Hydrocarbon Engineering July 2021 issue by PalladianPublications

July 2021

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CONTENTS July 2021 Volume 26 Number 07 ISSN 1468-9340

03 Comment

29 Advanced column internals for fouling towers

05 World news 10 It’s cool Gordon Cope, Contributing Editor, examines the profound challenges and adjustments facing Alaska and Canada as the demands and opportunities of the new decade gain momentum.

Ang Chew Peng and Lee Siang Hua, Sulzer Chemtech, Singapore, consider high-performance anti-fouling trays and packing that can help to minimise the accumulation of foulants in towers.

33 The ins and outs of corrosion studies Jim McVay, MISTRAS Group, USA, explains how corrosion studies can be used to determine potential damage mechanisms, corrosion types, and corrosion rate/potential to inform risk assessment and inspection planning.

38 Eco-friendly corrosion control Kai Zhang and Renate Ruitenberg, Nalco Water, an Ecolab Company, USA, discuss an innovative non-phosphorus and non-zinc mild steel corrosion control programme for cooling water systems.

43 Away with the salts Berthold Otzisk, Surjeet Kumar and Dr Michael Urschey, Kurita Europe, discuss ammonium salt removal management.

47 Embracing biology 14 Removing the ‘art’ from state-of-the-art Casey Metheral, IPCO Germany, outlines innovative solutions to a number of common issues faced by sulfur drum granulation operators and maintenance personnel.

19 SRU thermal stage revamps Karen Hanlon Kinsberg, Dimitri Travlos and Attila Racz, Worley Comprimo, discuss best practices for sulfur recovery unit thermal stage revamp design.

25 Mercaptan scavenging revisited Jonathan Wylde and Grahame Taylor, Clariant Oil Services, USA, examine the reaction of alkyl mercaptans with hydrogen sulﬁde scavengers.

Helma Hakala, VA TECH WABAG GmbH, introduces an innovative biological process for produced water treatment in Romania.

51 Vapour control options Anne Himmelberg, Aron Katz, and Victor Hoffman, John Zink Hamworthy Combustion, USA, assess vapour control options and introduce a suitable technology where vapour combustion technology is selected.

57 Expanding LNG options Enver Karakas and Stephen Ross, Elliott Group, USA, discuss how the use of cryogenic liquid expanders in gas liquefaction enhances plant efﬁciency.

61 Optimising LNG installations Vincent Higelin, Fives Cryomec AG, Switzerland, discusses two factors that should be considered while designing LNG installations with cryogenic pumps.

THIS MONTH'S FRONT COVER

IPCO introduces its latest drum granulation technology for the production of premium quality sulfur granules. The simple, yet advanced process is efficient and robust, while meeting the most demanding environmental regulations. The newest installation is now commissioned and operating in Italy, and IPCO invites customers to see its industry-leading drum technology in action.

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

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ack in May, Hydrocarbon Engineering hosted its second annual Refinery of the Future virtual conference, focusing on the latest developments, trends and innovations driving the future of the refining sector. The conference included a range of interesting presentations looking at topics including petrochemicals integration, digital transformation and site safety, as well as a reflection on a challenging year for the refining sector, courtesy of Wood Mackenzie. One of our keynote speakers at the conference was Lara Swett, the Vice President of Technical and Safety Programs at AFPM. Lara’s presentation looked at how the downstream sector became among the top safety performers in the manufacturing sector, and explored how AFPM members continually enhance safety at their facilities, whether through learning and development or pushing the envelope on technology use. The presentation was a fascinating insight into how the US refining and petrochemical sector has managed to achieve such an impressive safety record, and the role that emerging technologies and digital transformation will play as safety performance continues to improve. The AFPM’s focus on safety was also highlighted in a recent article that featured in Politco.1 The piece reflects on the shift in the industries’ approach to safety with the introduction of the ‘Advancing Process Safety’ (APS) programme. The data-driven programme – which was also discussed in detail by Lara Swett during her presentation at Refinery of the Future – focuses on collaboration and promoting knowledge sharing about safety incidents and good practices among many of the US’ refining and petrochemical companies. Jim Mahoney, who was the Executive Vice President of operations at Koch Industries at the time (and who also served as Chairman of the AFPM board from 2012 to 2014), explained: “We decided to come together as an industry back in 2010 and make a commitment to share information to reduce incidents. If we could share information, if we could learn from each other, then we could take our performance as an industry to another level.” The APS took a holistic look at process safety data from across the industries and analysed it in new ways. And rather than simply focusing on corporate safety leads, it brought together those workers responsible for on-the-ground safety at the plants to discuss common issues. This eventually shed light on the root causes of certain problems – including the fact that around one-third of workplace incidents were a result of human error – and provided clear data to support those findings. This information could then be used to identify solutions to the problems, and a number of sub-programmes have now been established to help companies continuously improve their safety performance. APS is considered a key driver behind a more than 50% reduction in incidents in the US’ refineries and petrochemical plants since 2011. And it provides clear evidence of the amazing results that can be achieved when our industry comes together and increases collaboration. Such a spirit of collaboration is always encouraged at Hydrocarbon Engineering. If you have a success story to tell, or an innovative solution to one of the problems facing our sector, we want to hear from you. Please get in touch using the contact information on the left of this page. 1.

‘Industry Collaboration Drives Incident Rates at Refineries and Petrochemical Plants to Record Lows’, Politico, (28 May 2021).

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WORLD NEWS Canada | Air

Products unveils plan for hydrogen complex

ir Products and its subsidiary Air Products Canada Ltd, in conjunction with the Government of Canada and the Province of Alberta, have announced a plan to build a landmark new net-zero hydrogen energy complex in Edmonton, Alberta. Air Products began work in 2018 on the core of this world-scale energy complex, which will begin with a transformative CA$1.3 billion net-zero hydrogen production and liquefaction facility expected onstream in 2024. The new facility will capture over 95% of the carbon dioxide (CO2) from

the feedstock natural gas and store it safely back underground. Hydrogen-fuelled electricity will offset the remaining 5% of emissions. The clean energy complex will help reﬁning and petrochemical customers served by the Air Products Heartland Hydrogen Pipeline to reduce their carbon intensity. The complex also marks a ﬁrst in the wider use of hydrogen in Alberta, enabling the production of liquid hydrogen to be an emissions-free fuel in the transportation sector, and to generate clean electricity.

Poland | PKN

ORLEN to invest in olefins complex expansion

KN ORLEN is investing in the expansion of the olefins complex at the Plock Production Plant in Poland. It is the key project in the strategic Petrochemical Development Programme and the largest petrochemical investment project in Europe in the last 20 years. The Olefins III Complex will be built using state-of-the-art technology to ensure greater energy efficiency, including a 30% reduction in CO2 emissions per t of product.

The project is scheduled for completion in 1Q24, and production is set to launch in early 2025. The oleﬁns complex will cover an area of almost 100 ha. The expansion is part of the ORLEN2030 strategy, which assumes that PKN ORLEN will achieve carbon neutrality by 2050. The company aims to reduce carbon emissions from its existing reﬁnery and petrochemical assets by 20% and cut down carbon emissions per megawatt-hour of electricity by 33% by 2030.

China | Vopak

awarded

contract for industrial terminal

uizhou QuanMei Petrochemical Terminal Co. Ltd has awarded Vopak a contract for storage and services of a liquid products terminal in China. The planned terminal would be constructed and operated as part of ExxonMobil’s proposed Huizhou chemical complex project. The contract award is subject to customary conditions, including closing of the transaction and obtaining regulatory approvals, whereby Vopak obtains an ownership interest in the terminal. This greenfield industrial terminal, located in Guangdong province, will serve a world-scale flexible feed steam cracker project to be constructed and operated by ExxonMobil (Huizhou) Chemical Co. Ltd (EMHCC). The project, which remains subject to final investment decision, is situated in Dayawan Petrochemical Industrial Park, which is one of the seven national petrochemical bases in China. Vopak will have ownership of 30% of the 560 000 m3 terminal, including the pipelines to connect the terminal to the jetty and EMHCC plant. Vopak will also provide services for the terminal and jetty through a separate wholly-owned Vopak entity.

