Hydrocarbon Engineering August 2021

August 2021

CLEAN & SUSTAINABLE

CO O L E R

BY DESIGN®

CONTENTS August 2021 Volume 26 Number 08 ISSN 1468-9340

03 Comment

29 The road to net-zero Robert Jolly, Johnson Matthey, UK, outlines how clean hydrogen can play a key role in the energy transition, if it is deployed now.

05 World news 10 Struggles in Southeast Asia Ng Weng Hoong, Contributing Editor, explains how Southeast Asia’s oil markets are struggling amid the continuing impact of the COVID-19 pandemic.

34 Severe-service solutions Robert Hsia, UnionTech, USA, introduces severe-service isolation solutions for hydrogen production via steam methane reforming (SMR).

39 Under pressure: the challenges of hydrogen compression Mark Barton, Luiz Soriano, John Stahley and Arja Talakar, Siemens Energy, USA, explain how hydrogen plays an essential role in a wide range of industrial applications and is increasingly emerging as a decarbonisation agent for the energy transition.

45 Optimising flow in parallel compressors Nabil Abu-Khader, Compressor Controls Corp., UAE, explores the operation of parallel centrifugal compressors using surge control.

50 Compressor Q&A 17 The best of blue hydrogen Yassir Ghiyati, Nitesh Bansal, and Mohammed Ilyas, Haldor Topsoe, Denmark, provide a review of the best available blue hydrogen technologies.

23 Blue routes Elias Xanthoulis, Andrew Board, Attila Racz and Tobias Roelofs, Comprimo, part of Worley, look at typical routes to blue hydrogen production, and how to maximise CO2 removal at high thermal efficiency in blue hydrogen facilities.

Hydrocarbon Engineering talks to a number of leading experts in compressor technology about efficiency, equipment reliability, safety and the environment, digitalisation, and life after the COVID-19 pandemic.

65 Simplifying the material specification Brandon Stambaugh, Owens Corning, USA, provides an in-depth look at common challenges faced when insulating an LNG facility.

71 A clean air strategy Matt Halsey, Servomex, UK, explains how hydrocarbon processing plants and refineries can implement cleaner air strategies using gas analysis.

75 A more sustainable future William Vickers, Ionix Advanced Technologies, UK, explains the contribution that corrosion monitoring technology can make towards increased industry sustainability.

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s I write this comment, the British Grand Prix (GP) motor race has just taken place at the Silverstone circuit in England, and was controversially won

by British driver (and current world champion) Lewis Hamilton. Now, I’m no expert in Formula 1, so I won’t get into the complexities of Hamilton’s victory here, suffice to say that he crashed into his closest rival, Max Verstappen, taking him out of the race. Hamilton received a 10-second time penalty for his role in the collision, but was still able to go on to win the race. In the aftermath, Verstappen reacted angrily to Hamilton’s victory (and his “disrespectful” celebrations, in particular), and Hamilton was also subjected to racist abuse on social media, all of which resulted in the British GP grabbing even more headlines than it usually would.

However, before the race had even begun, some interesting comments from Formula 1’s Managing Director, Ross Brawn, had caught my attention. In an interview with the BBC, Brawn suggested that hydrogen-powered cars could be the future of the sport. Emphasising that sustainability is a central objective of Formula 1, which has made a commitment to become carbon neutral by 2030, Brawn said: “Maybe hydrogen is the route that Formula 1 can have where we keep the noise, we keep the emotion but we move into a different solution.” Zak Brown, the Chief Executive of racing team McLaren – who made a commitment to carbon neutrality in 2011 – has said that there is a lot of interest in the potential of hydrogen among racing teams: “The challenge that we have is to make sure that it is safe and can produce the amount of power that’s required to do the lap times that we do, and hydrogen is very much on the table.”1 As the world transitions into a more sustainable future, there is growing consensus that hydrogen will have a key role to play. This issue of Hydrocarbon Engineering includes a special focus on hydrogen (starting on p. 17), with a number of articles outlining the exciting opportunities that clean hydrogen can offer across various industries and applications. The articles also look specifically at how blue hydrogen may hold the key to unlocking the full potential of hydrogen in the energy transition.

And on the topic of environmental sustainability, Palladian Publications is proud to announce that we now use Carbon Balanced Paper in all of our publications, including Hydrocarbon Engineering and our supplement, Tanks & Terminals. Carbon Balancing is delivered by the World Land Trust, an international conservation charity, who protects the world’s most biologically important and threatened habitats. Its Carbon Balanced Programme offsets emissions through the purchase and preservation of high conservation value forests. Through land purchase of ecologically important standing forests under threat of clearance, carbon is locked that would otherwise be released. These protected forests are then able to continue absorbing carbon from the atmosphere. This is now recognised as one of the swiftest ways to arrest the rise of atmospheric CO2 and global warming effects.

For more information about the initiative and the environmental benefits that it provides, visit: www.carbonbalancedpaper.com.

1.

ROWLATT, J., ‘Formula 1 boss Ross Brawn says hydrogen could be future fuel’, BBC, (15 July 2021).

HYDROCARBON

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August 2021

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WORLD NEWS USA | Linde

plant

starts up new liquid hydrogen

L

inde has announced that it has started up its fifth liquid hydrogen plant in the US, reinforcing the company’s robust supply network of plants in California, Alabama, Indiana and New York.

The new plant in La Porte, Texas, will supply over 30 tpd of high-purity liquid hydrogen to meet growing demand from Linde’s customers. The liquefier takes hydrogen from Linde’s approximately 600 km US Gulf Coast pipeline, which has over 15 independent hydrogen production

sources, giving it a reliable feed supply.

Linde will purify and liquefy the hydrogen before supplying it to end markets including material handling, mobility, aerospace, manufacturing, metals, energy and electronics.

The new plant aims to boost the reliability of Linde’s existing network, as well as make the supply chain more efficient and increase availability to serve the rising demand for both conventional and clean hydrogen.

France | TotalEnergies

partners with Technip Energies to advance low-carbon solutions

T

otalEnergies and Technip Energies have signed a technical cooperation agreement to jointly develop low-carbon solutions for LNG production and offshore facilities to accelerate the energy transition.

As part of this agreement, both parties will explore new concepts and technologies in order to reduce the carbon footprint of existing facilities and greenfield projects in key areas, such as: LNG production, cryogeny, production and use of hydrogen for power generation, or processes for

Albania | Excelerate

E

carbon capture, utilisation and storage (CCUS).

The qualification of new architectures and equipment that will be developed in these areas is also part of the agreement.

This partnership is based on a common belief that cooperation across the industry is needed to achieve energy transition goals. By partnering, Technip Energies and TotalEnergies rely on complementary expertise to decarbonise LNG plants and offshore facilities.

Russia | McDermott

awarded engineering and procurement contract for GCC project

M

cDermott International Ltd has announced that it has been awarded an engineering and procurement contract for a spent caustic treatment solution on the Gas Chemical Complex (GCC) project from Heat Transfer Technologies DMCC (HTT).

The GCC project is owned by Baltic Chemical Plant LLC, a subsidiary of RusGazDobycha. It is one of the largest polyethylene integration projects in the world and is located near Russia’s shores in the Gulf of Finland.

McDermott’s scope includes license technology rights, basic design engineering package (BDEP), module detailed engineering design and full procurement of main equipment. The modularised solution for the spent caustic treatment solution will be an integral part of the GCC project and enable the project’s production of up to 3 million tpy of polyethylene.

This award follows McDermott’s successful completion of front end engineering design (FEED) and ongoing early works on the GCC project.

Energy, Snam and Albgaz ink MoU

xcelerate Energy L.P., Snam S.p.A, and Albgaz Sh.a have signed a Memorandum of Understanding (MoU) in Tirana, Albania, to explore potential cooperation for the construction of a natural gas pipeline from the Albanian Vlora terminal to other natural gas infrastructure opportunities in Albania.

Under this MoU, Excelerate, Snam, and Albgaz will explore joint solutions, which could potentially supply underground gas storage in Albania, providing crucial energy security to the region.

Snam and Albgaz’s Albanian Gas Service Co. Sh.A, who maintain the gas transmission network in Albania,

could potentially operate and maintain the future pipeline.

The MoU was signed at the Palace of Congresses in Tirana by representatives from each entity. The planning is expected to begin immediately with representatives from each company forming a coordination team.

HYDROCARBON

ENGINEERING

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August 2021

WORLD NEWS DIARY DATES

announces ethylene plant performance success

21 - 23 September 2021

T

Gastech Dubai, UAE gastechevent.com

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

21 - 23 September 2021 LARTC Online worldrefiningassociation.com/lartc

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

04 - 06 October 2021 ILTA Houston, Texas, USA ilta2021.ilta.org

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

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

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

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

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

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

August 2021

6

HYDROCARBON

ENGINEERING

China | Technip

echnip Energies has announced that the Bora LyondellBasell Petrochemical Co. Ltd’s 1000 tpy ethylene plant has reached performance guarantees.

Technip Energies provided the proprietary technology and process design for the liquid ethylene plant in Panjin, Liaoning Province, China.

The Bora facility utilises Technip Energies’ Ultra Selective Conversion (USC®) U-coil and W-coil ethylene technology, which

combined produce high energy efficiency and high yields, resulting in reduced CO2 emissions.

The plant successfully started up in the middle of 2020 to reach its designed capacity shortly after the start-up and performance guarantee were met. By passing all performance guarantees, it is meeting the feed and raw material consumption, production rate and product specifications and the specific energy consumption intended.

USA | EIA:

refinery closures decreased US capacity during 2020

A

s a result of several US refinery closures in 2020, US operable atmospheric crude oil distillation capacity, the primary measure of refinery capacity in the US, dropped 4.5% to a total of 18.1 million bbl per calendar day (bcd) at the start of 2021, reports the US Energy Information Administration (EIA).

The end-of-year 2020 total is 0.8 million bcd less than the 19 million bcd of refining capacity at the start of 2020. According to the data in the EIA’s annual ‘Refinery Capacity Report’, the beginning of 2021 marks the lowest annual

capacity figure to start the year since 2015. Based on information reported to the EIA in its recent update, US refining capacity will not expand significantly during 2021.

At the beginning of 2021, 129 refineries were either operating or idle in the US (excluding US territories), down from 135 operable refineries listed at the beginning of 2020.

The additional refinery closures in the 2021 ‘Refinery Capacity Report’ largely reflect the impact of responses to COVID-19 on the US refining sector.

Canada | Shell

proposes large-scale CCS facility in Alberta

S

hell has announced a proposal to build a large-scale carbon capture and storage (CCS) project at its Scotford complex near Edmonton.

This would be a key step in transforming Scotford into one of five energy and chemicals parks for Shell around the world, providing customers with lower-carbon fuels and products into the future, such as hydrogen.

The proposed Polaris CCS project, would capture carbon dioxide (CO2) from the Shell-owned Scotford refinery and chemicals plant. The initial phase is expected to start operations around the middle of the decade, subject to a final investment decision by Shell, expected in 2023.

Polaris would have storage capacity of approximately 300 million t of CO2 over the life of the project.

LH L HH 2 2

August 2021 10 HYDROCARBON ENGINEERING

Ng Weng Hoong, Contributing Editor, explains how Southeast Asia’s oil markets are struggling amid the continuing impact of the COVID-19 pandemic.

F

or Southeast Asia’s oil industry, 2020 was the year to forget as disease, economic decline, political tensions and instability struck all at once.

The region’s population of nearly 670 million people used an estimated 880 000 bpd less oil in 2020 than they did the previous year.

This represented a record decline of nearly 13.5%, slashing the region’s oil demand to around 5.66 million bpd in 2020.

Collectively, the 10 economies of Brunei, Cambodia, Indonesia, Laos, Malaysia, Myanmar, Singapore, the Philippines, Thailand and Vietnam shrank by 3.9% in 2020, according to the Asian Development Bank (ADB).

Despite the bank’s expectation for an economic rebound of 4.4% in 2021, Southeast Asia’s prospects remain clouded. The emergence of deadlier and more contagious variants of the COVID-19 virus and the continued deterioration in US-China relations have put the region under renewed economic strain. For some countries, long-term political instability looms if their economies do not grow sufficiently or fail to recover altogether.

Myanmar Myanmar, one of Asia’s rising economic stars of the 2010s, is on the verge of political and economic collapse with the country on the brink of a civil war since a military coup in February 2021.

Both the US and China have reasons to intervene, potentially turning the country into a new source of regional conflict. China’s multi-billion-dollar investments in oil pipelines, storage terminals, and industrial facilities along Myanmar’s southeastern corridor have emerged as tempting targets for anti-government forces.

HYDROCARBON 11

ENGINEERING

August 2021

Table 1. Southeast Asia’s oil demand, population and economies

In Vietnam, the government will continue subsidising the country’s 2020 2020/2019 2021/2020 2020 2020/2019 two refineries to protect (thousand % % forecast (US$ (%) (actual) the country’s domestic bpd) million) supply security of fuels Singapore 1332 -4.9 5.7 6.0 317 420 -5.4 and products. The Indonesia 1230 -24.4 270.0 4.5 1 179 186 -2.1 145 000 bpd Dung Quat refinery which started up Thailand 1271 -9.5 70.0 3.0 425 133 -6.1 in 2009 and the Malaysia 728 -13.5 33.0 6.0 376 350 -5.6 200 000 bpd Nghi Son Vietnam 491 -11.9 98.0 6.7 206 683 +2.9 plant which began Philippines 378 -17.7 110.0 4.5 326 217 -9.6 operating in 2018 have Myanmar 104 -8.8 55.0 -9.8 89 800 +3.3 struggled to turn in a profit even during the best Cambodia 80 -11.1 17.0 4.0 20 272 -3.1 of times.

Brunei 24 +4.0 0.5 2.5 14 175 +1.2 Brunei was the oil Laos 22 -12.0 7.5 4.0 13 129 -0.5 industry’s main sparkle in Total 5660 -13.5 666.7 4.4 2 968 365 -3.9 Southeast Asia for 2020.

Sources: ADB, government agencies, BP, World Bank Its downstream oil sector was the breakout star following the full-year operation of a US$3.45 billion Table 2. Indonesia’s six refineries (thousand bpd) integrated refining-petrochemical complex.

Estimated oil demand

Population (million)

GDP

Cilacap, Java

348

Balikpapan, Borneo

260

Decarbonisation challenges

Dumai, Sumatra

170

Balongan, Java

125

Plaju, West Sumatra

118

The region’s oil industry must also contend with increased pressure from environmentalists demanding that Southeast Asian countries decarbonise their economies.

“Most Southeast Asian governments have started their energy transition towards energy security and diversification through balancing fossil fuels and renewable energies including biofuels,” said Sandy Gwee, Nomura Research Institute’s Principal Consultant on energy and smart cities.

She observed that even countries with oil and gas reserves are looking to develop renewable energy sources, citing Vietnam which already has the region’s largest solar and wind power portfolio.

She said Southeast Asian countries can help their transition by adopting policies and better technology to improve fuel efficiency and conservation.

Kasim, West Papua

10

Total

1031

Source: Pertamina

Despite the pandemic, Myanmar’s economy grew by 3.3% last year, making it the region’s best performer, said the ADB. Until the coup, oil companies were still optimistic about Myanmar’s future as they had set out for long-term expansion in the country’s downstream market and upstream sectors.

Indonesia and the Philippines, the region’s two most populous countries, are most at risk of plunging into a pandemic crisis along the lines of India. The oil refining sectors of both countries are in decline, with the Philippines bracing for the likely loss of its remaining refinery. Malaysia’s economic crisis is plumbing new depths amid shocking reports of starvation among the country’s poorest people.

Singapore’s downstream sector is reeling from the reduced operations of its three refining companies, and the collapse of Hin Leong Trading, the country’s biggest home-grown oil trading firm. The 58-year-old company went from planning to build Singapore’s fourth refinery in 2010 and mulling a listing on the local stock exchange in 2014 to filing for bankruptcy in April 2020. Founder Lim Oon Kuin faces fraud charges pertaining to bad trades that led to the company becoming insolvent on total debts of some US$3.5 billion owed to local and international banks. The Lim family has been forced to sell off corporate assets including a fleet of oil tankers and its 41% stake in the lucrative Universal terminal that operates oil storage services.

August 2021 12 HYDROCARBON ENGINEERING

Indonesia Indonesia’s proposed US$60 billion plan to expand and upgrade its ageing oil refining sector is at risk of being sunk by the lack of interest from foreign investors and the economy’s continuing uncertain outlook.

The Indonesian economy shrank 2.1% last year for its worst performance since the 1998 Asian financial crisis.

The ADB is optimistic Indonesia will recover, with its forecast for the region’s largest economy to grow by 4.5% in 2021 and 5% in 2022.

But the bank cautioned that Indonesia’s recovery will depend largely on how well it deals with the continuing COVID-19 pandemic crisis. It said the country of over 270 million people face global competition for vaccine, rising COVID-19 infections in vaccine-producing countries, and supply chain problems.

In July 2020, state-owned Pertamina unveiled its proposal to boost both its oil refining and petrochemicals

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capacities through 2027. The goal is to improve domestic energy security and reduce dependence on imports.

According to Bloomberg, the company’s President, Nicke Widyawati, told parliament that it expected to raise its 1.05 million bpd refining capacity to 1.8 million bpd and to add 8.6 million t of petrochemicals capacity.

The proposal looked unrealistic from the start as the pandemic was already ravaging not just Indonesia’s but also the global economy by mid-2020. Oil demand plunged as the economy came to a standstill.

Ms Widyawati’s announcement of Pertamina’s refinery expansion programme came shortly after the state oil and gas companies of Saudi Arabia and Oman ended their long-running discussions to invest in Indonesia’s downstream sector.

Without the participation of international investors, Pertamina will struggle to raise financing for such a long-term capital-intensive programme.

In April 2020, Saudi Aramco ended discussions with Pertamina to jointly expand and upgrade the existing 348 000 bpd refinery in Cilacap in central Java. In December 2019, Oman’s Overseas Oil and Gas LLC (OAG) exited from a proposal to build a new refinery in Bontang.

Balongan refinery fire The run of bad news for Pertamina continued into 2021 when a major fire broke out at its 125 000 bpd Balongan refinery in west Java on 29 March.

The incident further dented the company’s reputation as this was the latest in a series of refinery incidents over the past decade.

According to Indonesian consulting firm Tenggara Strategics, there were fire incidents at Pertamina’s refineries in Cilacap in 2011 and 2016, in Dumai in 2014, and in Balikpapan in 2019.

Tenggara said these incidents have undermined investors’ confidence in Pertamina’s ability to manage capital-intensive projects.

Despite rising domestic oil demand, Indonesia has failed to substantially expand its refining capacity for more than two decades. The country’s dependence on fuel imports now stands at around 300 000 bpd, around 18% of total consumption, according to Tenggara.

Consulting firm McKinsey said Indonesia could help its own cause by reducing fuel subsidies which have cost the government an average US$4 billion a year from 2015 to 2019.

“The current annual subsidy is the equivalent of investing in a major refinery upgrade every one to two years or a new refinery complex every four to five years. If 10 years’ worth of subsidies – about US$40 billion – were redirected to existing

Table 3. Thailand’s oil consumption

and new refineries, the impact would be enough for Indonesia to become self-sufficient in creating oil products,” McKinsey said in a recent report on Indonesia’s energy sector.

Brunei Spared the full impact of the COVID-19 pandemic, Brunei’s economy was among a fortunate few that grew in 2020 when most of the world fell into a deep recession.

The small Southeast Asian economy grew 1.2%, thanks to the full-year operation of a new US$3.45 billion oil refinery-petrochemical complex.

The Hengyi Industries complex started commercial operations in November 2019 and was able to produce refined oil and petrochemical products for export throughout 2020.

There were no reports of interruptions or major operational issues that often bedevil the early operations of new plants.

The Brunei-China joint venture integrated complex on Pulau Muara Besar reported revenues of US$3.5 billion in its first year of operations, said CEO Chen Lian Cai. According to Biz Brunei newspaper, the company exported 6.38 million t of petroleum products and 1.7 million t of petrochemicals to China and other neighbouring countries.

