Hydrocarbon Engineering - May 2021 by PalladianPublications

May 2021

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CONTENTS May 2021 Volume 26 Number 05 ISSN 1468-9340

03 Comment 05 World news 08 Latin America in focus

23 A clear plan of action Randy Cruse, Sentry Equipment, USA, outlines how operations can be optimised with a reﬁnery sample station audit.

Contributing Editor, Gordon Cope, outlines the opportunities and challenges facing the oil and gas sector in a number of countries in Central and South America.

27 A new way to lower sulfur Saeid Aﬂakian, Merichem Company, USA, presents a new approach to lowering total sulfur in the LPG product stream.

31 End-flash is totally cool Robert P. Saunderson, Air Products, USA, explores how to ﬁnd the right combination of LNG subcooling and end-ﬂash.

35 Keeping a steady flow Nicola Curtis, Rotork, UK, explains how ﬂow control supports safety and reliability in the LNG industry.

39 The key to competitiveness Tony Dodd, Servomex, UK, explains how to improve operational excellence through digitalisation of gas analysis equipment.

44 Simulation in a world of trouble: part one In the ﬁrst of two parts, Ralph H. Weiland and Nathan A. Hatcher, Optimized Gas Treating Inc., USA, examine two case studies showing disparities between simulation and plant data caused by defective equipment and contaminated solvents.

14 Subscribe to thrive Jeff Bause, NOXCO, USA, explains the beneﬁts of a subscription-style service in the reﬁning and petrochemical industry to more accurately budget annual ongoing maintenance.

19 Mastering the mechanics

47 Hot and cold recycle control Nabil Abu-Khader, Compressor Controls Corp., UAE, discusses the operation of a two-shaft gas turbine-driven centrifugal compressor with hot and cold recycle lines.

53 Catalyst Q&A

Jim McVay, MISTRAS Group, USA, explains the complexities of a full, comprehensive mechanical integrity (MI) programme, and how proper implementation can lead to fully-realised operations.

THIS MONTH'S FRONT COVER

Hydrocarbon Engineering talks to some of the catalyst industry’s foremost experts, who share their insights on the latest developments in the downstream catalyst and precious metals market.

Merichem® has spent 75 years delivering innovative solutions to its customers through robust technologies, excellence in service and sustainability solutions. Now, the company has developed and implemented a new approach to lower the total extractable sulfur in LPG product streams to less than 3 ppmw, offering a lower CAPEX and OPEX with no reduction in octane. Read the game-changing case study on p. 27.

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CALLUM O'REILLY SENIOR EDITOR

he International Energy Agency’s (IEA) ‘Global Energy Review 2021’ suggests that accelerating rollouts of COVID-19 vaccinations throughout many major economies, alongside widespread ﬁscal responses to the economic crisis, are helping to improve the outlook for economic growth and triggering a rebound in energy demand this year. There is, of course, a ‘but’. The pace of global vaccine rollouts, the emergence of new variants of the virus, and the size and effectiveness of economic stimulus measures all present signiﬁcant uncertainties. Meanwhile, even if there is a big rebound in economic activity, the IEA notes that there is a danger that CO2 emissions will be pushed to a new high. In its current projections, the IEA expects global energy demand to increase by 4.5% this year, which will offset the 4% contraction seen in 2020 and will push demand 0.5% above 2019 levels. Emerging markets and developing economies account for almost 70% of the projected increase, with demand set to rise 3.4% above 2019 levels. In advanced economies, energy use is set to be 3% lower than pre-COVID levels. Global oil demand is set to remain 3.2% below 2019 levels, despite an expected increase of 6.2% in 2021 compared to last year. Although oil use for road transport is expected to reach pre-COVID levels by the end of 2021, its use as an aviation fuel is projected to be 20% below 2019 levels even in December 2021. The only oil sector that is set to surpass pre-COVID levels is petrochemical feedstock, with plastic production increasing due to demand for packaging and personal protective equipment. LPG, naphtha and ethane demand are projected to increase by 4% in 2021. Meanwhile, natural gas is expected to grow 3.2% this year, placing global demand 1.3% above 2019 levels. The recovery in demand is seen primarily in Asia and the Middle East, with the industry and buildings sectors expected to lead gas demand growth in 2021 (the IEA expects demand in both sectors to increase by 5%). However, the big winner in the report is renewable energy. Last year, renewable energy use increased 3%, and it is expected that renewable electricity generation will grow by more than 8% in 2021, recording its fastest year-on-year growth since the 1970s. Wind is set for an increase of almost 17% (up 275 TWh), with China and the US accounting for more than half of global wind output, while solar photovoltaic (PV) electricity generation will increase by 145 TWh (almost 18%). The IEA expects the share of renewables in electricity generation to reach an all-time high of 30% in 2021. Hydrocarbon Engineering’s sister publication, Energy Global, is the number one place to keep abreast of the latest developments in the growing renewables market. If you’re not already receiving a regular copy of the digital magazine, I’d encourage you to head over to www.energyglobal.com to register for a free subscription today. There you will also be able to keep up with the latest news regarding solar, wind, bioenergy, electric & hybrid, energy storage and much more. HYDROCARBON

ENGINEERING

May 2021

www.arielcorp.co www.arielcorp.com/itstime

WORLD NEWS India | Maire

Tecnimont Group expands petrochemical business

consortium of Maire Tecnimont S.p.A.’s subsidiaries, comprised of Tecnimont S.p.A. and Tecnimont Pte Ltd, has been awarded an engineering, procurement, construction and commissioning (EPCC) lump sum contract by Indian Oil Corp. Ltd (IOCL), for the implementation of a new paraxylene (PX) plant and the relevant offsite facilities. The plant will be located in Paradip, in the State of Odisha, in Eastern India. The overall value of the contract is approximately US$450 million.

USA | Nacero

selects Topsoe’s technology

acero has licensed Topsoe TIGASTM technology for its natural gas-to-gasoline facility in Penwell, Texas, to produce 100 000 bpd of gasoline component ready for blending to US commercial grades. The plant will produce cleaner gasoline from low-cost natural gas, captured bio-methane from farms and landﬁlls, and mitigated ﬂared gas from the Permian basin. Topsoe is providing engineering and design services currently and will supply catalyst and proprietary hardware to the facility.

China | CNOOC

The scope of work entails EPCC activities up to the performance guarantees test run. Once completed, the new PX plant will have a capacity of 800 000 tpy. The time schedule is 33 months for mechanical completion from the award date. The PX produced will be used to feed the adjacent puriﬁed terephthalic acid (PTA) unit, thus ensuring availability of feedstock that will provide a signiﬁcant boost to the country’s manufacturing industry.

The Penwell facility will be the first gasoline manufacturer in the world to incorporate carbon capture and sequestration. The captured CO2 will be used for enhanced oil recovery. Gasoline produced by the TIGAS technology contains no sulfur, is cost-competitive with traditional gasoline, and can be used in today’s cars and trucks without modification. The Penwell facility will create a market for natural gas that is currently vented or flared and is expected to double the US market for captured bio-methane.

Lummus Technology wins master licensor contract

Russia |

ummus Technology has announced that it has been awarded a master licensor contract by PJSC Nizhnekamskneftekhim for its ethylbenzene, styrene monomer, ethylene dimerisation and olefins conversion technologies. These four plants will be part of the expansion of an olefins production facility in Nizhnekamsk, Russia. The dimerisation and olefins conversion units will be the first in Russia. Lummus’ scope includes the technology license and basic engineering for the ethylbenzene, styrene monomer, ethylene dimerisation and olefins conversion units. Once complete, the units will produce 250 000 tpy of ethylbenzene via the EBOneTM technology, 250 000 tpy of styrene monomer via the Classic SMTM technology and 150 000 tpy of polymer grade propylene production via olefins metathesis chemistry using Lummus’ ethylene dimerisation (DIMER) and olefins conversion technologies (OCT). PJSC Nizhnekamskneftekhim is one of the larger petrochemical companies in Europe and a leader in the production of synthetic rubbers and plastics in Russia.

and Shell start up new petrochemicals units

NOOC Oil & Petrochemicals Co. Ltd (CNOOC) and Shell Nanhai B.V. (Shell) have announced the start-up by their 50:50 joint venture, CNOOC and Shell Petrochemicals Co. (CSPC), of new units to supply the Chinese market with essential petrochemicals. One new unit is the largest of its type in China, producing up to 630 000 tpy of styrene monomer

and 300 000 tpy of propylene oxide. It is the second unit of its kind built at the petrochemicals complex in Huizhou, Guangdong Province, China, which is operated by CSPC. Three further new units process propylene oxide into up to 600 000 tpy of polyols, deploying the Shell Group’s advanced polyols technologies for the ﬁrst time in China.

The start-up of the new units completes a successful ‘phase two’ expansion of the CSPC complex and follows the commissioning of a second ethylene cracker in 2018. The complex now supplies customers with up to 6 million tpy of diverse, high-quality intermediate and performance chemicals, including polyols, ethylene glycol, polyethylene and polypropylene. HYDROCARBON

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May 2021

WORLD NEWS DIARY DATES 10 - 14 May 2021 RefComm 2021 Online reﬁningcommunity.com/refcomm/

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

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

13 - 16 September 2021 Gastech Singapore gastechevent.com

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

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

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

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

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

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

May 2021

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ENGINEERING

Planned refinery outages unlikely to affect US transportation fuel supplies USA |

ccording to analysis from the US Energy Information Administration (EIA), planned refinery outages during 2Q21 are unlikely to cause a significant shortfall in the supply of petroleum products in the US, particularly in transportation fuels. Despite the severe winter storm in mid-February and related unplanned outages in the Midwest and Gulf Coast regions, adequate inventory levels and lower-than-average demand will enable refineries to meet supply requirements despite the planned outages. Planned outages in the Gulf Coast region for 2Q21 are less

than 5% of the region’s capacity. The region’s total petroleum product inventory is currently higher than the previous 10-year (2011 – 2020) average and will likely be sufﬁcient to offset the lost production from planned outages. The Gulf Coast region contains more than half of US reﬁning capacity, and as a result, the region produces far more petroleum products than it consumes. The region’s surplus production supplies other US regions, notably the East Coast and the Midwest, as well as international markets.

China | Sinopec

starts up Dupont STRATCO alkylation technology units

uPont Clean Technologies has announced successful performance tests for the STRATCO® alkylation units at the Zhenhai Refining and Chemical Co. (ZRCC) refinery in Ningbo, Zhejiang, China and the Yangzi Co. (YPC) refinery in Nianjing, Jiangsu, China. The ZRCC and YPC STRATCO alkylation units both process MTBE raffinate feeds and are designed to produce 7700 bpd and 7500 bpd of alkylate, respectively. The alkylation units will enable Sinopec to generate low-sulfur,

high-octane, low-Rvp alkylate with zero olefins that meets the criteria of the China VI standard. The STRATCO alkylation technology is a sulfuric acid-catalysed process that converts low-value, straight-chain olefins (propylene, butylene and amylene) into high-value, branched components called alkylate. The technology helps refiners safely produce cleaner-burning gasoline with high octane, low Reid vapour pressure, low sulfur, zero aromatics and zero olefins.

Egypt | Honeywell

UOP technology selected by Anchorage Investments

oneywell has announced that Anchorage Investments Ltd will use Honeywell UOP’s C3 OleﬂexTM technology to produce 750 000 tpy of polymer-grade propylene for its new Anchor Benitoite petrochemicals complex in Suez, Egypt, near the southern terminus of the Suez Canal.

As part of the contract, Honeywell will provide technology licensing and basic engineering design, in addition to services, equipment, catalysts and adsorbents for the plant. This represents UOP’s third award for a C3 Oleﬂex unit in North Africa, following earlier wins in Egypt and Algeria.

any ts here

May 2021

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ENGINEERING

Contributing Editor, Gordon Cope, outlines the opportunities and challenges facing the oil and gas sector in a number of countries in Central and South America.

entral and South America encompass some of the largest reserves of crude in the world and a host of exciting new offshore plays. It also embraces a wide range of ﬁscal, regulatory and political differences, creating a spectrum of opportunities and challenges within the oil and gas sector.

Venezuela In Venezuela, years of mismanagement and lack of maintenance under the Chavez and Maduro regimes have crippled crude production. Reports indicate that during some months in late 2020, output had fallen below 400 000 bpd. However, crude storage remains high and, in spite of sanctions, Venezuela continues to export signiﬁcant amounts. According to various sources, the country exported at least 500 000 bpd in February 2021 (excluding reﬁned fuels). Petróleos de Venezuela, S.A. (PDVSA) uses ship-to-ship transfers, ‘phantom clients’, tankers operating without transponders, and oil swaps to conceal shipments.

In October 2020, a large explosion at the Amuay refinery shut down the 635 000 bpd plant. Although the Maduro regime was quick to blame foreign terrorists, reports indicate that a 100 000 bpd distillation unit was destroyed when a water leak caused a vapour blast. The accidental destruction at the Amuay refinery is indicative of the parlous state of refineries throughout the country. Fuel production is now primarily limited to the Cardon refinery, which has a capacity of 300 000 bpd, but is only producing 30 000 bpd. The lack of infrastructure maintenance has also caused the number of spills to increase exponentially. Although PDVSA and the government no longer issue statistics, independent estimates place the number at approximately 4000 per year, a twenty-fold increase over the decade. In addition to breaches within the country, the Caribbean Sea and national parks are also being polluted with crude leaking from refineries, pipelines, storage tanks and abandoned wells. The near-term future remains bleak. In March 2021, the Biden administration announced it was in ‘no rush’

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to lift US sanctions against Venezuela until the Maduro regime conducts serious negotiations with the opposition.

Brazil In its ‘Strategic Plan 2021 – 2025’, Petrobras announced that it was spending US$55 billion over the period, a 27% reduction from the year before due to COVID-19 related demand destruction. Fears that the move would derail the offshore oil boom were mollified when Petrobras pointed out that US$46 billion was earmarked for exploration and production in the pre-salt assets, where break-even prices are as low as US$35/bbl. Petrobras is in the midst of re-configuring its downstream capacity. It intends to divest seven refineries with a total of over 1 million bpd; most are in remote regions. It will retain a total of six refineries with a total capacity of over 1.1 million bpd; the majority are in the southeast, near the major consumption centres of Sao Paulo and Rio de Janeiro and adjacent to the pre-salt oil reserves. The company has also scheduled US$3.7 billion in capital expenditures over the next five years aimed at improving refinery performance, carbon mitigation and water recycling. In addition, Petrobras continues to build its Itabori gas processing plant in Rio de Janeiro state, scheduled for completion in 2025. The US$600 million facility will process up to 700 million ft3/d of offshore gas, primarily for petrochemical plants. Output from Petrobras’ fields hit a record high in 2020, reaching an average of 2.3 million bpd (2.84 million boed). The majority of growth came from pre-salt fields offshore, including the Mero field, where the commissioning of a floating production storage and offloading vessel (FPSO) in August 2020 added 180 000 bpd of production. A tender is underway to build three more FPSOs for the Buzios field, which could boost production from the giant pre-salt discovery to as much as 2 million bpd by 2030. The increased production is being met by strong demand; domestic fuel consumption is growing at twice the international average, and Chinese refineries are eager to pay a premium for the light, sweet crude that is easy to convert to low-sulfur diesel. In early 2021, President Bolsonaro ousted Roberto Castello Blanco, the CEO of Petrobras. The move was seen to be over a disagreement between the two, with Castello Blanco preferring the market to set prices while Bolsonaro preferred to subsidise prices and reduce public discontent prior to elections in 2022. Castello Blanco was widely admired internationally for his moves to cut debt and offload non-core assets. After the dismissal, the company lost US$13 billion in value and the Brazilian real fell by 2%. Observers point out that if the Bolsonaro administration continues with market interventions, it risks dampening much-needed international investment.