France | Axens

and Sulzer Chemtech deliver advanced FCC naphtha processing solution

xens and Sulzer Chemtech (GTC Technology) have announced that they have formed an alliance to license an advanced process for ﬂuid catalytic cracking (FCC) naphtha processing. The companies have said that the combined offering is based on Axens’ Prime-G+® hydrodesulfurisation

technology and Sulzer Chemtech’s GT-BTX PluS® extraction technology. The combined solution can reduce octane loss to a very low level for the gasoline pool. The technology is especially important in countries that are upgrading fuel speciﬁcations to meet environmental requirements, and it can be applied

in new, or retrofits of existing units in operation to maximise profit. It also provides refiners the option of converting FCC gasoline into petrochemical products – BTX and additional propylene – and obtaining additional margin in regions where gasoline demand is not sufficient. HYDROCARBON

ENGINEERING

July 2021

WORLD NEWS DIARY DATES

wins services contract at Burnaby refinery

31 August - 2 September 2021

23rd Annual Aboveground Storage Tank Conference & Trade Show Orlando, Florida, USA www.NISTM.org

21 - 23 September 2021 Gastech Dubai, UAE gastechevent.com

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

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

04 - 06 October 2021 ILTA International Operating Conference & Trade Show Houston, Texas, USA ilta2021.ilta.org

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

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

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

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

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

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

July 2021

HYDROCARBON

ENGINEERING

Canada | Worley

orley has secured a services contract with Parkland Refining (B.C.) Ltd for its strategic projects at the Burnaby refinery in British Columbia, Canada. Under the contract, Worley will provide consulting, engineering, procurement, construction management and commissioning services to support the strategic projects at the Burnaby refinery.

This is in addition to the existing relationship supporting sustaining capital work at the facility. The services will be led by Worley’s Calgary office with support from Advisian, Comprimo®, Worley’s North American offices and Worley’s Global Integrated Delivery team. The term of the contract is five years.

USA | EIA:

growing global production limits crude oil price increases

n its June ‘Short-Term Energy Outlook’ (STEO), the US Energy Information Administration (EIA) forecasts that rising global production of petroleum and other liquid fuels (driven by OPEC, Russia, and the US) will limit price increases for global crude oil benchmarks Brent and West Texas Intermediate (WTI). The EIA forecasts production will increase more rapidly than consumption, ending the large global stock draws seen in the ﬁrst two quarters of 2021 and limiting upward crude oil price movement.

India | McDermott

Higher crude oil prices and planned OPEC+ production increases contribute to the forecast that global petroleum supply will increase over the next several months, resulting in an essentially balanced market in 2H21. The EIA expects petroleum inventories to build in 2022 as production outpaces consumption. Based on this global supply and demand forecast, the EIA expects the Brent crude oil price will average US$68/bbl in 3Q21. The price is then expected to fall to US$64/bbl in 4Q21 and decline further to average US$60/bbl in 2022.

wins EPCC contracts

cDermott International Ltd has received two separate engineering, procurement, construction and commissioning (EPCC) contract awards from Indian Oil Corp. Ltd (IOCL) for the Haldia Refinery and the Barauni Refinery. The first award is an EPCC contract for a new diesel hydrotreating unit and associated facilities for the Barauni Refinery Expansion Project in Bihar. The second award is an EPCC contract for

the catalytic dewaxing unit and associated facilities at the Haldia Refinery in West Bengal. The catalytic dewaxing unit will help produce base oil, which can be utilised in finished lubricants. India is the world’s third-largest user of finished lubricants but is also, with a deficit of base oil, one of the world’s largest importers of base oil. Both projects contribute to greater independence for India’s domestic energy needs.

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hile Alaska and Canada may be the northern frontiers of the continent, both have a long and storied history of oil and gas exploration and development. As the challenges and opportunities of the new decade gain momentum, the regions are undergoing profound changes and adjustments.

Alaska Thanks to the discovery of the 25 billion bbl reservoir at Prudhoe Bay in the late 1960s, the state was exporting up to 2 million bpd from the North Slope via the Trans Alaska pipeline system (TAPS) throughout the 1980s. While production has ebbed over the last several decades to just under 500 000 bpd, exciting new discoveries give hope to the 77 000 Alaskans (one quarter of the population) who work in the oil and gas sector: In early 2021, 88 Energy announced an oil discovery at its Merlin 1 exploration well in the National Petroleum Reserve-Alaska (NPRA). Based in initial information, the Australian-based company is projecting a potential 650 million bbl reserve. The target reservoir in the Nanushuk formation is at a depth of approximately 1800 m. Just north of the Merlin discovery, ConocoPhillips is planning on developing its Willow prospect, a 750 million bbl reservoir. The multi-billion dollar project is designed to produce 160 000 bpd, or 600 million bbl over 30 years, starting in the mid-2020s. July 2021 10 HYDROCARBON ENGINEERING

Recent drilling by Australia-based Oil Search has now increased reserves at its Pikka discover east of Merlin to 1 billion bbl, pushing the US$3 billion development closer to approval. Oil Search and partner Repsol plan to have the discovery online by 2026. Shell, which has an 81 000 acre lease in the shallow waters of the Beaufort Sea, received approval in late 2020 to explore the West Harrison Bay prospect, also located in the Nanushuk Formation. The plan calls for the drilling of two wells in the next five years. In late 2020, Hilcorp Energy ﬁnalised its US$5.6 billion acquisition of BP’s energy assets in Alaska. The deal included BP’s interest in the Prudhoe Bay ﬁeld and TAPS. In February 2021, the company requested approval to drill two oil and gas exploration wells at its Whiskey Gulch prospect, located approximately 200 km southwest of Anchorage, on the south shore of Cook Inlet. Hilcorp already has several onshore gas wells, serviced by the ENSTAR natural gas line that runs down the peninsula. In early 2021, the Alaska Gasline Development Corp. (AGDC) announced it was seeking federal funding to build a natural gas pipeline from the North Slope to Fairbanks. The US$5.9 billion line would run approximately 800 km to central Alaska. The proposed line is part of a larger US$38.7 billion Alaska LNG project that would include a 1300 km line with a capacity of 3.3 billion ft3/d to transport gas to an LNG facility in Nikiski on the Kenai Peninsula. The plan is an effort to

Gordon Cope, Contributing Editor, examines the profound challenges and adjustments facing Alaska and Canada as the demands and opportunities of the new decade gain momentum.

monetise over 26 trillion ft3 of stranded gas in the North Slope.

Canada In April 2021, Inter Pipeline, which is building the Heartland petrochemical project near Edmonton, announced several purchase contracts that will cover 60% of the plant’s output. The US$3.2 billion plant is designed to convert propane into 525 000 tpy of polypropylene when it begins operation in early 2022; the long-term contracts to seven Canadian and international buyers will cover approximately 315 000 tpy. The plant is being designed with the latest technology, and will have a greenhouse gas (GHG) emissions footprint 65% lower than the global average for similar petrochemical facilities. In April 2021, Calgary-based Nauticol Energy announced it was building a US$3 billion blue methanol plant in northern Alberta. “This will be the ﬁrst project at world scale that will be net zero, or blue methanol, which is really important,” noted Mark Tonner, President and Chief Executive Ofﬁcer. When the plant enters operation in 2025, it will produce up to 3.4 million tpy of methanol, to be shipped by rail to ports in British Columbia for transport to Singapore. The plant will require 250 million ft3/d of natural gas as feedstock; modules will capture 1 million tpy of pure CO2 for sequestration. In addition, electrical power for the plant will largely be supplied by a biomass utility plant adjacent to the site. Singapore-based Fortrec Chemicals & Petroleum, which supplies marine fuel, is a partner in the venture. “Singapore is one of the world’s largest

bunkering fuel centres so there’s a big role that methanol will play in helping to decarbonise and improve the air quality of shipping,” said Tonner. In late 2020, Alberta launched a new programme to attract petrochemical investments to the province. The Alberta Petrochemicals Incentive Program (APIP) offers a direct 12% grant on eligible capital costs. The province has approximately 223 trillion ft3 in natural gas reserves, and exports over 10 billion ft3/d to markets in Eastern Canada and the US. The programme is designed to attract value-added projects to the province; government officials estimate that it could generate up to CA$30 billion in investments by 2030. Construction on Shell Canada and partners’ LNG Canada is approximately 25% complete. The first phase of the US$30 billion project, situated in the Pacific port of Kitimat, British Columbia, will have two 6.5 million tpy trains; phase two will add two further trains, bringing the plant’s capacity to 26 million tpy. The project includes TC Energy’s Coastal GasLink pipeline that will deliver up to 2.1 billion ft3/d from northern British Columbia to the coast. TC Energy reported that recent COVID-19 related lockdowns are expected to raise the cost of the US$6.6 billion line, as well as delay commissioning. Canadian crude production and exports are on an upward trajectory. Oil output in Western Canada is expected to rise from 3.9 million bpd in 2020 to 4.45 million bpd by the end of 2021, primarily due to the oilsands. Mexican heavy crude exports have slowed, and Venezuelan exports are curtailed by US sanctions. Canada now exports around 3.8 million bpd to the HYDROCARBON 11

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July 2021

US (primarily the Midwest and USGC), which is expected to rise to 4.2 – 4.4 million bpd by 2026. Although the Keystone XL line is once again cancelled, expansions on the current system will add almost 1 million bpd capacity by 2025, and crude-by-rail capacity is continually growing. To counter the ‘dirty oil’ image, oilsands operators are continually working to reduce their carbon footprint. Cenovus, which has been operating its Foster Creek SAGD project for 20 years, has two different solvent pilots underway. One of the projects involves solvent-aided process, where propane displaces about 10% of the injected steam. Preliminary ﬁndings support a 30% reduction in the steam-to-oil-ratio (SOR), a measure of the efﬁciency of the lift process. CNRL has been experimenting with an In-Pit Extraction Process (IPEP) at its Horizon open pit mine. The company uses a portable modular extraction plant that can be positioned at the mine face, where it extracts bitumen and leaves only dry tailings. The process greatly reduces GHG emissions and water usage, and eliminates tailings ponds.

