Hydrocarbon Engineering - June 2021

June 2021

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MODULAR PROCESS UNITS

CONTENTS June 2021 Volume 26 Number 06 ISSN 1468-9340

03 Comment 05 World news 08 European downstream developments

22 Leading the way to transformation Joseph C. Gentry and Charlie Chou, Sulzer Chemtech, GTC Technology, USA, explore three basic elements that are likely to be seen to be part of the refinery of the future.

Alan Gelder, Wood Mackenzie, UK, explains why the European downstream sector needs to adapt; doing nothing is not an option.

31 An evergreen optimisation approach A. Chen, A. Novotny, T. Case, D. Banks, and B. Eren, BASF, USA, outline how FCC catalysts optimise bottoms cracking.

38 Have your cake and eat it Juan Pereira De La Riera, Olivier Boisier, and Boris Hesse, Axens, France, discuss performance and energy savings in an FCC gasoline hydrotreatment unit.

45 Taking centre stage Karen Picker, Sandvik, USA, predicts the future of duplex stainless steels in reactor effluent air coolers.

51 Benefits of modular process units Mike Berckenhoff, MOGAS Industries Inc., USA, offers a comparison of modular vs stick-built process units for heavy oil pressure letdown.

55 Undergoing rigorous tests Scott Moreland, Quadax Valves Inc., outlines the various tests that Quadax’s valves underwent before they were installed at an LNG terminal in Europe.

15 Building up cyber defences David Miller, American Petroleum Institute (API), USA, looks at how the organisation’s standards address cybersecurity for the natural gas and oil industry.

19 A new arena of cyber protection Sam Miorelli, Siemens Energy, USA, looks at how to optimise refinery turnarounds with AI-driven cybersecurity advances.

THIS MONTH'S FRONT COVER

57 Blast test demonstration Dean Alcott, RedGuard, USA, details how a large-scale test demonstrates efficacy of steel blast-resistant modules.

61 Monitor, target, report Ronauld Weeks, Honeywell Connected Industrial, outlines best practices for energy management in today’s connected process industry.

Traditionally, refinery units are constructed on-site in a stick-built (site fabricated) fashion.

MOGAS Systems & Consulting’s (MS&C) approach is to build a modular process unit off-site in a controlled environment and provide delivery of a completed system.

The module features an excellent design, increased safety and push-button availability in one of the most complicated operations in a heavy oils unit.

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he recent cyberattack on the Colonial Pipeline has once again exposed the vulnerabilities in critical infrastructure.

At the time of writing, the pipeline had resumed normal operations, but only after Colonial had paid the US$4.4 million ransom demanded by DarkSide, the hacking group responsible for the ransomware attack. Colonial Pipeline’s CEO, Joseph Blount, told the Wall Street Journal that he authorised the payment after consultation with experts, as he did not know the extent of the damage or how long it would take to bring the pipeline’s systems back. A company spokesman said “Tens of millions of Americans rely on Colonial: hospitals, emergency medical services, law enforcement agencies, fire departments, airports, truck drivers and the travelling public.”

Undeniably, the pipeline is a critically important piece of national infrastructure.

Spanning 5500 miles between Texas and New Jersey, the pipeline carries approximately 2.5 million bpd of gasoline, diesel and jet fuel (around 45% of the fuel consumed on the US east coast). Wood Mackenzie has reported that the attack only had a marginal impact on fuel markets due to a combination of increased output from US refineries and imports from Europe.1 Of course, the fact that the ransom was paid quickly is another key reason for the limited damage; it is clear that the impacts would have been much more serious had the shutdown persisted for longer. It’s easy to sympathise with the dilemma facing Colonial in this instance. In Blount’s own words, the ransom payment was authorised as he felt that it was “the right thing to do for the country.”

However, the shared wisdom is that ransom payments only incentivise the hackers and fund future cyberattacks. It’s your classic ‘no-win’ situation (unless you are the hacker).

Our sector needs to learn from the incident and take active steps to protect itself from similar attacks. However, a recent study by Ponemon Institute and Siemens Energy revealed that although 56% of survey respondents had experienced a data breach or outage in the previous 12 months – and 54% expected an attack on critical infrastructure in the following 12 months – there was a pervasive lack of preparedness.

Only 31% of respondents believed they were ready to respond to, or contain, a breach.2 This issue of Hydrocarbon Engineering includes a dedicated section on cybersecurity, beginning on p. 15, with articles from the American Petroleum Institute (API) and Siemens Energy. The two pieces are very timely in light of recent events, and I’d encourage you all to take the time to read them. The API explains how its continuously updated standards help to address cybersecurity for the oil and gas sector, while the article from Siemens Energy looks specifically at how to optimise refinery turnarounds with AI-driven cybersecurity advances.

Before I sign off this month, I also wanted to remind everyone that Hydrocarbon Engineering will be hosting ‘SulfurCon 2021’ on 30 June. This free-to-attend virtual conference and exhibition will focus on the latest sulfur technology, innovations and services for the hydrocarbon processing sector, with expert presentations from leaders in the sector. For more information, and free registration, head over to www.hydrocarbonengineering.com/sulfurcon2021.

1.

2.

CROOKS, E., ‘Colonial pipeline hack exposes the vulnerability of critical infrastructure’, (14 May 2021), https://www.woodmac.com/news/opinion/Colonial-pipeline-hack-exposes-thevulnerability-of-critical-infrastructure/ ‘Caught in the Crosshairs: Are Utilities Keeping Up with the Industrial Cyber Threat?’, Ponemon Institute and Siemens, (2019).

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WORLD NEWS USA | Shell

sells refinery assets

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quilon Enterprises LLC d/b/a Shell Oil Products US, Shell Oil Co. and Shell Chemical LP, subsidiaries of Royal Dutch Shell plc, have reached an agreement for the sale of the Mobile Chemical LP refinery in Mobile, Alabama, to Vertex Energy Operating LLC. Vertex Energy is a US-owned, Texas-based specialty refiner of alternative feedstocks and marketer of high purity petroleum products.

The divestment is part of Shell’s strategy to reduce its global refinery footprint to core sites integrated with the company’s trading hubs, chemicals plants and marketing

businesses. These high-value energy and chemicals parks will produce more low-carbon fuels and specialty chemicals for Shell’s customers.

Shell Oil Co. has also confirmed that it has reached an agreement for the sale of its interest in Deer Park Refining Ltd Partnership, a 50-50 joint venture between Shell Oil Co. and P.M.I. Norteamerica, S.A. De C.V. (a subsidiary of Petroleos Mexicanos, or Pemex).

The transaction will transfer Shell’s interest in the partnership, and therefore full ownership of the refinery, to Pemex, subject to regulatory approvals.

Sweden | Haldor

Topsoe and Preem revamp Gothenburg refinery

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ogether, Haldor Topsoe and Preem have concluded the revamp of Preem’s Gothenburg refinery, which is part of Preem’s endeavour to reduce Sweden’s total carbon emissions by 20%.

This is the second revamp of the hydrotreater, following a revamp in 2010 that upgraded the unit to co-process 30% renewable feedstock using Topsoe’s HydroFlexTM technology.

With the second revamp, Preem and Topsoe have achieved 85%

China | North

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co-processing of renewable feedstock and continue to advance the field of renewable fuel production. Preem uses tallow and raw tall diesel as the main feedstocks.

The revamp of the refinery is a significant step in Preem’s long-term plan to produce 5 million m3 of renewable fuels by 2030. This would result in carbon emissions being reduced by 12.5 million t, corresponding to 20% of Sweden’s total emissions.

New contracts for Lummus Technology Egypt |

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ummus Technology has announced that its Novolen business has been selected as the polypropylene (PP) licensor by Anchorage Investments for its Anchor Benitoite project in Suez, Egypt.

Lummus’ scope includes the technology license for a 590 000 tpy PP unit as well as basic design engineering, training and services, catalyst supply and operator training simulator services.

The Anchor Benitoite project will encompass production units producing several different petrochemical products and intermediates. The project is envisioned to be a gateway to petrochemical activity on regional and global scales, increasing Egypt’s competitiveness and position as a petrochemical hub.

Lummus Technology has also announced an award for its butadiene extraction (BDE) technology from Korea Petrochemical Ind. Co. Ltd (KPIC).

The BDE unit will be part of KPIC’s Onsan Chemical Plant in Ulsan, Republic of Korea.

The project scope includes the technology license, basic engineering and training services. The unit will lead to the production of more valuable products from existing C4 streams and generate feed for an existing olefins conversion unit.

Huajin contracts DuPont Clean Technologies

orth Huajin Refining and Petrochemical Co. Ltd (North Huajin) has signed contracts with Refining Technology Solutions LLC, a subsidiary of DuPont Clean Technologies, for the license, basic engineering, and technical services for a new combined IsoTherming® kerosene/diesel hydrotreater (KDHT).

The grassroots hydrotreater is one of many units included as part of the greenfield fully integrated refining and petrochemical complex that will be located in Liaodong Bay New Area, Panjin, Liaoning Province, China.

North Huajin commissioned DuPont for an IsoTherming KDHT unit with a nameplate capacity of

37 000 bpd, capable of producing fuels compliant with both Jet 3 fuel standard and China VI diesel.

The technology will help the refinery minimise CO2 emissions due to lower energy requirement within the unit. This decrease in emissions will further assist China in its goal to become carbon neutral by 2060.

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WORLD NEWS DIARY DATES

Technip Energies lands large petrochemical contract

30 June 2021

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SulfurCon 2021 Online www.hydrocarbonengineering.com/sulfurcon2021

31 August - 2 September 2021 23rd Annual Aboveground Storage Tank Conference & Trade Show Orlando, Florida, USA www.NISTM.org

13 - 16 September 2021 Gastech Singapore gastechevent.com

21 - 23 September 2021 Global Energy Show Calgary, Canada globalenergyshow.com

26 - 29 September 2021 GPA Midstream Convention San Antonio, Texas, USA www.gpamidstreamconvention.org

05 - 07 October 2021 AFPM Summit New Orleans, Louisiana, USA afpm.org/events

13 - 14 October 2021 Valve World Americas Houston, Texas, USA www.valveworldexpoamericas.com

01 - 04 November 2021 Sulphur + Sulphuric Acid 2021 Online www.sulphurconference.com

05 - 09 December 2021 23rd World Petroleum Congress Houston, Texas, USA 23wpchouston.com

23 - 27 May 2022 World Gas Conference Daegu, South Korea www.wgc2022.org

To keep up with all the latest news on key industry events in light of the COVID-19 pandemic, visit hydrocarbonengineering.com/events

June 2021

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India |

echnip Energies has been awarded a large engineering, procurement, construction and commissioning (EPCC) contract by Indian Oil Corp. Ltd (IOCL) for its paraxylene (PX) and purified terephthalic acid (PTA) complex project in Paradip, Orissa, on the East Coast of India.

This EPCC contract covers the delivery of a new 1.2 million tpy PTA plant and associated facilities.

PTA is a major raw material used to manufacture polyester fibres, PET bottles and polyester film used in packaging applications.

The Paradip Refinery’s products meet the energy demands of the domestic market and are partly exported.

With the aim to create a value chain, Paradip Refinery has ventured into petrochemicals with the production of polypropylene (PP), mono ethylene glycol (MEG), and is now going into PX and PTA production.

In a press release, Technip Energies said that the availability of PTA at Paradip will provide a boost to polyester manufacturing facilities in the vicinity.

Nigeria | KBR

awarded EPC contract for BUA Group project

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BR Inc. has been awarded a contract to complete the front-end engineering design (FEED) for BUA Group’s new, modern refinery facility in Nigeria.

The award marks the continuation of a strong relationship with BUA Group, a leading agricultural and industrial chemicals conglomerate, after KBR successfully completed the conceptual feasibility study for the project in 2018.

The facility will support fuel production for Nigeria’s domestic and regional markets, helping to reduce the country’s dependence on imported supplies.

In a statement, KBR said that elements of the work will include sulfur removal facilities, water treatment facilities to meet high level environmental standards, and heat integration to ensure long standing efficiency of production.

Norway | Wärtsilä

to supply bio-LNG production plant

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ärtsilä has announced that it will supply a biogas liquefaction plant to Biokraft, a subsidiary of the Scandinavian Biogas Group.

The 25 tpd capacity plant will extend an existing bioLNG production plant at Skogn in Norway, also supplied by Wärtsilä, to a combined total of 50 tpd. This latest order was placed with Wärtsilä in April 2021.

The market for liquefied biogas continues to expand along with the increase in global efforts to restrict the use of fossil fuels. BioLNG is an abundant renewable energy source that is used as ‘green’ fuel in transportation, industrial, and marine applications.

The Wärtsilä equipment is scheduled for delivery in May 2022.

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Alan Gelder, Wood Mackenzie, UK, explains why the European downstream sector needs to adapt; doing nothing is not an option.

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he global pandemic has provided the European downstream sector with a glimpse into the future and clearly demonstrated that doing nothing is not an option for securing long-term survival. The pandemic, through various government lockdown measures, has shown a potential future of lower demand for transport fuels. This was a world in which the commercial viability of large swathes of European refining capacity was challenged, as Wood Mackenzie’s Refinery Evaluation Model indicates that only a handful of sites were cash positive in 2020 (so had a positive net cash margin [NCM]). Figure 1 also compares the 2019 NCM profile, where almost 70% of sites were cash positive. A cash positive position is key for sustained commercial success as it provides funds for future investment and returns to investors.

Demand growth will not suffice Since the end of March 2021, global oil demand has recovered strongly from the nadir of April 2020 when it had collapsed by around 20 million bpd compared to the previous year. 2Q21 global oil demand is already 13 million bpd higher than 2Q20 levels.

Wood Mackenzie projects oil demand to reach about pre-pandemic levels on a global basis towards the end of 2022. This is surely supportive for European refining?

The return of global oil demand to above pre-pandemic levels is necessary but insufficient for European refining’s commercial success for reasons of both demand and supply. Wood Mackenzie’s outlook of European demand is still 600 000 bpd below 2019 levels by the end of 2022, arising from a slow regional economic recovery and the gathering pace of energy transition, in which Europe is a leader.

On the supply side, very few refining projects under active development pre-pandemic were cancelled. Project completion has been slower than originally anticipated and the commissioning of mechanically complete facilities has been delayed given the poor refining margin environment. Even before the pandemic, new sources of supply were expected to outpace demand growth. The loss of three years of global demand growth hence poses a serious challenge to refiners as global utilisation is not anticipated to recover back to pre-pandemic levels during this decade unless refineries close. European refinery utilisation is particularly challenged as the new capacity additions are more competitive. As a region, it therefore struggles to export its growing surplus of gasoline (Figure 2).

