Hydrocarbon Engineering - April 2021 by PalladianPublications

April A il 2021

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CONTENTS April 2021 Volume 26 Number 04 ISSN 1468-9340

03 Comment 05 World news 08 Battling the black swan

27 The dew point revolution – more than measurement

Ng Weng Hoong, Contributing Editor, reflects on how the Asian downstream market has been impacted by COVID-19.

Paul Lyon, Maria Chwal, Gleb Derevyagin, and Alexander Derevyagin, Vympel GmbH, Germany, look at the evolution of chilled-mirror analysers, which can help empower end-users in unprecedented ways.

33 Savings through subtle operational

14 Creating order out of chaos Victor Scalco, General Atomics Electromagnetic Systems, USA, clarifies lost profits in a post-pandemic refining industry.

adjustments

Rupam Mukherjee and Shilpa Singh, Engineers India Ltd, India, examine how pre-planned changes in the operation of existing fired heaters can inspire quick savings without any major investment.

39 The details of design David A. G. Suares, Gas Processing Consultant, India, highlights design considerations that need to be considered when flaring ethylene oxide.

43 Delving deeper into wastewater Stan Barskov, Athlon, a Halliburton Service, USA, and Paul Campbell, Aster Bio, USA, discuss using advanced molecular testing to help spot early signs of trouble in activated sludge systems.

49 Navigating the impacts of change Michael Gaura, AMETEK Process Instruments, USA, emphasises the importance of carefully addressing the impacts of changing regulations and feedstocks in sulfur recovery units.

21 No foul, no harm for separation units Claudia von Scala and Thomas Raiser, Sulzer, Switzerland, look at how to address fouling in hydrocarbon manufacturing plants that use bio-resources.

THIS MONTH'S FRONT COVER

55 Sulfur Review Hydrocarbon Engineering presents a selection of sulfur technologies and services currently available to plant and refinery operations.

Accurate quality control measurements of natural gas require technology compatible with evolving infrastructure, the increased injection of hydrogen, and greener alternatives to traditional solutions. As a result, manufacturers oriented to innovation have a clear advantage over their competitors. The products of one supplier, the Vympel Group, are excellent examples of this.

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couple of months ago, BP successfully completed an autonomous vehicle trial at its Lingen refinery in Germany. Working with Oxbotica, an autonomous vehicle software company, the trial was a world first in the energy sector. According to BP, the vehicle travelled over 180 km fully autonomously, safely navigating the complex refinery environment including busy junctions, narrow paths, railway crossings, and multiple terrains, during both day and night and in unpredictable weather conditions. Following the successful trial, BP has said that it now plans to deploy its first autonomous vehicle for monitoring operations at the refinery by the end of the year. The company’s aim is for the vehicles to enhance human operations and improve safety by increasing the monitoring of irregular conditions, faulty equipment and security threats. The trial demonstrates how automation and digitalisation can be used to improve safety, increase efficiency and boost productivity at refineries, all while reducing carbon emissions. It is just one glimpse into what the future may hold for the downstream oil and gas industry. On 5 May, Hydrocarbon Engineering will be hosting its second ‘Refinery of the Future’ virtual conference, which aims to shine the spotlight on other innovative technology that is driving the future of the refining sector, as well as the latest industry developments, forecasts and trends following an unprecedented year. I’m delighted to announce that we have an excellent line-up of speakers, with experts joining us from Wood Mackenzie, Honeywell Forge for Industrial, AFPM, API, and Honeywell UOP. The presentations will cover a range of interesting topics including the recovery of global oil demand following the COVID-19 pandemic, the rise of artificial intelligence (AI) & machine learning (ML), safety & security, and petrochemical integration. In addition to these excellent technical presentations, Refinery of the Future will offer a host of new interactive features for attendees, including live Q&As following each presentation. We will also have a virtual exhibition running alongside the conference, so you can drop by our exhibitor booths to interact with company representatives and get the latest information on their products and services. And just like any physical conference, you will be able to network with your fellow attendees throughout the day by making use of our live chat and video conferencing features. If you haven’t already registered to attend Refinery of the Future, please head over to www.hydrocarbonengineering.com/refinery2021, and sign up to reserve your free space today. If you’re unable to join us live on 5 May, there’s no need to worry. By registering to attend, you will receive a recording of the full conference once the session has closed, so you can catch up with all of the presentations at your leisure. I look forward to seeing you all on 5 May. In the meantime, please enjoy this issue of Hydrocarbon Engineering, which is packed full of articles exploring revolutionary technology for the downstream sector, and insights into the post-pandemic future. HYDROCARBON

ENGINEERING

April 2021

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WORLD NEWS UK | BP

plans UK hydrogen project

P has announced that it is developing plans for the UK’s largest blue hydrogen production facility, targeting 1 GW of hydrogen production by 2030. The project would capture and send for storage up to 2 million tpy of carbon dioxide (CO2), equivalent to capturing the emissions from the heating of 1 million UK households. The proposed development, H2Teesside, would be a significant step in developing BP’s hydrogen business and make a major contribution to the UK government’s target of developing 5 GW of hydrogen production by 2030.

Worldwide |

IEA reports on uncertain future

orld oil markets have rebounded from the massive demand shock triggered by COVID-19 but still face a high degree of uncertainty that is testing the industry as never before, according to a new report from the International Energy Agency (IEA). The forecast for global oil demand has shifted lower, and demand could peak earlier than previously thought if a rising focus by governments on clean energy turns into stronger policies and behavioural changes induced by the pandemic become deeply rooted, according to ‘Oil 2021’, the IEA’s latest annual medium-term

Germany |

With close proximity to North Sea storage sites, pipe corridors and existing operational hydrogen storage and distribution capabilities, the area is uniquely placed for H2Teesside to help lead a low carbon transformation, supporting jobs, regeneration and the revitalisation of the surrounding area. The project’s hydrogen output could provide clean energy to industry and residential homes, be used as a fuel for heavy transport and support the creation of sustainable fuels, including bio and e-fuels.

market report. But in the report’s base case, which reflects current policy settings, oil demand is set to rise to 104 million bpd by 2026, up 4% from 2019 levels. The report notes that the global refining sector is struggling with excess capacity, and suggests shutdowns of at least 6 million bpd will be required to allow utilisation rates to return to normal levels. Meanwhile, the petrochemical industry will continue to lead demand growth, with ethane, LPG and naphtha together accounting for 70% of the forecast increase in oil product demand to 2026.

Total wins LNG bunker supplier license

Singapore |

he Maritime and Port Authority of Singapore (MPA) has awarded a third LNG bunker supplier license to Total’s subsidiary in charge of worldwide bunkering activities, Total Marine Fuels Private Ltd, for a 5-year term starting 1 January 2022. This achievement follows a 10-year agreement signed by Total in 2019 to develop an LNG bunker supply chain in the port of Singapore. It reaffirms the company’s commitment to contribute to the country’s ambition of becoming a key LNG bunkering hub for Asia. It also underscores Total’s confidence in the role of natural gas for the global maritime industry’s energy transition and in its potential to further reduce carbon emissions from ships, through the development and future introduction of carbon-neutral bioLNG. Alexis Vovk, President, Marketing and Services at Total, said: “Asia’s demand for LNG bunkering is growing and the contribution of Singapore is of essence for the development of a global LNG bunkering market. Moving forward, Total will continue to step up investments to bring greater value of our integrated natural gas supply chain to customers serving this important region, ultimately contributing to our target of serving more than 10% of the global LNG bunker market.”

Milestone for OMV and BASF

n collaboration with BASF, OMV has commissioned its new ISO C4 plant at the Burghausen site. The plant is based on a novel technology developed jointly by the two companies and has been producing high-purity isobutene since the end of 2020. The plant’s energy efficiency saves 20 000 tpy of CO2 emissions. Up to

80% of the heating energy required for the new process can be met by thermal discharge from an existing associated facility thanks to a heat integration approach. The energy-efficient process for the production of isobutene, achieving up to 99.9% purity, was developed in cooperation between BASF and OMV, and a worldwide patent application

was filed jointly by the two companies. BASF provides the catalyst and reaction concept that fulfills all process requirements by OMV. The new unit for the production of high-purity isobutene, which does not need chemical conversion of isobutene, has been integrated into the existing metathesis plant at OMV’s Burghausen site. HYDROCARBON

ENGINEERING

April 2021

WORLD NEWS DIARY DATES 12 - 13 April 2021 AFPM Annual Meeting Online afpm.org/events

19 - 30 April 2021 CORROSION 2021 Online nacecorrosion.org

5 May 2021 Refinery of the Future 2021 Online www.hydrocarbonengineering.com/refinery2021

10 - 14 May 2021 RefComm 2021 Online www.refiningcommunity.com/refcomm-2021

30 June 2021 SulfurCon 2021 Online www.hydrocarbonengineering.com/sulfurcon2021

13 - 16 September 2021 Gastech Singapore gastechevent.com

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

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

05 - 07 October 2021

MOL Group starts biofuel production at Danube refinery

Hungary |

ollowing several years of research and development, MOL Group has become a biofuel producer, through the realisation of an investment in the Danube refinery, Budapest, Hungary. Bio-feedstock will be co-processed together with fossil materials, increasing the renewable share of fuels and reducing up to 200 000 tpy of CO2 emissions without negatively affecting fuel quality. During co-processing at the Danube refinery, bio-feedstock is processed together with the fossil material in the production of diesel fuel. Vegetable oils, used cooking oils

Germany |

and animal fats can also be used for this purpose. As a result, the produced gasoil is partly renewable, without any quality changes compared to diesel produced entirely from crude oil. The main advantage of this method is that the resultant biodiesel can be still blended with a maximum 7% of bio-feedstock based fuel, in line with diesel standards, allowing the bio-share of the gasoil to be higher. In the next five years, MOL will spend US$1 billion on new sustainable projects to get closer to its net-zero CO2 emitter goal by 2050.

BASF, SABIC and Linde join forces

ASF, SABIC and Linde have signed a joint agreement to develop and demonstrate solutions for electrically heated steam cracker furnaces. The partners have already jointly worked on concepts to use renewable electricity instead of the fossil fuel gas typically used for the heating process. With this innovative approach focusing on one of the petrochemical industries’ core processes, the parties strive to offer a promising solution to significantly contribute to the reduction of CO2 emissions within the chemical industry.

Steam crackers play a central role in the production of basic chemicals and require a significant amount of energy to break down hydrocarbons into olefins and aromatics. Typically, the reaction is conducted at temperatures of about 850˚C in their furnaces. Today these temperatures are reached by burning fossil fuels. The project aims to reduce the CO2 emissions by powering the process with electricity. By using electricity from renewable sources, the fundamentally new technology has the potential to reduce CO2 emissions by as much as 90%.

AFPM Summit New Orleans, Louisiana, USA afpm.org/events

Canada | Vopak awards contract to SNC-Lavalin

15 - 18 November 2021

ERTC Madrid, Spain www.worldrefiningassociation.com/ERTC-CFP

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

April 2021

HYDROCARBON

ENGINEERING

NC-Lavalin has been awarded a framework contract to provide engineering and consultancy services to Vopak LNG in support of its LNG growth strategy. The framework covers global onshore facilities, marine structures and offshore floating technologies, with SNC-Lavalin delivering a range of services including concept and feasibility studies, engineering for

permitting, environmental assessments, FEED, and owner’s services through execution, commissioning and start-up. Work will be led by global teams and draw expertise from across the SNC-Lavalin Group in engineering disciplines, cost estimating and execution planning, ports and harbours, and permitting and consenting. The contract builds on previous work with Vopak’s LNG team in South East Asia.

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Ng Weng Hoong, Contributing Editor, reflects on how the Asian downstream market has been impacted by COVID-19.

April 2021

HYDROCARBON

ENGINEERING

s the h biggestt b black swan event since the Great Depression nearly a century ago, the COVID-19 pandemic will have a lasting profound impact on the global economy. For Asia’s oil industry, the pandemic has brought about demand destruction as well as the accelerated restructuring of the region’s refining sector. According to the Organization of Petroleum Exporting Countries (OPEC), Asia’s oil demand fell nearly 7.2% from 27.21 million bpd in 2019 to 25.26 million bpd in 2020. It is the Asian oil market’s first contraction since 1998. The pandemic has also boosted the rise of China and India as oil refining centres and product exporters, while hastening the decline of the sector in smaller countries that analysts had been expecting for years. China, the epicentre of the outbreak, has emerged as the world’s only major economy to grow in 2020. Its refiners have continued to expand capacity, partly in response to the government’s push to boost domestic energy security, and partly to take advantage of market conditions. The Indian government has pledged to double the country’s oil refining capacity from around 250 million t to 500 million t by 2030. The growth of the refining industry in both countries will come at the expense of their competitors in countries such as Singapore, Australia, the Philippines and Indonesia. Australia and the Philippines could become the first major economies in Asia to be without an oil refinery, as the industry is on the verge of collapse in both countries. Singapore’s largest refiner, Shell, reduced its 500 000 bpd refining capacity by half late last year to reduce carbon emissions as well as in response to weaker regional demand.

China as a major refined products exporter The world’s largest oil importer wants to become its biggest supplier of refined products. China exported nearly 1.3 million bpd of refined products in 2020, according to preliminary official data from the

country’s Customs department. This puts it within striking distance of Asia’s leading products exporter, South Korea, which shipped out 1.31 million bpd in the first 10 months of 2020, according to energy media Platts. India kept its position as Asia’s third largest products supplier, exporting around 1.13 million bpd, according to the Ministry of Commerce and Industry. Singapore, once Asia’s leading oil products supplier, fell further behind as its refining throughput dropped below 900 00 bpd last year for the first time since 2014. Singapore’s role as a swing products supplier has diminished over the past decade as its refineries are increasingly uncompetitive against mostly state-owned companies in China, India and the Middle East. Chinese refiners expanded their combined capacity to a record 17 million bpd in 2020, collectively making them the world’s second largest after the US, which had just over 18.9 million bpd of capacity at the end of 2019. Analysts expect China to eventually displace the US as the world’s largest producer of oil products later this decade. American refiners are under pressure to reduce both capacity and operations. According to BP, China doubled its refining capacity between 2005 and 2020.

The impact of COVID-19 According to the International Monetary Fund (IMF) and the World Bank, the Chinese economy likely grew by around 2% in 2020 in contrast to the global economy, which shrank by an estimated 4.4% – 5%. Beijing said the Chinese economy grew by 2.3%. Most countries reduced their oil refining operations in response to the collapse in domestic fuels consumption. Already teetering from years of poor performance, some refiners in Asia, the US, and Europe slashed production capacity as well as operations in 2020. China, in contrast, expanded its refining capacity even though the country’s domestic consumption fell by around 1.4% to 14.31 million bpd in 2020, according to the US Energy Information Administration (EIA).

HYDROCARBON

ENGINEERING

April 2021

Unlike other countries, China is also driven by fears of its worsening relationship with the US that includes the possibility of a military conflict. The pandemic has strengthened China’s resolve to boost domestic energy security, which includes expanding its refining sector. The sharp fall in energy prices in 1H20 aided Beijing’s cause, according to official Customs data. Even as it boosted crude oil imports by 7.3% to a record 10.15 million bpd in 2020, China paid nearly 27% less for its purchases compared to 2019. The additional supply mostly went into the country’s expanded storage capacity.

Malaysia faces political instability, fights over oil revenues 30 years ago, the Malaysian government unveiled a grand vision for the country to become a developed economy by 2020. The then Prime Minister, Mahathir Mohamad, targeted the national GDP to grow by an average annual rate of over 7.4% to expand the economy by eight times. He spoke of an innovation-driven industrialised Malaysia that would become less dependent on oil and commodity exports, and a society that would be socially advanced and harmonious. Instead, 2020 turned into a watershed year of catastrophes and growing political instability that continues to threaten the country’s long-term prospects. The economy remains dependent on oil, gas and commodity revenues. It is likely to have shrunk by at least 6% in 2020 for its biggest contraction since 1998, according to both the IMF and the Asian Development Bank (ADB). The COVID-19 pandemic has further weakened the Malaysian economy already affected by years of political infighting and weak oil prices. State energy firm Petronas, which directly provides more than 15% of the government’s revenue, expects to report a record loss for 2020 for its worst performance since founding in 1974. Dragged down by weak oil prices and reduced sales, the company reported a net loss of RM19.9 billion for the first nine months of 2020 compared with an RM36.4 billion net profit for the same period a year ago (US$1 = RM4.02). Given Petronas’ importance to Malaysia, the downgrade of its debt and creditworthiness by Fitch Ratings in December 2020 has sent shock waves across the country. Petronas’s long-term foreign- and local-currency issuer default ratings (IDRs) have fallen to their lowest in years, from A- to BBB+. It means Petronas will have to pay significantly more for its borrowings. Fitch has further warned that Malaysia would suffer “very strong” socio-political repercussions as well as energy security problems should Petronas default on its debts. The mention of default is of great concern to the Malaysian government and the business community as Petronas has long been regarded as being among the world’s best managed state energy firms. “A default would jeopardise Petronas’s ability to undertake upstream oil and gas production, refining, retail distribution of fuel, and gas supply to the power and other industries,” Fitch said. “Investors see Petronas bonds as a proxy for sovereign bonds as the company accounts for a large share of government revenue.” April 2021 10 HYDROCARBON ENGINEERING

Fitch said it expects Petronas to suffer a 40% drop in 2020 pre-tax earnings to RM87.4 billion as a result of the COVID-19 pandemic.