Challenges In addition to the cancelation of Keystone XL, crude producers in Canada face further pipeline complications. In late 2020, Michigan ordered Line 5 (which transports 540 000 bpd from Canada through the state to Ontario and Quebec) to shut down operations by 13 May, due to the potential for spills where it passes under the Straits of Mackinac in the Great Lakes. Pipeline operator Enbridge has sought legal relief, and the case is being heard in a US federal court. While the May deadline passed without closure, an eventual shutdown would affect refineries in Sarnia, Ontario, as well as millions of consumers in both Canada and the US. The Biden administration’s suspension of new leases on federal lands and waters threatens new discoveries in Alaska. Although exploration companies have a comprehensive catalogue of leases to keep them busy for most of the decade, if the suspension should turn into a permanent ban, then Alaska, which is primarily federal land, would find its future jeopardised. Along with 12 other states, Alaska filed a lawsuit to counter the White House suspension. “We fear that President Biden’s attack on federal oil and gas leasing has only begun, and the State must be involved to protect the interests of all Alaskans in the responsible development of the bountiful natural resources contained within Alaska,” said Governor Mike Dunleavy. The Biden administration also posted a temporary moratorium on new leases in the Arctic National Wildlife Refuge (ANWR). Federal agencies are also putting the brakes on the enclave that protects polar bears, caribou and endangered bird species. In early 2021, a proposed seismic survey of over 350 000 acres on the coastal plain of the ANWR was scuttled when the Department of the Interior ruled that the project lacked protection for polar bears. They noted that Kaktovik Inupiat Corp., an indigenous-owned company, failed to adequately identify polar bear dens in the region. The finding is another roadblock to the 2017 decision made by President Trump to allow exploration in the ANWR. Financing exploration in the region also became more difficult. In late 2020, Bank of America joined JP Morgan, Wells Fargo, Chase, Citigroup and Goldman Sachs by publicly announcing it would refuse lending for oil and gas exploration in July 2021 12 HYDROCARBON ENGINEERING

ANWR, although they continue to lend to fossil fuel development in other jurisdictions. The move (there are now approximately 50 ﬁnancial institutions worldwide with similar bans), drives up the cost of exploration, but major explorers have much better prospects (such as offshore South America), where costs and above-ground risks are lower. An ANWR lease sale held by the Bureau of Land Management (BLM) in the later days of Trump’s administration drew qualifying bids for only 11 tracts, most from an Alaska state agency acting as a backstop to the lease.

The future In early 2021, an alliance of government, indigenous, academic and economic developers announced CA$2.2 million in funds to develop a plan for the Edmonton Region Hydrogen HUB. The Edmonton region is already a major producer of hydrogen using steam reforming technology, primarily for upgrading crude. The money will be used to develop blue and green hydrogen projects, as well as the infrastructure to store and transport hydrogen to market in Western Canada. Green hydrogen also has great potential in Canada. It derives almost 60% of its electricity from hydro power, primarily in Quebec and British Columbia. Hydro-Quebec has commissioned Thyssenkrupp to build an 88 MW water electrolysis plant in Varennes, Quebec. When the plant enters service in 2023, it will generate over 11 000 tpy of green hydrogen, which will then be used to generate biofuels. A consortium is also looking at building a similar plant in British Columbia. The demand for lithium, a primary component of electric vehicle (EV) batteries, is expected to grow exponentially over the coming decade. However, commercial deposits are in limited supply and involve mining or evaporation processes that are environmentally damaging. However, brines from mature wells in Alberta contain high levels of lithium (over 70 mg/l), and companies are exploring means to economically harvest the metal in a clean manner. Calgary-based E3 Metals Corp. has a plan to produce 20 000 tpy of battery-grade lithium hydroxide using a direct lithium extraction (DLE) process involving highly-selective, ion-exchange technology. The US$600 million plant, located in central Alberta, would use renewable energy (either wind or geothermal) to make green lithium, re-injecting the spent brine in order to avoid freshwater contamination. E3 estimates that the average cost of producing lithium at its plant would be slightly over US$3600/t; the current retail price is in the range of US$12 000/t.

Conclusion The election of President Joe Biden in 2020 reversed the trend toward deregulation of the oil and gas sector in North America under the previous Trump administration. The White House has launched moratoriums on new leases on federal lands, which has the potential to signiﬁcantly impact Alaska. The cancellation of the Keystone XL pipeline and impediments toward existing lines carrying crude to the US could also disrupt Canada’s oil and gas sector. That said, explorers are continuing to discover new ﬁelds in Alaska and expanding production in the oilsands, guaranteeing that fossil fuels will continue to prosper as new forms of renewable fuel, including hydrogen, become a greater part of the energy mix.

July 2021 14 HYDROCARBON ENGINEERING

Casey Metheral, IPCO Germany, outlines innovative solutions to a number of common issues faced by sulfur drum granulation operators and maintenance personnel.

here are a number of nagging issues that have bothered sulfur drum granulation operators and maintenance personnel for decades. Operating a piece of industrial machinery should not be an ‘art’, even if the machinery is ‘state-of-the-art’. It should be straightforward and easy to understand. This article will explore the root causes of the common issues faced by operators and maintenance personnel, and outline strategies to correct or minimise each of the problems. IPCO’s latest drum granulation technology for the production of premium quality sulfur granules, the SG20, is now commissioned and operating (Figure 1). The technology is located at the site of a long-standing customer that operates multiple sulfur solidification facilities in Italy. The location provides easy access for customer visits while also providing a challenging climate that can push the operating limits of the machine under a wide range of ambient conditions. The new unit, which is a scaled-down version of the higher-capacity SG30 (up to 2000 tpd), is intended for forming at medium-range capacities (up to 800 tpd) while following the same operating principles of the larger model (Figure 2). It is a single-pass process, which means there is no need for screens or recycle conveyors to send sulfur through the drum multiple times. The sulfur seeds (the small starting point of every sulfur granule) are created externally from the drum, which simplifies the seed generation process and allows wider flexibility with the incoming liquid sulfur temperature. External seed generation also provides an innovative way to recycle the sulfur waste stream from the wet scrubbing system, which is further discussed in this article. The model is also skid mounted to reduce installation time and ensure a compact design.

Issue 1: sulfur build-ups It is no secret that older drum technologies require shutdowns every 12 to 24 hours to clean out various parts of the system to maintain steady operation. While there are examples where granulators have been run for extended periods, this results in a signiﬁcantly longer shutdown due to a more intense cleanout (Figure 3). After identifying the exact points in the system where sulfur build-ups occur, and studying each one, IPCO has HYDROCARBON 15

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July 2021

designed the system to minimise this issue. And while speciﬁc details cannot be shared in this article (due to the intellectual property involved), it is possible to operate the unit steady for a full week before requiring a shutdown to do a minor cleanout.

Issue 2: frozen and plugged sulfur nozzles/product quality Nozzles for spraying sulfur are an integral part of any drum granulation system. Considering that liquid sulfur needs to

be maintained within a specific range of temperatures (approximately 120 to 160°C), any ‘cold spots’ in the sulfur system have the potential to cause a problem. In previous technologies, sulfur spray nozzles on the sulfur header in the drum have always been cold spots because they extend outside of the steam-jacketing (Figure 4). If the liquid sulfur is not properly removed when the system is shut down, the sulfur will freeze inside the nozzle tip and prevent flow during the next start-up. Even if the spray nozzle is cleared of sulfur during a shutdown, but the system is down for an extended period, sulfur vapour from inside the header can condense and freeze in the nozzle tips and prevent a proper start-up. Fixing this requires an operator to manually clean out the nozzle or replace it before starting up the system. A single frozen nozzle can easily make the difference between premium granules and off-specification product. IPCO has removed this problem with the industry’s first heated sulfur spray nozzle, meaning that operators no longer need to consume time inside the drum rectifying frozen sulfur nozzles.