Hengyi Industries contributed to nearly 4.5% of Brunei’s GDP in 2020, underlining China’s overnight importance to the oil-rich sultanate.

According to the sultanate’s Ministry of Finance and Economy, Hengyi’s operations more than quadrupled Brunei’s gross value-added production from 226.4 million Brunei dollars (B$) in 2019 to B$921.2 million last year.

The Hengyi Group owns a 70% stake in the complex with the rest held by the Brunei government through its Strategic Development Capital Fund subsidiary Damai Holdings.

The complex currently comprises a 160 000 bpd refinery that produces fuels and oil products mostly for export as well as feedstock for the integrated petrochemicals plant.

The company’s importance to the Bruneian economy is expected to surge in the coming years as it has announced plans to invest more than US$13.6 billion in a second-phase expansion. The company said it plans to add 280 000 bpd of refining capacity and 11.2 million tpy of petrochemicals capacity aimed for exports, mostly to China.

With Singapore’s oil refining role on the wane, Brunei could eventually become Southeast Asia’s second major fuels supplier. With its second-phase expansion, Brunei will have a total of 440 000 bpd of refining capacity, just slightly less than half of Singapore’s.

Brunei’s new downstream industry could not have come at a better time, as its upstream oil and gas sector is in decline.

According to the Ministry of Finance and Economy, Brunei’s refined oil and petrochemical exports surged nearly 3.8 times from B$1.1 billion in 2019 to around B$4.2 billion last year.

2020

2019

Change (%)

Thailand

Gasoline

199 489

202 484

-1.48

Diesel

411 726

424 164

-2.93

Battered by the COVID-19 pandemic, Thailand’s economy shrank 6.1% in 2020, sending oil demand down by nearly 10%.

According to the Energy Ministry, Thailand’s domestic oil demand fell to 1.05 million bpd in 2020, compared with nearly 1.17 million in 2019. These data are lower than BP’s which count a broader mix of products.

Others

439 579

539 277

-18.49

Total

1 050 795

1 165 928

-9.9%

Source: Ministry of Energy

August 2021 14 HYDROCARBON ENGINEERING

Table 4. Thailand’s oil refining capacity (thousand bpd) PTT Global Chemical

280

Thai Oil

275

IPRC

215

Esso Sri Racha

177

Star Petroleum Ref Co.

175

Bangchak Petroleum Co.

120

FANG

2.5

“These endeavours will not only help secure Singapore’s lead as a top bunkering hub, but also support the vision for a greener and more sustainable maritime ecosystem.”

With the global economy expected to rebound in 2021, government and industry officials are confident Singapore’s bunker sales volume will again exceed 50 million t for the year.

LNG adds to fuel supply role

Table 5. Singapore’s bunker fuel sales (million t) 2016

2017

2018

2019

2020

48.6

50.6

49.8

47.5

49.8

The bulk of this demand destruction centred around fuel oil for use in power generation and shipping. Jet fuel use for aviation transportation also fell. Collectively, demand for those fuels collapsed by nearly 18.5% to a combined 439 579 bpd in 2020 from 539 277 bpd the previous year.

Gasoline demand slipped by nearly 1.5% to 199 489 bpd, while diesel consumption was off by more than 2.9% to 411 726 bpd.

In response, Thailand’s refineries reduced throughput by nearly 2% from 1 025 195 bpd in 2019 to 1 004 844 last year.

The country’s seven refineries have a total of 1.25 million bpd in capacity.

The sector will continue to struggle in 2021 amid the continuing weak outlook for refining margins and demand, said US ratings agency Fitch. “Travel restrictions are likely to continue for the most part of 2021. We therefore anticipate a recovery of the refinery business to be slower than our previous expectation,” it said in a recent report.

Thailand’s leading refining company, PTT Global Chemical, has announced plans to reduce its carbon footprint by increasing exposure to cleaner energy and the electric vehicle business.

The nation’s 2020 energy consumption contracted by 5.8% and is expected to shrink by between 0.2% and 1.9% this year, said the Energy Policy and Planning Office (Eppo), according to the Bangkok Post.

Singapore Remarkably, Singapore’s bunker fuel sales rose 5% to 49.8 million t in 2020 just as the global economy shrank by more than 3.5%.

Traders said Singapore took market share off its competitors in other countries as shipping firms sought to maximise efficiencies and reduce costs amid the economic recession.

Singapore’s Senior Minister of State for Foreign Affairs and Transport, Chee Hong Tat, saw this as “a vote of confidence in Singapore’s stability, connectivity and capabilities.”

He said Singapore will continue to upgrade its services while aiming to supply a wide range of cleaner fuels “to meet the diverse needs of ships that choose to call here.”

August 2021 16 HYDROCARBON ENGINEERING

Singapore has added LNG fuelling to its menu of services for the world’s shipping fleet calling at its port.

Long established as the world’s leading marine fuels supplier, Singapore undertook its first LNG fuelling of a container vessel last March. The CMA CGM SCANDOLA was fuelled by FueLNG Bellina, the country’s first LNG bunkering vessel, said the Maritime and Port Authority of Singapore (MPA).

The breakthrough deal for 7100 m3 of LNG underlines Singapore’s intention to reduce carbon emissions in its port operations and shipping industry.

FueLNG is jointly owned by the MPA, Singapore’s Keppel Offshore & Marine Ltd (Keppel O&M), and Shell Eastern Petroleum Pte Ltd, a unit of the Anglo-Dutch major.

The MPA formed the joint-venture firm “to provide more sustainable bunkering solutions for the shipping industry.”

According to the MPA, LNG is “the best immediately available solution” to reduce the environmental impact of maritime transport, as it enables a reduction of 99% in sulfur dioxide, 91% in particulate matter emissions and 92% in nitrogen oxide emissions compared with traditional bunker fuels.

“An LNG-powered vessel emits up to 20% less CO2 than conventional marine fuel-powered systems,” it said.

Shell has forecast that the annual global demand for LNG as a bunker fuel will grow from nearly 3.5 million tpd to 30 to 50 million t by 2040. There are about 400 LNG-fuelled vessels currently in operation.

Malaysia Malaysia’s state energy firm Petronas will be hoping for higher oil prices and an improving economy this year to bounce back from its first-ever annual financial loss in 2020.

In a year to forget, the golden goose of Malaysia’s resource-dependent economy was laid barren by the pandemic and a deadly explosion at its new US$27 billion oil-petrochemical complex. Petronas registered the worst performance of its 47-year history with a loss of RM21 billion on account of a RM31.5 billion impairment on assets, weak oil and gas prices, and reduced demand for its energy products.

Petronas said its annual revenue fell by more than 25% to RM178.7 billion from RM240.3 billion the previous year.

Without giving details of the impaired assets, the company said that it nevertheless remained cashflow-positive.

Despite the Malaysian economy shrinking by 5.6%, Petronas said it delivered an after-tax profit of RM10.5 billion. This was 78% lower compared to RM48.8 billion in 2019.

Petronas said it expects to restart operations at its Pengerang oil-petrochemical complex in Johor state in 2H21.

The complex, jointly owned with Saudi Aramco, is undergoing repairs after a massive explosion killed five people in March 2020.

Yassir Ghiyati, Nitesh Bansal, and Mohammed Ilyas, Haldor Topsoe, Denmark, provide a review of the best available blue hydrogen technologies.

C

arbon dioxide (CO2) emissions must be reduced to tackle global warming. Several governments have therefore already adopted relevant regulatory frameworks, such as emission trading schemes or carbon taxation, with the aim of reducing CO2 emissions.

As just one example, the EU Emission Trading System (ETS) directive drives CO2 reductions by setting a cap on the total CO2 emission allowance for each company and by reducing this cap figure over time. Companies can sell their surplus quotas of CO2 emission and are thus incentivised to invest in the most efficient technologies

with least CO2 formation and to capture, utilise and/or sequester the formed CO2.

Since its introduction in 2005, the EU ETS directive has passed through several phases. It is now in its fourth phase, in which the pace of annual cap reduction is set to increase significantly. The EU commission expects the directive to drive faster adaptation of both ‘blue’ and ‘green’ technologies that are essential for the EU’s journey towards climate neutrality by 2050.

According to the International Energy Agency (IEA), annual hydrogen production accounts for 830 million t or 3% of global CO2 emissions. As such, there is a need to HYDROCARBON 17

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Figure 1. Traditional steam methane reforming. decarbonise hydrogen production. However, the potential role that hydrogen can play in the net zero carbon economy is much greater as it can decarbonise other sectors as well by becoming a preferred energy carrier, either in its pure form or by being converted into ammonia. The Hydrogen Council estimates that H2 production will increase 8 – 10 times by 2050, emphasising the need for decarbonising H2 production.

Hydrogen is traditionally produced by steam methane reforming (SMR) using fossil-based feedstocks such as natural gas, LPG or naphtha. Hydrogen production from fossil sources without CO2 capture is termed ‘grey hydrogen’.

One promising way of decarbonising hydrogen production is by steam electrolysis fuelled by renewable energy. The hydrogen produced this way is completely green and leaves no CO2 footprint, whether from production or use. Companies such as Haldor Topsoe have commercialised electrolysis solutions that are easy to use as standalone hydrogen units or in hybrid setups in combination with traditional hydrogen production.

However, one of the main limitations of green hydrogen deployment at mega scale currently lies in the insufficient availability of green power capacity.

To unlock the full potential of hydrogen in the energy transition aimed at reducing CO2 emissions, it is therefore necessary to supplement green hydrogen with other clean hydrogen sources with a low carbon footprint (known as ‘blue hydrogen’). Such hydrogen can be formed by combining traditional production methods with clean technology innovations. Blue hydrogen can therefore be produced either by revamping an existing grey hydrogen plant or by constructing a grassroot blue hydrogen plant.

The definition of blue hydrogen is not yet completely agreed, but many key industry stakeholders correlate blue hydrogen with >90 – 95% CO2 recovery. One weakness of this definition, however, is that it disregards the inherent carbon intensity of the different hydrogen production August 2021 18 HYDROCARBON ENGINEERING

methods. To discuss this important point, it is necessary to review the main methods used to produce hydrogen in greater detail.

Hydrogen production technologies Steam methane reforming SMR is currently the technology most widely used to produce hydrogen. The main reforming process occurs over nickel-based catalysts inside tubes placed in a hot reformer chamber (Figure 1).

The steam reforming of hydrocarbons can be described by the following reactions: CnHm + n H2O → n CO + [n+½m] H2 - heat ⇄ CO + 3 H2 - heat CH4 + H2O ⇄ CO2 + H2 + heat CO + H2O

(1) (2) (3)

Reformer heat is generated by burning fuel gas, which is usually a combination of natural gas and pressure swing adsorption (PSA) off-gas but can also include other off-gas streams imported into the hydrogen plant. Waste heat from the flue gas is recovered by preheating the feedstock and by steam generation, before the CO2 rich flue gas is vented into the atmosphere. The hot process gas exiting the reformer contains a mixture of steam, H2, CO and CO2. This is cooled in a waste heat boiler generating utility steam before it is sent to the shift section where CO reacts with process steam to create more hydrogen and CO2.

The effluent from the shift reactor is normally sent to a PSA unit to separate pure hydrogen from the off-gas, which is sent to the reformer as fuel. In low hydrogen purity applications, the PSA unit can be avoided or replaced with a methanator.

In a blue hydrogen scenario, the CO2 in the process gas from the shift section is recovered in a CO2 removal unit before being sent to the PSA/methanator.

capture heat from the effluent before it leaves the SMR. This bayonet design is referred to as SMR-B (see Figure 2).

At high capacities, conventional SMR design is limited by the economical size of the reformer. Heat exchange reforming has been successfully deployed to extend the single train capacity limit up to 207 kNm3/hr.

Convection reforming

Figure 2. SMR-B reformer sketch.

For hydrogen production capacities below 30 kNm3/hr, convection reforming (HTCR) is normally a better option than SMR. In convection reforming, the reformer design is different since the tubes are bundled in a much smaller chamber and the heat required for the process is generated by a single burner. The tubes are in contact with the flue gas generated by the burner flame in a convection section.

HTCR design provides heat integration with no steam export and is therefore favoured in cases where steam is not a desired product or is less valuable than hydrogen.

The compact design of the HTCR unit favours modularisation and has thus been the preferred choice for small scale hydrogen production for decades.

Advanced autothermal reforming

Figure 3. SynCORTM reformer.

Depending on the reduction targets for CO2 emissions, it may also be necessary to add a flue gas CO2 capture unit.

Heat exchange reforming In some cases, steam generation in the hydrogen plant is not a viable solution, due to plant economics or CO2 footprint. In such cases, the surplus energy can be utilised to drive additional reforming by either adding a heat exchange reformer (HTER) reactor downstream of the SMR or by modifying the design and operation of the SMR itself. Both options have been successfully used in industry.

In both HTER and SMR-B, the steam export is significantly lower than traditional SMR technology, hence the fuel consumption is lower per hydrogen yield, resulting in lower CO2 footprint.

In an HTER layout, a portion of the feedstock bypasses the SMR and is instead fed into the HTER reactor, where it is heat exchanged with the hot effluent from the SMR. The reforming taking place in the HTER reactor results in an additional 25 – 30% more hydrogen production and is therefore also a good option for adding capacity to an existing hydrogen plant.

As mentioned above, another option is to alter the SMR design, using advanced bayonet catalyst tubes to August 2021 20 HYDROCARBON ENGINEERING

SynCORTM reforming is an advanced autothermal reforming (ATR) process, which is fundamentally different from the tubular steam reforming processes described above in the sense that the main reforming process takes place inside one SynCORTM reactor. The reactor has a compact design consisting of a refractory-lined pressure vessel with a burner, combustion chamber and a catalyst bed (Figure 3).

The process gas enters the SynCORTM reactor and is mixed with oxygen and additional steam resulting in a combination of partial combustion and steam reforming.

Among blue hydrogen technologies, this process has low OPEX since the reactor operates at a steam to carbon ratio of 0.6, which is 3 – 5 times less than SMR. The lower steam throughput also has the benefit of reduced equipment and piping sizing –a benefit that is most pronounced at large scale since the equipment and piping are kept within standard sizes even at very large single line capacities.

SynCORTM technology has a proven track record from more than 80 years of industrial operation. The largest SynCORTM reactor in operation today has a hydrogen production capacity of 500 kNm3/hr, and the economical limit for single train capacity is 825 kNm3/hr.

In SynCORTM, the external fuel demand is extremely low, hence a very high carbon recovery (>95%) can be obtained without needing to capture the carbon in the flue gas. It is therefore very well suited for blue hydrogen.

Partial oxidation Hydrogen can also be produced by partial oxidation (POx). It is a non-catalytic process where a fuel-oxygen mixture is partially combusted resulting in a hydrogen

rich syngas, which is then shifted before being sent to product purification.

The partial oxidation reaction occurs when a sub-stoichiometric fuel-oxygen mixture is partially combusted in a series of partial oxidation reactors. This chemical reaction takes the general form: CnHm + n/2 O2 → n CO + m/2 H2 The POx technology has certain well-known limitations, including: Continuous formation of soot, which must be removed frequently.

Relatively high CAPEX due to the need of multiple reactor design, large air separation unit (ASU) and soot removal unit.

High consumption of oxygen and power.

Very high operating temperatures (1300 – 1400°C), which significantly limits the service life of the burners.

Complicated water-cooled oxygen burner.

Figure 4. Optimal single line hydrogen production capacity with different reforming technology layouts.

Electrified steam methane reforming (eSMRTM) A new hydrogen production method is electrified steam methane reforming (eSMRTM). In this method, the main reforming reactions take place inside a catalytic reactor with reaction heat being generated by an electrical current. This means no hydrocarbon fuel is used in the reformer, which in turn means there is no reformer flue-gas. The energy density of an eSMRTM results in a reactor size that is a fraction of an SMR unit.

Furthermore, practically all the CO2 in the shifted process gas can be recovered at low cost in a CO2 removal unit, making this process a very good candidate for blue hydrogen production in cases where electricity prices are favourable.

The eSMRTM process has been successfully tested at pilot scale and will soon be tested in a demonstration plant.

Comparing layouts

Figure 5. Hydrogen yield for different hydrogen production technologies.

All the technologies mentioned above can be used to produce blue hydrogen. Selecting the technology best suited for any project will depend on multiple parameters, including capacity, yield and carbon intensity, as well as the levelised cost of hydrogen (LCOH).

A technology comparison of the main parameters is presented below starting with production capacity in Figure 4.

At small capacities, HTCR and eSMRTM are the most suitable technologies due to their compact design, whereas SynCORTM is the preferable choice at higher capacities because of low CAPEX. Its single reactor

layout and very low steam-to-carbon ratio operation enables the SynCORTM design to benefit more from economy of scale.

The ‘hydrogen yield per consumed natural gas feedstock’ is very high in eSMRTM due to its fundamentally different design with electrically heated reformer (see Figure 5). Among other technologies, SynCORTM and SMR-B have the highest yields. For SMR design, this is lower due to steam export, which is sometimes necessary to balance steam requirement outside the hydrogen plant.

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Figure 6. Carbon intensity of different blue hydrogen technologies.

Figure 7. Levelised cost of hydrogen for different reforming technologies. Main assumptions: natural gas: €4/million Btu, power: €50/MWh (power cost is varied from €15 – 50/MWh for eSMRTM to demonstrate cost sensitivity), CO2 credit: €25/t.

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Carbon intensity (CI) is now widely considered the most effective way to measure the success of a blue hydrogen technology in terms of reductions in CO 2 emissions. In Figure 6, CI is shown as the mass of CO2 emitted per unit of hydrogen produced. The grey columns, which show CI with no carbon capture, are highest for the SMR design due to its lower efficiency and higher fuel consumption, converting waste energy to high levels of steam export. SMR-B has the lowest inherent CI among conventional technologies, since it has no steam export, whereas eSMRTM CI is a step change better due to the nature of electrified reforming.

CI can also be reduced by capturing CO2 from the process gas. This is more economical than capturing CO2 from flue gas and is therefore normally the first step in CO 2 capture. In Figure 6, this is shown as light blue columns. For SynCORTM and POx, which are both oxygen fired processes, as well as for eSMRTM, achieving very low CIs is fully feasible by removing the CO2 formed in the process gas only. This feature makes these processes ideal for blue hydrogen production.

Going from light blue to deep blue hydrogen requires the removal of CO2 from the flue gas. This is most cost-effectively done in SynCORTM, due to lower levels of flue gas relative to hydrogen yield. It is not a necessary step for eSMRTM, since there is no flue gas in an eSMRTM plant.

The choice of technology ultimately depends on achieving certain targets as cost-effectively as possible. Figure 7 shows the relative differences in LCOH for each technology.

At the same operational targets and conditions, the hydrogen produced in SynCORTM has the lowest levelised cost, mainly due the combination of high yields, lower CAPEX and lower OPEX. However, eSMRTM is envisioned to be a better technology choice in niche conditions with low electricity prices and at small to medium production capacities.

Elias Xanthoulis, Andrew Board, Attila Racz and Tobias Roelofs, Comprimo, part of Worley, look at typical routes to blue hydrogen production, and how to maximise CO2 removal at high thermal efficiency in blue hydrogen facilities.

T

he need for decarbonisation of existing industrial operations drives the need for higher volumes of hydrogen production in many areas of the world. As the promise of large-scale green hydrogen is still some time away, reforming of natural gas, as currently applied in many installations, will continue to play a key role in the transition towards meeting the Paris Agreement goals. Adding CO2 capture to existing reforming installations and new greenfield natural gas reforming hydrogen production installations is a first step in reducing carbon emissions but warrants the question: at what capital and operational costs?

The predominant operating cost in a reforming unit is due to the natural gas. In addition, the pricing of CO2 emissions in the EU-ETS has reached an all-time high1 contributing to current and future OPEX while validating the economic need for carbon capture. The different process line-ups in blue hydrogen production determine the height of the initial investment while the extent of carbon removal varies. This article seeks to provide an answer to the question above by assessing the main blue hydrogen line-up options, by focusing on the most important techno-economic parameters of the processes, namely thermal efficiency and their respective carbon capture rates achievable, to produce the required hydrogen purity.

