing problems well in advance of failure. As the gas leaves the quench tower, it must be compressed to raise the pressure for the next processing stages. Each compressor stage depends upon the antisurge valve (#8) to Critical control valves in the warm section protect the equipment from catastrophic damage during low Figure 3 focuses on the front end of the ethylene process, gas flow. These types of valves are usually very large as they which begins with the cracking furnace. The furnace must be must carry at least the full compressor capacity, while enduring carefully controlled, or the process can become plugged with very high pressure drops and flow rates. coke deposits, forcing an extended shutdown. The three major They must also move very quickly and precisely to arrest control valves in this area are the hydrocarbon feed valve (#1), compressor surge conditions when they occur. These control the dilution steam ratio valve (#2), and the burner fuel control valves are customised with pneumatic boosters, actuators, and valve (#3). very high speed and precision positioners to meet the required Each of these valves must provide very tight flow control, performance specifications. They can also be specified with so high-performance globe valves with diagnostic positioners specialised trims and diagnostic positioners for performing are the norm. Any valve in hydrocarbon service will also require online partial stroke testing without process upset. some form of environmental packing to minimise emissions. After compression, the process gas enters the acid gas The steam valve may employ environmental graphite packing to absorber, which circulates an amine solution to absorb acidic minimise friction and handle the high temperatures. gases so they do not create process problems downstream. The The next major process area is the quench tower. Here, the most critical valve in this section is the rich amine letdown very hot gases from the furnace are quickly cooled to stop the control valve at the bottom of the acid gas absorber (#9 in reaction process and avoid the production of unwanted side Figure 3). This valve is subjected to high pressure drop by design so that the entrained acidic gases separate from the rich amine solution, allowing it to be recycled. This type of separation is known as out-gassing, and it generates noise, vibration and erosion. The internals of this valve must employ hardened trim materials, as well as Figure 1. The ethylene process starts with a cracking furnace to create the some type of anti-cavitation trim, to ethylene, and then progresses through a series of steps to remove acids and minimise damage and lengthen water, and to isolate the ethylene. maintenance cycles. Environmental the reactions. It is then compressed, and finally run through various vessels to remove acids and water. The product stream is then chilled and routed through a series of distillation columns to isolate the ethylene from other hydrocarbons formed in the cracking furnace. These towers remove methane, ethane, acetylene, propane, propylene, and other heavy constituents. Figure 2 shows an overview of the specific process vessels used in an ethylene plant, with the critical control valves highlighted. These valves must endure a variety of difficult process conditions, so each must be specified carefully.

Figure 2. This process flow diagram shows the major vessels and critical control valves associated with a typical ethylene plant.

August 2022 70 HYDROCARBON ENGINEERING

packing is required, and a diagnostic positioner is a good choice to detect and alarm as the valve develops the inevitable trim damage associated with this very difficult service. After leaving the acid gas absorber and caustic wash tower, the process gas enters the drying section, where all traces of water must be removed. Drying technologies vary, but usually the process involves multiple molecular sieve beds which are alternately switched in service to dry the gas, or switched offline to be regenerated. The dryer switching valves (#12 in Figure 3) are very critical to the process and must endure challenging process conditions. Figure 3. This flow diagram focuses on the front end ‘warm section’ of the These valves are constantly switched open and closed, and despite ethylene process. The major vessels include the cracking furnace, quench tower, cracked gas compressors, acid removal section, and dryer beds. large temperature swings and reverse pressure service, each valve must provide virtually zero leakage. The best valve design will depend on the specific application but will Critical cold section control valves usually require quickly stroking double eccentric ball valves or Figure 4 focuses on the back end of the ethylene process, high-performance triple offset valves. Diagnostic positioners in which begins with refrigeration and then runs through a series this service can detect developing valve problems well in of distillation columns to separate the process gases into a advance of failure to avoid unplanned dryer outages. variety of purified products. Very precise flow control is critical

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section of the plant tends to have extended runs with few shutdowns, so it is imperative that reliable, long-lasting valves are chosen. Each control valve must be carefully sized to provide consistent and stable control, and the valves themselves are usually high-performing globe valves with diagnostic positioners and environmental packing.

Conclusion The ethylene process poses a wide range of service conditions for control valve selection, and each application must be carefully evaluated to ensure the proper valve body style, trim, actuator, packing and positioner are selected to provide reliable and long-lasting performance. Figure 4. This flow diagram focuses on the back end ‘cold section’ of the Unexpected valve failures and process ethylene process. Ethylene is refrigerated to very low temperatures and shutdowns are extremely costly, so digital then passed through a series of distillation columns to separate and purify positioners with the ability to detect and the process streams. alarm developing problems are often employed, as they usually pay for themselves in a very short time by reducing unplanned for distillation column operation, so extremely accurate and downtime. consistent flow control is paramount in this section of the plant. The number of available design options are extensive, so The major valves in the distillation section for each column end users may find it helpful to consult with valve vendors to include the distillation feed control valve (#13) and distillation determine the best valve type, packing, materials of reflux control valve (#14). The initial columns in this process tend construction, and digital positioner for their specific to run at cryogenic temperatures, so control valve trim and application. soft parts must be selected to handle those conditions. This

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Hydrocarbon Engineering Issue August 2022

Articles inside

Keeping things operating smoothly

Controlling combustion for a cleaner future

Shipping’s new scene

Fight the surge

Control valve selection for ethylene plants

Streamlined operations

Leading the way towards LNG safety

A helping hand on the road to decarbonised operations

Comment

Big data in catalysis

The secret to safety

Keeping your options open

World news

Manage to mitigate