Issue 3: drum roller maintenance Granulation drums are large and heavy pieces of equipment that rotate on rollers (Figure 5). They are required to rotate for two reasons: to form curtains of falling sulfur granules in the drum, and to advance the granules from the inlet to the outlet. Other technologies will place the drum on an angle to use gravity to advance the granules, which creates high levels of stress on the rollers and alignment issues that require ongoing maintenance. IPCO granulators use a completely level drum with angled ﬂights to advance the product to the outlet, which prevents unnecessary wear and tear on the rollers, and no maintenance is required to keep the unit aligned.

Issue 4: dust emissions and scrubber waste Figure 1. IPCO SG20 in Italy.

Figure 2. Basic process flow diagram of IPCO SG.

July 2021 16 HYDROCARBON ENGINEERING

A drum granulator is essentially a large heat exchanger, converting a liquid into a solid. The inlet conditions directly impact the outlet conditions. Drum granulators use air and water to remove heat from sulfur to allow it to solidify. Air is pulled into the drum, water is evaporated into the air as the sulfur cools, and ﬁnally the air is discharged to the atmosphere. This air will contain sulfur dust that needs to be managed. Dust emissions handling in drum granulation has previously always involved trade-offs with only two options available, neither of which are attractive: Steam-jacketed cyclone – this technology melts the captured sulfur dust, creates sulfur vapour, and ultimately has high dust emissions. This creates major problems for operating in environmentally sensitive areas. It is also a very high consumer of steam as it heats up the air stream while melting the sulfur dust. Wet scrubber with dust collection system – this technology captures the sulfur

dust and creates a waste sludge (fine sulfur particles and water). This sludge needs to be further processed in some way. Traditionally, it is melted, filtered, and then fed back into the liquid sulfur supply system. While this is more complicated than the steam-jacketed cyclone, it allows for lower dust emissions. A new option has been invented to solve this problem. First, a wet scrubbing system was chosen so there would be no compromise on sulfur dust emissions. Then, the waste stream of the wet scrubber was directed into the external seed generation system. By injecting this waste stream directly back into the process, the captured dust is consumed as seed in the drum (Figure 2). This means that all the remaining trade-offs are avoided. This equates to zero extra work to operate and maintain sulfur melting/ﬁltering equipment, and lower energy consumption of the system.

Issue 5: H2S emissions

Sulfur that was originally produced from hydrocarbons inevitably contains some level of hydrogen sulﬁde (H2S) when it enters a sulfur forming facility. The drum granulation process involves spraying liquid sulfur through nozzles, which releases a portion of this H2S into the air stream. Depending on how much H2S is in the liquid sulfur supply and the facility’s stack emissions requirements, IPCO’s drum technology can be equipped with an H2S scrubbing system to meet any environmental regulations. This is exactly what has been done with the SG20 in Italy to meet the emissions requirements.

Figure 3. Major build-up (left) vs minor build-up (right) inside

ducting.

Figure 4. Unheated nozzles (left): sulfur can solidify. Heated nozzle (right): no solidification.

Issue 6: consistent operation Perhaps the biggest challenge operators face is understanding how to operate a drum under a countless number of scenarios (dry vs humid, day vs night, summer vs winter, low production rate vs high production rate). While it is possible to set a drum granulator with one set of parameters and let it run through the changing conditions, this system will not operate in an optimum condition. This will result in poorer product quality, wasted water, and build-ups that lead to shutdowns. Consistently producing high quality granules at the discharge of a drum relies on maintaining consistent conditions inside the drum. When the inlet conditions change (e.g. ambient temperature and humidity, liquid sulfur temperature and production rate), an operator must compensate for these changes by adjusting operating parameters. In the past, adjustment of operating parameters relied on a high level of knowledge

Figure 5. SG20 drum.

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ENGINEERING

July 2021

Figure 6. Operator guidance system. and operator experience to understand how the system reacts under varying conditions. Some of this knowledge would come from the drum supplier during initial commissioning of the unit. Typically, the supplier would help commission the equipment, and have the unit running smoothly before they left site. It would then be up to the operators to determine how to adjust parameters as the operating conditions changed. Unfortunately, this leaves many clients struggling to maintain the same product quality that was achieved during commissioning. Follow up visits from the supplier

are required and, little by little, the client may gain enough experience to run the unit on their own. Unfortunately, clients must often settle for lower quality product because they simply do not have the experience to run it as it was intended. IPCO has developed a process simulation that considers all the relevant process parameters and provides guidance on how to control the unit. This was accomplished by analysing an extensive collection of operating data from both the SG20 and SG30 to build a process simulation that can be applied to any operating conditions around the world. The result is an operator guidance system that removes the guesswork and allows clients to operate successfully and conﬁdently in any conditions (Figure 6). This takes the ‘art’ out of the operation, as it requires operators to simply follow the instructions provided.

Conclusion Historically, drum granulation has provided the highest quality sulfur product, but there have been trade-offs with the level of process complexity and stack emissions. The latest features incorporated into IPCO’s drum granulators resolve the biggest issues customers are facing. This ensures that all operators, regardless of experience level, have an environmentally friendly process that is simple and safe to operate, while producing the highest quality product.

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Karen Hanlon Kinsberg, Dimitri Travlos and Attila Racz, Worley Comprimo, discuss best practices for sulfur recovery unit thermal stage revamp design.

evamping or replacing the thermal stage of a sulfur recovery unit (SRU) is a common challenge faced by most facility operators, which requires a site-specific design analysis. Replacement could be considered as the thermal stage is a critical equipment cluster with a limited lifespan of typically 15 to 20 years, depending on the operating conditions to which they are exposed. The stage encompasses the main burner, thermal reactor, waste heat boiler (WHB), and the first condenser. Figure 1 shows a typical thermal stage block flow diagram. As facilities age, operators can see a corresponding increase in the frequency of chronic issues around the thermal stage. WHB tube leaks, ferrule damage and refractory lining deterioration, leading to patches on the shell, are common challenges. Separate from mechanical issues, there could be debottlenecking requirements within a plant that

warrant reviewing the thermal stage capacity. From a multitude of initiating events, facility operators are motivated to conduct a thorough review of the thermal stage performance. As each thermal stage has unique conﬁguration details and operating requirements, every evaluation should be handled on a case-by-case basis, with no ‘one-size ﬁts all’ solution. However, there are some common themes to be reviewed and considered to apply best practices in a thermal stage revamp design. The main areas of evaluation correspond to the key equipment items: the main burner, the thermal reactor with associated refractory lining and the WHB.

The main burner As burner technology has advanced in recent decades, one of the ﬁrst issues to consider is upgrading a low intensity burner to

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ENGINEERING

July 2021

Figure 1. SRU thermal stage. a high intensity model. Benefits of this change include improved mixing performance, which lowers the required residence time, better destruction efficiency for contaminants such as ammonia and aromatic compounds (benzene, toluene and xylene [BTX]), and the opportunity to debottleneck the SRU capacity with the addition of oxygen enrichment. Moving to higher levels of oxygen enrichment requires a new burner design with a dedicated oxygen port. These process improvements do come with mechanical layout impacts. High intensity burners are normally longer and may have a larger diameter than low intensity designs, requiring a change to the thermal reactor sizing and configuration. The plot space impact of a longer burner can be offset somewhat by reducing the length of the thermal reactor due to the lower residence time requirement afforded by the better mixing performance of high intensity designs. Additionally, if the current burner is a tangential design, moving to an axial burner arrangement (standard for high intensity) requires a different physical footprint for the overall thermal stage, depending on whether more length or a larger width are necessitated by the new equipment configuration. The demands placed on the burner have increased over the years, as the typical operating window has widened for most SRUs. Facilities can often require a whole spectrum of conditions: fuel gas firing during start-up and shutdown, 0 to 100% oxygen enrichment, 0 to 100% amine acid gas feed, and a range of sour water acid gas (SWAG) flows. To illustrate the increasing complexity: for 100% oxygen enrichment the design could require splitting some of the acid gas feed to the combustion air nozzle on the burner. This results in a more involved control and safeguarding system, and requires extra switching valves. These conditions go far beyond the demands of simple ‘air-only’ operation and typically warrant a customised burner design to meet this challenging range of scenarios. Computational fluid dynamics (CFD) modelling is typically provided by the burner vendor to predict the performance July 2021 20 HYDROCARBON ENGINEERING

of these customised designs. Therefore, it is vital to have solid collaboration with the burner vendor over the course of the engineering development to align between the project requirements and equipment capabilities.