Low utilisation and low refining margins are synonymous, so the commercial viability of the European refining industry is challenged for much of the current decade. The risk of rationalisation of competitively weak sites and poor margins for standalone fuels

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Figure 1. European 2020 preliminary net cash margin.

refineries is high. Cost reduction, efficiency improvements and improved optimisation remain critical to success, but these actions alone may not guarantee the survival of all European sites.

Adaption will be key.

Every refinery is unique, so there is a wide disparity of net cash margins across a region such as Europe. There were many sites in 2019 that enjoyed attractive net cash margins, but about one third of sites were cash negative for that period.

Figure 3 shows the 2019 European NCM profile, with the first and second quartiles dominated by integrated refinery petrochemical sites, with the weakest assets (in the fourth quartile) being predominately standalone fuels refineries. Any adaption strategies need to reflect the source of a site’s current competitive position and how these factors evolve in future.

Working in tandem with energy transition

Figure 2. Global and European refinery utilisation profile.

Figure 3. Competitive strength of integrated refinery petrochemical sites.

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As the world recovers from the COVID-19 pandemic, climate change is increasingly at the forefront of government policies. Energy transition is gathering pace. The associated electrification of the passenger car fleet will slow the pace of global gasoline demand growth and drive it into decline.

Meanwhile, the versatility and durability of petrochemicals ensures sustained demand growth, particularly in the developing world.

The first energy transition mega-trend relevant to refiners is a switch in demand away from gasoline to petrochemical feedstocks, so promoting the adoption of refinery – petrochemical integration, particularly for new facilities in Asia and the Middle East. In addition to diversifying the product slate, highly integrated refinery – petrochemical sites can capture higher value from economies of scale for investment, operational cost synergies and flexibility to shift yields to maximise overall site margins. There are risks to petrochemical demand growth as societies focus on the environmental challenges of plastic waste, so the growth for petrochemical feedstocks will be tempered by the increase in mechanical and chemical recycling rates. The mega trend will challenge the competitive position of many refining sites that currently enjoy advantaged ex-refinery gate pricing by virtue of their inland location. As local demand for refined products fall, any net deficit position becomes a net surplus unless supply is cut. The pricing consequences of such a shift can be dramatic, as it will prompt the rationalisation of inland sites, to the benefit of coastal locations.

The second energy transition mega trend is decarbonisation. This can be in a direct form in the reduction of carbon intensity of the fuels made available to consumers by increasing the contribution from biofuels or the chemical

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fuels refining; the NCM uplift grows as the yield of chemicals increases. This is an extract of Wood Mackenzie’s new site-specific benchmarking data available within its REM-Chemicals research.

As shown in Figure 4, it is important to understand the roles of different petrochemicals within the overall site economics and the context for the different contributions between sites. Given the cyclical nature of the petrochemical sector, these contributions will, no doubt, vary over time.

As shown in Figure 4, petrochemical integration clearly has benefits for overall site economics. The converse also applies in that refinery integration has clear benefits for the competitive position of petrochemical production. Figure 5 shows the cost of production profile for ethane crackers in Europe and the US. It shows the traditional profile of the Figure 4. European NCM uplift from petrochemicals against new ethane-based steam crackers in the petrochemical yield, 2019.

US Gulf Coast (USGC) being the most competitive, with the European liquids-based steam crackers being the least. However, extending the analysis of co-product credits to include the refined products from integrated sites can transform the competitive position along a petrochemical value chain. The additional co-product credits from the refinery re-locate the European site into one of the lowest cost producers within its peer group. For reference, the cost of ethylene production from the new Hengli facility (one of the world-scale second generation integrated sites recently commissioned in China) has also been included. Had it been fully operational in 2019, its ethylene cost of production would have been negative – a truly competitive position. Low costs of production along specific value chains ensure high utilisation at integrated sites despite margin weakness in any single petrochemical value chain. Wood Mackenzie Figure 5. US and European ethylene cost of production profile, considers it vital for the downstream sector to 2019. understand the economics of integrated sites to establish the dynamics of competitor behaviour in recycling of plastic waste. There is also the focus on emissions both refining and petrochemicals. reduction from the refining sector, which involves efficiency This disparity in overall site competitiveness arising from improvements and the potential switch away from methane petrochemical integration will remain in Europe, as it is steam reforming towards more sustainable forms of hydrogen expected to be one of the energy transition’s global leaders. generation. These are significant investments, for which returns Standalone fuel refineries face significant commercial pressure, may be poor as the technologies to decarbonise hydrogen so European refiners need to consider a strategic framework to production (CCS or electrolysis) are not yet mature. Whilst it is secure their long-term survival. critical to explore the role these technologies could play; it is Strategic framework for European sites key to allocate these activities to the sites that are sustainable The attributes of the ‘last site standing’ in the European refining far beyond the investment payback period. This is to ensure and petrochemical landscape that are commercially viable yet learnings can be captured and deployed effectively at locations compatible with Europe’s net-zero aspirations are: that will remain in commercial operation over the long-term.

Large, coastal, highly integrated refinery/petrochemical Chemical integration drives complexes that are globally competitive. competitive advantage during the Operating in a highly efficient, low carbon manner. energy transition An integral part of the circular economy (through In a world of globalised commodity markets in crude oil, adoption of second-generation biofuels and chemical refined products and bulk petrochemicals, a strong competitive recycling of petrochemicals) and integral to the local position is essential for high asset utilisation, positive cash community (via waste heat distribution to local flows and long-term sustainability. Petrochemicals add value to communities and other industries).

June 2021 12 HYDROCARBON ENGINEERING

Figure 6. Indicative European downstream decision tree (source: Wood Mackenzie).

Located in an industrial cluster that enables economies of scale on CCS, low carbon hydrogen and waste collection/management.

Given the uncertainty of the pace of the energy transition, agility will be a key attribute for any strategic framework that looks at the options available to individual refineries. Refiners will need to carefully monitor developments and opportunities for their transformation. This includes the policies and transformations in other sectors that will introduce new entrants into their traditional markets (as refined products compete with electricity and other sources as the energy for mobility).

Not all the current refining sites will survive the energy transition. Even for those that are currently well placed, adaption

is still required. The indicative decision tree (Figure 6) is a simplification of the options involved, with ‘no regrets’ moves focusing on efficiency improvements and margin capture through digitalisation and cost excellence, as well as benchmarking against key regional and global competitors to establish the current position of a site and the attributes of those that are already in first quartile.

Conclusion It is critical to understand what future success looks like in refining, petrochemicals, and emissions when mapping out any major investment to sustain the operating life of an existing asset.

Even in a rapid energy transition, the role of refining as a ‘conversion industry’ remains, but there will be less conversion of crude oil due to the greater role of alternative feedstocks.

Doing nothing in the face of the energy transition acknowledges that a site will ultimately close. For some, that could be the best decision, but one to be consciously made as part of business diversification. For those that aim to survive and thrive, they must invest and adapt to become one of the ‘last sites standing.’

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David Miller, American Petroleum Institute (API), USA, looks at how the organisation’s standards address cybersecurity for the natural gas and oil industry.

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s the pipeline cyberattack in the US demonstrated earlier this month, hardening our infrastructure to threats from bad actors is more important than ever before in order to reliably and safely meet our world’s growing energy needs. Over the last decade, the natural gas and oil industry has taken steps to address cybersecurity to protect the US’s critical energy infrastructure.

In fact, the American Petroleum Institute (API) has been working with experts since 2017 to update its pipeline cybersecurity standard which will publish later this year, hardening the industry cyber defences through a ‘layers of protection’ approach.

Recent cyberattacks underscore the seriousness of the threat and the need for industry to understand where its vulnerabilities lie. “It’s really highlighted the investments we need to make in cybersecurity to have the visibility to block these attacks in the future,” said Anne Neuberger, the Biden administration’s newly appointed Deputy National Security Advisor for Cyber and Emerging Technology.

The growing threat A report released last summer by the US Government Accountability Office (GAO) showed that the risk of

cyberattacks aimed at petrochemical facilities’ information and process control systems is growing.1 API has responded to these growing threats by updating its standards to account for the increased risk posed to the industry’s supervisory control and data acquisition (SCADA) systems, which are used to open and close valves and control critical safety systems across all segments of the natural gas and oil industry.

These control devices have been in use for decades but are increasingly being updated to make SCADA systems more interconnected to telecommunication networks and the internet. As these upgrades have increased across the industry, these devices have become more vulnerable to cyber intrusions, malicious software, viruses, and other cyber-based attacks.

The US Department of Commerce’s National Institute of Standards and Technology (NIST), the Department of Homeland Security, and other agencies have also been developing cybersecurity standards, risk management systems, and other systems of thought that address SCADA vulnerabilities to industrial facilities. API is working with these agencies to develop more robust cybersecurity protocols, risk assessments, technical evaluations, recommendations, and standards.

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Specifically, API’s standards programme has incorporated the NIST Cybersecurity Framework that provides principles and recommendations that all industries can use to address cybersecurity vulnerabilities. The framework has been applied around the world to help industry address critical infrastructure protection.

In addition, public-private collaboration and information sharing has become critical to addressing cyber threats and vulnerabilities. To this point, API is a participant in the Oil & Natural Gas Information Sharing and Analysis Centers (ONG-ISAC) and the Downstream Natural Gas Information Sharing and Analysis Center (DNG-ISAC). These organisations help coordinate the industry and its federal partners on cybersecurity and threat assessments.

Real world attacks Underscoring the risk to SCADA systems, there have been a number of recently reported cases of cyberattacks. In Florida, law enforcement officials stopped hackers who successfully tapped into a water utility’s SCADA systems with the intent of poisoning a town’s water supply.2 In this case, the utility’s vulnerability was its use of an older computer operating system with limited cyber protections. API has developed cybersecurity standards that can be applied across industries, and in this case could have been used to address the Florida utility’s vulnerabilities.

Utility and natural gas and oil operations have some similarities when it comes to their use of SCADA and other control systems in dealing with commodities. To this point, natural gas and oil infrastructure has always been a mainstay target for waging digital attacks. In 2017, Saudi Arabia’s vast petrochemical infrastructure was attacked using malware called Triton. Prior to that attack, the oil company Saudi Aramco experienced a 2012 cyberattack, which led to temporary supply disruptions. Learning from these attacks, as recent as October 2020, the US Treasury Department warned US companies that similar attacks were being considered against US energy assets.3

On the job Cybersecurity is a top priority for API member companies, and as owners and operators of critical energy infrastructure, API is providing leadership, proactive solutions, and ongoing coordination with federal agencies to help prevent future cyberattacks. Based on lessons learned from past attacks, the organisation works through its standards development process to identify key areas of operations that could be targeted by malicious actors, and then develop standards and recommended practices to counter those threats.

Two standards that are integral to API’s cyber strategy for downstream operations are API 780, ‘Security Risk Assessment Methodology’, and API 781, ‘Facility Security Plan Methodology for the Oil and Natural Gas Industries’.

Together, these standards offer the industry a way to assess the risk posed to a facility, and then use that risk assessment to provide recommendations on how to develop a comprehensive security plan.

API 780 provides the industry with the tools to conduct effective security risk assessments (SRA), which are used to identify the threats to facilities and establish measures to June 2021 16 HYDROCARBON ENGINEERING

help mitigate those threats. The API SRA methodology includes the following five steps: Characterise a facility’s infrastructure to assess the dependencies and interdependencies to understand which of the facility’s assets are most vulnerable and need to be secured.

Conduct a threat assessment, which is used to assess which of the facility’s assets would be the most likely targeted by an attacker. The threat assessment also determines the consequences if the assets are damaged, compromised, or stolen.

Conduct a vulnerability assessment to identify which kind of attack would be most successful if targeted.

Evaluate the consequences of an attack if it were to occur.

Perform a risk assessment to address response capabilities and countermeasures.

Once the SRA is completed, an effective facility security plan (FSP) can be developed using API 781. The FSP is individualised for a facility and outlines the procedures, processes, and responsibilities needed to help guard a facility against cybersecurity threats, as well as other security concerns.

The FSP provides facility personnel with guidance to protect employees, the surrounding community, the facility itself, as well as the company’s reputation. It is also essential that the FSP is periodically evaluated and updated to account for changes in operations, the environment in which the system operates, new data, and other security-related information. For example, the availability of new threat information may require a change in strategy for access control.

Personnel requirements are also essential to the proper management of the FSP in keeping a facility safe from attack. A cybersecurity officer should be designated to work with a company’s legal counsel on implementation of the plan, and access to the FSP should be restricted to the cybersecurity officer and other key officials that have been properly vetted.

Underscoring the effectiveness of these standards as deterrents, API 780 earned designation and certification by the Department of Homeland Security (DHS) as a qualifying anti-terrorism technology under the Support Anti-terrorism

by Fostering Effective Technologies (SAFETY) Act of 2002.

The SAFETY Act designation gives API members, and others that use the risk assessment methodology of API 780, liability protection if a terrorist attack were to occur at one of their facilities.

API 780 establishes a robust risk assessment process for natural gas and oil facilities, proactively enhancing safety and security for the industry, its workers, and the nation’s infrastructure. The liability protections are crucial to spurring the use and implementation of cyber risk methodologies, standards, and risk assessment systems across a number of industries that comprise the nation’s critical infrastructure. This important step by the federal government will help enhance national security through the application of API 780, which can help any operator enhance security at a range of facilities.

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API has also updated other key standards to include cybersecurity requirements. API Recommended Practice (RP) 554 for Process Control Systems addresses cybersecurity, adding requirements for software security protocols to be accounted for in control systems. The RP has three separate parts where cybersecurity is addressed. For example, Part 1 recommends that security and virus-protection become major concerns of newer Process Control Systems at both the design and operational phases. Part 2 addresses cybersecurity more comprehensively throughout the document, including software security, security and virus protection, and operating system security problems.

Process control system software design API RP 554, Part 3, goes on to address how cybersecurity should be part of a facility’s overall project planning.

It recommends that the planning process provide time and resources to identify the types of security systems necessary to protect each part of a facility’s control systems.

A framework for cybersecurity

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API is also updating its standard for protecting the control systems of pipelines and other large facilities. The forthcoming standard seeks to provide companies with the means of addressing cybersecurity risks more broadly across operations, including, but not limited to, pipeline operations.

The standard, API 1164, was first developed in response to the terrorist attacks of 11 September 2001. It was initially developed to help the industry understand and protect against the risks posed by any would-be attacker targeting a pipeline facility’s SCADA controls.

The latest version of API 1164, Third Edition, due to publish later this year, will provide the industry with a broader cybersecurity framework that lends flexibility in helping the industry address risks in all segments. This approach to cybersecurity applies to an increasing array of downstream operations, such as: Liquid transmission pipelines that handle a range of petroleum products, such as gasoline and diesel fuel.