Mexico In Mexico, plans are moving forward for the Energia Costa Azul (ECA) LNG plant, located in Baja California State. The US$2 billion project, a joint venture (JV) between IEnova, Sempra and Total, envisions 3.25 million tpy for sale to Asian markets in its ﬁrst phase. The project, which is being built at an existing regasiﬁcation facility, includes a 220 mile pipeline from the US to the terminal. Total and May 2021 10 HYDROCARBON ENGINEERING

Japanese utilities have already contracted 1.7 million tpy of output. Phase 2 of the project could see capacity increase to 12 million tpy. In spite of huge debts and declining crude production, President Andrés Manuel Lopez Obrador is keen on advancing former state champion Pemex in order to make Mexico ‘energy independent’. Plans include a US$8 billion refinery in Dos Bocas, Tabasco, to produce 340 000 bpd of fuel. The dispute over managing and operating the giant offshore Zama oilfield remains in flux. US-based Talos Energy discovered the 670 million bbl offshore deposit in 2015. Pemex, which says the oil extends into its adjacent lease, is seeking control of development. An independent evaluation estimated that 60% of the field rested in Talos land. Mexico’s energy regulator instructed the parties to conclude a unitisation agreement by the end of 2020, but the deadline has been extended into 2021. In February 2021, Mexico suffered a shortfall in natural gas imports when a Polar vortex froze wells in Texas, resulting in reduced production. In early 2021, the US was exporting an average of 5.7 billion ft3/d to Mexico. This dropped to an average of 3.8 billion ft3/d when Texas Governor Abbot ordered a temporary stop to exports. Mexico scrambled to keep pipelines open by ordering LNG deliveries to its Pacific and Gulf of Mexico regasification terminals and by switching utilities to coal and bunker fuels until exports once again began to return to normal the following week. Regardless, the event underscored the need to create underground gas storage. A plan under the previous administration to build up to 10 billion ft3 by redeploying the depleted Jaf gas field in Veracruz was mothballed by Obrador, but an initiative to convert three salt caverns to storage is being examined by Mexico’s Cenagas, the overseer of the nation’s pipeline grid. In late 2020, Obrador instructed the Energy Ministry to shorten 20-year permits for private companies to import fuels to just five years. In response, Mexico’s anti-trust regulator criticised the change, noting that it would severely hamper competition in the retail fuel market and limit infrastructure investments in transportation and storage.

Argentina Argentina has over 630 000 bpd refining capacity spread among numerous small refineries throughout the country. During the COVID-19 crisis, most were forced to drastically reduce production when demand destruction filled their storage tanks to capacity. As the lockdowns have lifted, consumption has begun to return to previous levels, allowing owners such as state-backed YPF to raise utilisation rates to over 70%. COVID-19 also affected the unconventional Vaca Muerta play. After stalling in early 2020 at around 90 000 bpd, crude output crept back to a record high of 124 000 bpd in December 2020. Consultancy company Rystad Energy estimates that output could reach as much as 150 000 bpd by the end of 2021. Producers in the Vaca Muerta are taking advantage of a 157 000 bpd pipeline running 900 km to the terminal of Puerto Rosales. The government estimates that

unconventional output could hit 1 million bpd by 2030; plans are already underway to increase the export pipeline’s capacity to 220 000 bpd this year, and eventually exceed 400 000 bpd. Meanwhile, unconventional gas production has been languishing due to incentives that favour oil. Now, the government has set its sights on creating a 1 billion ft3/d pipeline from Neuquen province to Brazil in order to build gas exports (which are currently limited to LNG). The resurgence in prices has given a much needed respite to the beleaguered country, but long-term challenges remain. Argentina is being propped up by a US$57 billion disbursement from the IMF. Debt defaults are common, inﬂation is rife and international investors are much more attracted to favourable conditions in Guyana and Brazil.

Guyana Offshore prospects in Guyana continue to improve. In September 2020, Exxon announced its 18th oil discovery, which adds to its previous estimate of more than 8 billion bbl of discovered recoverable resources in the area. By late 2020, Exxon had achieved its production goals for the Liza field of 120 000 bpd with its first FPSO, and is expected to have its second FPSO connected to the field in 2022. It has also announced that it will proceed with developing the Payara oilfield in the Stabroek block, which is expected to produce 220 000 bpd by 2024. By 2026, Exxon expects to produce over 750 000 bpd from the block. Hess, one of Exxon’s partners in Guyana, says that the Liza field is operating at a breakeven price of US$35/bbl, and the figure will drop to US$25/bbl when the second FPSO comes on-stream. The light, sweet crude can also be easily converted into low-sulfur fuel, reducing its discount vs the Brent crude benchmark.

Suriname In early 2021, Total and Apache announced their fourth oil and gas discovery in Suriname’s offshore waters in Block 58. The block, which sits atop the Guyana-Suriname basin, is adjacent to the proliﬁc Stabroek block in Guyana. ExxonMobil and partner Petronas are also major operators in Suriname, and announced a discovery in December 2020. Petronas noted: “The Sloanea-1 exploration well encountered several hydrocarbon-bearing sandstone packages with good reservoir qualities in the Campanian section. The well data proves excellent calibration of the hydrocarbon potential of the block.” In 2000, the USGS determined that the Guyana-Suriname basin held undiscovered resources of 15 billion bbl of crude and 42 trillion ft3 of gas. In light of recent discoveries, it has announced plans to re-survey the basin and upgrade its estimates. Suriname is holding a shallow-water auction in late April 2021, offering eight blocks adjacent to the discoveries. This is a signiﬁcant step for the country, as shallow-water regions were previously the sole purview of state oil company Staatsolie.

Colombia Although Colombia has been an important oil producer for decades, a lack of major new discoveries over the last

10 years has left it with only 2 billion bbl of reserves (about 6 – 8 years of production). With an eye to the success of Brazil and Guyana, the country is opening up its offshore regions to rejuvenate the sector. The government says that it has already secured US$1.6 billion in investment by offering attractive economics and policies, claiming that offshore fields could have an average breakeven price of US$31.77/bbl. Unconventional resources have the potential to solve Colombia’s low crude reserves. Although fracking is highly controversial, Ecopetrol has been given the green light to operate pilot wells in the Middle Magdalena Valley which may hold up to 7 billion boe of recoverable shale oil and gas. The pilot programme will be run in conjunction with ExxonMobil to leverage the international company’s expertise in the drilling and fracturing technology. Colombia is also pursuing non-conventional energy. The Andean country is looking to invest in wind and solar. Already a major producer of hydroelectric power, the government has plans to allocate 5 GW of wind and solar capacity in 2021, with the goal of supplying 10% of its energy needs by the end of the decade. The majority of refining in Colombia is owned by Ecopetrol (the Cartagena and Barrancabermeja facilities produce 415 000 bpd, more than 95% of the country’s total liquid fuel output), but a new player will soon by offering its services. Refineria Sebastopol is planning to build a 150 000 bpd refinery, part of a proposed US$6 billion energy hub planned for Puerto Berrio, located on the banks of the Magdalena River in central Colombia. In addition, the hub will include a 135 MW combined-cycle power plant, a photovoltaic solar park and a hydrogen unit. Violence is still a major issue in Colombia. Although peace deals were brokered between the main guerrilla groups, including the Revolutionary Armed Forces of Columbia (FARC), splinter groups continue to attack oilfields in the Llano basin and the 210 000 bpd Caño Limon-Covenas pipeline.

The future The Biden administration has announced that the security and prosperity of Central and South America are essential to the well-being of the western hemisphere. The Biden administration has announced that it will pursue a values-based cooperative strategy in Latin America to boost geopolitical stability. Goals include bolstering regional democratic institutions, alleviating poverty and fostering free trade. This focus is intended to encourage improved relations with Colombia, Brazil, Guyana, Suriname and other jurisdictions. In addition, the initiatives will reduce risk and augment investments in the oil and gas sector, infrastructure and other major needs. While many countries in Central and South America hold tremendous potential, the vitality of their respective oil and gas sectors are highly inﬂuenced by a wide spectrum of political agendas that both impede and promote investment. In addition to aboveground risk, exploration can also be a chancy business; ExxonMobil and others have encountered a small number of dry (and expensive) wells in the Suriname-Guyana basin. But, as a whole, the region represents some of the best prospects in the world for the foreseeable future. HYDROCARBON 11

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May 2021 14 HYDROCARBON ENGINEERING

Jeff Bause, NOXCO, USA, explains the benefits of a subscription-style service in the refining and petrochemical industry to more accurately budget annual ongoing maintenance.

ddressing the question of a facilty’s maintenance plans and costs in the year ahead and beyond is difficult enough in a ‘normal’ year, considering all of the unknown factors that arise before and during a turnaround. While a refinery or plant manager will always attempt to have a complete understanding of the level of work that needs to be completed during planned maintenance activities, the unknown of the future makes precise planning nearly impossible. The year 2020 presented a new level of unexpected factors to consider, which makes

the one-year forecast appear even more daunting. While some routine projects are easy for a manager to put pen to paper and calculate a number, there are many ‘one-off’ or monthly utility charges that complicate a forecast quickly, and make it more difficult to predict an actual cost with accuracy. It is a widely-stated figure that 30 – 40% of project expenditures come from unplanned work. In the refining space, this number can be mitigated due to the long-term planning period leading up to a turnaround, but the unknown factor of unforeseen expenses is still

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ever-present. The challenges that managers face as they attempt to budget for future maintenance costs are obvious.

The concept of subscription services One potential solution is to implement a much more precise and ‘planned’ budget for major anticipated expenditures whenever possible. In this case, think of a subscription service in the downstream sector to ensure that there is a cap on costs and to enable planned budgeting to remain very close to the forecasted plan. While the idea of subscription services may be new for some industries, the overall concept has been

Table 1. A comparison of the services included in a subscription partnership as compared to a traditional catalyst management plan Subscription service

Catalyst management plan

Focus is overall system performance

Focus is catalyst performance

System and catalyst testing

Catalyst testing

Full on-site inspection

N/A

Annual inspection/ maintenance

N/A

Catalyst life projection based on overall system performance, catalyst tests, and field data

Catalyst life projection based on laboratory test

Includes:

Catalyst laboratory testing

Catalyst life projection

Catalyst inspection

N/A

System inspection/field data analysis

N/A

Catalyst cleaning

N/A

Ammonia injection tuning

N/A

Replacement catalyst

N/A

Catalyst installation

N/A

Catalyst disposal

N/A

Figure 1. A subscription service ensures predictable,

structured payments and eliminates an unpredictable budget.

May 2021 16 HYDROCARBON ENGINEERING

around for generations. An example of a basic, well-known subscription service is that used for magazines, which can be widely bought from newsstands or retail locations at a fair, warranted, and convenient price – and one which many people are prepared to pay since there is an established and qualified demand. For those individuals who find great value in a particular magazine and want to read it on a routine basis, and who know they will turn to it time and time again, there comes a point that this ‘one-off’ price no longer seems fair or warranted and becomes much less convenient. A reader will then think to transition to a different model, as it is understood there will be an ongoing demand or need which can be forecasted. A reader then looks to a subscription service. First and foremost, the cost saving is pronounced, as there is typically a cost saving of 70% or more by changing the purchase to this different model. Moreover, once subscribed, there are some other indirect costs and/or time savings that may be realised. A convenience factor comes into play, as the publication is directly mailed to the subscriber and there is no extra effort required to procure the magazine. One does not need to take time to visit a newsstand to see if the new edition is available, and one is never inconvenienced by late delivery. The subscription also provides a certain peace of mind, as there is the confidence that the delivery will take place, with the task fully removed from a person’s to-do list. Finally, there is an implied guarantee of delivery, even if demand is particularly high in a given time period. A subscriber is guaranteed delivery regardless of other external factors. The bottom line is that with an on-going contract in-hand, it is expected that one will receive a superior price, better service, and the benefit of getting what is wanted without lifting a finger or even proactively thinking about the service.

The case for industrial subscriptions Translating this back to refineries and the petrochemical industry, there is an obvious place for a subscription service that will take budgeting forecasting to the next level. There is a clear opportunity for establishing a method and system to more accurately and precisely budget annual ongoing maintenance. In a perfect world, a facility manager could simply press the ‘set it and forget it’ button on all of the maintenance services that can and will be needed over time, and know that somehow the needed services will take place through the work of highly skilled workers, and the assets will do their jobs fully as intended. While that scenario is not possible for most assets, what if this ‘set it and forget it’ button was available for a recurring capital expenditure in a facility, such as the selective catalytic reduction (SCR) catalyst? This would be a way to remove the uncertainty of

replacement decisions and instead install a continuous performance guarantee. It would also allow the realisation of the full value of a plant’s SCR catalyst through what should be a detailed and proven lifecycle management programme, which includes ongoing testing, cleaning, and replacement. The premise of a subscription service for refineries, gas processing plants, and petrochemical facilities would bring value streams to facility owners and managers with the following benefits: A flat and forecastable rate for predictable budgeting. Streamlined operational planning. Guaranteed performance and emissions compliance.

Predictable budgeting Currently, when a plant purchases a new catalyst, the facility receives a warranty from the catalyst manufacturer. Plant management, however, assumes a great deal of responsibility after this transition takes place. Not only must the plant monitor the unit, but also tune, clean and troubleshoot the systems using the expertise of either a third party or via plant staff who may or may not be trained on the best way to maintain the system. Moreover, after many years, when the useful life of the unit has ended, plants must replace the catalyst at a significant capital expenditure.

Figure 2. A subscription service delivers performance, predictability, cash flow, and 100% risk mitigation through a turnkey solution.

It is important to note that every unit is different in size, design, age, permit levels, and so on. This means there is no consistent formula to use to calculate when maintenance will be required, or when the end of the useful life will occur and the dollars must be available. This makes budgeting especially difficult. A subscription service would turn this uncertainty around, and ensure that a facility has structured payments in place that would remain constant for an extended time.

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Streamlined operational planning Unknowns from the SCR system wreak havoc on longer-term planning and budgeting. Lead time on a new catalyst is often 4 months or more. This long lead time, paired with the ongoing effort to minimise the risk of NOX non-compliance, make it common practice to purchase a new catalyst too soon. This has an obvious impact on cash flow. A subscription service would maximise the useful life of the catalyst through a combination of carefully timed activity testing, catalyst cleaning, and tuning. Importantly, such a contract would help ensure a catalyst is not replaced too early in its lifecycle. Additionally, the concept of a subscription service offers up the potential for the strong purchasing power of a large-volume catalyst buyer.

Keeping guarantees in place SCR systems currently operate with only 3 – 5-year performance guarantees from catalyst manufacturers, as a catalyst loses efficiency as it ages. After the guarantee period, the operator bears the full risk of non-compliance. An alternative is to find a catalyst management and maintenance plan to reduce the frequency of replacement without a lapse of performance guarantee even after the supplier’s performance guarantee has expired. Having guarantees in place through a subscription will help ensure that plants meet their goal to be in full NOX compliance 100% of the time, and avoid the costly price of missing the mark. The transfer of responsibility to

another entity is very enticing, as is the mitigation of operational risk at a facility.

Making the reality of a subscription service come to life Optimally-timed, planned maintenance through a subscription programme would offer a great number of quantifiable benefits to a facility, with predictable and manageable costs at the top of the list. There are also qualitative reasons to participate in such a programme. Plant ownership and management would benefit from peace of mind and the understanding that there are tools in place to best calculate the optimum replacement time for a catalyst. A fixed and predictable budget also puts one at ease, as does knowing that outsourced catalyst lifecycle management experts are the ones managing the ‘black box’ and delivering optimal performance with needed and timely maintenance throughout the system. However, for such a programme to be a true success, a strategic partnership of trust, and one that offers complete transparency of unit performance data, is required. Will a subscription-based service become available, and provide all the described benefits, which are both quantitative and qualitative in nature? If so, many burdens would be lifted, many unknowns would be pushed to the side and the owners and managers of facilities would enjoy myriad benefits that include cost containment, streamlined operational planning, and guaranteed emissions compliance.

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Jim McVay, MISTRAS Group, USA, explains the complexities of a full, comprehensive mechanical integrity (MI) programme, and how proper implementation can lead to fully-realised operations.

n the fast-paced industry of today’s facility operations, maintaining integrity for assets and processes as a whole can be difﬁcult when personnel are already so pre-occupied on a daily basis. When facilities are in constant motion and assets are always operating, it can be a challenge to always stay on top of the true condition of equipment. Assets may degrade over time and cause shorter run times, longer downtime, and ultimately reduced mechanical integrity (MI). With facilities needing to meet rigid safety regulations and high productivity demands, it can be daunting to know where to start and all of the elements necessary to achieve true asset integrity. These factors make the need for comprehensive MI programmes essential to the success of any facility.

MISTRAS Group has experience in developing, implementing, and executing MI programmes in various facilities. MI programmes are an essential part of the company’s Asset Integrity Management Services (AIMS) programmes, which work to maximise safety and ﬁnancial return on assets through design, inspection, maintenance, and operational management.

Mechanical integrity within a PSM programme Process safety management (PSM) is required for all facilities handling hazardous materials through industry and government regulations. Often, however, facilities can struggle with implementing and executing the programme due to the

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installed, maintained, and replaced to prevent failures and damage. It is one of the most important elements of the entire programme.

Standards and analyses/assets involved A proper MI programme is designed, built, implemented, and operated in accordance with engineering standards, process safety information (PSI), operating procedures (SOPS), process hazard analysis (PHA), and in-service operations, monitoring, and inspections. Meeting these standards and analyses is of the utmost importance to operators and is why MI programmes are so important. They can help to ensure that the process continues to perform in a safe and reliable manner in operation by supporting the full life cycle of all equipment and piping in the process. The assets that are able to be assessed in an MI programme include: Pressure vessels and storage tanks. Piping systems and valves. Relief and vent systems/devices. Emergency shutdown systems. Controls such as monitoring devices, sensors, alarms, and interlocks. Pumps.