The thermal reactor When evaluating the thermal reactor, key elements to consider are: Capacity and configuration. Engineered refractory design. Instrumentation for temperature measurement. Thermal reactor capacity in terms of residence time is important when reviewing the NH3 and BTX destruction efficiency. Both flame length and diameter must be accounted for in the configuration, especially in case a low intensity (jet style) burner is part of the revamp design, which have longer flame lengths. A robust engineered refractory design is critical, particularly when oxygen enrichment is part of the thermal stage design. Many units have experienced chronic refractory failures after switching to oxygen enrichment without upgrading the refractory. The higher process temperatures drive the need for higher refractory design temperatures. Current industry practice is a two-layer brick system for the thermal reactor lining. It is highly recommended to engage experienced refractory specialists to provide an engineered refractory design, including a thorough thermal analysis of the thermal stage. This is a multi-component system, where all the elements from the reactor lining, the weather shield and the WHB tubesheet protection (ferrules) must work together comprehensively for the best long-term reliability. The design of the refractory and weather shield system should ensure the following: Refractory lining to withstand the whole operating temperature range including start-up and shutdown conditions.

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Figure 2. Two stage double combustion retrofit. Control the thermal reactor shell metal temperature within a defined range to prevent high temperature sulfide corrosion or wet H2S/SO2 corrosion. Control the WHB tube and tubesheet temperature within a range to prevent the same corrosion conditions as above. In conjunction with the refractory design considerations, it is important to have proper procedures in place for start-up (warming up rate) and shutdown (adequate purging). Without adequate purging, sulfur compounds can remain behind the refractory lining and/or ferrules, causing corrosion following a unit cooldown. The temperature measurement in the thermal reactor takes specialised instrumentation and design considerations. Without oxygen enrichment, temperature measurement is merely informative with a straight through configuration, except at start-up. But with split flow (or fuel gas co-firing), it is an actual (manual) control tool. With oxygen enrichment, temperature measurement is required for both control and safeguarding. Pyrometers should be installed free draining, looking at the opposing wall (however, if there is an option to measure gas temperature, that is valuable secondary information as it detects changes sooner). As pyrometers tend to drift, they require regular recalibration to continue providing reliable data. Thermocouples with ceramic sleeves are now available, which last longer if installed correctly (i.e. in the spot with least refractory movement and the hole drilled exactly right). With an inert purge, they do not corrode, but they can still break. Alternatively, there are also thermocouples now available which are embedded in a gas tight sapphire protection tube. This design has an integrated silicon carbide well and does not require an inert purge. They are promoted as being ideal for revamp applications due to their simplified installation. So, depending on the situation, the temperature measurement requirements and possibilities need to be determined. During revamps, it is possible to overlook what is working well within a unit. Specifically, if the plant is seeing stable and reliable temperature measurement, it is important to minimise the impact on that existing instrumentation and configuration. This is an operational aspect worth preserving for the post-revamp. A balance must be struck between the requirements for replacing ageing equipment with improved technology and maintaining the existing dependable elements. July 2021 22 HYDROCARBON ENGINEERING

The waste heat boiler The WHB is a very specialised heat exchanger and its design warrants careful evaluation. The constraints of the existing plot plan and equipment layout also require consideration when proposing changes in the WHB configuration. The progress towards higher levels of steam generation has also impacted the criticality of a robust design. In general, at higher operating pressures and temperatures, the margin for error in the mechanical reliability is much smaller. Kettle type exchangers have been applied widely in the industry. Thermosyphon type exchangers with a separate elevated steam drum can achieve higher water side circulation rates and, all other things being equal, are therefore capable of handling higher heat fluxes. In revamp situations this becomes an important factor as higher operating capacities and higher operating temperatures associated with oxygen enrichment result in higher heat fluxes. Traditionally, WHBs are designed with a thin (<30 mm) flexible tubesheet to limit the temperature gradient over the tubesheet. This ensures the hot face temperature remains below the design limits for carbon steel with respect to high temperature H2S corrosion. Generating steam at higher pressure levels requires more thickness for strength and this limits the diameter for a kettle type exchanger, which by design has a large unstayed area above the tube bundle. Traditionally, WHBs have been designed using limitations with respect to overall heat flux and/or mass velocity. These criteria do not account for configuration details of the bundle and refractory, nor for steam or process gas operating conditions. Therefore, relying on generic criteria alone risks either replacing a WHB unnecessarily or, worse, overwhelming the boiler, resulting in a failure. CFD analysis of both water and process side have been utilised to better predict boiler capabilities, which is time consuming and needs highly specialised knowledge to provide the correct input data. Comprimo has developed a tool, based on finite element analysis, which can help to determine if the design is nearing its limits and if further evaluation is required. If the boiler needs to be replaced and more surface area needs to be installed, this is typically achieved by increasing the tube count. This increases the overall diameter of the tube bundle and may exceed existing space constraints. It is possible to consider using smaller tubes (both in terms of tube diameter and pitch), as this will offer more surface area in a fixed tube bundle volume. However, this comes at the cost of the

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Figure 3. Double combustion with two-pass WHB – reduced plot space. additional process side pressure drop. Moreover, bundle configuration does affect the maximum allowable (critical) heat flux of the exchanger, above which vapour locking may occur, particularly at the front end of the tube bundle. For facilities with a congested layout or in case of modular unit layouts, space for growth could be limited. For facilities with more spacious layouts, as is often the case in North America, height restrictions are not normally a concern. Therefore, switching to a thermosyphon design with separate steam drum would allow bigger bundles to be suitable. The range of expected process gas outlet temperatures from the WHB is another issue. If the temperature is hot enough (higher than 320°C), the carbon steel outlet piping will require refractory lining to the first condenser inlet nozzle. This could impact the unit hydraulics and the total scope of the revamp project. Alternatively, the outlet piping could be stainless steel to avoid the need for refractory lining.

requirements as well as to limit the weight increase of the new design.

Project example

Comprehensive thermal stage supply

The above principles can be illustrated by an example where a 75% capacity increase was targeted, which was possible by incorporating oxygen enrichment up to 40%. The ratio of amine gas to sour water stripping (SWS) off gas could vary considerably, in some cases resulting in low temperatures during air-based operation and high temperatures during oxygen enriched operation. The thermal stage was completely blocked in by structural steel and other equipment, except on top. The burner vendor performed extensive CFD modelling to ensure good mixing, prevent hot gas impingement, and determine which ports to combine to limit length. The increased duty required replacing the original kettle type boiler with a thermosyphon type, with smaller tube diameter and longer length. This length increase was compensated by shortening the combustion chamber and marginally increasing its diameter. In cooperation with refractory engineers, the thinnest possible refractory was installed to satisfy the residence time

Once the extent of the revamp scope has been studied and determined, Worley Comprimo can offer the thermal stage as a complete engineering/procurement/fabrication supply contract in partnership with its Worley Chemetics colleagues. This contracting model can streamline the engineering and fabrication phases for the company’s clients under a single supplier umbrella and with the advantage of a single mechanical warranty for all the equipment in the full thermal stage.

July 2021 24 HYDROCARBON ENGINEERING

Double combustion option In situations where higher oxygen enrichment could be necessary, double combustion can be considered to manage the high temperatures associated with high oxygen enrichment levels. In double combustion, the oxygen is introduced in two stages, essentially distributing the temperature over these two stages. The design can be done either by installing two thermal stages in series (see Figure 2) with the second stage not having a burner, or as a single thermal stage (see Figure 3), employing a two-pass WHB where a portion of the oxygen demand is injected in the channel between the ﬁrst and second pass of the WHB, essentially creating a second combustion zone. The second option is preferred for grassroots and certain retroﬁts where plot space may be limiting.

Conclusion Overall, many factors require special attention when evaluating an SRU thermal stage revamp. Careful consideration is necessary to overcome the existing conﬁguration limitations while also working to minimise the physical impacts of new equipment. When all the elements of the design are integrated cohesively, the unit has the best chance for long-term reliability, ensuring a successful retroﬁt project.