Natural gas pipelines which deliver fuel to homes.

LNG operations that are delivering cleaner fuels around the world.

Propane air facilities.

This latest edition of API 1164 provides a set of requirements to help manage an operator’s cybersecurity posture by aligning a facility’s cybersecurity approach with the operator’s overall mission, objectives, risk strategy, and policies and procedures. The standard also provides the operator with a more holistic way of addressing cybersecurity, helping to enhance overall safety of the operation.

Since pipelines are required to both deliver and transport product to and from a refinery and other downstream facilities, such as LNG terminals, they are critical components that must be protected, or risk potential supply disruptions that can cripple the economy.

Looking to the future Overall, API stands ready to address new challenges facing the industry and has been actively working with its government and industry partners to address the risks posed by cyber adversaries and hackers. The organisation will continuously update its standards to incorporate improved analysis, new technologies, and risk management to enhance the industry’s resilience and, ultimately, the US’s infrastructure.

References

www.borsig.de/vt

1.

2.

BORSIG ValveTech GmbH Phone: + 49 (0)3304 288-0 Fax: + 49 (0)3304 228-50 ( PDLO YDOYHWHFK‫ך‬ERUVLJ GH *HUPDQ\

3.

Critical Infrastructure Protection - Actions Needed to Enhance DHS Oversight of Cybersecurity at High-Risk Chemical Facilities’, US Government Accountability Office (GAO), (May 2020), https://www.gao.gov/assets/gao-20-453.pdf BAJAK, F, SUDERMAN, A., and LUSH, T., ‘Hack exposes vulnerability of cash-strapped US water plants’, The Associated Press, (9 February 2021), https://apnews. com/article/business-water-utilities-florida-coronavirus-pandemic-utilitiese783b0f1ca2af02f19f5a308d44e6abb ‘Treasury Sanctions Russian Government Research Institution Connected to the Triton Malware’, US Department of the Treasury, (23 October 2020), https://home.treasury.gov/ news/press-releases/sm1162

Sam Miorelli, Siemens Energy, USA, looks at how to optimise refinery turnarounds with AI-driven cybersecurity advances.

C

yber threats are a real and growing risk to oil and gas operations up and down the asset chain. For refineries, the potential for a cyber-attack is not a rare, black swan event but instead an everyday occurrence that can significantly impact daily operations and long-term profitability.

Refineries are dynamic, active locations, with refinery personnel and people from many different vendors moving in and out of the site daily. As a result, the risk of someone plugging a random USB key into a computer and introducing – accidentally or purposely – some malware is much higher in a refinery than in a remote location such as a pipeline compressor station.

The risk compounds with multiple vendors, many of whom have their own equipment installed in the refinery’s systems. This equipment provides a data feed into the refinery and another entry point for a malicious cyber-attack.

The chances of a refinery falling prey to a cyber-attack increase substantially during a turnaround, shutdown, or outage. Whether it is maintenance to a single unit or a full-facility turnaround, a large number of unfamiliar people from original equipment manufacturer (OEM) providers and maintenance crews, who are not part of the day-to-day workforce, will have physical access to network endpoints throughout the facility. That access is not just limited to the specific machine they are working on but often includes adjacent equipment as well, since having an operations team member physically escort every worker all the time is not practical.

With so many new faces onsite making repairs and upgrades to the refinery’s operational technology (OT), the plant’s information technology (IT) systems are often left vulnerable. Turnarounds, shutdowns, and outages are ideal times to install new security patches and also make changes to the plant’s distributed control system (DCS), HYDROCARBON 19

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June 2021

event, it is taken out of observer mode to track and control normal operations – without the risk of shutting down a critical component of the refinery’s operations.

During a turnaround, shutdown, or outage, the platform can be easily placed back into observer mode, where it continues to track and report non-routine events or potential cyber Figure 1. As cyber threats increase in their sophistication and frequency, threats – but without the ability to the time for refiners to shore up their defences is now (image courtesy of intervene and prevent the perceived Siemens Energy). threat from entering the system.

This is particularly important when a which requires disabling some antivirus protections and other legitimate software upgrade from a vendor might be mistaken network security functions. This situation makes the plant as malware simply because the upgrade is so new or unfamiliar particularly vulnerable to a cyber threat. to the platform. But rather than shutting down the system and Whether the attack originates from within or outside, one delaying the upgrade, the platform records and reports the or more refining processes may be adversely affected. Critical event to the operations team, who can then investigate the systems and equipment might experience a drop in output or situation further. performance – or may fail altogether. And because the Because the cybersecurity platform is endpoint-based, it refiner’s legacy antivirus and cyber protection systems are identifies the physical location — the computer or system intentionally offline so that software updates or changes can – where the issue was detected. As a result, the operations be applied, a failure on startup may be hard to diagnose. Did a team can quickly go to that location, confirm the threat, and mechanical repair or upgrade fail? Did the vendor misconfigure resolve the situation – before the threat spreads to other their controls software? Or has malware crept in unnoticed? systems or becomes a more severe issue. Therefore, a refiner This all-too-common scenario presents a paradox. During can be confident that restarting issues are not symptoms of a major work, the refiner does not send its teams of physical nascent cyberattack. security personnel home and turn off the security cameras.

Tracking threats in one or more Yet when performing some OT and IT upgrades, the unwary facilities refiner does the cyber equivalent, leaving their systems Historically, if a cyber threat was detected during a patching exposed and blind to cyber threats — when those security operation, the refiner would have to spend extra time tracking functions are most critical. down the precise location of the threat. This is because legacy Shoring up cybersecurity with AI systems did not afford easy access to the data from one advances reporting interface – particularly in heterogeneous operations Threats like the ones described above are all too real and very in which multiple systems running on multiple operating expensive. In 2019, for example, Mexico’s state oil company systems had to be tracked.

Pemex was the victim of a ransomware attack that forced it to The platform does not require every machine it is tracking shut down many of its computers across the country.1 The to be running on the same version of the operating system (OS) attackers demanded US$5 million of Bitcoin to unencrypt the or even a current OS. The operator can quickly identify and affected computers, which Pemex refused to pay. While the review potential threats from multiple systems without having company stated that only 5% of its computers were impacted to piece together and convert data from machines running company-wide2, the situation required Pemex to quarantine different versions of the OS. and clean the affected systems — a costly and This new platform improves threat tracking and reporting in time-consuming operation. a heterogeneous plant environment. A management function In response to these types of challenges, Siemens Energy built into the platform allows refinery operations to assess and SparkCognition have teamed up to develop threats from many machines throughout one facility – or across DeepArmor Industrial, fortified by Siemens Energy, a multiple connected facilities – all through a single console. cybersecurity platform that leverages artificial intelligence (AI) This function moves the refiner away from a and machine learning to protect endpoint assets in the machine-by-machine lockdown approach and toward one refinery. This platform provides a means of always keeping the location where they can review and assess the entire refinery’s cybersecurity function online, even when certain IT operation with greater confidence and efficiency. If a threat cybersecurity functions must be disabled. is found, the affected endpoints can be locked down by The platform achieves this level of protection due to its DeepArmor Industrial from the central console – machine learning functionality. When DeepArmor Industrial is dramatically speeding up response times. first installed, it is placed in observer mode as it learns the As the OEM for the platform, Siemens Energy can perform processes. Once the refiner and Siemens Energy’s engineering the refinery’s cyber-threat monitoring function, freeing up team are convinced that the platform understands the operations personnel to perform other critical tasks when difference between routine operations and a cyber threat teams are stretched by aggressive turnaround schedules.

June 2021 20 HYDROCARBON ENGINEERING

Extending operations profitably by delaying patching outages A refinery’s IT department might recommend conducting small outages to install patches on a more frequent basis, perhaps even once per month. However, this frequency is not cost-effective and does not line up with the refinery’s business model.

The platform gives the refinery’s operations team a rational justification to delay that patching outage due to other business needs. Because of its AI capabilities, the platform stays ahead of vulnerabilities such as zero-day attacks and other critical threats.

While not a replacement for patching, the platform can act as a bridge to the refinery’s next reasonable opportunity to do a patching outage. The platform’s real-time, continuous tracking of threats gives the operations team confidence to delay an outage on a critical piece of equipment by a few weeks or months, extending profitable operations without putting plant systems at risk.

Entering a new arena of cyberspace protection A recent study by Ponemon Institute and Siemens Energy showed that while two-thirds of oil and gas executives say that their companies benefit from digitisation, even with the increased risk of cybersecurity threats, only 18% of energy companies are using AI to detect attackers.3 This is certainly evident when one considers the typical preparation for a turnaround. A great deal of thought and effort goes into ensuring that all the required hardware and

equipment are ordered and ready; however, much less planning goes into preparing on the software and digital side.

The potential cyber risks that the refinery could face during the outage are often not the foremost consideration.

But with advances such as AI-powered cybersecurity platforms, it does not have to be this way. It is possible for refiners to enter a new, assured arena of cyber protection – both during routine operations and when time is critical during outages, shutdowns, and turnarounds.

Cybersecurity platforms can provide day-to-day protection from external threats (e.g. zero-day attacks) and internal threats (e.g. an unexpected USB key) with its AI and machine learning capabilities. And in a turnaround, the platform’s ability to continuously monitor cyber threats gives refiners confidence that they will not miss a malware attack while busy with other outage-related activities.

As cyber threats increase in their sophistication and frequency, the time for refiners to shore up their defences is now. Refiners require a robust cybersecurity platform that can support both OT and IT systems and significantly lower the risks of a cyber-based attack taking down their plant.

References 1.

2.

3.

BARRERA, A. and SATTER, R., ‘Hackers demand $5 million from Mexico’s Pemex in cyberattack’, Reuters, (12 November 2019), https:// www.reuters.com/article/idUSKBN1XN03A ‘Pemex Is Operating Normally’, Pemex, (11 November 2019), https:// www.pemex.com/en/press_room/press_releases/Paginas/2019-048_ national.aspx ‘Caught in the Crosshairs: Are Utilities Keeping Up with the Industrial Cyber Threat?,’ Ponemon Institute and Siemens Energy, (2019), https://assets.new.siemens.com/siemens/assets/api/uuid:35089d45e1c2-4b8b-b4e9-7ce8cae81eaa/siemens-cybersecurity.pdf

HYDROCARBON 21

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June 2021 22 HYDROCARBON ENGINEERING

LEADING THE WAY TO

W

Joseph C. Gentry and Charlie Chou, Sulzer Chemtech, GTC Technology, USA, explore three basic elements that are likely to be seen to be part of the refinery of the future.

hile the oil industry is often attacked by vocal opponents of fossil fuels, who may ignore the positives of affordable energy and product innovations, it is clear that the refining industry will have to adapt in the future. This article will explore three basic elements that are likely to be seen in the refinery of the future.

Changes to the product mix The first dimension of the refinery of the future will be to produce less fuels and more petrochemicals. Fuels are used for transportation, heating and utilities, and the trend around the world is towards more fuel efficiency. This will result in relatively less demand for gasoline and diesel. Additionally, there will be more alternative energy resources used, where reliability of stable

production from wind or solar is not a factor. At the same time, there will be increased demand for petrochemicals to make plastics and other consumer goods, particularly propylene and aromatics.

Future of gasoline Motor gasoline is faced with the challenge of reduced long-term demand, and also more stringent specifications, particularly aromatics and sulfur. This challenge can be addressed by using a process that combines a refinery operation with petrochemicals, such as Sulzer Chemtech’s GT-BTX PluSSM. Aromatics and sulfur are extracted out of gasoline to produce high-purity petrochemicals. The rejected part is the olefin-rich fraction that can be converted into other petrochemicals by cracking or aromatising.

HYDROCARBON 23

ENGINEERING

June 2021

Therefore, petrochemicals can be made from something that would be going to a fuel. This process also desulfurises FCC gasoline without losing octane value.

Among all blending sources for the gasoline pool, FCC naphtha is the major contributor for the sulfur and usually requires hydrodesulfurisation (HDS) treatment.

Catalytically cracked gasoline also provides a good octane number, largely due to its rich olefin content.

However, regardless of the use of sulfur-selective catalysts, the FCC naphtha HDS still inevitably saturates a significant portion of olefins, and results in octane number loss across the FCC naphtha HDS unit. This is more of an issue as the specification for sulfur is reduced to the level of 10 ppm. Each olefin molecule going to its corresponding paraffin will lose approximately 50 octane numbers. RON loss in the FCC gasoline has become a pressing issue for the refineries trying to meet higher gasoline standards.

The GT-BTX PluS technology is a simple two-column extractive distillation system that can be dropped into the typical FCC naphtha HDS configuration, and avoids the octane loss problem. Figure 1 shows a typical FCC naphtha HDS configuration and the upgraded configuration with this technology.

In the upgraded configuration, the majority of olefins that were in the original HCN are cut to a new MCN stream, which is fed to the GT-BTX PluS unit.

The unit efficiently separates the MCN into two product streams with a selective solvent tailored specifically Figure 1. Typical naphtha HDS configuration compared to upgraded configuration with GT-BTX PluSSM. for this application.

Aromatics and sulfur compounds are separated Table 1. Comparison of FCC naphtha scheme with and without GT-BTX PluSSM into an extract, and the non-aromatics (including Conventional FCC naphtha Improved FCC naphtha desulfurisation scheme without desulfurisation scheme with olefins) become a raffinate.

GT-BTX PluS GT-BTX PluS The extractive distillation is Octane loss 2–5 <0.5 done by using Techtiv DSSM solvent. In this case, the Base Base x 40% (60% reduction) H2 consumption for HDS raffinate, having low sulfur Number of HDS reactors 1–2 No more than 1 (<10 ppm), can be blended HDS reactor size and HDS Base Base x 25% (75% smaller) directly into the gasoline catalyst volume pool without going to the Intermediate H2S stripper Required for Euro-5 Not required HDS unit. Therefore, almost Use of other high-octane Standard Less the entire quantity of olefins gasoline source (e.g. reformate, is preserved, and the octane oxygenate) to gasoline pool loss is reduced to nearly Yield for premium gasoline Standard More zero, regardless of how Flexibility to convert gasoline None Yes stringent the gasoline sulfur to petrochemicals specification is.

June 2021 24 HYDROCARBON ENGINEERING

Figure 2. GT-BTX PluS for petrochemical products.

Figure 2 shows an FCC naphtha processing configuration with a GT-BTX PluS unit aligned for the purpose of petrochemical production.