Characteristics of a blue hydrogen plant A blue hydrogen facility has three significant design parameters: Carbon capture – requirement of a minimum of 90 to 95% total carbon capture (95%+ is rapidly becoming the benchmark).

Thermal efficiency – requirement for high thermal efficiency targeting 75 to 80% (HHV basis, including power required), especially when natural gas cost is a significant factor, which is nearly always the case.

Hydrogen quality – ensuring high quality industrial hydrogen production, such as meeting the ISO 14687 Hydrogen Fuel Quality, which requires H2 of a minimum of 98 mol% purity, and strict specification of level of impurities such as CO (CO <1ppmv).

The hydrogen purity specification can be achieved via a pressure swing adsorption (PSA) or methanation purification step in which the design is actually governed not by the hydrogen purity but by the CO product specification. Specific to the PSA is the loss in the tail gas of approximately 6 to 8% of the feed to a PSA. The tail gas contains approximately 70 vol% hydrogen and it needs to be utilised as fuel gas in the HYDROCARBON 23

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fired heater burners or elsewhere. A methanator step could be more cost-effective, however methanation requires dewpointing to remove water to the required specification to prevent condensation in the downstream hydrogen pipeline, whereas PSA will reject water with the tailgas. A methanator is considered a more efficient option compared to a PSA, as more calorific content is retained within the product gas, but this depends on final product quality requirements.

There are two broad reforming methods of producing blue hydrogen: the conventional approach using steam methane reforming (SMR), and the oxygen-based approach, which lends itself to a number of commercially available processes, such as combined reforming, autothermal reforming (ATR), heat exchange reforming, and partial oxidation (POx).

All of the these methods are catalytic processes with the exception of partial oxidation.

The carbon capture rate also plays a role in later operations as the price of CO2 emissions will gradually increase, with recent EU-ETS prices exceeding expectations already. Therefore, maximising removal rates is both an environmental and economic driver. CO2 capture can be accomplished via: absorption in a solvent (physical or chemical), cryogenic based removal, and the use of membranes or solid adsorbents. In general, CO2 is compressed and/or liquefied for transport or usage. The use of commercially available amine-based solvents is the most common and mature technology option. Variations in performance are mainly derived from the use of proprietary and more formulated solvents. This includes lower energy consumption in the regeneration section or increased loading

capacity reducing the overall circulation flow rate. Other upcoming technologies include the use of membranes and solid adsorbents. Membranes could be advantageous through a lower energy demand, installation cost and plot space requirement in the case of high concentrations of CO2. Solid adsorbents are typically regenerable (thermal/pressure) and could outcompete the energy demand of amine-based systems in the future. For all technologies, developments are still ongoing and relative rates of adoption could change in the future. In blue hydrogen line-ups, the option of pre- or post-combustion capture plays a large role in the extent of carbon removal.

Typical blue hydrogen routes

Reforming of natural gas is an endothermic process requiring fuel provision for the reaction heat. Conventionally, this heat is provided by using natural gas as the fuel, the combustion of which results in significant quantities of CO2 produced. One of the fundamental considerations is the source of this energy/fuel. Instead of utilising natural gas, product hydrogen can be used instead. Figures 1 and 2 show an SMR path to blue hydrogen using hydrogen or natural gas as the fuel source.

The main advantage of the SMR route is the fact that expensive-to-produce oxygen is not required as a feedstock.

However, the process produces more CO2 per kg of feed gas than oxygen fed reforming routes. This requires carbon capture, limiting the efficiency of the process if high CO2 capture targets are to be realised. Attempting to limit the CO2 production by using product hydrogen as the fuel gas decreases production efficiency and limits achievable carbon capture rates to just over 80%. On the other hand, using natural gas as the fuel to the reformer in order to remedy this requires the addition of post-combustion capture on the combustion side of the SMR. This flowsheet option can achieve CO2 capture targets of 95%, but at the expense of reduced thermal efficiencies (well below 75%).

Figure 1. Typical SMR flow scheme with pre-combustion CO2 capture.

An ATR process provides an option of reforming hydrogen, with an overall lower CO2 production footprint. However, it requires a costly air separation unit (ASU) to provide the oxygen feedstock.

A number of options exist to optimise the ATR flowsheet (as shown in Figure 3): Optimisation of the reformer operating conditions while still meeting the carbon capture criteria for the Figure 2. Typical SMR flow scheme with post-combustion CO2 capture. project.

August 2021 24 HYDROCARBON ENGINEERING

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Optimisation of the steam system to minimise fuel consumption.

Optimisation of the pre-combustion carbon capture (solvent based) flowsheet to reduce thermal demand.

combination of ATR and SMR, thereby requiring less oxygen.

This flowsheet, suitable for the larger hydrogen production capacities, does have efficiency advantages over the SMR scheme. The scheme would be able to achieve 95% as the syngas methane slip is controlled by the ATR. However, the Implementing the above unit operations has shown to cost to achieve the required performance can make this achieve CO2 capture targets above 95%, while maintaining option unattractive compared to the other reforming options. thermal hydrogen production efficiencies approaching 80% Another option is to combine the ATR with heat exchange (on an HHV basis). reforming (parallel or series arrangement), which increases A single ATR train can achieve up to 400 kNm3/hr of overall thermal efficiency by removing the SMR component. hydrogen production (dependent on configuration), which is However, it introduces a heat exchange arrangement, which considered to be advantageous. This is a significant production limits the capacity of a single unit due to fabrication limits on capacity if one considers that most installed conventional the size of the heat exchange reformer. The major advantage grey hydrogen production plants rarely exceed 200 kNm3/hr. of this scheme (as shown in Figure 4), especially the series An option to minimise the expense of oxygen production arrangement, is the capability of capture rates in excess of is to have a combined reforming process, which utilises a 97%, at high thermal efficiencies of 80% (HHV), hence offering a technically optimum solution. However, especially for the higher capacity options considered for some of the developments (where two or more trains of heat exchange reformers would be needed), the additional gas-heated reformer (GHR) contributes and elevates overall costs. This configuration has limited commercial references.

POx offers a non-catalytic Figure 3. Typical ATR flow scheme with pre-combustion CO2 capture. route to blue hydrogen,

Figure 4. Heat exchange reforming scheme.

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alternative as it offers a lower CAPEX option and no ASU requirement. The breakpoint in this capacity, where SMR becomes a viable alternative, depends on a number of parameters and is very specific to each project.

Figure 5. Typical POx flow scheme (non-catalytic).

Conclusion Worley’s experience has shown that SMR or a ATR HE reforming combination of SMR (GHR) with ATR (combined reforming) would not Approximately Approximately 200 kNm3/h 400 kNm3/h achieve the carbon (single ATR with capture targets two GHRs) currently being set by the industry, which is particularly true for most greenfield blue hydrogen (large) 95 – 97% 97+% projects in Europe and the UK. The reforming 75 – 79.5% 80.5% would be expensive, especially at the Low Low capacities considered, and post-combustion Low High capture is required as an additional step to achieve the higher CO2 capture targets. For smaller capacities (below 100 kNm3/hr) and for existing facility retrofits (conversion to blue hydrogen), this route is a viable alternative. ATR and GHR technology can meet the high energy efficiency criteria at the 95%+ capture rate, with ATRs being more suited to the larger capacity projects.

This article has shown that an optimised ATR flow scheme can be achieved by carrying out a number of process parameter changes.

The CO2 capture rate achieved by the series coupled GHR configuration is the highest of all the reforming configurations considered and it can be achieved at thermal efficiencies exceeding 80% (HHV based). Although this is a promising technology, it does have the drawback of limited commercial references.

Non-catalytic POD, although not as techno-economically efficient as the catalytic approach, does offer the advantage of allowing for feed gas at lower purity, however reformer downstream catalytic processing (CO shift) still requires syngas clean-up steps at the exit of reforming, which negates some of this advantage.

Table 1. Technical assessment comparison of blue hydrogen technologies Description

SMR H2 fired

SMR natural gas fired

Combined reforming

H2 capacity (single train)

Downfired high capacity approaching 400 kNm3/h

Downfired high capacity approaching 400 kNm3/h

400 kNm3/h

Others low <200 kNm3/h

Others low <200 kNm3/h

70 – 85%

85 – 95%

Maximum 95%

Efficiency (HHV ~75% including power import)

<75%

75%

Cost

High1

High

High

Power import

Low

High

Low

Carbon capture rate

1

High CAPEX at large capacities

achieving 95%+ CO2 capture targets. The process requires a higher oxygen feed, increasing the size of the ASU. It displays a higher tolerance to feedstock impurities, which potentially would deactivate reforming catalysts if not removed.

Scrubbing systems are nonetheless typically required downstream of POx reforming to ensure that the CO shift process unit’s catalyst and equipment is protected, as indicated in Figure 5. This negates some of the advantages offered by the non-catalytic reforming route. Additionally, more severe operating conditions (much higher operating temperatures) of this process could have an impact on plant availability, which would need to be taken into consideration for this route to blue hydrogen.

Overall assessment of blue hydrogen routes Worley assesses reformer flow sheets and performs optimisation studies for a number of customers in this field.

For large scale blue hydrogen greenfield facilities, which need to meet high carbon capture rates (95%+) combined with high thermal efficiency, an oxygen-based catalytic reforming approach is the most thermally and techno-economically efficient path.

When smaller capacities are considered and (naturally) when retrofits to existing hydrogen generation systems are required, an SMR blue hydrogen option becomes a viable August 2021 28 HYDROCARBON ENGINEERING

Reference 1.

BULI, N., ABNETT, K., and TWIDALE, S., ‘EU carbon price hits record 50 euros per tonne on route to climate target’, Reuters, (4 May 2021), https://www.reuters.com/business/energy/eu-carbon-price-tops-50euros-first-time-2021-05-04/

M

Robert Jolly, Johnson Matthey, UK, outlines how clean hydrogen can play a key role in the energy transition, if it is deployed now.

omentum to limit global warming continues to build. Individuals, organisations and governments are seeking methods to implement in order to achieve the targets set by the Intergovernmental Panel on Climate Change (IPCC) to keep the global temperature increase below 1.5°C above pre-industrial levels. To limit the global temperature rise to

1.5°C it is essential to reach a net-zero situation for all greenhouse gas (GHG) emissions by 2050.

Whilst there has been growth in discussion, commitments and policy related to net-zero, there is still a significant gap between the commitments made by countries, Nationally Determined Contributions (NDCs) and the 1.5 °C pathway. A predicted gap of 29 GTCO2e/yr

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remains by 2030 (Figure 1). To give this context, the difference between the 2010 policy and the NDCs by 2030 is only 11 GTCO2e/yr. This shows the scale of the challenge and that there is much more that needs to be done.

The 1.5°C pathway is achievable, but it requires the deployment of the best low carbon technologies now.

Net-zero by 2050 will only be possible if we are on the 1.5°C pathway. The longer it takes to start reducing emissions, the larger the task will be, and there is a point where 1.5°C would not be achievable without a significant period of negative emissions.

Hydrogen’s part to play Urgently decarbonising the world’s energy systems is essential to meet the 1.5°C goal, and this is where hydrogen

has a role to play in providing clean energy for a wide number of applications. The Hydrogen Council identified its potential application in a number of key sectors: power generation (including energy storage), transportation, industrial and chemical processes, and heating buildings.1 Today, hydrogen is primarily used in industrial applications, such as hydroprocessing and chemical feedstocks. However, by 2050 hydrogen is anticipated to become a major energy source across multiple sectors. The expected growth in hydrogen is large, and equates to deploying one 67 kNm3/hr plant each day from now until 2050. To attain the capacity to supply this hydrogen, world scale hydrogen production units will need to be installed, and an acceleration in project development is required to increase the scale of current plants.

For existing operators, hydrogen offers a tool to allow decarbonisation of existing assets, securing the future of the business. But it also offers an exciting opportunity to become a new product line providing access to this new energy market. Thinking wider than just decarbonising existing hydrogen capacity is required to truly embrace the opportunity that hydrogen presents.

Blue hydrogen

Figure 1. Predicted emissions gap by 2030.

1 NDC – Nationally Determined Contributions Source: UNEP Emissions Gap Report 2020.

One of the primary ways to make low carbon hydrogen is through the reforming of hydrocarbon feedstocks coupled with carbon capture and sequestration (CCS).

This method of production is termed ‘blue hydrogen’. Blue hydrogen offers the opportunity to deploy large-scale hydrogen production today, resulting in a significant impact upon GHG emissions.

The US Department of Energy (DOE) set a target levelised cost of hydrogen (LCOH) of US$2/kg as the benchmark that would allow wide adoption of hydrogen as an energy source without significantly

Figure 2. A flowsheet producing H2 using Johnson Matthey’s LCH technology.

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impacting upon economies. To reach this target, technologies that are specifically optimised for blue hydrogen production are required.

Focus on emissions The term ‘blue’ can be used to represent any hydrogen production that includes some decarbonisation. If we return to the net-zero target, it becomes clear that it is essential to focus upon low emission production routes.

On a CO2 capture basis, this means striving for the highest rates possible, as any CO2 emission associated with hydrogen production will need to be accounted for through the deployment of alternative technologies.

A plant that is achieving 60% carbon capture still leaves a significant challenge to mitigate the 40% remaining emissions, and it also presents a substantial risk of exposure to CO2 pricing inflation for the operator of the facility.

Blue hydrogen requires a specific focus and a holistic approach to tackling the problems. Specifically, for blue hydrogen production it is important to aim for high purity H2 and CO2 products, and to maximise feedstock efficiency while intensifying the process (to enable brownfield deployment).

H2 production and CO2 capture cannot be considered as two separate problems in isolation. It is essential to view the process as a whole to fully reach the best solution to the problem.

Solution In focusing on blue hydrogen, Johnson Matthey (JM) has developed its LCHTM process for blue hydrogen production. The LCH technology offer combines JM’s proprietary gas-heated reformer (GHR) and autothermal reformer (ATR) technologies and allows for a higher hydrogen yield and greater energy efficiency than the standard steam methane reforming (SMR) technology for hydrogen production. The process delivers a high CO2 capture rate (>95%), high efficiency and low-cost solution.

The approach is based on established chemical process engineering, designed to operate at scale, enabling carbon reduction for industry, dispatchable power, domestic heating, and transport.

When compared to a conventional SMR, the LCH technology demonstrated 10% lower natural gas consumption, 10% less CO2 production, and 75% lower capital cost for the CO2 capture system.

Use of the technology de-risks the project by minimising the impact of increasing feedstock costs, increasing costs of CO2 transmission and storage and any governmental scheme for carbon taxation.

Process flowsheet The efficiency benefits of the LCH technology are achieved by recovering heat at maximum exergy (i.e. the highest possible quality) by coupling a GHR with an ATR (Figure 2). The main difference between the LCH and SMR

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Table 1. Comparison of LCH to SMR+CCS Units

SMR+CCS

LCHTM process

Natural gas energy (lower heating value [LHV])

MW

432

373

Hydrogen production

kNm3/hr 100 (90) (million ft3/d)

100 (90)

Hydrogen energy (LHV)

MW

300

300

Energy efficiency (LHV)

%

69.4

80.5

CO2 emitted

‘000 tpy

77.7

19

CO2 captured

‘000 tpy

700

603

CO2 captured

%

90

97

Relative CAPEX

%

100

61

Note: these numbers are provided for information and should be considered as indicative. SMR data source: IEAGHG Technical Report 2017-02. LCH CAPEX includes ASU. The LCH process is highly tuneable, allowing project specific optimisation and integration

flowsheets is that the energy to drive the reaction is provided by introducing oxygen to the ATR as opposed to burning natural gas in the SMR. ATRs are already used in the production of syngas in technologies such as methanol. These plants are very large and demonstrate that the technology is capable of producing hydrogen at large scale.

The heart of the process is the reforming block of GHR-ATR. The configuration of the reactors allows feedstock efficiency to be maximisued through efficient energy transfer. Importantly, all of the carbon dioxide is within the product stream and therefore at high pressure and purity. This means that it can be easily removed using standard industry removal technologies. The ability to apply pre-combustion CO2 removal on a high CO2 partial pressure steam means that CAPEX, OPEX and footprint of the system can be significantly reduced. This increases the ability to deploy the system on existing sites and decreases the LCOH being produced from such a system.

Comparison of LCH to SMR+CCS In Table 1, the LCH process is shown to offer higher efficiency, lower CAPEX and lower emitted CO2 when compared to SMR+CCS. It is important to note that comparing the CO2 capture rates of different technologies can still hide the actual emissions generated from the hydrogen production unit. In Table 1, the SMR+CCS unit was only achieving 90% CO2 capture (significantly increased capital cost to push those rates into the high 90s did not make sense for the study). For comparison, if the SMR+CCS option capture rate was increased to 97%, the emitted CO2 would be 23 000 tpy, which is still 20% larger than the LCH process.

This highlights how capture rates can hide the true carbon credentials of a solution. This difference is due to the process efficiency; in a low carbon world, it is important to maximise efficiency when converting hydrocarbon energy into hydrogen energy.

August 2021 32 HYDROCARBON ENGINEERING

Active projects The LCH process is already being used in the development of a number of projects.

HyNet is looking to develop a full hydrogen economy in a region of the UK, with a first phase producing 80 000 tpy of hydrogen for use in industry, homes and transport. The hydrogen plant at the heart of HyNet will utilise the LCH process, which will be hosted at Essar’s Stanlow Refinery. The initial phase focuses on supplying hydrogen to industrial applications, providing the required base demand to catalyse the development of the CO2 transport and storage and hydrogen infrastructure. The vision is to increase hydrogen production in subsequent phases once demand across various industries develops. The project demonstrates a design and execution that can be replicated elsewhere in the UK and internationally. When fully implemented, HyNet hydrogen will deliver low cost, low carbon hydrogen for key industrial users alongside non-disruptive blending to over 2 million households as part of delivering a net-zero industrial cluster in the region.

The Acorn project places advanced reforming technology at its core and will deliver a replicable process for cost-efficient hydrogen based around natural gas, whilst capturing and sequestering CO2 emissions. Here, the plan is to blend hydrogen into the natural gas grid for use across Scotland. The first phase is a 55 000 tpy hydrogen plant, and the LCH process has been the basis of the plant design for submission to the UK government’s Department for Business, Energy & Industrial Strategy (BEIS) Hydrogen Supply Competition.

Key advantages LCH is a high efficiency process, with low CAPEX. It offers the lowest natural gas usage per unit of hydrogen, maximising the conversion of hydrocarbon energy into hydrogen energy, and it also produces the lowest amount of CO2 per unit of hydrogen. A highly intensified footprint enables the amount of hydrogen per square metre of land to be maximised. The technology is also proven at scale, and has been deployed in both MeOH and NH3 plants for syngas production. This maturity has enabled design of the equipment to maximise reliability and uptime. Finally, all the CO2 within the process stream allows for the implementation of well-proven pre-combustion CO2 removal systems, ensuring all key technologies are mature.

Summary Limiting global warming to 1.5°C is a big challenge, but it is still achievable if low carbon technologies are deployed today. Clean hydrogen can play a key role in the energy transition and offers a solution that can be deployed into a wide number of industries and applications. JM’s LCH process enables low carbon hydrogen to be produced at scale, today, with leading environmental and economic performance, setting the world on the road to net-zero.

Reference 1.

‘Hydrogen, Scaling Up’, Hydrogen Council, Brussels, Belgium, (November 2017), p. 20.

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Robert Hsia, UnionTech, USA, introduces severe-service isolation solutions for hydrogen production via steam methane reforming (SMR).