Jonathan Wylde and Grahame Taylor, Clariant Oil Services, USA, examine the reaction of alkyl mercaptans with hydrogen sulfide scavengers.

ulfur-containing species found within oil and gas production fluids are far more varied than simply hydrogen sulfide (H2S). Other species include alkyl mercaptans (alkane thiols), dialkyl sulfides (such as dimethyl sulfide), dialkyl disulfides, carbon disulfide, carbon oxysulfide, and many others. While the majority of the industry focuses on the removal of H2S largely for corrosion mitigation and health and safety purposes, the removal of alkyl mercaptans is also of great concern and interest. Mercaptans are the sulfur analogues of alcohols where the oxygen atom is replaced with sulfur. They are much more volatile than their oxygen counterparts; while methanol and ethanol are liquids at room temperature and pressure, methyl mercaptan is a gas and ethyl mercaptan is a very low boiling point liquid. This is

attributed to the much weaker hydrogen bonding between sulfur and hydrogen when compared with oxygen and hydrogen atomic species. Mercaptans have very powerful, highly offensive odours and are often removed simply for this reason alone. They are very weakly acidic: methyl mercaptan has a pKa of 10.4 and ethyl mercaptan a pKa of 10.6, whereas H2S has a pKa of 7. The concentration of mercaptans found in oil and gas produced fluids varies but it is most typical for the total mercaptan concentration to be in the range of 0 to 150 ppm. Most cases will be at the lower end of this range (<20 ppm). Further individual mercaptans can vary and typical ranges for methyl mercaptan are 0.5 to 100 ppm, ethyl mercaptan 0.5 to 120 ppm, and butyl mercaptan 0.1 to 8 ppm. To date there has been very little in the way of systematic studies into the removal of

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ENGINEERING

July 2021

addressed this missing aspect together with a study into the capacity of conventional H2S scavengers to remove mercaptans from a multiphase application.4 Some surprising results were uncovered that challenged Molecular species containing sulfur conventional thinking on many fronts with respect to Apart from their reaction with H2S, very few rigorous these reactions. Hexahydrotriazines are the mainstay of studies have been carried out regarding the reaction of sulfur mitigation and indeed were found to be effective any of the above sulfur species with scavengers. While it for mercaptan removal. The removal of sulfur species is undoubtedly true, for example, that they all react with by hexahydrotriazines makes use of a vital feature of hexahydrotriazines (the most widely used scavengers in the sulfur atom. Being a Group VI or chalcogen the industry and often known simply as triazines), there element, sulfur has many electrons in its outer valance is a great paucity of careful studies. A 1951 study shell. Since these are further from the nucleus than the described the reaction of carbon disulfide with oxygen atom they are far more easily displaced, which 1,3,5 trisubstituted hexahydrotriazines or triazines and confers a high degree of nucleophilicity or affinity for found that they produced a cyclic thiadiazine-2-thione positive carbon centres upon this atomic species. Such (I) by insertion of the carbon sulfur species into the species are often referred to as soft nucleophiles, cyclic ring structure (Figure 1).1 indicating that the electron density is very easily Two studies have been carried out which touch on displaced and is not held tightly by the nucleus. The the aspect of sulfur mitigation by removal of reaction mechanism was studied in detail and there is mercaptans, but key questions are still left unanswered: one key aspect whereby it must differ from H 2S. The H2S molecule possesses two easily removed hydrogen perhaps, most notably, the reaction mechanism and atoms, and thus during its reaction with chemical identity of the reaction products was hexahydrotriazines this enables an overall insertion of a missing.2,3 An article published in November 2020 sulfur atom into the six membered ring, which opens and then closes via two S N2 nucleophilic substitutions. The resulting product is the dithiazine (II). Such a reaction is impossible for alkyl mercaptans, which only possess one easily removed hydrogen atom. The carbon sulfur bond of the mercaptan is very strong and remains unbroken in the reaction products ultimately formed. By means of careful isolation and analysis, the reaction products were shown to be (III), (IV) and (V), as seen in Figure 1. These are the logical products one would expect but were for the first time separated and identified. Not only were the reaction products positively identified for the Figure 1. Reaction products of molecular sulfur species with first time but the capacity of hexahydrotriazines. hexahydrotriazines, and in particular alkyl mercaptans other than the generic statement that: “H2S scavengers also remove mercaptans but with a lower level of efficiency.”

Table 1. Capacity of H2S, methyl and ethyl mercaptan reacting with hexahydrotriazines Scavenger

Sulfur species

Activity (%)

Observed capacity (kg/l)

Observed capacity (mole/l)

Calculated capacity (kg/l)

Calculated capacity (mole/l)

Assumed stoicheometry

Efficiency (%)

MEA triazine

H2S

0.12

3.53

0.13

3.68

MMA triazine

H2 S

0.23

6.76

0.23

6.65

101.8

MEA triazine

CH3SH

0.14

2.92

0.27

5.58

52.2

MMA triazine

CH3SH

0.47

9.79

0.48

9.98

98.1

MEA triazine

CH3CH2SH

0.29

4.68

0.35

5.65

82.9

MMA triazine

CH3CH2SH

0.53

8.55

0.62

85.5

July 2021 26 HYDROCARBON ENGINEERING

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indicates that, for both hexahydrotriazines, methyl mercaptan reacts every bit as fast as H2S, if not slightly faster. The reaction rate with ethyl mercaptan is markedly slower, as might be expected; typically the reactivity drops off as the substituent’s size and bulk increases, as shown in Figure 2. In summary, it is clear that when actual numerical capacity data for various Figure 2. Hexahydrotriazines relative reaction kinetics with sulfur species. common scavengers are determined (by an industry standard method), rather MMA hexahydrotriazine (or more accurately than supporting the conventional wisdom the findings 1,3,5-trimethylhexahydrotriazine), was shown in fact to show that they scavenge alkyl mercaptan more be greater than H2S. The experimental determination of efficiently than H2S, the most commonly encountered mercaptan capacity is a challenging undertaking and sulfur species in the oil and gas industry. It was also H2S detector technology is usually able to also detect discovered that – contrary to what has been generally alkyl mercaptans but with a lower level of efficiency. communicated – a quaternary ammonium compound, The typical technical sensor equipment responds to rather than scavenging by an alkyl transfer process to alkyl mercaptans anywhere from 33% to 50% the extent form a sulfonium species, in fact had no measurable to which it does for H2S. There are gas detector tubes chemical interaction with the mercaptan. 5 Further that can specifically detect alkyl mercaptan, some of studies are certainly needed, but the indications are which remove the H2S component first to avoid very positive that the state of the technology may well cross-sensitivity. Experimentation of mercaptans can be better than originally thought. effectively be carried out using recalibrated H 2S Conclusions and field significance detection technology but the determination of The removal of sulfur species from produced oil and scavenger efficiencies in the presence of H2S is more challenging. Any H2S detector will give an overall gas remains a vitally important consideration for response to all sulfur species but is of little use in and operators and, with the souring of many formations, of itself. One study used a sophisticated method of the importance only grows. While concentrating on the mathematically deconvoluting the absorbance of H2S most prevalent species (H2S) it is important not to and methyl mercaptan in composite gas breakthrough neglect other entities which must be addressed in studies.2 This allows the use of multiple mercaptans many situations. Relying on blanket statements and, in together with H2S in a common gas feed to a contact many ways, inaccurate ‘industry myth’ is clearly a poor tower. substitute for rigorous scientific studies. More recently, By recalibrating the conventional H2S analyser used the removal of mercaptans has finally received this for the industry-recognised autoclave reactor, type of attention not only from a numerical capacity multiphase mercaptan capacity numeric values were, data perspective but also from a rigorous organic for the first time, obtained for hexahydrotriazines, chemistry perspective, whereby the reaction products hemiacetals, metal carboxylates, and aldehyde have finally been identified and confirmed. scavengers, which were compared directly with those References obtained for H2S. In many instances superior 1. MERILL SCHNITZER, A., ‘Reaction of 1,3,5-trisubstituted performance was obtained with alkyl mercaptans Hexahydro-1,3,5-1 Triazines with Carbon Disulfide’, PhD Thesis, compared with H2S, which was not expected. Oklahoma A&M College, (December 1951). 2. CHAKRABORTY, S., LEHRER, S., and RAMACHANDRAN, S., ‘Effective A comparison of the results for molar capacity (this Removal of Sour Gases Containing Mercaptans in Oilfield leaves aside the molecular mass differences for the Application’, paper presented at the Society of Petroleum Engineers International Conference on Oilfield Chemistry, sulfur species) clearly indicates that MMA (3 – 5 April 2017), Montgomery, Texas, US. hexahydrotriazine is, in the data set shown in Table 1, a 3. OWENS, T.R., and CLARK, P.D., ‘Triazine Chemistry: Removing H2S and Mercaptans’, ASRL Quarterly Bulletin, 155, Vol. XLVII, No. 3, better scavenger for methyl and ethyl mercaptan than (October – December 2010), pp. 1 – 21. it is for H2S. The same is also true for MEA 4. WYLDE, J.J., TAYLOR, G.N., SORBIE, K.S., and SAMANIEGO, W.N., hexahydrotriazine. Such findings run contrary to ‘Scavenging Alkyl Mercaptans: Elucidation of Reaction Mechanisms and By-Product Characterization’, Energy & Fuels, Vol. 34, No. 11, conventional wisdom and should be considered when (November 2020), pp. 13 883 – 13 892. addressing field operations. Reaction rate information 5. WEERS, J. J., and GENTRY, D.R., ‘Quaternary ammonium hydroxides as mercaptan scavengers’, Patent US-6013175, (January 2000). can also be drawn from this testing methodology and July 2021 28 HYDROCARBON ENGINEERING