Elements of an MI programme Figure 1. Pressure vessel and storage tank inspections are essential to MI programmes, keeping operators updated on asset integrity to help them make informed run-repair-replace decisions.

complexities and subject matter expertise needed. An MI approach for a PSM programme is an ideal solution for putting safety at the forefront of operations. PSM refers to a set of interrelated approaches to managing hazards associated with process industries and is intended to reduce the frequency and severity of incidents resulting from releases of chemicals and other energy sources. These interrelated approaches include: Process safety information. Process hazard analysis. Operating procedures. Training. Contractors. Mechanical integrity. Hot work. Management of change. Incident investigation. Compliance audits. Pre-startup safety review. Emergency planning and response. Trade secrets. Employee participation. In a PSM programme, the various elements are interdependent, and all elements are related and necessary to make up the entire PSM picture. MI is deﬁned as the process of ensuring that process equipment is fabricated from the proper materials of construction and is properly May 2021 20 HYDROCARBON ENGINEERING

The basis of any programme is the organisation itself. An organisation should employ people that have good working relationships with inspection, operations, and maintenance. It is essential that necessary stafﬁng and competencies within staffs are present. Organisations must have ready access to facility process safety information and procedures to begin the implementation process and maintain an effective programme.

MI management documents MI management documents are a crucial element to the programme as a whole. These documents include written documents, document control and records. Written MI programme documents cover a wide variety of procedures and results, including organisation and reporting structure for inspection personnel, documenting and maintaining facility inspection and quality assurance and quality control (QA/QC) procedures, action management for inspection and test results, and more. A written and enforced standard for comprehensive and organised retention of inspection and test records is essential and is typically organised at the asset level. Initial acceptance and periodic re-review of MI programme documents are necessary throughout the project.

Competencies Personnel competencies come in the form of qualifications and training, competency assessment and verification. Competency levels for all MI personnel – including supervisors, engineers, inspectors and technicians – should be established and supported with initial educational and experience background requirements, training, and company/industry certifications. Complete and current training/certification records for all MI personnel should be maintained. Contractor competencies should be established

and routinely monitored by company personnel by way of a rigorous formal process.

Quality assurance and quality control QA/QC helps to ensure that all stages and elements in a programme are up to rigorous quality standards for safety and efﬁciency concerns. QA/QC appears in a MI programme through: A QA/QC programme. Equipment and piping design. Suppliers, fabricators and service providers. Welding QA/QC practices. Material verification and retro-positive materials identification (PMI). Installation and pre-startup practices. Critical in-service maintenance practices. Management systems, procedures, practices, and controls should be in place to ensure that QA programme requirements are continually met and properly adhered to. A comprehensive QA/QC programme is needed which follows applicable company and industry codes and standards, and is routinely updated when standards change as appropriate. A well-documented facility QC programme for the fabrication and receipt of new equipment (including PMI and receipt inspections) is particularly needed for staying on-task of MI efforts. New, repaired and replacement equipment should only be procured from a list of company-approved suppliers.

SEEING IS

BELIEVING

Figure 2. MI programmes can benefit from the

use of digitalised workflow solutions, which make asset integrity data more visible for operators and streamline communication across multiple plant functions.

It is also essential for MI personnel to have access to applicable company and industry design codes and standards. Personnel with appropriate expertise should also select materials for critical components, as material selection is important to the functionality of assets and not all operators have the knowledge of which materials are best for certain functions. An effective material control, marking, and PMI programme should be in place to ensure that new project and maintenance alloy and non-alloy materials are being installed

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as speciﬁed. Appropriate welding controls for fabrication should be established. Procedures for safe and effective pressure testing within facilities should also be addressed.

Degradation management Degradation management is essential for determining degradation mechanisms. Likely degradation mechanisms and expected degradation rates should be determined for all critical components and updated with any design and process changes. Necessary process controls should be established when determining degradation mechanisms. Communications and ready access to current degradation mechanism reviews and associated recommended process controls must be made to all stakeholders.

Inspection and NDE testing practices Inspection and non-destructive evaulation (NDE) testing practices include ﬁxed equipment inclusion, inspection plans, actual NDE, and the management of ﬁndings and recommendations. For the most effective inspection practices, all critical equipment and piping should be listed for inspection planning considerations with clear responsibilities for the MI personnel responsible for addressing each item. Items needed to be addressed often include thermowells, auxiliary piping on pumps, and third party equipment. For an effective asset integrity management system (AIMS) programme, data is the necessary component for real insight into asset integrity. Effective procedures for establishing comprehensive inspection plans based on damage mechanisms are a crucial aspect of inspection. An inspection data management software (IDMS) tool, such as MISTRAS’ Plant Condition Management Software (PCMS®), helps to ensure that data is properly stored and organised, and that operators can analyse all of a facility’s MI data. An IDMS links MI information across any technology platform for easy access. Storage of data, calculation of corrosion rates, storage of inspection plans, and monitoring compliance to support inspection programmes are essential tools for inspection data in today’s digital industry. Inspection tools used to conduct NDE testing and inspection practices have been expertly developed over decades of research and development. Ultrasonic testing (UT) is a major component of inspection tools and comes in various forms. Types of UT include: Standard thickness gauging UT. Automated UT. Long range guided wave UT. Phased array UT. Time of flight diffraction (ToFD). Standard, digital, and computer radiography, corrosion under insulation (CUI) inspection, online monitoring, and dye penetrant testing are a few of the many forms of non-destructive inspection methods utilised within an MI programme. The exact service used, or the combination of services used, is dependent on the needs of the facility and should be mutually decided upon in conjunction with facility and services personnel. An experienced inspection provider can offer facilities a greater advantage in executing a proper MI programme, particularly in determining the appropriate May 2021 22 HYDROCARBON ENGINEERING

NDT methodology required for a particular damage mechanism.

Pressure relief systems As safety continues to be a top priority for facilities and service providers alike, having a secure and effective management system in place for pressure relief devices (PRDs) is a necessary element of an MI programme. PRDs must be designed, developed, and documented effectively in the case of an emergency where a relief system is needed to discharge gas. A procedure is necessary to ensure all PRDs are scheduled for service at appropriate frequencies in accordance with site-specific procedures, industry codes and regulations. Initial ‘pop tests’ should be consistently reviewed critically and follow-up analysis should be conducted, and mitigations should be taken when tests demonstrate lack of proper PRD function. For tank pressure and vacuum vents, procedure(s) should be developed for certain necessary on-stream PRD inspections such as pre-startup installation inspections and periodic on-stream monitoring. Procedures should also be in place to ensure flare systems are periodically inspected for significant fouling and corrosion.

Repairs to equipment and piping Ensuring that repairs are able to be made to equipment and piping is necessary to keep MI programmes running smoothly. A large part of ensuring that repairs can be made is having the correct MI personnel for speciﬁcation and proper review of repair and testing procedures for equipment. Facilities need procedures and responsive resources to effectively conduct engineering analysis to determine ﬁtness for service (FFS) when defects and thinning are found during inspection and testing. Proper engineering analysis can avoid unnecessary conservative reactions and present a truer image of asset integrity. Facilities should establish a work process for the review and approval of temporary repairs, while tracking is also needed to ensure monitoring and timely removal.

Lessons learned An MI programme is helpful in keeping track of and trending leak histories and inspection planning updating so that the appropriate lessons can be learned for the future. Failure analysis on all failures that impact reliability or safety should be considered and noted for future reference. Root cause analyses (RCAs) used for all substantial failures that result in signiﬁcant reliability and/or safety impacts should be a routine practice. Key performance indicator (KPI) monitoring of MI programme performance is an essential part of learning from an MI programme and keeping operations in top condition.

Conclusion PSM and MI programmes are some of the most necessary parts of inspection in facilities. MI programming truly requires all players involved to be engaged in implementing the procedures for programme success. A ‘top down’ approach is necessary to drive the MI programming throughout operations, but it cannot be successfully executed without a ‘bottom up’ engagement from all personnel.

Randy Cruse, Sentry Equipment, USA, outlines how operations can be optimised with a refinery sample station audit.

n refineries, it is common for sampling systems to operate as separate entities within the plant. Each system collects its intended material, such as crude oil, condensates, and oil and water mixtures, to ensure that samples are representative, operators and equipment are protected, and the plant is operating safely and efficiently. This can leave equipment and operators siloed in a particular area, with little understanding of how their segment of the system interacts with other parts of the plant and affects the refinery as a whole. It also creates the risk of potential problems going undiscovered until it is too late. It is therefore critical to conduct a site-wide sampling audit to evaluate a plant’s sampling programme and ensure that all sampling stations are seamlessly working together. A comprehensive audit will not only assess the current state of a sampling system, it will also help refinery operators and managers develop a clear plan of action to ensure the processes they monitor remain safe and running properly.

Industry challenges: oil and gas Establishing a downstream project can run into the millions – or billions – of dollars in some of the most remote and challenging locations in the world, such as the Alaskan interior or the Arctic.

Schedules and budgets are tighter than ever due to fluctuating economic influences. However, safety remains critical, and stakeholders are concerned about the impact of projects on everything from the community to the environment. Furthermore, an industry shortage of technical talent, which is expected to worsen as the current generation of experienced engineers retires, complicates these issues. All of these challenges drive the need for a sampling audit that highlights how a plant can optimise existing refinery operations and strategically expand capacity to meet demand without significantly impacting the bottom line.

Get buy-in from all stakeholders While the demand for an audit often comes from within maintenance or operations, it is critical that the audit is championed by upper management, such as a plant manager or business unit manager, and presented to a buying group for it to be successful. Even if a buying committee is on board, procurement and contracts are often denied because the group does not want to open their operation to a new and potentially unknown vendor unless absolutely necessary.

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Audit proposals therefore need to be exceptionally detailed, including vendor information. It is advisable to choose an equipment vendor that offers service as well; for example, Sentry Equipment offers all service in-house, without outsourcing to another company that could stymie efforts to implement an audit. Choosing a full-service partner allows a plant to seamlessly request and implement an audit with the original equipment vendor.

A valuable SWOT analysis A sampling audit is a technical review of a sampling system’s strengths, weaknesses, opportunities and threats (SWOT). Audits are conducted by certiﬁed sampling experts to identify SWOTs in business areas, sampling units/types and within speciﬁc samplers. The analysis reviews the following: If any updates, modifications or new systems need to be added. Modifications can include: retrofits of current equipment, replacement of worn lines, installation of new sample coolers, analysers, etc., or adding a secondary cooling system or a magnetite trap. Priority of divisions based on the refinery’s needs. Estimated costs of potential repairs, edits, etc. Risks associated with not taking recommended action(s). For example, the audit might note that close attention should be paid to the needle assembly on a bottle system,

as various samples tend to leave crystal-like deposits that can lead to plugging. Audits also take into account pressure (PSI), temperature, and processes being audited to make a series of recommendations for the reﬁnery.

Tailored recommendations Each audit should be customised to the plant and domains or locations within the plant. No two samplers or processes work the same way, and many sampling areas are often under different types of management, depending on the location within the plant. These elements need to be considered when evaluating the system as a whole.

Prioritised actions The result of an audit is a comprehensive list of recommended actions that plant operators can take to optimise their sampling systems, from repairing equipment to replacing an entire system. When identifying needs, the sampling expert conducting the audit should use a system for identifying priorities. For example, Sentry provides comprehensive insight into all samplers within a plant, regardless of manufacturer or brand, providing a maintenance schedule or best practices to ensure the longevity of repairs, modiﬁcations and replacements.

Table 1. Example of Sentry Equipment’s audit report for a refinery customer Sampler type

Key components

Routine maintenance guidelines

Notes

TSI-3 bottle system

TSI-31-T-SS sample valve

Inspect sample valve for proper function. Replace if cycle positions are not producing desired results

This system is not currently functioning. Main line feeding the panel is plugged. Additionally, the N2 system has at minimum a faulty flow meter. If plug is cleared, entire N2 system should be serviced before returning to service

Table 2. Example of a sample station priority matrix Highest priority

Medium priority

Lower priority

Little to no existing sample station infrastructure and regularly caught, higher risk samples

Some existing sample station infrastructure but in very poor condition and largely not compliant with O-029

Existing infrastructure is mostly working and largely compliant with O-029 but needs some minor improvements to be fully compliant

Samples from bleeders Samples from behind single isolation Sour samples in fresh air High pressure samples Certain bag samples which could be caught through sample stations Samples without essential safety features (boxes, cooling systems, etc.)

Stations with broken valves/vents Stations which are totally plugged or inappropriately designed for sample being caught Stations without double isolation or safety purges like purges/vents Stations still mostly usable but with serious flaws

Stations which need spring loaded valves Stations with vents not routed far enough away from the collection point Stations with inappropriate thickness of needles Stations missing gauges and flowmetres Stations which do not have constant circulation (if required)

May 2021 24 HYDROCARBON ENGINEERING

An audit helps optimise plant systems Running an efficient refinery requires real-time data analysis. Gleaning critical insights from sampling equipment is essential to product quality, safety and operational processes. A properly designed representative sampling system with the right sampling equipment ensures process samples are repeatable and reliable to help refineries maximise return on investment, better manage loss control, and reduce operating costs.

Matching the equipment to the application Capturing representative samples and protecting the operator is critical in high-temperature and high-pressure applications commonly found in reﬁneries. It is therefore essential to match an application to the sampling equipment. A sampling audit can also ensure that the right equipment is matched to the application(s) within a reﬁnery. Automatic samplers help to optimise sampling accuracy and repeatability for hydrocarbon liquids such as crude oil, condensates and oil and water mixtures. They isolate the process without interrupting the process line, and offer a variety of different types depending on the application.

An audit will ensure that applications are matched with the correct sampling equipment throughout the course of a reﬁning process.

Assess the need for training While an audit does not speciﬁcally measure plant personnel’s knowledge of the sampling systems, it can often uncover areas where operators need training, whether on an existing system or a recommended new piece of equipment. Not only does training ensure new operators get adequate guidance, it also helps experienced operators stay up-to-date on proper operating procedures. An audit can help management clarify where training should occur, from a junior engineer to maintenance personnel.

Figure 1. Example of low-emission sampling systems.

Figure 2. Technicians inspecting sampling equipment for audit.

May 2021 26 HYDROCARBON ENGINEERING

Training often offers detailed information on application-speciﬁc equipment so operators can safely collect emission-free samples. This should include: Types of sample systems installed in the refinery. Why each type of sampling system is used. How to use each sampling system. How to conduct sample collection preparation. Common issues with each type of sampling system. General maintenance guidelines. Routine maintenance checklist. An audit can also help supply plant personnel at all levels with this critical information.

Staying current with the latest regulations Sampling audits are even more important in light of evolving regulations and guidelines. Not meeting the new and current US Environmental Protection Agency (EPA) regulations can result in large fines, as well as damage to the environmental and plant personnel. It is advised to protect processes and prevent these costly risks with representative sampling. In December 2020, the EPA published its final version of the updated ‘Fuels Regulatory Streamlining’ rule, which will take effect in January 2022. The new rule updates the EPA’s existing gasoline, diesel and other fuel quality programmes to improve overall compliance assurance and maintain environmental performance while reducing compliance costs for the industry and the EPA. As part of the EPA’s continual effort to ensure that fuel quality standards established under the Clean Air Act (CAA) continue to be met, it streamlines and modernises existing fuel regulations under 40 CFR part 80 fuel quality regulations by transferring them into a new proposed set of regulations in 40 CFR part 1090. The updated rule takes a wholistic look at the existing part 80 regulations, attempting to consolidate the many different and overlapping regulations into the proposed part 1090 regulations that will better reflect how fuels, fuel additives and regulated blendstocks are produced, distributed and sold in today’s marketplace. Any company involved in the production, distribution or sale of transportation fuels, including gasoline and diesel, could be affected by this update. Under the current EPA Part 80, gasoline manufacturers are required to measure 11 complex model parameters. For the updated part 1090, this has been reduced to just three parameters: sulfur, benzene, and Reid vapour pressure (during summer months only. See the rule for more details). Diesel manufacturers will have to continue to test for sulfur. Accurate test results depend upon the sample being representative of the entire fuel batch. To achieve this accuracy, it is critical to be sure that the representative sampling system meets these updated sampling requirements. A sampling audit will review a fuel sampling equipment and application to ensure readiness before the EPA Fuels Regulatory Streamlining rule takes effect in 2022. Conducting a specialised sampling audit can help guide plants in making critical business decisions and implementing high-quality sampling processes.