Fights over oil revenues Malaysia’s protracted domestic political infighting is another long-term burden on Petronas’ finances and the economy. As part of a deal to stay in power, Prime Minister Muhyiddin Yasin has yielded to demands by the resource-rich eastern state of Sarawak for a bigger share of oil and gas revenues. Neighbouring state Sabah expects to win similar concessions that will further reduce Petronas’ financial and operating capacity. Muhyiddin Yasin, who only took office in March 2020, needs the support of both states to survive an increasingly bitter struggle for power among the country’s various political factions. Sarawak’s victory over the central government partly contributed to last year’s resignation of Petronas Chief Executive Wan Zulkiflee Wan Ariffin, who had openly opposed the deal. His downfall was also tied to the poor performance of the oil-petrochemical project between Petronas and Saudi Aramco in the southern state of Johor. Touted as Malaysia’s new industrial hub, the US$27 billion downstream complex has become a financial black hole since achieving investment approval in 2014. Its implementation has been dogged by environmental and community protests, operational problems, and poor market conditions. Last March, a major fire and explosion at the site caused the death of at least five workers, further adding to the project’s cost and start-up delay.

Australia’s oil refining industry faces collapse Australia could become the world’s first major economy to be without an oil refinery as the industry faces a complete wipeout from mounting financial losses. Australia will be left with three small, decades-old refineries by the end of 1Q21 when BP shuts down its 148 000 bpd Kwinana plant in Western Australia state. BP said it will convert the Kwinana site into a logistics terminal to import, store and distribute fuels to meet the demand of domestic consumers. “Regional oversupply and sustained low refining margins mean the Kwinana refinery is no longer economically viable. Having explored multiple possibilities for the refinery’s future, BP has concluded that conversion to an import terminal is the best option,” the company said in a statement. Esso, Caltex and Viva Energy have warned that their refineries, with a combined capacity of around 317 000 bpd, are also at risk of closure. They, too, could become terminal operators and fuel importers. All four refiners expect to suffer record losses in 2020 from the continuing onslaught of falling domestic oil consumption, declining margins and competition from rising fuel imports. With the BP plant closure, Australia could also set an unwanted world record for the fastest collapse of any

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country’s oil refining industry. In 2011, it had seven refineries with a combined capacity of 790 000 bpd. Australia’s refining industry has been on the ropes for most of this century, its likely demise foretold in a parliamentary report from the House of Representatives in 2012: “Recent and impending closures of oil refineries in Australia have raised concerns about the viability of Australia’s oil refinery industry.” It warned that Australian refiners could no longer compete against their rivals in Asia and the Middle East which have built newer, larger and more sophisticated plants since the late 1990s. “Australia’s oil refineries are at a competitive disadvantage in the region. Decisions to close selected refineries have been based on commercial considerations, as some have been operating at a loss,” the report said of the industry’s impending fate. “As a result, the trend has been to move away from domestic refining to a greater dependence on liquid fuel imports. This will include converting selected domestic refineries to import terminals.” Within three years of the report’s release, Caltex, Shell and BP each closed down a refinery for a combined loss of 330 000 bpd of capacity.

total shutdown, the country would become entirely dependent on imported fuels. Australia’s economy is expected to shrink by more than 5% in 2020, due mostly to the COVID-19 pandemic, said the Reserve Bank of Australia. This will cause domestic oil consumption to fall below the 1 million bpd mark for the first time since 2016. In 2019, Australians consumed 1.046 million bpd of oil, down nearly 0.9% from the previous year.

The Philippines’ only refinery on the brink

The Philippines’ oil refining industry will be extinct if Petron Corp. closes down the country’s remaining plant. The company’s President, Ramon Ang, has complained of mounting losses from operating the 180 000 bpd refinery at Bataan on Luzon island since the start of the pandemic in 1Q20. Briefing the media in October 2020, he stated that “an uneven playing field” had contributed to the company’s financial losses. Petron is expected to seek substantial financial and tax relief from the government to continue operating its refinery to serve the country’s nearly 110 million people. As in other countries, energy consumption has also fallen sharply in the Philippines. The ADB has forecast the nation’s COVID-19’s death blow economy to contract by a record 7.3% in 2020. The loss of those refineries on the heels of the report fired up In August, Pilipinas Shell, a subsidiary of the a decade-long national debate about Australia’s declining Anglo-Dutch major, said it would permanently shut down its energy security. The debate is still far from settled. 110 000 bpd refinery in Batangas City, located south of the The International Energy Agency (IEA) has repeatedly capital of Manila. Citing “demand destruction” from the stated that Australia has not been doing enough to boost its pandemic, the company’s President and CEO, Cesar Romero, national emergency oil stockpile. For almost a decade, it has announced the closure of what used to be the Philippines’ hovered between 55 and 80 days of supply to meet domestic second largest oil refinery which started up in 1962. “It is no demand, well below the 90-day level required by the IEA. longer economically viable for us to run the refinery. It is The impending loss of the BP refinery will make it even with a heavy heart that we announce the cessation of oil harder for Australia to reach that elusive 90-day stockpile refining activities,” he said in a statement. target. In the extreme but now likely scenario of the industry’s The company plans to convert the site into a terminal to import, store and distribute fuels. It will follow the path set by other refiners in Asia and Table 1. Australia’s oil refineries Australia that have shut down fuels production Refiner Location State Capacity Status in favour of a role in logistics. (bpd) Pilipinas Shell said the move will enable the Viva Geelong Victoria 129 000 Operating company to optimise the use of its assets to Energy “enhance cost and supply-chain Caltex Lytton, Queensland 108 000 Operating competitiveness.” Brisbane Shell’s decision likely triggered Petron’s Esso Altona, Victoria 80 000 Operating complaint about the “uneven playing field” in Melbourne the country’s downstream oil market. BP Kwinana Western 143 000 Closing 1Q21 According to BP, the Philippines’ oil Australia consumption reached a record 458 000 bpd in Total 460 000 2019, having grown by an average annual rate of Australia more than 4.5% over the decade. BP

Bulwer Island, Brisbane

Queensland

109 000

Closed January 2015

Caltex

Kurnell, Sydney

New South Wales

135 000

Closed October 2014

Shell

Clyde, Sydney New South Wales

86 000

Closed September 2012

Total closed

April 2021 12 HYDROCARBON ENGINEERING

330 000

Singapore-Philippines joint venture to acquire storage and pipeline firm A joint venture firm led by a subsidiary of Singapore’s Keppel Corp. will acquire the Philippines’ largest petroleum storage facility for US$267 million.

Keppel Infrastructure Fund (KIT) said it and the Philippine’s Metro Pacific Investments Corp. (MPIC) expect to complete the deal by early 2021, with the Singapore firm owning an 80% share in the joint venture. The partners will acquire Philippine Tank Storage International (Holdings) Inc. (PTSI), which owns Philippine Coastal Storage & Pipeline Corp. (PCSPC) that operates the country’s largest petroleum products logistics facility. PCSPC’s assets include three tank farms and a marine terminal area on a 150 ha. site in the Subic Bay Freeport Zone. The company plays a key role in importing, storing and distributing petroleum products to the Metro Manila area as well as Luzon island, which accounts for more than half of the country’s oil products demand. Located in a sheltered deepwater harbour, the tax-friendly Subic Bay Freeport Zone facilitates the berthing of specialised vessels and petroleum tankers throughout the year. In a statement, KIT said PCSPC is converting and upgrading some of its tanks. When completed in early 2021, the terminal will have 86 tanks with a combined storage capacity of approximately 6 million bbl or about 36% of the country’s total. “PCSPC presents an attractive opportunity for KIT to capture opportunities arising from the strong macroeconomic outlook as well as robust growth fundamentals for imported petroleum products in the Philippines,” said Matthew Pollard, CEO of Keppel Infrastructure Fund Management.

Japan’s Eneos to restructure Osaka and Chiba refineries In response to Japan’s declining domestic oil consumption, the country’s largest downstream company, Eneos Holdings, has announced a restructuring of the ownership and operations of two of its refineries. The 115 000 bpd refinery in Osaka is being converted into an asphalt-fuelled electric power facility, while the 129 000 bpd Chiba plant will focus on exporting refined products to markets in the Asia Pacific region. In 2010, Eneos and Chinese state firm PetroChina established a 51/49 joint venture to operate the two refineries for 10 years. Following the agreement’s recent expiry, Eneos said it will become the sole operator of the new power facility in Osaka. As for the Chiba refinery, Eneos transferred its 51% stake to the Osaka International Refining Co. (OIREC) in December. OIREC was jointly established in October 2010 by Eneos and PetroChina International (Japan) Co. Ltd, a subsidiary of the Chinese state firm PetroChina. Until recently, Eneos’s 11 plants accounted for nearly 55% of Japan’s 3.52 million bpd of refining capacity. The company, known previously as JXTG, said it plans to become a “low-carbon energy supplier” to prepare for Japan’s declining oil consumption on account of the country’s shrinking, ageing population, and sluggish economy. Japan’s oil demand is likely to have fallen further in 2020 to reach a 50-year low. According to BP, Japan consumed 3.812 million bpd of oil in 2019, compared with 3.876 million bpd in 1970.

April 2021 14 HYDROCARBON ENGINEERING

Victor Scalco, General Atomics Electromagnetic Systems, USA, clarifies lost profits in a post-pandemic refining industry.

t the beginning of 2020, the refining industry anticipated a year of profitability, with projects expected to support refinery expansions, upgrades and new grass root efforts. However, the global COVID-19 pandemic introduced an unseen assailant on the industry worldwide, with its effect on oil and gas production still reverberating throughout the refining community today.

The pandemic’s ripple effect Despite the fact that global oil prices closed at averages of US$51/bbl in 2020, the year remained one of volatility, spurred on by countries adopting climate change policies to limit carbon emissions as well as the growing global pandemic crisis. In April 2020, US crude plunged deep into negative territory, and Brent dropped below US$20/bbl. During the following months, the refining industry desperately tried to reinvent itself as the pandemic destroyed fuel demand, exposing an unforeseen future reality of a world operating with a much lower hydrocarbon dependency. The reality is that there is still a high probability that hydrocarbon production in the coming years could remain weak as recovery efforts from the pandemic begin to take hold.1 It is therefore essential for today’s modern refineries to increase their opportunities in order to remain profitable and in the black. Reducing lost profits from the refinery process and investing in more efficient technologies that improve profitability is of the utmost urgency as the industry moves into post-virus stability. Even before the events of 2020, a major topic of concern was the impending implementation of IMO 2020, a marine fuel regulation mandating the reduction of sulfur content to a maximum of 0.5% and total ash to below 60 ppm. Although the IMO 2020 regulation was not fully enforceable due to the effects of the global pandemic, it has had an impact on refiners who are no longer working at peak capacity, are unable to make the investment in fuel oil, or have been forced to close their facilities altogether. During the post-pandemic shift, it is important for refineries to evaluate key technologies in order to become more sustainable, target new market opportunities, and reduce operating costs to ensure lost revenue can be obtained by the most efficient processes possible. Supply and demand cycles are different now: lack of demand, accompanied by refineries operating significantly below peak capacity, is delaying turnaround periods and postponing planned facility upgrade activities. Delaying these projects directly affects future profits and operating growth, particularly if key enabling technology improvements are neglected as a result of the pandemic.1

A shifting world stage Saudi Arabia’s leading position on the world’s oil and gas stage needs no introduction. The country’s decision to cut oil production and postpone expansion projects into 2021 reflects expectations for demand to weaken further as business operations across the globe continue to be impacted by the pandemic crisis. Reducing waste and stabilising profits from key refining assets is paramount and are the only actualities that can support positive growth in 2021.2

HYDROCARBON 15

ENGINEERING

April 2021

Table 1. Feedstock properties Clarified slurry oil (CSO) market

CSO clarity (ppm)

Carbon black feedstock

100 – 500

Refinery fuel

50 – 150

Marine fuel

50 – 100

Pitch feedstock

25 – 100

Needle coke feedstock

25 – 100

Hydrotreater feedstock

10 – 50

Carbon fibre feedstock

5 – 10

Figure 1. Over 750 000 bpd of slurry is made worldwide.

Before the pandemic, India was adding to overall capacity, accounting for 15% of the total expansion in the Asia-Pacific market. Besides building primary distillation capacity, Asia-Pacific refiners invested heavily in catalytic cracking, hydrocracking, and petrochemical production. The apparent growth in petrochemicals and the utilisation of refined products is expected to support profitability in the post-pandemic Asia-Pacific market. National oil companies in China and India are revisiting plans to expand refining capacities from earlier mandates prior to the outbreak. On the other hand, Japanese refiners appear to be heading into a second round of capacity reductions.3 Overall, the long-term transition from fuel to petrochemicals appears to be heading in the right direction in order for the market to remain strong. The route for middle distillate conversion to chemicals with existing technologies is challenging, however, and technology improvements are required to support this transition. Furthermore, long-term demand and uncertainty concerning middle distillates are being influenced by the effects of the COVID-19 pandemic. This long-term drive for petrochemicals will increase the use of catalytic cracking, resulting in increased slurry make and loss revenue if not addressed by applying the right separation technologies today.

The answer is in the reactor The first commercial fluidised catalytic cracker (FCC) was introduced 70 years ago. In order to keep FCC technology evolving and current, a continuous string of mechanical April 2021 16 HYDROCARBON ENGINEERING

and catalyst improvements have been implemented in response to factors such as degradation in feedstocks, the need for product quality improvement, petrochemical drivers, and environmental pressures. In many cases, improved catalysts have led to innovation, such as the advent of zeolites, which have also led to the implementation of riser cracking. Moreover, catalyst advances led to improved selectivity, to allow for more and heavier feed processing in a refinery. This selectivity and the reduced demand for fuel oil has allowed operators to increase the amount of residual oil going to the FCC. Two examples of technology improvements the refiner can use to dig deeper into the crude barrel are catalyst coolers that can be incorporated into FCC regenerators, and highly selective catalysts with the ability to provide high conversions with reduced coke. As refiners introduce larger quantities of residual into the FCC, slurry oil yields increase and the quality of the slurry oil decreases due to a larger proportion of asphaltenes and heteroatoms entering the FCC. This is relevant because the level of asphaltenes in the slurry oil becomes a factor in deciding which technology is best for removing particulate solids. Asphaltenes are the most hydrogen deficient constituents of slurry oil. They become more active and react with one another at higher temperatures to form coke, especially in the presence of metal surfaces. To minimise downstream processing difficulties, the removal of the contained catalyst will keep diluted solids below recommended concentration levels.

Slurry oil yields and properties Slurry oil yields differ in each FCC operation. Complex refineries are able to reduce slurry generation to below 4% of the FCC yield for petrochemical production. As a transportation fuel, FCC can see yields as high as 12%. Regardless of the percentage of slurry, if not handled properly, there is profit loss and waste to be disposed of. Generally, refineries can mix slurry into heavy fuel oil as a viscosity cutter. Slurry oil’s low API gravity, however, limits how much can be blended.4

Clarified slurry oil applications and markets The use of slurry oil as cutter stock for heavy fuel oil blending has also historically been a major outlet for slurry oil. However, trace metals deposited on FCC catalysts, such as nickel, vanadium, and sodium, or adhering to catalyst particles and FCC catalysts themselves, which contain aluminium and silicon as major components, can combine with other elements to form high melting point compounds that are corrosive to valve seats and exhaust valves in diesel engines. Solids contents for marine and refinery use in the range of 50 – 150 ppmw are generally permissible.5 Beyond fuel use, clarified slurry oil (CSO) is also sold to make carbon black, which is used in automobile tyres, belts, hoses and pigments, etc. The carbon black industry has always used slurry oil as feedstock (carbon black feedstock – CBFS), but this activity is seen more so in the Asia-Pacific

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region than North America. Typical CBFS properties are given in Table 1. The worldwide consumption of CBFS is approximately 130 000 bpd, with most of the market focused on the highly profitable low ash speciality grades. CBFS has a high density, and in order to obtain this desired density, high temperatures are required, meaning that special attention needs to be paid to the FCC fractionator operation. Although refiners are not always able to reach the required slurry oil density for carbon black applications, specialised separation equipment can be used to meet the less than 50 ppm catalyst fines requirement and help realise greater profits. Some refiners increase their slurry consumption in order to increase value in process streams in hydroprocessing assets by feeding CSO to hydroprocessing, primarily for hydrocracking or severe hydrotreating. Slurry oil solids contents should be reduced to very low levels to prevent operational disruption. Downflow packed bed reactors will accumulate particulates near the entrance of the reactor that will eventually bridge the hydroprocessing catalyst

Figure 2. 2000 ppm main column bottom catalyst

fines viewed through a scanning electron microscope. Average particle size is 60% under 15 μm.

Figure 3. Electrostatic separation.

April 2021 18 HYDROCARBON ENGINEERING

particles and cause plugging and premature shutdown. Reactors operating in trickle flow do not have the velocity to carry catalyst particles through the packed bed.5

Separation technology of today Catalyst particles (ash) are a particular problem for slurry, especially for low API and viscous oils that require long residence time to allow for catalyst settling. Obtaining low ash (less than 0.05 wt%) requires special techniques, such as heating, chemical additives, filters, electrostatic precipitators, centrifuges, and cyclones. Selecting an attrition-resistant catalyst helps to a great extent, and a few refiners buy higher-priced hard catalysts to alleviate ash problems in slurry oil.5 Historically, holding tanks are used to allow solids to settle out of the slurry oil. Many refiners ‘de-ash’ with chemical settling aids, which accelerate ash settling in storage. These chemicals are polymeric compounds that adhere to the catalyst surface, causing an agglomeration of the fine particles in order to accelerate separation. Sludge from slurry oil holding tanks in most countries is listed as a hazardous waste. Frequent cleaning of settling tanks is required and is expensive. Depending on the tank size and rate of slurry oil production, estimated cleaning costs range from US$1 – US$4 million per cleaning. In the absence of countermeasures, increasing residual feed to the FCC tends to increase the rate of slurry oil production and sludge formation rate.5 The first membrane filters entered the slurry oil service market in 1990, and use different techniques. Electrostatic precipitators are routinely used to remove catalyst fines from the FCC stack and a similar principle is used for the removal of solids from liquids in an electrostatic slurry separator. Gulftronic® Electrostatic separation of FCC catalyst fines from slurry oil has been in commercial operation for over 30 years. The technology has continuously been improved to offer a more robust, automatic process to remove catalyst fines from slurry oil or other hydrocarbon streams using di-electrophoresis. Electrostatic separation is capable of capturing sub-micron catalyst fines, while other technologies are limited to the size of the particle captured, typically over 15 μm.3 Unique to electrostatic separation technology is the ability to backflush with raw feed or vacuum gas oil. This increases the middle distillate production and reduces loss from decreased reactor productivity. The technology is not affected by the presence of asphaltenes, making it an excellent choice for removing solids not only from residual FCC derived slurry oil but also from gas oil crackers. Electrostatic separation operating efficiently is impervious to plugging from asphaltenes and waxes, significantly reducing downtime and annual maintenance costs. The efficiency offered by electrostatic separation technology, coupled with reduced costs, has a direct effect on a refinery’s bottom line and profit margins.