Ang Chew Peng and Lee Siang Hua, Sulzer Chemtech, Singapore, consider high-performance anti-fouling trays and packing that can help to minimise the accumulation of foulants in towers.

istillation and absorption are essential mass transfer processes in reﬁning, petrochemical and chemical processing plants. These towers are usually equipped with internals such as trays, structured packing or rings, as well as associated feed distributors and collectors. Some of these towers, in certain services or applications, are prone to fouling. Over time, this accumulation of foulants will eventually plug the column internals, adversely affecting the hydraulic and separation performance of these towers. It is in the producers’ economical interest to operate the plant as long as possible before having to shut down the towers for cleaning. There are several methods to mitigate fouling, depending on the type of foulants and their mechanism of formation. In recent years, Sulzer has developed robust, high capacity mass transfer components featuring anti-fouling designs that minimise the accumulation of foulants for a longer run length between turnarounds. This article will discuss some high-performance anti-fouling trays and packing that have been developed for these fouling and often heavy-duty services, as well as their successful applications.

Fouling mechanism and overview of mitigation In the wide range of process operations, there is a tremendous variation in the fouling tendencies of the process fluids and associated equipment metallurgy. Fouling is generally referred to as “solids inhibiting the flow of vapour and/or liquid on the trays or packing”. These solids can be particles, polymers or corrosion products and have different textures ranging from powdery to sticky. The main fouling mechanisms commonly observed in the industry include: Deposition of solids such as corrosion products, catalyst particles. Solid precipitation leading to formation of carbonates and chloride salts. Chemical reactions such as polymerisation and coke formation. Figure 1 shows the wash bed of the coker main fractionator after three years of operation. The first step in dealing with fouling is to identify the fouling components and the mechanism of formation. As per HYDROCARBON 29

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literature, if the foulants are introduced into the towers, the most effective method to keep these fouling materials out of the towers is with filtration.1 Some foulants that have developed inside the towers are caused by reaction or degradation of process fluids. It is possible to mitigate the fouling if the operating temperature is controlled at the level where these reactions or degradation cannot take place. Adjustment of column temperature often involves the control of operating pressure. For instance, the refinery vacuum distillation unit (VDU) is operating at high vacuum to avoid cracking of the heavier hydrocarbons, producing coke particles which will plug the column internals. Using process control to manage fouling can be costly as it deviates from the optimal operating points, which produce the most product at the lowest energy input. In certain applications such as olefins production, anti-foulants have proved to be effective in inhibiting polymerisation. However, the use of anti-foulants may not be the solution for all fouling services. In towers where the various methods (such as filtration, process control and anti-foulants) cannot effectively mitigate fouling, producers and operators turn to mechanical solutions – the use of advanced column internals specially designed to handle the fouling conditions, prolonging the run length between turnarounds.

Figure 1. Coke formation in the coker wash bed after three years of operation.

Figure 2. Sulzer VG AF™ anti-fouling trays with SVG™, push valves and enhanced outlet weirs.

July 2021 30 HYDROCARBON ENGINEERING

Fouling resistant trays Most of the towers that handle dirty or heavy process fluids are equipped with trays, unless there are temperature or pressure drop requirements which favour the use of packing. Trays have a relatively open structure and are less prone to plugging compared to the denser packing. In towers that process very heavy feeds and have lower demand on separation performance, baffle trays are often applied. There are various types of baffle trays, including segmental baffles, disc and donut and showerdeck trays. These baffle trays are segmented plates that allow the liquid to descend from baffle to baffle while the vapour passes through the liquid curtain formed between the baffles. These baffles can be sloped, to minimise the accumulation of solids on the decks. In general, baffle trays have lower efficiencies compared to cross-flow trays due to the substantially reduced vapour-liquid contact. For distillation towers that have stringent requirements for product purities, adequate vapour-liquid mixing on the tray deck is essential for separation performance. If the fouling is not severe, specially designed cross-flow trays can be applied. Certain zones on the trays are more susceptible to the settlement of foulants, such as the area behind the downcomers and outlet weirs, as well as on the stagnation zones where liquid flow is slower. A good ‘anti-fouling’ tray design centres around the techniques to mitigate the fouling for each of these problem areas: Enhanced outlet weirs to minimise accumulation of solids. Push valves to promote the flow of liquid, to avoid stagnation zones. Sloped downcomers for a higher downcomer bottom velocity to flush the solids. Foulants can also plug the tray decks over time, so the selection of the appropriate perforation is very important. It is widely known in the industry that movable valves are not recommended for dirty services as the valve legs may become stuck due to foulants, restricting their ability to open fully. In most fouling services, large fixed valves are applied, with the selection of the perforation size depending on the type and size of the fouling particles. Figure 2 shows Sulzer VG AFTM anti-fouling trays with large SVGTM fixed valves, and enhanced features to minimise fouling on the tray decks. The largest, most fouling resistant, fixed valve in the Sulzer portfolio is the XVGTM, which has been successfully applied in numerous applications including towers processing bitumen with sand. Figure 3 shows these XVG trays after three years of operation in this service. The vapour handling capacity of large valves can be a concern, as they are often associated with lower capacity as compared to smaller valves. As producers ramp up production throughput, there is a demand for high capacity anti-fouling valves for heavy-duty services. As such, Sulzer developed the UFMTM AF, a large fixed valve with excellent vapour handling capacity comparable to mini valves, as shown in Figure 4. The signature domed shaped cover directs vapour downwards towards the tray deck, thereby reducing the overall froth height, and increases vapour-liquid mixing on the deck. When tested in a 1 m test column with a chlorobenzene/ethylbenzene test system, UFM AF displayed 10% higher useful capacity than conventional fixed valves while maintaining high efficiency, as shown in Figure 5. UFM AF has been successfully applied in

heavy duty services including reﬁnery main fractionators, beer towers and beer strippers, improving their run length while meeting the high capacity demands. A recent revamp of the stripping section of a crude tower, from seven conventional trays to nine UFM AF trays, brought about an increase in recovery of diesel, even when the tray spacing was reduced by 20%.

Fouling resistant structured packing For some towers, it is essential to keep the overall column pressure drop as low as practically possible to maintain a low column bottom temperature and, in some cases, to decrease the compression ratio of downstream compressor. Structured packing is usually the preferred choice of mass transfer internals for these towers, as pressure drop across packed columns is five to ten times less than trayed columns. The typical examples are the VDU and FCC main fractionator in oil refineries as well as primary fractionator and water quench towers in naphtha cracker complexes. To fulfill the low pressure drop requirement and maintain the high resistance to fouling, anti-fouling structured packing has been developed. These heavy-duty packings, formed by corrugated metal sheets, include the following features: Large crimp height. Moderate to low surface area (between 40 – 90 m2/m3). Smooth surface without grooving or orifices. Thicker metal sheets (at least 0.5 mm thick). Shorter element height. The thicker metal sheets with shorter element height improves the robustness of the packing and the ease of cleaning. The large packing void and smooth surface make the packing less susceptible to the deposition of foulants. Figure 6 shows a Sulzer anti-fouling packing, MellagridTM AF. With the corrugated metal sheets within the packing being held together by tie-rods, there are contact points between the peaks of the crimps of adjacent metal sheets. Experiments have shown that these contact points are essential for a proper spread of liquid to fully wet the metal packing surface. This distribution of liquid is not only critical to mass transfer, it also minimises the risk of coke formation through reduced dry spots. Though spacers could eliminate the contact between corrugated metal sheets, this will adversely lead to uneven liquid distribution, aggravating the fouling issue. There are other inevitable contact points between the packing and other surfaces such as column wall, support beams and distributors, and Sulzer has engineered solutions to mitigate fouling at these zones. Deposition of solids may also occur between the packing elements. The change in vapour flow direction as liquid descends from one element to another results in a higher liquid holdup at the transition. Compared to denser structured packing, anti-fouling packing with larger void allows for lower pressure drop and holdup between the packing layers, which reduces the risk of coke formation. Liquid distributors are the heart of the packed columns; anti-fouling structured packing cannot work well without a well-designed liquid distributor. Liquid distributors specially designed for dirty services usually have large orifices on both sides of the liquid arm channels. Lateral liquid discharge uses

orifices raised above floor level (away from heavy fouling materials that may accumulate on the floor) to minimise the potential plugging of the holes. Overflow notches could be added on the upper edges of the liquid channels to allow liquid to overflow in a controlled manner, in the undesired circumstance that the primary orifices are plugged over long periods of operation. The following case study illustrates how fouling leads to premature flooding of the packed columns, and it was successfully debottlenecked with the use of advanced column internals. In 2014, a FCC main fractionator in an Asian refinery,

Figure 3. Sulzer XVG™ trays, in tower processing bitumen with sand, after three years of operation.

