Hydrocarbon Engineering August Issue 2021 by PalladianPublications

September 2021

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CONTENTS September 2021 Volume 26 Number 09 ISSN 1468-9340

03 Comment

37 Emissions catalyst cleaning – no need to wait for a turnaround

05 Guest comment

Steve Houghton, Groome Industrial Service Group, USA, explains how online catalyst cleaning can deliver a higher return on investment than traditional cleaning.

07 World news 12 No smooth sailing on the Gulf Coast Gordon Cope, Contributing Editor, explains how producers on the US Gulf Coast are navigating a maze of obstacles.

43 The carbon negatives Bradford Cook, Sabin Metal Corp., USA, looks at the impact of increasing carbon and coke in spent precious metals catalysts.

47 The case for controlling sulfur impurities William K. Rouleau, Merichem Company, USA, discusses the need for controlling sulfur impurities in order to prevent contamination and to improve the efﬁciency of end user products.

51 Easing the flow James Wood and Sergio Treviño, Southwest Research Institute (SwRI), USA, introduce a midstream heavy crude oil processing technique for cost-effective pipeline transportation.

55 Leaks: a costly problem 17 Thriving in the new reality Nick Flinn, Shell Catalysts & Technologies, UK, explains how the uncertainty of the COVID-19 pandemic offers opportunities for reﬁneries.

22 Optimum flow technology Tom Ventham, Unicat B.V. & G. W. Aru, LLC, looks at how to unlock SMR catalyst reformer proﬁtability, with uniform tube packing and improved ﬂow patterns.

29 An alternative route Ghith Al Shaal, Christoph Hauber, Ioan-Teodor Trotus, and Fabian Schneider, hte GmbH, Germany, explore the utilisation of pyrolysis oils in the p production of fuels and chemicals.

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Michael Strobel, Swagelok Company, USA, identiﬁes common causes and costs of ﬂuid system leaks, and outlines methods to prevent them.

61 Financially optimised maintenance Jason Apps, ARMS Reliability, Australia, describes an agile, RCM-based approach to developing optimal maintenance plans.

66 Accelerating production insights John Cox, Seeq, explains why advanced analytics provides the specialised functionality required to accelerate insights when working with time series data.

Magcat provides a fundamental shift in the optimum way to deploy heterogeneous catalyst in tubular reformers, such as those generating hydrogen at refinery sites. Optimisation of catalytic chemistry is yielding ever diminishing returns. Focus has now switched to support, ensuring fluid dynamic, mechanical, and heat transfer properties maximise economic and operational returns from existing equipment.

2021 Member of ABC Audit Bureau of Circulations

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Hydrocarbon Engineering

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

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CALLUM O'REILLY SENIOR EDITOR

he recent study into climate change by the UN’s Intergovernmental Panel on Climate Change (IPCC) paints a bleak outlook, and demands change from government leaders and stakeholders ahead of the COP26 conference in Glasgow, UK, later this year. We all know the vitally important role that the downstream sector has to play in helping to reduce emissions. And we all know that embracing change is absolutely essential to the future of our sector (and our planet). But we also know that our industry plays an indispensable role in modern society; a fact that is often forgotten (turn to p. 5 of this issue for a Guest Comment from Chet Thompson, President and CEO of the AFPM, who explains more). Shortly before the IPCC released its report, McKinsey & Co. published its ‘Global Downstream Outlook to 2035’, which considers the long-term challenges for the downstream sector brought about by technological advances, evolving regulations and increasing concerns about climate change. It examines the future of the sector through the lens of three potential scenarios: energy transition (reference case), delayed transition, and accelerated transition. It suggests that demand for light product (gasoline, diesel/gasoil, and jet/kerosene) will plateau by the mid-2020s, even in the delayed energy transition scenario. The report forecasts that demand will fall by 2.8 million bpd from 2019 levels to 2035, based on current trends, rising to 11.7 million bpd if the energy transition accelerates. Light product demand is expected to fall most sharply in North America and Europe. McKinsey based its prediction on six major shifts that it sees impacting long-term global energy demand: the uptake of electric vehicles, efficiency gains and the uptake of low-emission fuels for aviation and marine, increased demand reduction and recycling of plastics, cost reductions for renewables and storage, electrification of residential heat, and electrification of EU industry low and medium temperature heat. However, the report suggests that while the industry is expected to contract in some regions, it will remain very large in all scenarios. The global refining sector is still expected to produce 94 million bpd of liquids in 2035, even in the accelerated energy transition scenario. Tim Fitzgibbon, Senior Expert at McKinsey, stressed that it is essential that refiners adapt to build in resilience to a rapidly changing downstream sector. He suggests that refiners should embrace digitalisation, while potentially investing in decarbonisation and better integrating into petrochemicals. Fitzgibbon explained: “Many refiners can capture pockets of growth by directing investments both into emerging markets and further down the value chain. They should also consider placing big bets on emerging value pools including new energy services, new mobility and advanced fuels. These shifts are essential to achieving every penny of potential profitability as the product and geographical market mix shifts beyond recognition.” HYDROCARBON

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September 2021

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GUEST COMMENT CHET THOMPSON PRESIDENT & CEO, AMERICAN FUEL & PETROCHEMICAL MANUFACTURERS (AFPM)

Petrochemical efiners and petrochemical manufacturers fulfil manufacturers an indispensable role in today’s world. Our are making major industries make modern life possible through contributions to address the issue of mismanaged affordable fuel and petrochemical products plastic waste. Several of our members have recently that enable everything from daily transportation announced major breakthroughs in advanced recycling. to advanced technologies, to critical health and These breakthroughs will allow us to turn plastic waste medical products such as N95 masks and syringes for into virgin quality feedstocks, yielding products of the life-saving vaccines. Our products make life better, same quality, strength, durability, and purity as those safer, and more productive for people everywhere. manufactured from virgin feedstocks. These advanced For nearly two years, we have navigated a recycling innovations vastly pandemic that has brought increase the possibilities hardship and loss, and of what we can do with driven millions of people plastic waste and will help into poverty. We also face Our industries are make the world a greener the prospect of a global place. population that will grow prepared not only to At AFPM, we are by 2 billion over the coming working with policymakers decades. Our industries help the world recover and other stakeholders are prepared not only to economically, but also to advance public help the world recover policies that enable our economically, but also to supply the fuel and members to safely and to supply the fuel and petrochemical needs of sustainably provide the petrochemical needs of a fuels and petrochemicals growing population. We a growing population. that the world’s growing must do this sustainably, populations and now and for generations economies need to thrive. to come, while addressing We are advocating for critical issues such as a nationwide high-octane fuel standard that would climate change, the management of plastic waste, and result in emissions reductions equivalent to taking rising standards of living. hundreds of thousands of cars off the road each year. In the last 10 years, refiners have invested more We are pursuing policies to address plastic waste in the than US$100 billion to improve efficiency and environment and spur progress in advanced recycling. produce lower carbon fuels. These investments have We also support our members’ extensive work and reduced our emissions and carbon intensity by 12% in investments to operate more sustainably; increase the past decade. And despite its historic expansion, production of low carbon fuels; and drive technological the petrochemical sector has experienced similar innovation in carbon capture, utilisation and storage, results. among other emissions-reducing technologies. Today, refiners are bringing more low carbon fuels Throughout our 150-year history, the reﬁning and to market, making record investments in the scale of petrochemical industries have continually evolved to renewable fuels like renewable diesel and sustainable meet the world’s changing needs and offer solutions aviation fuel. They are also driving progress in to our most pressing challenges. The vital role that our emission reductions through technologies such as products play in a healthy and thriving society cannot carbon capture and storage and increasing renewable be ignored. power generation at their facilities.

HYDROCARBON

ENGINEERING

September 2021

Offices Worldwide

WORLD NEWS Asia Pacific | SGMF

supports growth of gas as marine fuel in Asia

he Society for Gas as a Marine Fuel (SGMF) has set up its first regional committee to facilitate cooperation and information sharing as uptake of LNG ship fuel surges in the Asia Pacific region. The first tasks of the new body will be to prepare a publication on the pathway to green ammonia as well as a regional dashboard tracking trade patterns to measure the multi-faceted impact of conversion to gas as marine fuel. This dashboard will build on an existing East Coast

Australia dashboard developed by DNV, released in late 2020. The committee draws on a diverse range of perspectives across SGMF’s APAC membership, which comprises around 35 companies from segments including shipowners, ports and shipyards. Other committee members come from companies including BHP, Rio Tinto, China Classiﬁcation Society, Korean Register, MPA, Petronas, Woodside Energy, ENN and Pilbara Port Authority.

China | Lummus

Technology starts up alkylation unit at ZPC refinery

ummus Technology has announced the start-up of its CDAlky alkylation unit at Zhejiang Petroleum & Chemical Co. Ltd’s (ZPC) reﬁnery in Zhejiang Province, China. The unit has a capacity of 45 000 bpsd of alkylate product, making it the largest alkylation unit ever licensed by Lummus. The start-up is the second Lummus CDAlky unit at ZPC’s complex, resulting in a combined capacity of 59 000 bpsd of alkylate production. This makes it the second

UAE | ADNOC

largest alkylation complex in the world. The new alkylation unit processes C4s from upstream refining and petrochemical units, resulting in a very high concentration of isobutylene in the total olefins blend while producing excellent alkylate quality. Earlier this year, Lummus announced the successful start-up of the first C5 CDAlky unit in the world, as well as its first CDAlky unit in the US, located at Valero’s Saint Charles Refinery in Norco, Louisiana.

Australia | Woodside

and BHP to create global energy company

oodside Petroleum Ltd and BHP Group have entered into a merger commitment deed to combine their respective oil and gas portfolios by an all-stock merger. On completion of the transaction, BHP’s oil and gas business would merge with Woodside, and Woodside would issue new shares to be distributed to BHP shareholders. The expanded Woodside would be owned 52% by existing Woodside shareholders and 48% by existing BHP shareholders. The transaction is subject to conﬁrmatory due diligence, negotiation and execution of full form transaction documents, and satisfaction of conditions precedent including shareholder, regulatory and other approvals. With the combination of two high quality asset portfolios, the proposed merger would create the largest energy company listed on the ASX, with a global top 10 position in the LNG industry by production. The combined company will have a high margin oil portfolio, long life LNG assets and the ﬁnancial resilience to help supply the energy required for global growth and development over the energy transition.

signs framework agreements

he Abu Dhabi National Oil Co. (ADNOC) has signed framework agreements for concept and front-end engineering design (FEED) services for major projects across its full value chain to support the delivery of its 2030 strategy. The framework agreements were signed with AMEC International Ltd (part of the Wood Group), Fluor,

McDermott, Mott MacDonald, SNC-Lavalin International Arabia Ltd – Abu Dhabi (part of the Kentech Group), Technip Energies, Worley, and a joint venture between Tecnicas Reunidas and NPCC. The agreements have a combined scope worth up to US$1 billion and the potential for 50% of the value to ﬂow back into the UAE’s economy under ADNOC’s

In-Country Value (ICV) programme, over the agreement term between 2021 and 2026. The scope of the agreements is based on the forecasted requirement for external project engineering services across the ADNOC Group. The agreements will run for ﬁve years, with an option for a two-year extension. HYDROCARBON

ENGINEERING

September 2021

WORLD NEWS DIARY DATES 04 - 06 October 2021 ILTA Houston, Texas, USA ilta2021.ilta.org

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

Poland | KBR

contract

wins ethylene technology

BR has been awarded a technology licensing contract by Hyundai Engineering and Técnicas Reunidas for PKN ORLEN’s Petrochemical Development Programme in Płock, Poland. Under the terms of the contract, KBR will provide technology license,

basic engineering design, and proprietary equipment for its ethylene technology – Selective Cracking Optimum Recovery (SCORETM) – for PKN ORLEN’s Oleﬁns Complex III Project. This is Europe’s largest petrochemical project in 20 years.

11 - 14 October 2021 API Storage Tank Conference Nashville, Tennessee, USA www.API.org/storagetank

awards largest catalyst management agreement in its history

12 - 13 October 2021

Gulf Coast Conference Galveston, Texas, USA www.gulfcoastconference.com

12 - 15 October 2021 & 21 - 22 October 2021 Downstream USA Online & Houston, Texas, USA www.reutersevents.com/events/downstream

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

25 - 27 October 2021 Opportunity Crudes Conference Online www.opportunitycrudes.com

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

15 - 18 November 2021 ADIPEC Abu Dhabi, UAE www.adipec.com

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

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

September 2021

HYDROCARBON

ENGINEERING

Bahrain | Bapco

dvanced Refining Technologies LLC (ART), the joint venture of W. R. Grace & Co. and Chevron, has been awarded a full-cycle catalyst management (FCM) agreement by state-owned Bahrain Petroleum Co. (Bapco). The exclusive five-year agreement, which includes an option to renew for an additional five years, is valued at US$240 million. It is the largest catalyst management agreement signed in Bapco’s history. The award is part of the Bapco Modernisation Programme (BPM), which aims to boost Bahrain’s oil refinery processing capacity from 267 000 bpd to 380 000 bpd. In addition, ART will supply its Resid Hydrocracking catalyst

technology for a wide variety of feedstocks to maximise bottom of the barrel upgrading. ART will also provide FCM services for the reclamation of metals from spent catalysts. When fully operational in 2023, the new Resid Hydrocracking unit, known as 1RHCU, will be the main proﬁt centre for the Bapco Reﬁnery. 1RHCU utilises LC-FINING process technology licensed from Chevron Lummus Global (CLG), a joint venture between Chevron and Lummus Technology. The unit is a two-train design with a processing capacity of 65 000 bpd. Less than a dozen of these units exist globally, and the Bapco unit will be one of the largest examples.

India | McDermott awarded additional EPCC

project for Barauni Refinery expansion

cDermott International Ltd has received a contract award for the engineering, procurement, construction and commissioning of a new naptha hydrotreating unit and a new isomerisation unit with associated facilities for the Barauni Reﬁnery Expansion Project in Bihar, India, for Indian Oil Corp. Ltd. The units treat heavy naptha streams by removing sulfur, nitrogen and metal compounds to produce

Bharat Stage-6 compliant gasoline, which produces a cleaner fuel to meet high emissions standards. The scope of the project includes project management, residual process design, detailed engineering, procurement, fabrication, inspection, transportation, installation, construction, and all processes through to mechanical completion and commissioning. The work will commence in 3Q21.

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Gordon Cope, Contributing Editor, explains how producers on the US Gulf Coast are navigating a maze of obstacles.

he US Gulf Coast has been a mainstay of North American energy for more than a century. In addition to massive offshore ﬁelds, the shale revolution has created one of the largest single sources of oil and gas in the world. But the region is facing major environmental, regulatory and market challenges that complicate its prospects.

Offshore While capital expenditures for greenﬁeld projects in the Gulf of Mexico have been reduced over the last several years through modular design and other engineering innovations, the most cost-efﬁcient method is

to explore for new reserves near existing projects. In April 2021, BP announced an oil discovery at its Puma West prospect in Green Canyon Block 821, located over 200 km off the Louisiana coast. While the company did not estimate the size of the discovery, it noted that its exploratory well had encountered potentially commercial quantities of crude in high-quality reservoirs similar to nearby Miocene ﬁelds. The discovery sits just west of the Mad Dog platform, facilitating a tie-in to existing infrastructure. In May 2021, Shell announced a signiﬁcant discovery at its Leopard prospect, located almost 400 km southeast of Houston, Texas. HYDROCARBON 13

ENGINEERING

September 2021

The well encountered 183 m net oil in multiple levels. The discovery is located within the Perdido Corridor, which encompasses the company’s Great White, Silvertip and Tobago fields. In June 2021, BP announced the start-up of the Manuel project, which includes a subsea production system that ties two new wells into the Na Kika platform, located 140 miles off the coast of Louisiana. The project originally held over 300 million bbl of oil equivalent (boe), located in five adjacent oil and gas fields. Since 2003, it has been producing approximately 130 000 bpd and 500 million ft3/d. The new wells will add 20 100 boe/d to output.