Table 2. Other profitability from the electrostatic separator Electrostatic separator

Mechanical filtration

~ Gulftronic economic value

Comments

Heavy cycle oil (HCO) back flush medium impact

0 bbl/stream day (raw feed back flush)

3200 bbl/stream day (slurry) * 4% = 128 bbl/stream day (HCO) * 365 days * US$43 = US$2 008 960 costs

US$2 008 960/yr savings

Gulftronic Electrostatic Separator allows this saving by using raw feed or vacuum gas oil (VGO) as backflush medium

FCC overall production yield impact

0 bbl/stream day displacement of FCC feed with HCO

(3200 bbl/stream day) HCO backflush will have an impact of - 2% on overall production yield (US$2 569 600)

US$2 569 600/yr savings by eliminating HCO yield impact

64 bbl/stream day * 365 * US$110/bbl, conversion lost production

Market ‘conversion’ impact

Increased sub-micron removal: instantaneous

3 months off-spec product to develop cake (initial commissioning and every time the filter has to be taken offline for repair – average 1 month per year). Quantifiable to US$3 456 000/yr

US$3 456 000/ yr increased revenue from clarified slurry oil (CSO) market (numbers for first year only)

US$12/bbl * 3200 bbl/stream day (slurry) * 90 days

The economics of making the right choice The following example demonstrates the value that can be generated by using electrostatic separation methods in removing FCC catalyst fines from slurry oil. An 80 000 bpd gas oil FCC unit had a slurry oil yield of 4 vol.%, or 3200 bpd. The catalyst content of the slurry oil was 2000 ppm. This was compared against the base case in which the refinery used a holding tank to reduce its solids. The slurry oil holding tank was assumed to require cleaning once per year at 2000 ppm slurry solids at a cost of

US$1.5 million. Increased catalyst loads incur higher frequency slurry holding tank cleaning and total costs. A portion of the FCC feed was used to backwash the electrostatic separator after which it, and the associated catalyst, were fed back to the FCCU, thus reducing fresh FCC catalyst costs. FCC catalyst costs were assumed to range from US$2000 to US$5000/t. It was estimated that the average product upgrade value for this CSO could be between US$2 – US$4/bbl. Benefits from not having to purchase chemical settling aids were not considered even though such costs are estimated to be in the order of

US$45 000/yr. A basic case of slurry-to-bunker fuel specifications with a minimal uplift of US$2/bbl were presented, along with one case for recovering 4000 ppm of catalyst with US$4/bbl uplift. Profits from the use of an electrostatic separator can range from approximately US$4.5 to US$11 million/yr. Without the proper technology installed in this process, the reality is a true loss to the refiner.5 An electrostatic separator removes more than 99% of the catalyst from the slurry to give a CSO product containing less than 50 ppm of FCC catalyst. Catalyst savings might not be as valuable for a residual unit, but would still be significant. Individual cases involving deep residual cracking benefits would have to be calculated based on a thorough knowledge of the residue fluid catalytic cracking (RFCC) feed, operating conditions, catalyst characteristics, etc. It is important to note that smaller catalyst particles returned to the unit have an inherently larger surface to volume ratio and could have a considerably higher residual cracking activity than the larger equilibrium catalyst held in the unit. With the increased focus on petrochemical production to increase profits, the right technology to increase the value of slurry is the key to survival. The bottom line is greater profit from the bottom of the barrel, even in a post-pandemic reality.3

Out of the chaos comes value Of all the many challenges the world refining industry has experienced since the early 1900s, the long-term effects of recent climate initiatives and the COVID-19 pandemic have by far created the highest level of uncertainty in the market today and for the near future.

The downstream industry needs to find new ways to return profit and maintain on-specification product. Whether it is providing highly valuable CBFS or meeting the new IMO 2020 mandate for marine fuel at less than 60 ppm ash, the removal of FCC slurry oil solids to low levels presents an opportunity for improved profitability for refiners. The ability to clarify slurry oil for use in higher value applications, yielding over US$4/bbl or eliminating the need for the disposal of hazardous waste from a sludge in a holding tank, supports the drive to stabilising and improving a refinery’s bottom line. The upheaval brought about by recent events has opened the door to new opportunities for the industry to initiate changes to weather an uncertain future. Fossil fuel is an integral part of the global economy and continues to contribute strongly to the world’s economies and a daily way of life. The refining industry must continue to seek ways to innovate, evolve and prepare to meet the challenges in the years ahead. The first step is to invest in the right technology to increase refining capabilities to ensure a return to profitability in a post-pandemic reality.

References 1.

2. 3. 4.

RUSSO, R., ‘Pandemic hastens threat of closure for struggling oil refineries,’ Hydrocarbon Processing report, (8 January 2021). ‘A historic oil price collapse, with worries headed into 2021,’ Reuters, (29 December 2020). SCALCO, V., ‘The plight of the modern refinery: Racing to meet IMO 2020 regulations,’ Hydrocarbon Processing, (12 December 2019). ’Methodology and Specifications Guide, Petroleum Product & Gas Liquids: US Caribbean and Latin America’, S&P Global Platts, (January 2012). GUERCIO, V. J., ‘US Producing, exporting more slurry oil,’ Oil & Gas Journal, (4 October 2010).

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Claudia von Scala and Thomas Raiser, Sulzer, Switzerland, look at how to address fouling in hydrocarbon manufacturing plants that use bio-resources.

he raw materials used in bio-based hydrocarbon manufacturing plants, such as biorefineries, tend to cause fouling in separation units, affecting the equipment’s performance. Production facilities can take a number of preventative measures to alleviate this, such as selecting the right

column internals. These are key to minimising fouling and optimising operations, leading to continuous, reliable and high-performance purification processes. The build-up of unwanted deposits on the internal surfaces of separation units is common in a wide range of manufacturing activities. However, this phenomenon HYDROCARBON 21

ENGINEERING

April 2021

can be prevented to minimise – or even eliminate – any potential disruption to production. By doing so, businesses can maintain peak flux, throughput, capacity and efficiency. Furthermore, it is possible to maximise uptime and equipment service life while decreasing both capital and running costs. Reducing the likelihood and occurrence of fouling requires an in-depth, holistic understanding of the specific separation process, feed and components used. In effect, this event is caused by a complex interplay of chemical systems, material used within the unit, operating conditions, as well as the specific geometry of the internals utilised.1 Therefore, to effectively address any malfunctioning of columns, internals and processes due to fouling degradation, manufacturers need to be able to pinpoint the mechanisms behind fouling in their applications. Closely collaborating with a skilled mass transfer expert that has experience with such systems can help to determine what leads to fouling in a specific application.

Figure 1. UFM™ AF tray deck.

Figure 2. VG™ AF trays.

April 2021 22 HYDROCARBON ENGINEERING

Fouling causes in bio-based material manufacturing Some common physical and chemical changes that facilitate the formation of deposits involve phase separation and solidification, which tend to sediment on surfaces. Key mechanisms include the vaporisation of volatile components such as solvents, polymerisation, coking (or thermal cracking), condensation, sedimentation, crystallisation, precipitation and supersaturation. Furthermore, supersaturation can be caused by the evaporation of solvents, cooling of the feed below the solubility limit or heating above the solubility limit of solutions with inverse solubility. The mix of streams with different compositions or pH variations are also possible origins. In addition to this, foaming in separation units can contribute to fouling if solid particles are entrained in the foam. In biofuel and biochemical production, the raw materials used can often act as foulants. For example, in facilities that use crops or plant-based biomass, key materials that can cause deposits include organic carbohydrates such as polysaccharides, lignin, proteins, and extractives such as phenolic compounds, aromatic carboxyl acids and fatty acids. Similarly, manufacturing activities that rely on microbial fermentation can form biofilms that can occlude key surfaces in separation units. Therefore, companies seeking to prevent this issue and maintain high-performance processes should first look at reducing the ingress of these kinds of impurities into the separation unit. This can be achieved by setting up filtration stages prior to the actual purification train.

Select the optimum tray design While this pre-treatment is a highly effective solution to help reduce fouling, it cannot remove all foulants present in the feed, as some are not solids until they form in the separation unit. Therefore, additional measures should be considered by manufacturers of bio-based materials to further prevent the occurrence of this phenomenon. In particular, it is important to select pieces of equipment that have been designed for fouling services. This means choosing solutions that are both resistant and tolerant to this issue. While resistance can prevent or reduce fouling itself, tolerance allows the internals to sustain a certain amount of material deposition without a corresponding reduction in its performance, efficiency, throughput or capacity. Another important factor to be considered is the easiness for cleaning. For example, trays are easier to clean with a water jet compared to structured packing. The first aspect to consider is the material used. In particular, electro-polished surfaces on column internals are extremely smooth, thus limiting the ability of fouling materials to stick to them. Secondly, the mechanical and hydraulic design of internals is crucial. Typical fouling-resistant components feature large openings that allow any foulant to pass through the unit without accumulating. Examples of such designs include baffle and dual flow trays, as well as grid structured packing.

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An additional element that can contribute to enhanced resistance to fouling, while also improving the system’s tolerance, is the use of elevated orifices, such as fixed valves and tabs. In these designs, the openings are distanced from the tray deck, where particles may deposit, allowing the efficient and effective separation of bio-based materials. UFMTM AF valves are an example of such devices (see Figure 1).

Another working example of this solution is provided by Sulzer’s V-Grid range of large valves.2 Their openings are characterised by a large, elevated trapezoidal shape. Additionally, their design promotes lateral vapour release, which induces a cleaning action on the tray deck that removes deposits. The XVGTM valve type has also been successfully applied to a beer column in an ethanol manufacturing plant, where it was key to reducing downtime associated with column cleaning. In particular, the plant was able to extend the intervals between shutdowns from every few weeks to less than once a year. Figure 2 shows a VGTM AF tray deck with XVG valves. To further strengthen the internals, it is also possible to include push valves and a stepped outlet weir. The first makes the liquids and solids move uniformly across the tray deck, while the second prevents the accumulation of solid particles at the end of the tray deck.

Identify the right packing

Figure 3. Mellagrid™ 40 AF.

Figure 4. Mellapak™ structured packing.

Figure 5. Installation of Mellapak.

April 2021 24 HYDROCARBON ENGINEERING

When it comes to packed beds, the large openings of structured, grid-based systems are ideal. They are also characterised by low surface areas, which make the entire packing surface wet, preventing solids from drying on the surface of the structured packing (see Figure 3). In addition to this, the design of the liquid distributor in packed columns plays a key role in preventing and mitigating fouling. A suitable technology, such as Sulzer’s splash plate distributor VEP, is characterised by elevated orifices to allow solids to settle at the bottom of the troughs without obstructing these orifices. Furthermore, the presence of side orifices with splash baffles creates a more homogeneous distribution of the liquid and avoids the creation of dry areas. Finally, specialised parting boxes on the liquid distributor prevent the formation of liquid dead zones, which could induce unwanted polymerisation within the distributor. When looking at column packing, the typical surface of structured packing has a fine structure to promote the spreading of the liquid on the packing surface, ensuring a good mass transfer between the liquid and the gas phases (see Figure 4, MellapakTM, and Figure 5, installation of Mellapak). This roughness, however, can promote fouling, and therefore the packing surface should be adapted to have a structure that enhances wettability while reducing fouling. To complement these well-established column internals, which are used for fouling services in a wide range of industries, innovative technologies that address the specific needs of bio-based product manufacturers are being developed. These are designed to enable companies to benefit from comprehensive high-performance systems. For example, Sulzer has recently adapted a structured packing that minimises biofouling. This is extremely beneficial in heat-integrated distillation and dehydration plants, which turns carbon-rich industrial emissions into bioethanol fuels. These require special operating conditions and a suitable system to extract the diluted biofuel after the bacterial metabolic process while avoiding the formation of biofilms onto the processing equipment.

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In facilities experiencing extreme fouling, companies can also look at adding anti-foulants. These can act in a different way. For instance, they may inhibit polymerisation or the formation of corrosion products. The selection of the most suitable inhibitor depends on the specific mechanisms behind fouling in a given application. Along with fouling, manufacturers of bio-based materials are particularly exposed to foaming, which can promote the deposition of solid particles. In particular, bioethanol fermentation processes produce large quantities of carbon dioxide that form bubbles when the liquid becomes saturated and froth the feed. In these situations, it is important to look for column internals that minimise the foaming and to equip the separation units with foam breakers. These include anti-foaming agents or mechanical components, such as feed devices with centrifugal separators or shower valves installed above liquid surfaces. Moreover, freeing the headspace in the top section of columns can reduce the likelihood of foam formation. A common example of fouling coupled with foaming is encountered in beer columns in first- and second-generation bioethanol plants, where ethanol and water are separated from fermentation broth. These pieces of equipment can experience plugging issues, requiring plant operators to set up periodic cleaning-in-place shutdowns. Specially developed anti-fouling trays have been proven to minimise the need for regular cleaning. In addition to the selection of suitable separation equipment, it is also essential to define optimum operating conditions. These can greatly contribute to the prevention or minimisation of fouling and foaming phenomena as well as maximise productivity. Key parameters to consider include vacuum conditions, turbulence levels within the unit, process temperatures and any thermal variation. While fouling is a common challenge for manufacturers of bio-based materials, there are a number of elements that can successfully help them address this issue while maintaining peak performance in their separation units. By working together with a leading separation technology specialist, companies can rely on a partner that can develop highly effective systems that minimise or eliminate fouling while providing a robust setup able to withstand harsh operating conditions. Such an expert can also provide assistance in fine-tuning processes and equipment to maximise the end result. Ultimately, manufacturers can leverage these solutions to efficiently deliver high-quality products and enhance their competitiveness in the market.

References 1. 2.

PILLING, M., ‘Dealing with column fouling,’ PTQ, (Q1 2016). SUMMERS, D., ‘Experiences in Severe Fouling Service,’ Sulzer Chemtech USA, Inc, presented at the AIChE Spring National Meeting, (8 April 2008) New Orleans, Louisiana, US.

Paul Lyon, Maria Chwal, Gleb Derevyagin, and Alexander Derevyagin, Vympel GmbH, Germany, look at the evolution of chilled-mirror analysers, which can help empower end-users in unprecedented ways.

t is not possible to imagine life in the modern world without electronics. One of the hallmarks of modern electronics is their rapid development. An obvious example of this is the amazingly fast evolution of the mobile phone. In just a few years, it has been transformed from a simple telephone to a powerful handheld device that has many functions, only one of which is a telephone. But the difference between, for example, a ‘clamshell’ phone and a smart phone, involves more than just added functionality. It is a case of new technology sweeping away limitations and empowering the user in ways that were inconceivable before this technology was available. There have been similar, though perhaps less visible, revolutionary developments in other fields as well. One example of this is in the technology used to monitor the quality of natural gas; specifically, in the chilled-mirror technology employed to measure the water dew point and the hydrocarbon condensation temperature. As is the case with the smart phone, the evolution of an established technology has eliminated barriers and given end-users new solutions that were previously unimaginable.

Products such as Vympel’s chilled-mirror analysers not only remove a number of limitations compared to analysers employing older technology, but they also empower end-users in unprecedented ways. To fully appreciate the paradigm shift these instruments represent, it is necessary to briefly revisit the basics of chilled mirror technology. In a manner that is reminiscent of the way that water droplets collect on the outside of a cold drink, a chilled-mirror analyser uses a temperature-controlled surface, the mirror, that can be heated and cooled at will to cause condensation to collect in order to establish the dew point temperature. Traditionally this mirror has been made of polished stainless steel. In order to automate this technology, a light source (LED) and a photodiode are added. The light from the LED reflects from the mirror onto the photodiode. To find the water dew point (WDP) in natural gas, the mirror is cooled under control. When water droplets form on the mirror, some of the light is scattered. The reduction in the amount of light reaching the photodiode through scattering is used to determine the dew point temperature. HYDROCARBON 27

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is why chilled-mirror analysers have remained largely unchanged for decades.

From innovation to revolution

Figure 1. Water condensation.