This configuration is basically identical with the one shown in Figure 1 for gasoline production. In the petrochemical mode, the extract from the GT-BTX PluS unit (which is already pure aromatics plus sulfur) is diverted to a separate small HDS unit, where the sulfur is reduced to <1 ppm. Right after that, the petrochemical-grade BTX is produced. Depending on the FCC severity, the aromatics content in the MCN can range from 30% to 75% from the dehydrogenation reactions. Considering that the FCC is often the largest unit in a refinery, and that much of the energy has already been input to the cracking reactions, it is prudent to convert the FCCU into a major aromatics producer.

The configuration with GT-BTX PluS provides unique flexibility for the refineries, with a very small investment, to easily convert gasoline molecules into petrochemical molecules. Such refineries will have premium position to continue to prevail in the future market.

Intensely optimised for energy efficiency Figure 3. GT-DWCSM dividing wall column.

Table 1 compares the key differences of the two configurations.

Gasoline to petrochemicals Another challenge for the current refineries in the world is the rapid market change away from fuels and toward petrochemicals, which has a steady growth rate in the long-term forecast. Catalytic cracking dehydrogenates heavy feedstocks into many unsaturated components, which are intermediates to petrochemical products. The raffinate fraction from GT-BTX PluS technology is concentrated in these components, which can be re-cracked or further cracked into propylene; or aromatised into additional BTX components. By recycling this raffinate, the FCC propylene yield can be potentially increased by 2 – 6%, which is a boost for FCC units aiming for maximising propylene.

The existing LCN can also be recycled back to the FCCU for propylene yield increase. The HHCN (the heavy remaining portion after the light portion of the original HCN was cut to MCN) is heavy enough to be blended into the diesel or jet fuel pool if desired.

June 2021 26 HYDROCARBON ENGINEERING

The second element that will be common in the refinery of the future will be intense adoption of energy efficiency. This will include pinch technology in heat exchange, recovery of low-level heat from waste sources, and reconfiguration of separation schemes.

Along these lines, Sulzer Chemtech uses dividing wall column (DWC) technology in a number of unique applications. A dividing wall separates a column into two parts: a prefractionation zone where the widest components are separated first and a final fractionation zone. This avoids the thermodynamic inefficiency of back-mixing components, resulting in lower energy consumption. The single column design also has lower capital costs.

DWC technology is not new, but relatively recent to move into the mainstream due to misunderstandings about how the systems work and the interface between process application and equipment design. Sulzer Chemtech brings all of this under one umbrella with single point responsibility for the process guarantees.

One particular advantageous technology is to use a top DWC to recover LPG from fuel streams. LPG creates higher greenhouse gas emissions than dry gas in the fuel system. In this design, the functions of heavy oil absorption on one side of the top wall are combined with conventional rectification on the other side of the wall. By doing this, it is possible to obtain >97% propane recovery from refinery offgas without using a refrigeration system.

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Other applications that are prime candidates for DWC technology include naphtha splitting, isom unit recycle processing, food-grade hexane and BTX separation.

Hybrid solutions are another way to reduce energy consumption along with bringing additional benefits.

A hybrid design combines two separate technologies which are most effective in a certain operating regime

Table 2. Comparison of two columns to GT-DWCSM Equipment count and plot space Equipment

Conventional two column system

GT-DWC

Column

2

1

Reboiler

2

1

Condenser

2

1

Pump

4

3

Plot space

100%

Approximately 30% less

Figure 4. Flow sketch of GT-LPG MaxSM.

into a single operation that covers the full regime. One example is GT-LLESM, where liquid-liquid extraction is combined with extractive distillation for aromatics recovery. Each operation is used where it is best applied to save energy and experience better performance.

Another application of a hybrid technology is GT-Styrene20SM, which uses distillation or extractive distillation combined with crystallisation to produce an ultra-high purity styrene product. In this technology, low-quality styrene coming from steam cracker pyrolysis gasoline or polystyrene recycle pyrolysis oil is concentrated by distillation/extractive distillation, then finally purified by crystallisation. Ultra-high styrene is produced, which exceeds all industry standards, even from highly contaminated feedstocks. Hybrid technology enables production of valuable petrochemical products, which would otherwise go to fuel.

Environmentally sound and operationally safe The third pillar of the refinery of the future is having operations that are environmentally sound and operationally safe. This includes reducing waste, upgrading waste to usable products, and meeting clean fuel regulations. In addition to having GT-Styrene20 applied to recycle polystyrene, other waste plastics can be pyrolysed and processed into petrochemicals or refinery fuels. Before the products can be introduced into the refinery, the raw materials need to be pre-treated to eliminate the objectional components and poisons that would preclude the further processing.

Sulzer Chemtech offers MaxFluxTM technology for this need, along with further upgrading of the components to its optimal destination. If the feedstocks are from agricultural waste, BioFluxTM technology is applied, which is designed for the oxygenates and other components unique to biological sources.

To be operationally safe, there is a continuing trend to reduce usage of hazardous solvents. There are many components such as dimethyl formamide (DMF), acetonitrile (ACN), and n-Methyl pyrollidone (NMP), which are on the high hazard list, and restricted in their use. Sulzer Chemtech has introduced different solvents under the name Techtiv to replace some of these hazardous chemicals.

Conclusion

Figure 5. GT-Styrene20SM.

June 2021 28 HYDROCARBON ENGINEERING

In the old days, the primary function of refineries was ‘boiling oil’, simply to separate it into different fractions. The refinery of the future will be much different, having adopted all of the catalytic and conversion processes already, and moving into more petrochemical operations with higher efficiency, safety, and integration of operations. New technologies will lead the way to this transformation.

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We lead FCC catalyst innovation for your optimizing needs Exceeding customer expectations for ‘bottoms cracking’

F

A. Chen, A. Novotny, T. Case, D. Banks, and B. Eren, BASF, USA, outline how FCC catalysts optimise bottoms cracking.

luidised catalytic cracking (FCC) unit bottoms are often one of the lowest value refinery products, and thus good bottoms cracking performance is desired by many refiners. This desire is evident in that bottoms cracking is consistently one of the most requested objectives for catalyst selection studies. Bottoms yields are typically set by refinery crude selection, market economics, and unit limits, which are all often outside of FCC unit control. The choice of FCC catalyst strongly influences bottoms cracking performance, and is therefore a cost-effective and practical solution to optimising FCC bottoms yields. This article discusses the main considerations that influence bottoms cracking, and then presents case studies demonstrating the value of good catalyst design strategy for minimising bottoms yield.

Recently, there has been intense focus on developing catalytic materials to minimise bottoms yields, but it can often seem mysterious how those novel materials are utilised to improve refinery profitability. A sound catalyst design must factor how catalytic materials interact with complex refinery objectives and constraints to unlock profitability. In fact, the meaning of ‘bottoms cracking’ may be dependent on unit circumstances (e.g. minimum bottoms vs heavier bottoms) and sometimes may not even address bottoms yield directly (e.g. increased light cycle oil [LCO], minimum coke, or heavier feed). Improving bottoms cracking does sometimes require using novel matrix materials; however, it is often straightforward to enable bottoms cracking simply by adjusting LPG/naphtha

ratio to enable higher conversion. The following sections of this article cover key factors which influence bottoms yields and the value of bottoms conversion.

Feed and catalyst impacts on bottoms yield, bottoms quality, and coke It is well understood that FCC feed quality represents the single largest contribution to conversion and raw product quality. In general, a lighter feed (high API) tends to be more crackable than a heavier, resid-based feed. Higher-boiling range materials in resid feeds have greater concentrations of aromatics and are thus more difficult to crack in an FCC unit. In addition to measuring bulk properties, it is important to understand feed sources since feeds which appear similar based on bulk properties can exhibit quite different crackability. For example, due to its high aromaticity, coker gasoil produces lower conversion and less valuable yield slate compared to vacuum gasoil (VGO) than would be expected by examining bulk properties.

Feed metals and nitrogen content also have a profound influence on bottoms upgrading improvement, by directly inhibiting the FCC catalyst’s performance and impacting yields.

By far, the most impactful feed metals are sodium and vanadium, which irreparably destroy the catalyst’s crystalline structure, leading to reduced activity, lower conversion, and poorer coke selectivity. The strong dehydrogenation activity of nickel and copper deposits on catalyst directly increase FCC dry

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gas yield. Iron can also be troublesome for some catalysts, as it blocks surface pores, thereby preventing access to interior active surface area.

In terms of catalyst design, the elements which hold greatest influence over bottoms upgrading capability are matrix activity and rare earth content. Specifically, catalyst suppliers consider zeolite-to-matrix (Z/M) and rare-earth-to-zeolite (REO/Z) ratios when designing a catalyst formulation for improved bottoms upgrading performance.

Matrix activity plays a prominent role in a catalyst’s bottoms upgrading capability by increasing LCO/bottoms vs coke.

Typically, the lower a catalyst’s Z/M, the greater the extent of bottoms upgrading which can be expected for a given catalyst activity and conversion. Moreover, the type and relative quantity of matrix employed will impact bottoms upgrading, as well as coke and yield selectivities. A common trade-off for improved LCO/bottoms is reduced activity retention. Since LCO/bottoms typically improves with increased activity, the Z/M vs activity relationship must be carefully considered when designing a catalyst for optimal bottoms upgrading.

Increasing rare earth content will increase activity, thereby increasing conversion and bottoms upgrading capability.

However, the resulting increase in the catalyst’s REO/Z ratio will tend to impart a higher gasoline selectivity and reduced gasoline octane, along with lower LPG olefin selectivity. Having an awareness of these trade-offs enables the refiner and catalyst supplier to move a unit around its optimisation space to fully optimse bottoms upgrading performance.

Impacts of FCC constraints Now that this article has touched on feed and catalyst factors which influence bottoms yield, it will focus on how unit constraints influence how a refiner may view and approach bottoms upgrading. Often, unit constraints dictate bottoms cracking limits, and understanding constraints determines what bottoms cracking means to that unit and what can be done to achieve the objective. While feed quality is not typically

Table 1. Example pricing for typical FCC products US$/bbl

Specific gravity

US$/t

% naphtha

Fuel gas (C2-)

16

0.51

196

35

C3

27

0.51

334

60

C3=

33

0.52

398

71

nC4

31

0.58

334

60

iC4

31

0.56

346

62

C4=

90

0.61

930

167

Light naphtha

63

0.71

558

100

Heavy naphtha

63

0.77

515

92

Light cycle oil

74

0.93

500

90

Bottoms

57

1.05

341

61

Feed

59

0.90

412

74

1,3 C4==

June 2021 32 HYDROCARBON ENGINEERING

adjustable, catalyst can be tailored to produce optimal yields with a unit’s constraints. This section walks through ideas for addressing some common constraints.

The most common constraints encountered on an FCC relate to key rotating equipment, such as the main air blower and wet gas compressor. Constraints on both pieces of rotating equipment limit conversion, and thus limit bottoms cracking. An FCC facing a wet gas compressor constraint could limit the reactor temperature, thereby reducing the flexibility to increase conversion. An FCC facing a main air blower constraint could be limited on the minimum feed preheat temperature and maximum reactor temperature. Thus, consideration of REO/Z and Z/M ratios is important to optimise catalyst activity in order to maximise conversion within the reactor temperature and catalyst to oil limitations set by these pieces of equipment.

Additionally, the ability to reduce bottoms may be hindered by metals contamination from heavier feedstocks. The tendency of a feed (e.g. concarbon, metals) to produce high delta coke often leads to high regenerator temperatures and results in similar limits on conversion. High contaminant metals could lead to excessive coke and dry gas yields, limiting both the main air blower and the wet gas compressor or resulting in a fuel gas processing limitation. Increased contaminant metals could also push a unit to its catalyst addition limit to maintain a target catalyst activity. Thus, catalyst design must take metals trapping and passivation into consideration along with the zeolite and matrix surface areas to achieve target activities within catalyst addition limits.

The opposite spectrum of this is a feed processing lighter, more easily crackable feed. In these scenarios, coke selectivity or delta coke may not play as big of a role in the unit limits.

Instead, the limits could relate to hydraulic limits, such as maximum LPG handling, maximum LCO rundown, or even minimum bottoms rundown rates. In these cases, the unit may have enough air blower capacity to increase reactor temperature to reduce bottoms yield. This higher reactor temperature, however, could lead to a catalyst circulation limit or even an LPG hydraulic limit. In this case, catalyst activity could be utilised to improve LCO/bottoms or even bottoms yield. At minimum bottoms rundown limits, ‘improved bottoms cracking’ could simply mean shifting gasoline into LCO to improve LCO/bottoms ratio.

Impacts of FCC operating targets As options for upgrading bottoms are considered, it is essential to understand the relative value of products that bottoms will become. Refineries generate FCC price sets to allow optimsers to analyse different scenarios to identify the most profitable strategies. Analysing these price sets directly provides insight into the best catalyst design strategies to meet an FCC’s needs.

Table 1 shows example prices for typical FCC products. The first column of the table shows prices in US$/bbl, which is often how they are represented, particularly in North America. In this example, naphtha, LCO, and C4= have higher US$/bbl values than feed, and the rest of the products have lower US$/bbl value than feed.

Column two shows how broadly specific gravities vary for the different FCC products. Because of the variation in product densities, it can be difficult to appreciate the impact of volume swell on unit economics. Another way to represent a price set is

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to use product densities to convert to mass-based pricing, which is shown in the third column. By representing pricing this way, it is much easier to directly compare product value by removing effects of volume swell from pricing. An extra simplification for analysis is to normalise prices to a specific product or feed – column four shows product values (on a mass basis) normalised by dividing by light naphtha price.

Column four identifies the relative value of products and makes readily apparent, for example, which products have higher or lower value than naphtha or bottoms. One price comparison that may not be immediately intuitive in this example is light naphtha vs LCO. On a volumetric basis, LCO appears to be more valuable, but because of the significant density differences in the products, light naphtha is approximately 10% more valuable than LCO. Another comparison that could be unexpected is that bottoms and LPG saturates have almost the same value, so a shift of bottoms to LPG is approximately at break-even in terms of economics.

When bottoms cracks to other products, value will typically increase (with the exceptions of fuel gas and coke), so it is completely reasonable to minimise bottoms. What is equally significant as minimising bottoms is optimising what bottoms conversion produces. In the example price set, it is not surprising that C4= is the most desired product, but it may be surprising that naphtha is the next most valuable product. It is also interesting that, though incremental LPG impacts wet gas compressor capacity, there is no economic penalty otherwise for producing LPG from bottoms. This example analysis shows how a little bit of work can provide significant clarity and thus transform a generic catalyst objective from ‘minimise bottoms’ to ‘maximise conversion of bottoms to C4= and naphtha.’