Onshore In June 2021, the West Texas Intermediate (WTI) benchmark surged above US$70/bbl, a mark that makes most shale oil proﬁtable. Shale basins throughout the US are rebounding, but the greatest recovery is in the Permian. Prior to the pandemic, production stood at around 4.8 million bpd. It dropped to below 4.3 million bpd by mid-2020, but by mid-2021 it had climbed to 4.6 million bpd, with drilled but uncompleted wells (DUCs) falling signiﬁcantly. There is still considerable potential for upside, but several caveats are in order. January 2020 saw an all-time high of 13.1 million bpd US production; as of mid-2021, that level is still sitting 2 million bpd below, at 11 million bpd. Even with thousands of shale oil DUCs still on inventory, reaching the previous record would require massive investments; producers, especially shale operators, are more focused on cutting debt and rewarding stockholders. The consolidation in the Permian basin based on stock deals (rather that outright purchases) is part of this focus. In April 2021, Pioneer Natural Resources merged with Double Point Energy in a US$6.4 billion deal. The acquisition gives Pioneer 97 000 acres of largely-undrilled, non-federal land in the Permian basin with a potential for up to 100 000 bpd production.

Refineries The precipitous fall in fuel demand due to COVID-19 has refiners throughout the world critically examining under-performing assets, and the US Gulf Coast (USGC) is no exception. Over the course of the last two years, Shell has mothballed its Convent refinery in Louisiana and sold its controlling interest in the Deer Park refinery in Texas. When it is finished, Shell will have one refinery remaining in the region – the 227 400 bpd plant in Norco, Louisiana, 40 km west of New Orleans. The facility produces ethylene and propylene in addition to fuels; the chemicals are used as feedstock for Shell’s nearby Norco and Geismar petrochemical plants.

Pipelines While pipeline operators have largely met the growth of crude production in the Permian basin, servicing the related associated natural gas production has lagged. Several new gas pipelines have recently entered service, however. Kinder Morgan’s Permian Highway Pipeline came online in early 2021, moving up to 2.1 billion ft3/d from the Waha hub in West Texas to the Gulf Coast. Whitewater’s Aqua Blanca September 2021 14 HYDROCARBON ENGINEERING

began operations in early 2021, transporting 1.8 billion ft3/d to the Waha hub, where it is expected to move south to export hubs along the Whistler Pipeline when it is completed in late 2021. In January 2021, Double E submitted a request to the US Federal Energy Regulatory Commission (FERC) to begin construction on the Double E pipeline, a 135 mile conduit designed to move up to 1.35 billion ft3/d of natural gas from the Summit Lane Plant in the Permian basin to the Waha Hub. Double E has secured ExxonMobil as an anchor shipper (which also holds a 30% stake in the project). The line is expected to enter service late in 2021. In light of the cancellation of the Keystone XL pipeline, companies are working on supplying sufficient alternate capacity to deliver heavy Canadian crude to USGC refineries. In addition to incremental gains on existing Enbridge and TC systems, Plains All American and partners are working to reverse the Capline pipeline. Originally built in 1967 to move imported crude north from Louisiana to the Patoka hub in Illinois, it eventually became a white elephant as domestic sources were developed. Now, the 1017 km, 40 in. pipeline is being reconfigured to deliver up to 650 000 bpd to the Gulf Coast. First portions are expected to begin operations early in 2022, with scale-up proceeding throughout the year.

Petrochemicals A major portion of the US’ 40 million tpy ethylene capacity is located in the Gulf Coast. Total’s new Baystar 1 million tpy ethylene cracker in Port Arthur, Texas, began start-up in June 2021. The JV with Borealis is designed to supply a new 400 000 tpy polyethylene plant near the Houston Ship Channel, as well as an adjacent 625 000 tpy plant expected to come online in early 2022. Over 8 million tpy of new capacity is being planned for 2021 and beyond. Weather had a recent major impact on Gulf Coast petrochemical plants. In February 2021, a polar vortex hit the state of Texas (see ‘Batten down the hatches’ sidebar). While electricity blackouts made the news, another signiﬁcant disruption had longer-term impact. More than 60% of polyvinyl chloride (PVC) production capacity was still out of operation over a month after the storm. PVC serves as a vital feedstock to the production of housing materials, cable insulation and car parts; the disruption sent manufacturers in the US and abroad scrambling to keep their factories open.

LNG The LNG market has had a wild ride over the last year. When the COVID-19 pandemic wiped out LNG demand in Asia in mid-2020, several plants in the USGC temporarily shut down, including Freeport’s three trains in Texas. By 2021, however, demand had roared back; in March 2021, LNG exports averaged a record 10.5 billion ft3/d. Freeport not only brought all its capacity back online, but ran almost 20% in excess of its 12.3 million tpy nameplate capacity. Freeport is now looking at adding a fourth, 5 million tpy train, with a ﬁnal investment decision (FID) expected in 2022, and a start-up in 2026. Additionally, several aspects point to longer term growth. US suppliers have developed contracts that are not linked to oil-pricing; as prices rebound, spot shipments

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become more competitive. Major LNG consumers in Asia are also keen to diversify sources in order to reduce risks associated with potential supply disruptions in the Middle East, and European consumers are wary of over-reliance on Russian supplies. Many consuming nations (in Asia, especially) are eager to switch from coal-ﬁred utilities to cleaner-burning natural gas. While the price for Henry Hub gas has risen over the last year, US LNG producers still remain well within competitive international pricing.

Challenges The election of President Joe Biden is having a signiﬁcant impact on energy in North America as the White House focuses on climate change. It imposed a freeze on new oil and gas drilling permits on federal lands, as well as a moratorium on lease sales. The Bureau of Ocean Energy Management (BOEM) subsequently cancelled a March 2021 lease sale that would have offered 78.2 million acres in the Gulf of Mexico. Approximately 12% of US production comes from federal lands; if the freeze becomes a permanent ban, states such as Wyoming, New Mexico and the offshore Gulf of Mexico would be signiﬁcantly impacted over time.

The future Many within the US oil and gas sector are taking the shift in climate priorities to heart, and are seeking ways to proactively meet environmental goals. In June 2021, The Greater Houston Partnership, a business group that represents over 900 companies, released a McKinsey study that tabulated over 500 000 new jobs associated with a proactive energy transition policy designed to leverage existing infrastructure. “If we move forward in the energy transition in a smart and resilient way, we will stay at the forefront of the energy sector,” said Houston Mayor Sylvester Turner. “The City of Houston’s innovation and adaptability will be key as the energy industry diversifies.” A major key to the transition could be a public-private carbon storage project to collect CO2 from Gulf Coast petrochemical plants and sequester them beneath the Gulf of Mexico. ExxonMobil has proposed a massive plan to capture CO2 from the 50 largest industrial emitters located on the 80 km long Houston Ship Channel and then piping it to offshore reservoirs located almost 2 km below the ocean floor. The plan would cost US$100 billion in order to store 50 million t by 2030, with an additional 50 million t over the following decade. Houston could also become a low-carbon hydrogen hub. The greater metropolitan area is home to one-third of US hydrogen production; it contains a network of 48 hydrogen plants and over 900 miles of hydrogen pipelines. “The region’s enormous port, rail and air infrastructure represents a significant platform for implementing large-scale decarbonisation initiatives,” noted Bobby Tudor, Chairman of the Partnership’s Houston Energy Transition Initiative. In the short-term, North America’s oil and gas sector has benefited tremendously from the discipline shown by OPEC+ over the last year, its members largely sticking to self-imposed quotas that have allowed a huge glut to September 2021 16 HYDROCARBON ENGINEERING

Batten down the hatches In February 2021, a polar vortex hit the state of Texas, causing gas wells to freeze and production to drop from around 24 billion ft3/d to as low as 11 billion ft3/d. Cut off from fuel, the power grid failed in major metropolitan areas, plunging millions into the cold and dark. By the time power had been restored, the state had lost billions in revenues and tallied over 100 fatalities. The weather event hit petrochemical facilities hard, taking an estimated 30 million t of ethylene capacity offline, the vast majority located along the Texas coast. Dow Chemical, Formosa Plastics, BASF and other major manufacturers declared force majeure and instigated shutdowns at over three dozen facilities in the wake of the cold snap. Because of complications arising due to the unplanned shutdowns, more than 60% of PVC production capacity remained offline for over a month after the storm. Manufacturers who rely on the chemical feedstock found themselves in a bidding war to keep their plants open; polymer grade prices (PGPs) rose to an all-time high of US$1.25/lb in late February 2021, before falling back to under US¢80/lb in March. Severe weather has also affected refineries. When a massive rain and lightning storm dumped up to 10 in. of rain and engulfed Port Arthur, Texas, several Gulf Coast refineries had to slow production. Total’s 225 500 bpd Port Arthur refinery in Texas went offline after a power loss, a transformer blowout at Motiva’s 607 000 bpd Port Arthur refinery took a coker offline, and a catalytic reformer shut down production at Valero’s 335 000 bpd Port Arthur facility. Hurricanes are an unfortunate annual event in the Gulf of Mexico. The hurricane season, which runs from June to November, saw record numbers of major events strike the USGC region last year. In August 2020, almost 300 offshore platforms were evacuated ahead of Hurricane Laura, shutting in over half of all gas production and 80% of oil production. Onshore, six refineries representing over 2 million bpd capacity were shuttered. When the hurricane made landfall in Louisiana, it damaged infrastructure at the Phillips 66 and Citgo refineries, partially reducing output for several weeks. The National Hurricane Center expects an active hurricane season in 2021; in June 2021, tropical storm Claudette forced Chevron to evacuate its Tahiti platform. dissipate and prices to stabilise above US$60. In July 2021, OPEC+ ministers reached consensus on a new deal, agreeing to boost overall production by a total of 2 million bpd by the end of 2021, as COVID-19 lockdowns recede and demand increases. The group also stated that it plans to end all output restrictions by September 2022. In the longer term, an energy transition toward renewables, as well as a shift from internal combustion engines (ICE) to electric vehicles (EVs), will eventually reduce demand for fossil fuels. In the meantime, USGC producers are reaping billions of dollars in cash flow; those with vision are planning for a future in which they will play an integral part in new forms of energy and new ways to meet climate challenges.

Nick Flinn, Shell Catalysts & Technologies, UK, explains how the uncertainty of the COVID-19 pandemic offers opportunities for refineries.

he COVID-19 pandemic prompted a dramatic fall in product demand and skewed product slates. This has presented refiners with the challenge of needing to increase margins and profit. In addition, there is also accelerating activity around the energy transition and the need to reduce carbon emissions which will have an effect on product slates as well. With the combination of these two challenges, the reality is that there will likely be a prolonged recovery and

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returns on investment. This is important as more stringent emissions regulations are enacted and as other market changes occur, and different products may be required to meet growing demand for winter diesel and biofuels. A revamp can help resolve operational issues caused by the pandemic having disrupted global economic activity on a large scale, resulting in many refiners having to operate well below their normal throughputs, running their equipment far differently from their design points or delaying their turnarounds. This has often exposed or caused operational problems such as radial maldistribution, channeling of liquid flow or pressure-drop limitations that have led to suboptimal unit performance. As more countries and regions continue to adopt regulations requiring ultra-low sulfur levels in automotive gas oil, refineries need to react by increasing the operating severity of their diesel hydrotreating units. In some instances, this can be successfully managed by changing to a modern high-activity catalyst system, such as one from Shell Catalysts & Technologies, often in combination with upgrading the reactor internals. If these improvements are insufficient or Figure 1. Five key value-adding design differentiators of Shell’s deepflash additional capacity is required, then technology. revamping an existing unit is often a more cost-effective option than long-lasting consequences that will require refiners to building a new grass-roots unit. modernise their facilities. However, many refiners will Some areas are seeing a change in the demand split have to adopt a conservative approach to capital from heating oil to automotive diesel, which generally investment with a goal of continuous improvement has much stricter specifications for properties such as designed to maintain competitiveness. While all of this sulfur, density, cetane and boiling range. Refineries is challenging, there are low-capital revamp affected by this will need severe hydrotreating of a opportunities that can deliver high returns quickly and higher proportion of distillates, including more difficult help refiners seize opportunities in the new business cracked components, so they can be blended into the reality. automotive diesel pool. This article will provide an overview of current For some refiners, there is an economic incentive to challenges and information on revamp scenarios for meet additional, more stringent specifications such as refineries that require low capital expenditures and offer low aromatic diesel or to meet severe cold flow high return on investment. These are intended to help properties. A reduction in product cloud point is refiners with ways to remain competitive. Considerations achievable by including dewaxing technology into an include increasing regulations, carbon reduction, market existing diesel hydrotreater. There is also a growing changes due to the pandemic and other forces, and world energy demand and incentive for biofuel technology equipment solutions. In this article, five production. The two most common types of biofuel are possible revamps will be covered along with insights for bioethanol and biodiesel. The two routes for producing each one. biodiesel are the transesterification of vegetable oils or animal fats to make fatty acid methyl esters (FAME) or Distillate hydrotreating the hydrotreating of vegetable oils or animal fats to Revamping a diesel hydrotreater is a relatively low-cost make paraffins in the diesel boiling range (hydrotreated response to several issues that can bring strong financial vegetable oil or HVO). September 2021 18 HYDROCARBON ENGINEERING

DISPLACER REPLACEMENT WITH VEGAFLEX Upgrading measurement technology eliminates costly maintenance

Reﬁneries have a number of displacers they’re using for level measurement. Unfortunately, displacers are mechanical measurements, so it takes a lot of labor and time to keep them reliable and functional. f A VEGAFLEX guided wave radar is typically the best option for replacement because displacers are installed in a displacer cage resembling a bridle, bypass chamber, or pipe. f The VEGAFLEX requires a fraction of the time and cost of maintaining old displacers. Further information: www.vega.com

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FCC-PT/FCC Shell Catalysts & Technologies recommends that refiners should take an integrated approach to the fluidised catalytic cracking pretreatment (FCC-PT) and FCC units. This is even more important in today’s environment when yield shift flexibility and low-cost operations can be key to competitiveness. The rationale for considering an integrated approach to the FCC-PT and FCC units is straightforward. Even though the two units have very different operating modes, constraints, and objectives, together they have complex interactions that cover feed quality effects, constraint-driven limitations and turnaround timings. The performance and limitations of each unit strongly influence the other, so substantial value is at risk if refiners do not consider the two units as an integrated operation. For example, when considering upgrading an FCC-PT unit with the latest catalysts and technologies, remembering the FCC unit constraints will help in capturing the full potential margins from the synergy between both units. Similarly, by considering the units in isolation, a refiner could fail to identify the projects that would deliver the biggest returns. Applying the best-available technology does not have to mean highly capital-intensive projects with extended implementation downtimes. With an experienced technical team assessing, developing, and implementing integrated solutions, many upgrades in capability are achievable with minor impacts on shutdown scopes and budgets, thereby providing a net return.