Saeid Aflakian, Merichem Company, USA, presents a new approach to lowering total sulfur in the LPG product stream.

ecent changes in fuel standards complying with the US Environmental Protection Agency’s (EPA) Tier-3 have caused many refiners to address their compliance methodology for fuel sulfur levels. One area that is often missed is the advancements available in caustic treating. Caustic treating provides a lower CAPEX and OPEX, as well as no reduction in octane, and continues to find a place in the modern refinery process portfolio. Many caustic treating systems can achieve less than 30 ppm total sulfur in LPG blends by removing acidic sulfur species, such as hydrogen sulfide, carbonyl sulfide and light mercaptans. What is not well known is that this same technology can reduce extractable sulfur to less than 3 ppmw (not counting non-acidic inert sulfur species) with the application of new developments in process layout and catalysts. This article will discuss the operation of such a unit at a major Padd 2 refinery in the US.

The need for ultra-low sulfur (ULS) caustic treating technology Merichem worked with a major Padd 2 refinery that produces a high volume of finished products such as gasoline with a throughput capacity of approximately 170 000 bpd. Refinery personnel were evaluating capital scope options and requirements for manufacturing gasoline with 10 ppm sulfur to meet EPA Tier-3 regulations. As a result, they determined that the total sulfur content of their butane/butylene (BB) stream would need to be maintained at less than 10 ppm. To allow for inert sulfur compounds already present in the hydrocarbon feeds, the sum of unextracted acidic sulfur and back-extracted disulfide oil would need to be 3 ppm or less as sulfur. Caustic treating removes acidic sulfur species. The alkaline pH of the caustic solution reacts with the sulfur species (most notably mercaptans) to form water-soluble, ionic compounds which preferentially move into the caustic phase. Once separated from the hydrocarbon phase, the aqueous sodium mercaptides are sent to an oxidative regeneration unit where heat, oxygen and catalyst are introduced. The mercaptides react with the oxygen to form mostly insoluble HYDROCARBON 27

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disulﬁde oils (RSSR or DSO), which are then removed from the caustic. The regenerated (or lean) caustic is then returned to again interact with the hydrocarbon, extracting more acidic sulfur species. The extraction and oxidation reactions of mercaptan (RSH) and caustic (NaOH) are shown here: Caustic Extraction:

RSH+NaOH ⇒ NaSR+H2O

Oxidative Regeneration: 2NaSR +

O2 + H2O

Catalyst

RSSR + 2naOH

While it is relatively easy to reduce extractable RSH in the product to 1 – 2 ppm as sulfur (S), one of the largest challenges to caustic treating is preventing the resulting DSO from returning to the hydrocarbon feed. The DSO is typically both entrained and dissolved in the oxidised caustic. The colloquial term for the DSO which returns to the treated hydrocarbon is ‘re-entry sulfur’ or ‘back extraction’. To achieve the low sulfur requirements, Merichem Company offered its REGEN® ULS technology, which reduces DSO back extraction allowing total sulfur product specifications below 10 ppmw. Merichem designed the REGEN ULS technology by combining two separate existing technologies in such a way as to force the DSO to separate more completely from the regenerated caustic compared to a traditional REGEN system. Pairing a high-efficiency RSH removal system (THIOLEXTM) with a specially designed REGEN ULS, where total DSO back extraction is reduced to only 1 – 2 ppm as S, allows for a much lower total S product specification compared to a standard REGEN. The first REGEN ULS unit was installed in Taiwan over 10 years ago and has since been successfully operating and meeting product specifications.

Technology advantages The THIOLEX technology utilises caustic soda as the treating reagent to remove acid gas and mercaptan compounds from liquid hydrocarbon streams. The non-dispersive FIBER FILM® Contactor used in the technology enables reduced CAPEX and less plant space requirements compared to most treating alternatives. The large interfacial surface area, microscopic diffusion distance and continuous renewal of the aqueous phase when using the Contactor combine to yield greater mass transfer efﬁciencies. Because the aqueous phase adheres to the ﬁbres in the Contactor rather than being dispersed into the hydrocarbon phase, aqueous carryover is virtually eliminated. The FIBER FILM® Contactor was designed as an improvement to conventional caustic/hydrocarbon dispersive mixing designs such as trays and mixing valves. It reduces caustic carryover with the hydrocarbon after the contacting and reduces the size of the separation vessels. The patented REGEN ULS achieves low total S in the lean caustic by using up to three DSO-removal steps: The bulk free DSO is first decanted. Next, the caustic is solvent washed to remove most of the dissolved DSO. Finally, for DSO polishing, the caustic flows through a DSO adsorption bed. This three-step process allows a near total elimination of DSO re-entry sulfur in the treated product. In many cases, butane can be treated pre-fractionation in a single train compared to conventional technologies requiring treatment of multiple trains post-fractionation. In this case study, total mercaptan sulfur content of the BB feed was reduced from 222 ppmw to less than 2 ppmw for combined mercaptan and DSO.

Description of the process

Figure 1 contains a schematic flow diagram of Merichem’s THIOLEX/REGEN ULS treating unit with untreated BB. The hydrocarbon stream is treated in a THIOLEX system using lean caustic from the REGEN ULS. The untreated BB stream has a design throughput of 13 000 bpd and total mercaptans of 222 ppmw as sulfur. After treatment in the THIOLEX unit, the sum of remaining mercaptan plus DSO as sulfur is reduced to 2 ppmw. The mercaptide-rich caustic is directed to the REGEN ULS system, where it is oxidised on a fixed catalyst bed. The resulting DSO is then removed from the caustic using first bulk phase separation and decanting, then solvent washing, and lastly adsorption on a fixed bed (not indicated) to yield the ultra-low sulfur (ULS) lean caustic that is recirculated to the THIOLEX unit for continuous treating. The technology super-regenerates the mercaptide-rich caustic and returns a lean caustic almost free of DSO. This allows ultra-low sulfur levels to Figure 1. Schematic diagram of the THIOLEXTM and REGEN® ULS technology. be obtained in the treated butane product.

May 2021 28 HYDROCARBON ENGINEERING

Utilising THIOLEX technology, the BB stream is treated with regenerated (lean) caustic to extract acidic sulfur components. The REGEN ULS regenerates the spent caustic from the THIOLEX unit while removing almost all DSO. Figure 2 shows the actual BB feed throughput in bbl/hr, total sulfur and total extractable mercaptans in ppmw in

the feed. Even as flow was reduced, feed sulfur remained high in both streams. Figure 3 shows the results of both total product sulfur and mercaptans compared to the design BB product specification (the solid green line). For a month of normal operation, the impurities in the feed BB compared to the design case, the BB unit was under the total S product specification of 2 ppmw. Table 1 shows the design feed throughput and impurities compared with actual feed throughput and impurities. As can be seen from the results, the stream successfully met all product specifications.

Delivering financial, operational and environmental benefits Cost effective and efficient

Figure 2. Actual butane/butylene (BB) throughput, total sulfur and total mercaptans as the impurities in the feed.

Merichem’s combined THIOLEX and REGEN ULS solution is less expensive than hydrotreating or once-through caustic treating with no regeneration. Compared to a typical REGEN, the REGEN ULS costs 10 – 15% more, but yields a much lower total sulfur hydrocarbon product. The FIBER-FILM Contactor enables more surface area for the mass transfer of hydrocarbon impurities with caustic soda. Due to this efﬁcient mass transfer rate and low energy mixing, residence time is signiﬁcantly reduced, and emulsions and caustic soda carry-over are minimised.

Environmentally sound Regenerating and recycling caustic soda not only lowers OPEX but also helps protect the environment. Without a regeneration unit, spent caustic must be processed internally or manifested and shipped as hazardous waste to a third-party waste handler. With a regeneration unit there is still some caustic that needs to be removed; however, the volume shipped out is much lower than it would be if the unit was a single pass with no regeneration unit. Alternative technologies such as hydrotreating are also signiﬁcantly more energy intensive.

Net results A determined commitment to teamwork by both parties resulted in the refinery in this case meeting its requirements for manufacturing 10 ppm sulfur Figure 3. Actual BB mercaptans and total sulfur in the product vs product to meet the EPA Tier-3 regulations for the product specifications for mercaptans and DSO. gasoline. The THIOLEX/REGEN ULS technology provided Table 1. Feed and product specifications (ppmw) and a reduction in the sum of mercaptans and disulfide oil as unit throughput sulfur to lower than 2 ppmw in the product stream along BB (design) BB (actual) with ease of operation. Feed totul sulfur 240 170 The unit can handle turndown scenarios and has Feed RSH 220 150 handled up to 20% C5+ material in the feed, with the only impact being increased caustic consumption. On a Feed non-extractable sulfur 16 20 day-to-day basis, operating involvement is minimal. Most Product total sulfur 2 of the operation is monitoring levels, pressures, flows, and Product RSH + DSO 2 1 temperatures with occasional caustic batching and catalyst Throughput (bbl/hr) 540 400 additions. May 2021 30 HYDROCARBON ENGINEERING

Robert P. Saunderson, Air Products, USA, explores how to find the right combination of LNG subcooling and end-flash.

n a natural gas liquefaction (LNG) facility, the amount of subcooling performed on the LNG and the quantity of end-flash vapour produced affects the investment in liquefaction equipment and refrigeration power. Since there is limited flexibility in some instances and a wider array of possibilities in others, it is important to understand each of the available options. This will allow the right combination of LNG subcooling and end-flash to be selected based on all factors influencing the decision when using an AP-C3MRTM or AP-DMRTM LNG process.

Fully-subcooled liquefaction process While liquefaction of natural gas is performed at high pressure (55 – 75 bara), the LNG storage tank is operated just above atmospheric pressure. To prevent ﬂash in the LNG storage tank due to adiabatic pressure reduction from liquefaction pressure to tank pressure, LNG must be subcooled to approximately -161.5°C to -163°C in the main cryogenic heat exchanger (MCHE). This is known as a ‘fully-subcooled’ liquefaction process. The feed gas to liquefaction in a fully-subcooled process must have ≤ 1 mole% nitrogen content to meet the

standard LNG product specification in the storage tank. Although this process produces no adiabatic end-flash or tank-flash, vapour is formed in the LNG storage tank due to heat leak and pump work in the LNG piping to storage and heat leak into the storage tank itself. This vapour is known as storage tank boil-off gas (BOG). The BOG, which is displaced by rising liquid level in the tank from incoming product, must be withdrawn from the storage tank to avoid an overpressure. Although nitrogen will preferentially migrate to the vapour phase, there is not enough BOG formed to appreciably lower the nitrogen content of the LNG. Since BOG is mostly methane (usually 84 – 97% methane, 3 – 16% nitrogen, and ≤ 125 ppm ethane), it is often compressed and used as fuel. In a fully-subcooled process, the nitrogen concentration in the BOG and the MCHE exit temperature strongly correlate with the nitrogen content of the natural gas feed as shown in Figure 1. Since the fully-subcooled process generates a relatively small amount of BOG that can be used as fuel, this process is a good fit when the refrigerant compressors in the liquefaction unit are driven by motors drawing power from the local electric grid. In facilities where the

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End-flash liquefaction process When the feed gas to liquefaction has > 1% nitrogen content, the fully-subcooled and flash-in-tank processes are not acceptable options, since nitrogen must be expelled from the LNG prior to entering the storage tank. Instead, an LNG flash drum is included downstream of the MCHE allowing the MCHE exit temperature to be warmer, typically between -145°C and -151°C depending on plant fuel requirements, since a warmer exit temperature creates more flash vapour. This is known as an Figure 1. MCHE exit temperature and BOG nitrogen content as a function ‘end-flash’ liquefaction process and is of nitrogen content in the natural gas feed. depicted in Figure 2. The LNG flash drum usually operates at 1.25 bara. The vapour generated in the LNG flash drum, which has a higher nitrogen content than BOG, is typically compressed and sent to the fuel header. The MCHE exit temperature is influenced mainly by fuel demand and feed gas nitrogen content, with a higher fuel demand or greater feed gas nitrogen content leading to a warmer MCHE exit temperature. When using an LNG flash drum, 90 – 95% of the fuel requirement for the gas turbines driving the refrigerant compressors and other power generators can be drawn from the end-flash and BOG while a buffer of about 5 – 10% of the fuel is typically drawn upstream of liquefaction.

Figure 2. Schematic of the ‘end-flash’ liquefaction process.

refrigerant compressors are driven by gas turbines, the BOG provides only a small fraction of their fuel requirement, so typically the remaining fuel is drawn from feed gas upstream of liquefaction. Generally, the feed pressure is greater than the fuel header pressure, so no additional compression is needed. Fuel drawn upstream of the liquefaction unit will contain any LPGs that were not removed in an upstream NGL extraction unit.

Flash-in-tank liquefaction process Since most LNG storage tanks can accommodate additional vapour, some facilities elect to operate with adiabatic tank-flash gas. When adiabatic flash gas in the storage tank becomes part of the BOG, the LNG temperature at the MCHE exit is typically -155°C to -156°C. This is known as a ‘flash-in-tank’ liquefaction process. Although a lower percentage of the feed gas becomes net LNG compared to the fully-subcooled process, the refrigeration power required per an identical amount of LNG in storage (specific refrigeration power) can be 6 – 7% lower for the flash-in-tank liquefaction process. Generally, the adiabatic flash portion of the BOG is 65 – 75 mass% of the total vapour generated in the storage tank. This process removes a larger amount of nitrogen from the LNG. Typical tank designs can accommodate the increased vapour flow when the feed gas has ≤ 1 mole% nitrogen. May 2021 32 HYDROCARBON ENGINEERING

End-flash liquefaction process with nitrogen rejection At higher feed gas nitrogen content an LNG flash drum may not be sufficient to expel enough nitrogen to meet the ≤ 1 mole% nitrogen specification in the LNG product. Since nitrogen removal is a broad topic with too many options to cover here, please consult the reference listed at the end of this article for more information.

End-flash liquefaction process with recycle To further reduce the specific refrigeration power, the MCHE exit temperature can be warmed to -140°C to -146°C if a portion of the end-flash is compressed and recycled to rejoin the natural gas feed at the liquefaction unit inlet. This is known as an ‘end-flash with recycle’ liquefaction process and is depicted in Figure 3. Recycling end-flash vapour creates a higher nitrogen content in the LNG exiting the MCHE, meaning that it is important to be aware of the threshold where a nitrogen removal scheme becomes necessary instead of an LNG flash drum due to the additional cost of this unit.

Advantages of end-flash liquefaction processes Although a larger fraction of feed gas is diverted to end-ﬂash gas in the end-ﬂash processes, the refrigeration required per unit of net LNG in the storage tank decreases as the MCHE exit temperature becomes warmer. Reducing MCHE duty by

warming the MCHE cold-end exit temperature decreases the amount of refrigeration required at the coldest temperatures. A colder MCHE exit temperature is achieved mainly by increasing the nitrogen content of the mixed refrigerant (MR). The rest of the MR is hydrocarbon based: methane, ethane, and propane. Since nitrogen is the MR component with the highest heat capacity ratio, it is the most power intensive to compress. End-flash processes redistribute duty from the coldest section of the process to the less energy intensive warmer parts, thereby reducing refrigeration compressor power consumption for the same net LNG production. Provided there is a use for the end-flash and BOG, typically as fuel, it is favourable from a refrigeration perspective to make the MCHE exit temperature as warm as possible. This is most advantageous when trying to keep the power requirement for the refrigeration compressors within the power available from the installed gas turbines that drive these compressors. As the MCHE exit temperature is warmed, power is diverted from the refrigerant compressors to end-flash compression. The diversion of power from refrigerant compression to end-flash compression is approximately power neutral from an overall liquefaction unit perspective. The end-flash compressor and end-flash recycle compressor are typically driven by electric motors.

Externally connected piping and platforms are supported from the vessel without the requirement for an additional structure. This design also eliminates low pressure cryogenic piping between the LNG flash drum and end-flash exchanger, which decreases pressure drop to the end-flash compressor suction.

Figure 3. Schematic of the ‘end-flash with recycle’ liquefaction process.