Balancing operation vs constraints to maximise flexibility Up to this point, this article has discussed how bottoms conversion is impacted by feed quality, catalyst properties, operating limits, and economics. The challenge to designing an effective catalyst solution comes from finding out how to piece together all of these factors into a formulation that not only meets unit objectives but is also valuable considering reasonable potential process or market upsets. With a cursory look at the example price set in Table 1, it might seem that the best catalyst should be one with a specialty matrix product with the highest LCO/bottoms vs conversion characteristics.

However, a closer look showed that naphtha should be favoured over LCO. Bringing a light ends constraint into the picture makes the problem even more interesting – how do we consider the trade-off if converting a pound of naphtha into C4= causes us to de-convert a pound of naphtha (or LCO) into bottoms?

The example price set shows that converting a pound of bottoms to naphtha or LCO is more valuable than converting a pound of naphtha to LPG=. If the FCC is operating against a light ends limit, incremental conversion could be more valuable as naphtha than LPG=. However, if the FCC is operating less constrained (as many units did during the COVID-19 pandemic), it could be valuable to put more emphasis on producing LPG=.

Accounting for unit constraints, an objective to ‘minimise bottoms’ could be transformed into something more specific such as ‘maximise conversion of bottoms to naphtha’ or June 2021 34 HYDROCARBON ENGINEERING

‘maximse conversion of bottoms to C4= and naphtha.’ Other constraints (temperatures, pressures, etc.) or adjustments in feed or product pricing could also be easily incorporated into the analysis. For example, if LCO values were higher or LPG values were lower, then it would be straightforward to translate the bottoms objective accordingly as ‘maximise conversion of bottoms to LCO and C4=’ or ‘maximise conversion of bottoms to naphtha and LCO.’ Similarly, regen temperature or air limits could change the bottoms objective to ‘minimise coke’ (or even ‘maximise coke’ for cold regens).

As mentioned earlier in this article, a request for ‘bottoms cracking’ can be translated into several different detailed objectives to address the needs of each refinery, and this piece has touched on just a few. The relatively simple example outlined thus far illustrates how economics forms the basis for identifying opportunities to capture increased profits through catalyst improvements. Actual examples are usually more complex and could involve more complicated scenarios, but similar logic still applies. By approaching catalyst optimisation systematically, very specific objectives can be defined to support maximum value capture. A few real-world examples are discussed in the following section to illustrate how a refiner can maximise value capture, along with where it is possible to run into pitfalls and how to address them.

Case studies After identifying the objectives and constraints required to enhance bottoms upgrading at the FCCU, the next step is to design a catalyst that maximises the refinery’s economic objectives while delivering flexibility in operations. A good catalyst design for bottoms upgrading starts with dialling in the zeolite to matrix ratio and optimising rare earth level. Increasing matrix area and/or employing specialty matrix to improve bottoms cracking without considering appropriate zeolite content can produce a low activity catalyst, which may carry higher catalyst addition requirements. The additional catalyst required would effectively counter any potential bottoms upgrading benefits with increased operational expenses. Along with finding the optimum Z/M ratio, the proper rare earth is necessary to maintain healthy coke selectivity and yield selectivity. The following case studies highlight the importance of the Z/M ratio of the catalyst design when focusing on bottoms upgrading to meet different operating objectives.

Case 1: VGO FCC seeking bottoms upgrading with coke selectivity In this first case study, a North American refiner that typically processes VGO feeds wanted to run a greater quantity of challenge feedstocks. Working with BASF as the incumbent catalyst provider, an extensive review of the FCC constraints was conducted by utilising KBC PetroSim to identify how operational flexibility can be maximised around the unit’s constraints. After reviewing the FCC product price set, it was determined that BASF’s Luminate technology would be well suited to maximising conversion and bottoms upgrading with a focus on reducing dry gas yield, improving coke selectivity, increasing bottoms cracking and increasing LPG olefinicity.

Luminate design features include increased matrix surface area along with pointed adjustment of zeolite and rare earth levels, which allowed for an optimised pathway to bottoms

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upgrading at this refinery. Table 2 highlights resulting ACE yield shifts for Luminate’s performance at similar catalyst activity.

Dry gas was reduced while the improvement in coke selectivity translated to a 15°F reduction in regen bed temperature and notable increase in catalyst-to-oil ratio. The change to Luminate increased overall liquid yields of gasoline and LCO via improved bottoms conversion and coke selectivity.

Table 2. Luminate yield shifts Average values

Wt% delta

FACT activity

+0.1

Nickel (ppm)

-100

Vanadium (ppm)

-150

Dry gas

-0.3

C4=/C3= (wt/wt)

+0.1

Gasoline (C5 – 430°F) + LPG

+1.6

LCO (430 – 730°F)

+0.6

Bottoms (730+°F)

-0.7

Case 2: balancing zeolite-to-matrix and activity to maximise bottoms upgrading This second case study emphasises the importance of tuning into the proper amount of Z/M in the catalyst design for optimal bottoms upgrading performance. The VGO unit was being supplied the incumbent Catalyst 1 (BASF NaphthaMax, high Z/M), when production objectives shifted due to a more bottoms upgrading centric economic profile. The following two bottoms upgrading catalysts were evaluated in a back-to-back trial structure: Catalyst 2 (non-BASF, low Z/M catalyst) and Catalyst 3 (Luminate, moderate Z/M catalyst).

Figure 1 illustrates the range of catalyst additions employed for the respective catalyst technologies, and Figure 2 highlights the LCO/bottoms performance for each relative to conversion. At slightly increased addition rates on average, Catalyst 2 consistently carried lower activity than the incumbent catalyst. Any technological bottoms cracking improvement which might have been offered by Catalyst 2 was overshadowed by the loss in conversion, such that there was no discernible difference in bottoms upgrading performance between NaphthaMax and Catalyst 2. The unit was then transitioned to BASF’s Luminate technology, designed with a moderate Z/M to preserve base activity while utilising improved matrix. While catalyst additions for Luminate were increased over NaphthaMax, bottoms upgrading was clearly differentiated from both preceding technologies. Applying seasonal product pricing to the yield shifts observed under Luminate for improvements in bottoms upgrading, and in consideration of the additional catalyst additions, the unit saw an uplift of around US$0.2/bbl for the technology upgrade. For a 50 000 bpd FCC, this translates to around US$3.5 million in increased profitability for one year. The comparative performance represented here serves to reinforce the importance of perfectly balancing Z/M with activity to optimise unit performance and profitability while minimising OPEX exposure.

Conclusion Figure 1. Box plot of catalyst additions.

Figure 2. LCO/bottoms selectivity vs conversion.

June 2021 36 HYDROCARBON ENGINEERING

The often requested and broadly-based objective of improved FCC bottoms upgrading can carry starkly different meanings for different refiners. A comprehensive understanding of the unit’s optimisation space is critical, in addition to close collaboration with the catalyst supplier, to implement an optimal bottoms upgrading solution for a given FCC unit. By combining sound engineering principles with fundamental FCC catalyst knowledge, BASF has a record of accomplishment for meeting and exceeding customer expectations for ‘bottoms cracking’ in its many different forms. In a recent refinery trial, BASF was able to help secure a significant profitability boost of approximately US$0.2/bbl for a refiner evaluating multiple catalyst options – equivalent to about US$3.5 million/yr for a 50 000 bpd unit. To conclude, a key to unlocking and preserving maximum profitability is strong engagement with catalyst suppliers to enable an evergreen, proactive optimisation approach as refinery objectives and market dynamics evolve.

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S

Juan Pereira De La Riera, Olivier Boisier, and Boris Hesse, Axens, France, discuss performance and energy savings in an FCC gasoline hydrotreatment unit.

ince the first reference was put in operation back in 2001, Axens’ fluid catalytic cracking (FCC) gasoline hydrotreatment technology, Prime-G+®, has demonstrated the ability to achieve deep desulfurisation of gasoline with minimum octane penalty. This was made possible by the unique combination of smart schemes with the most specific catalysts, capable of very high hydrodesulfurisation (HDS) rates with minimum olefins saturation.

For years, the very high value of octane barrel made it profitable for most refiners to push their FCC gasoline hydrotreatment units towards maximum octane retention ‘whatever it took’ in terms of energy consumption. The growing importance of environmental stakes and the introduction of CO2 emissions in the unit economics, however, is progressively shifting the optimum operating point towards better energy

efficiency, which inevitably impacts the product properties.

This article describes how the use of Axens’ new generation HDS catalyst HR 856 can help to significantly lower the CO2 emission levels of a FCC gasoline hydrotreatment unit through energy savings and without compromising the unit profitability.

FCC gasoline hydrotreatment FCC gasoline hydrotreatment technology is found in a large variety of layouts within the industry. The presence of a gasoline splitter, although not systematic, is very frequent. At high HDS level, this piece of equipment allows for significant octane savings thanks to the production of a light gasoline which is rich in olefins bypassing the HDS section.

The counterpart is that the production of this light gasoline requires a non-negligible amount of

HYDROCARBON 39

ENGINEERING

June 2021

Table 1. CO2 emission factors Utility

Value

Unit

Information

Electricity

0.432

tCO2eq/MWh Average US grid mix 2018*

HP steam

0.187

tCO2/t

Onsite production from refinery fuel gas, considering a boiler efficiency of 90%

MP steam

0.151

tCO2/t

Onsite production from back pressure turbine exhaust (fed with HP steam)

LP steam

0.100

tCO2/t

Onsite production from back pressure turbine exhaust (fed with HP steam)

Cooling water

0.00013

tCO2/m3

Onsite production.

Pumps P5 bar; efficiency 80% Cooling: central cooling water tower with Treturn - Tsupply = 10˚C

Boiler feed water (BFW)

0.2

tCO2/t

Onsite production Production of BFW (145˚C) from LP steam and demineralised water + electricity (pumping)

Fuel gas

0.0576

tCO2/GJ fuel (LHV)

Average value given for refinery fuel gas**

Fuel oil

0.0786

tCO2/GJ fuel (LHV)

Average value given for residual oil #6**

Hydrogen

9.7

tCO2/t

Hydrogen production from steam methane reformer (SMR)

* Source: https://www.epa.gov/egrid ** Source: API (2009)

energy to be brought to the system, generally under the form of high pressure (HP) steam.

On the catalyst side, as on the licensing side, Axens offers solutions for FCC gasoline hydrotreatment. In the HDS section, HR 806 and HR 846, used alone or in combination with HR 841 for better octane retention, allow for the desulfurisation of the most refractory species encountered in the gasoline boiling range while preserving olefins.

During the last decade, IFPEN and Axens have focused their catalyst R&D on performance, with selectivity being one of the targeted development lines. As a result, a new generation HDS catalyst (HR 856) has been released, which allows for the same excellent HDS activity and resistance to contaminants as HR 806 and HR 846 but with significantly lower olefins saturation. This new generation catalyst can help refiners to push for further octane savings and reduce energy consumption.

Unit utilities bill

Figure 1. CO2 emissions breakdown for reference unit.

Figure 2. Base case utilities cost breakdown.

June 2021 40 HYDROCARBON ENGINEERING

Unit performance would not be achieved without the introduction of a certain amount of energy. In a scenario where global policies target large CO2 emission cuts and require industries to reduce their emissions and eventually to pay for it (through carbon tax or by emission allowances under cap-and-trade systems), assessing the unit performance in a low energy consumption mode is more relevant than ever.

A case study was conducted for a reference FCC gasoline hydrotreatment unit to gain a picture of the energy bill inside the unit. The unit treats 20 000 bpd of a typical full range FCC gasoline from 1000 wtppm of sulfur down to 10 wppm. The unit has a selective hydrogenation section (SHU), a splitter and a one stage HDS section with two reactors and a heater in between. The HDS section is fitted with a recycle gas loop. The design is representative of the earliest one stage FCC gasoline hydrotreatment units that were commissioned by Axens, which means it does not benefit from the latest design improvements for energy savings. Loaded catalysts are benchmark SHU and HDS catalysts.

For the different case studies presented in this article, the price of utilities is based on averages from Axens’ project database. For CO2, a price of US$65/t is assumed based on the price range considered by the oil industry in investment decisions (from US$25/t to US$100/t).

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The CO2 emission factors expressed in CO2 t/unit of utilities produced is summarised in Table 1.

Looking at the breakdown of CO2 emissions and utilities for the reference unit on Figures 1 and 2, the following conclusions can be drawn: Steam is the biggest contributor to the utilities expenses not including CO2 and also the biggest contributor to CO2 emissions. 70% of the total steam consumption is for the splitter.

Hydrogen consumption is the second biggest contributor to the utilities expenses, not including CO2, and also the second biggest contributor to CO2 emissions.

Electricity is not a major contributor to the operating expenses nor to CO2 emissions. 43% of the total electricity consumption is for the recycle gas compressor.

CO2 emissions become critical when considered as an operating expense. Even if CO2 is not yet considered as an operating expense by all refiners, many oil and gas companies tend to apply an internal carbon price when evaluating investment decisions (either static value or a range of values that changes over time). Looking at the mid-term (2030), considered carbon prices can be much higher than the one considered in the present case study.1,2

Figure 3. CO2 emissions and unit profitability: comparison splitter low pressure to BASE CASE.

In an attempt to reduce the utilities bill and the CO2 emissions as much as possible, acting on both the splitter steam consumption and the make-up hydrogen consumption thus seems inevitable. On the other hand, acting on the power consumption shall probably not be regarded as a priority.

The different low energy scenarios

Figure 4. CO2 emissions and unit profitability: comparison splitter low reflux ratio to BASE CASE.

Figure 5. Comparison of compressor low electricity consumptions to BASE CASE.

June 2021 42 HYDROCARBON ENGINEERING

Two ideas come to mind when it comes to reducing the splitter steam consumption, each one having specific undesirable consequences in terms of performance: Decreasing the operating pressure. This has an impact on the product yield as some valuable C5 could be lost to the purge and end up in the fuel gas system or at the flare.

Decreasing the reflux to feed ratio. This has an impact on the light cracked naphtha (LCN) recovery and ultimately on the octane retention and the hydrogen consumption, as some light olefins are dropped into the HDS feed with the risk of being hydrogenated.

These two scenarios will be explored and it can be seen how the use of Axens’ new generation HDS catalyst HR 856 can offset any loss in performance arising from a low energy operation. The result for the refiners is a significant increase in profitability and a significant decrease in CO2 emissions.

A third scenario will also be investigated, which is a decrease of electricity consumption through a decrease of the HDS recycle gas compressor throughput. This should help to definitely rule out this solution as a major path towards energy savings.

The economics will use a product price of US$600/t (gasoline SP 95) and an octane value of US$0.9/octane bbl (AKI based).