August 2021 34 HYDROCARBON ENGINEERING

A

ccording to the US Department of Energy (DOE), natural gas reforming or steam methane reforming (SMR) currently accounts for 95% of the hydrogen produced in the US; it is arguably one of, if not the most, cost-effective and energy efficient methods to manufacture hydrogen. Figure 1 depicts an overview of a typical SMR process. SMR is considered a mature production process whereby a methane source (i.e. natural gas, biogas, syngas, etc.) reacts endothermically with high-temperature steam in the presence of a catalyst to yield hydrogen, carbon monoxide, and carbon dioxide: CH4 + H2O (+ heat) → CO + 3H2 Subsequently, the carbon monoxide and steam are reacted in the presence of a catalyst to produce additional hydrogen and carbon dioxide in regard to the ‘water-gas shift’ reaction: CO + H2O → CO2 + H2 (+ heat) Finally, the hydrogen gas is purified via pressure swing adsorption (PSA), which removes carbon dioxide and other impurities. Oftentimes, an ammonia plant will exist downstream from the hydrogen plant, whereby the hydrogen is reacted with nitrogen to yield ammonia.

Isolation challenges posed by severe-service environments The combination of high temperatures and pressures results in a severe-service environment which presents significant challenges to fluid isolation requirements. At the reformer and steam generator, temperatures and pressures can reach or exceed 1500°F and 1500 psig respectively. These elevated temperatures and pressures are prevalent throughout various modules of and applications within the SMR process, including the reformer, boiler feed water, feed gas lines, steam drum bridles, purging applications and blowdown applications.

Beyond the SMR island and at the ammonia section of the plant, these temperature and pressure challenges also persist throughout the nitrogen applications – as an example, nitrogen supply valves to compressors and flare headers may reach or exceed 4000 psig at 400°F. As the world advances on renewable energy initiatives, hydrogen has been gathering strong momentum as a ‘strategic pillar’ for energy transition, as it is a clean-burning molecule and a potential substitute for fossil fuels. Combined with carbon capture and sequestration (CCS) technologies, the SMR process enables the conversion of conventional hydrogen production, referred to as ‘grey hydrogen’, to the production of low-carbon hydrogen, otherwise known as ‘blue hydrogen’. For blue hydrogen to become economically viable as a primary energy source, the costs across the entire hydrogen value chain, including production, storage, distribution, etc., need to be reduced to meet the DOE’s cost targets for future automobiles and other applications. With respect to hydrogen production, the SMR process remains as the most cost-effective method as compared to

others, such as electrolysis. Although the SMR process is considered a mature technology, both commercial and environmental optimisation opportunities exist and are being realised via sustained higher temperatures and pressures in particular areas of the process. For example, the Hydrogen Council and McKinsey & Co. assert that: “conducting ATR [autothermal reforming] at higher temperatures can also increase the methane-to-hydrogen conversion rates, resulting in lower methane content in the product gas, further reducing emissions.”1 As a result, new plants are designed to run much hotter and at higher pressures in specific applications and modules as compared to those in existing facilities. Moreover, the efficacy of a true closed-loop system without leaks to atmosphere become critically important, from both a commercial and environmental perspective. As such, reliable isolation with positive shutoff becomes not only much more challenging for the valves in these applications, but also vitally important for the entire production process.

Valve selection from general service to severe-service At lower temperatures and pressures, torque-seated gate valves, often equipped with either solid Stellite® or Stellite-welded overlay trims, may suffice for applications that do not require tight shutoff. Torque-seated valve designs involve the application of substantial forces to the valve components to adequately seal against line pressure. Over time, these forces wear down the critical sealing components of these types of valves resulting in shortened product lives vs those of position-seated valve designs.

As temperatures and pressures rise, gate valves are often replaced by Y-pattern globe valves, similarly equipped with either solid Stellite or Stellite-welded overlay trims, to achieve improved shutoff performance at initial installation.

Unfortunately, the improved shutoff performance of globe valve is offset by substantial pressure drop across the valve and short product longevity.

The design of a globe valve involves a tortuous flow path that results not only in a high pressure drop (reduced Cv), but also in persistent erosion to its sealing elements. Furthermore, globe valves, like gate valves, are also torque-seated, which must be ‘hammered-down’ to seal against line pressure, resulting in sustained wear to the internal components of the valve.

Combined with multi-turn and rising stem mechanics, the sealing efficacy of globe valves is often compromised by these factors, resulting in packing leaks to atmosphere throughout the life of the valve. In addition to packing leaks, seat leaks often plague the performance of globe valves, as a temperature differential between the upstream and downstream sections of a closed globe valve results in thermal expansion of the inlet side of the valve vs thermal contraction of the outlet portion of the valve, which contains the plug. As such, the sealing efficacy of the plug and seat is compromised, and the globe valve will leak through downstream.

To address the underperformance of globe valves in severe-service applications, companies such as Union Tech engineer and manufacture quarter-turn, metal-seated floating

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Figure 1. Overview of a typical SMR process.

Figure 2. Cutaway of a two-piece severe-service MSBV.

ball valves (MSBVs) that can achieve a ‘bubble-tight’ seal per ANSI FCI 70.2 Class VI shutoff – or better. Figure 2 shows a cutaway image of a severe-service MSBV. The quarter-turn mechanics of a MSBV not only eliminates packing leaks, but also enables the usage of low emissions packing that complies with prevailing fugitive emissions certifications, such as API STD 641. Furthermore, the position-seated design of a MSBV utilises the line pressure to assist in sealing, which results in a substantial increase in valve longevity and reduction in maintenance/replacement costs. Moreover, the straight-though flow path not only eliminates the pressure drop across the valve, but also protects sealing components from erosive damage. These major design advantages have resulted in the widespread replacement of globe valves, not only in SMR applications, but also in other severe-service applications in power plants, refineries, etc.

Features and considerations of severe-service MSBV designs By definition, MSBVs incorporate a metal-to-metal seal; without appropriate coatings, the metal-to-metal components would gall during operation. Severe-service MSBVs apply high performance, hard-faced coatings to protect valve components August 2021 36 HYDROCARBON ENGINEERING

against not only the galling of sealing surfaces, but also the wear, erosion and corrosion that threaten the long-term performance of the valve. After the application of the coatings, the sealing components are then mate-lapped to achieve zero leakage shutoff. Severe-service MSBVs are custom engineered products, and as such, coatings are often customised for a particular application. As an example, certain purge valves in the SMR may operate at 570 psi and 775°F with infrequent cycling.

Union Tech’s high velocity oxygen fuel (HVOF) chromium carbide coating would be appropriate for this particular application.

Of the available MSBVs in the marketplace, manufacturers may employ several designs, each with their own advantages and disadvantages. For example, some MSBVs utilise an integral downstream seat, machined out of the valve body. This design realises the benefit of cost reduction, but it sacrifices performance as the valve trim and body typically consist of different materials with different coefficients of thermal expansion. Other designs, such as Union Tech’s Z1 MSBV, utilise matched ball and seat materials with identical coefficients of thermal expansion – the downstream seat is hydraulically pressed into the body, which eliminates any voids that could arise from seat distortion during the process. Figure 3 provides an image of the components of a unibody severe-service MSBV with a pressed-in seat design. The ball is then ‘final lapped’ to the pressed-in seat to ensure the sealing integrity of the ball and seat following installation. Although more costly, this design elects product robustness and performance scope expansion over cost minimisation.

MSBVs are commonly equipped with mounting bracketry and stem adaption components for actuation. The importance of the mounting bracketry and stem adaption designs is often overlooked and, as a result, often a source of valve package failures in the field. First, the height of the mounting bracket should be determined by both the line temperature and valve orientation (i.e. horizontal or vertical) to safeguard the actuator, controls, and accessories from excessive heat radiation. Most engineering departments of MSBV manufacturers have access to heat dissipation curves specific to their valve packages and should be able to provide guidance on appropriate bracket heights (and in more extreme cases, heat shields and other heat dissipation equipment) specific to each application. Second, mounting bracketry and stem adaption components should be engineered to ensure that the axis of rotation is centred and stabilised throughout the length of the stem. In the case of vertical piping, gravity applies an orthogonal force to the stem, further challenging the stability of the rotational axis.

Insufficient support of the stem in relation to suboptimal mounting bracketry and stem adaption designs often results in

stem misalignment or side-loading. Valves with side-loaded stems will operate with substantially increased operating torques or seize completely; inspection of components will reveal galling on stem and other internal components of the valve.

Other features common to severe-service MSBVs include: One-, two-, or three-piece design.

Uni or bi-directional sealing.

Customisable end connections.

Blowout proof stem design.

Scraper seats.

Purge ports, steam jackets, etc.

Fugitive emissions performance certification (i.e. API 641).

Safety integrity level certification (i.e. SIL-3).

Conclusion Hydrogen is one of the key pillars for energy transition, and investment into efficient production methods is crucial for success. As these new process technologies leverage efficiencies from increased temperatures and pressures, robust and dependable isolation solutions are necessary throughout the production facilities. Severe-service MSBVs employ technologies that have been field-tested across many other industrial applications and can provide new hydrogen production plants with necessary and ideal valving solutions.

Figure 3. Components of a unibody severe-service MSBV with a pressed-in seat design.

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Reference 1.

McKinsey & Co., ‘Hydrogen Insights: A perspective on hydrogen investment, market development and cost competitiveness’, (February 2021).

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Mark Barton, Luiz Soriano, John Stahley and Arja Talakar, Siemens Energy, USA, explain how hydrogen plays an essential role in a wide range of industrial applications and is increasingly emerging as a decarbonisation agent for the energy transition.

I

n the US alone, it is projected that demand for hydrogen could reach as high as 41 million tpy by 2050 – more than four times what it was in 2020.1 Today, most of the hydrogen produced worldwide is used for the production of ammonia and fertilizers, and feedstock for downstream refining processes, such as hydrocracking and desulfurisation. But this is expected to change as increased volumes of both ‘blue’ and ‘green’ hydrogen

become available and make their way into applications for mobility, power generation, and energy storage.

Compressors are an enabling technology used to safely and cost-effectively transport hydrogen across the value chain. However, compressing hydrogen often presents unique technical challenges that are not typically seen with other process gases, such as methane (CH4) or carbon dioxide (CO2).

This article explores some of those challenges and outlines

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different applications. Hydrogen-rich applications are typical in refineries and chemical plants where recycle or make-up compressors are used to handle process gas containing high hydrogen content and other constituents (Figure 1).

Reciprocating and centrifugal (i.e. turbo) compressors are the two most widely used machines for hydrogen compression. Reciprocating compressors work on the principle of positive displacement and use a piston to reduce the volume of gas inside a cylinder, thereby increasing its pressure. Turbocompressors operate by imparting tangential kinetic energy using one or more stages of rotating impellers and stationary diffusers.

Figure 1. BDC-18H3 compressor, 4 throws, hydrogen

application, 3.000 psia discharge pressure; shipped in 2019.

Figure 2. HHE-VL compressor, 4 throws, hydrogen

application on test stand in the Naroda, India facility; shipped in 2020.

important factors for end-user consideration when selecting a compressor for hydrogen service.

Hydrogen compression 101 Hydrogen is the most common element in the universe and, with a molecular weight of 2.02 g/mole, is the lightest of all gases. It possesses a very high energy content per unit of weight (caloric value = ~33 kWh/kg), making it an ideal energy carrier. However, its density at atmospheric conditions is low (90 g/m3) compared to other gases, which means compression is frequently required to meet various process conditions of different applications.

Hydrogen has a unique characteristic that can present a challenge for safe compression. Ordinarily, when gas expands from higher pressure to a lower pressure, at normal temperatures, it cools down. Hydrogen, on the other hand, heats up when expanded at a temperature above its ‘inversion point’ of -112˚F (-80˚C). This characteristic is known as the ‘Reverse Joule-Thomson effect’.

Generally speaking, hydrogen compression applications can be separated into two categories: pure (100%) hydrogen and hydrogen-rich. An example of a 100% pure application would be a hydrogen production facility, where hydrogen is produced – ideally from an electrolyser powered by renewables – and then compressed and stored for various August 2021 40 HYDROCARBON ENGINEERING

Reciprocating compressors State-of-the-art positive displacement reciprocating compressors represent the most efficient option for compressing pure hydrogen and hydrogen-rich gases.

The inherent design of the reciprocating compressor, in which a volume of gas is drawn in and positively displaced by the action of a reciprocating piston, means that the molecular weight of the gas does not compromise compression efficiency. This enables the reciprocating compressor to achieve high overall compression ratios in fewer stages than turbocompressors (Figure 2). For example, achieving a pressure ratio of 4:1 in an equivalent application typically requires six stages in a centrifugal compressor. In a reciprocating compressor, this can be accomplished with two stages and at a lower CAPEX. Listed below are considerations for end-users when specifying a reciprocating compressor for use in hydrogen service.

Energy savings and capacity control Basic methods of capacity control on a reciprocating compressor can efficiently reduce process capacity and power consumption. Plug, port, or finger unloaders can be used to unload compressor cylinder ends – facilitating 100% capacity and 50% capacity with a corresponding reduction in power consumption.

Additionally, pneumatically-actuated fixed volume clearance pockets can increase cylinder clearance, effectively reducing capacity without losing the energy of compression.

If variable capacity is required, hydraulic variable volume clearance pockets can be implemented to dynamically adjust cylinder clearance during operation, controlling compressor capacity and limiting consumed power. Further refinement in capacity control and power savings can be recognised with an Infinite Stepless Capacity Control System, such as Dresser-Rand ISC, a system that has been in use for more than 50 years. Any of these systems alone or in combination enable efficient use of power while reducing OPEX.

Compressor valves Compressor valve designs should be reviewed and optimised for operation with hydrogen-rich gases. When excessive power is needed to force suction and discharge valves to open (allowing gas to flow into and out of the compressor cylinder), power is lost. Reducing excessive differential pressure across the valves will result in more efficient use of power.

Figure 3. A typical Siemens Energy hydrogen recycle centrifugal compressor package.

When compressing hydrogen-rich gases, valve lift and effective flow area are significantly less than would be required for heavier gases. Limiting valve lift reduces the distance through which the valve element accelerates before seating. The Dresser-Rand Magnum valve utilises polyetheretherketone (PEEK) valve element material, which has high strength and low mass. The combination of low mass and reduced distance to accelerate results in reduced impact force on the valve element. Performing a dynamic valve analysis (DVA) optimises valve flow area and differential pressure to improve valve reliability and allow for efficient use of power.

Cylinder lubrication Most process applications are tolerant of lubrication in the compressor cylinder and packing case. Some services utilise mineral oils, while others may necessitate synthetic lubricants compatible with the process. Cylinder lubrication should be selected for the specific service application – using oil product data sheets to ensure suitability with the compressor and the process.

Cylinder lubrication affects reliability of the piston and packing rings, and rider bands, as well as cylinder liner and compressor valves. Therefore, the reliability of the cylinder lubricator is critical to the reliable operation of the compressor. Just as marginal lubrication can lead to excessive wear rates, excess lubrication can create detrimental conditions of operation. Lubrication rates should be adjusted per the manufacturer’s recommendation to suit the unique process condition.

Non-lube cylinders Other applications where oil carry-over into the process gas stream may compromise the process, or poison a catalyst, may necessitate non-lubricated cylinders and packings. These applications include very cold boil-off gas compression or liquefication applications where the gas will be chilled and liquified. Any oil carry-over may compromise the process when operating at low temperatures. Conversely, as operating pressures and temperatures increase, accelerated wear rates may be observed. In these applications, it may be advantageous to consider increasing the number of stages, to August 2021 42 HYDROCARBON ENGINEERING

reduce each stage ratio, or to lubricate the cylinder and packings and remove accumulated oil with coalescing filters after the final stage of compression to increase reliability and run-time.

Non-lubricated cylinders are available to 3000 psig (200 BarG) discharge pressure. Special materials are applied on wear components (typically proprietary polytetrafluoroethylene [PTFE] or PEEK alloys) to guarantee adequate lifetime. Overall, the best design for each application will involve factors such as tolerance of the process to oil carry-over and expected maintenance intervals, among others.

Siemens Energy has more than 2 million hp of reciprocating compression installed in ‘blue’ hydrogen-rich services, including tail gas, feed gas, and make-up services, as well as pipeline and storage. As ‘green’ hydrogen services develop, the company intends to use its technology and experience to support the growing market.

Centrifugal compressors When designing a centrifugal compressor for hydrogen service, several process parameters must be considered (Figure 3). These include, but are not limited to, suction pressure, temperature, discharge pressure, volumetric flow rate, impeller operating speed, etc. Operating speed is especially relevant because the polytropic head and pressure ratio that a compressor or stage produces is proportional to the square of the speed.

Because of hydrogen’s low molecular weight and high sonic velocity, it will have a comparatively lower pressure rise per stage of the compressor relative to heavier gases. This means that in applications with high discharge pressures, the impeller operating speed must be increased, or additional compressor stages must be added. The latter can significantly increase rotordynamic complexity. In some instances, the maximum permissible shaft length may not provide sufficient space to incorporate the required number of stages. In such cases, the only option is to increase impeller operating speed.

However, this then requires consideration of material strength limits.

Mechanical strength limits of the impellers are directly correlated with tip speed. The maximum allowable impeller tip speed varies depending on the specific material used and the geometry of the impeller. These material strength limitations typically are not a concern when designing compressors for service with higher molecular weight gases because the Mach numbers limit the operating speed.

However, in the case of hydrogen, the mechanical strength and impeller stress levels can become limiting factors.2 This issue is further complicated by the potential for hydrogen embrittlement, i.e. hydrogen-induced cracking (HIC). HIC occurs when atomic hydrogen diffuses into an alloy.

Depending on the material used, this can reduce toughness and lead to failures below documented yield stresses.

Titanium impellers with specialised surface coatings have proven to be successful in mitigating the risk associated with HIC. Other design enhancements, such as interstage cooling, can also reduce its likelihood.

It is important to note that there are currently no available test methods that can accurately simulate the conditions that

a high-speed impeller may experience in a centrifugal compressor operating in 100% hydrogen service.

Siemens Energy has developed a novel test method for this purpose to provide guidance on a new NACE standard for testing HIC, much like the limits for stress corrosion cracking (SCC) in NACE MR0175.3 Extensive studies on the design of blades and impeller geometry have shown that when high-strength titanium alloys are used, these stress levels can be reduced to allow for pressure ratios of up to 1.45:1 per stage.4 Therefore, a six-stage machine with a total pressure ratio of 4:1 with 100% hydrogen is technically possible. It can be assumed that the commercial availability of these machines will increase in the coming years when the market demands them.

Despite these challenges, it is possible to safely meet high discharge pressures with centrifugal compressors in hydrogen-rich service. For example, at one Gulf Coast refinery, Siemens Energy supplied a nine-stage, constant speed centrifugal machine for a hydrotreating unit.

The compressor, a DATUM D16R9S, is powered by a 16 000 hp motor and is based on a well-proven design, with no special modifications in a straight-through configuration.

All nine stages are contained within a single casing fitted with a single inlet nozzle and a single discharge nozzle to accommodate the hydrogen gas flow. In preliminary performance testing at a Siemens Energy manufacturing facility, the compressor achieved a polytropic head of 169 954 ft-lbf/lbm (approx. 18 880 ft-lbf/lbm per stage) – the highest level ever recorded with a DATUM unit.1

Conclusion The role of hydrogen in the global energy landscape is growing rapidly. While demand in downstream oil and gas and refining applications will remain robust in many regions of the world, the enormous potential for hydrogen as a clean energy carrier will inevitably see its use expand into other markets, including mobility, power generation, and energy storage. As the energy transition continues to gain steam, the need for compressors that can safely and efficiently move hydrogen throughout the value chain and make full use of its benefits within specific processes will be critical.

With a comprehensive portfolio of both centrifugal/turbo and reciprocating compression solutions designed for use in hydrogen applications, along with a global manufacturing network, Siemens Energy is prepared to meet the growing demand for hydrogen compression and enable customers to shift to a more efficient and sustainable future.

References 1.

2.

3.

4.

GREENHALGH, K., ‘US demand for hydrogen may quadruple by 2050: NREL’, IHS Markit, (November 2020).

MILLER, H., and SOROKES, J., ‘Pushing the Limits of Compression’, Hydrocarbon Engineering, (February 2019), pp. 81 - 84.