Figure 2. Hydrocarbon condensation. However, that is all that these analysers can do, and they have some inherent limitations in terms of accuracy and measurement certainty. For one thing, registering the dew point based on an arbitrary definition of the difference between some light and less light is not ideal. The sensitivity of these analysers can vary widely. In addition, this type of device cannot measure the hydrocarbon condensation temperature (HCT), which is also a critical parameter. In order to measure the HCT, the analyser must be altered. Due to the fact that hydrocarbons condense to form a reflective film, the ‘mirror’ has a matte surface, as opposed to being highly polished. In this configuration, the amount of reflected light reaching the photodiode starts off relatively low. When hydrocarbons condense to form a reflective film, the amount of light reaching the photodiode increases and the temperature at which this happens is registered as the HCT. But here again it is a difference between some light and some more light. Likewise, the device is limited to this one measurement. In both of these cases, one could imagine the situation as being akin to raising or lowering the amount of light using a dimmer. This type of instrument may seem old-fashioned, but it has the great advantage of offering a first principle measurement. By measuring the dew point temperature in this way, a physical property of the gas is being registered directly. All other technologies require some type of calculation or conversion from some secondary phenomenon. Perhaps that April 2021 28 HYDROCARBON ENGINEERING

Now, however, there is a new understanding of what a chilled-mirror analyser should be. The revolutionary nature of these new analysers lies in the way that essential components have been reconceived using state-of-the-art materials. Instead of polished steel, the mirror is made of a dielectric material. The light source is a polarised laser instead of an LED, and the new analyser has three photodiodes rather than just one. Individually, these changes would be enough to represent a new generation of technology, but taken together, they fundamentally change the nature of this type of analyser. With a polarised laser as the light source and a mirror made of dialectric material, it is possible to orient these two components so that the laser strikes the mirror in such a way as to achieve the phenomenon of total refraction. In other words, when positioned at a very specific angle, virtually all of the light hitting the mirror is refracted into it. As a result, none of the light is reflected or scattered. Consequently, no light reaches any of the photodiodes. This creates a situation where any light reaching a photodiode will register as either water or hydrocarbon condensation. In this case, the situation is more akin to turning a light on and off with a switch, rather than raising or lowering the amount of light with a dimmer. It is a qualitative change in the way that light is used to register condensation on the mirror. These innovations reduce uncertainty, and make possible a significant increase in sensitivity and measurement repeatability. Moreover, inherent in this new technology is the capability of discerning water condensation from hydrocarbon condensation. As a result, these analysers can be set up to measure either the WDP (Figure 1) or the HCT (Figure 2); one analyser can take either measurement, or indeed both alternately. This ability to clearly discern one condensation from the other is due to the dissimilar condensation behaviour of water and hydrocarbons and to the inclusion of multiple photodiodes arranged at different angles to the axis of the light rays from the laser. To register hydrocarbon condensation, a photodiode is placed directly opposite to the laser in order to receive the light rays reflected from the shiny surface of the hydrocarbon condensate. To register water condensation, two photodiodes are arranged at angles to the laser – one at an acute angle and one at an oblique angle. Only light that is scattered will reach these, so the analyser will only register this condensation as being water droplets. Due to the fact that the light from the polarised laser can also be refracted by the hydrocarbon condensate film, albeit at a different angle, the result is that light from the surface of the film and light from the surface of the mirror both reach the photodiode. These light signals are slightly out of phase, as the one from the mirror’s surface has travelled slightly further. This asynchronicity creates a pattern of interference that the analyser uses to enhance the sensitivity and accuracy by more than an order of magnitude over older technology. These innovations remove a number of limitations, and open up new possibilities in how a gas sample can be evaluated.

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Figure 3. Measurement chamber outside the

explosion-proof housing for the electronics. Note the in and out gas connections at the base of the analyser.

It also offers more options for customised solutions that can better meet the specific needs of an end-user. It should also be noted that chilled-mirror analysers generally have the advantage of being largely unaffected by changes in the gas matrix. This quality is not compromised by the innovations incorporated into Vympel’s technology. This compatibility with a diverse range of gas compositions makes these devices suitable for use with hydrogen. Whether the application is for natural gas enriched with a certain percentage of hydrogen or for hydrogen alone, as long as an instrument has the required explosion protection, no further modifications are required. Aside from the measurement cell technology, the overall design of these new units incorporates a number of innovations. The explosion-proof housing is equipped with cooling fins to help dissipate the heat created by cooling the mirror and to help cool the analyser in warmer environments. This housing is a monobloc design, which makes it both strong and lightweight. This also means that these analysers can be smaller than older designs. The units are also aesthetically appealing. Two of the analysers, the portable Hygrovision mini and the automatic online FAS analyser, have won the Red Dot award in the category of industrial design. Moreover, compared to traditional configurations, these analysers have a fundamentally different layout. For example, while all of the electronics of these devices are enclosed in the explosion-proof housing, the actual measurement chamber, through which the sample gas flows, is located on the exterior of this housing (Figure 3), which removes several limitations. For example, older designs often have safety issues. It has been common practice to achieve an explosion-proof rating by simply enclosing the entire instrument in an April 2021 30 HYDROCARBON ENGINEERING

explosion-proof box. A casual review of a number of explosion-proof analysers will reveal this common trait. But this approach has a significant flaw. By locating the measurement chamber within the explosion-proof housing, it is unavoidable that sample gas must pass through this housing on the way both to and from the measurement cell. If there is any kind of leak in the connections, gas can easily cause the body of the analyser to become overpressurised, creating a situation that is extremely dangerous. Beyond the fact that the electronics may be exposed to an explosive gaseous mixture, overpressurisation alone presents extreme danger. If technical personnel attempt to open this type of analyser for routine service, explosive decompression can lead to tragic consequences. A pressure of only 2 bar is sufficient to create an extremely hazardous situation. By placing the measurement chamber outside of the explosion-proof housing, any leakage will simply dissipate into the atmosphere. While leakage of any kind is not acceptable, in this case it does not develop into a hidden danger. And this is not to say that the measurement chamber itself is not under pressure, as it is. It is included in the explosion protection certification of the entire device. But since the gas flows continuously through the measurement chamber, when the gas supply is closed off, the pressure in the chamber drops to the ambient air pressure. It is essentially impossible for these analysers to present a danger to on-site personnel. Another advantage to locating the measurement chamber on the outside of the housing is that it allows for easy access of the mirror. This simplifies the process of cleaning it of mild contamination, eliminating extended downtime just to deal with a minor maintenance issue. Another significant advantage of locating the measurement chamber at the surface of the analyser is related to how the analyser can be installed. With older designs, there is basically one type of installation available: mounting the unit on a panel or on the wall of an enclosure. This requires gas sampling and delivery to the panel which, in turn, requires the installation of additional infrastructure. Vympel analysers are not limited to this one option. With the measurement chamber located on the exterior of the base of the housing, it is possible to mount the analyser directly on the pipeline (Figure 4), which offers several advantages. Firstly, in terms of the measurement itself, there is essentially no response delay, as the sample gas passing through the measurement chamber could be considered as essentially being still in the pipeline. As a result, measurements reflect as nearly as possible the state of the pipeline gas in real time. On-the-pipeline installation also means the elimination of gas sampling and delivery infrastructure required for a panel-mounted analyser. This reduction in infrastructure corresponds to a reduction in costs as there is less equipment to install and maintain. The option of on-the-pipeline installation is not only due to the location of the measurement chamber, but also the light and compact nature of Vympel’s analysers. For example, at only 6.5 kg, a CONG Prima 2M unit can easily be supported by a pipeline that is only 20 cm in diameter. On-the-pipeline installation has also created the opportunity for another innovation: zero-emission/zero-loss

Figure 4. CONG Prima-2M automatic online dew point analyser mounted directly on the pipeline.

sampling. The natural gas vented after quality control analysis adds up to a meaningful amount over time. In the past, since the gas composition tended to be very stable, quality control monitoring was kept to a necessary minimum to keep these losses at tolerable levels. But as the infrastructure has expanded, and the sources for the gas in the pipeline have increased in number, gas composition can be much more variable. Consequently, this increases the need for continuous monitoring in more locations. As a result, more gas is being vented after analysis than ever before. Whether directly vented to the atmosphere or collected for vent to a flare, the value of this gas is lost. In addition to this traditional cost of doing business, operators are faced with climate-change related regulatory limitations on the amount of greenhouse gas emissions that are allowable, whether in the form of methane or the carbon dioxide created from burning vent gases in a flare. Zero-emission/zero-loss sampling creates a positive flow through the measurement chamber and returns the sample gas to the pipeline. This system does not require any pumps or repressurisation because the gas enters and leaves the system under the same pressure. The sampling probe itself incorporates innovative architecture that results in this positive flow to and from the analyser when gas is flowing through the pipeline (Figure 5). By eliminating the loss of sample gas through venting after analysis, this technology not only saves the value of the gas itself, but also the value it represents in terms of carbon credits.* By employing zero-emission sampling, carbon credits that would normally be consumed can be treated as a commodity that can be sold or traded. In other words, zero-emission sampling not only reduces costs, it can actually become a source of positive revenue.

Conclusion Breakthrough sensor technology, unique instrument configuration, aesthetic yet robust design, and unprecedented installation options are just a few of the transformational innovations that are driving the evolution of this chilled-mirror technology. The list could go on to include modular system design that is expandable and updatable; solutions that are powered by renewable energy; the elimination of consumables, as illustrated in the development of innovative patented inertia-gravity filtration technology; and supplemental cooling channels built into all chilled-mirror analysers, for extension of the measurement range. As is so often the case, the development of revolutionary technology only requires one company to recognise that bold innovation is possible. Whether for smart phones, electric cars, or reusable rockets, deliberate revolutionary advances in technology have led to unprecedented possibilities for end-users. Dew point analysers for end-users in the natural gas industry can be added to the list of technologies that have been transformed by one clear-sighted company.

Figure 5. Drawing of the zero-emission sampling system for use with on-the-pipeline installation of CONG Prima-2M (shown) and FAS analysers.

April 2021 32 HYDROCARBON ENGINEERING

Note

*Carbon credit is a term for a tradable right to emit 1 t of carbon dioxide (tCO2e) or alternate greenhouse gas equivalent.

Rupam Mukherjee and Shilpa Singh, Engineers India Ltd, India, examine how pre-planned changes in the operation of existing fired heaters can inspire quick savings without any major investment.

ired heaters and furnaces are ubiquitous in the oil refining industry. Over the decades, fired heaters have seen major changes in their design as well as in operational practices. Today, the expectation of fired heaters has gone beyond just providing a stable source of process heat. Now, these pieces of equipment are expected to deliver process heat with maximum efficiency, reliability, availability and safety, at the same time as providing minimum losses in terms of OPEX and CAPEX. Further adding to their complexity is the ‘pollution control’ dimension, which has to be kept under strict abeyance. Quite understandably, the cost of energy is under strict observation, as every refiner attempts to keep figures under control. From the environmental perspective, depleting resources make it increasingly imperative to

reconsider energy consumption patterns in oil refineries, especially at this point of time when almost all commodity prices are affected by the oil price. Fired heaters are highly energy-intensive process units and have therefore been pinpointed as lynchpin machines, whereby the greatest savings can be achieved. The saying goes ‘a penny saved is a penny earned.’ The same holds true with fired heaters, where a percentage unit of energy saved is equivalent to thousands of dollars added to the refinery’s profit margin. Therefore, these heaters need to be designed and operated at the maximum level of fuel efficiency. Currently, more than 60% of refinery fuel is consumed in fired heaters and even small improvements in efficiency can create lucrative benefits.

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Fired heaters necessary for performance analysis The foremost principle is that fired heaters are customised to be operated for a particular envelope of service conditions, which should be well defined during the design stage. With time, the process and the operating conditions change on a significant level. These changes can be due to various reasons. A common example of changing operating parameters is seen when a crude unit approaches its end-of-run phase. In that phase, the preheat train of exchangers fails to deliver the desired level of preheat due to the inherent fouling nature of the crude. Thus, the loss in preheat has to be made up in the fired heater through additional firing. Another common changing process condition is encountered when any unit undergoes a revamp. It is quite often the case that after a revamp, the heat duty requirement of the fired heater is brought down drastically due to better energy recovery in the upstream circuit, leading to lower firing in the heater. There are various other similar examples by which the process operating conditions of a heater varies within its lifetime. A heater that is designed for one particular set of process conditions is bound to show varying characteristics when it encounters a new set of conditions that are widely different from the original one. Thus, the ‘best operational point’ for one particular set of process conditions may be inefficient when the terminal conditions change. The crux of this discussion rests on the argument that energy efficiency improvement practices in fired heaters do not always call for capital intensive hardware changes. Rather, an in-depth analysis of the current process conditions can provide a fair indication of where energy is being lost or wasted, whereby simple solutions can be applied to achieve savings. A closer look into heater operating parameters can reveal valuable information. For example, deterioration in heat transfer surfaces can occur as a result of prolonged operation, which calls for additional firing in fired heaters, thereby lowering the efficiency. Damaged or worn-out extended surface areas in the convection section often result in a higher flue gas stack temperature and lower convection section heat recovery. It is important to plug these heat leakages; however, it is advised that the operating conditions are analysed first before delving into any line of action. There may be other reasons for the flue gas stack temperature to increase. A common reason may be that the process fluid inlet temperature to the convection coils has increased significantly post-revamp scenario, which causes the flue gas stack temperature to rise due to the temperature differential. Therefore, a detailed process study needs to be undertaken in order to determine why the flue gas temperature at the convection section exit is higher than previous readings, and ascertain if it is a result of the heater performing badly. Efficiency improvements in fired heaters are considered as ‘tailor-made solutions,’ as each case needs to be adjusted within the framework of their repercussions and limitations, and based on merits and demerits of each revamp action.

Efficiency improvement measures The efficiency of an existing fired heater can be enhanced by reducing heat losses. Heat losses occur through the heater walls and as the flue gas exits the stack. Heat losses through April 2021 34 HYDROCARBON ENGINEERING

the walls constitute a small percentage and do not yield a large energy saving. Moreover, the radiation heat loss saving evens out after an optimum insulation thickness is reached. Most of the efficiency improvement measures, therefore, focus on reducing stack heat loss. The common ways to enhance heater efficiency include: Fine-tuning operating parameters through operational adjustments. Ensuring heat recovery through additional heat transfer area/air preheating – this method requires hardware augmentation. Obtaining heat recovery through steam super heating or steam generation system – this method requires hardware augmentation. As outlined, the latter two methods require hardware modifications and augmentation. Although these options are potentially more beneficial in terms of return on investment, this article will focus on ways of fine-tuning current operating parameters. The main advantage of this option is its quick viability, as only minor or no modifications to the existing system are required.

Fine-tuning of fired heater operation The overall efficiency of a fired heater is heavily indebted to its operating conditions. Therefore, optimising the heater’s operating conditions plays a prominent role in attaining the desired efficiency. Some of the important parameters which require accurate optimisation are described below.

Excess air control Excess air level impacts the process in two ways: It dilutes the flame zone, resulting in a lower temperature of the heat source and thereby reduced heat transfer by radiation. It increases the mass of flue gas, thereby increasing the sensible heat loss through flue gases. The more excess air, the more energy is wasted when heating it from an ambient temperature to the combustion temperature. Thus, a reduction in excess air entails no investment and is a very attractive solution. However, a certain amount of excess air is essential to ensure proper combustion inside the furnace. The industry standard is to maintain the excess air level in the range of 15 – 20% in fired heaters where fuel oil is fired. In the case of fuel gas-only fired systems, excess air level in the range of 10 – 15% is more common place, depending upon the type of fuel and combustion air system adopted. The tangible parameter for the excess air can be referred from the measured oxygen volume percentage in the flue gas. Typically, a sample is collected at the arch of the heater below the convection shock rows. Effort should be made to maintain the oxygen level at arch to 2 – 3 vol%. Since traditional oxygen analysers generally installed in furnaces are prone to faulty readings, it is recommended that periodic sampling of flue gas from the furnace is conducted and the oxygen level measured.

Case study 1 A large capacity crude processing facility was operating a crude distillation unit (CDU) heater with a rated absorbed duty

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Table 1. Benefits of excess air control Heater absorbed duty

86 million Kcal/hr

Heater coil inlet temperature

291˚C

Coil outlet temperature

368˚C

Fuel used

Fuel oil with 1 wt% sulfur

Fuel dew point

132˚C

Flue gas temperature leaving APH

157˚C

Arch oxygen percentage measured

5.5 vol%

Draft control

The above data was analysed and it was found that the furnace was operated on 38% excess air. Being a balanced draft system operated on fuel oil, 20% excess air is considered ideal and safe. Accordingly, air flowrate to the furnace was adjusted to 20% excess air. Findings after adjustment are tabulated below: Before adjustment

of 86 million Kcal/hr. Considering that heavy fuel oil was being fired, the operator was maintaining an arch oxygen level of 5.5 vol% to be on the safer side. The furnace was taken up for detailed analysis and the results are shown in Table 1. The information in Table 1 provides an effective example of very high returns with minimal or no capital investment. However, care must be taken to optimise excess air and ensure that the complete combustion process is not hampered.

After adjustment

Excess air

38%

20%

Arch oxygen vol%

5.5

3.3

Calculated fuel efficiency

90.3%

91.2%

Total fuel consumed

9708 kg/hr

9610 kg/hr

Total fired duty

94.8 million Kcal/hr or 376 million Btu/hr

93.9 million Kcal/hr or 372 million Btu/hr

Annual fuel saving considering 8320 service hours annually

815 tpy

Energy equivalent saved (considering LHV of fuel oil as 9768 Kcal/kg)

7900 million Kcal/yr or 31350 million Btu/yr

Savings

~US$125 000 annually considering equivalent energy cost as US$4/million Btu

In a natural draft heater, a stack damper is used to control the draft. It is essential that the damper is in a proper operable condition; the draft at the radiant arch should be maintained close to 2.5 mmWC. During heater operations, it is recommended to monitor the draft at the radiant arch along with excess air level and adjust stack damper/burner air registers accordingly. Closing the stack damper will reduce the draft and decrease excess oxygen in cases of natural draft furnaces. Opening the stack damper, on the other hand, will increase the draft and excess air level. The burner air registers’ opening is then adjusted to maintain the desired level of oxygen in the flue gases. These actions result in the optimum level of draft and excess air, a reduction in stack loss, and consequently an increase in fuel savings. There are instances where operators maintain the draft inside the heater at 8 – 10 mmWC, with a belief that this practice will ensure a safer operation. However, with such a strong draft, air ingress and tramp air leakage into the furnace will have an adverse jolt on the efficiency figure. Sight doors left open or partially-open explosion doors (as shown in Figures 1 and 2) are common sources of tramp air leakage, which can affect the furnace’s efficiency substantially. However, this tramp air will be read by an oxygen analyser at arch and provides a false sense of safety from running the furnace at adequate excess air.