Splitter steam reduction The operating parameters of the reference unit have been modified in terms of splitter operating pressure and splitter reflux to feed ratio, first with HR 806 and then with HR 856 (Figures 3 and 4). The BASE case considers standard operation conditions for the splitter in terms of pressure and reflux ratio. Running case BASE -1 bar means that the unit splitter pressure has been lowered by 1 bar. Concerning the reflux ratio, BASE -10 reflux ratio (RR) means that the reflux ratio has been lowered by 10%.

As mentioned, operation at lower pressure causes a loss of yield, thus degrading the product value. With HR 806 loaded, this operation shows positive net incomes only when the switch from HP steam to MP steam is possible.

Low reflux ratio operation causes higher octane losses which degrades the product value. However, with HR 806, running at BASE-10 RR is profitable. For RR of BASE -20 RR and below, savings in utilities do not compensate the losses in octane value.

At BASE conditions, a substantial gain of US$2.8 million/yr is obtained by switching to HR 856. At the optimum pressure conditions, i.e. BASE -2 bar, considering that a switch to medium pressure (MP) steam is possible, the gain reaches US$3.7 million/yr.

In terms of RR, the most profitable option with HR 856 is BASE -10 RR, leading to a gain of US$3.1 million/yr. BASE -20 RR still shows significantly better profitability than the BASE case with HR 806 and the reduction of CO2 emissions reaches 13%.

Splitter low energy modes are very profitable when conjugated with a switch to HR 856, and the impact on CO2 emissions is significant.

Power consumption reduction Operation feedback from the last 20 years show that refiners often challenge the HDS section H2/HC design value, considered as high especially when compared to conventional naphtha hydrotreaters.

Although the positive impact on electricity consumption from a lower H2/HC ratio might be appealing, one should keep in mind the negative effects on the catalyst performance, including: The catalyst activity is decreased, which has to be compensated by a higher operating temperature to keep the product on spec.

The selectivity of the catalyst is decreased, meaning a higher octane loss and a higher make-up H2 consumption can be expected for the same product spec.

The results from the study shown in Figure 5 illustrate that the reduction in electricity consumption does not compensate the loss of product value. Besides, the cycle length reduction due to higher weighted average bed temperature (WABT) in the HDS reactor has not been taken into account, which would tip the balance in favour of other strategies even more.

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It is convenient, however, to indicate that in the case of a steam-driven compressor, a different assessment would have to be conducted.

The digital role In parallel with catalyst R&D, Axens has put significant efforts into the development of digital applications aiming to improve customer experience, maximise profitability and help to control CO2 emissions.

For example, the Connect’InTM application includes a performance delta dashboard, which offers the possibility to model the unit using proprietary models and to compare in real time the actual performance vs the inferred one. This helps refiners to detect any deviation to the optimum operation and identify the parameters that can be tuned with the support of technical services engineers.

It is observed that units often over-perform in terms of desulfurisation, which has cost implications in terms of octane, utilities consumption and CO2 emissions. The use of an advanced process control (APC) based on licensor’s in-house models inferences would automatically avoid these performance issues with a fast payback. An APC would also help the refiner set the optimum operating parameters based on both energy consumption and product value.

By using real time fluid properties analysis (fluid properties as a service [FPaaS]), the digital experience is enhanced: the use of relevant near infrared (NIR) solutions as a real time properties analyser is providing results as expected in the improvement of inference models.

Conclusion In the context described in this article, limited to operating expenses in early FCC gasoline hydrotreatment designs, it has been shown that an overhaul of the operating parameters might be a good step to take.

The use of the high selectivity catalyst HR 856 allows profitability to be combined with a reduction in CO2 emissions to get the best of both worlds. This is even more significant when applying a price for CO2.

It has also been shown that decreasing the splitter operating pressure and decreasing the splitter reflux to feed ratio are probably the first actions to consider to decrease the utility/CO2 bill. This is site-dependant, and the optimum parameters have to be set case-by-case.

In a case-by-case setting scenario, digitalisation becomes a powerful tool to define the optimum parameters, demonstrating that an integrated offer is gaining in importance and that a catalytic solution, only by itself, is no longer in position to respond to refiners interests.

Other scenarios, considering capital expenses, would lead to more optimised schemes. This can be achieved by means of a revamp, in the case of existing units, or by the implementation of the latest state-of-the-art design, for grassroot units.

References 1.

2.

‘Getting to Net Zero’, Total, (September 2020).

‘Progressing strategy development, bp revises long-term price assumptions, reviews intangible assets and, as a result, expects non-cash impairments and write-offs’, BP, (15 June 2020), https://www.bp.com/en/global/corporate/news-and-insights/pressreleases/bp-revises-long-term-price-assumptions.html

Karen Picker, Sandvik, USA, predicts the future of duplex stainless steels in reactor effluent air coolers.

H

ydroprocessing units are responsible for producing low sulfur content fuels that meet ever-increasing rigorous industry regulations.

They have always played a significant role in the production of cleaner fuels, but in recent years they have taken the centre stage in refining industry maintenance and reliability discussion forums for two reasons.

Firstly, the International Maritime Organization Sulfur Regulation (IMO 2020) that came into effect on 1 January 2020 limits the sulfur content in marine fuels from 3.5% down to 0.5% m/m. This is expected to switch the typical demand of 3.5 million bpd of high-sulfur residual fuel to 0.5% sulfur fuel. Such a significant shift in demand has encouraged refiners to review and improve their hydroprocessing operations so that they are ready to gradually meet the market needs based on the implementation of this new regulation.1,2 Secondly, since the early 2000s, the refinery industry has seen an increased number of failures in reactor

HYDROCARBON 45

ENGINEERING

June 2021

Figure 1. Material resistance to NH4HS corrosion. effluent air coolers (REAC) fabricated from duplex stainless steels (DSS).

Hydroprocessing units improve hydrocarbon products by removing contaminants such as sulfur and nitrogen during the hydrotreating stage and converting heavier feeds into lighter products during hydrocracking operations.

The overall process utilises hydrogen and a catalyst that reacts with the contaminants mentioned above to form hydrogen sulfide (H2S) and ammonia (NH3). The reactor operates at temperatures between 700 – 850°F and the effluent is cooled by passing through a series of shell and tube heat exchangers before arriving at the REACs, with a temperature typically below 300°F, where it is cooled down further before being sent to separators. These air coolers are vulnerable to corrosion due to the formation of salts such as ammonium bisulfide corrosion (NH4HS), and ammonium chlorides (NH4CL), stress corrosion cracking (SCC) and sour water corrosion.

Corrosion and material selection Managing corrosion in REACs through equipment design, material selection, maintenance and inspection is well defined in the American Petroleum Institute Recommended Practice 932-B (API RP 932-B). On the topic of corrosion, particularly relating to NH4HS, chlorides and H2S partial pressure, the most recent version of this document, published in 2019, has incorporated key findings that have been defined as contributing factors to corrosion issues in these systems.

Such findings are the results of joint industry studies done in the refining industry for the past 15 to 20 years.

Some of the highlights include: Limiting NH4HS concentration to 2% for carbon steel and up to 8% if other corrosion mitigation measures are taken.

The importance of water wash and the quality of the water wash process in avoiding the formation of solid salts due to the chloride present in the stream.

The impact that H2S partial pressure and shear wall velocities have on the corrosion resistance of different construction materials including carbon steel as well as corrosion-resistant alloys.

June 2021 46 HYDROCARBON ENGINEERING

In general, hydroprocessing units with NH4HS concentrations above 2% will suffer from higher corrosion rates. These will be greatly affected by the flow regime, salt deposition, temperature, relative humidity and higher H2S partial pressure among other factors. Furthermore, it has been demonstrated that: “Carbon steel performs acceptably under low NH4HS concentration and velocities. Alloy 825 is more appropriate for more severe conditions”.3 This last statement derives from the first phase of a joint industry programme (JIP) that provides a relative ranking of 14 materials evaluated in ammonium bisulfide corrosion in H2S-dominated alkaline sour waters typical of REAC systems. This is summarised as the ‘pony chart’ on NACE paper 06576 ‘Prediction and Assessment of Ammonium Bisulfide Corrosion Under Refinery Sour Water Service Conditions’, and also adopted by API RP 932-B (Figure 1).4 For years, duplex stainless steels, both regular DSS 2205 and super duplex 2507, have been deemed the most suitable and economic materials for REACs. This is because, as with many other applications, they have demonstrated superior corrosion resistance in many different aspects as compared to other alloys. For example, DSSs are known to have superior SCC to 300 series alloys and, for hydroprocessing applications, they have demonstrated superior NH4SH corrosion resistance to alloys 825 and 625 while offering lower investment costs. However, while DSSs have been used in REACs since the 1980s and were certainly the material of choice during the 1990s, the fate of this family of alloys in this application is progressively coming to an end due to the increased number of cases of failures associated with the usage of DSSs in REACs.

Duplex failures As mentioned, the use of DSSs, particularly 3RE60 (UNS31500), in REACs was common in the 1980s, and the use of DSS 2205 for this application gained popularity in the 1990s. Unfortunately, at the same time, early reports of DSS failures in this application also began to increase.

In 2015, the Materials Technology Institute (MTI) published a detailed report that was one of the first to gather and investigate the origin of these failures. This report explores the nature of eight REAC failures that occurred over the course of 10 years since the early 2000s and aims to correlate the failure mechanism with the operating conditions and fabrication practices for REAC systems constructed from DSS 2205.

Overall, reported failure locations in the REAC system varied from tube-to-tubesheet welds, pipe welds, pipe to nozzle welds and header box welds. However, the common denominator between all the events was the failure mechanism, identified in most cases as cracking that initiated at the welds.

From the detailed investigation, this report concludes that sulfide stress cracking due to high ferrite content in the welds and heat affected zone (HAZ), resulting in most cases from inadequate fabrication practices, was the root cause. However, some failures

Table 1. Testing conditions for static and flow-through coupons simulating have been experienced “even ammonium bisulfide environments when fabricators have Test Temperature PH2S NH4HS Laboratory flow Duration (hr) Condition attempted to use what seem to (˚F) (psia) (wt%) loop velocity (ft/s) be the recommended and staticor flow-through required welding controls,” and 1 130 50 15 0.50 48 H2Sfor this reason, “2205 DSS has dominated 2 130 30 30 0.80 48 experienced unpredictable region 5 3 130 10 10 0.20 48 reliability in REAC service”.

Duplex stainless steels are 4 130 20 20 0.80 48 unrivalled in a large number of 5 190 5 5 0.80 48 applications in the temperature 6 190 8 8 0.80 48 range -58°F to 600°F where a combination of corrosion the REAC systems: hydrogen stress cracking (HSC) or resistance and mechanical strength is required. The key sulfide stress cracking (SSC). For this reason, API to the unique properties is the duplex structure and the technical report 938-C, ‘Use of Duplex Stainless Steels in harmonious interaction between the two phases. the Oil Refining Industry’, points out that the However, the duplex structure also renders them NACE MR0175 specifies a ferrite content limit of inherently sensitive to phase transformations that may 35 – 65% for wrought and cast materials and 30 – 70% lead to reduced toughness and/or corrosion problems. for the welds.6 This is because a microstructure with Correct production, heat treatment and welding require ferrite content above 70% will be more sensitive to the a thorough knowledge of the relationship between presence of hydrogen in the process and that this, along microstructural phenomena and properties. with the already vulnerable ferrite phase and the Ideally, DSSs have a microstructure that is 50% presence of high tensile stresses, makes for the perfect austenite (γ) and 50% ferrite (a), but this precision is hard to achieve, especially during welding operations. An recipe for hydrogen embrittlement which has an imbalanced microstructure with too high a ferrite increased risk of appearance in welds or HAZ with a content has a significant impact on the properties of the ferrite count between 70 – 75%.7 In the majority of the cases presented by the MTI material that leave it vulnerable to many different report, the ferrite content of the HAZ was reported to corrosion mechanisms, one of which is closely related to

hydroprocessing units has evolved. Based on the JIP referenced before, nowadays, end users are proactively moving away from specifying DSS for this application. Instead, now the common metallurgies used are alloy 825 or alloy 625, depending on application needs.

Comparison of various nickel grades for REACs Material selection for any application must strike a balance between reliability, corrosion performance and project economics. While alloy 625 is, in Figure 2. Ammonium bisulfide (NH4HS) corrosion using static coupons. general, a superior corrosion resistance alloy to alloy 825, when it comes to ammonium bisulfide corrosion, as demonstrated by the JIP, it has been ranked with similar corrosion resistance to that of alloy 825 for REACs. Alloy 825, a 38% nickel alloy with a pitting resistance equivalent (PRE) number of 28, is a well established traditional nickel alloy characterised by its good corrosion resistance to acid and very good ressistance to SCC. Alloy 625 on the other hand, while originally developed as a high-temperature alloy, has established itself as a staple alloy for wet corrosion applications Figure 3. Ammonium bisulfide (NH4HS) corrosion using flow through. due to its extremely good corrosion resistance in widely be significantly above the 70% threshold with only one carrying acidic and chloride containing environments. This case where it was between 63 – 70% in the HAZ, and yet is due to its very high nickel content of about 61% and a the equipment failed at the welds of the header box PRE number between 46 and 56. confirming what the duplex literature demonstrates. Since Since material costs are typically associated with the the 2015 release of the MTI report, additional failures have nickel content of the alloy, it is expected that alloy 825 been reported by end-users in various forums. offers a significant cost advantage over alloy 625 while, at In recent years, the API Committee on Refining least for NH4HS, offering similar corrosion performance.

Furthermore, it is important to highlight that material Equipment Subcommittee on Corrosion and Materials selection has to take into consideration other factors (SCCM) has continued the investigation on REAC failures affecting the system and, depending on what these factors and conducted a survey with a large industry participation are, the need for a higher nickel alloy might be justified. that not only aimed to correlate operating and process For example, alloy 825 is a great option for conditions with the failure mechanism but also aimed to conventional hydroprocessing units where high chloride develop recommendations for proper inspection and content might not be expected and salt deposits may not assessment of DSS REACs currently in service. be a concern. But if these factors are expected then the use This report will become public in 2021 and will offer of alloy 625 for this application is justified. However, end users more insight information to make educated further development of more modern super austenitic decisions about the continued use of duplex in REACs as stainless steels such as Alloy 28 (UNS N08028) and well as their maintenance and inspection protocols.

Alloy 35 (UNS N08935), have enabled end-users and However, with the information known today, it is safe to licensors to perform more cost-effective materials say that given the evidence and uncertainty in the use of selection, particularly for the tubes. This is because duplex for REAC systems, the material selection for June 2021 48 HYDROCARBON ENGINEERING

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alloy 28, with a nickel content of 31% and a PRE of 36, offers superior corrosion resistance in strong acids to that offered by alloy 825. However, on the other hand, alloy 35, with its 35% nickel content and PRE of 52, offers superior corrosion performance to alloy 625 making them both economic alternatives to the traditional materials of choice: alloy 825 and alloy 625.