Hydrocracking Refiners seeking to adapt their assets can take advantage of the inherent flexibility of a hydrocracker in several ways. This includes shifting to petrochemicals, improving residue conversion, moving to higher margin lubricant base oil feed and the processing of lower-priced crudes. With industry commentators asserting that demand growth for gasoline and diesel is set to weaken in the long-term, some refiners are evaluating how they can repurpose their facilities. Though most hydrocrackers commissioned in the past 15 years have traditionally been designed as diesel-producing machines, they are now increasingly being reconfigured towards naphtha. Many refiners are pulling naphtha out of gasoline and then redirecting light naphtha to the ethylene cracker and sending heavy naphtha through additional processing units to produce paraxylene. If desired, it is also possible to continue to produce jet fuel, for which long-term demand is expected to remain strong. The need to respond to the IMO 2020 fuel-sulfur cap and invest in residue conversion projects remains strong for many. By revamping a hydrocracker, repurposing it and integrating it with another fuel conversion technology such as solvent deasphalting, delayed coking or thermal cracking, refiners can cost-effectively reduce their exposure to high-sulfur fuel oil. September 2021 20 HYDROCARBON ENGINEERING

Global petrochemical industry struggling with challenges and low operating rates These are unprecedented times for the global petrochemical industry, and some products and value chains, including ethylene oxide (EO), are suffering from exceptionally challenging market conditions and low operating rates. This environment forces EO producers to re-examine their operating and investment plans. When margins were good, the whole focus was on maximising production and minimising downtime, but now it is important to realise that there are other ways to improve profitability. Some of the options to consider include: Debottlenecking to run harder and reduce unit production costs. Adding or increasing high-purity EO (HPEO) capacity to improve margins and diversify the product portfolio. Lowering the carbon dioxide level to allow catalysts to run longer and at higher selectivity. Operating at lower rates to maximise selectivity and lifetime from the catalysts. Increasing energy efficiency. The right choice depends on the local market environment and the drivers of each producer and each site. The position in terms of ethylene availability and the depth of the local market for HPEO can have a major influence on the choice of strategy. For some, the optimum solution will involve adding or increasing HPEO, increasing work rate and changing to a latest-generation catalyst. But for others, it might mean bringing down operating costs by running at lower rates or by looking for opportunities to improve efficiency.

There is also a global trend away from Group I products based on solvent technology towards Group II and Group III lubricant base oils produced using catalytic dewaxing and hydrofinishing technology. In some regions, lubricant base oil feed can command a higher margin than middle distillates, so refiners are revamping their hydrocrackers to enable the right feed quality. The hydrocracker’s catalyst system and configuration are key, as they have major influences on the yield and quality of the final base oil products. Another popular revamp objective is to facilitate the processing of lower-priced opportunity crudes such as West African, Mexican, Colombian, and Venezuelan, and non-standard feeds such as heavy coker gas oil and deasphalted oil (DAO).

Reactor internals The pandemic has disrupted global economic activity on an unprecedented scale, so many reﬁners have been operating well below normal throughputs, running equipment far away from design points or delaying turnarounds. Unfortunately, this has often exposed or caused operational problems such as radial

maldistribution, channeling of liquid flow or pressure-drop limitations that have led to suboptimal performance. Meanwhile, as the need to increase margins and profitability has arguably never been greater, other refiners are exploring processing lower-cost crudes, more severe feedstocks or renewable feed components such as used cooking oil or tallow. However, such changes exacerbate the risk of fouling and can constrain performance. Because they are designed to prevent fouling and increase catalyst volume and utilisation, Shell Catalyst & Technologies’ latest-generation reactor internals provide one of the most compelling response options available to refiners today. Furthermore, they offer a quick profit return for relatively low capital expenditure – payback can be in a few months.

OGT | ProTreat® brings out

THE EXPERT IN YOU

Vacuum distillation

PTU

NU MB

The performance of a vacuum distillation unit (VDU) can have a major bearing on a refinery’s margins. Not only is this the last opportunity to remove valuable distillates from crude and, therefore, to minimise refinery fuel oil make, it also improves the feed quality for the downstream conversion units (hydrocracking or fluidised catalytic cracking units) and is a major determinant of their cycle lengths. Consequently, a VDU revamp offers refiners a major margin-improvement opportunity. Revamping these units using Shell Catalyst & Technologies’ deep-flash, high-vacuum technology can often be a low-cost way to unlock downstream assets, as it can help to increase vacuum gas oil (VGO) yield, enhance unit throughput, and improve unit reliability while also ensuring that contaminant levels remain within the conversion units’ acceptability limits. Such projects can generate substantial value, as the capital cost is usually relatively low and payback times are short, typically a year or less. In addition, hardware changes can often be implemented within an existing refinery turnaround window. Such technology has been developed through extensive research on mass transfer and separation equipment, including five key design features that can be tailored to meet specific revamp requirements. They include a proprietary furnace coil design, Schoepentoeter1 inlet device, wash-oil section design, insulated, low pressure drop, draw-off trays and direct contact condensation sections.

SIM

OF N O U L AT I

You need the right answers! We can help provide them.

Conclusion Existing global economic challenges combined with the pandemic have presented refiners with a dilemma – how to make smart investments while preserving cash in order to maintain their competitive position. These scenarios provide opportunities for a focused investment through revamps that can keep a refinery competitive and achieve high returns.

Note 1.

Schoepentoete is a Shell trademark.

Optimized Gas Treating, Inc.., Buda, TX 78620 +1 512. 312 .9424, www.ogtrt.com HYDROCARBON 21

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OPTIMUM

FLOW

TECHNOLOGY Tom Ventham, Unicat B.V. & G. W. Aru, LLC, looks at how to unlock SMR catalyst reformer profitability, with uniform tube packing and improved flow patterns.

September 2021 22 HYDROCARBON ENGINEERING

n almost every industrial application, advances first focus on areas of catalytic improvement. Steam methane reforming is no different, but nickel catalysis improvement has plateaued. This leaves operators in a quandary. Changes in market demands and product specifications, as well as advances in adjacent catalyst technologies – from hydrocracking1 to ammonia synthesis2,3 – necessitate greater hydrogen output. However, in most cases hydrogen remains unscalable from existing equipment without expensive retrofit. Moreover, as a highly energy intensive process, and thus a major CO2 emitter, steam methane reformer (SMR) operators are

mandated to attain new levels of efficiency for sustainability reasons. Aware that many in the industry were nervous about this seemingly unassailable issue, Magma Catalysts & Ceramics (now part of Unicat Catalyst Technologies LLC) has developed an alternative way to produce catalyst for reformers. Importantly, MagCat catalytic behaviour is nearly identical to existing SMR catalysts, as it similarly uses nickel as the active ingredient. However, its shape, size, and physical properties change how fluid flow passing through reformer tubes interacts with solid catalyst. Consequences of these flow changes impact energy

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transfer; a critical limiting factor in highly endothermic reaction systems. Furthermore, improvements inherent in the design of the catalyst technology mean that beneﬁts can last longer into the cycle, unlocking value potential. This article offers readers a visualisation of an alternative approach to packed-tube SMR loadings.

Shape and size Previously published articles have discussed in detail how differences in MagCat production give new possibilities in terms of optimised size, minimal drag, spherical shape, and ability to add surface texturing and sub-surface porosity.4 This article takes a macro view to show how the catalyst technology responds dynamically in hot reformer tubes and how this becomes the true realisation of beneﬁts that can be valorised by operators.

Improved loading technique To begin this thought experiment, let us consider loading MagCat to the reformer. Several years ago, smart operators identiﬁed dense loading of reformers using springs suspended on wires to slow catalyst pellet average drop

velocity and give benefits over traditional sock filling techniques. Dense loading can improve cold-tube pressure drop profiles by reducing pellet breakage when dropping from height. The number of rejected tubes outside dP tolerance reduces, and sometimes a lower overall loading time is experienced. In addition, dense loading can allow 3 – 7% more traditional-shaped cylindrical catalyst pellets to be loaded in a given tube.5 This directly translated to surface area increase which was commonly becoming a limiting factor for many reformers pushed to produce more hydrogen at higher outlet temperatures. Although dense loading MagCat remains feasible and can be preserved as a predilection of decision makers, rigorous testing and evaluation has proven that if the catalyst technology is dropped directly into reformer tubes it will not result in excessive breakages or loading profile inconsistencies. Very high strength properties and spherical shape mean that the catalyst technology automatically arranges into uniform packing patterns in every tube loaded, thus achieving maximum catalyst quantity in each tube. This criticality to load as many pellets as possible, to avoid activity or cycle length limitations, is less significant for MagCat filled reformers due to increased particle surface area. To achieve certainty of good reformer operation, it is important to examine responses of catalyst types in heated tubes and over a cycle comprising several shutdowns.

Catalyst dynamics in a thermally cycled reformer tube Step one: loading

Figure 1. Example of Magma/Unicat test rig filled with wagon wheel cylindrical catalyst.

Figure 2. Computer simulation of Magcat packing in cold or hot operations.

September 2021 24 HYDROCARBON ENGINEERING

Assume two scenarios. One is a steam reformer, well-loaded with traditional cylindrical SMR catalyst using dense loading methods and attaining dP tolerances of 3% or less. Although such loadings can be defined as acceptable under cold conditions, shape characteristics of cylindrical catalysts mean loading patterns (when viewed cross-sectionally at points along the tube) are chaotic, random, and non-repeating through the length. The second situation is an identical reformer with MagCat, filled using sock loading or dense loading technique if preferred by the user (differences are not expected using either technique). Spherical shapes have complete rotational and reflection symmetry and dynamic properties to roll and pivot into openings, due to a naturally low moment of inertia which results in optimised packing. Cold pressure drop measurement across these two catalyst loadings (assuming similar particle diameter) will show lower deltas for MagCat. Symmetrical, spherical shapes impart less drag than bluff cylinders orientated in all

possible axes. Additionally, bed voidage with MagCat is higher due to regular and uniform spaces between adjacent spheres, controlled by assigning appropriate sphere size for each reformer. Randomly packed cylinders have voidage deﬁned by holes through the piece as well as irregular gaps (or no gaps) between adjacent particles. Selecting smaller MagCat sizes achieves constant pressure drop with improved radial heat transfer and activity. For example, a constant catalyst size is maintained for both MagCat and traditional cylindrical catalyst loadings.

Step two: heating As reformers heat at start-up, metal tubes expand. Although solid pellets also experience increasing volume, this is slight as there is lower coefﬁcient of thermal expansion (CTE) for ceramic materials than metal alloy

reformer tubes. In systems dense loaded with cylindrical type catalyst, increased available bed diameter results in catalyst dropping down tubes as pellets, reordering themselves to fill gaps. Rearrangement of catalyst happens in an uncontrolled way that cannot be checked, verified, or repeated. Randomly packed systems become more chaotic as bridges form, as well as areas of tightly packed catalyst with little room for uniform gas flow. Bed void space, or bulk voidage, is another way to examine this effect. This mathematical measurement compares available reactor volume, in this case thermally expanded cross-sectional area multiplied by original catalyst fill height, over volume of solid material in the bed, i.e. catalyst pellets. Bulk voidage is a powerful comparison for measuring changes in dynamic systems as some parameters remain consistent; expanded tube volume is considered constant over comparison cases, and particle internal voidage is also assumed initially fixed (i.e. assumes no breakage). Moreover, calculation of bulk voidage can be directly translated to bed pressure drop via Ergun’s equation.6 As void fraction increases, pressure drop reduces: Pressure drop = A/V (1- ε)/ε3 Where ε = the void fraction (porosity) of the bed, A = area, and V = volume.

Figure 3. Uniform packed reformer tubes vs random packing.

Figure 4. Sequence of thermal cycling in reformer

tubes.

September 2021 26 HYDROCARBON ENGINEERING

Bulk voidage of freshly packed, cold tubes is a function of particle internal void fraction and interstitial void space between adjacent particles. When tubes expand internal void, fraction remains fixed, but interstitial voidage varies as particles move and reorder. In traditional cylindrical catalyst fills, when hot tubes expand and cylinders reorder, catalyst level drops. Mathematical simulation work of this scenario shows overall bed voidage reducing, as catalyst rearranges and squeezes out interstitial voidage. This means pressure drop increases in traditionally filled, cylindrically-shaped catalyst as tubes heat and voidage reduces. MagCat spheres respond differently in heated tubes. Uniform packed beds, when sock loaded or dense loaded, respond predictably and repeatably as tube diameter increases. Investigations show that outer-ring spheres move to stay in contact with the wall, conducive to good transfer of heat into the bed. Spheres adjacent to this outer-ring move less in comparison. This follows through to spheres in a central core that barely move from original positions. Properties of spheres, particularly when textured to add frictional roughness, allow both fluent movement of outer spheres that fan-out to maintain essential wall contact, as well as a centre benefiting from adherent characteristics of regular, uniform packing to hold and maintain frameworks based on fundamental principles of structural shape arrangements. As opposed to beds using traditional cylindrical catalyst, catalyst fill heights in tubes loaded with MagCat do not drop significantly in a hot system. This results in increased bulk voidage in expanded tube volumes. A stable catalyst core and uniform packing with spheres means large

agcat

Textured TM

LOWER POTASSIUM FOULING

INCREASED HYDROGEN

FUEL SAVING

PRESSURE DROP REDUCTION

INCREASED TUBE LIFE

Figure 5. Impact on flow from catalyst type. voids will not be present to cause cascades of pellets down the bed or significant rearrangements from initial loading. By preserving bed height and thus increasing voidage, Ergun’s equation shows pressure drop with MagCat reduces at start-up rather than increasing, as experienced with traditional reformer catalysts. A further benefit of operating with this type of spherical catalyst loading is flow patterns. As reactant gases pass vertically through the bed, and energy in the form of heat moves laterally from heated walls, the catalyst position remains uniform throughout the tube. This is highly conducive to even reaction rates; maximising conversion and minimising temperature hot spots. Flow uniformity and elimination of dead spots, back-eddies, and no-flow regions minimises methane slip values and extends cycle lengths by accessing available catalytic activity and advancing tube lifetimes.

Step three: cooling For any typical hydrogen plant cycle, numerous shutdowns will be experienced. Some shutdowns are determined by scheduled or unscheduled events affecting downstream units, whereas others will be directly related to issues or occurrences in the hydrogen plant. Different units experience different regularities of shutdown, but all reformer units expect to shutdown several times during a typical cycle. Furthermore, frequent variations in hydrogen production requirements, other operational deviations, and furnace changes (e.g. ﬂuctuating fuel caloriﬁc values if using PSA purge gas) create both minor and more major temperature variations throughout the catalyst cycle. During cool down, reformer tubes contract in the direction of original internal diameter. In traditional cylindrical catalyst loadings, this process is associated with impending catalyst breakage as tightly packed pellets. Having rearranged to wider diameter tubes, it is not possible to reorientate back to the original positions of the cold tube. Shape and randomness of packing result in pieces locking together rather than shifting position in response to kinetic contracting forces. This results in breakage. Consequences of thermal cycling include pressure drop increases over the run as well as activity reductions. Voidage reduces further upon each shutdown September 2021 28 HYDROCARBON ENGINEERING

and catalyst fill level falls as crushed catalyst loses structure and establishes narrower vapour pathways through the bed. MagCat spheres respond differently in cooling tubes. During heat up and operation, the outermost spheres stretch out, staying in contact with the tube wall. When cooling, spheres that have incrementally moved now relax; reorientating to original positions through a series of successively smaller shifts approaching the centre. Symmetry and ball-like shape allow the catalyst technology to move and roll without interlocking. Contraction forces are distributed evenly around the tube circumference and into the centre. This avoids weak-points of focusing unbalanced stresses on sacrificial pellets crushed to absorb forces acting on the bed. Catalyst fill level, which minimally reduced during warming or operation with MagCat, is maintained at or close to original level and the natural uniformity of spherical packing is retained. Higher crush strength of the catalyst technology resists breakage during operational temperature fluctuations that produce minor changes in tube diameter, by encouraging reorientation of particles rather than breaking. No catalyst crush strength is high enough to impose excessive stress on tubes. Long-term observation with MagCat will be reduced gradient of pressure drop increase over time and retention of activity, as witnessed by maintenance of low methane slip through the cycle. This is additional to lower initial pressure drop due to a naturally optimised shape for minimal drag, consistent and uniform packing profile, and higher (instead of lower) bulk voidage during warm up.