The end-flash exchanger The cold temperature vapour from the LNG flash drum is approximately -161°C to -162°C and can be used to provide refrigeration to a portion of the feed gas drawn at high pressure from just upstream of the MCHE warm-end inlet at about -30°C. The heat exchanger used for this refrigeration recovery is called an end-flash exchanger and is depicted in Figure 4. An end-flash exchanger covers a similar temperature range to the MCHE and has a duty that is about 2% of the total MCHE duty. The benefit of end-flash processes and the end-flash exchanger is most apparent when it can be used to increase LNG production by diverting power out of the refrigerant compressors and duty out of the MCHE and other liquefaction unit heat exchangers. Although it is possible to route the cold -161°C vapour from the LNG flash drum directly to compression instead of recovering its refrigeration, using this vapour as refrigerant in an end-flash exchanger and warming it to approximately -30°C prior to compression can increase LNG production by 1.5 – 2%. Typically, the end-flash system consists of the end-flash exchanger and a separate LNG flash drum. There are several types of heat exchangers that have been used in end-flash service. The most common involve an array of parallel brazed or printed-circuit aluminium heat exchangers mounted inside in an insulated steel-framed structure. The other type is a coil wound exchanger (CWHE). The end-flash exchanger can experience significant thermal stress due to the very wide temperature range it covers (-30°C to -160°C). The MCHE, which covers a similar temperature range, has mostly been a CWHE due to its mechanical tolerance for high thermal stress. The LNG flash drum can be incorporated into the sump of the CWHE shell as shown in Figure 5, thereby reducing overall equipment count and plot space requirements.

Figure 4. Schematic of the ‘end-flash’ liquefaction process including end flash exchanger.

Figure 5. Schematic of the wound coil end-flash exchanger.

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Table 1. Debottlenecking by converting to end-flash processes Liquefaction process

MCHE exit temperature

Net LNG in storage tank

(˚C)

(% of base case)

Refrigeration compressor gas power

End-flash compressor (+ recycle compressor) gas power

(% of base case)

(% of refrigeration compressor gas power)

Flash-in-tank (base case)

-156

100% (base case)

End-flash, no recycle

-151

103.5%

100%

3.5%

End-flash, with recycle

-146

107.5%

100%

7.5%

Case study: using end-flash liquefaction processes for debottlenecking When the feed gas to liquefaction has ≤ 1 mole% nitrogen, the prevailing tendency is to design the liquefaction unit using a fully-subcooled or flash-in-tank liquefaction process to avoid the capital cost of the end-flash equipment – separator, exchanger, and compressor(s). However, adding this equipment and converting to an end-flash process (with or without end-flash recycle) can represent a debottlenecking opportunity to increase LNG production. Table 1 shows an example of how conversion from a flash-in-tank process to an end-flash or end-flash with recycle process can increase net LNG in storage (after BOG is deducted) by adding power for end-flash and

recycle compression without increasing refrigeration power consumption. This example is applicable when gas turbines are used to drive the refrigerant compressors. All the end-ﬂash vapour is used as fuel unless it is recycled to join the feed gas at the liquefaction inlet.

Case study recommendations

For an LNG facility with ≤ 1 mole% nitrogen in the feed gas, it is best to evaluate liquefaction processes with and without end-flash during the design phase. Since gas turbines have mostly discrete power generating capability, the desired LNG production capacity may not fit well with any reasonable combination of gas turbines selected to drive the refrigerant compressors. The power of certain gas turbine drivers can be augmented by electric starter/helper motors, but in some instances the addition of an end-flash system may be the best option to maximise LNG production capacity.

Reference 1.

OTT, C. M., ROBERTS, M. J., TRAUTMANN S. R., and KRISHNAMURTHY, G., ‘State-Of-The-Art Nitrogen Removal for Natural Gas Liquefaction: New Solutions to Meet Market Needs’, Gastech (2014).

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Nicola Curtis, Rotork, UK, explains how flow control supports safety and reliability in the LNG industry.

he growth of the worldwide LNG industry shows little sign of slowing down. Instead, the production and use of LNG is a clear area of growth, and McKinsey forecast that it is due to grow 3.6% every year up to 2035.1 The use of LNG is increasing in importance as the demand for gas grows and large quantities of gas are processed and transported around the world. A key beneﬁt of LNG is its ability to be moved around the world on specialist carrier ships or cryogenic tankers, providing easy access for customers. Once processed into LNG, the resulting liquid is 600 times smaller than its natural gaseous state. This makes transportation more economical than if the original natural gas was transported. Once regasiﬁed, LNG is used as a fuel source, increasingly as commercial transportation fuel and as a power source for domestic and industrial use. It can also fairly claim green credentials when used as a fuel source compared with other fossil fuel types such as oil and coal, as it releases reduced emissions into the atmosphere. Despite the high quantity of natural gas available, it is often found in remote locations that are hard to access. This means that there are many complex processes involved at all stages of

LNG production. The LNG supply chain is complex and technical, involving extraction and liquefaction, shipment on special tankers, regasiﬁcation at import terminals, and distribution. Safe and reliable ﬂow control has a key role within each part of the LNG industry process and specialist products and services are required.

How flow control products ensure safety within LNG The extraction, processing and transport of LNG around the world must be completed in a safe and reliable way. Flow control plays a key role at every stage; from the extraction of gas, to its liquefaction, transport (both in pipelines and LNG carriers), regasiﬁcation, and distribution/onwards transportation. During the exploration and production stage, natural gas is extracted by producing wells in either ‘associated gas’ deposits or sometimes a by-product of oil production or extracted from coal seams as a non-associated gas. The gas is dried and processed before it is converted into LNG, removing condensates, impurities (such as carbon dioxide and hydrogen sulﬁde), and water.

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Flow control in LNG downstream applications

Figure 1. Flow control systems play a role at all stages of the journey of LNG.

Figure 2. Rotork actuator installation at a wellhead and separator skid in Australia.

Extremely cold temperatures are an inherent part of LNG. During the liquefaction process, the natural gas is cooled to -162°C, when it becomes the clear, colourless liquid that is known as LNG. The valves used to control the flow of this product must therefore be suitable to work at very low temperatures. For example, cryogenically safe valves are primarily made from 316 stainless steel, which maintains body strength at these very low temperatures, and they must meet safety standards such as BS 6364. The flow control equipment that controls the valves, such as actuators, must also provide safe and reliable operation within consistently hazardous environments. Products must allow for maximum uptime and operational efficiency. Flow control systems that have been well designed and correctly maintained will allow for this, as well as compliance with environmental standards. The precision and control provided by actuators removes human error, increasing accuracy, efficiency and reliability within an automated process. For example, intelligent electric actuators, such as IQ actuators from Rotork, play a vital part in the transportation of LNG, controlling the flow of liquefied gas onto carriers in a safe, reliable and efficient fashion. Intelligent actuators have many other benefits in controlling the flow of LNG, such as detailed real-time and historical feedback information through data logs (e.g. alarms, valve torque profiles and number of valve movements/operations). They will be suitable for use in hazardous environments; actuators within the IQ range are explosion-proof, offer double sealed enclosures to prevent water ingress and are IP rated (IP66/68 at 20 m for 10 days). May 2021 36 HYDROCARBON ENGINEERING

Regasification usually occurs at a coastal import terminal. These terminals have specialised requirements to cater for the management and handling of LNG. The performance of actuators is a key part of safe and reliable operation during these processes and the flow control products used require high safety standards. Actuators are a constant presence at automated tanks farms, performing isolating duties for routine flow control, modulating actions and fail-safe activity for vital safety requirements. Tank farms will also use intelligent electric actuators for safety related duties such as emergency shut down (ESD), which is vital in case of dangerous events such as fire, flooding or any event where continued operation could be hazardous. Pneumatic flow control equipment is another common sight on LNG terminals and sites. Pneumatic scotch yoke actuators, such as Rotork’s GP range of pneumatic actuators, operate the cryogenic valves used on main pipelines. They perform open/close functions, controlling the natural gas before and after it is made into LNG, as well as the LNG itself. The precise control that these actuators offer is essential. For example, flow can be cut off straight away by the fail-safe functionality before any damage is caused due to the spring-return module inside the actuator. Some valves within vaporisers are small and compactly arranged, requiring compact and quick actuators that offer isolating and modulating duties in hazardous and cryogenic environments. The applications at this stage of the LNG process include tank pump discharge, vapour discharge, tank liquid fill, water cooling circuit valves and operation of gas outlet valves. Control and monitoring centres also play a key role on LNG sites, controlling hundreds of actuators simultaneously. Rotork’s ‘Master Station’ control system, for example, is in use across the world on LNG sites such as the Pengerang deepwater petroleum terminal in Malaysia, which has a regasification unit, two 200 000 m3 LNG storage tanks, and berths for the loading and unloading of LNG vessels. While the actuators control the flow of LNG, a master station remotely controls the hundreds of intelligent actuators, using a field network (PakscanTM). This kind of system provides robust and reliable plant control and monitoring, which is essential within the LNG industry.

The importance of intelligent flow control asset maintenance Intelligent flow control assets within the LNG industry maximise operational reliability and efficiency. This article has focused on the importance of these assets within the LNG industry, but their maintenance and smooth running is of equal importance. LNG flow control assets perform daily in challenging operating and environmental conditions. They often work within environments with extreme temperatures and excess vibration, yet still need to operate reliably. Maintenance programmes that support assets in working effectively (ensuring the availability of assets at all parts of the LNG journey) are essential. Asset failure or obsolescence has dangerous implications, including reduced quality, financial loss and even reputation damage. Unplanned downtime is undesirable and costly, but sites which have a full life cycle asset management programme (such as Rotork’s ‘Lifetime

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view of an asset’s life cycle, with ﬂexibility and customer choice, allowing customers a bespoke approach to maintenance. In addition to bespoke maintenance programmes, many ﬂow control products must have Safety Integrity Level (SIL) ratings. SIL is an established system of standards of the performance requirements of a safety system. It is part of an overall shared safety plan that includes techniques, technologies, standards and procedures that help operators protect against hazards, an essential function within LNG.

Conclusion

Figure 3. IQ3 actuators at the Pengerang terminal, Malaysia, during the installation stage.

Management’ programme) are likely to see improved performance, increased uptime and an important decrease in unplanned maintenance costs. These service programmes offer a steady, set cost to plant operators. A service plan for ﬂow control assets all along the LNG journey should have a holistic

The current demand for LNG has many explanations, including the multitude of ways in which it can be used (both domestically and industrially), a clean burn and subsequent reduction in combustion relayed emissions (compared to other fossil fuel sources), and the advances in technology within the natural gas industry which mean more is now being found. The ability to liquefy and then regasify this gas means it can be accessed by countries in every corner of the world. The LNG industry is complex, but with efficient and reliable flow control equipment such as actuators, LNG production, transportation and distribution can be conducted in a safe, productive and profitable way. Effective flow control and associated systems play a vital role at all stages of the LNG journey, meeting the ever-growing increase in demand.

Reference 1.

‘Global gas and LNG market outlook to 2035’, McKinsey.

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Tony Dodd, Servomex, UK, explains how to improve operational excellence through digitalisation of gas analysis equipment.

eliable, accurate and stable gas measurements are essential to many industrial operations, helping to optimise production processes, maintain safety and meet regulatory requirements. As current innovations in technology and digitalisation develop, it is almost certain that the solution surrounding the measurement can be improved, with signiﬁcant beneﬁts for the operational excellence of plant operators investing in Industry 4.0. The challenges introduced by cultural and workforce shifts have combined with ongoing economic, competitive, and regulatory pressures to increase the focus on

operational excellence – seeking the optimisation of processes, assets and people. Operators performing in the top quartile stand out when compared to competitors in the fields of safety, reliability, efficiency, sustainability and financial performance. On average, they record three times fewer safety incidents, see a 4% increase in operational availability, reduce maintenance costs by half, lower emissions and energy use by 30%, and reduce operating costs by 20%. The positive impacts on profits and margins make a continued focus on operational excellence critical to

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Figure 1. Gas analysis is essential to support

operational excellence and competitive performance in many industrial facilities.

Figure 2. A service plan, supported by predictive

condition-based monitoring, increases confidence that unplanned downtime can be avoided.

competitiveness, or even survival. These gains in operational excellence often come from incremental, thoughtful and focused digitalisation initiatives; for example, ﬁnding ways to automate or streamline manual, error-prone or slow activities, and improving situational awareness. Low-cost sensing, connectivity, data storage and processing can be fully utilised, enabling more informed and responsive operations and maintenance, and creating new levels of optimisation and asset management.

Offline gas analysis and the impact on operational excellence Gas concentration measurements support the operational excellence objectives of many industrial processes, meaning that if those measurements become unavailable for any reason, operational revenue decreases while operational costs and risks are increased. An ofﬂine gas analyser means that the process control system has less information on which to base adjustments, leading to the degradation of control and higher operational costs. A process may be able to continue, thus avoiding a shutdown, but cannot run optimally. The consumption of energy, fuel, and other resources may increase, other assets may be affected, and the operator will incur additional costs to remedy the ofﬂine analyser. May 2021 40 HYDROCARBON ENGINEERING

Take the example of the NOX emission reduction process in combustion power plants (DeNOX), using selective catalytic reduction (SCR). Ammonia (NH3) is injected into the gas flow from the combustion process. It reacts with NOX in the flue gas, in the presence of a catalyst, to form H2O and N2. Surplus unreacted NH3 (ammonia slip) is wasteful and costly, and often leads to harmful deposits which impact the catalyst and may cause corrosion of air pre-heaters located further downstream. A gas analyser going offline can also impact operational revenue, since the degradation in control capability can take product quality off-spec, reduce product yield or increase product scrappage. Consider semiconductor wafer manufacture, which relies on ultra-pure gases. The smallest impurities can result in major defects, leading to product scrappage. Operational risks are also increased by an offline gas analyser. In the ammonia slip example above, an offline analyser means harmful emissions increase, and can affect regulatory compliance. Accurate gas analysis is essential to maintain safe operation in some processes, such as combustion in control fired heaters. These are integral to many hydrocarbon processing applications, and depend on the stable, continuous measurement of excess air. Operating large, fuel-hungry units efficiently – for example, those on ethylene crackers – requires a delicate balancing act, ensuring efficient, low-emission operating conditions while remaining on the safe side of a tipping point that leads to potentially explosive low-oxygen, fuel-rich conditions.

Factors that can reduce gas analysis availability While balancing cost and risk, it is essential to achieve high availability for gas analysis. Nonetheless, there are a number of factors that may lead to reduced availability. Issues with installation and commissioning can affect tightly planned and coordinated construction, upgrades, and shutdowns, and could delay the startup/restart of production. Delays can cost operators up to hundreds of thousands of dollars each day, with lost revenue and the need to re-schedule dependent works. Late delivery, defective materials, poor installation and limited field access to information are all factors that contribute to such delays. If an analyser is exposed to unforeseen process and operating conditions, this is often detected by the analyser’s diagnostics, though this is not always the case. Depending on the conditions encountered, gas measurements may stop while the analyser reports faults or out-of-specification indications to the plant control system – for example, changes to the ambient or sample gas temperature, pressure, or flow levels, poor power supply or excessive vibration. Specific gas concentration measurement technologies may also be able to detect additional conditions – for example, tunable diode laser spectroscopy (TDLS) measurements can be compromised by unexpected background gases and high dust or particulate loading in

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the process gas stream. Some conditions can damage the gas analysis system and require replacement parts. Inadequate maintenance is another factor that can lead to performance degradation, and ultimately to an unavailable measurement. Sampling systems and analysers themselves often include filters which protect the gas sensors from expected contaminants such as particulates and moisture. These typically need regular cleaning or replacement. Even under standard operating conditions, analyser optics can become obscured over time and will require cleaning. These maintenance activities – including cleaning or replacing filters, cleaning optics or performing periodic validation of measurement accuracy – usually require analysers to be taken offline. Additionally, the incorrect operation of an analyser – accidentally adjusting a critical configuration, for example – can effectively render the analyser offline, or at least make it unreliable. Examples of this include disabling or changing the temperature or pressure compensation configuration, modifying assigned behaviour of outputs, or even modifying essential measurement details, such as optical path length of an in-situ installation. The final factor is unexpected component failure, which typically leads to diagnostics identifying the faulty part. The nature of the faulty part dictates the impact this has on the gas measurement and its availability to the control system.

Dealing with unavailability events using current methods Many of the current methods utilised to deal with unreliability events are manual, inefficient, error-prone and not always sufficiently data-driven. They may involve taking notes and photographs, or capturing limited digital logs on-site, then travelling to an office in order to consult the necessary documents – such as orders, delivery notes, contracts, manuals, drawings, and technical bulletins – then returning to the site or contacting the distributor/supplier for support. While emails and phone calls can reduce travel time, they are a limited and imprecise way to convey all the necessary information about an issue. It may take a number of communications, supported by site visits, to accumulate the information needed for remote support workers to offer their insight. All the while, the offline duration increases. Even when the problem is identified, expert service team visits do not happen instantly, potentially extending the impact on revenue, while travel and subsistence add costs and introduce new workers onto the site, increasing risk. Additionally, one visit may not be enough – was a diagnosis based on notes, photos and limited data logs enough to ensure the right tools and parts were brought along to provide a fast and accurate first response? Gas analysers have been intelligent devices for many years and are integrated into control systems. They have, however, been more focused on providing the gas measurement and health indications necessary to provide May 2021 42 HYDROCARBON ENGINEERING

situational awareness to process control systems and operators. This means that they have not continuously recorded or exposed all events and data streams to allow a retrospective and contextualised analysis of analyser and process behaviour, as there has not been sufﬁcient processing and storage capacity or connectivity bandwidth. By not recording all events and data streams, maintenance activities remain scheduled events, regardless of system conditions, contributing to waste and unnecessary risk. Experience, or the process of elimination, may also resolve some issues. While inbuilt diagnostics may not clearly identify the problem, experts may infer that a condition exists using other data – for example, excess vibration, poor power supply and some spectral quality issues.