Periodic cleaning of heat transfer surfaces Fired heater components are subject to severe firing conditions and operate mostly at elevated temperature levels. As a result, heater components are much more susceptible to wear and tear. Thus, planned periodic maintenance of these components is essential. Coking and fouling of heater tubes are very frequent occurrences that deteriorate the heat transfer rate. Soot blowers are quite effective at removing soot deposition due to their online cleaning abilities. A proper cleaning schedule, aided by soot blowers, is imperative in order to optimise heater operations. Air preheaters are also susceptible to soot depositions from flue gases. An air preheater washing system is generally provided for the purpose of cleaning the soot deposits and to enhance the effectiveness of the heat transfer surface.

Timely maintenance

Figure 1. Opened sight door.

April 2021 36 HYDROCARBON ENGINEERING

Burners play a pivotal role in smooth heater operations. Properly scheduled burner maintenance periods can ease out many unforeseen instances of flame impingement, unstable firing, erratic flame pattern, etc. Most burners are compatible with both fuel gas and fuel oil in firing operations. In India, heavy fuel oil is still a primary source of furnace firing, and

thus burner tips often experience wear and tear as well as tip coking/clogging. Cleaning these clogged/eroded burner tips and repairing the damaged burner refractory may prove lucrative in the long-term. Special emphasis and care should be paid to the health of the gas tips, which usually have a smaller pore drilling. These small drillings are susceptible to clogging when the fuel gas is unclean, or when it contains high percentage of unsaturates or saturates heavier than C3. There are multiple cases and instances where these tips have eroded badly due to soot formation on gas tips (Figure 3). Fuel oil fired burners are generally operated on a fuel oil-steam pressure differential concept. It is imperative that the differential is maintained in the range of 0.7 – 2.1 kg/cm2 for an optimised operation. However, original equipment manufacturer (OEM) advice should be sought after in cases where the burner has been designed to operate on a particular differential pressure figure. Generally, medium-pressure steam consumption for burning fuel oil should be limited to 40 kg/hr of medium pressure steam consumed per 100 kg/hr of fuel oil burnt. Coker heaters and certain heavy vacuum heaters are also equipped with online tube cleaning facilities, such as online spalling. Other methods, such as steam air decoking, are also widely used. It is recommended to engage with a company that has proven to be effective at scrapping off coke deposits from the tube surfaces. Cleaner tubes correspond to better heat transfer and better energy efficiency.

Case study 3 Once the furnace was shifted to 100% fuel gas firing (as was achieved in case study 2), further opportunities for optimisation were evident. With a cleaner fuel gas firing, excess air could be reduced to 15%. More importantly, the flue gas could also be cooled further, as a lower dew point of flue gas was generated from clean fuel gas firing. The effects of these optimisation measures are shown in Table 3.

Fuel change Stack losses form a major amount of energy that is vented into the atmosphere. The stack loss is, in turn, limited by the sulfur dew point of the flue gas. The higher the sulfur content is within the fuel, either in the form of bound sulfur in fuel oil or in the form of hydrogen sulfide in fuel gas, the lower the maximum achievable efficiency. Thus, higher efficiencies within fired heaters can be achieved by utilising a clean fuel for combustion. Bypassing of a percentage of air across the air preheater is commonplace in certain refineries where the flue gas dew point is exceedingly high, owing to heavy sulfur laden fuel oils. This is done to ensure that the air preheater metal temperature is higher than the dew point of the flue gas, which otherwise may pose serious corrosion problems. However, this air bypassing should also be analysed on a periodic basis with change in the fuel characteristics. Laboratory sampling of fuel oils may be useful in this regard. Changeover from fuel oil to fuel gas firing also should help in achieving efficiency improvements. However, abrupt changes from fuel oil to fuel gas should be refrained from and a proper study must be conducted of the operating parameters whenever such a programme is undertaken. The approximate benefits for shifting over to fuel gas firing from fuel oil firing are illustrated in the following case studies.

Figure 2. Partially open explosion doors (image

courtesy of DUGUE, J., ‘Fired equipment safety in oil and gas industry’, Energy Procedia, Vol. 120, August 2017, pp. 2 – 19).

Figure 3. Worn out gas tips due to heavy unsaturates in fuel gas. Table 2. Shifting to fuel gas firing

Fuel oil LHV in Kcal/kg

100% fuel oil firing

100% fuel gas firing

9768

11 648

Case study 2

Excess air

20%

This case study analyses the same crude furnace that was presented in case study 1. After optimising the furnace excess air to 20%, the next step was to shift to 100% fuel gas firing, while maintaining all other parameters. The results can be seen in Table 2.

Flue gas temperature maintained at exit of APH

157˚C

Quantity of fuel required to be fired to attain required process duty

9610 kg/hr

8088 kg/hr

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Table 3. Optimising parameters for 100% fuel gas

firing

Fuel gas firing – before optimisation

Fuel gas firing – after optimisation

Fuel gas LHV in Kcal/kg

11 648

Excess air

20%

15%

Flue gas dew point

132˚C

110˚C

Flue gas temperature maintained at exit of APH

157˚C

135˚C

Quantity of fuel required to be fired to attain required process duty

8088 kg/hr

7978 kg/hr

Total fired duty

94.2 million Kcal/hr or 373.8 million Btu/hr

92.9 million Kcal/hr or 368 million Btu/hr

Differential fuel gas saving

110 kg/hr

Total fuel gas saved considered 8320 service hours

915 tpy

Equivalent energy saved

10 658 million Kcal/yr or 42 300 million Btu/yr

Equivalent saving in operational cost considering US$4/million Btu

~ US$170 000

Thus, the crude furnace – which was originally operated on 100% fuel oil firing and 5.5 vol% oxygen level at arch – was optimised to 100% fuel gas firing with only 15% excess air and further heat recovery in the air preheater. The optimisation exercise led to a reduction in hourly energy consumption from 376 million Btu/hr to 368 million Btu/hr. This led to approximately 66.5 million Btu of energy saved per operating year, which yielded approximately US$2.66 million/yr in savings.

Conclusion As technology has advanced, energy consumption within refineries and petroleum plants has been significantly reduced from the levels of consumption seen in the 1980s or 1990s. A fair amount of heat saving potential in the existing fired heaters still remains to be captured. There are various ways through which efficiency and energy improvements in fired heaters can be obtained. This article illustrates a number of ways in which improvements in fuel consumption can be realised with little to no capital investments. Furthermore, the ideas presented can be implemented within an operating furnace without the need for downtime or a major design alteration. Nevertheless, in order to obtain more savings or return on investment from fired heaters, operators can employ more capital-intensive projects or initiatives that require hardware modification within the heater. Such capital-intensive projects should be planned during scheduled turnarounds, as they involve substantial downtime.

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David A. G. Suares, Gas Processing Consultant, India, highlights design considerations that need to be considered when flaring ethylene oxide.

he flaring of gases released from normal process vents and safety valve discharges following an overpressure scenario is widely practiced in refineries, petrochemical and chemical plants. In past projects, ground flares, elevated flare stacks or a combination of these two systems have been successfully used even for the flaring of pure ethylene oxide (EO) or EO-rich streams. However, the flaring of pure EO or EO-rich streams requires certain additional precautions as well as several stringent design considerations, which need to be taken care of owing to the toxic, highly reactive and flammable nature of EO. Because of this, EO was often vented

off from high point vents directly to the atmosphere in many older plants. As EO is toxic and a known carcinogen, the disposal of large quantities of EO or EO-rich streams from process vents and safety valve discharges by direct venting to the atmosphere has raised environmental concerns in recent years. EO (or oxirane) is the simplest cyclo-ether. It is a colourless gas at room temperature with a sweet etheric odour and is prepared by reacting ethylene with air or oxygen over a silver oxide catalyst. EO by itself is a good sterilising agent and is also used to treat foodstuff. However, EO is generally further reacted with other chemicals in order to produce EO

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derivatives, the most important of which is ethylene glycol which is used in the manufacture of polyester and as automotive antifreeze. EO is an important raw material in the manufacture of ethanolamines, ethyleneamines, glycol ethers, polyurethanes and solvents. The following two reactions of EO are of special note: 1. Decomposition of EO: EO vapour or EO vapour mixed with air can decompose explosively, generating carbon monoxide and methane. This exothermic reaction can be represented as: C2H4O ---> CO + CH4 2. Disproportionation of EO: the disproportionation of EO consists of a reduction-oxidation reaction resulting in the production of ethylene and carbon dioxide and can be typically represented by: 4C2H4O ---> 3C2H4 + 2CO2 + 2H2

Design considerations Owing to its toxic, highly reactive and flammable nature, a standalone EO flare system (piping, knockout drum, liquid seal drum and flare stack) should be used for the disposal of vapours containing pure EO or EO-rich streams, as certain special design and safety requirements need to be considered.

Rupture disc upstream of pressure relief valve The two most commonly used relief devices in the process industry are rupture discs and pressure relief valves. Due to their non-closing nature, rupture discs by themselves should not be used in EO service. When relieving EO, a rupture disc should be installed upstream of the pressure relief valve in order to prevent the build-up of solids or blockage at the inlet to the pressure relief valve. Solid deposits at safety valve inlets could form as a result of polymerisation of EO. All pressure relief valves used in EO service should conform to the requirements of API 520 and API 521. Further, the pressure relief valve shall be de-rated due to the upstream rupture disc and a capacity correction factor of 0.9 shall be used.1

Minimisation of the relief device inlet pipe length The inlet pipe length from the vessel or column shell to the relief device should be minimised, as pockets of stagnant EO vapour in a long inlet line could lead to the polymerisation of EO, resulting in the build-up of solids. This, if unchecked over a period of time, could ultimately lead to blockage of the line, thus leading to a hazardous situation in the plant during a major relief scenario.

Purging requirements As practised in a typical hydrocarbon flare network, a normal fuel gas or natural gas purge would need to be provided at all flare header and sub-header dead ends in order to maintain a small positive velocity in the header or sub-header.2 This should be backed up by nitrogen to increase the reliability of the purge. However, in addition to the normal purge, an emergency purge needs to be provided for the EO flare. The main function of the emergency purge (natural gas or nitrogen) is to April 2021 40 HYDROCARBON ENGINEERING

sufficiently dilute the EO-rich stream in order to make it non-explosive. It is to be ensured that the emergency purge is always available. The availability of the normal and emergency EO flare purges is one of the most critical considerations for an EO flare and needs to be closely monitored. These purges are essential for the uninterrupted operation of the connected plant. It is highly risky to operate the plant if there is a failure of either one of these purges. The concentration of EO diluents is a function of the pressure and temperature of the system. Based on data reported in the literature in the absence of air within the system, the concentration of diluents required in order to keep the system non-explosive will not be less than 15% methane (considering a binary mixture of EO and methane) or 40% nitrogen (considering a binary mixture of EO and nitrogen).3 However, it is recommended that an appropriate factor of safety (approximately 2 – 3) should be imposed on these limits due to the limited availability of data at higher temperatures. In order to improve the reliability of the system, the emergency natural gas purge should be automatically backed up by nitrogen through the use of a safety integrity level (SIL)-rated interlock. A pressure sensing system consisting of two or more pressure transmitters placed between the rupture disc and the pressure relief valve inlet should be used for all pressure relief valves which could potentially release EO-rich streams to the flare. During an overpressure scenario, the rupture disc would rupture and the high pressure at the pressure relief valve inlet would be used to trigger the emergency purge. One or more additional pressure transmitters can be located at each pressure relief valve discharge in order to further increase the reliability of the system.

Flare gas analyser A flare gas analyser (e.g. a gas chromatograph-based analyser that is sensitive to even 1 ppm of EO) located on the main flare header can be programmed to trigger the emergency flare purge in case the concentration of EO or oxygen exceeds a certain fixed value which is input into the system.

Materials of construction Any piping and equipment which can come into contact with the EO-rich stream would need to be of stainless steel (SS). The use of SS minimises the potential for rust formation. The 300 series austenitic SS have been widely used in EO service. Type 304L has been successfully used for the EO flare headers and sub-headers, while Type 304 and Type 316 SS have been used for small tubing which cannot be cleaned of rust. Austenitic SS can be used in those areas where EO liquid is likely to remain for long periods of time (e.g. suction and discharge piping of flare knockout drum pumps, low point drains, etc.). Traces of rust on the internals of carbon steel piping or equipment could catalyse the disproportionation of EO, which would further raise the local temperature above the EO decomposition temperature, thus leading to a hazardous situation. Furthermore, even clean carbon steel could catalyse the polymerisation of EO but at lesser rates than rusted carbon steel. Therefore, the use of carbon steel piping and equipment in an EO flare network is prohibited.

Since EO attacks a number of non-metallic materials, including several types of polymers and elastomers, proper care should be taken in order to select a proper material of construction for gaskets, O rings, packing, etc. This would include rigorous monitoring and inspection programmes before a material is deemed fit for use in EO service. Polytetrafluoroethane (PTFE) is resistant to EO even up to 260˚C and has been used successfully in such applications.3

Grounding requirements EO liquid is conductive. As such, if EO is stored in a metallic container that is grounded, the static charge cannot accumulate. However, if the system is not properly grounded, a static charge can be generated and lead to ignition due to the low value of the minimum ignition energy of EO (which is even lower than gasoline vapour). Therefore, all EO flare system components (including piping and equipment) need to be properly grounded in order to prevent the build-up of static electricity, which could ignite EO and thereby start a fire which could lead to an explosion.

Prevention of flash-back A flare system is usually equipped with a liquid seal drum in order to prevent flashback. However, this method suffers from some drawbacks due to the possibility of losing the liquid seal (e.g. if the seal gets blown-out following a peak release or if there are issues in establishing and maintaining the required liquid level). The use of two liquid seal drums in series – one located at the base of the flare stack and another located between the outside battery limits (OSBL) flare knockout drum and the stack – can further enhance the reliability of the EO flare liquid seal system. In the case of EO flares, the flare tip is provided with an anti-flashback device (‘velocity section’), which would need to be designed to minimise possible flame flashback initiated at the flare tip by ensuring that the forward velocity of the flared gases exceeds the flashback velocity.3 Furthermore, an appropriate velocity seal would also need to be provided to prevent air ingress and conserve purge gas. Close follow-up with the flare vendor is recommended at every stage during the design of an EO flare system in order to increase the reliability of the system in view of the hazards associated with EO. Flare regulations followed by some countries, such as Russia, allow for the possible inclusion of a spare flare stack and liquid seal system in order to further increase the reliability of the EO flare system and thus ensure uninterrupted operation of the connected units.4 However, before exploring this option the overall economics of the system needs to be studied.

Sampling of flare condensate Flare condensate collected in the flare knock-out drum would need to be periodically sampled. Any EO-containing flare condensate is required to be routed to the re-absorber column or elsewhere inside the EO unit for further recovery of EO. However, if the flare condensate does not contain EO it may be routed to wastewater treatment.

References 1. 2. 3. 4.

‘Sizing, Selection, and Installation of Pressure-relieving Devices in Refineries,’ API RP 520, Part I – Sizing and Selection, 8th Edition (December 2008). ‘Pressure-relieving and Depressuring Systems,’ API RP 521, 6th Edition (January 2014). ‘Ethylene Oxide Product Stewardship Guidance Manual’, Ethylene Oxide Panel Ethylene Oxide Safety Task Group, 3rd Edition (May 2007). ‘Rules for the Design and Safe Operation of Flare Systems,’ Russian PB 03-591-03 (1992).

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Stan Barskov, Athlon, a Halliburton Service, USA, and Paul Campbell, Aster Bio, USA, discuss using advanced molecular testing to help spot early signs of trouble in activated sludge systems.

or over a century, distinguishing between living and dead microorganisms and assessing the overall viability of the biomass in the activated sludge process has been a huge challenge for wastewater treatment plant operators. Still today, operations rely on a variety of monitoring tools such as mixed liquor volatile suspended solids (MLVSS) concentration, sludge volume index (SVI), oxygen uptake rate (OUR) and various other techniques to evaluate wastewater treatment effectiveness, adjust operating conditions, and ensure the plant operates as it was designed, in order to produce quality effluent that meets permit standards. While the deployment of microscopic exams and adenosine triphosphate (ATP) tests provided insight into the health of the biological unit, these techniques still lack the ability to quantify the actual bacteria required to treat a waste stream. Nor are they able to track the changes in biomass population over time or how it responds to changes in the influent stream composition.

Microscopic exam Basic microscopic exams are rudimentary tests conducted routinely by wastewater plant operators to qualitatively assess biomass health. These tests can provide insight on the quality, size and density of the biomass floc, determine the presence of protozoa and other multicellular organisms, qualitatively assess the quantity of filamentous bacteria present within the floc, and identify non-filamentous (Zoogleal) bulking (Figure 1). Advanced microscopic exams will selectively classify the different types of filamentous bacteria and determine whether excessive amounts of extracellular polysaccharides (EPS) are present within the floc. While these techniques are still considered the ‘gold standard’ of the wastewater

treatment practices, they are very subjective and rely heavily on the knowledge and experience of the interpreter performing the exam. The inability of Microscopic exams to quantify various microorganisms present within the biomass and trend the changes occurring within the microbial community over time makes it very difficult to use their results for identification of chronic biological problems. It is still, however, a great tool for operators to use as a ‘quick check’ of the biomass health. As a general rule, a healthy biomass is characterised by light to dark-brown, medium-density floc particles with an abundance of protozoa (single-celled eukaryotes such as amoebas, flagellates, ciliates and many others) and a minimum number of filamentous bacteria. However, other operational indicators (SVIs, total suspended solids [TSS], etc.) are also widely utilised to assess biomass health.