Conclusion This article has detailed a fundamental shift in how to deploy heterogeneous catalyst in tubular reformers, such as those used to generate hydrogen at reﬁnery sites or other syngas producers. Attention previously given to optimisation of catalytic chemistry is yielding ever diminishing returns. Focus must now switch to the support ensuring ﬂuid dynamic, mechanical, and heat transfer properties maximise economic and operational returns from existing equipment.

References 1.

4. 5. 6.

MALDONADO X. E. R., PRIETO, C. M., UTRERA, J. C. E., and RODRIGUEZ, J. P., ‘Boosting mild hydrocracking performance’, (August 2020), https://www.digitalrefining.com/article/1002457/ boosting-mild-hydrocracking-performance FULLER, J., FORTUNELLI, A., GODDARD III, W. A., and AN, Q., ‘Discovery of Dramatically Improved Ammonia Synthesis Catalysts through Hierarchical High-Throughput Catalyst Screening of the Fe(211) Surface’, Chem. Mater, 2020, 32, 23, 9914 – 9924 (17 November 2020), https://pubs.acs.org/doi/10.1021/acs. chemmater.0c02701 HUMPHREYS, J., LAN, R., and TAO, S. ‘Development and Recent Progress on Ammonia Synthesis Catalysts for Haber–Bosch Process’, (10 December 2020), https://onlinelibrary.wiley.com/doi/ full/10.1002/aesr.202000043 BENNINGTON, G. and VENTHAM, T., ‘21st Century Hydrogen’, Hydrocarbon Engineering, (March 2021), pp. 32 - 36. https://www.unidense.com/technology MACDONALD, I. F., EL-SAYED, M. S., MOW, K. and DULLIEN, F. A. L., ‘Flow through Porous Media-the Ergun Equation Revisited’, Ind. Eng. Chem. Fundamen, 1979, 18, 3, 199 – 208, (1 August 1979), https://pubs.acs.org/doi/abs/10.1021/i160071a001

Ghith Al Shaal, Christoph Hauber, Ioan-Teodor Trotus, and Fabian Schneider, hte GmbH, Germany, explore the utilisation of pyrolysis oils in the production of fuels and chemicals.

owadays, economies and industries are heavily reliant on limited fossil-based resources that do not contribute to a circular economy. In this context, a continuous sustained effort is required to shift gear towards more sustainable and renewable resources. An increasing number of governments and companies have taken the initiative to integrate circular economy in their politics and regulations to minimise their carbon footprint. Two essential factors in this transition process are the utilisation of alternative feedstocks and the

minimisation of process waste by increasing process efﬁciency and recycling process waste. Both factors are highly entwined, since the waste of one process can be the alternative feedstock for the other process. In a previous article that featured in the September 2020 issue of Hydrocarbon Engineering, one instance was shown of hte supporting research to minimise the carbon footprint through the use of bio-derived synthesis gas followed by Fischer Tropsch synthesis and hydrocracking of the wax products to produce synthetic fuels.1 While this approach is elegant, it is also very energy intensive. In this article, an

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optimal catalysts converting highly diverse pyrolysis oils requires a large number of catalytic tests with a smart design of experiments. To speed up the process and catalyst development, high throughput testing is mandatory.

Waste refinery concept

Figure 1. Starting materials for pyrolysis oil production.

alternative route with lower energy consumption will be discussed, and ways in which laboratory catalyst testing can support R&D in this field will be described. This route avoids the production of bio-derived synthesis gas via the utilisation of pyrolysis oils in the production of fuels and chemicals. Pyrolysis oils can be defined as the liquid product of a fast heating process at short to medium contact times, in an oxygen poor atmosphere, applied to a wide variety of feedstocks (Figure 1). The feedstocks include biomass such as residual agricultural products, wood, and waste from paper production, and these pyrolysis oils are also called bio-oils. Another feedstock that can be used in the production of pyrolysis oil is plastic waste. This can be post-consumer plastic waste or end-of-life tyres which, in the worst case, would end up in landfills without recycling. The defined structure of the pyrolysis oil is not fixed, and it always depends not only on the feedstock used in the process but also on the process parameters including temperature, reactor design, presence of catalysts, pyrolysis time, etc. Pyrolysis offers numerous advantages as it positively contributes to the defossilisation process by offering an alternative solution in the transportation sector while also offering a solution for the growing global landfill crisis. Thus, it contributes to closing the value chain cycle by saving on raw materials and enabling more versatile recycling of waste. These factors present solutions toward a more sustainable circular economy and have attracted the attention of many industries, including refineries. With refineries experiencing a very unprofitable period due to COVID-19 and travel restrictions keeping kerosene demand at historically low levels, investments in new units are less likely and drop-in solutions for integrating renewable feedstocks in the existing units seem more probable. Developing a strategy to handle the above concerns with pyrolysis oil conversion in a refinery, even as a co-feed, is a great way to decrease a refinery’s carbon footprint. Finding the right feed composition and the September 2021 30 HYDROCARBON ENGINEERING

Many refineries have already considered steps to increase the efficiency of fuel production. In this regard, FCC, hydrotreatment, and hydrocracking units were integrated to upgrade the secondary stream coming from the refinery to gasoline, diesel, and chemicals such as monomers or aromatics. These technologies can also be used to process the pyrolysis oil and upgrade the outcomes of the pyrolysis process toward fuels and chemicals. Yet, by integrating the upgrading process of pyrolysis oil in the workflow of the FCC and hydrotreatment unit, the refineries will be able to produce a sustainable fuel with a smaller carbon footprint and with lower consumption of fossils. This concept is known as waste refinery and could be applied on pyrolysis feed only or a mixture of pyrolysis oil and low-quality stream from oil (e.g. VGO). The later process is known as the co-processing of pyrolysis oil and oil residue. While fuel production is one possible and convenient application, there is also an emerging trend for the petrochemical industry, especially in Europe, to offer fully recycled plastic products. This is an alternative for plastics producers to circumvent restrictive policies by which more and more single-use plastic products or plastics with a very short lifespan (such as packaging) are being banned. Instead of reducing plastics consumption, sustainable recycling offers the chance to keep the quantity of plastics in use at a high level in a CO2- and waste-neutral manner. With the known limitations of mechanical recycling and plastics sorting being a ponderous and costly process, one pragmatic approach in chemical recycling of plastics wastes is the use of mixed-plastics feedstocks (e.g. from municipal solid waste that is not suitable for mechanical recycling), and to tune the pyrolysis step itself toward a maximum yield of short-chained monomers directly or feedstocks that will be used in state-of-the-art technology that already converts mixtures of hydrocarbons into light olefins – particularly FCC and naphtha crackers.

Purifying = valorisation The starting materials for pyrolysis oil production, whether waste plastics or biomass-derived sources, along with the conditions for the pyrolysis process itself, will determine the chemical composition of the product pyrolysis oil. One must keep in mind that pyrolysis alone will probably produce a condensed liquid product which is highly reactive due to the presence of reactive oxygenates and/or unsaturated compounds. Without applying any stabilisation, pyrolysis oils could even be unstable for storage at room temperature. Feeding or co-feeding pyrolysis oils in a reﬁnery unit requires developing a stabilsation strategy – this can be, for example, a low-temperature hydrotreatment step applied immediately after pyrolysis to saturate the most reactive oleﬁns and dienes and/or to remove the most reactive oxygen atoms. This can also help to reduce the free-carboxylic-acid acidity of pyrolysis oils, although

this alone is not the greatest corrosion risk, as will be discussed in this article. In the hydrotreatment of pyrolysis oils, the relative instability of these feeds already needs to be considered in terms of the feed-handling procedures. Even for pyrolysis oils that have undergone some stabilisation treatment, care must be taken to not overheat these to avoid the buildup of particulate matter due to polymerisation reactions. In fixed-bed hydrotreatment applications, even with pre-stabilised pyrolysis oils, the more common approach is to first react the feed at a relatively low temperature, either in a separate reactor or by applying a cooler inlet temperature and increasing the temperature toward the lower catalyst beds. In this manner, one can saturate and deoxygenate more of the reactive species (olefins or oxygenates) while minimising the chance for polymerisation reactions, which can clog a reactor. As shown in previous publications, hte has options for connecting reactors in series both in high-throughput (1 – 10 milliliters [mL] catalyst volume) and in bench-scale units (20 – 100 mL catalyst volume) which can be used to support pyrolysis oil conversion studies.2,3,4 Once a reliable stabilisation, handling, and storage procedure for the pyrolysis oils is established, converting a pyrolysis oil to a fuel or to chemicals bears more similarities to conventional processes applied in oil refining.

New challenges of (hydro-)processing Hydrotreatment to remove heteroatoms such as sulfur and nitrogen from oil fractions is a standard process in every refinery. Sulfide-type catalysts of the metals Co, Ni and Mo are most frequently used in the hydrodesulfurisation (HDS) and hydrodenitrogenation (HDN) of oil fractions. Pyrolysis oils resemble crude oil fractions in that they contain carbon, sulfur, and nitrogen, but pyrolysis oils will also contain significantly higher amounts of oxygen or chlorine than crude oil fractions. Other elements that can be found in pyrolysis oils include fluorine and bromine, as well as sodium, potassium, calcium, and phosphorus. The elemental composition of

the pyrolysis oils determines some of the challenges involved when converting it to fuels or chemicals. Metals and phosphorus can act as catalyst poisons, but there are strategies for keeping their effects in check, either by employing a washing step or with the use of guard beds. The combination of chlorine and oxygen in one feed means water and hydrochloric acid (HCl) will be among the products of a hydrotreatment step. In this context, corrosion can become an issue. The greatest risk of corrosion is not simply from the presence of hydrochloric acid in itself or from the carboxylic acid groups of the compounds in the oil, but rather the possibility of having liquid water droplets condensing downstream of the reactor where they can also dissolve the HCl product and slowly corrode steel parts. With 316-grade stainless steels, one strategy that can be applied to mitigate corrosion is to simply ensure that water cannot condense downstream of the reactor by heating this part of the pilot plant to temperatures above the dew point. Oxygen removal is usually performed via hydrodeoxygenation (HDO) or decarboxylation/ decarbonylation. The HDO reaction can be catalysed by the same types of metal sulfide catalysts used for HDS and HDN reactions. However, in hydrotreatment processes of crude oil fractions, the high sulfur content of the feeds also ensures that the active species remain in the sulfide form. Depending on the catalysts and reaction conditions, the hydrotreatment of pyrolysis oil with low sulfur content might require spiking the feed with compounds containing sulfur (such as dimethyl disulfide) to avoid the loss of sulfur from the catalysts’ active phase. Oxygen removal results in the production of CO or CO2 or in the production of water. Ideally, one would prefer to minimise CO/CO2 production to maximise the carbon atom efficiency. Even without affecting the carbon efficiency, water as a product also brings some special challenges. Aside from the possible corrosion issues referred to above, water also makes product analysis more difficult because the liquid product consists of an organic and an aqueous phase which must be separated.

The right fit

Figure 2. Schematic overview of processes where pyrolysis oils can be converted in a refinery.

September 2021 32 HYDROCARBON ENGINEERING

Hydroprocessing and cracking (FCC and/or steamcracking) processes are the available means of integrating the upgrading of pyrolysis oils in existing reﬁneries or chemicals production complexes. Choosing a suitable combination of a pyrolysis reactor, product fractionation, and upgrading or reﬁning steps will play a major role in making the use of plastics-derived or biogenic pyrolysis oils a rewarding investment.

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parameters at the same time. As for short contact time processes, the developed workﬂows for feed supply and analytics can be implemented in a micro downer unit, which most effectively simulates FCC operation under industrially relevant conditions.

Analysis Standard refinery processes are best addressed with offline analysis of the liquid samples. Offline analysis of liquid samples includes S/N analysis, pH measurements, simulated distillation, XRF, cloud point/pour point, etc. The analysis of pyrolysis oils and their reaction products also requires the use of more specialised analysis techniques such as high-performance liquid chromatography (HPLC), 2D gas chromatograph (GC), and nuclear magnetic resonance (NMR). Aside from these offline analysis Figure 3. Workflow for investigating pyrolysis oil conversion processes on a techniques, the test unit should be laboratory scale. equipped with a GC that offers detection of light hydrocarbons and Finding the right catalyst and the right process non-organic effluents such as H2S, CO, CO2, and hydrogen. condition for the conversion of pyrolysis oil can benefit Additionally, for a complete assessment of heteroatom greatly from running many tests to replicate the industrial concentrations in low-boiling naphtha fractions and light process conditions in a laboratory. Figure 2 offers an hydrocarbons, the integration of online detectors for sulfur, overview of possible pyrolysis oil conversion routes, nitrogen, and heteroatoms is the best choice to gain a highlighting the processes. The two main types of deeper understanding of the product quality, as this processes applied in the upgrading of pyrolysis oils are determines if a pyrolysis-oil-derived product is suited for fixed-bed hydroprocessing applications or short contact further processing in a cracking unit with very specific time cracking applications. Regardless of which is selected, limitations toward impurities. hte can support process research with catalyst testing Conclusion projects or by providing testing equipment for these Pyrolysis oils offer a pragmatic solution for both reducing applications. the amount of waste in landfills and for decreasing the Thus, the complex nature of pyrolysis oils has been carbon footprint associated with fuels and chemicals investigated and the most common challenges for the derived from fossils. Before processing pyrolysis oils into a laboratory equipment can be addressed (Figure 3 offers a refinery or chemicals production complex, a large number schematic overview of these): of experiments are required to ensure that their use can Feed supply generate the desired product properties and to evaluate Direct usage of a full-range pyoil requires special pumping how the long-term use of pyrolysis oils as a feedstock equipment that covers extreme boiling point ranges with impacts catalyst performance. In this endeavour, hte can light components tending to gas out at high temperatures offer testing solutions for both fixed-bed and and waxy residue potentially clogging parts of the unit at short-contact-time fluidised bed processes to aid in finding low temperatures. the best conditions for converting pyrolysis oils to fuels or chemicals.

Reactor setup Investigating hydrocracking catalysts cannot be done without a thorough pre-treat, while a hydrocracking catalyst offers some hydrotreating capabilities in itself – a combination of a set of the different type of catalysts renders a catalyst screening effective, as one can choose to vary temperatures, load different ratios or combinations of catalyst samples, and screen all these September 2021 34 HYDROCARBON ENGINEERING

References 1. 2. 3. 4.