An independent investigation utilising the same laboratory, test conditions as seen in Table 1, and software analysis as that used by the JIP has demonstrated that both alloy 28 and alloy 35 are suitable alloys for REAC applications with corrosion resistance to NH4HS superior to SDSS 2507 in both static and flow through corrosion testing conditions as seen in Figure 2.

Additionally, since all these alloys belong to the family of austenitic alloys, the fabrication challenges associated with duplex alloys are not a concern.

Instead, in the case of alloy 825 and alloy 28, they are so similar, metallurgically speaking, that they both use the same welding procedure, offering this as a fabrication advantage.

Conclusion

question mark over the effectiveness of DSSs, once popular in REAC production, as a suitable material for these applications due to the high risk of cracking deriving from the high ferrite content of the welds HAZ. High nickel alloys are today’s material of choice for this application. However, recently developed super-austenitic alloys have demonstrated to be an attractive alternative with a better price to performance ratio. It is therefore important for REAC manufacturers to engage with materials providers to ensure they select the most appropriate alloy for optimised performance.

References 1.

2.

3.

4.

5.

Reactor effluent air coolers have a critical role to play in the performance of hydroprocessing units and it is therefore vital that the materials used in their manufacture are able to withstand the specific demands expected of them. Recent research places a significant

6.

7.

https://www.imo.org/en/MediaCentre/HotTopics/Pages/ Sulfur-2020.aspx. https://www.breakthroughfuel.com/blog/imo-2020-sulfurregulation/#:~:text=Beginning%20January%201%2C%20 2020%2C%20the,the%20maritime%20and%20trucking%20 industries..

American Petroleum Institute, ‘Design, Materials, Fabrication, Operation, and Inspection Guidelines for Corrosion Control in Hydroporcessing Reactor Effluent Air Cooler (REAC) systems’, Washington, DC : American Petroleum Institute, API RP 932-B, (2019).

HORVATH, R .J., CAYARD, M. S., and KANE, R. D., ‘Prediction and Assessment of Ammonium Bisulfide Corrosion Under Refinery Sour Water Service Conditions’, Corrosion 2006: NACE International, Paper No. 06576, (2006).

MOORE, D. E., ‘Fabrication of 2205 Duplex Stainless Steel REACs in Refinery Hydroprocessing Units’, s.l.:Materials Technology Institute, (2015).

American Petroleum Institute, ‘Use of Duplex Stainless Steels in the Oil Refining Industry’, s.l.:API, 2014, API 938-C. CLAES-OVE, P., SVEN-ÅKE, F., ‘Welding practice for the Sandvik duplex stainless steels SAF 2304, SAF 2205 and SAF 2507’, Sandviken: Sandvik, S-91-57-ENG (1994).

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Mike Berckenhoff, MOGAS Industries Inc., USA, offers a comparison of modular vs stick-built process units for heavy oil pressure letdown.

T

raditionally, refinery units are constructed on-site in a stick-built (site fabricated) fashion. Another approach is to completely build a modular process unit off-site in a controlled environment and provide delivery of a complete system. In high-pressure letdown, modules feature an excellent design at reduced costs, increased safety, and push-button availability, in one of the most complicated operations in a heavy oils unit. Modules drive down both CAPEX and OPEX.

Engineering cost savings A modular design is optimised by the original equipment manufacturer (OEM), who has a better understanding of the particular process within the unit. For example, a properly engineered and optimised module may be built with 10 in. pipe, while the same process in a stick-built engineering, procurement and construction (EPC) design would typically use larger pipe, even up to 18 in. This overly conservative approach by stick building adds cost with no performance gains over a module. The expense for larger steel pipe, welding, inspection, pipe fittings, and associated valves necessary with a stick-built unit are not required in a modular construction. This reduces the

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Functions

Traditional letdown system

MS&C modular letdown unit

Control

✓

✓

Hot standby

-

✓

Switch to standby train

✓

✓

Purge

-

✓

Flush/depressurise

-

✓

Isolate

✓

✓

Fully redundant control valve

-

✓

Figure 1. Benefits of a module.

Figure 2. Availability comparison. overall cost to the end user when opting for a module, and a footprint reduction of up to 40%.

In a stick-built project, the engineering essentially starts over for each project, but not for an OEM module.

Valves, piping and other components that are required, regardless of the fabrication method, account for approximately 75% of the total cost. This leaves 25% for engineering and other costs that vary from stick-built to module. Since each stick-built unit is custom, the engineering is created new every time. However, with a module there are many pieces of the core design that do not change from one project to the next. This reduces engineering costs.

Improved safety Modular units improve overall plant safety in three ways.

Firstly, the module is tested as a complete assembly vs individual components (which leads to less operational risks and a quicker start-up) before becoming integrated with the unit, and rigorously verified using finite element analysis (FEA) software. Every conceivable operating mode – from both trains on the module being hot, to one train is hot while the other is cold, to both trains being cold – are analysed and the design optimised to accommodate these very different modes of operation. This improves the reliability of the units to ensure the following: No leaks at any joints.

June 2021 52 HYDROCARBON ENGINEERING

Maintenance personnel safety when removing control valves while the other line is still in operation.

The correct pipe anchoring systems are used to allow for movement of the piping during different plant operations.

Secondly, by automating the module’s operation (not just of day-to-day activities, but also abnormal or infrequently used modes), operators are free to monitor and maintain the rest of the facility so it performs as well as the letdown modules.

Plant personnel are not required to be around the modules during normal operations for confirmation that the train has been cleaned, properly cooled, depressurised, cleared of any remaining liquids, and ready for maintenance. Once the automated process is complete, maintenance personnel can confirm isolation of the train and easily assess when it is safe to remove a control valve for maintenance work.

Finally, OEM modules often employ proprietary valve technology, such as within patented y-valves, to not only reduce the module size significantly, but to also eliminate areas for plugging that traditional designs create. By eliminating ‘dead zones’ within the y-valve, process fluid cannot pool and cool and allow coke to form and solidify.

OEM y-pattern valves in modules eliminate coking zones completely to always ensure a clear and open path to either module train as needed. Around the y-valve ball, potential coking is cleared using OEM proprietary purging and flushing.

Enhanced performance leads to improved OPEX A better understanding of the controls by OEM engineers promotes an enhanced performance of the final unit. Figure 1 demonstrates how this modular letdown unit provides benefits over a traditional letdown system. Features such as a hot standby, purge, and flush contribute to greater availability. However, the biggest advantage is in the fully redundant control valve.

These functions are incorporated in a module, but not in a stick-built system. The availability of the OEM modular unit exceeds 99.97%. This is possible because of the unique 100% / 0% operating philosophy (run-to-failure). Technology licensors originally intended these plant letdown stations to operate this way. Issues with past mechanical limitations forced plants to deviate from this intent for greater availability of their systems in the case of an upset. Modules allow plant operators to recapture this original design intent by providing uninterrupted access to both trains of the letdown module with the push of a button. This OEM module employs an advanced warming system that fully warms and pressurises both control valves and process lines without wearing out expensive control valve trim or the need to manually warm up a train over a prolonged period. This increases the availability of the system and the entire plant.

MS&C experience in heavy oils is evidenced in the construction of their medium-pressure letdown station.

PLUG PLAY

&

MODULAR PROCESS UNITS Safer automated operation (operators physically distanced from hazards)

More efficient quicker switch over better structural planning less construction delay (weather, manpower) fully tested before unit is shipped

Lower cost of ownership operational stability lower OPEX and CAPEX

Higher quality Modules have a shorter build schedule, which have a positive impact to the customer’s NPV (net present value) when revenue stream begins earlier.

Call today

Proprietary technology within MOGAS’ severe service patented y-valves eliminate coking zones.

+1 800.544.0291

mogas.com

OEM expertise compact design

catalyst waste are reduced due to unplanned cutbacks in reactor operations. Coke and solids build-up are reduced plant wide as conversion rates are maintained and temperature excursions in the reactor are minimised. All of this leads to increased product capacity as more of a desired product is produced on the first pass, reducing the need to recycle product, and allowing the facility to process additional raw product.

Net present value The customer has a positive impact to their net present value (NPV) if the revenue stream begins earlier since modules have a shorter build schedule. The net benefits can be substantial compared with stick-built costs.

Therefore, the CAPEX is lower with a module.

Figure 3. A modular unit for medium-pressure letdown.

Figure 4. Severe service valves include this patented

y-valve.

Using an automated module, an experienced crew has an availability of 99.9%. With stick-built, construction availability is reduced to only 94.9%. For the example shown in Figure 2, an experienced crew is capable of performing the necessary maintenance on a shutdown lasting 12 days. If the crew is not experienced and a shutdown stretches out to 15 days, then the availability difference decreases to 92.1%, while the module maintains 99.9%. The availability analysis assumes two trains in parallel per letdown station and three letdown stations in series. Furthermore, this OEM module allows for a two-year service life, whereas the stick-built unit has a three-month service life.

This prolonged operational stability allows for improvements in the plant’s overall conversion rate. And, even more importantly, with today’s technologically improved plants and advertised greater conversion rates, long-term steady state operation of the facility is essential.

By making both trains instantly available and providing programming for the switching from one side to the other at a moment’s notice, the stability of the level in the separators can be maintained, providing greater conversion rates for longer periods of time.

Finally, with increased availability and improved stability over longer periods of time, upsets are reduced. By maintaining continuous stable control, hydrogen usage and June 2021 54 HYDROCARBON ENGINEERING

The difference The MOGAS Systems & Consulting (MS&C) modules include a Performance Guarantee in addition to standard warranties on components. A Performance Guarantee states that the modular unit will perform as intended by the customer for the duration of a pre-determined period.

This includes all components (valves, piping, etc.) and programmed instrumentation (DSC/PLC, etc.), and the process modes for operation, such as low- and high-pressure warm up, hot standby, steady state, train switch over, black oil draining, high- and low-pressure cool down, flush and depressurisation. A Performance Guarantee provides the end user additional piece-of-mind not typically seen with stick-built units by directing single point responsibility instead of shifting of performance issues between different component suppliers.

The modules also include application experience of engineers. Construction engineers must have heavy oil experience to understand the complications in that application. This is true for both EPC stick-built units and MS&C modular units. For example, control valve sizing is one of the most critical elements in a let down station.

This is done based on the vast experience and knowledge of the module supplier with heavy oils processing units. It is common for stick-built EPC construction teams to rotate from project to project, and not build upon the lessons learned from their last project. MS&C engineers are a core team whose focus has been only heavy oils for decades.

Their knowledge is shared amongst the team to provide consistency between projects with continuous improvements.

Conclusion Improved safety alone could be considered sufficient cause for choosing a module over stick building. The design and automation not only reduce the likelihood of an accident, but by not having personnel in the danger zone between crowded valves, the impact of an event is greatly reduced.

When safety is combined with enhanced performance through greater availability, improved conversion rate, and reduced upsets, the end result is reduced OPEX. Considering both lower CAPEX up front and lower OPEX during operation, the choice for modules over stick-built becomes clear.

Scott Moreland, Quadax Valves Inc., outlines the various tests that Quadax’s valves underwent before they were installed at an LNG terminal in Europe.

N

atural gas is often described as the cleanest fossil fuel. As such, the demand for LNG is steadily rising and will become increasingly important for many countries who want to add additional sources of supply.

At LNG terminals, the imported LNG is unloaded from gas tankers at special berthing facilities and stored in large LNG storage tanks. In order to keep the gas liquefied, the pipelines and the storage tanks withstand a temperature of

-162°C. Before delivering to the transmission network, the liquefied gas will then be warmed up and evaporated.

Case study Top entry valves are preferred for these applications, since the central top flange can be removed and all internal components can be easily extracted from the body.

Müller Quadax GmbH was awarded a large contract to replace side entry valves with top entry butterfly valves at HYDROCARBON 55

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June 2021

Figure 1. Every valve is tested before delivery.

an existing LNG installation, as well as at a new LNG terminal. Located in Europe, this terminal enables access into the Northwest European gas market, with an initial throughput capacity of 12 billion m3/yr, which will be increased to 16 billion m3/yr in the future. This terminal is also equipped with three loading bays for trucks and a dedicated jetty for smaller (bunker) vessels.

During storage and transportation, natural gas could leak into the atmosphere, particularly on critical components such as measuring devices and process valves.

Besides the negative environmental effect, these fugitive emissions could also have an impact on security. Therefore, the LNG terminal’s operating company requested an individual performance test for the approval of cryogenic valves that are installed in its terminals and storage tanks.

For this purpose, the cryogenic test according to BS 6364 has been combined with an endurance test according to EN 12567. The QUADAX® 4-offset Butterfly Valve DN 500 mm, ANSI class 150 has been tested at the ITIS test laboratory in the Netherlands, specifying 10 thermal cycles with a fugitive emission test alternating at 20°C and -196°C. There was also an endurance test, with 500 mechanical switches at -196°C measuring the internal and external leakage after determined cycles. The benchmark in terms of the seat leakage was less than 3000 ml/min. for a valve of DN 500 mm based on BS 6364 and a maximum allowable fugitive emission of ≤1.0•10-3 mbar·l·s-1 at any time of the cycles. The valve was tested with helium at 19 bar test pressure whereas the seat leakage and fugitive emission was measured after 20/40/80/150/300 and 500 cycles.

Due to the four offset design and the precision in manufacturing, the butterfly valves performed well in both high temperature and cryogenic applications.

The test institute ITIS BV certified that the seat leakage did not exceeded a low value of 590 ml/min., and that no leakage was detected after 500 cycles. Moreover, the fugitive emission at the bonnet and trunnion gaskets of the top entry valve never exceeded a value of ≤1.0•10-5 mbar·l·s-1. The round seat and sealing geometry of butterfly valves is a totally friction free metal-to-metal design. Due to this round geometry, after a couple of hundred cycles, the seat and sealing ring is literally looped-in and provides high tightness even if the material is shrinking and expanding due to extreme temperature differences.

Conclusion

Figure 2. Cryogenic test of QUADAX® top entry valve.

June 2021 56 HYDROCARBON ENGINEERING

Valves are critical components at each stage of the liquefaction and storage process at LNG terminals, and their performance and reliability are crucial for environmental and safety reasons. The QUADAX® Quadruple Offset Butterfly Valve outperformed a severe thermal endurance test and provided evidence of its quality and reliability in LNG installations.

Additionally, the company’s top entry butterfly valves fully satisfy the requirements of the EN 1473-2016 specifications for valves, and they are specifically designed for LNG applications where control and maintenance work can be performed safely and easily in the installed position without further risks to the service personnel.