Adenosine triphosphate testing The development of ATP test kits has allowed operators to measure the quantity of all living microorganisms within biomass and assess the real-time viability of the wastewater treatment plant. ATP is the primary energy molecule for all life forms and is found in and around all living cells. The measurement of ATP concentration in a wastewater sample is a direct measurement of the quantity of microorganisms present in the biomass. The ATP test allows the operators to manage wastewater treatment plants and optimise bioreactor parameters using three simple metrics such as cellular ATP (cATP), biomass stress index (BSI), or active biomass ratio (ABR). cATP is very specific and can vary from plant to plant. However, if either BSI exceeds 50% or ABR is lower than 10%, activated sludge treatment effectiveness will deteriorate HYDROCARBON 43

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significantly, and immediate corrective actions will be required to avoid effluent permit violation. ATP tests offer greater opportunities for process optimisation compared to the simple microscopic exams through a long-term data trend. Nevertheless, microscopic exams and ATP tests provide a limited insight into the specific microorganisms required for trouble-free wastewater treatment operation.

Microbial community analysis (MCA) and quantitative polymerase chain reaction (qPCR) Recent advances in molecular biology now make it possible and affordable to understand and track key ‘players’ in the activated sludge system and how their presence, or lack of, impacts wastewater treatment plant performance. MCA is a microbial census that provides quantifiable insight into the biomass in a

wastewater treatment unit. It describes the composition of the biomass in ways that microscopic exams, ATP tests and other techniques cannot. MCA uses high-throughput DNA sequencing technology to identify and quantify the relative abundance of various microbial species present in the wastewater system essential to the treatment of a particular waste stream (Figure 2), such as: Ammonia and nitrite oxidising bacteria (AOB and NOB). Nitrate reducing bacteria (NRB). Phosphorus accumulating organisms (PAO). Sulfate reducing bacteria (SRB). Various filamentous, bulking and foaming bacterial species. It is important to note that, depending on the industry type (chemical, petrochemical, refinery, etc.), the relative abundance of various microorganisms in the biomass will be different and it is critical to determine the historical ‘norm’ for the specific facility before an accurate prediction can be made using this data. This information should be used as a guide only, as changes in wastewater composition will inevitably affect the relative abundance of the specific microbes in the biomass. qPCR is a selective and sensitive test used to determine the fraction of the biomass made up by specific bacteria of interest. This information is then used for tracking the changes in these sub-populations over time, similar to tracking SVIs or mean cell residence time (MCRT) to use as an indicator for wastewater challenges and issues. qPCR tests are extremely sensitive and able to detect low levels of undesirable filamentous bacteria before they can be detected using a standard microscopic analysis. These tests can be customised to fit the need of any plant, identify and quantify specific bacteria present in a given system, making them instrumental during system upsets or unexpected plant shutdowns.

Nitrification challenges in industrial wastewater treatment One of the challenges faced by most industrial wastewater treatment plants is nitrification. Nitrification is a critical step in refinery and petrochemical wastewater treatment systems as more stringent discharge regulations are imposed on these facilities. Nitrification is the biological oxidation of ammonia carried out by two unique types of microorganisms, Nitrospira and Nitrosomonas. These bacteria are autotrophs, meaning they use inorganic sources of carbon such as carbon dioxide and carbonate to grow and reproduce, unlike the great majority of the other microbes that utilise organic substrates both as an energy and carbon source (heterotrophs). Nitrifiers are slow growing bacteria and are more sensitive to growth conditions Figure 1. A typical microscopic exam showing a such as pH, temperature and the presence of toxic compounds. healthy biomass (top) and presence of specific Maintaining optimal treatment conditions at all times in a given filaments using gram staining (bottom). wastewater system is not always possible and this makes qPCR an ideal data point to trend nitrifier population changes within a facility in the Table 1. ATP test biomass health assessment parameters face of variable operating conditions. Definition Calculation Healthy system It is common for refineries and cATP: cellular ATP tATP (total ATP) – dATP (dissolved ATP) Process specific petrochemical plants to lose nitrification BSI: biomass stress dATP/tATP x 100% < 30 efficiency due to various plant activities. index (%) Figure 3 shows a historical trend of how ABR: active [(cATP (ng/mL) x 0.5) / MLSS (mg/L)] x > 25 various activities such as sour water tank biomass ratio (%) 100% cleaning and turnarounds affect nitrifier April 2021 44 HYDROCARBON ENGINEERING

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population. In both cases, nitrifiers have been significantly inhibited by these events, resulting in a significant increase in effluent ammonia numbers. The historical trend provides vital information regarding the ‘normal’ fraction of the nitrifying bacteria in the biomass. This data can be used as a guiding tool to bio-augment bacteria (as a healthy nitrifying bacteria population takes days to establish) in the event when rapid plant start-up is imminent.

Filamentous bacteria challenges in industrial wastewater treatment Almost every wastewater plant will experience issues with excessive amounts of filamentous bacteria in the biomass. Figure 2. Relative abundance of various microorganisms in a typical Filamentous bacteria present a number of chemical plant. operational challenges such as inhibition of biomass settling in the clarifiers and excessive foaming. Both of these events, if not addressed in a timely manner, will cause Table 2. Relative abundance of specific effluent TSS to trend upwards and threaten environmental microorganisms in petrochemical wastewater compliance. Filamentous bacteria can be either an acute or Group Range (% of Group Range (% of chronic issue, but despite their origin, qPCR techniques can be reads) reads) effective in pinpointing the root cause of the problem by AOB 0.1 – 1 GLY 0–2 identifying the specific filamentous bacterium present in the accumulators system. Historically, advanced microscopic exams and gram (GAO) staining techniques have been required to identify the most NOB 1–5 High EPS 3 – 30 common filamentous bacteria species. These techniques, as producers already mentioned, rely heavily on the experience and Nitrate 10 – 50 Foaming 0–1 knowledge of the person conducting the examination. reducers Many filamentous bacteria appear very similar under the Sulfur 0.5 – 4 Filaments 0.1 – 4 microscope and their appearance can be misleading while oxidisers qPCR will selectively identify and quantify the predominant Sulfur 0–1 Methylotrophs 2 – 15 organism present within the sample. Figure 4 shows a Neisser reducers (SRB) stain slide identifying M. parvicella as the predominant 0–2 Methanogens 0 PO4 filamentous microorganism inhibiting sludge settling in the accumulators secondary clarifiers. M. parvicella is very common in municipal (PAO) wastewater treatment plants and grows under conditions of low food to mass (F/M ratio), low temperature, high lipids, and long sludge age. The relative hydrophobic cell surface of M. parvicella make them water resistant and enables them to float when aerated, creating an excess amount of foam in the aeration basin. These findings were inconsistent with the plant’s operating conditions, e.g. high F/M ratio, high chemical oxygen demand (COD), and high volatile organic acids (VOA). No excess foaming was observed in the system either. qPCR analysis of the same sample demonstrated that although M. parvicella is present in the biomass, the predominant filamentous bacteria causing settling issues is in fact Thiothrix sp. These findings were in agreement with the Figure 3. Historical trend of nitrifier population in a Gulf Coast refinery. physical characteristics of the system. April 2021 46 HYDROCARBON ENGINEERING

Accurate filaments identification is critical in establishing the correct course required to reduce the filamentous species present in the system. Corrective actions to control and reduce the growth of M. parvicella typically start by increasing waste in order to increase the F/M ratio and decrease the sludge age. Here, corrective actions to control the growth of Thiothrix sp. focus on the elimination of low nutrient zones and elimination of septicity in primary treatment and secondary clarifiers. Developing an action plan to rid the system of the incorrectly identified filament will result in wasted time, energy, and money at best, and effluent permit violations at worst, as the corrective actions can amplify the growth of the offending filamentous species. Accurately and confidently identifying species of trouble causing bacteria will result in more decisive, impactful corrective actions, which will lead to more reliable wastewater treatment plant performance.

Conclusion Previously only used in research settings, molecular testing is now available for use in wastewater treatment systems with complex operations and more stringent treatment goals. MCA and qPCR represent a leap forward in biological wastewater monitoring, and their ability to provide quantitative assessment of the biological wastewater system microbial population offers a significant advantage over microscopic exams or ATP tests. Over the coming years, combining field experience in wastewater treatment and advanced biochemistry is expected to become the routine workflow of every wastewater treatment plant operation.

Figure 4. M. parvicella – Gulf Coast petrochemical

facility.

Table 3. Predominant microorganism identified using qPCR

Filament type

% Abundance

Date

Thiothrix sp.

9.1

28 October 2019

5.3

20 March 2020

13.5

13 April 2020

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Michael Gaura, AMETEK Process Instruments, USA, emphasises the importance of carefully addressing the impacts of changing regulations and feedstocks in sulfur recovery units.

he efficient and reliable operation of sulfur recovery units (SRUs) continues to be critical to hydrocarbon processors, which are tasked with delivering end products that contain lower levels of sulfur while simultaneously reducing the amount of sulfur that is emitted to the local environment. In January 2020, the International Maritime Organization’s initiative to lower pollution from ships – often referred to as IMO 2020 or MARPOL 2020 – represented the most recent global regulatory requirement on an

end product that directly affected refiners. This change lowered the available H2S content in fuel oil from 3.5% to 0.5%, driving ever greater removal of sulfur components in processing operations and higher recovery efficiency of elemental sulfur (SX) in SRUs. Local and national jurisdictions are continuously reviewing and modifying emission maximums, further impacting the design and operation of SRUs. As a reminder, an SRU is tasked with one primary objective – to recover some amount (often 96+%) of the elemental sulfur that has

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Figure 1. Typical SRU layout, with common analyser locations. been delivered to it. Hydrocarbon feedstocks that are used in most natural gas processing facilities and refineries contain sulfur that must be removed. The sulfur contains very little energy value and, more importantly, can negatively impact final product purity requirements. There is a positive element to recovering elemental sulfur however, as it can be sold and used in fertilizer and medical drug production. During hydrocarbon processing, sulfur components can be stripped out of the feedstocks using combinations of catalysts, temperature, pressure, and the introduction of excess hydrogen, and sent to the SRU for elemental sulfur removal. The gas streams delivered to the SRUs are typically referred to as acid gas and/or sour water stripper gas and, unfortunately, frequently consist of components other than just ‘sulfur compounds’, which will be touched upon later in this article. Upon entering the SRU, the feedstocks undergo a modified Claus reaction to have SX removed. The gas enters a reactor furnace, continues through a series of converters and condensers – where the elemental sulfur is captured – and then either enters a tail gas treatment unit (TGTU) before being burned in a thermal oxidiser, or the TGTU is either bypassed or not required and the gas stream is burned in the thermal oxidiser before exiting the SRU via a stack (Figure 1).

Feed gas analysis (AT1) Gas streams entering the SRU are often referred to as ‘SRU feed gas’ and are complex as they can include many different components at varying concentrations. It should be remembered that the feed streams entering the SRU are a result of prior processes – stripping and hydrotreating. As such, they can be impacted by changes in the plant feedstocks and process upsets, resulting in significant changes to their make-up. Hydrogen sulfide (H2S), carbon dioxide (CO2), ammonia (NH3) and ‘hydrocarbons’ (THC) are the most common constituents, with H2S having the highest expected concentration. In the reaction furnace, the SRU feed gas is mixed with air or pure oxygen and heated to produce sulfur dioxide (SO2). This is shown in reaction 1 below. The SO2 will then react with H2S in the converters and elemental sulfur will be produced, see reaction 2 below. Modified Claus reaction (heat) 3H2S + 3/2O2 ---> SO2 + 2H2S + H2O SO2 + 2H2S ---> 3/x SX + 2H2O

(1) (2)

Historically, SRU operators attempted to maintain a strict 2:1 ratio of H2S:SO2 to ensure reliable operation and April 2021 50 HYDROCARBON ENGINEERING

high SX recovery. With different licensors and users constantly modifying their equipment and processes, the actual H2S:SO2 ratio may be different than 2:1. In any case, designers and users do strive to maintain a proper ratio of H2S:SO2 throughout the converters and condensers. A process engineer can see how important it is to control the flow of feedstock into the SRU or the amount of air/oxygen injected to maintain a proper ratio. Experienced SRU engineers know that management of feedstock and oxygen flow rate is not too difficult when the incoming components and concentrations are consistent and known. Issues arise when the feedstock begins to vary. When hydrocarbon concentrations are suddenly changing, the impact on the SRU can be significant. The hydrocarbons consume more of the available oxygen, reducing the amount of H2S being converted to SO2 in the reaction furnace. From Figure 2 and Table 1, it can be seen that the amount of oxygen being introduced to the reaction furnace needs to increase as more hydrocarbons enter the reaction furnace, and reduced as the hydrocarbons ‘go away’. Some SRU professionals have said that problems arise not when the hydrocarbons come in, but rather when the hydrocarbons suddenly go away. What they have experienced is that the excess oxygen being introduced into the reaction furnace results in excess SO2 formation. This results in SO2 breakthrough to the TGTU, causing damage to the amine found in TGTU absorber. Costs of US$40 – 50/litre are common for specialised amines, so damages not only result in possible plant shutdown or TGTU bypass (higher SO2 and H2S emissions will need to be reported), but also increased operational expense. Conversely, SRUs that have extremely efficient converters and condensers, or lower recovery requirements, may not have a TGTU present. For these applications, end users have noted that a sudden increase in hydrocarbons requires operators to get on the air in the incinerator (thermal oxidiser) to prevent a temperature condition at the emission stack. AMETEK has a dual analytical bench analyser that is specifically designed to measure the incoming SRU feed gas components and their concentrations. The IPS-4 analyser utilises both an ultraviolet (UV) and infrared (IR) bench to measure in real time the components and concentrations, and houses a fit for purpose sample conditioning system in one enclosure. Coupled with a double block heated acid gas (HAG) probe, the IPS-4 Feed Forward solution has been installed at SRUs around the world.

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Figure 2. The sudden increase in hydrocarbons entering the

SRU results in an increase in H2S after the final condenser. SO2 concentrations would decline and the desired ratio would not be met.

Table 1.Hydrocarbons ‘steal’ the O2 intended for H2S to SO2 conversion Compound

Moles O2 per mole Ratio of O2 needed per mole HC HC compared to per mole H2S

Methane

Ethane

3.5

Propane

Butane

6.5

Pentane

Hexane

9.5

Tail gas/air demand analyser (AT3) A tail gas or air demand analyser is located after the final condenser and is present in nearly every SRU. Measurements here are often referred to as ‘feedback control’, as they provide feedback on the (nearly) final product. This feedback control is responsible for approximately 10% of the air/oxygen that is entering the reaction furnace – the remaining 90% is typically designed into the system. Measurement at this point is the most reliable way to ensure the proper ratio of H2S to SO2 has been maintained after the reaction furnace and provides final component concentrations before the TGTU or thermal oxidiser. With such a high installation and utilisation rate, and so many articles readily available on the purpose of the tail gas/air demand analyser, it is only necessary to briefly touch on some key items to consider: As previously mentioned, the ideal ratio of H2S:SO2 in the SRU is typically 2:1. Most plants operate with up to 2 – 4% H2S and 1 – 2% SO2 expected at the condenser outlet, but some require lower or higher ranges based on engineered design or sulfur recovery requirements. It should be kept in mind that it may be necessary to use ranges that cover upset conditions, so that operators can get back to proper operations after something unexpected occurs prior to or at the reaction furnace. April 2021 52 HYDROCARBON ENGINEERING

Ensure proper thermal management of the sample gas throughout the analyser system – probe to analyser to return location. SX is unique in that its phase can change very easily when sample handling temperatures are not properly maintained. If the sample temperature is not maintained high enough, the SX can condense as a solid, resulting in blocked sample gas analyser inlet and outlet lines. If sample temperatures are too high, the SX can go from the desired gas phase to a gelatinous one. This too can result in blocked inlet and outlet sample lines, or contamination of the gas analyser optical cell. Money spent on a well-proven design will pay for itself in analyser uptime and reduced maintenance. Focus on measurement requirements and not just the technology used in the analyser. It is important to select an analyser system that provides the measured components and concentrations that are required and that a team can operate and maintain. It is recommended to search for references within the sulfur community.