ADAM, P., HEUNEMANN, F., VON DEM BUSSCHE, C., THIEMANN, T., and ENGELSHOVE, S., ‘Hydrogen infrastructure – the pillar of energy transition’, The practical conversion of long-distance gas networks to hydrogen operation, Siemens Energy, Gascade Gastransport, Nowega GmbH. DI BELLA, F. A., ‘Development of a centrifugal hydrogen pipeline gas compressor,’ Technical Memorandum No. 1785, US Department of Energy, (16 April 2015).

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Nabil Abu-Khader, Compressor Controls Corp., UAE, explores the operation of parallel centrifugal compressors using surge control.

A

compressor map shows the characteristics, performance, and operational limits of a compressor, i.e. surge, choke, minimum, and maximum speeds (performance curves). The distance between the operating point and the surge control line (SCL) of a centrifugal compressor map cannot be easily determined using compressor manufacturers’ supplied data.

This is because surge limit line (SLL) points can vary with inlet gas conditions, and mainly gas composition changes.

The introduced coordinates by Compressor Controls Corp. (CCC), which are reduced flow squared (q2sr) vs reduced head (hpr) or compression ratio (Rc), do not contain measured variables that change with gas composition changes.

This article presents the load-sharing, load-balancing, and recycle-balancing techniques for parallel centrifugal compressors based on CCC’s invariant coordinate space surge control map computation principle.

Proximity to surge and the invariant coordinates In order to prevent compressor surge with minimum recycle or blowoff, an antisurge controller must accurately determine how close the compressor is operating to its surge limit. The antisurge controller can use a variety of functions to calculate proximity to surge, each of which represents a different set of simplifying assumptions to

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define a coordinate system in which the surge limit is invariant to process changes.

The reduced polytropic head (hpr) was derived from Equation 1 and Equation 2:

Rc = Pd⁄Ps

hpr =

(

Where Ts and Td are the temperature in suction and in discharge respectively of the compressor (or compressor stage) of interest, measured in units of absolute temperature.

On the other hand, the reduced flow squared (q2sr) was also derived from Equation 6:

(1) σ

Rc – 1 σ

)

q2sr = dpos ⁄Ps

Where Ps and Pd are pressure in suction and in discharge, respectively, of the compressor (or compressor stage) of interest (measured in units of absolute pressure), and Rc is the compression ratio. σ is the polytrophic exponent of the gas being processed, non-dimensional and is derived from Equation 3: σ = (k – 1)⁄(k * η)

(3)

Parameter (σ) can be assumed constant if gas composition and gas parameters remain reasonably constant within the operating range of the compressor, but it may be necessary to correct for gas composition changes in some cases. k is the average isentropic exponent of the gas being processed which, for ideal gas, equals the ratio of specific heats Cp and Cv, as shown in Equation 4:

k = Cp⁄Cv

(4)

η is the polytropic efficiency of the compressor (or compressor stage) of interest, η <1.

Using the definition of polytrophic process, σ can also be calculated using Equation 5: σ = log (Td⁄Ts)/log (Pd⁄Ps)

(6)

(2)

(5)

Where dpos is the differential pressure of the flow-measuring device at the suction side of the compressor (or compressor stage) of interest.

When the flow-measuring device is located in the discharge side of the compressor (dpod), a compensated reduced flow in suction (dpos) can be derived, as per Equation 7:

dpos = dpod (Pd⁄Ps). (Ts⁄Td)

(7)

To develop the invariant coordinate space, the reduced flow squared (q2sr ) is normally used in the X-coordinate. As a CCC rule of thumb, if the gas composition and gas parameters remain reasonably constant, then the Y-coordinate can be simplified as the compression ratio (Rc). However, if the gas composition and gas parameters change dramatically then reduced head (hpr) should be used in the Y-coordinate. Within this ‘non-dimensional’ coordinate space, the angular distance between the operating point and the SLL (SS) can be calculated, as per Equation 8:

SS = SlopeOPL⁄SlopeSLL

(8)

Where SlopeOPL = hpr ⁄ q2sr, op is the slope of the operating point line in the compressor map, while SlopeSLL = hpr ⁄ q2sr, SLL is the slope of the surge point line in the compressor map.

The variable SS is calculated continuously in the antisurge controller. Since SS is less than 1 for normal operation, and SS is greater than 1 when the system is in surge, this allows for easy judgement of different compressor systems by using the same surge parameter variable. The antisurge controller continuously calculates how much the operating point deviates from SCL using the SS parameter considering the overall control margin (b). The new calculated parameter is well known as the deviation (DEV) and is typically being calculated as per Equation 9: DEV = 1 – SS – b

Figure 1. An example of a two-identical parallel compressor network.

August 2021 46 HYDROCARBON ENGINEERING

(9)

The DEV is positive when the operating point is to the right of the SCL. In this case, if

the antisurge valve is not fully closed, the antisurge proportional-integral (PI) response should gradually close it.

The DEV will have a value of zero at the SCL. The DEV will be negative when the operating point is to the left of the SCL. The controller will vary the position of the antisurge valve as needed to keep the operating point on or to the right of the SCL. In its closed-loop response, the antisurge controller will vary its output based on its PI tuning parameters and then might use its open-loop recycle trip response if the operating point crossed the recycle trip line (RTL) to protect the compressor from surge.

It should be noted that there are many cases where the antisurge valve opens even if the calculated DEV is positive.

Examples include being in a process limit condition, receiving a compressor stop or emergency shutdown (ESD) request, or recycle-balancing with other trains in a parallel compressor network. These conditions, among others, override the DEV calculation loop, ‘forcing’ the antisurge valve to open.

Load-sharing and load-balancing There are many methods used to implement load-sharing among parallel compressor control applications.

One method is commonly known as the base-loading method, in which the operator would select the more efficient train and ‘base-load’ it either at the maximum speed (for maximum flow) or at the maximum efficiency (for minimum power consumption). Clearly, this method is not optimal as it requires operator intervention.

A second method is based on flow-balancing. There are many disadvantages to this method, including additional flow elements and controllers – which increases the capital cost – and a triple cascade control scheme (pressure into flow into speed), while for dissimilar trains one train might surge before the other, especially at low loads.

CCC’s equidistant from surge load-sharing/load-balancing method has mainly two responses: Load-sharing (primary capacity response): master controller’s pressure or flow control response is broadcasted to each train. If the DEV is positive, the primary capacity response manipulates the load-sharing controller final element, satisfying the master controller demand. If the DEV is negative or zero (this can also be tuned), the system manipulates the antisurge valve to further help with not getting the compressor into surge.

Load-balancing response: each load-sharing controller selects the lowest DEV reported by any of its companion antisurge controllers and use it as a process variable (PV). These lowest DEVs are then reported to the master controller, which calculates the average DEV and sends it back to each load-sharing controller as a common load-balancing SP. Each load-sharing controller calculates a proportional-integral-derivative (PID) load-balancing response to raise or lower the

Figure 2. Parallel compressor operation (load-balanced).

Figure 3. Parallel compressor operation while the load-sharing (LS) controllers are in soft manual mode (not load-balanced).

Figure 4. Parallel compressor operation with load-balancing gain equal to 0 (not load-balanced).

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AS valves closed.

Altering the master SP while maintaining the header discharge throttle valve (FV-003) at 100% open will result in distributing of the load across both trains and the Figure 5. Parallel compressor operation (Train 1 is unloaded and Train 2 is running on network will still maximum speed). balance, as shown in Figure 2. The red line represents the SLL and the green line represents the SCL. The current speed for both compressors is 6500 rpm, delivering the same flow to the discharge header.

The next step is to vary the output of the Figure 6. Parallel compressor operation with reduced plant demand (recycle-balancing LS controllers in soft disabled). manual mode. For example, reducing the output of LS1 to 55% will reduce Train 1 speed to 5870 rpm and increasing LS2 output to 85% will increase Train 2 speed to 6620 rpm, as shown in Figure 3. Each train will deliver different flow quantity. Since LS controllers are in soft Figure 7. Parallel compressor operation with reduced plant demand (recycle-balancing enabled). manual mode, there will be no balancing and each train will performance of the train to bring its DEV value equal follow its own manually given output. The perception of to the master controller’s average DEV. using manual mode for LS controllers will paralyse the equidistant from surge technique.

This method ensures that each compressor runs at Next, the load-balancing gain can be put equal to the same distance from its SCL, preventing any parallel 0 for both LS1 and LS2 before they are turned into compressors from recycling until all are operating at automatic mode. It will be seen that both trains will their surge control limits and balances their loads when increase their outputs/speeds in the same direction, as operating away from those limits. shown in Figure 4, to satisfy the master controller SP. The network will not balance since the load-balancing gains Load-balancing simulation are set to 0.

Figure 1 shows the process being simulated with To load-balance the two trains again, the second step two-identical centrifugal compressors in parallel. There can be repeated and the load-balancing gains can be put is a common master controller (MC) controlling header equal to 1 for both LS1 and LS2. If LS1 and LS2 are turned discharge pressure while each compressor train has its into automatic mode, Train 1 will increase its speed from dedicated antisurge (AS) and load-sharing (LS) 5870 rpm to 6500 rpm and Train 2 will reduce its speed controllers. from 6620 rpm to 6500 rpm in order to balance the The first step is to see how the two-identical network on the received remote SP (average DEV) from compressor network operates at the same distance from the master controller. The network would balance and surge in a load-balancing scheme. As shown in Figure 1, each train will deliver the same flow quantity, as was flow is divided between the two trains with both shown in Figure 2.

August 2021 48 HYDROCARBON ENGINEERING

Figure 8. Parallel compressor operation with reduced plant demand (recycle-balancing enabled).

Recycle-balancing For parallel compressor systems, the AS controllers can also equalise the recycle rates to avoid unnecessary recycling. If the load declines to a point where recycling becomes inevitable, the load-balancing will not ensure that the recycle rates are identical for all the compressors. In that case, recycle-balancing works to equalise the recycle. Each AS controller compares its output to the output of the parallel AS controller(s) and if its output is less, it will increase its own recycle rate to match the highest output.

in Figure 6, and each train will be running at its own speed and flow.

The next step is to unload Train 1 and then enable the recycle-balancing feature in both trains (the recycle-balancing rate can also be regulated).

After loading Train 1, both trains will end up sharing the required recycling to meet the reduced plant demand. This is accomplished by an AS valve opening of around 10% in each train. Both trains will have the same speed, flow, and recycling values. The network is both load- and recycle-balanced, illustrated in Figures 7 and 8.

Recycle-balancing simulation

Summary

For the same process described above, Train 1 can be unloaded. Here, Train 2 will be forced to increase its speed (to 7000 rpm) as shown in Figure 5, while trying to maintain the demand from the master controller since it is the only train left contributing to the discharge header.

Reducing the plant demand by closing the discharge header throttle valve (FV-003) from 100% to 70% should result in an increase in the header discharge pressure.

If Train 1 is loaded now it will enter the start-up sequence, increasing its speed and ramping its AS valve close. This will result in a further increase in the header discharge pressure. When the Train 1 AS controller enters the run state, and since the master header discharge pressure became more the SP, the master controller will command both trains to lower their speeds. This forces Train 1 to hit its SCL earlier than Train 2 and start to recycle to maintain its operating point on the SCL. Train 2 will ‘slowly’ load-balance with Train 1 at DEV equal to 0 without any recycling. Finally, Train 1 will recycle around 21% while Train 2’s AS valve will remain closed. The network will not recycle-balance, as shown

CCC antisurge, load-sharing, and master controllers integrated applications can load-balance and recycle-balance centrifugal compressors running in parallel. Equalising the relative distance from surge, or DEV, is the best means for distributing flow amongst parallel compressors. Through this way dissimilar trains can easily be accommodated. In low plant demand circumstances and when recycling becomes inevitable, a recycle-balancing control strategy can be applied to further optimise parallel trains. Additional features within CCC controllers (such as performance override control [POC] and loop decoupling) can be used to further stabilise the process within its safe boundaries.

Bibliography 1.

2.

3.

JACOBSON, W., et al., ‘Compressor Loadsharing Control and Surge Detection Techniques’, paper given at 45th Turbomachinery & 32nd Pump Symposia for Turbomachinery Laboratory, Texas A&M Engineering Experiment Station, Houston, Texas, US (September 2016).

Compressor Controls Corp.; AN21 Load Sharing for Parallel Compressor Networks (February 2014).

Compressor Controls Corp.; UM6411 and UM6412 Reference Manuals (March 2019).

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Hydrocarbon Engineering talks to a number of leading experts in compressor technology about efficiency, equipment reliability, safety and the environment, digitalisation, and life after the COVID-19 pandemic.

Ben Williams, Process Compressor Sales & Market Development Specialist, Ariel Corp.

Ben is the Process Compressor Sales & Market Development Specialist for Ariel Corp., located in Mount Vernon, Ohio, US. His responsibilities include the sizing and selection of Ariel’s API-618 Moderate Speed Process compressors and consulting with Ariel distributors, end-users and EPCs on their compression requirements. He has over 35 years of experience with reciprocating compressors; primarily those associated with the refinery and petrochemical industries.

Sami Tabaza, Gas Processing Market Manager, Atlas Copco’s Gas and Process Division Sami Tabaza is the Gas Processing Market Manager for Atlas Copco’s Gas and Process Division. With more than a decade of experience in turbomachinery business development, marketing and applications engineering, Sami has held various positions in the US and Middle East. He currently oversees gas processing centrifugal compressor applications in the NGL and fractionation plants, focusing on process improvement, product optimisations, and standardisation.

Ben Berwick, Product Manager, Cook Compression Ben Berwick joined Cook Compression in 2020, bringing 25 years’ experience creating technology solutions for increased reliability and efficiency of industrial rotating machinery and compression systems. Ben previously served in design engineering, strategic marketing, and leadership roles for Bently Nevada Corp., Dresser-Rand, Rolls-Royce Power Systems, and Honeywell Process Solutions.

Brian Pettinato, Manager of Aero and Structural Dynamics, Elliott Group Brian Pettinato is Manager of Aero and Structural Dynamics at Elliott Group in Jeannette, Pennsylvania, US. He has been with Elliott Group since 1995. His primary area of expertise is machinery dynamics. Brian is a fellow member of ASME, a member of STLE, and a registered Professional Engineer in the State of Pennsylvania. He serves on the Turbomachinery Advisory Committee of Texas A&M and on the API 684 rotordynamics task force.

Richard Smith, Director of Product Strategy, Howden Richard has approximately 40 years of experience in providing practical customer solutions for process applications combining thermodynamics and rotating machinery. Initially orientated toward heat transfer and change of state involving heavy slow rotation machinery, an early career change toward gas compression developed a broad experience across the power generation, mineral refining, petrochemical, and general heavy industries. High power applications involving fans, rotary, reciprocating compressors coupled with the high speeds of turbo technologies, have created solid foundations to recognise and provide optimum and reliable process solutions.

Pallavi Baddam, Manager of US Applications Engineering & Process Automation, Mitsubishi Heavy Industries Compressor International (MCO-I) Pallavi Baddam is the Manager of US Applications Engineering & Process Automation at Mitsubishi Heavy Industries Compressor International (MCO-I) in Houston, Texas, US. Pallavi began her career as a control systems engineer for gas turbines with Rolls-Royce Energy Systems Inc. (now Siemens Energy). She later worked for Dresser-Rand Co. as a Proposal Development Engineer prior to joining Mitsubishi Heavy Industries where she leads the application engineering group and also heads the development of automated design tools. She has extensive experience (over 15 years) in turbomachinery used for the oil and gas industry and has worked on many challenging projects.

August 2021 50 HYDROCARBON ENGINEERING

Explain why compressor technology is so crucial to downstream operations.

Ben Williams, Ariel Corp.

Compressor technology, whether it be selection tools, improvements in components, monitoring, predictive maintenance, or an advanced support network, all lead to improved reliability. Reliability is key in the downstream industry. Downstream compressors must meet the demanding requirements of the industry and run for extended periods between shutdowns.

Reciprocating compressors must continue to operate reliably while being subjected to changing operating conditions, gas compositions or capacity (flow) requirements. The design and materials of construction for compressor components such as valves, seals and capacity control devices are crucial to reliable operation.

Ben Berwick, Cook Compression Compressors are fundamental to the operation of downstream facilities. Similar to the crucial role that pumps serve in moving liquids, compressors generate the necessary pressure rise to move gases – of varied type and purpose – throughout a downstream facility. From the crucial yet relatively low pressure (150 psi) plant utility air systems serving instruments, pneumatic tools, rotating devices, and plant control devices, to the 50 000 psi hyper compressors essential for low density polyethylene (LDPE) production, compressors serve a wide breadth of applications.

Whether reciprocating, centrifugal, or screw type, compressors are typically a large energy consumer, are essential to continuous production, and must reliably and safely transport high pressure and often hazardous gases throughout numerous plant processes. Accordingly, compression technology – encompassing the electrical systems that control and monitor compressors, to the mechanical parts and engineered materials of their componentry – is crucial for minimising energy consumption, downtime, and risk to plant personnel and the environment we all share.

Brian Pettinato, Elliott Group Downstream operations such as oil refining, chemical, and petrochemical processes operate on a continuous basis often going anywhere from 3 to 10 years without ever shutting down. Each centrifugal compressor is an essential part of these processes constituting a major capital expense that is engineered to order and often the determining factor for plant or process throughput. Compressors require a considerable amount of energy and expense to operate. So, of course, compressor technology is quite crucial. Compressor technologies that address such typical concerns as efficiency, range, durability, and safety have been under continuous development from the beginning. More recent technologies include developments for reduced emissions, reduced noise, and improved operational flexibility.

Pallavi Baddam, Mitsubishi Heavy Industries Compressor International (MCO-I) Downstream applications such as petrochemical operations involve many complex processes where boosting the pressure of the gas helps promote catalytic reactions, thermal decomposition, refrigeration operations and generation of byproducts. For example, in an ethylene plant, the hydrocarbon feedstocks are cracked at temperatures between 1470°F and 1580°F (800°C and 860°C). The cracked gas is then quenched and cooled before it enters the compressor. The compressed crack gas goes through acid removal, drying and cryogenic separation processes (i.e. further fractionation) in order to separate into different byproducts such as ethylene and propylene, etc. Multiple compressors are used in the above process, i.e. for cracked gas compression, ethylene and propylene refrigeration.

Compressors are crucial in these processes as they strongly influence overall plant performance, efficiency (power consumption), and operational reliability, including safety and environmental impact.

How can compressor technology help to improve efficiency in gas processing and downstream operations?

Ben Williams, Ariel Corp.

Improved efficiency can come in many forms; the efficiency at which the compressor operates when compressing gas, the efficiency with which it meets varying operating conditions, extended operating hours between maintenance needs, or the efficiency at which replacement parts and capable service providers are available. All of these ‘technologies’ improve the operations experience.

Sami Tabaza, Atlas Copco’s Gas and Process Division Selecting the right compressor technology based on the application and plant’s operation philosophy is key for improving the throughput of the plant. Operators examine compressor equipment from various efficiency angles: CAPEX, OPEX, power efficiency, emissions, as well as footprint. These aspects are all considered efficiencies, and they provide the reason why plant owners and operators tend to select compression technology specific to their plant’s applications.

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IGC, for example, has high power efficiency and meets other required efficiencies relevant to CAPEX/OPEX/footprint.

This is due to how it is designed and optimised. As an example: in refrigeration compressors where the compressor’s efficiency drives the complete refrigeration cycle’s coefficient of performance (COP), the compressor technology improves overall gas plant efficiency.

Brian Pettinato, Elliott Group Downstream operations are often looked at holistically. Simply stated, it is the overall efficiency that matters, and this is inclusive of the compressor, driver, and overall plant. The first step is to properly select and match the compressor to the requirements of the process, not just at a best efficiency point, but over the map of expected operation. Just as important is a good match between the compressor and the driver. Overall efficiency is essentially an exercise in multi-variable optimisation, and this is heavily dependent on available technology.