Dean Alcott, RedGuard, USA, details how a large-scale test demonstrates efficacy of steel blast-resistant modules.

O

n 23 March 2005, a massive explosion at a Texas City refinery in the US during the restart of an isomerisation unit led to 15 deaths and 170 injuries.

The majority of the casualties were workers officed in temporary non-blast rated wooden office modules. At the time, the American Petroleum Institute (API) Recommended Practice 752 (RP752), ‘Management of Hazards Associated with Location of Process Plant Buildings’ had been in place for 10 years. It presented siting guidance for new ‘stick-built’ structures and hazard analysis guidance. However, the RP752 did not take into consideration the safe siting of temporary buildings. The standard for siting of temporary buildings Recommended Practice 753 (RP753), ‘Management of Hazards Associated with Location of Process Plant Portable Buildings’, was released in 2007 in large part to address the dangers exposed in Texas City.

Even with the adoption of RP753 and all of the process safety changes made in the last 15 years, the danger is still great in hydrocarbon processing plants and the upstream feed.

In 2020, there were 71 deaths and 216 injuries worldwide in refineries, petrochemical plants, and in relation to pipelines.

As part of required quantitative risk assessments (QRAs) in process plants, engineers determine safe siting for portable buildings to protect them from fire, gas and vapour cloud explosions. In congested facilities where the buildings cannot practically be sited outside of identified blast hazard areas, buildings must be engineered to protect occupants from the hazards. In the case of protection from a vapour cloud explosion, this protection can come in the form of a blast-resistant module (BRM).

Blast-resistant modules Before examining how to fabricate and test a BRM, it is important to consider the forces it is designed to mitigate. A vapour cloud explosion is exactly as it sounds – it can originate in a broken pipe or valve, or an overflowing distillation tower as demonstrated by the Texas City example. Due to the temperatures and pressures of many of the refining processes, a HYDROCARBON 57

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release to the atmosphere causes the hydrocarbons to vaporise. If not stopped quickly, this vapour forms a cloud close to the ground. Once that cloud finds an ignition source, an explosion can take place, often setting off multiple explosions. When large vapour clouds form, explosions will have longer durations (50 – 200 msec.) than, for example, a weapon’s discharge. Ultimately, this means BRMs must withstand forces over a longer duration than a building used for military applications, such as a military guardhouse.

Once the engineers have identified the blast zones, not every petrochemical plant or refinery may need to consider the implementation of BRMs. However, in some cases, a QRA may conclude that an existing building is now in a blast zone due to process changes. In some cases – typically with lower blast ratings – these buildings can be retrofitted. This work must be designed by an engineer with specific blast protection experience, and performed by qualified contractors. Retrofits vary greatly from simple glass replacement to significant structural changes. Sometimes the simplest solution is to pull the people and buildings out of the blast zone and relocate them to non-blast areas. It is important to consider process control and process safety, as well as work efficiency.

In cases where new space is required, a modular solution such as a BRM can provide a fast and cost-efficient solution.

Onsite disruption is minimised and weather delays are eliminated, as the modules are built in a factory. The design, fabrication, assembly, quality control and testing are performed by people who make blast-resistant buildings every day.

RedGuard and RedGuard Specialist Services have carried out multiple large-scale blast tests to prove the efficacy of the

companies’ steel designs. The first was carried out in 2007, at the beginning of the BRM industry, using 567 kg of ammonium nitrate and fuel oil (ANFO). The second was completed in 2020 with 2721 kg of ANFO. The purpose of the larger charge weight and longer standoff distance was to increase the blast wave duration on the buildings, while also applying a high blast pressure. The live blast test also validates structural computer modelling and challenges basic structural design assumptions.

Various accessories were also tested, such as windows, blast anchors, and intumescent coating.

Test set-up Figure 1 shows the layout of the blast test. The test arena was located in Deschutes County, Oregon, US. The test structures included: An anchored 12 ft x 40 ft (3.6 m x 12 m) BRM (10 psi 200 ms) to model the typical installation of a custom, permanently installed BRM. Internally, the unit had typical finishes, a dividing wall and a desk with a crash test dummy to simulate human response.

An unanchored 12 ft x 40 ft (3.6 m x 12 m) BRM (8 psi 200 ms) to model the typical installation of a temporary rented unit.

An unanchored 8 ft x 20 ft (2.4 m x 6 m) BRM (8 psi 200 ms) with a window and intumescent coating to test coating adhesion during a blast, and to test window performance during the blast.

A wooden trailer similar to the previously described Texas City buildings.

An old truck provided by the test laboratory to observe the reaction.

With the buildings and truck in place, RedGuard and the testing company spent nearly a week installing a wide array of measurement devices, including: Interior and exterior pressure gauges.

Free-field pressure probes.

Decibel metres.

Load cells.

Anthropomorphic test device (ATD), also known as a ‘crash test dummy’.

Passive sliding measurements.

Accelerometers.

Linear encoders.

Figure 1. Layout of the blast test.

Figure 2. Blast test explosion.

June 2021 58 HYDROCARBON ENGINEERING

When designing a BRM, each component must be analysed for its reaction to the blast. The combination of all components must withstand the free-field blast pressure, blast duration, and not exceed the designed damage level per the American Society of Civil Engineers (ASCE). The ASCE levels are low, medium and high response: Low – localised component damage. Building can be used, however repairs are required to restore the integrity of the structural envelope. Total cost of repairs is moderate.

Medium – widespread component damage. Building should not be occupied until repaired. Total cost of repairs is significant.

High – key components may have lost structural integrity and building collapse due to environmental conditions

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RedGuard Specialist Services Tel. +971 4 816 4500 sales@redguard.specserve.com redguard.specserve.com

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may occur. Total cost of repairs approaches replacement cost of the building.

Figure 3. Anchored unit before the blast.

RedGuard and RedGuard Specialist Services only design buildings to low or medium response levels due to concern about occupants in a building that has lost structural integrity.

It takes more steel and a more conservative design to achieve low and medium response.

After the blast test, when data from the above instruments is collected, a huge amount of effort goes into analysing deflection or deformation of all measured components to be sure that the intended design is met.

The blast Figure 2 shows the blast wave propagating towards the test buildings, as filmed by a drone. The blast was created from 2721 kg of ANFO, slightly elevated in the centre of the arena.

The following is an excerpt of the test pressures generated by the blast:

Anchored building

Figure 4. Anchored unit after the blast.

Peak pressure front face: 23.5 psi.

Peak pressure roof: 10.6 psi.

Peak pressure back face: 4.7 psi.

Free field pressure: 9.9 psi near the anchored building, 7.5 psi near wooden trailer.

The full test report is 254 pages, and the companies collected nearly a terabyte of data, photos and video. It is impossible to share all of this information in a single article, but to offer an understanding as to why BRMs are used, refer to Figure 3 and Figure 4 for the before and after of the 12 ft x 40 ft anchored BRM. It sustained no structural damage, whereas the wooden trailer was completely destroyed (as seen in Figure 5 and Figure 6).

Test conclusions:

Figure 5. Wooden trailer before.

Figure 6. Wooden trailer after.

June 2021 60 HYDROCARBON ENGINEERING

The three BRMs all survived the blast with little or no damage. All would satisfy the requirements for low damage level as per ASCE specifications.

The wooden trailer surpassed the high damage level and collapsed.

BRM doors and windows remained functional after the blast, and the intumescent coating remained intact for later successful fire testing.

Based on force and acceleration data collected on the crash test dummy, it is estimated that BRM occupants would suffer minor to no injury. This conclusion is based on pressure sensors, accelerometers and sound measurement inside the BRM. The unanchored buildings moved less than 5 cm in the blast.

To summarise, the amount of real data that can be collected and applied to BRM designs from a live blast test is incredible. Given the critical life-saving role of these buildings, live tests are vital. The live test confirmed RedGuard’s computer modelling and, in some cases, showed the company where its designs were too conservative and could be modified for efficiency.

Ronauld Weeks, Honeywell Connected Industrial, outlines best practices for energy management in today’s connected process industry.

A

lmost all process industry facilities have begun to engage in energy management initiatives, yet sometimes the benefits from these initiatives can erode as fast as they are achieved.

This is primarily because things change, whether that is in the process, systems, fidelity of rigorous simulation models used, or aged assets. As a result, a degree of maintenance is required to maintain rigorous simulation models.

Different methods and technologies are important in decreasing the total cost of ownership and keeping energy management initiatives relevant. So why does energy

performance monitoring, targeting and reporting have a higher propensity to fail in the process industries compared to other industries, such as building management?

Experts believe it is typically down to the process industries taking a complex approach to what is essentially a simple but repetitive task. In addition, chemical and petroleum engineers tend to take a rigorous simulation and precisely theoretical approach to solving these problems.

These approaches were necessary when the world was not connected by sensors, and the need for data via simulated values, in the absence of real-time data, was necessary to supplement this knowledge gap. However, times have HYDROCARBON 61

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changed. Workers are now 80 – 99% connected to their assets, and the remainder is gradually being added via new advances.

Honeywell persists in pushing rigorous simulation as the first tool in its energy monitoring, targeting and reporting strategy. The company believes that it is time to leverage methods and tools that are easier to implement and maintain, and which provide the information needed

Keep it simple and grow For most pacesetter facilities addressing energy management, keeping it simple and being flexible is key. It is possible to be nimble in a few steps: Collect data vigorously (historian and other data sources).

Contextualise vehemently (common asset model).

Cleanse and validate data (data scrubbing and quality).

Collect events/modes that affect process behaviour (shifts, operating modes, range controllers, plans/workflows, etc).

Utilise a surveillance engine which can exploit multiple methods of analysis, has an extensive equipment library for rotating and static equipment, and which can leverage templates to decrease total cost of ownership on equipment models-graphics-dashboards-calculations and can deploy fault models/notification workflows (analyse).

Connect seamlessly to data sources using service oriented architectures (standards based connectivity/exchange).

Utilise standards based reporting services (reporting services).

Figure 1. Five-step data processing model.

June 2021 62 HYDROCARBON ENGINEERING

to make faster, flexible and more accurate directional decisions/actions.

The rationale Energy management is a major pillar in many process industry operations excellence strategies. The management of energy information is the most important component of any effective, continuous improvement energy management initiative. It is widely accepted by best-in-class facilities that monitoring, targeting and reporting (MT&R) alone on energy usage can lead to significant energy reductions. Practical working knowledge and techniques such as MT&R – which includes computational methods of correlations, best operation base lining, and data mining and analytics on key drivers such as production, and uncontrollable variations such as weather – are the most effective and show greater longevity than rigorous simulation which erode as systems, conditions, personnel attrition and expertise retirement ensues.

Therefore, the question becomes: why is looking back, predicting conditions from historical information and utilising smaller, more focused, equipment-based simulation models so much more effective? The answer lies in the fact that energy used by any business varies as production processes do, volumes change, equipment ages and inputs vary.

Determining the relationship of energy used, or which should be used, to key performance indicators (KPIs) allows facilities to do the following: Know how much better or worse they are compared to before.

Understand energy trends which are seasonal in nature and operations cycles/modes effects, etc (this is in contrast to a theoretical rigorous simulation which normally does not account for weather, operation cycles/modes, or whether a standby pump or exchanger is running).

Understand equipment residual life effect on total energy usage.

Compare analyses and benchmark similar facilities.

Identify and filter historically-reactive operation decisions which have a large effect on energy usage.

Develop more insightful energy usage measures which have profound effects on a facility energy intensity index.

The strategy to long-term energy MT&R success lies in keeping it simple and evolving an energy accounting and auditing strategy towards a simple ‘measure, analyse and adjustment’ methodology.

It is important to start by understanding operations based on past data. It is therefore advisable to: Alert and notify for action (i.e. energy deviations, equipment health, precursive conditions) and investigate how this compares historically and based on the plan; not the theoretical optimum initially. If one is running to the plan of the business, the planners and field development should have optimised to the available constraints of one’s operations already.

Run large simulation optimisations offline whenever possible (at all times resist putting these online, as maintenance failure is common); these normally should only be used to support/validate comparative analysis of real time deviations and KPIs intermittently. This is an offline internal auditing exercise.

Calculate KPIs, chart, track and report. This is 95% of the process then complete, at more than half the cost it would have taken using a rigorous simulation approach to energy management.

Figure 2. Energy business process flow.

Solutions architecture should look simple. One should think about taking transformative steps rather than a ‘big bang’.

Be guided by standards An energy management (MT&R) initiative should support ISA95-Operations Performance implemented using a requirements decomposition similar to the one below on all relevant energy business processes. Furthermore, efforts in energy management should be guided by ISO 50001 and

its associated audit standards for energy. In general, it is advisable to keep the following with respect to ISO 50001 in mind: ISO 50001 requires an organisation to monitor, measure and analyse the key characteristics of its operations that determine energy performance at planned intervals. Equipment used in monitoring and measurement of key characteristics should be calibrated to ensure data are accurate and repeatable.

ISO 50001 requires an organisation to establish an energy baseline(s) for the measurement of the energy performance.

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ISO 50001 requires an organisation to identify appropriate energy performance indicators to monitor and measure its energy performance.

Conclusion

Figure 3. Process optimisation at work.

Option 1 is the ‘Manual Benchmark of Energy’ performance baseline: the strategy outlined in this technology suggests that the user should apply a baseline on an asset, unit or plant by specifying a start and end time to consider as a reference. Use a baseline period and regression techniques to generate a target energy model. Monitor current performance along with baseline time period performance to compare and understand deviation.

Option 2 is the ‘Use Design Benchmark’ model: the strategy outlined in this technology note recognises the need for rigorous equipment simulation on a supportive and smaller basis, but suggests leaving large plant- or field-wide simulations to a task conducted offline (or specifically on the supply side, not the demand side) and for intermittent auditing purposes if warranted.

Honeywell’s solution can help to improve maintenance lead time. The company’s monitoring approach leverages multiple methods with both principle-based efficiency models and predictive analytics. This provides a comprehensive view of the asset’s performance rather than just relying on pure machine learning models. In turn, this can improve decision quality and increase lead time by 2 – 3 times, implementing the right action before a potential failure can cause downtime and secondary equipment damage The solution also helps its customers as it can be deployed efficiently, accelerating time to value. It leverages asset predictive analytics and performance digital twins, when compared with in-house or pure analytics based solutions.

Analytics models and workflows and asset library is built-in, thereby lowering implementation effort by 3000 man-hours on average, which is equivalent to approximately US$500 000 in a typical application of over 1000 modelled assets The solution has also resulted in reduced OPEX via improved asset maintenance and performance optimisation.

In addition to assisting with reliability-based maintenance programmes, the solution also enables performance and process optimisation using the same offering.

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