Tail gas treatment (AT4, AT5, AT6) For SRUs equipped with TGTUs, proper analyser selection and installation can result in high measurement availability (high uptime) and prevention of significant operational expenses when the unexpected occurs. Not every SRU contains a TGTU, as super-efficient conversion and condensing of SX may not require final treating prior to the thermal oxidiser at the emission stack. For those SRUs that do have a TGTU, there are two locations that could most benefit from some type of gas analysis. TGTUs almost always include a reduction reactor, catalyst – cobalt molybdenum (CoMo) or other proprietary active material, a quench tower, an absorber, and a regenerator. Gases enter the TGTU after having nearly all of the SX removed and, after moving through the TGTU, the gases are sent to a thermal oxidiser before being emitted through the stack with as little H2S and SO2 as possible – exact limits or emission rates are often defined by local environmental requirements. Between the reduction reactor and the quench tower, gas from the final condenser is heated and mixed with an excess amount of hydrogen – often injected, but sometimes already present in the tail gas – to convert any remaining sulfur components (that are not H2S) to H2S. Formulas 3 – 7 indicate the reactions that take place in the CoMo reactor: SO2 + 3H2 ---> H2S + 2H2O S + H2 ---> H2S H2O + CO ---> H2 + CO2 COS + H2O ---> CO2 + H2S CS2 + 2H2O ---> CO2 + 2H2S

(3) (4) (5) (6) (7)

Some users have chosen to measure SO2 and/or H2 at this location, AT4 on Figure 1, to ensure that SO2 is not

Sulfur recovery unit workers have a lot to worry about. Analyzers shouldn’t be one of them. Managing all the processes in a sulfur recovery unit (SRU) is arduous work—demanding skill, concentration, and dedication through every shift. Fortunately, the reliability, accuracy, robust design, and operating ease of AMETEK analyzers can make that tough work a little easier. AMETEK engineers have been designing industry-standard SRU analyzers for decades, and that shows in the products’ accuracy, reliability, and longevity. Because we make analyzers for every part of the process—from acid-feed gas to tail gas to emissions, including the gas treating unit, sulfur storage (pit) gas, and hot/wet stack gas—you get the convenience of one source for unparalleled engineering and support for all your analyzers, while your operators benefit from consistent interfaces and operating procedures. For decades, we’ve been dedicated to making your SRU operation the most efficient it can be for the long term. Learn more at www.ametekpi.com/SRU.

conversion of SO2 to H2S prior to the absorber. COS and CS2 measurements help complete the plant sulfur balance calculations, but more importantly indicate an issue with the catalyst found in the CoMo reactor. As the catalyst ages, the COS and CS2 levels will rise (Figure 3). Figure 3 actually details two different issues with the TGTU operations. The increase in COS readings indicated a problem with the CoMo catalyst properly Figure 3. Unexpected upsets in the TGTU, captured by a gas analyser. converting sulfur species to H2S. After the catalyst was replaced – note 1 week of no entering the absorber where it is known to damage amine analyser readings – the TGTU was started back up and (as previously mentioned). However, for most operations, the H2S readings were much higher than expected. The end user subsequently made corrections to their amine this location is not ideal. SO2 concentration usually is at a very low ppm level, leading users to question whether the regenerator. The net result was that the user was able to analyser is reading correctly, the sample often has a high properly repair their TGTU, and not shut down the dew point requiring water removal, and is highly toxic. It is entire SRU to troubleshoot the entire system. This saved known, however, that if a proper amount of excess H2 is time and considerable expense. maintained elsewhere in the TGTU, SO2 will be converted One final point to note about the quench tower (formula 3). H2 concentrations do not change much from outlet and absorber outlet measurements is that the the inlet of the quench tower to the thermal oxidiser, so sample at these points is extremely hazardous to human users have moved to measuring H2 before and after the life. Use of a heated sample probe that integrates a absorber instead. single inlet and outlet tap and double block mechanism In the quench tower, the H2S in the gas stream is – such as AMETEK’s HAG probe – is recognised as a cooled and removed from the TGTU, with the resulting requirement and not an option. ‘sour water’ often returned to the reaction furnace at CEMS (AT7) the beginning of the SRU. At the top of the quench Measurements at the thermal oxidiser are driven by tower, commonly referred to as the quench tower regulatory requirements. Many users are required to outlet, H2 is measured, as little to none should be swept away by the cooling of the quench tower. This is a much measure SO2, NOX, H2S, CO, CO2 and sometimes O2 concentrations. Most of the regulated components are more reliable measurement point for H2, as the dew point is usually much lower, making sample handling going to be present in low ppm concentrations. There much easier. Engineers may also measure H2S at this are many technologies used by many suppliers of location for material balance purposes or to measure continuous emissions monitoring systems (CEMS), but it the efficiency of the absorber (absorber outlet is critical to consider where this measurement is H2S/absorber inlet H2S). AMETEK has found that H2 occurring. The SRU is constantly handling and converting analysis at this location is required for confirmation that a gas stream that is highly toxic and corrosive. AMETEK’s the TGTU is operating correctly and that the amine in experience indicates that careful consideration of the absorber is protected from SO2 upsets. potential upset situations leads to design and In the absorber, any remaining H2S is removed by implementation of the most reliable measurement amine or other stripper. The stripper is then recycled in systems. A system that is designed to handle any SX or SO3 carryover is going to be more complex and more the regenerator and the H2S that is removed in the regenerator is again returned to the reaction furnace at expensive, but maintain a much higher uptime in the SRU the start of the SRU. Gas exiting the absorber ‘overhead’ than one designed to measure furnace effluents (as an is then directed to the thermal oxidiser. H2S example) elsewhere in the plant. The increased uptime measurement is universal at this point, as it directs reduces fines from regulatory agencies that can quickly sample and air flow rates at the thermal oxidiser prior to exceed the price difference between a basic CEMS and final release of the completely treated gas to the stack. one designed for purpose. This is another measurement The company’s experience indicates users are also point for which working closely with other members of measuring H2, carbonyl sulfide (COS) and carbon the global SRU community is recommended, in order to disulfide (CS2) at this point: solicit feedback on best solutions and not focus on a The H2 measurement at this point is a back-up to H2 specific analytical technology. In being completely analysis made after the quench tower. This transparent, AMETEK integrates a variety of technologies redundancy is driven by a desire to confirm that when asked to provide an SRU CEMS, based on excess H2 has been present, resulting in complete experience and end user requests. April 2021 54 HYDROCARBON ENGINEERING

Hydrocarbon Engineering presents a selection of sulfur technologies and services currently available to plant and refinery operations.

AMETEK Process Instruments For producers that need to reduce or remove the amount of sulfur present in their hydrocarbon products or emissions, the sulfur recovery unit (SRU) is recognised as a critical operational unit. The reaction furnace, converters, condensers and (sometimes) tail gas treatment units (TGTUs) found in a typical SRU work together to convert the hazardous and regulated hydrogen sulfide (H2S) found in the acid gas or sour water stripper gas – delivered from various process units in a natural gas processing plant or refinery – into elemental sulfur. In nearly every SRU, an air demand analyser (ADA), sometimes referred to as a tail gas analyser, measures H2S and sulfur dioxide (SO2) concentrations after the final condenser, and sends this information back to a control system that manages the acid gas and oxygen feed rates and reaction furnace temperature. This is frequently referred to as feed back control and is present in nearly all SRUs. Over the past decade, process engineers have continued to identify ways to increase sulfur recovery efficiencies and reduce

operational expenses, and many have additional measurement locations in an SRU. Measurement of the composition of the incoming acid gas can provide control systems with data that can be used to make increasingly precise process adjustments. Instead of relying on just the ADA data, processes can be adjusted to account for changes in the H2S, CO2, NH3 and hydrocarbon that are the result of unplanned upstream process upsets. Hydrocarbon concentration is most critical to respond to, as the hydrocarbons can bind with the oxygen or air being injected to convert H2S to SO2, and ultimately, elemental sulfur. To achieve sulfur removal efficiency requirements and prevent catalyst or other hardware damage, this sample analysis needs to be continuous with no sample lag time. Measurements of H2S, SO2 and hydrogen (H2) in the TGTU can be used to ensure that excess H2S and SO2 are captured and recycled back to the front end of the SRU. In addition to supplying thousands of air demand analytical solutions around the world, AMETEK is also recognised as a leading supplier of feed gas and tail gas treatment solutions. HYDROCARBON 55

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Black & Veatch Black & Veatch is a leader in the design and construction of sulfur recovery units and related sulfur management facilities. The company has over 70 years of design-to-construction experience covering the complete range of sulfur recovery applications. Total sulfur production of Black & Veatch designed units exceeds 47 000 long tpd (approximately 25% of the world’s current production). Sulfur recovery has been an active core technology for the company’s oil and gas business, and one in which several proprietary positions have been developed. This experience includes a variety of Claus plant tail gas treatments, including Amoco’s Cold Bed Adsorption (CBA), ARCO’s Tail Gas Cleanup, and Shell ‘s Claus Off·Gas Treating (SCOT). Black & Veatch, in conjunction with major burner technology providers, offers proprietary oxygen enrichment technology to gain additional capacity from existing sulfur recovery units. The company’s sulfur experience encompasses both natural gas and petroleum refinery applications and includes engineering the upstream amine treating and sour water processes, which have resulted in projects over the full range of acid gas compositions, sulfur recovery technologies, tail gas

Brimstech Corp. The main problem of a sulfur forming package is creating lump sulfur inside the granulation drum, which poses several barriers to meeting the requirements of the Sulphur Development Institute of Canada (SUDIC), such as: Decreasing heat transfer from the body of the granulation drum. Decreasing the amount of granular sulfur between blades on the body of a granulation drum. Disturbing the creation of sulfur curtains inside the granulation drum. Increasing the range of size distribution and decreasing the quality of granular sulfur because of the availability of crushed sulfur in output. Unbalancing of the granulation drum and dedicated motor and gearbox. After the creation of a sulfur lump inside the granulation drum, it shall be turned off and lumps shall be cleaned on a regular basis; therefore, it wastes a lot of operating time and also the daily production rate is decreased because of the cleaning period. Parameters such as humidity, temperature of sulfur, temperature of water, ambient temperature and seed generation rate have an impact on the creation of the lump. Although there is no control on these parameters during the granulation process, the major parameter which leads to creation of a sulfur

Comprimo® With a depth of industry experience, Comprimo offers a broad technology portfolio for all associated sulfur block technologies in relation to gas treating and sulfur recovery. The April 2021 56 HYDROCARBON ENGINEERING

clean-up, sulfur degassing including the proprietary MAG® system, sulfur storage, and solid sulfur forming technologies. The company provides conceptual process design, optimum process selection and configuration, development of basic process design packages, and execution of full scope EPC services for new units and for the revamping of existing facilities. It also offers complete commissioning/startup assistance including operating support, training, and troubleshooting. Recent projects include detailed engineering and procurement for the addition of a new 2025 tpd tail gas treating unit (TGTU) to the existing 3 x 675 tpd Claus/CBA SRU trains at Reliance’s Jamnagar refinery complex in India. This TGTU was commissioned in May 2019. The unit has successfully demonstrated overall sulfur recovery efficiency of 99.9% and other guarantee parameters as per performance testing carried out at design throughput during the month of January 2020. This TGTU is very similar to another Black & Veatch designed TGTU operating at the same facility. These two TGTUs are the largest in the world. Since 1915, Black & Veatch has continued to deliver innovative and sustainable solutions to the oil and gas industry – some well-established, and some emerging.

lump is a lack of enough seed in the granulation drum. In addition, parameters such as water flow rate and air flow rate may be changed in order to control seed generation rate as well as quality of output sulfur. Considering a new option, so as to provide more flexibility for seed generation rate, leads to a huge difference in the quality and capacity of the sulfur granulation package. In the old, traditional method, all sulfur spray nozzles are installed on a header, and sulfur is fed into the spray nozzle just through one steam jacketed pipe. Sometimes these nozzles are choked because of the small size of the hole on the nozzles and the granulation process will be disturbed. In order to tackle this issue, a liquid sulfur header including two headers which are 1 in. and 2 in. sulfur pipe is installed inside the granulation drum, rather than just one sulfur header which is surrounded by a 5 in. steam jacketed pipe. The last two spray nozzles of the liquid sulfur header are fed through 1 in. sulfur pipe and the remaining liquid sulfur spray nozzle, including two more seed generation spray nozzles, are fed through 2 in. pipe. Consequently, the choking risk of seed generation spray nozzles is decreased dramatically. In addition, sometimes the amount of seed is higher than the requirement, and the percentage of under size is more than the requirement of SUDIC. Therefore, a valve is considered on a 1 in. sulfur header and it might be closed manually when seed generation rate is higher than the requirement in order to increase flexibility, the daily production rate and the operability of the granulation drum, as well as decreasing cleaning time.

company’s suite of technologies provides a solution at low CAPEX and OPEX levels to meet local sulfur recovery efficiency regulations and give operators confidence and peace of mind. The company has more than 65 years of experience and expertise in the development, application and management of

Delivering sulphur solutions for a more sustainable world

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Our large range of technology solutions ensures our customers keep their costs low, reduce their carbon footprint and meet or exceed their sulphur recovery targets.

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gas treating and sulfur process technologies, with more than 1200 licensed sulfur recovery units worldwide. Excellent technology is available to deliver optimised solutions for every project, backed by the engineering delivery capability of the combined Worley organisation. With five execution centres supported by a comprehensive global network of experts, the company is able to provide clients with responsive technical

Delta Controls Corp. Delta Controls Corp. is an internationally recognised expert in designing, engineering, manufacturing, and supporting process equipment. Delta Controls’ 49 years of instrumentation design expertise allows its Louisiana-based company to provide innovative and quality solutions for demanding applications. Delta Controls’ ClausTempTM division is dedicated to researching, engineering, and manufacturing temperature instrumentation for Claus thermal reactors in sulfur recovery service. Model HTX ClausTempTM Thermocouple is specifically designed for Claus thermal reactors and is a premier thermocouple of measuring sulfur recovery unit temperatures. The HTX is suitable for temperatures up to 1700˚C and utilises a separate outer refractory thermowell that provides protection from thermal shock and shifting refractory. The nozzle insulating kit (Model HNP) simplifies installation and protects against sulfur build-up in the nozzle, while the flush gas station (Model HFS) maintains proper internal flush gas pressure and continuous flow prevents corrosion of the thermocouple element wires. The Model HTS ClausTempTM Compact Thermocouple is designed for smaller process connections and does not include the outer refractory thermowell, while the unpurged Model HTV ClausTempTM Thermocouple uses the patent-pending

Enersul Ltd Partnership Enersul Ltd Partnership, headquartered in Calgary, Alberta, Canada, has been a leader in sulfur forming, handling, storing and loading for more than 60 years. With over 100 000 tpd of installed capacity, the Enersul GX is a popular sulfur granulation process choice for producers of premium sulfur granules around the world. The company offers several versions of the process, with varying production capacities ranging from 50 to 1700 tpd per unit. The GX suite of granulation technologies is being continuously improved and optimised, and customised configurations of the process can be offered to meet any daily production requirements. The MODEXTM sulfur remelter represents a significant breakthrough in sulfur remelting. The system arrives 90% pre-assembled, enabling efficient on-site installation and commissioning. It has been successfully commissioned in

Haldor Topsoe Topsoe has launched its new technology line, ‘Smarter Sulfur Solutions’, comprising the technologies listed here. April 2021 58 HYDROCARBON ENGINEERING

support and access to over 100 dedicated sulfur experts. Through strategic relationships with other technology suppliers, Comprimo continues to expand its portfolio. A prime example of this is the addition of TopClaus® to its tail gas treating technologies, which combines the know-how of Comprimo with respect to sulfur recovery and Haldor Topsoe’s knowledge of wet sulfuric acid technology. QSeal technology and an additional monocrystalline sapphire thermowell. Model HIR ClausTempTM Pyrometer detects the intensity of infrared energy radiated by the refractory hot face in a Claus thermal reactor. This sensed energy is converted into an electrical signal which accurately displays the temperature. The electronics employ a dual-wavelength ratiometric measurement that is unaffected by flames, partial nozzle obstructions, or coated lens windows. HIR’s maintenance-free design uses a unique lens assembly heated with a steam jacket, preventing sulfur build-up and eliminates the need to clean the viewport glass. The loop-powered, drift-free electronics does not require frequent calibration service. Model HIP ClausTempTM Handheld Pyrometer is a robust tool for troubleshooting Claus thermal reactor temperature measurement issues and calibrating permanently installed pyrometers. The HIP utilises the same sensor and electronics as Model HIR and measures temperature using reactor sight ports and pyrometer lens windows. Delta Controls’ sulfur instrumentation products are used in over 150 sulfur plants internationally, including refineries, gas plants, and upgrade facilities. The company’s products are engineered to provide freedom from maintenance and also improve maximum uptime, resulting in lower maintenance costs for SRU plant operations.

Western Canada to melt sulfur feedstock with up to 20% contamination. The SafeFoam Transfer System (STSTM) is a sulfur handling technology that reduces sulfur fines generated at critical transfer points, resulting in safer and more environmentally friendly sulfur handling. The system arrives skid mounted and 90% pre-assembled. Initially developed in response to specific customer requirements, Enersul also offers the HySpecTM H2S degassing process. This modular solution offers quick, effective and economical H2S degassing of liquid sulfur to 10 ppm or less. Enersul has pioneered many of the technologies and practices currently used by the global hydrocarbon industry to effectively process, handle, store and load sulfur. The company has an experienced team of in house and on-site representatives to support its product offerings, including after sales site services, aftermarket parts supply and on-site training services.