Centrifugal compressor technology has never stopped advancing. Stage efficiency has been improving via increasingly sophisticated 3D impeller and return system geometries and application of improved surface finishes. The efficiency of stacked stages has been improving via better stage-to-stage matching. Efficiency is better maintained over the long-term by wash systems and coatings that prevent compressor fouling and erosion. Compressor efficiency is further improved by management of secondary flows using advanced seal concepts. Finally, reduction of parasitic power losses at bearings and other locations provide further energy savings. Efficiency continues to improve as more advanced technology is put into play.

Richard Smith, Howden Efficiency improvements in downstream operations is often a factor of utilisation and hence compressor reliability is a key factor.

The basics of compressor technology have all been long established and, as a whole, the industry and its key players are mature. Continuous developments in materials, lubricants, seal and valve design, together with computer aided analysis and design, all combine to provide marginal improvements in efficiency, reliability and extended mean time between maintenance (MTBM). For efficient operation, it is imperative that the correct compressor technology is selected based upon: 1.

Volumetric flow, pressure rise, static pressure range, temperature range.

2.

Continuous or intermittent operation.

3.

Flow and pressure regulation requirement.

It is this third criteria of flow and pressure regulation that is too often overlooked in helping to improve efficiency in downstream operation. Plants rarely operate at design and hence the ability of the selected compression technology, together with its capacity control technology to maintain high efficiency away from design flow or pressure, can significantly influence plant operation. Additionally, today’s process requirements often operate on shorter timescales as customers are producing more on demand.

Pallavi Baddam, MCO-I In the example of an ethylene cracker plant (provided in my previous answer), compressors constitute the largest energy consumption. Typically, petrochemical plants spend millions of dollars each year in fuel for steam production or electricity to power these compressors. Compressor power consumption is directly proportional to its overall polytropic efficiency, and therefore every percent of efficiency improvement translates to reduction in overall power consumption and plant operating costs.

What steps do you take to improve equipment reliability and safety?

Ben Williams, Ariel Corp.

Reliability begins with the compressor selection. With a reciprocating compressor, lower piston speeds, reduced discharge temperatures and lower valve impact velocities will all improve the life of the non-metallic wear parts. These items are taken into consideration when making the initial compressor selection. Ariel provides an industry leading compressor selection tool and offers a line of moderate speed reciprocating compressors specifically designed to meet the reliability requirements of the downstream industry.

Established limits, design guidelines and work instructions/procedures must be followed to ensure safe and reliable operation of a reciprocating compressor.

Sami Tabaza, Atlas Copco Gas and Process Equipment reliability is the probability of a machine or an individual component to deliver the intended function within the given conditions for a given time duration. By definition, safety means to be free from an unacceptable risk of harm.

The original equipment manufacturer (OEM) bears responsibility for part of this aspect, while the other part of the August 2021 52 HYDROCARBON ENGINEERING

OUR RAPID RESPONSE PROMISE

WE PROMISE IMMEDIATE SUPPORT. THEN WE OVER DELIVER.

YOUR PLANNED MAINTENANCE PROFESSIONALS DETAILED PLANNING & EXPERT SUPPORT ENSURES RELIABILITY

Unexpected emergencies happen but can be mitigated with proper maintenance planning. Proactive maintenance is vital for long-term profitability. Implications for delaying machine maintenance can include losses to production even pre-outage and postponing scheduled maintenance may result in a larger workload during an outage timeframe. With proper forward planning, costs can be reduced by up to 20%.

Contact service@mhicompressor.com to stay ahead.

MCO-I Pearland Works 14888 Kirby Dr. Houston, Texas 77047 Tel: 1-832-710-4700 mcoi.mhi.com

responsibility lies with the operators and process team at site (for example, to follow recommended operation and maintenance procedures). Equipment reliability and safety is directly associated with its quality.

The knowledge and experience of proven design, manufacturing processes, quality procedures and onsite or field tests are essential to delivering a quality machine. This results in higher reliability and safety. For the compressor OEM, for example, it starts with the design stage of the equipment: sizing the machine and its individual components in a proper way, selecting the right materials for the site conditions, plant location and process, engineering calculations (i.e. computational fluid dynamics, finite element analysis, etc.). Installing a proper asset performance monitoring system (i.e. temperature and vibration monitoring probes and system) is another example. All of these steps are very important for the reliability of this critical equipment in a gas plant or in downstream operations.

Lastly, I always encourage our teams to look very closely at what surrounds the designed equipment and the circumstances associated with different mode of operations. So, if there is anything that needs to be looked at and addressed in that context, it is done during machine design and manufacturing.

Ben Berwick, Cook Compression Cook Compression closely equates reliability with safety. The reliability of compressor components is foundational to ensuring overall safe compressor operation. It is too easy to surmise that some compressor component failures may only have a small consequence. Even where a failure results in considerable production or capital loss, those negative outcomes remain small and inconsequential relative to the ever-present likelihood that a compressor component failure could lead to a systemic failure – causing personal injury or the release of an explosive or environmental hazard. This is especially true for the high stresses that compressor valves, packings and sealing components endure. The solution for reliability is in two parts: in the component design and in proper maintenance.

For downstream applications, Cook Compression designs components to the particular circumstances of each application, including but not limited to the range of expected gas composition, speed range, pressures, gas loads, lubrication and temperature range. Engineers then optimise the component designs by drawing from a breadth of common and specialty materials to ensure reliability and safety, as well as to maximise efficiency and longevity. Once installed and run for a period of time, component reliability depends on the aforementioned application-specific design as well as adherence to recommended maintenance activities.

Long-term best practices for maintenance include evaluating changing operating conditions, such as those that might arise from feedstock property changes. Given the decades-long lifespan of most reciprocating compressors, they are likely to operate with different gas compositions, pressures and output requirements at various points in their life. When such changes occur, the cycle of reliability must begin again, including a re-evaluation of the components’ suitability for safe and reliable operation under the new conditions and, where necessary, a new optimised design.

Brian Pettinato, Elliott Group Quality, reliability and safety are very much inter-related. The starting point is people: their knowledge, training, communication, discipline to processes, ability to perform clean hand offs, their ability to ask ‘what could go wrong?’, and empowerment to apply foresight and make necessary changes. Of course, even with good people, there are always improvements to be found. Robust quality and corrective action systems are essential to ensure that necessary changes make it back to the people and vendors, and then into designs, procedures, and systems. The thought process for a good safety decision also applies to quality, and reliability. Technology development is only slightly different in that we intentionally go well beyond operational limits and actually confirm wear, breakage, instability, and other failure mechanisms for the purpose of establishing robust margins that improve the safety and reliability of our products.

Richard Smith, Howden Safety is at the core of what we do throughout our business. Our commitment to safety is embedded throughout all departments and locations in Howden. Our people and processes foster this culture across product lifecycle including design, manufacturing and testing, to transport, installation and operation as well as maintenance.

Safety and awareness training is carried out frequently within Howden, where performance is monitored and challenged monthly at board level in pursuit of achieving zero accidents. Additional experience from even minor incidents is circulated both internally and externally via safety alert notifications.

With over 160 years of engineering excellence, Howden is recognised as a trusted supplier of reliable compressors that meet the demands and specifications of continuous critical service applications, often operating in harsh environments.

For Howden, continuous improvement of equipment reliability and safety is carried out through design. It is also important to recognise that reliability directly affects safety, not only the consequences of a catastrophic failure, but more that lack of reliability usually demands human intervention – and working on site is an increased risk for safety.

Howden Uptime, the company’s performance analytics tool, supports the implementation of new processes in the digital refinery. It delivers actionable insights into how equipment is operating under specific conditions. This insight can predict when equipment needs maintenance, which can then be used to prevent any cases of unexpected downtime resulting in cost savings, increased reliability and increased safety.

August 2021 54 HYDROCARBON ENGINEERING

Pallavi Baddam, MCO-I Centrifugal compressors handling high pressure and high density gas can sometimes encounter rotor instability, high bearing temperatures and vibrations while in operation. MHI has continuously improved the reliability of compressors by coming up with various ways to attenuate the rotor vibration by performing various rotor dynamic analyses during the design stage and mechanical run tests.

Typically, in a cracked gas compressor, fouling is a common phenomenon which not only has a crippling effect on compressor performance but also causes the unit to shut down due to increased vibration levels. Thus in order to ensure safe and reliable operations, we use anti-fouling techniques such as SermaLon coating to avoid corrosion and foulant deposition on the surfaces and water injection to avoid the polymerisation at high temperatures, by keeping the gas temperatures lower.

Incorporating features such as remote monitoring helps with predictive maintenance of the equipment, thereby allowing us to take early action prior to fault detection. The goal behind remote monitoring is to increase the availability by avoiding unscheduled maintenance and minimise the scheduled down time.

In addition to this, solutions such as extended overhaul intervals, smaller maintenance windows, compact and light equipment, modularisation or package standardisation as a means of reducing cycle time and cost, all help to ensure safe and reliable operations.

How can compressor technology assist plants operating in extreme environments or with demanding applications?

Sami Tabaza, Atlas Copco Gas and Process Flexible and robust compressor technology is important to operate in extreme environments and demanding applications.

Examples include installations in extreme sour applications, or in offshore or extreme high- or cold-temperature environments.

Unexpected changes in the suction conditions, such as temperature, pressure or mol weight, can also affect the compressor performance. In such scenarios, flexible and robust compressor technology can counter such unforeseen conditions, preventing major disruption of the compressor’s operation.

Ben Berwick, Cook Compression For compressors in extreme environments and demanding applications, highly engineered products are paired with specially formulated materials to achieve efficiency and reliability targets. Thermoplastic materials can be optimised with custom fillers to maximise the function of the component (e.g. oil wiping) and to address specific process needs (e.g. non-lubricated, dry gas, high temperature). Experience has shown that specially formulated materials, paired with a fit-for-purpose design, can extend seal component life while improving sealing effectiveness and compressor throughput.

Plants operating with demanding conditions must balance longevity of components with cost-effectiveness. Exclusive specialty materials such as Vespel or Torlon can provide high performance in difficult applications, but at excessive cost and lead time relative to uniquely blended PTFE and PEEK formulations. Component manufacturers who possess the in-house knowledge for creating and proving out such blends provide a balance of performance, cost and timely delivery for plants.

Richard Smith, Howden For plants operating in extreme environments or with demanding applications, selection of compressor technology based on reliability and safety should be the priority. This inherently results in a compressor that is robust and provides ease of maintenance, another important consideration for often remote, extreme environments.

Ultimate efficiencies are usually the product of fine tolerances, demanding relatively clean process gases and operating environments to allow these tolerances to be maintained.

Circumstances where compressor operation will be in an extreme environment or has a demanding application favour compressor selection based upon reliability, aiming to achieve improved plant efficiency by ensuring maximum availability and utilisation. Outages in remote and extreme environments can often be lengthy and costly.

How can compressor technology help to reduce emissions in downstream operations?

Brian Pettinato, Elliott Group As previously stated, compressors require a considerable amount of energy to operate. They are often driven by very large motors, steam turbines, or gas turbines. Reducing the energy requirement through efficiency is a key to reducing emission in downstream operations.

Another form of emissions is that of the gas stream itself. Such emissions are of particular concern because they can have a greater impact on health, safety, and the environment. Gas stream emissions can be categorised as either captured or fugitive. Captured emissions occur along controlled leak paths, such as the oil or dry gas end seals of a compressor where the emissions are captured and then sent for processing or flaring. Fugitive emissions, if there are any, are August 2021 56 HYDROCARBON ENGINEERING

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For over 40 years, Atlas Copco Gas and Process has custom-engineered turbomachinery for the challenging processes found in downstream applications. Our reliable integrally geared and single-shaft compressors are designed to readily adapt to changing conditions, making it easier for you to keep productivity high and OPEX low.

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uncontrolled and go directly to the atmosphere. These emissions typically occur at joints and other static seal locations throughout the plant, and this can include the horizontal or vertical joints of a centrifugal compressor as well as its nozzles and other connection points. More rarely, fugitive emissions will be the result of a material or weld rupture.

A new compressor when first installed will operate at its designed efficiency. Fugitive emissions are not a problem and captured emissions are as designed using acceptable amounts of available buffer gas. But it is not enough to have good efficiency and low emissions just at commissioning, these need to be maintained throughout the life of the equipment.

Wash systems and coatings are applied to reduce fouling and keep compressors at peak efficiency between turnarounds.

Specialty materials and cladding are used for resistance to wear from corrosion and erosion. Aerodynamics can be upgraded during planned outages to shift the compressor map for new operational requirements, new gas composition, or simply to improve the efficiency of older machines. Oil seal upgrades to better oil seals or to dry gas seals can reduce the amount of captured emissions that requires additional processing or flaring. Leak paths that develop along casing horizontal or vertical split-lines can be managed through repair, redesign, and in some cases, by advanced sealants.

Compressors are also an enabling technology for emission reduction through carbon capture and sequestration.

Ben Berwick, Cook Compression Minimising compressor emissions is closely linked with proper configuration and maintenance. For instance, reciprocating compressors operating with valves that do not maximise process flow require greater input power to overcome the valves’ inefficient operation. For an engine-driven compressor, or a motor-driven compressor supplied by a fossil fuel-driven electrical generator, that inefficient valve ultimately leads to excess CO2 emissions from excess fuel burn. Likewise, poorly maintained valves and valve designs that are more prone to fouling will effectuate the same indirect contribution of excess CO2 emissions in driving the compressor.

The packing case of the reciprocating compressor is the primary source of emissions of the process gas itself. While most downstream compressors utilise vapour recovery and purge systems to prevent direct leakage to the atmosphere, those systems have limited capacity and under certain conditions may be taken to flare. Ultimately, minimising emissions in both direct and indirect form requires proper component selection and best practice maintenance for the specific operating conditions and overall compressor design.

Pallavi Baddam, MCO-I Petrochemical plants (along with others like steel, cement, etc.) emit carbon due to the complex thermal processes and high temperature heat requirements. As such, carbon capture, utilisation and sequestration (CCUS) is one of the most mature and cost-effective options to reduce emissions. CO2 compressors are intrinsic to this process. In addition to improving the compressor efficiency to reduce the overall emissions, the plant owners are also considering options such as vent recovery systems and using large electric motors instead of traditional steam turbine drivers to reduce the carbon footprint.

What has been your company’s biggest recent achievement or innovation in compressor technology?

Ben Williams, Ariel Corp.

Ariel Corp. has recently released the Ariel Smart Compressor (ASC). This system is installed on the compressor frame by the manufacturer. The system includes a number of electronic sensors, wired to an onboard central processing unit (CPU).

The CPU will deliver data to local control panel(s) and remotely to the cloud.

Among the data collected and available are process gas pressures and temperatures, lube oil temperature, valve cap temperatures, main bearing temperatures and compressor vibration. The collected data will be invaluable in trend analysis, maintenance planning and compressor performance optimisation.

Sami Tabaza, Atlas Copco Gas and Process It is a challenging question, because in all the different market segments Atlas Copco Gas and Process is active in, there have been achievements and innovations in their own right. But when talking about Atlas Copco IGC’s in various markets, we have completed some great developments.

Recently, our technology has gained stronger acceptance in some of the most challenging applications while replacing other traditionally accepted and used technologies in many projects. For example, we have gained ground compared to screw and recips in PSA tail gas, which is a varying mol weight application. Other examples include IGC being used instead of screw or between bearing centrifugal compressors for medium to large-scale refrigeration applications, or instead of recips or between bearing centrifugal compressors for high pressure boil-off gas applications in LNG plants.

Brian Pettinato, Elliott Group Our most recent achievement has been the development of Very High Flow coefficient covered wheel compressor stages.

The previous technology of High Flow Coefficient covered wheel compressor stages had been developed for flow

August 2021 58 HYDROCARBON ENGINEERING

The Ariel Smart Compressor. The next generation in compression monitoring, optimization, and management. Our unique electronic platform includes sensors that relay measured data to an onboard central processor that delivers compressor operational and condition data to your preferred location or personal device via the Ariel Fleet Manager. Reduce downtime, cost of ownership, and environmental impact, while operating at peak efficiency with the Ariel Smart Compressor.

www.arielcorp.com/arielsmartcompressor

coefficients above 0.10 and crossing just above 0.2. Our latest technology takes us above 0.25. This enables us to select a smaller and faster compressor that is a better match to a steam turbine or gas turbine driver.

Richard Smith, Howden This depends on how “biggest recent achievement or innovation” is defined. In terms of downstream operations, it would have to be Free Floating PistonTM technology for Howden’s Thomassen oil-free reciprocating compressor and especially its application for hydrogen compression. The extended continuous running of oil-free reciprocating compressors on hydrogen at up to 100 bar and 20 MW rating is now well proven with blue chip producers, some having in excess of 100 000 hr operation without the need for piston ring or bearer band change and with no noticeable reduction in performance.

We are experiencing a significant increase in activity and business in this area, which is linked to the expanding market for biofuels and the inevitable hydrogen economy.

Howden has served the grey hydrogen market in a large number of applications for many years. For the rapidly evolving green and blue hydrogen markets, Howden solutions already serve a wide variety of clean energy/hydrogen applications such as eFuel, green steel and hydrogen refuelling stations, as well as power-to-gas worldwide.

Pallavi Baddam, MCO-I Increasing demand for products such as plastics, fertilizers, etc., in the world is driving plant sizes/capacities and, in turn, compressor sizes. This trend is common for not only the greenfield plants but also brownfield expansions. In order to meet the increased train capacity, and maximise process efficiency with minimum equipment and CAPEX, MHI has been continuously making improvements to the compressor design by incorporating impellers with large flow coefficient impellers and improved efficiency, etc. MHI also has vast experience with ‘Footprint replacement’ (FPR) applications where the existing compressors and/or steam turbines are replaced with new higher performance machines whilst keeping the same foundation/footprint. The FPR feature allows for a larger expansion capacity (e.g. ethylene plant 711 000 tpy -> 1.1 million tpy) at a lower cost compared to traditional revamp/re-rotoring of existing machines.

MHI’s recent achievement includes providing new compression equipment to the world’s largest ethylene (2.3 million tpy) and ammonia (3600 tpd) plants.

How have advancements in digitalisation changed the compressor sector?

Ben Williams, Ariel Corp.

Although condition monitoring has been around for decades, the ability to view and control the compressor from anywhere in the world at any time has revolutionised the compressor industry. Data collection has proven invaluable in troubleshooting and trend analysis of the compressor and its components.

Sami Tabaza, Atlas Copco Gas and Process Currently, there are many initiatives and changes taking place in our company related to Internet of Things (IoT) and digitalisation, and this is happening across all divisions and business areas within the Atlas Copco Group worldwide. In the Gas and Process Division, there is a wave of automation processes that are being developed to improve efficiency in all departments including applications, engineering, analytical groups, aerodynamics, and also in workshop and logistics.

These measures help to optimise processes and their efficiency.

We will ultimately see things going in the direction of greater speeds – translating into shorter lead times and deliveries to customers, but at the same quality level. Customers are bound to benefit from all these advancements in other ways too, e.g. through cost optimisations helping the feasibility of their projects.

During the COVID-19 pandemic, our remote monitoring and remote commissioning solutions have helped many customers to run and start the plants on time with very limited in-person resources available on site.

Ben Berwick, Cook Compression Digitalisation has arguably provided, and will continue providing, the greatest opportunity for improving overall equipment effectiveness (OEE) for compressors. Hydrocarbon processing facilities began adopting digital technologies in asset management decades before the current wave of Cloud/Industrial Internet of Things (IIoT) technologies, analytic-based data science tools, and digital connectivity solutions. While the initial generation of digital technology matured and served reliability professionals exceptionally well, today’s digital solutions are contributing dramatic advances.

Reliability-centered maintenance (RCM) and condition-based maintenance (CBM) stand out as areas that are increasingly governed by modern data availability and analytics. With today’s leading technologies, compressor operators are connecting individual component sensors and integrating existing legacy data systems with maintenance management systems and digital twin technologies, which have been demonstrably effective in improving predictability of equipment health and revealing ways to optimise uptime and efficiency. The key to these systems’ efficacy is less about the technology, however, and more rooted in how they can embed operational and subject matter expert (SME) knowledge within August 2021 60 HYDROCARBON ENGINEERING

INNOVATION

FOR THE HYDROGEN TRANSITION

For more than a century, Cook Compression has developed innovative sealing and valve technologies to move the compressor industry forward. Today, we are ready for the next big move – toward a carbon-neutral future.