Improving work processes through digital transformation Digital transformation provides a major opportunity to improve these work processes, but it depends on the combination of increased amounts of real-time and static digital data, along with increased access to it. If future products and services enable timely access to the right data, for the right people, in the right place, then availability issues and activities could look very different. Transparency and communication of supply issues could be improved by increasing data collection and tracking from order to delivery, throughout internal processes. The goal is to eliminate supply issues, but if problems arise, early awareness enables sites to take early action to minimise disruption. Asset management systems are used increasingly by industrial facilities to create digital twins of their facilities and assets, enabling connected workers – carrying out installation, commissioning or maintenance work – to access 2D drawings, 3D models, manuals, technical bulletins and other information at the site via appropriate mobile or wearable devices. Annotated augmented reality capability, enhancing the worker’s view with a digital overlay, can provide visual guidance for the task. Many of the delays in resolving issues are removed by access to data on this ‘right time, right place’ basis. Equipment suppliers such as Servomex will need to provide product data in appropriate ways to extend these services to gas analysis systems. While not every facility has advanced asset management or site-wide wi-fi in place, both are increasingly available and are enablers for transforming practices. Gas analysis systems can build upon those services by including a dynamic E-Ink based QR code on every gas analysis system that encode the system’s unique identity, current physical build, firmware details and other essential data. When scanned by a smartphone or tablet app, the QR code enables immediate retrieval of accurate version/built specific information from either the advanced asset management system or Servomex systems, to support fast local resolution. For example, available information could

include 2D and 3D drawings, user, service and safety manuals, and technical bulletins. The app could also offer direct access to technical or application support, providing maximum context to the support operative, minimising the requirement to collect more information. There is also a further possible application for annotated augmented reality technology, with experts providing visual guidance and over-the-shoulder support to the workforce. Additional security controls, including well-established methods such as two-factor authentication, can help prevent mis-operation of the analyser, protecting it against ill-considered or unintended changes to critical configuration. A service plan increases confidence that unplanned downtime can be avoided. However, while preventative maintenance is nowhere near as costly as reactive maintenance, it is still not optimal. If maintenance is carried out only when conditions require it, operational costs can be reduced, revenue less affected and risks lowered. This can be accomplished through predictive condition-based monitoring, which requires significantly more data than process control. Rather than use the NAMUR NE 107 type diagnostic health indicators currently provided by gas analysers for process control, the data behind those indicators is exposed. Analysis of patterns, trends and correlations can then deliver greater insight into changes over time, and at what moment those changes may impair performance.

Plant operational intelligence systems are becoming increasingly capable of ingesting and cleansing this type of data, then contextualising and analysing it to provide dashboards or notifications of critical events to the workforce. Traditional Fieldbus protocols – such as Modbus – can be used to integrate equipment into these systems; however, since Modbus maps for all types of device are unique and do not conform to a standard profile, ingestion would need to be configured, introducing another cost and productivity overhead. A more plug-and-play approach would be enabled by gas analysers supporting newer connectivity methods, such as Wireless HART or OPC-UA. With the appropriate device, system and service level security provision, suppliers such as Servomex can leverage additional operational intelligence services to monitor gas analyser assets on the plant operator’s behalf under service level agreements, providing enhanced levels of optimised service response.

Conclusion The key to the competitiveness – and in some cases survival – of many industrial operations is operational excellence, which can deliver huge benefits for safety, reliability, efficiency, and financial performance. The expert application of digitally transformed capabilities may enhance these objectives and allow innovative gas analysis suppliers to take advantage of developing technologies that ensure maximum availability of their equipment.

In the first of two parts, Ralph H. Weiland and Nathan A. Hatcher, Optimized Gas Treating Inc., USA, examine two case studies showing disparities between simulation and plant data caused by defective equipment and contaminated solvents.

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imulation tools are used extensively in a wide range of activities, from plant design, unit revamps and troubleshooting, to plant optimisation and unit monitoring. Confidence and trust in a simulator are usually gained by running simulations against measured plant-performance data. But what happens when measurement and simulation do not align? Can we learn anything from such experiences? In the first installment of this two part article, two case studies are used as examples, each one initiated by disparity between simulation and plant data too large to be attributed to just modeling and measurement errors. Examples are defective equipment and contaminated solvents. In the second part of this article, poor temperature control, and a problem with the model itself will be discussed. Each case compares simulation results with measured performance metrics, and each one uses a combination of data and simulation to deduce logically a diagnosis and to resolve the issue. In each case there is some gross deficiency either in a measured parameter, in the integrity of one or more pieces of equipment, in faulty or overly-simplistic thinking, or in the simulator itself.

Case study 1 Following an internals and solvent change out, a pair of fuel gas treaters in a US West Coast reﬁnery were unable to reach the treated gas H2S level that the simulator they were using (modiﬁed ideal stages) said should be achieved. The sulfur emissions from the units were on the cusp of exceeding the permit limit, meaning that corrective action was imperative. A consultant was approached for advice. Because the two treaters are so similar, this article will focus on only one of them.

The treater originally used trays to treat the gas using diethanolamine (DEA) which resulted in gas comfortably below 4 ppmv H2S. To improve throughput, trays were replaced with random packing (#2 Minirings) which lowered pressure drop and increased tower capacity. To take advantage of its lower required energy for solvent regeneration, N-methyldiethanolamine (MDEA) was substituted for DEA. Simulation of post-change-out conditions showed that both treaters were capable of producing treated gas below 1 ppmv of H2S. However, performance tests after the revamp showed the treater was actually achieving only 26 ppmv H2S – far higher than expected – and contributing to the plant now pushing emissions limits. The consultant surmised that the liquid residence time on the packing was not nearly long enough to achieve treat, and he made the recommendation to put the original 17 trays back into the column. When the switch back was made, a repeat of the performance test surprisingly showed that column performance was unchanged – it was still producing 26 ppmv H2S in the treated gas. The reason this happened is explained below. When the trayed and packed cases were run in Optimized Gas Treating’s (OMT) ProTreat® mass transfer rate-based simulator using MDEA, the predicted H2S content of the treated gas for both internals types was calculated to be 0.64 ppmv, but the measured value was a factor of 40 higher. This is too large to be anything other than an error either in the basic data fed to the model or in the model itself. What turned out to have been overlooked was the real solvent analysis, i.e. incomplete data was used in the model. It was not realised that heat stable salts (HSS) have a profound effect on treating, primarily by affecting vapour-liquid HYDROCARBON 45

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equilibrium over the lean solvent. In this case, it happened that the 38 wt% MDEA solvent contained 2.2 wt% heat stable salts (230 ppmw sulfate; 2580 ppmw acetate; 3225 ppmw thiocyanate; 14 305 ppmw formate; 1675 ppmw chloride). These levels of HSS are fairly typical of amine solvents in refinery environments, a fact that should be kept in mind when trying to resolve amine treating problems in refineries. When the simulation was rerun with the measured HSS levels (how the HSSs actually break down into individual salts matters), the ProTreat simulation produced a treated gas with 26 ppmv H2S, in perfect agreement with measured data. This is an example of faulty, simplistic thinking combined with a lack of understanding of the process chemistry which resulted in presenting the model with incomplete data. In ignorance, the faulty assumption was made that HSS had no influence on the process, and was therefore ignored. The lesson from this example is that solvent contaminants can make a huge difference to both a simulation and to real performance. Ignoring this resulted in considerable lost profit and wasted time performing multiple, expensive revamps to solve a problem that, in reality, had a completely different, unrelated cause.

Case study 2 In this case, a leaking heat exchanger caused simulations to produce wildly different predictions from what was being measured in the plant. The simulator was not wrong; it was just being applied when assumptions about equipment integrity were violated. A great use for a simulator is to point out defective equipment (including flow meters). A refinery amine unit came out of a turnaround six months prior, and its performance was deteriorating. Revamp work in the turnaround included: The switching of sieve trays to valve trays in the amine regenerator for increased capacity. The increase of H2S to the system by approximately 20 tpd, leading to reboiler duty being increased from 77 to 85 million Btu/hr, the limit of the system. The increase of the DEA solvent strength from 25 wt% to 30 wt% to handle the additional sulfur load. Pertinent observations made over the time since the turnaround include: The H2S lean loading measured immediately following the turnaround (0.006 mol/mol measured) was higher than prior to the shutdown (0.001 – 0.003 mol/mol), and it had been increasing steadily ever since. It was currently at 0.012 mol/mol (4 – 12 times the pre-turnaround value). Several operators felt the new trays were already fouled. The tray supplier claimed the trays were functioning properly and noted that valve trays are slightly less efficient than sieve trays, the price that must be paid for increased hydraulic capacity. When a plant first runs into trouble, the engineers and unit operators usually come up with a host of explanations. Speculation runs rampant and almost everyone has their own theory. But troubleshooting must be based on data, not speculation. During the turnaround, no changes were made to the absorber, although changed absorber performance is what May 2021 46 HYDROCARBON ENGINEERING

flagged the problem; however, regenerator trays were changed from sieve to valve type. It is OGT’s experience that crossflow tray type is important in determining hydraulic performance, but it does not play a great part in deciding treating performance. The most significant observation was the 4 – 10 times increase in lean solvent H2S loading. ProTreat simulator modeling immediately following the turnaround gave an H2S lean loading of 0.0074 mol/mol. When the pre-turnaround conditions were substituted in the simulation, the simulated lean loading dropped from 0.0074 to 0.0052 mol/mol. This compared more favourably with the measurements just before the turnaround of 0.003 mol/mol, and is only 0.0014 higher than the post-turnaround value. Both simulations agreed well with other measured performance parameters (e.g. flow rates and temperatures). However, the simulated post-turnaround lean loading of 0.0074 is far lower than the presently measured value of 0.012. Thus, simulation was close to both pre- and immediate post-turnaround measured data but far from the present value. Simulation results return to a fairly close alignment with immediate post-turnaround observations, meaning that the increase in lean loading to 0.012 mol/mol is probably not the result of any of the changes made during the turnaround. Something else must have been happening after the turnaround to explain the source of the extra H2S loading. The root cause analysis (RCA) team investigating this problem inquired about the maintenance history during the turnaround and learned a key piece of information. After unit cleaning and inspection, the turnaround crew had plugged several leaking tubes in almost every heat exchange bundle in the amine circuit. The only explanation left was a lean/rich heat exchanger leak. Subsequent sampling of the lean amine on both sides of the exchanger confirmed this diagnosis. The plant was fortunate that tie-in valves were already in place to allow a spare lean/rich exchanger bundle to be tied in while the plant continued to operate. New 316 stainless bundles were installed while a temporary spare exchanger was placed into service, and a costly shutdown was avoided.

Summary Without simulation, a defect can hide and go uncorrected for a long time. What is worse, using a less-than-rigorous simulator with tuning parameters buried within it can lead to some fruitless and costly adjustments to operating conditions, hardware replacements, misdiagnosis of the true problem, or the resigned acceptance of reduced processing rates and lost revenue. Troubleshooting is not always as straightforward as the examples here, but it can be made a lot easier when a reliable simulator is used to assess the validity of measured data. It is almost always important in assessing lean loadings to account for the HSS levels, simply because HSS levels can account for the lean loading value itself. In sweetening to low residual acid gas levels, solvent lean loading can determine the treat actually achieved. With a reliable simulator, it is almost always possible to pinpoint the cause(s) of poor performance as the simulator will show what the plant, as-speciﬁed, should be doing. It is up to the engineer to use the simulator thoughtfully to ﬁgure out why expectations are not being met.

Nabil Abu-Khader, Compressor Controls Corp., UAE, discusses the operation of a two-shaft gas turbine-driven centrifugal compressor with hot and cold recycle lines.

he usual objective of a gas turbine (GT) fuel controller is to vary the fuel ﬂow as needed to maintain the desired power turbine speed regardless of load or fuel quality variations. In some applications, that speed set point (SP) is held constant, but it is more commonly varied to achieve a cascade control objective. Compressor Controls Corp. (CCC) has developed various application software solutions called ‘control applications’ (or just ‘controllers’) to drive, protect, and sequence the entire GT train. This article will demonstrate how a two-shaft GT drives a centrifugal compressor having two recycle lines (hot and cold). It will also show how the train reacts when exceeding design boundaries including centrifugal compressor surge.

GT integrated control system For a GT-driven compressor, the control system would combine logic controller (LC), speed indicating controller (here ‘fuel’ or ‘GT controller’ [SIC]), performance indicating controller (PIC/PF), and user-deﬁned indicating controller (here ‘antisurge’ [UIC/AS]) control applications. ‘S’ antisurge for cold recycle (SUIC/SAS) control application can also be added for cold recycle requirements. The SP for the GT controller would then be controlled by the

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PF control application in a cascade control scheme. The control applications would communicate among each other to provide integrated control and protection of the entire train.

Advanced GT closed-loop to power turbine speed (NPT) minimum governor After passing all start permissives, a two-shaft GT enters the startup sequence where it passes through two phases: Open-loop control: during the initial phase of a startup, the fuel demand is calculated using open-loop control techniques. This phase typically consists of ignition, flameproof, fuel control valve (FCV) warmup and FCV ramp sub-phases. Closed-loop control: after the open-loop control phase, the GT applies closed-loop control to ramp up high-pressure rotor speed (NHP) and then NPT. This phase

Figure 1. Train in shutdown.

Figure 2. Train start.

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depends on the startup goal and typically consists of NHP warmup, NHP acceleration, NHP loading, NPT warmup, NPT control, and NPT loading sub-phases. The startup sequence quickly ramps the local SP through NHP and NPT pre-conﬁgured critical zones. This minimises the turbine’s operating time at these critical speeds. For a two-shaft GT, normally either NPT or NHP loop is selected as the main control loop PV, thus determining which process variable will be controlled when no limiting conditions exist. That loop then calculates a proportional integral derivative (PID) bidirectional response to deviations of its PV from a local or remote SP. The remaining loops operate as limiting control loops that protect the GT against excessive speeds such as NPT, pressures such as compressor discharge pressure (CDP), temperatures such as exhaust gas temperature (EGT), ﬂameout, critical speed operation, and axial compressor surge. If only one limiting loop is active, its PID response is selected. If multiple limits are exceeded, the GT controller selects the high limiting loop with the lowest or most-negative proportional plus derivative response and adds the lowest or most-negative differential integral from any active loop. For safe operation, limiting loops have more priority than the main PV control loop.

EGT limiting loop The EGT is the temperature at the GG (gas generator) discharge. In multi-shaft applications, EGT is also called T4 and the power turbine exhaust temperature is referred to as T6. While the combustion chamber temperature (T3) imposes a more direct limitation on the turbine’s power output than EGT does, the latter is frequently the only one of the two that is measured. The combustion temperature is then indirectly limited

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by variable EGT limits, in which case the EGT acronym is an implied reference to T3. Typically, the high-limiting threshold for EGT is deﬁned as a function of CDP. There is no provision for EGT low limiting. On the other side, the efﬁciency of the GT is also affected by T1; the more ambient the temperature is, the less turbine’s power output.

Cold recycle control A cold recycle loop serves to prevent heat buildup within a process. The most common process application for an SAS controller is to control the ﬂow through a cold recycle loop in a network of parallel compressors. However, there are other applications for SAS, including serving more than one compressor section simultaneously, and when sustained recycling is necessary. Therefore, it is often desirable to use this cold recycle loop ﬁrst where possible.

Figure 3. Compressor loading.