While none of the technologies are brand new, they are now assembled under one headline. WSA (Wet gas Sulfuric Acid), known and appreciated in a multitude of industries since the 1980s, turns sulfurous

off-gasses into concentrated sulfuric acid of commercial quality with unsurpassed energy efficiency, SNOXTM flue gas desulfurisation, also removing NOX and particulates, without consuming limestone and without generating gypsum. The high energy efficiency of a SNOXTM unit helps reduce specific CO2 emissions from heaters, boilers and power plants by up to 10%, TopClaus®, jointly developed with Comprimo, is a combination of two proven technologies, Claus and WSA. TopClaus delivers effective sulfur removal at lower initial cost and lower operational costs than a Claus unit with conventional tail gas treatment. The Claus unit converts sulfur compounds in the feed streams to elemental sulfur with 95 – 97% efficiency. Residual sulfur is removed in the WSA unit, bringing the total sulfur recovery up to typically 99.9%, but higher recovery is possible when needed. The WSA unit produces sulfuric acid that is returned to the Claus unit to be reprocessed to elemental

IPCO IPCO designs and delivers sulfur processing and handling systems to the strictest production and environmental parameters, with a typical turnkey project covering everything from pumping liquid sulfur from the storage tank to loading equipment for the solid end product. The company has an in-depth understanding of the sulfur market’s requirements and can deliver effective solutions for molten sulfur truck and rail car loading, block pouring, solidification, downstream storage and reclamation, as well as bulk loading for truck, rail car and ships. In terms of solidification, there are systems available to meet all throughput requirements. For small to mid-size capacity operations, the Rotoform system offers excellent product uniformity and environmentally friendly operation. The efficiency of this single step, liquid-to-solid process results in high quality pastilles of uniform shape and size, free-flowing for easy handling, while a predictable high bulk density is a major advantage in terms of storage and transportation. For higher capacity sulfur solidification requirements, the SG system offers the state-of-the-art in sulfur drum

Merichem Company Merichem offers multiple treating systems that remove H2S, COS and mercaptans from gas and liquid hydrocarbon streams ranging from natural gas to condensates and light crude oils. For caustic treating systems, the company’s proprietary and patented FIBER FILM® Contactor is the core of its THIOLEXTM technology that combines extremely high mass transfer area with minimal shear mixing while generating almost no aqueous phase carryover. As supporting technology, Merichem offers a full suite of caustic regeneration (REGEN®) systems that can be configured with THIOLEX, depending on the treating need to reduce caustic consumption. The removed H2S is converted to a safe, soluble sodium salt. Mercaptans are converted to an oil that is removed from the system. THIOLEX and REGEN technologies have been installed

sulfur. TopClaus is well suited for both greenfield projects and revamps. SmartSARTM for regeneration of spent sulfuric acid from alkylation and other operations without producing sour wastewater. SweetPlusTM for cleaning of difficult fuel gasses to allow them to easily be used as fuel or even feed for hydrogen production, for example. SweetPlus combines a hydrogenation process with the WSA process to deliver sweet fuel gas, and the sulfur is removed in the form of concentrated sulfuric acid. Haldor Topsoe is a world leader in catalysts and technologies that help the industry control sulfur levels in fuels and emissions. The company has licensed more than 165 units for removing sulfur from various gasses and waste streams. Topsoe’s hydroprocessing technologies and catalysts are widely used to remove sulfur, nitrogen, oxygen and metals from various oil fractions. The company is a leader in the production of ultra-low sulfur diesel and processing of renewable fuels.

granulation. This product line consists of two sizes: the SG30, which is the highest capacity drum granulator on the market, and the SG20, which is a medium-sized unit. The first SG20 has recently been commissioned and is already exceeding expectations. This latest version of the technology has design enhancements that are taking sulfur drum granulation to a new level of performance and operator experience. It is a surprisingly quiet machine, operating far below standard noise level limits. A revamped layout provides easy access to all components for observation and maintenance. New design features have resulted in major reductions in cleaning requirements; any operator familiar with other drum granulators will immediately appreciate the cleanliness of this technology. The unit can be easily started and stopped at any time with the simple push of a button. Like all of the company’s forming technologies, it produces SUDIC quality product. Further definition of product parameters will soon push the limits of continuous runtime as IPCO strives for unlimited continuous runtime. IPCO looks forward to welcoming customers on-site in Italy to witness this latest advance in sulfur drum granulation.

around the world to treat streams ranging in size from <1000 bpd to 150 000 bpd, containing up to 10 000 ppm feed mercaptans and requiring less than 5 ppm total S in the product. LO-CAT® is a non-caustic based, liquid redox process that converts H2S in any gas stream to elemental sulfur, which is removed via filtering as a sulfur cake. It has achieved H2S removal efficiencies of 99.9+% in many different applications and industries including natural gas production, oil refining, biogas, landfill gas and many others. These applications range in size from a few standard cubic feet per minute to many million standard cubic feet per day, and from a few hundred pounds of sulfur produced each day to greater than 10 long tpd. The sour gas entering these LO-CAT systems contain anywhere from 100 ppmv H2S to 50+% H2S and pressures range from a few inches of water column up to 400 psig. HYDROCARBON 59

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Merichem has also introduced Ecotreat®, a treatment system that selectively removes H2S from sour gas streams using a sulfur-catalyst scavenger and produced water as a medium in the absorber. As a full-service licensor and provider of technologies, Merichem offers in-house design, engineering, and fabrication.

Optimized Gas Treating Inc. Optimized Gas Treating Inc. licenses a comprehensive commercial simulation software for the complete end-to-end sulfur processing system, from sour gas to degassed elemental sulfur in a single, seamlessly constructed flowsheet. Unit operations are built on a detailed mass and heat transfer rate basis, resulting in simulations that are truly predictive, in every sense of the word. The ProTreat® simulator models the treating of sour gases and hydrocarbon liquids to remove H2S, CO2, mercaptans, phenols, and HCN along with sour water rundown and stripping. The SulphurPro® simulator models Claus sulfur production from acid gas and SWS gas feeds. All units in the train can be monitored in real-time using the ProBotTM process analysis tool. ProTreat and SulphurPro can be licensed together or separately along with ProBot. AGR, AGE and TGTU simulations permit up to three-amine blends using all commonly-used commercial amines, including ammonia, proprietary speciality amines such as INEOS GAS/SPEC*, DOW UCARSOLTM and Eastman AdapT®, hot potassium carbonate (HotPot) promoted with any amine, as well as physical solvents such as DMPEG (e.g. Coastal AGR®, SELEXOLTM and Genosorb®-1753). Glycol dehydration units using MEG, DEG and TEG are modelled with accurate solubility data

The company offers customised design and equipment packages based on customers’ requirements and can provide proprietary equipment up to complete modular systems. Merichem maintains its own Technical Services group and provides customers with 24/7 free technical service support, advice, and data review.

for hydrocarbon and BTEX emissions using equations-of-state and activity models of public and private research (e.g. GPA, ASRL) and commercial data. Caustic soda and potash solvents are available for simulating mercaptans removal. Corrosion in the plant can be monitored using a fundamental chemistry, hydraulics and kinetics-based corrosion model. The SulphurPro simulator provides state-of-the-art analysis, design and troubleshooting for the Claus SRU and its variations (SELECTOXTM, MODOP, subdewpoint, SuperClaus®) based on validated kinetics for the conversion reactions (including catalyst deactivation) and additionally combustion, contaminant formation and destruction reactions (NH3, BTEX, COS, CS2, H2) in the thermal reactor and waste heat boiler. Built-in sulfidic corrosion monitoring is available for the fragile WHB tube-to-tubesheet joint area and elsewhere in the SRU exchangers. Sulfur condensers and reheaters can be analysed in rating and design modes. The hydrogenation reactor uses pore-diffusion limited kinetics, and even quench towers are simulated on a mass (water, H2S, CO2, NH3) and heat transfer-rate basis. The incinerator model predicts accurate emission rates from kinetics. The ProBot unit monitoring supervisor and process advisor allows the entire plant to be monitored in real-time, including acid-gas and sulfidic corrosion rates as well as system, subsystem and individual unit performance.

SBS Steel Belt Systems S.r.l. Founded in 1984, SBS Steel Belt Systems S.r.l. is an Italian company which produces steel belt machinery and turnkey plants for a wide range of industries, including oil and gas, petrochemical, chemical, food and pharma. In the field of oil and gas, the necessity to deacidify crude oil or natural gas requires the conversion of the removed H2S in elementary sulfur, which represents one of the main raw materials in various industrial fields. Sulfur can be sold in liquid form but in certain cases it is necessary to solidify it when long distance transportation is required. The company’s pastillation technology, based on Accudrop pastillator head, enables the transformation of liquid sulfur into solid regular hemispherical pastilles capable of resisting all handling and storing mechanical solicitations and minimising generation of dust, which is typical of brittle materials such as sulfur. SBS has been supplying a wide number of turnkey plants (packages) for sulfur solidification, where the company’s steel belt solidification units are often equipped with: Liquid sulfur pumps and filters. April 2021 60 HYDROCARBON ENGINEERING

Sulfur solidification line.

Liquid sulfur temperature preconditioners (when requested). Solid sulfur handling systems. Solid sulfur storage facilities with silos or by stockpiles. Solid sulfur bagging or truck/trains loading systems. Cooling systems to process cooling water. Steam/diathermic oil or electrical heating systems. H2S and sulfur dusts filtering units.

15-18 NOVEMBER 2021 HOTEL MELIA CASTILLA, MADRID, SPAIN

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In 2020, SBS completed the second phase of the Zohr project in Egypt, which is the twin of the previous plant supplied in 2017. SBS also delivered packages for sulfur solidification to major end users in Russia and Azerbaijan last year. Presently, SBS is manufacturing another solidification plant for a major end user in Russia, which includes the supply of high speed solidification units equipped with SuperAccudrop pastillation head, capable to overtake 15 tph of sulfur (for each solidification unit).

A tradition of SBS is the continuous development of its equipment/machinery, not only as far as production capacity is concerned but also in terms of quality of processed product. For this reason, in 2020, the company inaugurated a new test centre in its operative seat in North Italy. The new dedicated area is equipped with specific outfits to test sulfur pastilles’ quality according to SUDIC testing conditions, in order to evaluate the efficiency of each implementation of the solidification process with SBS machinery.

SensoTech The production of sulfuric acid is an important process. Monitoring the sulfuric acid strength online and in real-time enhances safety and efficiency of the plants. For this, the LiquiSonic® analyser from SensoTech can be used. Manual sampling is time-consuming and involves security risks. The laboratory analysis provides only delayed data, making a real-time intervention in the process impossible. Inline measuring methods monitor the sulfuric acid strength in real-time and thus enable a continuous measurement, providing the data online. The most suitable measuring method for determining the acid strength is sonic velocity measurement. Conductivity and density probes do not provide a clear signal between 80 – 95 wt% and 95 – 100 wt%. The LiquiSonic analysers (pictured) come up with clear signals over the complete range from 80 – 100 wt%. In the chemical, petrochemical and mining industries, the relevant concentration ranges are from 70 wt% to 100 wt% sulfuric acid, 20 wt% to 35 wt% oleum or 50 wt% to 60 wt% oleum. Here, the sonic velocity meters provide clear and high-precision data of the acid strength. For example, in alkylation units, LiquiSonic enables a lowering of the spent acid and an efficient control of the rate of fresh acid addition. In pickling and etching baths of the metal and chemical sector, the concentrations usually range between 0 – 30 wt%. In such processes LiquiSonic sensors also reliably measure the acid strength. In the bathes, sonic velocity is combined with a second physical value to determine the salt concentration simultaneously.

Siirtec Nigi Since the 1970s, Siirtec Nigi has been designing and providing its customers with tailored solutions, either air-Claus and air oxygen-enriched Claus, tail gas treatment (trademarked as HCR) which lets the sulfur recovery efficiency rise to more than 99.9%, and its own sulfur degassing process. The search for the best plant solutions has led to the development of the Advanced Ammonia Claus (ADC), where the disposal of larger quantities of ammonia is made possible compared to the traditional Ammonia Claus. In addition, Siirtec Nigi has also developed SplitOxy, an improved oxygen enrichment approach to revamp an SRU, limiting the reaction furnace temperature to reasonable levels while enhancing operational flexibility and control. In 2020, April 2021 62 HYDROCARBON ENGINEERING

The LiquiSonic® analyser from SensoTech precisely monitors the sulfuric acid and oleum strength and provides the data online and in real time.

If the measuring values exceed process thresholds, a signal will be sent immediately, ensuring timely countermeasures can be initiated. This significantly increases work environment safety and product quality, and reduces costs caused by acid waste. Both a too high and a too low concentrated acid are reliably detected, as well as acid runaways. The LiquiSonic Sensors are plug and play and installed directly into pipes or vessels. For process automation, the real-time data can be transferred to process control systems via multiple interfaces. Made of Hastelloy C-2000, the sensors are resistant to corrosion. The robust construction requires neither gaskets nor moving parts, meaning that the sensors are maintenance-free with long-term stability. The measuring values are completely stored in the controller. Through secure remote access, the user can operate the controller from a PC.

two sulfur recovery units were started up with this new technology, one in Colombia (Ecopetrol’s Barrancabermeja refinery) and the other one in Italy (API Ancona refinery). The sulfur degassing process performances have been improved (residual H2S in the degassed sulfur is less than 5 ppmw) while maintenance and restoration in the event of failure were minimised. In summary, Siirtec Nigi offers a full range of technologies for sulfur recovery, including sour water stripping (single or two column arrangement), gas sweetening and acid gas enrichment, modified Claus, Advanced Ammonia Claus, Ammonia Claus, SplitOxy and generic oxygen enriched air Claus, HCR (Claus tail gas clean up), sulfur degassing, and thermal and catalytic oxidiser with and without heat recovery section.

Sulphur Experts Decades ago, sulfur recovery was a money-making endeavour for refiners and gas processors. During that time, Sulphur Experts learned that the best way to maximise sulfur production – regardless of the kind of sulfur recovery unit (SRU) – was to maximise recovery efficiency. In other words, the aim was to maximise revenue by maximising performance. Today however, sulfur recovery is not a profitable endeavour but rather a necessary cost of doing business to meet regulatory and environmental standards for sulfur content in liquid and gas petroleum products. Despite this trend reversal, Sulphur Experts’ goal remains the same: to maximise SRU performance. However, maximising performance now means reducing operating costs – and sometimes capital costs – instead of maximising revenue. Either way, improved SRU performance has a direct benefit to a company’s bottom line: a dollar saved is a dollar earned. Sulphur Experts, based in Canada, the US, Europe, and Latin America, is recognised for providing quality analytical services to the sulfur recovery industry, enabling plants to optimise their units towards higher efficiency and reliability.

Wood Wood sulfur recovery technology (acquired from Amec Foster Wheeler) consists of licensed designs with over 50 years of experience and ‘know how’ in the following areas: revamps and upgrades, process simulation and basic design, equipment design and supply, plant layout and modular supply, and safety and operations. Processes included in Wood’s sulfur technology are amine treating and regeneration, conventional and two-stage sour water stripping, sulfur recovery, amine-based tail gas treating, SO2 scrubbing, and seamless integration of sulfur degassing and sulfur handling. Wood has been involved in over 500 sulfur-related projects worldwide, covering a wide range of feed compositions ranging in size from 4 to over 650 tpd and sulfur recovery efficiencies meeting requirements up to and exceeding 99.98% recovery to meet the most stringent environmental requirements. Wood’s Acid Gas Burner design utilises intense mixing with low pressure drop and provides an unobstructed view of the thermal reactor interior and waste-heat boiler tubesheet. The company’s thermal stage design achieves a compact layout and minimises the overall footprint. Continued burner improvement through computational fluid dynamics (CFD) and field trials ensure predictable operation.

Recent revamp case study A US refiner needed to improve the performance and safety of a 1970s vintage SRU.

This specialised sampling of difficult and dangerous process streams and subsequent use of proprietary analytical techniques is the basis for the evaluation. This is then coupled with a detailed engineering review of the resultant data, using expertise stemming from over five decades of testing plants around the world. In parallel, the company’s other divisions, Amine Experts and Dehydration Experts, use the same approach of specialised sampling and analysis of amine process systems. This has led to advancements in the understanding of these particular processes, all geared towards improving on-stream efficiency, protection of equipment, and safe operation. The efficient operation of these upstream units, in turn, means a more efficient and reliable operation of the SRU. Such testing and evaluation is carried out on a regular basis, mostly in response to a troubleshooting requirement, but increasingly more often as a preventative step. Over the years the data collected from the thousands of plant tests has also allowed Sulphur Experts to develop a series of international training programmes, focused on the efficient operation of amine and sulfur plants.

Wood assessed the equipment, controls and process scheme to fully understand the underlying issues. The company’s sulfur specialists designed an improved process flowsheet providing a solution that removed many of the operating problems, including a deteriorating sulfur pit. Redundancy for critical interlocks was added, and the instrumentation and overall control system were modernised.

New SRU/TGTU A refiner in the Eastern Mediterranean contracted Wood to deliver a process design and pre-FEED package for a new SRU and TGTU to provide redundancy in its sulfur recovery operations. Project challenges included a very low allowed SO2 emission limit (100 mg/Nm3) and relatively low feed stream pressure. These challenges were overcome by designing a robust Claus unit with excellent conversion and minimal residual COS and CS2 in the Claus tail gas. The TGTU was designed using formulated MDEA solvent to ensure efficient H2S removal in the absorber while minimising CO2 pickup. A key aspect of the design incorporated the vent stream from sulfur degassing into the thermal stage of the SRU, thereby eliminating the contribution of the vent to emissions. Wood’s advanced CFD modelling, combined with a thorough understanding of the combustion, mixing, heat transfer and reactions in the thermal stage, delivered the solution to meet the necessary low SO2 emission limit.

Zeeco

SRU reaction furnaces and high-intensity style burners

For more than 40 years, the sulfur industry has relied on Zeeco for combustion equipment that meets the stringent regulations and operating parameters for sulfur recovery units (SRUs).

The company’s high-intensity style burners achieve rapid combustion in very small volumes under a wide range of reaction furnace conditions. ZEECO® burners can operate under HYDROCARBON 63

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reducing (oxygen-deficient) environments without the smoke, soot, or oxygen slippage that cause damage to downstream catalytic reactors. The company’s spin vanes create a vortex recirculation zone upstream of the burner discharge so that hot flue gas is recirculated into the burner mixing zone, creating a highly stable flame front.

process typically occurs between 1200 – 1600˚F (650 – 870˚C) in the presence of excess oxygen with a residence time between 0.7 and 2 seconds. The company’s systems can incorporate waste heat recovery equipment to generate steam for other plant operations.

Acid gas flame monitoring Waste heat boilers, in-line heaters and sulfur condensers Zeeco can design and supply waste heat boilers, sulfur condensers and soot-free in-line heaters for SRUs. As flue gases reach the outlet of the reaction furnace, they are cooled in a fire tube waste heat boiler to condense any gaseous sulfur. The gases then pass to the sulfur condenser where residual sulfur compounds are catalytically converted to sulfur in one or more stages.

SRU thermal oxidisers The company’s thermal oxidiser applications with ZEECO FREE JET® ultra-low-NOX burners incinerate tail gas at very low flue gas NOX levels. The multi-stage combustion

The ZEECO ProFlame+ SRUTM integrated flame scanner provides reliable flame detection and strong background flame discrimination, even in challenging high-temperature processing environments such as SRU reaction furnaces or thermal oxidisers.

CFD capabilities Zeeco’s computational fluid dynamics (CFD) modelling capabilities help achieve predicted performance for thermal reactor and the tail gas incinerator packages. In particular, the company can assess ammonia and BTEX destruction levels, flame shape, as well as combustion air, fuel gas and flue gas distribution, including temperature, pressure and velocity profiles from inlets to outlets of the combustion chamber.

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