ROBERTS, T., DANNENBAUER, K., and HUBER, F., ‘Test for Success’, Hydrocarbon Engineering, (September 2020), pp. 49 – 52. TROTUS, I-T., ADELBRECHT, J-C., HUBER, F., PONGBOOT, N. and UPIENPONG, T., PTQ Catalysis, Vol. 24 No. 5, Q4 2019, pp. 79 – 83. DANNENBAUER, K., TROTUS, I-T, HENKEL, R. and HUBER, F., ‘Testing times’, Hydrocarbon Engineering, (November 2020), pp. 27 – 30. DANNENBAUER, K., TROTUS, I-T, HENKEL, R. and HUBER, F, ‘Going head-to-head’ Hydrocarbon Engineering, (March 2021), pp. 53 – 56.

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Steve Houghton, Groome Industrial Service Group, USA, explains how online catalyst cleaning can deliver a higher return on investment than traditional cleaning.

he performance of an SCR catalyst system is more critical than ever. Refineries are under close scrutiny with regulators, who are keeping a close eye on atmospheric pollutants. Tight restrictions on NOX levels make high-performing emission control technologies an essential element of the business model. From a production standpoint, refinery owners and management aim to achieve maximum NOX reduction while minimising ammonia consumption and backpressure, all in an effort to ensure efficient operations. And how does a refinery today most efficiently and successfully achieve these goals? The answer is through a properly designed, installed, and maintained SCR catalyst system – with emphasis on skilled and forward-thinking maintenance services that continue once it is ensured the system has a solid foundation.

The role of online cleaning In a situation where a refinery faces operational issues – such as commonly increased backpressure and NOX conversion issues – a choice must be made. A plant can completely shut down a unit to carry out required maintenance. Or, a facility can look to find another option, preferably one where operations can continue while the work takes place. This latter method, known as online cleaning, has enormous benefits for a refinery or facility in the oil and gas or petrochemical space looking to efficiently maintain a NOX or CO catalyst. Perhaps most importantly, a plant manager does not need to worry about emergency shutdowns or be concerned about operating out of compliance, and there is no need to run at limited capacity. These challenges are taken off the table so that the focus can be on continuing production and delivering return on investment (ROI). This is arguably the goal of every refinery operator.

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Figure 1. Post-cleaning inspection image.

including reduced NOX conversion through the SCR due to blocked active Vanadium sites. It is important to note that the nature of the contaminant is crucial to understand when diagnosing an issue and proposing a solution. Due to the design of the catalyst itself, fine refractory dust can cause enormous problems with limited to no visual evidence on the face of the catalyst itself. Additionally, this particular plant saw increased ammonia slip caused by unreacted ammonia, which overwhelmed the remaining catalyst section that was not affected by the refractory contaminant. These are both environmental concerns that put the plant uncomfortably close to NOX and ammonia permit allowances. The ultimate concern for the plant, which was causing the unit to run at limited capacity, was back pressure. Plant management gradually dialed down production capacity from 100% to 90%, with production eventually brought all the way down to 50%. Running at limited capacity resulted in an immediate negative impact on the business operations of the facility, specifically revenue and output. These financial pressures also put pressure on plant management, as the team closely monitored the situation and searched for solutions to the problem. However, the management’s hope was for the problem to work itself out while the unit ran at limited capacity. As time went on, there was no sign of performance improvement and production loss mounted. As the issue grew progressively worse over a two-week period, plant management reached a point where they had to decide whether to shut the unit down or find another option. It is important to note that this particular facility and unit were not built with online cleaning in mind by the design engineers, as there were no access ports that would enable access to the upstream side of the SCR catalyst for cleaning. While this caused challenges and concerns when the online cleaning option was presented, it was not a deal-breaker.

No ports? No problem Figure 2. Example of access door install in progress. Perhaps the best way to showcase the beneﬁts of online cleaning can be demonstrated by a case study example. There are six main points to emphasise when considering an example reﬁnery online cleaning project: The process capabilities of online cleaning. The importance of optimising project design. How the system works. The expected shift count. The quantifiable value of online cleaning. How safety engineering is essential for each step of the process.

Case study The featured case study took place in early 2021. This speciﬁc facility, located on the West Coast of the US, experienced an upset and refractory was liberated from the duct walls. This resulted in the masking of approximately 40% of the SCR catalyst face and caused multiple environmental issues, September 2021 38 HYDROCARBON ENGINEERING

The solution? A required – but implementable – custom design would allow access for a trained team to then correct the issue and avoid a plant emergency shut down. It was necessary to change the process capabilities and carefully consider how the system works. Education was an important part of the early steps of the process. While the plant was interested in online cleaning, the facility’s management team thought this option was not possible as there was no way to access the catalyst while the unit was running. The Groome team of technical representatives and engineers reviewed the facility unit drawings and visited the reﬁnery to inspect unit access. The team identiﬁed an online cleaning design along with a critical operating and safety plan. The ports were a critical piece to the solution puzzle, and early on it was determined how many access ports were needed to effectively clean the catalyst while the unit was operating. Exterior visual inspection allowed for project access and safety planning coordination. Factors considered in the development of the plan included: Operator accessibility.

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Figure 3. This graph demonstrates that three units with the same exact design, operating at the same time, can have different running parameters based on SCR performance.

The location of mounting points for cleaning equipment and fall protection. Job hazard analysis (JHA) for mitigated heat and exposure. Additional information was also required in the planning process. This included unit drawings of the plant, highlighting duct wall design and metallurgy. As the plan for port design was developed, key factors considered included the following: Orientation of catalyst face. Wall depth. Wall design. Wall material. Duct frame structure.

The importance of the planning process The proper planning and optimisation of all of these factors enables the most strategic solution to be developed. This includes the ultimate decision for the correct number of doors, the proper size of doors, as well as maximised access to the face of the catalyst. In this particular case, the planning phase was thorough and extensive. As a result of detailed planning, the Groome team expedited both the custom design of the doors, as well as door production. Integrated into the process, safety and production protocols were outlined to drive project efﬁciency and environmental, health and safety (EHS) compliance. During the planning phase, the continued increase of NOX levels due to lack of conversion posed a rising environmental concern. It became increasingly clear that it was critical for the facility to address these issues while the unit continued operations. Taking into account both internal and external considerations, Groome designed the port installation process September 2021 40 HYDROCARBON ENGINEERING

to accommodate and focus on one port at a time – this was to ensure there was no unit interruption or imbalance. It is worth noting that installing multiple ports to increase project production efﬁciency is possible with some duct wall designs. Factors considered include gas path pressure and the temperature level at the catalyst face. In the case of this particular plant, the unit’s gas path had a vertical up-ﬂow with a catalyst in the horizontal orientation. The catalyst bed sat on a frame that provided an unobstructed gas path, but did hinder access in some areas. While this was taken into consideration when placing the vacuum ports, it is important to note that the key to navigating around the catalyst and duct frame components is a modular cleaning tip design. Since no two units are ever the same, the team must be prepared with different length, angles and sized tips for each scenario. It is not uncommon to have to utilise two or three design setups for each cleaning so that any unexpected challenges can be resolved quickly. For this project, the catalyst was corrugated; however, all styles of SCR or CO catalyst can be effectively cleaned while online whether corrugated, extruded, or pleated. It is essential that the selected maintenance team have the required skills and experience to service all catalyst manufacturers, plus have the required capabilities to work on catalysts of any age (which may range from brand new to 10 or more years in service). Catalyst pitch is also not an issue but is certainly a design consideration.

The immediate benefits of online cleaning Once the port installation was inspected and the team received the green light to continue, Groome moved forward to complete a comprehensive cleaning in four shifts. A day-and-night schedule expedited the cleaning process. Results were quickly realised when viewing plant running

minutes. The thorough cleaning reduced the back pressure by 55%, which restored the operations to the original design pressure. The team quickly returned the unit to the plant due to the chosen – and efﬁcient – method of cleaning. In addition to improved back pressure, NOX conversion, and decreased ammonia slip, the plant was able to realise an immediate ROI on the project due to shutdown avoidance.

In addition to these near-term results, the project provides ongoing beneﬁts for this plant with its future operations and maintenance needs. The presence of cleaning ports is truly an evergreen asset upgrade and will allow efﬁcient cleaning to take place at any time in the future. The work carried out during this project is basically an insurance policy to keep the plant up and running into perpetuity. And in the event of a unit upset, plant management now has options that were not present before this work was completed.

Additionally, high-temperature ﬁlters should be utilised to not damage the baghouse. Skipping this advice can cause schedule delays in the cleaning, which puts at risk additional crew production. While each project has a different production and safety design due to unit design characteristics, personal protective equipment (PPE) utilised on each project is relatively consistent (there must be top-grade PPE for the team when working on a unit in operation). It is also essential to take the proper heat safety precautions since heat is escaping through the ports. It is advisable to continually monitor the temperature and ambient air with sensors worn by each operator. An appointed crew member can be on point to act as a timekeeper to rotate the crew regularly, so the team avoids excessive exposure. In addition, heat arresting systems allow for tempered air to be monitored by a dedicated crew member; this works to ensure touchpoints are managed with appropriate PPE and to protect the cleaning equipment itself.

Continued safety

The bottom line

There is an escalated level of protocol for safety when the project is performed while the unit is in operation. Safety measures are engineered into each step of the project to mitigate the risk of injury from heat exposure, NOX exposure, burns, or falls. High-temperature compliant stainless-steel hoses are utilised to perform cleanings and the size of the hoses depends on how much vacuum is needed to draw.

There is no doubt that the care and maintenance of the catalyst must be top-of-mind and high on the priority list for all reﬁnery ownership and management. Today’s additional tools and techniques can assist a plant’s team to achieve the desired results in the optimal way – a way that enables the facility to continue production and minimise downtime, all while delivering a strong ROI. Online cleaning is a solution that is likely to continue gaining traction in the industry.

The lasting benefits of online cleaning

Bradford Cook, Sabin Metal Corp., USA, looks at the impact of increasing carbon and coke in spent precious metals catalysts.

trend has emerged in the petroleum and petrochemical refining industry over the past five years or so as an ever-increasing percentage of carbon is being found within alumina and silica-alumina precious metals (PM) catalysts sent in for reclaim. Some of the material arriving is over 40% carbon, and this has been corroborated by many PM refining companies around the world. This high-carbon trend is creating processing backlogs for precious metals refiners, which is resulting in long delays in metal returns to catalyst owners. This article hopes to raise awareness in petroleum and petrochemical leadership teams, and open further dialogue between the catalyst owners and precious metals refiners to find and implement solutions to this dilemma.

It is unclear whether this high-carbon trend is a result of less in-situ pre-reclaim burning to save time/money on turnarounds, longer process run times, or simply more difﬁcult feedstocks. The most likely answer is that it is a combination of all of these factors. The decision to delay maintenance and turnarounds during the COVID-19 crisis has been quite common, but this high carbon issue pre-dates the virus. The issues of feedstock choice and the analysis of run-time lengths being far more technically motivated decisions, this article will instead focus for the moment on the bottom line that must be addressed: the removal of the carbon. Not that long ago, it was standard operating procedure for just about every precious metals catalyst user to remove the majority of the carbon, moisture, trace solvents, etc. when

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Why kilning? Basic sampling theory rightly stresses homogeneity, so there is no getting around the necessity of kilning. The contamination levels within the catalyst, whether they are carbon, moisture, etc., must be eliminated or greatly reduced to make it possible to properly sample. Inaccurate sampling would result in erroneous precious metal content calculations – which is bad for everyone. Additionally, both hydro- and pyrometallurgical precious metals recovery methods require low-carbon feed for best precious metals recoveries and overall efficiency. Figure 1. Remaining at or around 10% for at least six years prior to Reclaimers are doing what they can to 2011, the rise to the present day is dramatic and clear: three times more handle this growing need for excessive carbon and coke than just a few years ago. kilning. The construction of Sabin’s third kiln is complete in North Dakota, US, and change-out was imminent. This was accomplished in one of theoretically this will eliminate approximately one-third of two ways: the user would either conduct their own the backlog. The problem is that the dirty stuff just keeps pre-reclaim burn in-situ, or the spent catalyst would be sent coming; and now the repercussions are being felt by the off-site to a vendor specialising in regen and thermal catalyst owners and the PM marketplace. reduction. The carbon negatives Unfortunately, it has now become much more common for the user to dump the spent catalyst and send it out to the Increased wait times for final precious metals PM reclaimers dirty. The increase in carbon-loaded lots return shipped to Sabin (those that must be kilned) is shown in Catalysts that are received clean (that is, with carbon, Figure 1. benzene, moisture, etc. all within acceptable tolerances) can In-situ pre-burn and the perception of proceed directly to sampling. The typical settlement time for cost savings these relatively clean materials (from receipt at the reclaimer Two petroleum customers have provided pre-reclaim burn facility to final delivery of the precious metal value to the cost case studies from units with different catalyst types. client) is generally three to four months. This includes all Although both case studies used essentially the same processing, laboratory analysis of the samples, and final timeline, for discussion purposes the in-situ regen time has paperwork agreement and execution. These so-called ‘clean’ been rounded up to an even 24 hours. Each unit in the study catalysts may have come from a product line that does not contained 200 000 lbs of catalyst, but different products generate carbon, benzene, etc., or they may have been burned were being made, so the revenue per day varied – and in situ (the pre-reclaim burn) or sent out for burn at a therefore so did the cost: specialised vendor before shipping to the precious metals reclaimer. US$550 000 revenue/d reactor = in-situ burn at The settlement time when kilning is required is at least US$2.75/lb twice that long. In some extreme cases, heavily coked catalysts (over 40% or so) require second or third runs US$945 000 revenue/d reactor = in-situ burn at through the kilns to reduce the carbon sufficiently. This US$4.73/lb timeframe includes waiting in line for kilning and the kilning time itself. Average: US$3.74/lb Lease rates on platinum (Pt) are currently around 3.5%; however, lease rates on palladium (Pd) are less easily sourced, Suffice to say, precious metals reclaimers charge as it is in sparse supply. Standard platinum content of 0.3% significantly less than US$3.74/lb for kilning. It would certainly means that leasing costs can exceed US$1000/d. It is not appear from the front-end view that outsourcing the carbon unusual for some catalyst owners to spend closer to removal is cost-saving, as it allows a faster refinery return to US$2000/d on lease fees. In either case, it closes the production. This is probably one of the main factors driving perceived savings gap by a significant amount. catalyst users to choose to forego the in-situ burn, drop the ‘Trapped’ precious metals dirty catalyst and send it off for kilning at a much lower rate. If a PM reclaimer has a backlog at the kilning pinch-point, all of These high levels of coke, carbon, and other contaminants are the material waiting in line is just sitting in the warehouse. All creating significantly higher operating costs for the reclaimers, of the platinum group metal (PGM) ounces contained have storage issues, and (not so obviously) the carbon negatives been removed from circulation for the length of the backlog. presented in this article. September 2021 44 HYDROCARBON ENGINEERING

Silicon carbide, tungsten and other materials added to automotive catalyst recycling have created similar issues. Specialised processing is now necessary in the preliminary recycling stream, and there are only a few places that can mitigate the ‘contaminants’. Meanwhile, an untold number of PGM ounces remain trapped in inventories waiting their turn. This problem will continue for many years as improvements and changes in catalytic convertor engineering and design are usually done a decade in advance, and therefore the autocatalyst in vehicles hitting the market now will not be returned to the recycling market until those cars are junked – an additional 10 years down the road. China has effectively closed its export of any PGM catalysts in the last few years. Over 80% of puriﬁed terephthalic acid (PTA) production is in China, to name just one market example. Lastly, the details of the mining industry cannot be ignored. PGM comes from South Africa and Russia almost exclusively. The ore quality in these regions is deteriorating, it is getting more expensive to pull each ounce out of the ground, and demand is not falling.