Our state-of-the-art development capabilities build on years of experience extending equipment run times in hydrogen and hydrogen blends. With our brand-new Innovation Lab, expert engineers and dynamic TruTech™ materials portfolio, we continue to design new solutions and set new standards for performance.

Partner with us today to create a green tomorrow. cookcompression.com/h2-innovation North America +1 877 266 5226 Europe +44 151 355 5937 China +86 21 24112600

Cook Compression is a proud part of Dover Precision Components

RCM/CBM. For all that digital hardware and software adds to the compressor sector, it is digitisation’s ability to enhance SME productivity that drives improved OEE outcomes. Success is premised on the fact that digitisation facilitates collaboration among SMEs representing the compressor operators, maintenance teams, OEMs, and component manufacturers.

Richard Smith, Howden Historically, Howden has contracted to supply both bare shaft machines and skid mounted compressor packages. The skid mounted compressor packages for the oil and gas market in particular are always provided with extensive instrumentation for control, monitoring and protection. The split between local control panel with a programmable logic controller (PLC) and interface for customer connection to their distributed control system (DCS) has gone in favour of the latter, especially for downstream operations. In many cases, this information had always been available but from a security perspective, contained by customer concerns.

Improvements in communications technology and its security, coupled with an increase of remote operation/control and reduced experience at site, has created a need and opportunity for IoT. We have developed Howden Uptime to bring real time communication options for customer support. Benefits include: compressor performance optimisation using digital twin technology, early warning of potential issues, extended maintenance intervals, avoidance of unplanned downtime, and expert advice close at hand (online assessment).

How has the COVID-19 pandemic impacted the downstream/gas processing compressor market?

Sami Tabaza, Atlas Copco Gas and Process Naturally, the pandemic has impacted the entire hydrocarbons supply chain, demand and supply dynamics, and it has also slowed down investments in all segments. The industry is seeing a spike in material costs and has experienced some challenges in logistics and transportation of goods across the globe. We’ve also seen many acquisitions recently, and our customer base is changing constantly.

On the positive side, the pandemic has expedited the move towards digitalisation and Cloud-based collaboration, both within our own teams and with customers. That is a very positive development which I expect will have a sustainable impact on the ‘ease of doing business’ in the future.

Pallavi Baddam, MCO-I As 2021 came into effect, the industry has seen a lot of pent-up demand due to the slowdown in 2020 as a result of the pandemic. The first six months of 2021, at least for MHI, have been extremely busy. Not only are the orders focused in ammonia and fertilizer and urea-type projects, but we are also meeting customer needs from traditional petrochemical, olefin and refinery facilities as well. Recently, MHI picked up a revitalisation project for the power generation sector. There is a lot of demand for projects that probably should have happened in 2020. Now, we would like to think that our customers are back on track expanding their businesses.

What does the future hold for compressor technology?

Ben Williams, Ariel Corp.

Hydrogen compression is not new but ‘green’ hydrogen production is an emerging market. Green hydrogen is hydrogen produced from electrolysis powered by renewable energy sources. These green hydrogen applications may lead to multiple types of compression being required to meet the higher pressure, higher purity requirements of the hydrogen market.

Lower suction pressures are typically better suited for reciprocating compressors and the higher discharge pressures, purity requirements and typical flow requirements may require other compression technology, such as diaphragm compressors or hydraulic intensifiers. Therefore, at times, a combination of compressor technologies may be required.

The IoT is another advancement in reciprocating compressor technology. This will enhance compressor monitoring and data collection, thereby improving operational reliability. The Ariel Smart Compressor (ASC) captures the power of this technology.

Ben Berwick, Cook Compression Given their fundamental role in transporting gases, compressors will continue to be vital to the energy industry’s future.

Accordingly, in the face of global challenges to reduce greenhouse gas emissions and conserve natural resources, compressor technology will continually evolve to operate with greater efficiency and lower energy consumption. Since compressors are often driven by electrical motors, they fit well within the progression toward renewable-generated electrical power. Moreover, as alternative fuels such as hydrogen come into the carbon-neutral mix of energy sources, August 2021 62 HYDROCARBON ENGINEERING

compressors will adapt to move that gas too. The challenge of compressing hydrogen fuel gas is maintaining gas purity (which requires non-lubricated components) and achieving high compression ratios. The stress and demands on sealing materials under such conditions exceed those in typical industrial hydrogen compression applications. As technology evolves to meet the challenges facing hydrogen fuel gas compressors, the resulting material technology is expected to feed back into many traditional downstream compression applications for further reliability, safety and efficiency advances.

Brian Pettinato, Elliott Group There is no reason to think that the trends of the last several decades will change for the downstream sector.

Compressors will continue to get more efficient. Power in a given compressor body will continue to go up. Speeds will continue to push even higher. Captured emissions will continue to be reduced. Noise and weight will continue to be concerns that are addressed. Controls and monitoring will continue to get smarter, more integrated, and more pervasive.

I think it starts to get interesting when we consider what will be needed to achieve this future: from the technology standpoint, we need even more advanced manufacturing, materials, analysis, and instrumentation.

Richard Smith, Howden Our mission is to provide products and services to enable our customers’ vital processes to advance a more sustainable world. To do this, we have an increased focus on the hydrogen economy, energy storage, biofuel production and energy recovery.

The United Nations Framework Convention on Climate Change (UNFCCC) has been active since 1992 bringing the world’s best scientists together with political leaders to recognise climate change, provide evidence of the causes and predict the consequences. To date, through various revisions of the UNFCCC Report on Climate Change, each update has provided evidence that exceeded prior predictions – all being worse. The need for change is finally being accepted.

Practical revolutionary compressor technology is not currently visible, and increased activity with biofuels and hydrogen will create a direction of evolution within compressor technologies. Gains for increased efficiency of compressor technology may only be achievable for short initial periods. The development of compressor capacity and pressure control features using instrumentation, data acquisition and analysis to drive advanced actuators are likely to bring the largest gains in performance and efficiency at ‘off peak’ design (variable clearance pockets, variable valve timing, and variable speed).

Brandon Stambaugh, Owens Corning, USA, provides an in-depth look at common challenges faced when insulating an LNG facility.

D

emand for LNG continues to grow as the world transitions to cleaner energy systems. As a result, new terminals and expansions of existing terminals have been planned and announced to meet this increased demand. Facility designers, engineers and contractors face a common set of challenges based on the facility location, layout and temperatures at which it operates.

This article will look at eight common challenges faced when insulating an LNG facility and how one insulating material – cellular glass – helps engineers and facility managers overcome these challenges while

improving facility safety, reducing maintenance and labour, and improving the workplace environment.

Thermal performance LNG facilities require insulation systems to address thermal performance at extreme temperatures. Primary process piping and equipment throughout these sites can operate at -165˚C (-265˚F), which means reliable and long-lasting insulation is needed to keep pipes and storage tanks at temperature without warping.

When insulation is subject to extreme temperatures, there can be a rate of thermal expansion or HYDROCARBON 65

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contraction. Organic-based insulations tend to contract more in cold and cryogenic applications than insulation types that are non-organic. Some organic materials, such as plastic foams, can have coefficients that are five to ten times larger than those presented by metal materials. This difference can lead to open joints and allow for unwanted heat gain, which reduces the overall thermal efficiency of the system. The movement may also allow entry points for moisture or water vapour.

However, using FOAMGLAS® cellular glass insulation systems, which are designed to function in temperatures ranging from -268˚C to 482˚C (-450˚F to 900˚F), provides thermal contraction complementary to that seen with carbon or stainless steel and concrete. Use of cellular glass insulation in situations where extreme temperatures occur may help reduce the number of contraction joints, eliminate the need for secondary (or multiple) vapour barriers,

protect joint seals, and keep moisture from entering an insulated system during temperature cycling.

Moisture protection – vapour drive Despite the cold temperature of the pipes, LNG facilities may face a particular challenge from moisture as many are situated in locations with warm and/or humid climates. Pipes or vessels may function at temperatures reaching down to -165˚C (-265˚F), and can be located in areas where the ambient temperature remains 32˚C (90˚F) or above with 90% humidity. As moisture seeks to move from hot to cold conditions, the combination of cold pipes or tanks and warm outside temperature drives moisture to insulation.

Adding permeable or absorptive insulation to a cold pipe can create a dew point where moisture can collect and potentially freeze within the insulation even if it does not reach the pipe. According to information from ASHRAE, approximately 98% of insulation failures are linked to moisture.1 The collection of ice within insulation can also add weight to the pipe and reduce the lifespan of equipment.

Moisture protection – corrosion under insulation (CUI) Cellular glass insulation is impermeable and can help protect LNG systems from invasion by moisture or water vapour. It should be noted that LNG facilities also have processes that operate at or above ambient temperatures that require insulation, or has piping that may be shut down for extended periods where corrosion risk is increased. The non-absorbent insulation does not promote corrosion on carbon or stress cracking corrosion of stainless steel. When used as part of a sealed system, the insulation can help prevent moisture from entering the system. Traditional cold sealed systems can be used in temperatures ranging from -196˚C to 121˚C (-320˚F to 250˚F).

Figure 1. LNG facilities face multiple challenges but

picking the right insulation can help improve system performance and safety.

Compressive strength and equipment support

The need for compressive strength cannot be overlooked when insulation is selected for an LNG facility. It is a necessary design consideration in insulation choice – especially when working with tank bases, piping or vessels. The failure of insulation materials from compression can hasten deterioration of the insulation system and result in mechanical system or equipment damage.

When insulation is used on pipe supports and hangers, providing a material with a high compression strength Figure 2. Cellular glass insulation is non-wicking, non-absorbent and allows for supports to be used impermeable to water and water vapour. on the outside of an insulation August 2021 66 HYDROCARBON ENGINEERING

OCTOBER 4-6, 2021

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

KEYNOTE SPEAKER PREVIEW

MORE 2021 KEYNOTE SPEAKERS TO BE ANNOUNCED!

Taking Command: Leadership and Risk Management

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

The Cook Political Report’s Political Outlook

David Wasserman Senior Election Analyst, The Cook Political Report After two turbulent "change" elections in 2016 and 2018, what does 2020's split verdict mean?

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

ILTA2021/ILTA.ORG

system, which helps prevent thermal breaks in the system. If an insulated pipe fails, it can alter how a load is distributed. When this occurs, the entire system may surpass its stress tolerance. Damage, including increased leak or rupture risk, is particularly possible at sensitive areas such as nozzles, flanges and fittings following a system imbalance.

When insulation is used on storage tank bases, a compressible insulation could cause a drop in thermal insulation performance or unwanted settlement of the structure. If not stopped, these situations could continue to degrade, leading to ground heaving or even system failure from ruptures in the bottom of tanks as foundation temperatures exceed limits.

There also needs to be an awareness of how insulation functions with extreme temperatures.

Long-term creep can occur when extreme temperatures are applied to insulation or the accessories used with insulation. Compression creep may start when a solid material deforms or moves after a mechanical load is applied. The compressive properties of FOAMGLAS insulation are consistent over time and across a wide range of service temperatures. It has been tested against a wide array of industry standards.

Cellular glass insulation is capable of supporting heavier loads than many other insulating materials.

FOAMGLAS HLB insulation tolerates a range of compression and has declared compressive strengths for specific grades ranging from 800 kPA (116 psi) to 2400 kPA (348 psi).2 Its compressive strength and dimensional stability cut the need for additional treatment at pipe supports and allows it to be used under storage tanks. Cellular glass insulation provides a stable base for heavy storage tanks and can be used with cryogenic tanks to limit heat gain and preserve system lifespan.

Fire protection Risk of fire on-site at LNG facilities is a consideration.

As site locations shrink and move towards populated areas, there is increased interest in developing new

ways to mitigate fire risks. Selection of a non-combustible insulation that does not wick or absorb flammable liquid can reduce the opportunity for fire spread, toxic smoke generation, and help improve the safety of an LNG facility.

FOAMGLAS insulation has been subjected to numerous fire (and smoke) tests – including ISO 22899 Jet Fire, ASTM E 136, ASTM E 84 and UL 1709.

FOAMGLAS systems alone and in combination with other materials such as mineral wool, ceramic blankets or intumescent coatings can be designed for protection time ranges from 30 minutes to over 4 hours.

Made of glass, without binders or fillers, the insulation can serve to help protect piping and equipment in critical process areas should a fire break out. Its fire protection qualities could allow time for shutdown of equipment and for critical evacuation of personnel.

Fire suppression In addition to the general threat of a fire occurring at an LNG site, a more specific concern is a fire starting in a containment pit, or impound area following an unexpected release of liquid. LNG pool fires may ignite when the -165˚C (-265˚F) LNG boils off or vaporises after encountering warmer surfaces. The invisible vapour created is flammable once it reaches a specific concentration, which may occur some distance from the initial spill. Once generated, the vapour could encounter ignition triggers, including static electricity.

However, the use of an effective fire suppression system, especially focused on containing the spill pool and limiting the production and release of volatile vapour, may improve facility safety.

One passive safety system that can be employed in these situations is the FOAMGLAS pool fire suppression (PFSTM) system. The system can be combined with existing safety measures and provides a passive response that reduces thermal radiation and lowers total flame height in contained pool fires. It helps mitigate thermal flux, limits rate of combustion and may help reduce the

Figure 3. The combination of the FOAMGLAS® PFSTM and Cryo SpillTM Systems can reduce vaporisation and thermal

shock along with flame height and thermal radiation if an LNG pool fire occurs in a containment pit.

August 2021 68 HYDROCARBON ENGINEERING

HELP PROTECT YOUR TANK BASE SYSTEM WITH FOAMGLAS® CELLULAR GLASS INSULATION Selecting the proper insulation for your tank base is critical to staying operational, safe, and high-performing.

FOAMGLAS® ,MKL 0SEH &IEVMRK ,0& -RWYPEXMSR TVSZMHIW GSRWXERX XLIVQEP IƾGMIRG] FSEWXW WYTIVMSV compressive strength, and is moisture impermeable and noncombustible. From cryogenic to hot tank base applications, FOAMGLAS® Cellular Glass Insulation has been trusted globally for decades.

Now Offering XL Block Sizes (IWMKRIH JSV IEWI SJ MRWXEPPEXMSR ERH QSVI IƾGMIRX ETTPMGEXMSRW SR XERO FEWIW *3%1+0%7® HLB Insulation is now available in larger sizes. FOAMGLAS® HLB Insulation is offered in six standard grades to meet the loading requirements for various tank base system designs. XL formats are available in FOAMGLAS ® HLB 800, 1000, and 1200.

X-LARGE FORMAT 24 x 36 in 600 x 900 mm

STANDARD FORMAT

CONTACT A REPRESENTATIVE FOR REGIONAL AVAILABILITY.

18 x 24 in 450 x 600 mm Standard sizes still available.

www.foamglas.com 1-800-327-6126 © 2021 Owens Corning. All Rights Reserved. © 2021 Pittsburgh Corning, LLC. All Rights Reserved.

size of the overall pool fire by minimising the amount of fuel available to maintain the blaze.3 The Generation 2 PFS system uses a series of modules comprised of a cellular glass insulation core, cladded with stainless steel and interconnected. The material used is non-combustible, non-corrosive and resistant to vermin. Once installed, the modules provide a buoyant cover that can wait on the bottom of an empty containment pool until a spill occurs, reducing the potential for deployment delays. Should a spill occur, the interconnected blocks rise to the surface of the released LNG and provide an insulating cap to help reduce the vaporisation, thermal radiation and flame height. The system can also be used with firefighting foams.

Field trials conducted with the FOAMGLAS PFS system on an LNG test pit of 100 ft2 found that firefighters were able to approach the edge of the containment pool and put out the flames using dry chemical extinguishers.3 Additionally, a series of experiments were conducted at the Emergency Services Training Institute at Texas A&M University. Those trials found that the view factor of a pool fire capped with the FOAMGLAS PFS system was lower than that experienced using high expansion foam, and the system provided heat protection to nearby equipment or personnel. The smaller fire also stayed within the comparatively lower temperature range of 200˚C to 500˚C (392˚F to 932˚F).4

Cryogenic liquid spill protection Additionally, cellular glass insulation can be used to line containment pits both to reduce vaporisation of LNG and to protect the concrete and steel rebar used in pit walls.5 Spill pits for cryogenic liquid are commonly comprised of concrete and steel rebar. However, both react negatively to rapid temperature drops – sudden cold shocks may reduce their load-bearing capacity.

When exposed to extreme cryogenic temperatures, carbon steel may become brittle or fracture.

However, using cellular glass insulation (FOAMGLAS Cryo SpillTM System) to line pit walls helps insulate concrete and rebar from a cold shock should a spill occur. In testing, FOAMGLAS insulation protected steel and concrete from a cold shock produced by liquid nitrogen at -196˚C (-321˚F) for more than an hour.

Both materials maintained a temperature well above those needed for embrittlement or cracking to occur.

Noise (acoustics) LNG facilities can be loud – especially when liquification and regasification occur – and employees may need hearing protection to meet 85 dB regulations and facility location and zoning requirements. But selecting the right types of insulation can help with noise mitigation as it remains easier to treat the problem at its source than remediate it.

A combination of cellular glass insulation and mineral wool can insulate cold and cryogenic pipes and meet class C and D acoustic compliance using less material than is needed in other systems. The reduced amount of mass and cladding can help with ease of installation and handling, potentially lowering labour costs. Additionally, the thinner amount of material needed drops the amount of weight added to piping.

The application overfits a base layer of cellular glass insulation with mineral wool to provide additional acoustic performance. Mineral wool insulation provides a fibrous layer to help sites meet noise levels less than 85 dB by using systems that have been tested in accordance with ISO 15665.

Owens Corning® mineral wool pipe insulation is water-repellant and non-combustible. When used with FOAMGLAS insulation, appropriate vapour barrier jacketing, mass-loaded vinyl and recommended accessories, it can form a unique acoustic system.

Conclusion Although LNG facilities face numerous challenges to operations and safety, identifying these challenges before starting the design process can help protect the functioning and longevity of the site while protecting employee safety. While several kinds of insulation can provide pieces to the puzzle that is LNG facility safety and design, cellular glass insulation can address multiple challenges at one time.

The insulation can reduce fire risks, repel moisture from insulated systems and reduce the amount of noise generated while providing support for storage tanks without compressing or losing thermal performance.

References 1.

2.

Figure 4. Combining cellular glass with mineral wool insulation reduces facility noise and helps meet class C and D acoustic standards – all while maintaining cryogenic thermal performance.

August 2021 70 HYDROCARBON ENGINEERING

3.

4.

5.

ADAMS, L., ‘Thermal Conductivity of Wet Insulations’, ASHRAE Journal, (October 1974).

‘Compressive strength performance in Industrial Insulation’, Foamglas Technical Newsletter. Minimum lot average values when tested in accordance with ASTM C240 / ASTM C165 or EN 826 Annex A per ISO 3951.

‘Vapour & Fire Control Testing of FOAMGLAS® PFS System (Gen 2) on LNG’, Resource Protection International, (February 2014).

‘FOAMGLAS® Insulation on LNG’, MKOPSC, Texas A&M University.

‘Energy Analysis Report 17343’, Owens Corning, (2020).

I

Matt Halsey, Servomex, UK, explains how hydrocarbon processing plants and refineries can implement cleaner air strategies using gas analysis.

ncreasingly stringent environmental regulations, along with international action to reduce the impact on climate, such as the 2016 Paris Agreement, have made plant operators more aware of their contribution towards greenhouse gas emissions.

Gas analysis systems provide an effective solution for plants looking to reduce their emissions and operate in an ecologically responsible way.

Servomex operates a clean air strategy that focuses on three key process areas: combustion efficiency, gas clean-up, and emissions monitoring.