The additional cold recycle loop is typically controlled using an SAS control application, whereas the non-cooled (or hot) recycle loop is controlled by an AS controller. The AS controller calculates an ‘S’ value (the position of the compressor operating point [OP] relative to the surge control line [SCL]) for its compressor. The SAS controller receives that ‘S’ value and calculates a corresponding deviation. By setting the deviation SP within the SAS controller, the operator can control which recycle loop (hot or cold) will react first to protect the compressor from a surge condition: When the SAS deviation SP is given a value greater than zero, the SAS valve will begin to open before the AS valve. This is the typical setting except in the case of rapid or large disturbances. When the SAS deviation SP is given a value less than zero, the SAS valve will begin to open after the AS valve. When the SAS deviation SP is given a value equal to zero, both AS and SAS valves will begin to open at the same time. Like in the AS controller, an RTL is also configured within the SAS controller, relative to the deviation SP. The RTL(SAS) will move with any changes made to the deviation SP within the SAS controller. For a well-tuned control system, using the cold recycle loop should provide enough flow to prevent surge, reducing the need for the AS controller to open its hot recycle valve. At the same time, the hot recycle loop is still required, especially during large process disturbances.

Simulation demonstration

Figure 4. Cold recycle loop.

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The process to be simulated is a gas-pumping station comprised of a two-shaft GT driving a process centrifugal compressor, as shown in Figure 1. The compressor includes two recycle loops: one upstream of the discharge cooler (the hot loop), controlled by an AS controller, and one

downstream of the cooler (the cold loop), controlled by an SAS ﬂow to protect the compressor from surge, with no action controller. The PF is set up to send its output as a remote SP to from AS1 control valve (CV-106) as shown in Figure 4. After the GT controller. The LC was custom designed to sequence the stability, the OP of the compressor settles on SCL(SAS) at a GT startup, pressurise the gas compression station, and purge deviation of the OP from the SCL (DEV) of 0.100. the compressor before it goes online with the process. Figure 5 shows a hot recycle loop: imagine that the load Figure 1 shows a train start. Initially the GT controller is in valve is opened back to 75%, stability is waited for, and the ‘shutdown’ and ‘local’, PF1 is in ‘tracking’, AS1 is in ‘shutdown’ deviation SP on the SAS1 controller is then set to -0.100. This and SAS1 is in ‘purge’. The GT controller must be ‘reset’ before will place the SCL(SAS) to the left of SCL(AS). If the load valve the turbine can be started. After ‘reset’ is inserted, and after is closed by 30% (from 75 to 45%) to induce another surge passing all start permissives, the GT controller will change its protection response, the AS1 control valve (CV-106) will open state from ‘shutdown’ to ‘ready to run’. The turbine can then and sustain a recycle ﬂow to protect the compressor from be started by initiating a ‘start’ command. Once started, the surge, with no action from SAS1 control valve (CV-107) as train will reach the minimum governor speed (start goal) of shown in Figure 5. After stability, the OP of the compressor 4525 rpm NPT as shown in Figure 2. settles on SCL(AS) at a DEV of 0.000. In this train, the turbine can be started and run on either During closed-loop control, imagine the load valve is gaseous or liquid fuel. Only all-gas or all-liquid (100%) settings opened back to 75% and the deviation SP adjusted in the SAS1 are possible for startup. Initially the selection is set to ‘gas’ via controller to 0.100 again. If the knockout drum SP is reduced ZT-FCV (position transmitter-fuel control valve). With the to 620 psig, the speed of the GT will reduce due to the compressor loaded and stable, it can be switched to ‘liquid’ cascade control from PF1 to satisfy the new process via ZT-FCVL (position transmitter-fuel control valve liquid). requirements. During closed-loop control: The GT controller will manipulate the selected FCV using Figure 3 shows compressor loading. The compressor can PID control to satisfy the remote SP received from PF1. be loaded by asserting the ‘load’ command and allowing the The train’s speed is maintained between minimum turbine to reach stability at a knockout drum pressure of (4525 rpm) and maximum (6500 rpm) NPT governor speeds. 660 psig. Putting the GT controller in ‘remote’ will enable the PF1 controller to send its output to the GT controller as a remote SP. Both AS1 and SAS1 controllers will start closing their recycle valves, as shown in Figure 3. If the GT controller is not in ‘remote’, the compressor will load at the minimum governor speed (4525 rpm). If in ‘remote’, the PF1 controller will send its output as a remote SP to the GT controller. This results in an increasing speed as the PF1 controller achieves a knockout drum Figure 5. Hot recycle loop. pressure SP of 660 psig. Figure 4 shows a cold recycle loop. Imagine that the deviation SP in the SAS1 controller is set to 0.100, and the load valve is closed by 30% (from 75 to 45%) to induce a surge protection response from the controllers. Note that SAS1 control Figure 6. The reaction to the driven centrifugal compressor surge and the train stability valve (CV-107) opens after centrifugal compressor surge. and sustains a recycle HYDROCARBON 51

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Figure 6 shows the reaction to the driven centrifugal compressor surge. Imagine a centrifugal compressor surge event is induced by closing the load valve from 75% to 10% (increasing the process resistance) as shown in Figure 6. The SAS1 control valve will open ﬁrst based on its PI and then recycle trip (RT) tunings, as shown in the pink trend, followed by AS1 control valve (PI and RT actions too), as shown in the red trend, to protect the compressor from another surge event. Figure 6 also shows train stability after centrifugal compressor surge. The train stabilised after one surge cycle on SCL(SAS) as shown in Figure 7. Knockout drum pressure is maintained at 620 psig with SAS control valve open only. AS1 control valve closed automatically since the DEV is positive. The operator would typically rectify the load valve and then reset the surge count to eliminate recycling.

Figure 8 shows EGT limiting. Typically, the average EGT is calculated by the GT controller, then it is used as the EGT PV. Imagine that everything is returned to normal by setting the load valve position at 75%, and the knockout drum SP is then increased from 620 psig to 720 psig (via PF-1). EGT limiting at 1200°F will be activated, preventing the train from increasing its speed further as shown in Figure 8. Process requirement cannot be maintained due to EGT limiting loop taking control of ZT-FCV. Since the GT controller is in limit, the PF1 controller is in ‘tracking’. This mode of operation implies the unit is running ‘ﬂat-out, full power’. To safely stop the train, we can ﬁrst ‘unload’ the compressor, put the GT controller in ‘local’, and then give the ‘stop’ command to the GT controller. The stop sequence shuts the GT down gradually. Typically, the selected SP (either the cooldown or the minimum governor speed) is then held constant until the cooldown timer expires, thus allowing the turbine to cool down, then closes the FCV completely, as shown in Figure 1.

Summary

Figure 7. Train stability.

Various loops govern the operation of the GT. In order to achieve integrated control of a GT-driven rotating equipment train, various CCC controllers were developed. A well-tuned GT-driven centrifugal compressor train should absorb upsets, changes in the process conditions, as well as load demand requirements. At the same time, the control system should be designed to apply various limit loops to protect the train. Other application-speciﬁc features such as overspeed protection, ﬂameout and over-fuelling protection, and fallback strategies can be applied as needed.

Reference Figure 8. EGT limiting.

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1. Compressor Controls Corporation; UM5525, UM6414, UM6421 Reference Manuals, (March 2019).

Hydrocarbon Engineering talks to some of the catalyst industry’s foremost experts, who share their insights on the latest developments in the downstream catalyst and precious metals market. Dr Detlef Ruff, Senior Vice President, Process Catalyst, BASF Dr Detlef Ruff joined BASF in 1995 as a Research and Development Chemist. In his career at BASF, spanning more than two decades, Dr Ruff has held various positions in operations, planning, strategy, marketing and business with increasing responsibilities. He served as Executive Assistant to the Chairman of the Board of BASF from 2001 to 2003, followed by a ﬁve-year delegation to Singapore as a Regional Marketing Director for Agricultural Products. Back in Ludwigshafen, Germany, Dr Ruff served as Vice President Global Strategy and Product Development for the Dispersions and Pigments business. In 2013, he took over global responsibility for the Process Catalysts and Technologies business at BASF Corp. in Iselin, New Jersey, US, as Senior Vice President. He currently serves as Senior Vice President, Process Catalysts, at BASF SE in Ludwigshafen and as Chairman of the Supervisory Board of BASF Catalysts GmbH, Hannover, Germany.

Lars Skyum, Senior Vice President, Clean Fuels and Chemicals Catalysts, Haldor Topsoe A/S Lars Skyum has been working for Haldor Topsoe since 1995. In this time he has worked in the catalyst business, where he has had various positions in technical service, sales and strategic marketing. In 2012 he was appointed Vice President for hydprocesssing catalysts, and since 2020 he worked as Senior Vice President, Clean Fuels and Chemicals Catalysts, being responsible for Topsoe’s hydroprocessing and syngas catalyst business.

Rajesh Gattupalli, Vice President and General Manager (VPGM), Honeywell UOP Rajesh Gattupalli is VPGM for Petrochemicals in UOP’s Lifecycle Solutions & Technologies business. He joined UOP in 2008, holding a number of roles in R&D, product line management and marketing. He most recently served as Senior Business Leader for alkylation technologies.

Dr Meritxell Vila, General Manager, MERYT Catalysts & Innovation Dr Meritxell Vila began her professional life working for Repsol at the Research Centre in Cartagena, Spain, studying ion exchange resin catalysts for the ETBE/MTBE synthesis. After spending several years on process development at the pilot plant units of the research centre, focusing on diesel hydrotreatment and gasoline hydrodesulfurisation, she moved to the Repsol Cartagena refinery to work at the quality control laboratory and the process department in the Lubricants and Hydrotreatment divisions. She was the Catalysts Coordinator of the refinery for several years, including the C-10 large project to double Cartagena refinery’s capacity. In 2011, Meritxell joined IMCD Spain, moving into chemicals distribution, where she worked as the Product and Project Manager, representing the major international catalyst and adsorbent manufacturers in the Spanish and Portuguese markets. In 2016, Meritxell started her own company, MERYT Catalysts & Innovation, to help customers to optimise their processes by reducing costs in catalysts, adsorbents, and chemical products. The company also develops innovative technologies to save energy and reduce emissions.

Bradford Cook, Vice President – Sales and Marketing, Sabin Metal Corp. Brad joined Sabin Metal Corp. in late 2012 and was named Vice President of Sales and Marketing in January 2015. He has over 35 years’ experience in the precious metals industry. Brad has been a member of the International Precious Metals Institute since 1999, has served on its Board since 2007, and was the President of the Institute for the 2012 – 2013 term. He has written numerous articles for industry publications and delivers presentations on precious metals around the world. HYDROCARBON 53

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Explain why catalysts are so crucial to refining and petrochemical operations. Rajesh Gattupalli, Honeywell UOP The introduction of catalysis in 1933 changed refining by introducing a new capability to processes that had been governed only by pressure, temperature and time. Catalysts made it possible to break and rearrange molecular bonds to produce specific products. Since that time, catalysts have been made more efficient and selective. Just by coming into contact with a catalyst, hydrocarbons can break apart, combine, and rearrange themselves into different molecules. New catalysts rely on the invention of new materials to provide greater activity, reliability and durability.

Dr Meritxell Vila, MERYT Catalysts & Innovation Catalysts are crucial, not only in refining and petrochemical operations, but also in around 90% of all chemical processes. Thanks to the fact that they decrease the activation energy of the chemical reactions, increasing their velocity, we can carry out the desired reactions under milder operation conditions. Therefore, thanks to them, we can perform our desired reactions at lower temperature and pressure and we can obtain our products in less time. Consequently, we can consider catalysts as the biggest energy savers in the industry. Therefore, catalysts are our best allies to maximise the profitability of our processes, because any improvement in the catalytic system (the catalyst together with the reactor design) has a direct impact on the yields, selectivity and the energy consumption of the reactions.

What are the main applications of your company’s catalysts or catalyst technologies within the downstream sector? Dr Detlef Ruff, BASF The catalyst division of BASF has a broad portfolio of products and services to support the downstream refining and petrochemical sector, which includes FCC catalysts and additives, a core suite of petrochemical catalyst solutions and adsorbent solutions. The portfolio covers selective hydrogenation catalysts for applications from C2 to C5+ hydrocarbons, Aromatics/olefin saturation catalyst and products for de-aromatisation, alcohol production, guard beds (sulfur, Cl, F), gas processing (removal of Hg, mercaptans, C6=, BTX and water), amine catalyst and olefin purification. BASF also facilitates the scale up and production of customer-specific catalyst formulations to meet customer-tailored requirements. The refining industry continues to develop with dynamic technology changes influencing the productivity and needs in the industry. BASF remains an innovative long-term partner in the industry, meeting customers’ needs with excellent service, product innovation and technical refining expertise. Our goal is to be the partner of choice for refineries that energise the world.

Lars Skyum, Haldor Topsoe A/S Topsoe is a leading supplier of catalyst and licensed technologies used for renewable fuels, hydroprocessing, ammonia, methanol, and hydrogen technology. This includes blue and green offerings of all of these technologies. We also have catalyst and technologies available for removal of SOX, NOX and particulate matters from flue gasses, and catalysts for production of sulfuric acid. In the hydroprocessing space we can supply the entire portfolio of catalysts: grading material for pressure drop control and protection against bulk catalyst contamination, all types of hydrotreating catalysts used in the naphtha to resid range (straight-run as well as cracked feedstocks), naphtha and diesel selective hydrocracking catalysts, and diesel dewaxing catalysts. For the processing of renewable feedstocks, Topsoe, as a part of our licensed Hydoflex technology, developed a whole family of tailor-made grading, hydrodeoxygenation (HDO) and dewaxing catalysts. For refiners, we also supply all catalysts used for hydrogen production. Furthermore, we have catalysts for claus tail gas treatment, benzene saturation and other petrochemical catalysts. For methanol and ammonia plants, Topsoe is able to supply licensed technologies and all front-end and synthesis catalysts.

Rajesh Gattupalli, Honeywell UOP UOP catalysts are used in a wide range of applications – to treat or purify feedstocks in preparation for subsequent catalytic processes that crack or rearrange hydrocarbons into new and homogeneous forms. These catalysts produce intermediate feeds for fuels production, performance enhancing additives such as alkylate and MTBE, and aromatics and olefins and other chemicals that are the basis for plastic resins, films and fibres. They are also used in a wide range of emerging sustainable energy processes including renewable fuels, hydrogen production, and carbon capture technologies. May 2021 54 HYDROCARBON ENGINEERING

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Dr Meritxell Vila, MERYT Catalysts & Innovation At MERYT Catalysts & Innovation we provide a wide portfolio of catalysts and adsorbents for refineries and petrochemical processes. The catalytic processes that we cover are FCC, hydrocracking, hydrotreatment, catalytic reforming, syngas, isomerisation, hydrogenation, dehydrogenation and etherification. We also supply selective adsorbents for purification of the different refinery and petrochemical plants streams. Additionally, we provide selective catalytic reduction (SCR) technology for NOX emissions reduction in refinery and chemical plant furnaces.

To what extent has the downstream catalyst/precious metals market changed over the past five years? Dr Detlef Ruff, BASF Excluding 2020, the overall refining and petrochemical catalyst market has continued to grow in the past five years in particular, driven by rising standards of living, population growth, and increasing demand for petrochemical products. Regulations have continued to evolve which has provided new opportunities in the catalyst market to support achieving tighter fuels specifications (IMO requirements for sulfur, gasoline sulfur, and octane), air emissions requirements, improved sustainability through renewable fuels processing and to adjust yield slates in support of these and other refining objectives. Additionally, the market continues to see moves towards more integrated petrochemical complexes and a shift in growth to the Asia Pacific and Middle East regions. As the need to achieve higher fuel economy standards and a focus on controlling greenhouse gas emissions becomes more important in North America and Europe, we see new opportunities to introduce new catalytic solutions and to support customers as they optimise their refinery operations.

Rajesh Gattupalli, Honeywell UOP More development has occurred in the last five years than in the previous 20. Refiners today are looking for catalysts that support process intensification, with greater efficiency than existing catalysts and that can perform multiple chemical conversions in a single step. As a result, refiners can process more feedstock with fewer and smaller units, requiring less real estate, equipment and energy.

Brad Cook, Sabin Metal Corp. The biggest changes to the platinum group metals (PGM) market over the last five years have been price volatility, elevated interest rates for leasing PGM and the overall availability of high-purity forms of these metals. Over 85% of all palladium above ground on earth is in automotive catalytic convertors, along with a substantial amount of platinum and rhodium. Sabin is not involved in the recycling of autocat, but we do share a common problem with that industry: a growing amount of ‘contamination’ in the catalyst feed arriving for recycling. In the autocat recycling industry, the introduction of tungsten (W) and silicon carbide (SiC) into the convertors to achieve higher emission control standards many years ago has resulted in processing challenges for the recyclers now that those older cars and convertors are being scrapped. In the petroleum and petrochemical industry, the problem is carbon (C) and coke. In past years, the catalyst user performed a ‘pre-reclaim burn’ in situ to reduce carbon contained, but many clients now leave the carbon mitigation to the precious metals recyclers. These two issues (increasing SiC and W in automotive catalysts, and increasing C in alumina-based petroleum/petrochemical catalysts) have combined to create huge recycling backlogs, higher treatment costs, and bottlenecks in the both the availability of palladium and recovery streams of PGM overall.