Call to action There would appear to be a limited number of possible corrective actions. One solution would be for PGM reclaimers and regen vendors to add more kiln capacity. This is ongoing, but at best can only achieve partial correction. The time constraints created by the excessive carbon content will continue to result in higher lease costs.

Additionally, if the PGM reclaimers raise their kilning prices to near or the same level as the cost of in-situ pre-reclaim burning, the catalyst users will re-evaluate shipping the catalyst dirty. This should have the desired effect over time. Competition is always encouraged, as long as it can be done on a level playing field. In precious metals, a ‘lowest-bidder mentality’ is problematic: its consequences are incorrect sampling, inaccurate assay, improper disposal of wastes, or other improper behaviour.1 Catalyst owners must calculate the full cost of skipping the in-situ burn and start making this process the norm again. When perceived savings to catalyst owners appear within a single area of fiscal responsibility, and the future repercussions remain somewhat clouded, the type of decision required would have to come from a higher level of management. In short, the ‘big picture view’ of the upper echelons is critical. A greater sharing of information between catalyst users and precious metal refiners will help to gain greater understanding of this problem, and industry forums such as the American Fuel and Petroleum Manufacturers (AFPM) and International Precious Metals Institute (IPMI) conferences would seem logical venues to do so. It is advisable to get involved in this kind of industry stewardship and work together to achieve the ‘win-win’.

Reference 1.

COOK, B., ‘Protecting the Precious’, Hydrocarbon Engineering, (June 2019), pp. 41 - 43.

William K. Rouleau, Merichem Company, USA, discusses the need for controlling sulfur impurities in order to prevent contamination and to improve the efficiency of end user products.

ossil fuels, formed from organic material over the course of millions of years, are the most widely used energy sources in the world. As an overall share of energy consumption, oil sits on top of the spectrum at 33% of all energy consumption. Natural gas ranks third at 24%. In all, fossil fuels represent 82% of the world’s energy needs. Acidic in nature, sulfur is one of the most common and undesirable impurities present in crude oil. Sulfur

compounds tend to deactivate some catalysts used in refining process units and can cause corrosion problems in pipeline, pumping, and refining equipment. Sulfur levels in automotive fuels also impairs the effectiveness of emission control systems which can lead to the sulfur oxide gases in the air. When those gases react with water in the atmosphere, they form sulfates and acid rain that can cause damage to buildings, destroy automotive paint finishes, acidify HYDROCARBON 47

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soil, and ultimately lead to loss of forests and various other ecosystems. Sulfur emissions also cause respiratory illnesses, aggravate heart disease, trigger asthma, and contribute to the formation of atmospheric particulates. The presence of sulfur is a critical issue that requires both conventional hydrodesulfurisation and alternative desulfurisation methods such as selective adsorption, oxidation/extraction (oxidative desulfurisation), etc. for removing refractory sulfur compounds from petroleum products. Research laboratories and reﬁneries are

Figure 1. FIBER FILM treating units used in caustic treatment for removal of impurities from liquid hydrocarbon streams.

spending large amounts of money to ﬁnd viable and feasible solutions for reducing sulfur to a concentration of less than 10 mg/l.

Problem There are many types of crude oil produced around the world that range in density and consistency, from very thin, light weight and volatile fluidity to an extremely thick, semi-solid heavy weight oil. The market value of an individual crude stream is reflected in its inherent characteristics. Sulfur content is one of the most important characteristics of crude oil that affects its market price. The sulfur content of crude varies from less than 0.05 to more than 10 wt% but generally falls in the range of 1 – 4 wt%. Crude oil with less than 1 wt% sulfur is referred to as low sulfur or sweet, and that with more than 1 wt% sulfur is high sulfur or sour. Crude oils contain sulfur heteroatoms in the form of elemental sulfur (S), dissolved hydrogen sulfide (H2S), carbonyl sulfide (COS), inorganic forms and most importantly organic forms, in which sulfur atoms are positioned within the organic hydrocarbon molecules. Sulfur containing constituents of crude oils vary from simple mercaptans, also known as thiols, to sulfides and polycyclic sulfides. Mercaptans are made of an alkyl chain with –SH group at the end (R–SH). It is imperative that the impurities are removed to standards suitable for edible or industrial use.

The technical solutions

Figure 2. LO-CAT treating unit used with catalyst to

reduce H2S concentrations to less than 1 ppm from gas streams.

September 2021 48 HYDROCARBON ENGINEERING

There are a range of hydrocarbon treating equipment, catalyst, and service solutions that remove sulfur and other impurities from hydrocarbon liquids and gases to the upstream, midstream, and downstream energy sectors. CAC®-Products are a series of carbon-activated catalysts that have been designed for use within solid-bed hydrocarbon-treating technology. These products remove the heavy mercaptans found in jet fuel, kerosene and other middle distillate streams. CAC-Products are pre-impregnated with cobalt-based catalyst and will reduce mercaptan concentrations to less than 5 ppm. JeSOL®-Products are a series of sulfur extraction catalysts that have been designed for use within hydrocarbon-treating technology without the need of solid-bed contacting. These products are utilised by reﬁners and midstream processors to extract sulfur compounds from distillate, gasoline, and condensate streams and provide feedstock treating ﬂexibility across a wide range of COS, H2S and RSH concentrations. These products are supplied with a full life-cycle service which includes delivery of fresh catalyst and return of spent solution. ARI®-100 Products are a series of concentrated cobalt catalysts that have been designed for use within regenerative caustic treating processes and are designed to accelerate the oxidation of mercaptans found in petroleum fractions. The products are offered in either a powdered form or a solids-free liquid form.

MC-500® Products are a series of catalysts that have been designed for use within the LO-CAT® iron-redox sulfur removal technology. The products will remove H2S from any type of gas stream and reduce the H2S concentrations to less than 1 ppm. All catalysts mentioned are manufactured to be utilised within licensed treating processes.

The challenges The conventional method of contacting two immiscible liquids – such as hydrocarbon and caustic or amine – is to disperse one liquid thoroughly into the other as small droplets. Impurities pass between the two phases at the surface of the droplet. Mass transfer can only be improved by creating more numerous and smaller droplets in order to increase surface area. Even when the dispersion-based system provides adequate treatment, separating the two phases is usually extremely inefficient. The mixture must remain in the phase separator until the caustic droplets settle out by gravity, a process that may take hours. As the treating requirement becomes more difficult, mixing energy is increased to maximise interfacial surface area, leading to a greater dispersion of the aqueous phase which causes the separation time to become exponentially longer. Stable emulsions can form in the mixing device, resulting in massive carryover out of the separator vessel. Due to excessive carryover, expensive equipment such as knockout vessels, sand filters, water wash units and electrostatic coalescers must be installed downstream to remove the dispersed aqueous phase from the treated product. Treatment is often interrupted if an emulsion develops. Conventional dispersion and phase separation methods come with a host of problems, such as: lack of turndown capability, plugging, flooding, channelling, long settling times, aqueous phase carryover, plot space requirements, product contamination, and unpredictability. Caustic treating processes with dispersive mixing devices were once the only option available to the industry. Yet conventional dispersion and phase separation methods are subject to numerous shortcomings, such as lack of turndown capability, pluggage, flooding, channelling, unpredictable treating results, long settling times, aqueous phase carryover, generation of dilute aqueous wastes, lower service factor, hydrocarbon losses, larger plot space, product contamination, and additional processing steps and equipment needed to separate phases.

The treating processes There is a technology on the market today with a unique design with a significantly larger interfacial surface area, using minimum mixing energy, allowing for enhanced microscopic diffusion and a continuous renewal of the aqueous phase. Efficiency of mass transfer is improved by an order of magnitude which reduces operating costs. FIBER FILM® contactors are equipment for caustic removal of mercaptans, naphthenic acids and hydrogen sulfide impurities from hydrocarbon streams. Mass transfer September 2021 50 HYDROCARBON ENGINEERING

equipment creates an interfacial surface between hydrocarbon and caustic phases in a non-dispersive manner. It consists of a multitude of fibres packed in a cylindrical column where the hydrocarbon and aqueous phases flow co-currently downward forming a thin film on the fibre surface. This eliminates problems associated with the principle of droplet formation and dispersion of one phase into the other, followed by conventional sulfur extraction/sweetening units. Best case treating systems are custom designed to meet customer requirements, then engineered and fabricated to the customer’s specifications, whether the need is for a completely new facility, or a minimum retrofit to upgrade existing equipment.

Results Petroleum refining is a unique and critical link in the petroleum supply chain, from the wellhead to the pump. Selecting the optimum treatment for removing impurities from hydrocarbon streams is a challenging task for any refiner. By providing the means to offer a series of proven liquid hydrocarbon treating technologies, oil companies can offer services that complement their own technology portfolios. Examples include: Turkish oil company Tüpraş treated a 22 000 bpd hydrocarbon stream at its Izmir refinery. The technologies help meet jet fuel specifications. In addition, its licensed caustic neutralisation technology treats up to 1.6 m3/h of spent caustic ahead of the existing wastewater treatment plant. Samsung Total Petrochemicals Co. Ltd required technologies for its heavy-ends by-product upgrade project. It treated 15 000 bpd of jet fuel in order to meet internationally accepted jet fuel specifications. Refineria de Cartagena SA (Reficar) selected technologies to treat hydrocarbons and spent caustic at its refinery in Cartagena, Colombia. It treated coker LPG and saturated LPG at the facility. It added technologies, in conjunction with salt and clay beds, to treat kerosene and jet fuel streams. Shell Eastern Petroleum Pte Ltd used selective technologies for a revamp project at its refinery in Pulau Bukom, Singapore. It treats propane/propylene, butane/butylene and light catalytically cracked gasoline streams to meet product specifications. According to Global Market Insights, the global oil refining market will surpass US$7 trillion by 2024, but not all crude is created equal.1 The relative value for a crude is largely determined by its yields, which in turn is determined by its characteristics as it enters or leaves the refinery. The growing demand for lighter petroleum products coupled with the introduction of air borne emission regulations will continue to drive technological advancements in desulfurisation.

Reference 1.

https://www.gminsights.com/pressrelease/oil-refining-market

James Wood and Sergio Treviño, Southwest Research Institute (SwRI), USA, introduce a midstream heavy crude oil processing technique for cost-effective pipeline transportation.

ransporting heavy crude oils through pipeline or by other transportation means is challenging and often requires the petroleum industry to resort to rail transport for inland sources. Heavy and extra-heavy crude oils are difficult to transport via pipelines because of their high viscosities, asphaltene and paraffin deposition, increased content of formation water, salt content, and corrosion issues.1 Heavy crude oil and bitumen production and transport are at least twice as capital- and energy-intensive as the production of conventional oil.2 The expenses and energy requirements associated with the production and transport of heavy crude oil arise from the high viscosity at reservoir conditions, as well as the presence of undesirable compounds such as asphaltenes, heavy metals, and sulfur. This makes heavy crude oils difficult to produce, move by pipeline, and refine.

Pipelines are widely regarded as the most attractive option for transporting crude oils. They offer low costs and relatively low environmental impacts compared to other transport options that require loading and unloading oil in environmentally sensitive places. As such, several technologies have been developed to facilitate the transport of heavy crude oil via pipelines, including heating and injection of ﬂow improvers. Southwest Research Institute® (SwRI®) scientists and engineers have developed a new process for treating heavy crude oils, making pipeline transportation of heavy crude oil and similar commodities more cost-effective and less energy intensive. ‘EZ Flow’ combines hydrodynamic cavitation processing of the heavy crude oil with proprietary addition of chemical formulations to reduce the heavy crude oil’s viscosity by over 60%, helping it ﬂow more easily through existing pipelines.

Background There are several driving forces behind the development of a new process for making heavy crude oils ﬂowable in pipeline. First, heavy crude oil transport is a necessity for petroleum producers worldwide. For example, at least 50% of crude oil reserves in Mexico are heavy and extra-heavy crude oils.3 Canada currently relies on heavy crude oil to meet production needs, producing approximately 700 000 bpd of synthetic crude oil that comes from heavy crude oil, bitumen, and tar sands. These synthetic crudes are transported via pipelines to reﬁneries in Canada and the US.2 The pipeline technologies currently available to transport heavy crudes are expensive, requiring large volumes of chemicals or diluent, and tremendous energy resources in the form of heat. They often HYDROCARBON 51

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high density and viscosity (≥1000 cP at 40°C) and very low mobility at reservoir temperature of the commodity.2 The asphaltene’s macromolecules precipitate and aggregate in the oil, contributing greatly to its high viscosity and density, as well as pipeline flow resistance. The most important factor influencing its high viscosity are the intermolecular forces between the large, branched molecules and the tendency of the asphaltenes and paraffins to coalesce, producing aggregates of heavy hydrocarbons. Those agglomerations generate structural compression of the oil and reduce its relative volume. That, in turn, increases the density or API (American Petroleum Institute) weight of the heavy crude oil. Because of these natural physical and chemical properties, heavy crude oils and extra-heavy crude oils are difficult to transport in general and very difficult to transport via pipeline over long distances.

Usage

Figure 1. Pre-mixing chemical with heavy crude. require multiple treatment techniques simultaneously or the addition of diluent injections down the pipeline. Non-pipeline transportation methods, such as rail or tanker trucks, are expensive, incurring fuel costs, transport maintenance, and high environmental impact, in addition to risks for derailment and collisions. For example, when considering air pollution and greenhouse gas costs alone, the costs associated with moving a fully loaded 100-car train of crude oil from North Dakota, US, to the US Gulf Coast are approximately US$150 000 one-way. The same transportation to the US East Coast results in costs of approximately US$210 000. The total estimated air pollution and greenhouse gas damages for oil shipped by rail from North Dakota in 2014 exceeded US$420 million.4 A literature review of current heavy crude oil pipeline transportation technologies concluded that: “For the increasing exploitation of heavy oil and bitumen, it is necessary to develop technology to aid in their transportation through pipelines.”2 Globally, of more than 80 million bpd of crude oil that are produced, about 11 million bbl of that are classiﬁed as heavy crude oils.5

Relevant theory Logistically, transporting heavy crude oil and bitumen via pipeline is challenging at best and often impossible due to the September 2021 52 HYDROCARBON ENGINEERING

According to API, the US has more than 190 000 miles of liquid petroleum pipeline that deliver crude oils, including heavy crude oils, to refineries and chemical plants throughout the US. EZ Flow is a potentially cost-effective method for transporting heavy and extra-heavy crude oils over long distances by pipeline over various terrain. The mechanism behind the method’s effectiveness is that the treatment reduces the intermolecular forces between and inside the agglomerates of the heavy crude oil and promotes a dispersion phenomenon, the opposite of aggregation. The chemical and mechanical treatment of the heavy crude oil work in unison to reduce viscosity. Chemical additives (Figure 1) reduce the interfacial tension in heavy crudes, whereas hydrodynamic cavitation (HC) provides enough energy to enhance the chemical action (Figure 2), break the aggregates, and disperse the asphaltenes. It is like intense local thermal treatment that does not raise the whole mass of oil to the target temperatures needed for the disaggregation. The chemical formulation of the associated additive is a proprietary mixture of low concentration compounds, compared to other treatment options, designed specifically to optimise the hydrodynamic cavitation of the heavy crude oil that can reduce heavy crude oil viscosity by over 60%. The additives will not interfere with subsequent processing in the refinery. The composition of the chemical formulations and hydrodynamic cavitation process may be further optimised to lower the viscosity of different types of heavy and extra-heavy crude oils from different regions to make any unconventional crude oil flowable for transport through existing pipelines. The advantages of this heavy crude oil treatment technology for pipeline transportation include very low chemical additive costs and environmentally friendly qualities. The technique is not technically demanding and treated oils can be stored for long periods of time without affecting the viscosity improvements. The process may be scaled-up to a commercially viable operation with low upfront and operational costs.