Analytical solutions for these areas will support plants in their clean air goals, while also optimising processes to deliver reduced fuel consumption and higher yields.

Stage one: effective combustion control There are no realistic alternatives to combustion when it comes to creating the high temperatures needed for many hydrocarbon processing applications. Achieving an efficient reaction is therefore key.

The reaction of oxygen (from air) with fuel typically generates harmful emissions, while also using a significant

amount of fuel and creating potential safety hazards.

Obtaining an efficient reaction means optimising the ratio between the air and fuel.

Before gas analyser technology was developed, fired heaters were typically run in high excess air conditions. This avoided the creation of unsafe conditions that could lead to an explosion, but was inefficient and increased the level of fuel consumption.

Additionally, excess oxygen (O2) will combine with nitrogen and sulfur in the fuel to produce unwanted emissions such as oxides of nitrogen (NOX) and sulfur (SOX).

By accurately measuring O2 and combustibles such as carbon monoxide (CO), plant operators are better able to balance the air-to-fuel ratio, controlling the combustion reaction.

This produces a number of benefits, particularly where plants are looking to improve environmental standards. It reduces fuel consumption, resulting in fewer emissions, lower NOx, SOX, and CO generation, and a decrease in the greenhouse gas carbon dioxide (CO2).

As a solution for monitoring O2 in combustion, Zirconia sensing is a long-established technology. It delivers reliable, accurate results with a fast response to changing conditions.

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Each process point requires the application of appropriate gas analysis technology. The off-gas measurements for O2 and NH3 slip benefit from the use of TDL open-path measurements (as provided by the Laser 3 Plus), which reduce issues with catalyst particulates experienced by in-situ or simple extractive systems.

Close-coupled extractive systems are reliable and cost-effective when measuring O2 and combustibles (COe) in flue gas, while the SERVOTOUGH SpectraExact 2500 is suited for the off-gas CO and CO2 measurements.

A combustibles sensor can be added easily, and at modest cost, to provide an all-in-one combustion control solution, such as in Servomex’s SERVOTOUGH FluegasExact 2700 combustion analyser.

The more recent development of tunable diode laser (TDL) technology provides an even faster measurement, particularly for carbon monoxide. This also takes an average result across the measurement path, rather than measure a single point. However, TDL sensing is highly specific to the gas being measured, so separate analysers are required for O2 and CO. For this application, Servomex’s SERVOTOUGH Laser 3 Plus Combustion TDL analyser can be configured to measure either O2 or CO. It can also be configured to jointly measure CO and CH4, providing a rapid-response measurement for safety in natural gas fired heaters and boilers.

The second phase in the aforementioned clean air strategy is to support the removal of harmful substances from process gases which might otherwise be emitted by the plant. Examples of these applications include DeNOX (ammonia slip) treatment and flue gas desulfurisation.

Process efficiency

Ammonia slip

Gas analysis is used in many applications to support greater process efficiency in the same manner as optimising combustion. An efficient process reaction generates fewer harmful emissions, so this also plays its part in cleaner air.

For example, one of the largest air emissions sources in a refinery is the fluid catalytic cracking unit (FCCU). In a typical FCCU, a process control oxygen measurement is required in the regenerator off-gas, where low O2 causes incomplete combustion of the catalyst coke while excess O2 reduces catalyst life.

Measuring the CO and CO2 in the same off-gas helps calculate catalyst coke formation, enabling catalyst regeneration efficiency to be determined. Excess O2 and CO levels are monitored in the regenerator flue gas, while ammonia (NH3) ‘slip’ is measured at the selective catalytic reduction (SCR) outlet to control the DeNOX process.

Ammonia (NH3) or urea is used to suppress the harmful emissions of NOX from combustion, through either a SCR or selective non-catalytic reduction (SNCR) process.

These methods require accurate NH3 dosing to reduce NOX levels – if insufficient NH3 is used, then NOX emissions are not adequately suppressed, while excess NH3 causes the eventual formation of ammonium bisulfate (ABS), a white powder that can plug the catalyst in SCR processes, damaging equipment and reducing the value of the fly ash by-product.

Therefore, it is vital that plants manage DeNOX processes by controlling the level of ammonia slip to between 2 – 3 ppm of NH3. NH3 can be monitored by extractive sampling. However, this is difficult, since the sample must be kept above 290˚C (554˚F) to prevent the formation of ABS and sulfuric acid.

Inlet NOX concentration, fuel composition and catalyst performance can also affect the measurement, while Infrared-based extractive systems may also be impacted by signal interferences from gases formed by the process, and by high levels of dust.

A more effective solution is a TDL analyser installed directly into the process ducts. This provides a signal that is averaged across the duct, for a more accurate NH3 reading despite uneven flow conditions.

Stage two: process gas clean-up

Flue gas desulfurisation

Figure 1. Using the Laser 3 Plus TDL analyser in ammonia slip applications.

August 2021 72 HYDROCARBON ENGINEERING

A flue gas desulfurisation (FGD) system is designed to remove sulfur compounds (SOX, chiefly SO2) from exhaust gases. It is typically used by fossil-fuel power plants and operators in other SOx-emitting processes, such as waste incineration.

The most common method sees the flue gas sprayed with a wet slurry of lime, which reacts with SOX and scrubs up to 95% of the SO2 content from the gas. Gas analysers measure the SO2 content after treatment to ensure that remaining sulfur compounds meet regulatory limits.

Gas analysis in this process is challenging, as gases containing SOx can be corrosive, and

treatment temperatures are usually kept high to prevent moisture content from damaging equipment. The most effective and accurate measurement for SO2 in this application is provided by non-contact, photometric sensing technology.

Servomex’s SERVOPRO 4900 Multigas uses infrared gas filter correlation (Gfx) technology to measure SO2 in this application. This allows accurate, real-time measurements at very low levels, without interference from background gases.

Gfx technology also supports sulfur recovery units (SRUs), which recover sulfur from streams containing H2S.

Stage three: emissions monitoring Monitoring flue gas emissions helps protect the environment and determine the efficiency of the process.

It also demonstrates that plant operators are complying with the necessary regulations.

Greenhouse gases – CO2, CH4, and nitrous oxide (N2O) – and key pollutants such as NOX, SOX, and CO, must be measured in order to achieve a clean air strategy and meet regulatory requirements.

To measure all the necessary components of the flue gas, and ensure compliance, a continuous emissions monitoring system (CEMS) is required.

This system must be capable of offering the highest sensitivity and accuracy when dealing with multiple measurements for pollutants and greenhouse gases.

Multi-component gas analysers are suitable for this application, and depending on the process can either

deliver all the necessary measurements in one device or form a key part of an integrated, comprehensive CEMS. For example, a single 4900 Multigas can monitor four gases simultaneously, measuring from a choice of O2, CO2, CO, SO2, NO, CH4 and N2O, so multiple analysers can easily cover the pollutants of interest.

Any gas analysis system must also meet MCERTS and QAL1 certifications to comply with regulatory criteria.

Carbon capture and storage (CCS) The capture and storage of CO2 – rather than releasing it into the atmosphere – not only results in a cleaner environment, but also allows the CO2 to be used in other processes. It falls within two phases of the clean air strategy, as it encompasses elements of both gas cleaning and emissions monitoring.

Three methods exist for CCS: post-combustion, oxyfuel, and pre-combustion. Post-combustion CCS is when CO2 is removed from the flue gas after fossil fuels have been burned. Oxyfuel CCS produces a flue gas consisting almost entirely of CO2 and steam by reacting the fuel source with almost pure O2, so flue gas can be stored/sequestered without significant pretreatment.

Both methods can be retrofitted to existing plants or used in new ones.

Pre-combustion CCS, performed before the fuel is burned, converts the fuel into a mixture of hydrogen and CO2. This is difficult to retrofit and so is better suited to newly built facilities.

Whichever method is used, once the CO2 is captured it is then compressed into a liquid and transported for storage.

Requiring accurate gas analysis, industrial-level CCS is likely to expand in coming years as countries look to meet Paris Agreement carbon reduction targets.

The SERVOTOUGH SpectraExact 2500 photometric analyser can be used for this application. It is capable of single or multi-component gas monitoring in corrosive, toxic, or flammable streams, using Infrared and Gfx sensing to measure CO2 at percentage and ppm levels.

In addition to measuring the flue gas to ensure CO2 removal, it is also capable of assessing the purity of the removed CO2 prior to it going to storage.

Cleaner energy sources As part of their emissions reduction plans, many operators are moving to cleaner energy sources, such as hydrogen. At the same time, plants that produce hydrogen are ramping up output to meet this increased demand.

Hydrogen gas (H2) burns much more cleanly than CH4, as it does not contain carbon, so CO2 is not formed as a combustion by-product. Gas analysis again plays a major role, as the purity of the hydrogen directly affects its quality as a fuel.

Depending on the manufacturing method, the most common contaminants will be O2, CO, and CO2, which can all be monitored by the MultiExact 4200, Servomex’s multi-component analyser, using a mixture of paramagnetic, infrared, and Gfx technology.

Whatever cleaner energy sources emerge in the future, it is certain that gas analysis technology will have an important part in the process.

A cleaner future Gas analysis is essential to cleaner plant and refinery operations, whether it is in ensuring more efficient processes, supporting the safe removal of pollutants, or monitoring the remaining emissions to the atmosphere.

It also supports emerging trends in the industry, such as the desire for greater process optimisation, the move towards cleaner fuels, and the achievement of higher product yields.

For such a wide range of goals, an equally wide range of sensing technologies is required. Partnering with an expert gas analysis supplier is vital; by offering a diverse selection of technologies, and the expertise to support them, such suppliers can ensure the best-fit and most cost-effective solution for each application.

Service support is another key consideration – forging a service contract that maintains gas analysis systems at peak performance means the refinery or plant keeps operating as cleanly as possible. Servomex’s Service Network, for example, offers customisable service packages depending on the level of support required.

Each of the phases outlined in this article is a vital component of any cleaner air strategy. By combining all three, plants and refineries can fully address the impact of their operations on the environment, playing an important part in creating a world with cleaner air.

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William Vickers, Ionix Advanced Technologies, UK, explains the contribution that corrosion monitoring technology can make towards increased industry sustainability.

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ownstream refinery operators face an existential challenge with a range of critical pressures facing the industry. With the drive towards a low carbon future, the coming period requires refinery operators to adapt their business strategy and operations if they want to secure their future. On top of everything, the ongoing effects of the COVID-19 pandemic bring both business and operational challenges to maintain the safety and health of the business operations and staff.

All of these challenges require operators to put sustainability front and centre of their strategy, and to look at all aspects of their long-term operations in order to meet emissions targets, minimise the risk of unplanned outage, maximise production availability and rates, and reduce operational risk. Industrial plant digitalisation is spreading across a wide range of sectors, including oil and gas, energy and nuclear, and process industries. Plant digitalisation is increasingly seen as a key element to enable long-term sustainability of a refinery or upstream operation, with a range of monitoring applications including corrosion monitoring driving towards digitalisation.

Automating thickness measurements can allow for an increase in the data collection frequency providing up-to-date measurements to feed into both asset integrity programmes and to guide process control and productivity optimisation. This approach can underpin long-term sustainability by

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enabling businesses to meet their environmental and safety obligations whilst delivering improved economics.

Production challenges There is a mandated requirement for oil and petrochemical operators to continuously test and monitor the health and condition of their infrastructure.

This is increasingly important as the lifespan of these assets continues to lengthen over time, driven by reduced investment in new capacity in some regions, while demand for refinery products is likely to remain volatile as economic activity around the world recovers from the economic effects of the COVID-19 pandemic.

Energy demands are increasing globally and the transition from current to future low carbon energy sources will remain a complex process.

Economic pressures dictate that refiners must be able process lower priced and varied feedstocks to optimise their profitability, while meeting increasingly demanding emissions targets. Changing market and user demands will require high levels of flexibility from the refinery, while these varied feedstocks bring with them increased corrosion risks that must be managed.

The high costs and associated risks of plant-infrastructure failures, coupled with increasing asset lifespan, is creating a growing need for permanently installed and continuous sensing in these industry sectors. Industry is demanding change as it seeks to reduce operating and employee risk, and drive down costs while gaining higher quality data on the performance of critical assets.

Effective corrosion monitoring is especially important for high value refinery assets where service life can be extended and/or maintenance be deferred.

While conventional inspection approaches have and will continue to be important in the management of corrosion, these complex challenges are driving refineries to move towards the preferred use of continuous monitoring of their assets combined with proactive maintenance.

Introduction to automated ultrasonic testing Traditionally, the thickness measurements which are used on a downstream plant or in upstream operations are generated manually by non-destructive testing (NDT) inspectors and are prone to errors and inaccuracies due to the challenge of fully matching calibration/reference material to the asset, variations in equipment and exact inspection locations, and natural human variations in implementing methods and procedures. For this reason, manual ultrasonic testing (UT) measurements are generally considered to be accurate to a maximum of ±0.1 mm and most commonly are only accepted to be accurate to ±0.5 mm.

To enhance precision, combined with the need to reduce the presence and cost of people working on site, manual UT measurements are taken at relatively low collection frequencies to ensure changes in wall thickness are detected. Even so, it is not uncommon for August 2021 76 HYDROCARBON ENGINEERING

thickness measurements to be seemingly thicker than one taken 5 years earlier due to very low rates of corrosion/erosion and measurement error leading to incorrect calculation of wall loss rates and reduced value of the measurement.

Automating thickness measurements can allow for an increase in the data collection frequency from years to hours, providing up-to-date measurements to feed into both asset integrity programmes but also, importantly, to guide process control and productivity optimisation.

Automating thickness measurements bring reduced errors associated with manual measurements by utilising fixed, installed monitoring sensors and automated measurement calculations using advanced algorithms.

This allows the precision of the measurements to be increased to 0.010 – 0.025 mm, allowing smaller changes in wall thickness to be detected.

An increase in precision combined with an increased frequency of data collection allows for statistical analysis of the data and determination of wall loss trends.

Trending of thickness data points collected every 12 – 24 hours can allow for corrosion rates as low as 0.020 mm/yr to be detected. It also allows for short- and long-term corrosion rates, as described by API 510, to be calculated from almost live data, allowing for changes in corrosion rate to be detected after only a few weeks, and allowing corrosion rates to be used for process control and optimisation. As a result, automated UT monitoring technology and the powerful data it generates delivers major benefits to plant operators, including increased plant up-time, optimised plant economics and profitability, and reduced operating costs by enabling preventative maintenance. The main barriers to wider adoption of UT monitoring remain the perceived high cost of installation of the solution and the challenges of installation and operation. Next generation UT monitoring solutions will provide lower cost solutions with rapid returns on investment, coupled with live on-line installation and easy operation.

Case studies The following cases illustrate the investment that major operators are making in corrosion monitoring as a long-term approach to improving the efficiency and sustainability of their operations. The examples illustrate different scenarios and associated benefits for refiners faced with particular business challenges.

Case study 1: refinery-wide installation – optimising plant economics A recent refinery-wide installation of a HotSenseTM corrosion monitoring system shows its major contribution to overall refinery economics in a fast-changing operating and business environment.

One of the key benefits of installed ultrasonic probes combined with automated monitoring nodes is the ability to detect change in wall loss rates. In this case, the refiner was seeking a system which was stable and predictable and did not pose a significant challenge to the asset managers who can run the plant with a clear

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Figure 1. Real-time thickness measurements collected

using Ionix HotSense and an ultrasonic monitoring system.

A sudden acceleration in wall loss is successfully detected after a reduction in process temperature.

integrity of assets with safe Integrity Operating Windows (IOWs) being re-defined every time a process is required to operate outside of previous confines. Generating the data required for the IOWs via manual NDT methods would not be practical for the refiner due to the low frequency of data collection and low precision of measurements leading to decisions being made on data collected over many years preventing short-term changes from being detected. Installing automated, fixed UT monitoring on the other hand allowed for the critical high wall loss rates to be detected over a period of weeks. Combined with data from other sensors such as temperature probes, electrical resistance (ER) probes and corrosion coupons, wall loss rates can be correlated with process conditions to allow for the determination of new IOWs and operation of the plant which maximise production whilst ensuring asset lifetime is in-line with replacement and turnaround schedules.

Figure 1 shows an example output from the automated UT monitoring system where the measured wall thickness and temperature is shown. It can be seen that the system has been able to detect a sudden acceleration in wall loss soon after a reduction in the processing temperature. This change in actual wall loss rate, not estimated from a coupon or ER probe, would not have been detected using standard NDT monitoring methods, especially at these high process temperatures.

The other key benefit to the operator of the increased monitoring frequency of automated UT systems is that changes in wall loss rate could be detected early prior to the requirement for an unplanned shutdown for repair/replacement and more importantly before a loss of containment. Corrosion is estimated to be responsible for 25 – 30% of all shutdowns,1 costing £3.4 billion/yr in the US alone.2 With flaring during shutdowns and restarts combined with loss of containment being major contributors to emissions, implementing a preventative maintenance programme off the back of an online UT monitoring is a cost-effective way for the refiner to hit emission reduction targets.

Figure 2. Ionix HotSense ultrasonic sensors and an

Case study 2: targeted monitoring – increasing productivity and enhancing safety

plan for its inspection schedule and ultimate retirement and replacement. However, the move towards a more sustainable oil and gas production and refining industry requires changes to be made in the crude slates, products and processing conditions such as operating furnaces at lower temperatures. What is more, these changes need to be made at a higher frequency than previously experienced as fuel demands and emissions targets are reviewed and revised.

The COVID-19 pandemic has also shown how demand for fuels can change rapidly. These rapidly changing production conditions require constant review of the

In another example, a European refinery had identified a number of high temperature locations which were showing increased corrosion and required increased monitoring, with no prospect of conventional inspection without a full plant shutdown. The customer sought an automated system which could provide automated, on-stream wall thickness measurements with data being used by both asset integrity and process control teams.

The customer had an active WirelessHART network which was feeding data from a range of process and safety sensors directly to their process optimisation software within the plant control room. The automated UT system needed to integrate with the host WirelessHART network and feed data to the control systems. The data also needed to be accessible to the plant asset integrity team who sat outside of the plant

automated monitoring system installed on a live high temperature plant and integrated into an existing process control sensor network.

August 2021 78 HYDROCARBON ENGINEERING

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fence. All of this needed to be achieved without the installation of any additional IT infrastructure and without adding additional cybersecurity protection measures. All of the installation locations required a minimum ATEX Zone 1 certified solution and would need to operate at between 150 – 380°C. In this case, HotSense intrinsically safe UT sensors were deployed with a WirelessHART monitoring node, in the areas of concern during normal plant operation, and integrated into the existing plant-wide WirelessHart operating system (see Figure 2). The system performs all the thickness calculations in the field and presents the process variables to a wireless gateway, which are passed directly into the host control and historian systems.

As a result, at low incremental cost, this investment allowed continuous monitoring of the areas of high risk on the plant, and by avoiding shutdown during installation and ongoing operation served to increase plant productivity and reduce operating costs.

Conclusion Shifting fuel and energy demands are placing pressure on the refining industry to output a changing product portfolio and do so at reduced operational costs to ensure sustainability of the industry. At the same time,

environmental and legislative pressure to reduce carbon emissions are adding further challenges to plant operators.

The change in process conditions presents a particular asset integrity challenge as IOWs must be frequently updated based on limited data whilst ensuring the highest levels of safety and plant availability. A shift towards the use of automated inspection methods, such as ultrasonic inspection for wall thickness and corrosion monitoring, enables plants to monitor the effect of process and feedstock change on assets and optimises processes and interventions accordingly.

WirelessHART enabled automated systems allow data to be collected from all plant assets, including remote locations, and aggregated at a centralised location for analysis. The data collected from such systems can be critical in maximising plant availability and detecting the potential for loss of containment or unplanned shutdown that would otherwise be missed by traditional manual methods.

References 1.

2.

GE, Corrosion & Erosion – Inspection solutions for detection, sizing & monitoring, 2010.

NACE Cost of Corrosion Study, 2002.

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