How can catalyst technologies help companies meet the challenge of increasingly competitive conditions in the downstream sector? Rajesh Gattupalli, Honeywell UOP Because catalysts are integral to process technology, newer and more capable catalysts can significantly improve the economics of refineries and petrochemical plants with reduced energy and water consumption, producing fewer low-value byproducts, and accommodating a wider range of feedstocks. They also facilitate the production of more sophisticated products as demand patterns change. This affords refiners improved operating margins and slate flexibility so molecules can be directed to processes where they will generate the greatest value. This is most evident with catalysts that can be used in existing capital assets – essentially reprogramming a refinery to make new products without significant capital investments.

Dr Meritxell Vila, MERYT Catalysts & Innovation Catalysts play a key role in the production scheme. Depending on them, we can have longer cycle lengths, lower hydrogen consumption (in hydrotreatment units), more propylene production (in FCC units), more cracking and therefore May 2021 56 HYDROCARBON ENGINEERING

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more yield (in hydrocracking reactors), etc. Each process has its key variables to make it more profitable, meaning that there are a lot of variables to consider, including the price of the catalyst. In consequence, the selection of the right catalytic scheme for every one of our processes can increase our margin very importantly, improving our competitiveness. In the refining sector now more than ever, catalysts play this key role, as the margin is lower than years ago. Every small improvement matters.

How can catalyst technology help companies meet strict environmental regulations? Dr Detlef Ruff, BASF BASF’s catalyst technologies directly reduce the impact of SOX and NOX emissions in the FCC unit. BASF offers SCR catalyst for NOX reduction, and other products such as the low NOX CO Promoter for NOX reduction and SOX reduction additives, like EnviroSOx, to reduce regenerator SOX emissions. Additionally, as constraints or requirements develop in the operational or regulatory environment, new catalytic solutions are developed to meet the new requirements and to help refiners meet environmental requirements.

Lars Skyum, Haldor Topsoe A/S There are several environmental regulations for which there are catalyst-based solutions. Some are single-parameter specifications, such as caps on diesel sulfur content. Others comprise a broad set of requirements and incentives. An example is the renewable fuel standard (RFS) programme in the US, which aims to reduce greenhouse gas emissions. Meeting some regulations may provide a payback if catalyst technology is applied. By reducing required operational temperatures and pressures, catalysts reduce energy requirements while also reducing production of CO2, NOX, and SOX. Improved catalysts intensify these benefits while also extending catalyst cycle life. Catalytic hydrotreating and hydrocracking continue to lead the way in producing ultra-low sulfur diesel (ULSD) and low-sulfur gasoline from ever more difficult feedstocks. The most significant recent driver is the IMO 2020 rule, which lowered the allowable sulfur content of marine fuel oil from 3.5 wt% to 0.5 wt%. The same catalyst technologies are also used to convert a wide array of plant-derived oils and waste products into renewable fuels and chemicals. Haldor Topsoe is a successful licensor of renewable fuels technology for 100% renewable fuels production (grassroots and revamps) and for co-processing, with a total of more than 500 000 bpd of production capacity licensed. Catalytic mercaptan oxidation improves the sweetness of light fractions, such as LPG and naphtha, allowing them to meet product and pipeline specifications. SOX transfer additives decrease FCC SOX emissions by moving SOX from the regenerator to riser/reactor, where it is converted to H2S. The H2S is recovered and transported to a sulfur plant, where it is converted into elemental sulfur. Other catalytic processes, such as SNOX, reduce NOX and SOX in flue gases. Many catalytic processes contribute to meeting gasoline specifications by producing blend components with low benzene and low Reid vapour pressure (RVP). These include alkylation, isomerisation, and catalytic reforming. New alkylation processes employ ionic liquid or solid-state catalysts, which decrease utility requirements and reduce acid wastes. Looking into the future, we are striving to stay ahead of the curve – by exploring the boundaries of science, continuing to provide excellent products, to anticipate greenhouse gas regulations by decreasing NOX and CO2 emissions, and to further develop promising carbon emission reduction technologies.

Rajesh Gattupalli, Honeywell UOP Because catalysts are the heart of most refining processes, we’re developing new catalysts that provide more cost-effective, lower environmental impact ways for refiners to produce the next generation of cleaner-burning fuels. This involves measurement of ‘six efficiencies’ – the highest value use of carbon and hydrogen, the lowest emissions of CO2, the lowest requirements for utilities and water, and the highest return on capital. Catalyst systems with higher activity, stability and selectivity are critical to meeting these objectives.

Dr Meritxell Vila, MERYT Catalysts & Innovation Catalysts have been helping companies to meet environmental regulations since these started. For example, the MTBE catalyst was developed to substitute tetraethyl lead in the 1990s when lead was prohibited as an octane booster in gasolines. Hydrotreatment and hydrocracking catalysts help refineries to reduce sulfur content in different fuels and have improved its activity to the required environmental regulations. For example, in Europe during the 1990s, diesel was allowed to contain 2000 ppmw of sulfur, whereas currently it must contain less than 10 ppmw. This reduction has been possible thanks to an impressive improvement in catalyst technologies. Other examples include the production of biofuels, where it is necessary to hydrogenate vegetable oils and other types of difficult feeds. Other very helpful and necessary catalysts can be found at sulfur recovery units, as these catalysts allow refineries to meet the strict regulations of sulfur emissions at the stack. Catalysts can help us meet most of the strict environmental regulations. May 2021 58 HYDROCARBON ENGINEERING

New ultra-high activity TK-6001 HySwell™ catalyst for hydrocracking pretreatment and ULSD production

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How will catalytic solutions help advance the growth of hydrogen production? Lars Skyum, Haldor Topsoe A/S Topsoe has developed a number of new catalysts for hydrogen production focusing on improving the economics for hydrogen producers. Many hydrogen plants today are restricted by the minimum steam-to-carbon (S/C) ratio they can operate at due to the limitation of traditional iron chromium based high temperature shift (HTS) catalysts. By introducing the new SK-501 FlexTM HTS catalyst formulation, Topsoe has been able to remove this limitation and at the same time increase the catalyst activity level. For plants operating at maximum throughput, this means that a more flexible catalyst enables operation at a higher feed rate with a lower S/C ratio, which results in more hydrogen production from the plant. In other words, the SK-501 Flex is a non-CAPEX revamp for more hydrogen production. In addition to the increased S/C ratio flexibility, the new formulation of SK-501 Flex also puts an end to the health, safety, and environmental risks associated with handling and managing hexavalent chromium when compared to traditional HTS catalysts as it is 100% chromium free. Ultimately, there is no risks of exposure to hexavalent chromium during loading, operation, unloading, or final disposal of the catalyst.

Dr Meritxell Vila, MERYT Catalysts & Innovation Hydrogen production is absolutely linked with catalysts. There are several ways to produce hydrogen, but almost all of them are related to catalysts and/or adsorbents. The most traditional and established is the steam reforming of natural gas, naphtha, heavy fuel oil or coal. Although this is a mature technology, it is still the most economic one, and so we can expect it to be used for a long time, and any improvement in the catalysts involved will have a great impact in the process. Hydrogen is also obtained by electrolysis of water, and if the electricity comes from renewable sources, we obtain green hydrogen. In this process, we have many different electrocatalysts, currently based in noble metals. There is a lot of research in order to improve these technologies, ﬁnding alternative non-noble metal electrocatalysts, to make this process more proﬁtable. Other hydrogen catalytic production processes are photocatalysis (obtention of hydrogen from water and sunlight), reforming of ethanol and sugars and cellulose biomass processing. All of these processes are the subject of deep research to increase the production of hydrogen.

What has been your company’s biggest recent achievement or innovation in terms of catalytic solutions? Dr Detlef Ruff, BASF At BASF, innovation never stops as our customer needs are continuously evolving and new products, services and optimisation efforts are required to meet emerging economic needs, operation constraints, and regulatory requirements. The biggest achievement in the industry remains the ongoing innovation achievements and focus on continuously applying the new innovations to meet the market and speciﬁc customer needs. BASF Catalysts’ commitment to innovation and excellent technical service is in-tune with the ever-changing market and customer needs. The company continuously innovates and commercialises new products, supported by a global technical service group to ensure that BASF’s products and offerings deliver immediate value at individual customer sites. Innovation is a driving force that enables BASF’s customers to be more successful. BASF is pleased with our recent achievements in the past several years to deliver many groundbreaking new technologies (Valor®, Multiple Framework Topology, AIM, Improved Zeolite Y, Boron Based Technology) and products (FourtuneTM, Fourte®, ZEAL®, Altrium® and the application of Valor®) that have enabled customers to be more successful.

Lars Skyum, Haldor Topsoe A/S In the early 2000s, Topsoe discovered a new activity site in hydroprocessing catalysts: the brim site. With this finding, the company developed the BRIM® technology, as well as the HyBRIMTM and most recently a new HySwellTM technology. TK-6001 HySwellTM is a unique supported NiMo catalyst and the first catalyst prepared with the HySwell technology. Since it was launched in 2019, Topsoe has achieved more than 10 sales with several already installed and performing excellently. The TK-6001 HySwell has delivered up to an impressive 17°C improvement compared to the previous catalyst in a commercial unit. So far, only unsupported hydroprocessing catalysts are seen with such high activity. However, unsupported catalysts are very costly and cannot be regenerated. HySwell catalysts can be regenerated, and they utilise the active metals better, which drives down cost compared to bulk-metal catalyst formulations. This is clearly more sustainable, and also more efficient when targeting volume swell. May 2021 60 HYDROCARBON ENGINEERING

The ultra-high activity achieved with Topsoe’s HySwell catalyst preparation technology enables refiners to upgrade fossil oil fractions which cannot be upgraded using other catalysts. The benefits include much better utilisation of the world’s fossil energy resources, and HySwell produces even cleaner and less polluting gasoline, jet, and diesel fuels. Due to their high activity, HySwell catalysts will stay longer in service in any hydroprocessing unit. This means fewer production stops (and consequently significantly improved efficiency and profitability for the refiner), as well as reduced catalyst consumption, fewer operating resources, and less consumption of raw materials.

Brad Cook, Sabin Metal Corp. Sabin has been working very hard for the last several years on two capacity issues. Firstly, the addition of a third kiln unit for the thermal reduction process that reduces carbon/coke contamination, which is now complete, certified and in use. Secondly, our overall refinery expansion, which will allow Sabin to make more pure platinum and palladium faster than ever before. We expect to announce the increased refining capability later this year.

What is the most challenging project that you have encountered recently? Dr Detlef Ruff, BASF The challenges faced by the oil refining industry vary from region-to-region and from customer-to-customer, covering many diverse and often interconnected topics. Examples of the challenges to be faced every day in the refining and petrochemical industry include the impact of crude oil and refinery product pricing; how to sustain long-term profitability in uncertain market conditions; how to control operating expense; the impact of changing product specifications; how to improve agility and flexibility to adopt the latest FCC catalyst technologies; how to meet changing environmental regulations and future policy changes; and how to train the new generation of professionals. To be successful in this market, there is not one single most challenging project but a series of on-going difficult challenges which must be solved. The most difficult challenge is maintaining the continuous and balanced focus on all the

unique industry challenges to ensure all of our customers are successful in achieving their unique objectives with the solutions we provide. BASF’s focused commitment to partnership, service and innovative ﬂexible products are incredibly important to the success achieved by our customers and the reﬁning industry.

Lars Skyum, Haldor Topsoe A/S Topsoe is a licensor of many different process technologies in the refining and pretrochmical industries. Currently we are extremely busy with a very large number of renewable fuels projects in the US and EU. Half of these are grassroots projects and the other half are revamps of existing refining assets. In general, revamps are more complicated due to the fact that we have to reuse as much of the existing equipment as possible for the new purpose to miminise the required CAPEX, while maximising the capacity within the constraints of the existing equipment. We have recently revamped a hydrocracking unit from fossil service to 100% renewable fuels service. In addition to the engineering skill set required for the reconfiguration, we had an added constraint – a 9 months time schedule from project kick-off to production of renewable fuels. It was quite challenging to do the required unit review, engineering, reconfiguration and procurement of the necessary new equipment, including reactor internals and catalyst to meet this very tight timeline. With an innovative project engineering execution strategy together with the EPC, we will be able to meet this timeline. The project will start up in the summer of 2021.

How has the COVID-19 pandemic affected the downstream catalyst industry? Rajesh Gattupalli, Honeywell UOP The industry encountered the steepest and fastest decline in demand for transportation fuels in history last year. This lowered production of jet fuel and gasoline, and lowered economic activity even affected diesel used for commercial transportation. Demand for petrochemicals also fell slightly. As a result, reﬁneries dialed down production and even shuttered some production, delaying some catalyst turnarounds. But demand for new catalyst designs remains strong, and as fuel demand continues to climb this year, turnarounds are rising as well.

Lars Skyum, Haldor Topsoe A/S When the catalyst industry entered 2020, we came from a situation where the demand for hydroprocessing catalyst had increased year over year for a period of 2.5 years. As a result of the increasing demand, lead times were relatively long at the end of 2019, and our customers had therefore placed orders well in advance with delivery in 2020. With the breakout of COVID-19, some customers had problems maintaining their planned turnaround activities due to restricted mobility of personnel, and at these sites catalyst suppliers were asked to delay the shipments if possible. Soon, the global demand for fuels decreased, and as the refineries operated at lower utilisation rates, the catalyst life time was extended, resulting in lower demand and shorter lead times. A few refineries have even been forced to shut down, and in these cases shipments were not only delayed but cancelled. Now, 1.5 years after the first cases in China, the demand is slowly returning, especially in China and the US, whereas European customers are still moving some planned replacement from 2021 to 2022. From a production point of view, Topsoe has been able to produce consistently despite COVID-19. We have been careful in preventing COVID-19 cases at our factories, and with good planning we have not had any issues securing raw materials. Despite the difficult situation, we have therefore not had any supply issues.

What does the future hold for the catalyst/precious metals market? Dr Detlef Ruff, BASF Catalysts are critical in the process of converting petroleum from crude and other feedstocks to refined products such as gasoline, diesel and petrochemical feedstocks such as naphtha and olefins. The demand for catalysts over the coming 5+ years is expected to grow in response to the recovery following COVID-19, the continued rising living standards, population growth and the increased integration of petrochemical production as part of refinery operations. The industry focus on becoming more sustainable is also leading to a growth in demand for cleaner petroleum products and is a factor driving the global refining catalyst market. The refining and petrochemical market must anticipate and respond to a wide range of customer needs. A few of the major challenges are summarised here: New and improved innovative catalyst designs to support the market shifts to cleaner fuels, use of alternative feedstocks and to meet the growing demand for petrochemicals. May 2021 62 HYDROCARBON ENGINEERING

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Optimised catalyst performance to drive economic improvement at the refinery or petrochemical complex. Increased focus on unlocking refining potential through catalyst optimisation to unleash changes to current constraints and operational optimisation to improve profitability with an increasing need to evaluate response time to changing requirements. Supporting global and regional sustainability initiatives while meeting environmental regulations. Supporting requirements to develop methods to reduce greenhouse gas emissions and CO2 reduction as new feedstocks are evaluated and used, such as biofeed, pyrolysis oils from plastics, and other alternative feedstocks.

Brad Cook, Sabin Metal Corp. I am very bullish on PGM. PGM comes from South Africa and Russia almost exclusively, the ore quality is deteriorating, it is getting more expensive to pull each ounce out of the ground, and demand isn’t going down. The metals we call ‘precious’ were originally given that title based on their beauty and workability as jewellery. This made these metals highly sought after, which in turn made them valuable. They’re still considered very valuable for these same reasons, but today there are much greater reasons to be mindful of PGM: Conservation (pollution control, wise management of natural resources): the automotive catalysts and the industrial filtration units that reduce emissions. Energy (both creating energy and improving performance): fuel cells, gasoline, jet fuels, even your spark plugs are platinum-tipped. World health (disease prevention and cure): treatments, medical devices and pharmaceutical products that contain PGM or are made using PGM. PGMs remain at the forefront, the absolute cutting edge, of all three of these crucial technologies. Sabin, along with our competitors, customers and partners around the world, need to continue to work together to develop strategies to overcome the issues I’ve mentioned here. A cooperative effort is the only way to ensure that these crucial metals remain sustainable, available, and cost-effective for continued use into the world of our grandchildren and beyond.

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Hydrocarbon Engineering - May 2021

Articles inside

Catalyst Q&A

Keeping a steady fl ow

Simulation in a world of trouble: part one

End-fl ash is totally cool

The key to competitiveness

Hot and cold recycle control

A clear plan of action

A new way to lower sulfur