Benefits for oil refining In addition to reducing viscosity to allow for pipeline transportation, EZ Flow could be used to upgrade heavy crude oil. The changes created in the heavy crude oil ﬁeld

will facilitate processing in the refinery and within the encompassed operations. Heavy crude oil upgrading associated with EZ Flow will require further research and optimisation, but it could produce significant benefits for the oil refining industry. The research performed to date has been developmental, but the application of the technology to industry has the potential to change the dynamics of the unconventional crude oil market, bringing transportation costs more in line with those of conventional crude oil. The next phase of research will begin scaling-up the technology.

Figure 2. Schematic diagram of the high-speed rotor of an HC LabSPR.6 3.

References 1.

MARTINEZ-PALOU, R., ‘Transportation of Heavy and Extra Heavy Crude Oil by Pipeline: A Review’, Journal of Petroleum Science and Engineering, pp. 274 - 282, (2011). HART, A., ‘A Review of Technologies for Transporting Heavy Crude Oil and Bitumen via Pipelines’, Journal of Petroleum Exploration and Production Technology, pp. 327 - 336, (2014).

5. 6.

Investigación y Desarrollo, ‘New Technology Reduces Transportation Costs of Heavy Oil’, Distrito Federal, Mexico: Investigación y Desarrollo, (2016). CLAY, K., ‘The External Costs of Transporting Petroleum Products by Pipelines and Rail: Evidence from Shipments of Crude Oil from North Dakota’, National Bureau of Economic Research, (2017). GOUNDER, R., ‘Introductory Chapter: Heavy Crude Oil Processing An Overview, Processing of Heavy Crude Oils’, IntechOpen, (2019). RAJORIYA, S., CARPENTER, J., SAHARAN, V. K. and PANDIT, A. B., ‘Hydrodynamic cavitation: an advanced oxidation process for the degradation of bio-refractory pollutants’, Reviews in Chemical Engineering, vol. 32, no. 4, (2016), pp. 379 - 411.

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Michael Strobel, Swagelok Company, USA, identifies common causes and costs of fluid system leaks, and outlines methods to prevent them.

luid system leaks are a frequently occurring problem in many industrial facilities. Their commonality, however, does not make them less problematic. Even the smallest leak can compromise a plant’s safety and proﬁtability. To best defend against leaks, it is helpful to understand how and why leaks occur, how to locate and test for them, and how to develop a strategy to address and reduce leaks plantwide.

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This article will review common causes of leaks, appropriate methods for identifying them, and proactive strategies for reducing leaks across a facility.

A costly problem Across a given industrial facility, ﬂuid system leaks can contribute to a wide range of preventable costs, including the following: Unplanned downtime: plants lose valuable production output potential every time they shut down a process to fix a leak. This downtime can result in significant profit loss. Off-spec production: leaks may lead to the inadvertent production of an off-spec product. This material must then be reworked, sold at a reduced price, or discarded. Damaged equipment: leaking lubricants can lead to premature wear on critical equipment and, in some cases, total machine failure. Hydraulic fluid leaks: it is estimated that millions of gallons of hydraulic fluids are wasted each year. A single gallon of hydraulic fluid averages US$40. Slips and trips: fluid leaks can pool on the plant floor, contributing to an unsafe work environment where personnel may slip or trip. Non-compliance fines: leaks can lead to significant fees or fines for non-compliance if systems and equipment violate safety regulations. In addition to fees or fines, fugitive emissions can be expensive to repair and dangerous to the health of employees.

Time and labour costs: locating and repairing leaks requires time and money. In certain instances, a special team may be necessary to manage toxic chemical leaks, potentially leading to the exorbitant cost of shutting down a system for a thorough inspection. The most effective way to reduce these unnecessary costs is to quickly identify and repair leaks already occurring and, more importantly, to prevent leaks before they happen.

Identifying common leak causes How do leaks occur? Individual fluid system components themselves are typically not to blame. Rather, human error that occurs during the selection, specification, or installation process is the most common culprit. Choosing the right components and installing them correctly can reduce the frequency of leaks, helping to enhance plant safety and save significant cost. To better understand and reduce leaks throughout a facility, it is helpful to understand these three common causes of leaks:

Improper tube fitting installation Tube fittings that have been improperly installed can lead to poor performance. It is important to ensure that technicians know how to properly make up a fitting, including proper ferrule orientation and appropriate use of a gap inspection gauge (Figure 1) to verify the correct amount of pull-up.

Unreliable metal-to-metal seals Maintaining reliable metal-to-metal seals can be challenging over the long-term. It is important to follow manufacturer guidelines precisely to avoid leaks when using these types of seals. In some cases, as with valves, it may be necessary to replace a metal-to-metal seal with one featuring a soft seat seal. This can be particularly beneficial when repetitive gas shutoff is required.

Figure 1. Use a gap inspection gauge to ensure

sufficient tightening of a fitting. If the gauge will not enter the gap between the nut and fitting body (left), the fitting is sufficiently tightened. If it will (right), additional tightening is required.

Poor tubing selection, handling, and preparation Incorrect tubing selection and improper preparation can further increase the potential for leaks. For example, tubing materials that are incompatible with the process fluid or external environment will be prone to corrosion, premature failure, and therefore, leaks. Poor tube handling or cutting can also impact performance. Dents, scratches, or poor deburring can compromise the fitting’s ability to create a reliable seal. When building a fluid system, correcting these common mistakes can be an effective way to reduce the likelihood of leaks over the system’s lifetime.

Figure 2. A real leak involves a system fluid escaping via cracks or gaps between sealing surfaces.

September 2021 56 HYDROCARBON ENGINEERING

The three most common types of leaks When leaks do happen, it is important to be able to identify the type of leak so that proper corrective

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measures can be taken as soon as possible. The following outlines more information about the three most common forms of leaks:

Real leak Real leaks (Figure 2) are the result of a pressure barrier’s failure to contain or prevent a system fluid from escaping into the surrounding environment. Real leaks occur due to some form of gap between sealing surfaces or cracks in the material. They are commonly found in valves in which the packing material may have become brittle, cracked, or deformed. Therefore, it can be helpful to use valves that swing open in-line so technicians can make a simple packing replacement instead of needing to uninstall and reinstall (or replace) the entire valve.

Virtual leak A virtual leak (Figure 3) is the release of an internally trapped fluid into a fluid system, often resulting from material outgassing, absorbed or adsorbed fluids, entrapment in crevices, or dead legs (Figure 4).

Permeation Permeation (Figure 5) is the passage of ﬂuid into, through, and out of a pressure barrier that does not have holes large enough to permit more than a small fraction of the molecules to pass through any one hole.

Effectively detecting leaks Most leak testing is performed while the system is pressurised, either with actual process ﬂuid or a surrogate (water, air, nitrogen, and helium are common surrogates). Test methods can be broadly segmented into those typically performed on installed equipment, and those more commonly performed on a benchtop or in a laboratory.

Visual testing Simple visual inspection is an effective way to ﬁnd leaks in a liquid system, e.g. spotting actual drips or surface wetting below the location of the leak. Visual tests are most commonly performed on installed equipment, but they can also be used for test or benchtop hose assemblies.

Figure 3. A virtual leak releases fluid trapped within a system into other areas of the system.

Bubble testing Bubble testing is a simple test for gas systems. It uses a thin ﬁlm surfactant, soap solution, or submergence in a water bath to identify leaks. If bubbling is observed in the surfactant or in the water bath after pressurisation, this indicates the presence of a leak.

Pressure change testing

Figure 4. Within a dead leg, old material trapped in the tee formation becomes a virtual leak into the main fluid stream, resulting in contamination.

Pressure change testing is performed by pressurising equipment in isolation at a certain pressure for a certain length of time. Leakage is indicated by a gradual, measurable drop in pressure. Pressure change testing is common in benchtop applications, but it can be used on installed equipment with careful considerations.

Airborne ultrasonic testing This type of test can only be used on gas systems and requires an airborne ultrasonic measurement device to locate the presence of a leak. It can be used to approximate the rate of leakage for pressurised systems, and is therefore common on installed equipment. It can also be performed on unpressurised systems, assuming an ultrasonic transmitter can be placed inside the system to be tested.

Mass spectrometry testing

Figure 5. Permeation involves fluid that penetrates and moves through and out of a pressure barrier.

September 2021 58 HYDROCARBON ENGINEERING

This test uses a mass spectrometer to detect the presence of trace amounts of leaks in gas systems and can help quantify the leakage. Outboard testing is used for pressurised systems, while inboard testing is used on vacuum systems. This method is most commonly used on a benchtop to identify very small leaks.

Prioritising fixes After identifying leaks in a plant, it is not often possible to ﬁx all of them straightaway. Instead, leaks should be categorised as follows to prioritise repairs:

Dangerous leaks Any leak that presents a safety hazard requires immediate attention. This includes noxious gas and caustic chemical leaks, as well as leaks that create slip/fall hazards.

Costly leaks Collectively, all the leaks in a plant may add up to a signiﬁcant cost. However, even small leaks can be responsible for a signiﬁcant percentage of that cost. Fixing a small leak of expensive argon gas, for example, may offer drastically greater savings compared with stopping a large leak – or even numerous small leaks – of cheaper compressed air.

Nuisance leaks There may also be a variety of minor leaks that do not compromise safety or lead to major costs. These low-priority leaks can be addressed when it is convenient.

Real world impacts The impact that leaks can have on a plant’s bottom line is observable in a recent project undertaken by a large petrochemical producer operating in Texas, US. Faced with rising utility costs, the producer wanted to review its

consumption of utility gases. The producer purchases compressed air and nitrogen from an adjacent plant using ‘pay meters’ under an agreement that is based on a minimum/maximum quantity model. If the usage exceeds the maximum level, the adjacent plant charges a higher rate. This was unfortunately a regular occurrence. With the help of Swagelok Texas Mid-Coast, the producer evaluated its utility gas systems, which had largely gone unchecked for years. The team audited the utility gas systems for six units and then provided a detailed analysis that enabled the petrochemical producer to see the locations of leaks, their severity, and the potential payback opportunity if the facility were to correct each leak. From there, the company could prioritise and plan fixes that could result in major potential annual estimated cost savings from the often-overlooked leaks. To date, with just a fourth of the customer’s units evaluated, Swagelok has found a combined savings opportunity of close to US$500 000/yr. As repairs were completed, the petrochemical producer also noticed an ancillary benefit – it was able to reduce the size of its permanent compressor rentals and may be able to potentially eliminate them all together. This will result in significant additional cost savings. The project is indicative of the impact leaks can have on an operation and its expenses. For hydrocarbon facility operators, examining critical systems for leaks can lead to major benefits.

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Jason Apps, ARMS Reliability, Australia, describes an agile, RCM-based approach to developing optimal maintenance plans.

he contribution of asset performance to meeting the financial goals of an asset intensive business is clear. In the age of connected devices and assets, and with machine learning and artificial intelligence (AI) gaining momentum, it is surprising that organisations are still unclear if they are performing the appropriate amount of routine maintenance on their assets. The concept of asset maintenance optimisation is simple: to perform technically feasible maintenance at the interval which minimises total costs. Perform the maintenance too often, and costs increase due to over-maintaining. Perform the maintenance too infrequently, and the costs increase due to failures caused by under-maintaining.

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It is common for asset managers to be challenged by their executives to reduce maintenance costs whilst maximising asset performance. Conceptually, it sounds simple: minimise routine maintenance that is not adding value while preventing the unplanned failures that are occurring. This high-level view is also what is likely driving the over-application of asset health and asset condition monitoring programmes, with the allure of AI-based interventions. Conceptually, to monitor an asset and only respond once degradation or performance deviation is detected makes sense. So much so, that some organisations have approached this with a view to it being the totality of their asset care approach. Practically, however, there are some limitations. Firstly, basic asset care still needs to be in place, since the connected technologies cannot currently monitor

for all known failure modes. The absence of the basic principles of asset care therefore create exposure to unplanned failure risk. Secondly, in the absence of basic asset care, asset life can also be reduced. The monitoring may pick up the degradation and prevent unplanned failure, however the aim is to get maximum life from assets such that total cost of ownership is minimised. Basic asset care prolongs the life of assets, keeps them in good health and operating safely. Thirdly, from a logistics perspective, there are set maintenance crews, tools, and equipment. As such, maintenance must be scheduled as best as possible to smooth the resource requirements and reduce the cost to execute. In a world where we react to monitoring, the organisation is exposed to potential increases in cost through uneven resource requirements and times of peak resource requirements at relatively short notice. Lastly, connecting operations plans to asset care windows is also a critical element in minimising the cost of maintenance. If the plant is on a 12-week shut down cycle which aligns to their operational goals and product requirements, then adherence to this schedule is key. If some degradation is determined and there is a need to take an asset offline to conduct corrective maintenance, there is significant decision making required to ensure operational plans are maintained. For example, bringing forward a plant shutdown and performing a short stop will be carefully considered, as well as any other corrective maintenance or routine maintenance that should be conducted at the same time. Therefore, minimising maintenance costs and maximising asset performance is achieved through a balanced approach of basic asset care and routine maintenance coupled with more advanced asset health Figure 1. Viewing reliability as a process combining and condition monitoring. reliability centred maintenance (RCM) and asset strategy management (ASM). With the current technology and content available, there is significant opportunity to standardise and optimise basic asset care and routine maintenance. Financially optimising routine maintenance is then surprisingly quick and simple. Fundamentally, the sound principles of reliability centred maintenance (RCM) – a widely proven, accepted and thorough methodology – are taken to develop or review maintenance strategies and utilise simulation or analytical techniques to optimise the maintenance intervals, considering asset characteristics and specific operating context. Additionally, there is an opportunity to utilise generic content, which can be a reasonable starting point for the RCM structure. For most assets, there are detailed failure mode and effect structures available, Figure 2. A petrochemical case study resulted in US$15 million in some with typical maintenance tasks savings and a 37% reduction in production losses over a one-year included. These ‘models’ can be easily span. modified and customised in a short amount September 2021 62 HYDROCARBON ENGINEERING

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of time, enabling the justification of all tasks through a connection to the applicable failure mode and the related effect of failure. This then positions the organisation for optimisation. The key concepts of RCM which can be used to create models for financially optimised routine maintenance are: Functional based analysis. Failure modes and tasks being technically feasible. Understanding the characteristics of failure. For each given instance of the asset, the likelihood of failure can be updated to reflect the asset installation, the environment, and the operational context. The effects of failure can be quantified, along with specifying the corrective maintenance costs. Simulation or analytical methods can then be used to assess the total costs when conducting the maintenance at a specific interval. If this is repeated for several intervals, a plot can then be created to compare the total costs for different intervals. This plot can be used to determine the optimal interval to conduct the maintenance. This method should consider all relevant elements such as: Routine maintenance costs. Corrective maintenance costs. Failure costs, including consequential asset damage and any production or business impacts. All materials and resource costs. Effectiveness of the routine maintenance. Currently, available technology makes this rapid, easy and automatic. Once the models are built, the analysis can be conducted automatically and periodically.

Reliability as a process The main benefit of using RCM as a basis for developing a maintenance plan is that it supports a consistent planning structure across an organisation and provides a solid foundation to continually evolve plans. Routine maintenance needs to be optimised on an ongoing basis. With so many input variables, it is not hard to see how quickly the decision may need to change. Routine maintenance, and the associated interval, may need to be altered as operations, asset duty, asset age, the availability of new technologies, schedules, materials, and product changes. To drive this ongoing review, an organisation needs to structure their resources and technology to support rapid, efficient update and implementation of the latest decisions. To achieve this, financially optimised maintenance programmes conduct this review as a process. It is ongoing and continuous. It is not a periodic review conducted by a project team, but an ongoing process, or reliability-based alignment, of routine maintenance to operational goals, given the current operating environment and asset condition. Called ‘asset strategy management’ (ASM), this process is a structured September 2021 64 HYDROCARBON ENGINEERING

approach built on a foundation of RCM that drives continuous review and improvement of routine maintenance, triggered by changes in business priorities and operating environment. Industries managing inherently high levels of risk – including downstream operations – tend to glean the greatest benefits from ASM.

Case study A recent example can be seen from work completed by ARMS Reliability with a petrochemical company in the Americas. The company sought to optimise routine maintenance plans and strategies for improved plant reliability and reduced costs. Its current process to manage routine maintenance was close to a run-to-failure approach, leading to high costs due to lost production. A maintenance strategy development process was performed to best suit the criticality of each asset and then combined with all available information, including original equipment manufacturer (OEM) recommendations, technician knowledge and experience, and ARMS’ libraries of information for maintenance tasks and failure history. With a focused approach, maintenance plans were then created of tasks that were optimised for cost and risk. The project resulted in US$15 million in cost savings from increased plant reliability and reduced maintenance costs, and a 37% reduction in production losses over a 10-year span.

Benefits With an ASM process in place, organisations have not only the information to conduct the proper maintenance tasks at the correct intervals for each of their assets, but also the understanding of why they should perform maintenance this way, which helps shift mindsets and the organisational culture to a more proactive, reliability-centred approach. ASM can help organisations in a wide variety of industries effectively execute and manage RCM decision making to create bottom-line results. Organisations taking on the ASM approach typically experience: 1 – 6% better performance via increased asset availability. 5 – 30% lower costs. 10 – 30% managed risk through mitigated safety risks. 10 – 50% less reactive maintenance. 200 – 600% more productivity by speeding up strategy development.

Conclusion The vital takeaway is that whether it is process, people, technology or data related, if asset maintenance is not strategically managed, then reliability improvement efforts to deliver value are likely to fail.

OCTOBER 4-6, 2021

HOUSTON, TEXAS M A R R IOTT M A R QUIS H OU ST ON GE OR GE R . B R OW N C ON V E N TION C ENT ER

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Taking Command: Leadership and Risk Management

Admiral William H. McRaven, USN (Ret.) Retired U.S. Navy four-star admiral and former chancellor of the University of Texas System Author, Make Your Bed: Little Things That Can Change Your Life and Maybe the World Retired U.S. Navy four-star admiral and former chancellor of the University of Texas system, William H. McRaven opens our conference with a presentation on leadership and risk management. McRaven is an expert on the topic, having commanded special operations forces at every level, before eventually taking charge of the U.S. Special Operations Command. He is a recognized national authority on U.S. foreign policy and has advised Presidents George W. Bush and Barack Obama as well as other U.S. leaders on defense issues. McRaven has been recognized for his leadership many times, including in 2011, when he was the ﬁrst runner-up for TIME Magazine’s “Person of the Year.” McRaven’s book Make Your Bed: Little Things That Can Change Your Life and Maybe the World, based on his 2014 UT commencement speech, has received worldwide attention.

The Cook Political Report’s Political Outlook

David Wasserman Senior Election Analyst, The Cook Political Report After two turbulent "change" elections in 2016 and 2018, what does 2020's split verdict mean? Highly respected election analyst David Wasserman cuts through the spin and uses fascinating facts, ﬁgures, and maps to take audiences on an entertaining and strictly non-partisan tour of how 2020 could impact the future political landscape. Drawing on his extensive research on cultural, demographic, and voting patterns, Wasserman handicaps the 2022 midterms and beyond. David drew praise for accurately forecasting Trump's path to winning the Electoral College in 2016, as well as Biden's path in 2020. Wasserman is the U.S. House editor and senior election analyst for the non-partisan newsletter, The Cook Political Report, and a contributor to NBC News.

ILTA2021/ILTA.ORG

September 2021 66 HYDROCARBON ENGINEERING

John Cox, Seeq, explains why advanced analytics provides the specialised functionality required to accelerate insights when working with time series data.

rocess plants and facilities typically have large amounts of historical data stored in historians and other data stores, with more added daily as digital transformation initiatives and Internet of Things (IoT) technologies proliferate. This data has potential value, but only if insights can be quickly created and shared among team members to drive faster decision making. Many team members come from different backgrounds with varying areas of expertise, adding challenges. Due to their focus on process dynamics, modelling, sensitivity analyses, and real-time control implementation, process control and automation engineers use a variety of specialised data collection, simulation, and analytics tools. As a result, their data analytics activities are typically distributed among a variety of software applications, most or all of which are not shared with all team members. This creates communication barriers and decreases work efficiency when having to replicate results in these various software applications, or when sharing presentation quality results with colleagues. While extremely useful for their targeted purposes, analytics tools designed specifically for process control are normally ill-equipped to cover the wide spectrum of analytics tasks required when creating insights to time series data, namely: cleansing data, identifying appropriate and focused data time periods, creating before/after comparisons, scaling calculations across assets, and automated reporting. These tasks must be performed by both process and automation engineers. Many of the traditional analytics tools currently in use, such as spreadsheets, were not designed to provide insights from time series data, causing difficulties with analysis (Figure 1). Even if results can be created using the limited

capabilities of spreadsheets for this specialised task, sharing findings is very cumbersome. Therefore, advanced analytics applications are needed which encompass the analytics tasks and workflows common to process engineers, automation engineers, and other operations team members. This same type of application must provide pertinent process control analytics features, and it should be easy to use by all. These advanced analytics are a new generation of software applications that blend innovation in machine learning and data science with easy-to-use features, and they are specifically focused on use cases within a particular industry, in this case process manufacturing.

Bridging the process dynamics divide When troubleshooting process operation or analysing process improvement benefits, process and automation engineers alike often want to find recurring, very specific time periods of operation (e.g. startups, transitions, phases, setpoint ramps, batch sequences, etc.), and then perform analysis on those time periods. To address these needs, advanced analytics applications provide extensive contextualisation features, often referred to as capsules and conditions. These features are specifically designed for creating insights on process data and provide many flexible identification methods, including threshold deviations, increasing/decreasing trends, time spans pre- and post-events, and others. Using contextualised time periods as inputs, process performance metrics can be calculated based on those periods, including notifications triggered from a range of simple to complex analytics when used in monitoring processes.

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Moving into the reporting arena, analytics applications provide users with the ability to integrate their analytics calculations with auto-updating reports and dashboards as well as static documents. This supports the full range of reporting and workﬂow management requirements for use in daily production meetings, incident investigation summaries, site energy use monitoring, and live control room displays. Where applicable, asset trees residing in asset-conﬁgured data sources can rapidly extend analyses and reports across similar assets, which may be individual pieces of equipment,

such as pumps, up to much higher-level assets (e.g. units or sites). With the advanced analytics application in hand, process engineers and subject matter experts can quickly create and share insights, as shown in the examples below.

Evaluating and reporting process improvement benefits

Typical goals of process improvement projects are reducing variability of finished products, lessening invasive corrections by operators, increasing production rates, and decreasing energy usage. Whether it is a process change, equipment modification, or a new automatic control implementation, engineers are required to narrow the data analysed down to the appropriate time ranges of interest. Quantification tools can then be used to calculate signal statistics and other metrics to make performance-based operation comparisons pre- and post-change. Data trend views, such as chain views with time periods concatenated (Figure 2), or capsule view with time periods overlaid to support batch analytics, visually condense the data displayed to only the valid comparison windows, making it easy to determine if the implemented changes resulted in more Figure 1. Spreadsheets are commonly used to analyse the time optimal process operation. series data created by process plants and facility operation, but Those same contextualisation and they typically fall short. quantification features can also be used to streamline process troubleshooting, another common activity for process and automation engineers. Extending these concepts further, there is collaborative value in having automation engineers’ dynamic analytics integrated within the same application used by process engineers, operators, and managers for analytics and reporting. Collaboration examples include: Process engineer uses detailed process knowledge to cleanse and contextualise data, providing the automation engineer with Figure 2. Evaluating raw material level effects on batch datasets optimised for dynamic model fits, or operation cycle time performance using chain view. for control strategy design. Automation engineer creates calculations which measure setpoint tracking performance for critical process signals, and easily publishes these in the analytics dashboarding application for regular review by the operations team. Process and automation engineers collaborate to document process design concepts and control strategies, and then develop calculations to monitor the consensus key performance indicators (KPIs). Process documentation and KPI calculations are integrated within the analytics application.

Add-ons for process control specific analytics Figure 3. A causal map identifying cause and effect for flotation level signals in a concentrator process.

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Process and automation engineers derive signiﬁcant analytics value from contextualisation and calculation tools, and these tools provide the

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Dynamic correlations and modelling: going beyond standard prediction modelling

Figure 4. Dynamic model used for what-if analyses to reduce product transition waste.

Figure 5. Asset tree functionality enables large scale controller performance monitoring. required capabilities for many different types of analyses. Beyond these foundational tools, there are several capabilities that control engineers can specifically utilise in their unique roles, while fitting within the context of advanced analytics features. These go beyond the common analytics approaches and can optionally employ Python libraries and associated machine learning algorithms. The following examples briefly outline cause and effect, basic dynamic simulation, and controller performance monitoring applications performed using these and other tools.

Process variation troubleshooting: finding the needle in the haystack When the process is operating abnormally, automation engineers can spend hours manually inspecting time series data trends for cause/effect relationships and anomalies. The root cause of abnormal behaviour can be very difﬁcult to pinpoint in processes with many sensors, recycle streams, and/or heat integration. The following analytics functionality makes process troubleshooting efforts more efﬁcient: Identifying process changes: benchmark signal statistics across time periods to identify deviations from normal behaviour, and then condense critical signal behaviour in chain or capsule view for easy visual inspection. Causality analysis: generate causal maps to guide cause and effect determination for a large number of signals or complex processes (Figure 3). September 2021 70 HYDROCARBON ENGINEERING

Standard prediction modelling does not inherently handle time delayed or time lagged signal correlations, which are often present in industrial processes due to liquid volume, transport delays, and equipment characteristics. New formulas and tools in advanced analytic applications provide improved approaches to meet dynamic modelling needs: Signal alignment: a variety of methods can be used to align related upstream and downstream signals across varying time periods. For example, process data and quality results from a laboratory must often be compared, which requires alignment in time. Dynamic modeling: user friendly formula functions for time shifting and first order filtering can be combined to generate first order and more complex dynamic model responses. Applications include: Dynamic model fitting of process gain, deadtime, and first order response time for PID controller tuning determination and advanced control implementation. Real-time process estimation. What-if analyses (Figure 4). Correlation analysis: this generates a heatmap correlation matrix summarising the pairwise, maximised signal correlations and corresponding time shifts. This is useful for revealing time-lagged correlations in large datasets, and for creating time shifted signals for further modeling and analysis.

Control loop performance monitoring As part of the base regulatory control layer in distributed control systems, the design and performance of PID controllers is key to reducing process variability to the point where it does not adversely impact production rate and product quality. Therefore, automated monitoring of PID controller performance is essential to proactively identifying oscillations and other types of increased process variation. Contextualisation, formula, and asset friendly scaling features can be combined to automatically monitor individual controller performance, with standard/custom KPIs created to provide unit and plant level performance roll-ups (Figure 5).

Conclusion Process plants and facilities typically create large volumes of data, which is usually stored in historians or other databases. Accessing and analysing this data to create insights, and then sharing results, is very difﬁcult and time consuming using traditional tools, such as spreadsheets. A new generation of advanced analytics applications specially designed to work with time series data empowers engineers and other team members to quickly create insights, and to share the results of their work across the organisation.

7th Opportunity CrudesConference OCT.. 25--27,, 2021 1 | Partt 1—Virtuall

Refining in Transition: Crudes for Fuels & Petrochemicals in Demand

OPEN FOR REGISTRATION Register today to take advantage of the pre-conference discount by visiƟng: hƩps://opportunitycrudes.com/register21.php The urgent tasks of recovering from oil demand destruction due to the coronavirus pandemic have been complicated by oil market volatility and an unsteady fuel rebound in many parts of the world. Meanwhile, persistent climate scrutiny has prompted many refiners to shift their current operations in crude selection and processing. Therefore, we cordially invite you to attend the upcoming two-part Opportunity Crudes Conference: this year's virtual event (via Zoom) on Oct. 25-27 to address impacts and implications surrounding the uncertainties related to the pandemic recovery and increasing calls for decarbonization, and the in-person meeting in Houston, TX (US) on Oct. 24-26, 2022, to validate strategies and technologies during these changing times going forward. In this year's virtual meeting, we have assembled over 20 well-known speakers with hands-on business and technology knowledge, experiences, and insights on how to tackle challenges and gain benefits amid the energy transition centering on four matrices: x

How to stay profitable in an environment of shifting fuel demand and unstable crude prices due to supply dominance by OPEC+ producers; x Ways of decarbonization for meeting targets to reduce greenhouse-gas emissions, e.g., via crude selection and trades based on carbon intensity and carbon taxes, co-processing of conventional oil and biofeeds, and prevention of fouling and corrosion to improve energy efficiency; x Portfolio adjustments to sustain long-term business viability, i.e., balancing between petrochemicals, fuel production, and bitumen asphalt; x Technology solutions to facilitate both business and energy makeovers, i.e., digitalization and IoT innovations, refinery -PC integration, crude-to-chemicals, etc. Visit https://opportunitycrudes.com/agenda21.php to review an agenda of this very timely and focused conference. Our unique virtual event is flexible, letting you enjoy the live event and watch recorded presentations after the meeting at your leisure. It will provide connectivity via town hall meetings to exchange ideas with participating speakers and colleagues from around the world and to share knowledge across the upstream, midstream, and downstream sectors. The conference will also address your needs through pre-submitted questions to speakers.

Register today and join representatives from Alberta Innovates, AVEVA, Baker Hughes, Baker & O'Brien, Becht, Bharat Petroleum, Center for Strategic and International Studies, CHS, Dorf Ketal, CVR Energy, DuPont Clean Technologies, Ecopetrol, Emerson Automation Solutions, Energy Analysis International, Halliburton, Hindustan Petroleum, Intertek, KBR, LyondellBasell, Modcom Systems, Motiva Enterprises, Nalco Champion/Ecolab, Natural Resources Canada, NexantECA, Nynas, OMV Downstream, Petrobras, Schneider Electric, Shell Global Solutions, Shell Oil, Solomon Associates, Suez WTS, TotalEnergies, Upgrading Solutions, Wood Mackenzie, YPF, and more. Attendees and speakers come from around the world: Argentina, Austria, Belgium, Brazil, Canada, Colombia, France, India, the UK, and the US.

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Hydrocarbon Engineering August Issue 2021

Articles inside

Leaks: a costly problem

Easing the fl ow

The case for controlling sulfur impurities

Thriving in the new reality

No smooth sailing on the Gulf Coast

An alternative route

The carbon negatives

Guest comment

Emissions catalyst cleaning – no need to wait for a turnaround

World news

Optimum fl ow technology