Figure 4. Sulzer UFM™ AF fixed valve.

Figure 5. The capacity enhancement of UFM™ AF over conventional fixed valve

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customised liquid distributors. Since the revamp in 2015, this FCC main fractionator has been operating successfully without any hydraulic constraint. It is able to handle an additional 10% higher capacity above the revamp loadings, with products well within speciﬁcations. The observed pressure drop is also lower than predicted.

Conclusion

Figure 6. Sulzer anti-fouling Mellagrid™ AF. equipped with six structured packing beds and two trayed sections, was only able to operate at 85% of the design loads. Process simulation and hydraulic evaluation indicated that the tower was not at hydraulic limits. The study of the column pressure drop proﬁle revealed that the actual pressure drop across the bottom three beds was much higher than predicted by the hydraulic tool. Further investigation suggested that the cause of poor tower performance was the accumulation of foulants in the packing from the catalyst carryover. In the following year, the packing in the bottom slurry pump around bed, wash bed and heavy cycle oil (HCO) pump around bed were replaced with Sulzer anti-fouling packing Mellagrid with

Fouling in distillation towers can be a costly problem as it prematurely limits the hydraulic capacity, affects the product specifications, and requires regular cleaning. This article discussed the techniques used to mitigate fouling by mechanical methods. For trayed columns, the combination of large fixed valves with advanced tray design features provide a robust solution for fouling applications. The development of high capacity anti-fouling valves allows these towers to handle higher throughput while maintaining good mass transfer efficiency. In heavy-duty packed columns, the use of Mellagrid AF – the large void structured packing with smooth surfaces – minimises fouling tendency. Carefully designed liquid distributors ensure that the liquid distribution is not adversely affected in these packed columns processing heavy fluids. These advanced engineered solutions have successfully proven to minimise the accumulation of foulants on the mass transfer equipment, thereby extending the tower’s run length between turnarounds and offering economic benefits to producers.

Reference 1.

PILLING, M., ‘Dealing with column fouling,’ PTQ, (Q1 2016).

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Jim McVay, MISTRAS Group, USA, explains how corrosion studies can be used to determine potential damage mechanisms, corrosion types, and corrosion rate/potential to inform risk assessment and inspection planning.

orrosion studies – also known as degradation mechanism reviews (DMRs) – examine the process, design, materials, and history of a process unit. They are now relatively common exercises in operating facilities, necessary for the sufﬁciently well-grounded and dynamic inspection programmes needed in today’s operating environments. API RP 970 (Corrosion Control Documents) helps, but it has omissions in areas that responsible operators need to address. Standardised criteria for consistent determinations of environmental cracking mechanism vulnerabilities is but one example; rigour of data review and analyses is another. The execution of a corrosion study is complex. It requires a multi-disciplined team of inspection and engineering subject HYDROCARBON 33

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matter experts (SMEs) with advanced knowledge of mechanical, corrosion, reliability, and materials engineering disciplines. With such a wide range of competencies required, operators can beneﬁt by partnering with a third-party service provider to ensure corrosion studies are executed accurately and effectively. This article will discuss good practices and possible pitfalls in executing corrosion studies, along with possible practices that can be implemented to optimise these efforts.

Key participants in corrosion studies Carrying out comprehensive corrosion studies requires a team of dedicated and well-versed professionals who know how to perform their respective responsibilities. Key participants in corrosion studies include: Inspection/process supervisors. Corrosion experts. Operations. Process engineering. On-site/internal corrosion/metallurgical engineering. Inspectors/inspection planners.

Other experts can be helpful as well, such as process SMEs, maintenance, and chemical vendor representatives. MISTRAS Group provides experts for each of these specialties, allowing proper damage mechanisms and defects to be evaluated.

In-depth look at process corrosion study process The process of executing a corrosion study is involved, but is ultimately extremely useful for the operational well-being of process units. The process is viewed in steps: Selection of corrosion expert and corrosion team company personnel resourcing to support the intended study. If the right people cannot commit necessary effort to the study, it is advisable to do it another time. Determination of work processes, schedules and required deliverables. Information/data gathering: this part of the process is driven by the corrosion expert personnel. The owner is responsible for responsiveness and the quality of data provided. Corrosion review meeting: the corrosion expert facilitates a corrosion review meeting. Full plant attendance and participation is ideal. Corrosion report: a corrosion study report is prepared. It features the basis, findings, and recommendations for mitigations and process controls. The corrosion study report should be thoroughly reviewed by the corrosion review team as a whole and accepted by the owner for the purpose of ultimately well-informed inspection programming. Critical plant information that should be reviewed includes the following: Applicable operations manuals and procedures. Past, current, and future degradation-related operating data requested by the corrosion expert. July 2021 34 HYDROCARBON ENGINEERING

Current process hazard analysis (PHA) reports. Simplified process flow diagrams (PFDs). Piping and instrumentation diagrams (P&IDs). Equipment design and materials of construction. All applicable management of change (MOC) completed since the last corrosion study. All available information on damage mechanism related incidents from the owner’s incident management database and industry sources (e.g. American Fuels and Petrochemical Manufacturers [AFPM] incident portal). Inspection histories. Any available corrosion control documents (including material flow diagrams). Leak repair locations and histories. Exchanger bundle replacement histories (if applicable). Any special accelerated corrosion inspection programmes. Refinery dead leg lists and dead leg inspection programme history. Condition monitoring location (CML) corrosion rate data and analysis and other corrosion rate information (corrosion coupon analysis, corrosion probe data, etc.). Previous applicable corrosion studies.

Special attention in the form of special tasks and checks should be attended to in an effort to ensure the quality of the corrosion study. Process management, veriﬁcation and quality of all data reviewed, corrosion review team composition, damage mechanisms considered, and corrosion study report content are among the topics that could be addressed. Other quality related topics are discussed below. Assembling and using a checklist to keep track of determined quality-related tasks and checks through a corrosion study is also a valuable tip. Organising quality-related tasks and checks tasks is a good idea to stay on top of the study. Useful categories to include in a checklist are: Task category. Required elements. Task responsible person. Corrosion engineer and/or owner inspection supervisor assessment of compliance (if applicable). Objective evidence of compliance to study requirements. Owner/supervisor approval. Additional comments.

Corrosion report deliverables The corrosion expert typically writes a final corrosion report, comprised of a summary of the corrosion study activities. Consideration should be given to require a unit premise document and process summary which may be supplemented by a critical asset level process data spreadsheet containing information such as representative fluid/phase, operating temperature, operating pressure, toxics and toxic percentages identified for each unique process. Applicable degradation mechanism descriptions should be included in the report. All PHAs and MOCs reviewed should be documented. The report should include all

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assignment to ensure repeatability and compliance to ‘Recognized And Generally Accepted Good Engineering Practices’ (RAGAGEP). Verifying the completeness and accuracy of all process safety management (PSM) related-information used in the study is important. PSM information includes PFDs, P&IDs, material ﬂow balance sheets, and material ﬂow diagrams (MFDs). The inspection supervisor should also verify the accuracy and completeness of inspection data in the inspection programme and in other records used in the corrosion study. This data could appear in original fabrication records, inspection reports, thickness data, repair records, and more.

Common pitfalls of less managed reviews Figure 1. Since different inspection results can result in different CML data, corrosion studies help to more accurately determine the amount of corrosive CMLs, enabling plants to more effectively plan their inspection and maintenance strategies.

injection and mixing points, dissimilar metal weld locations, and vulnerable piping systems and circuits. Expected corrosion rates for each asset should be presented and, if requested, external corrosion rates should be included. For a comprehensive characterisation of corrosion, applicable environmental cracking, and other damage mechanisms, the affected assets, expected corrosion rates or ‘potential/probability’ assignments for each damage mechanism as applicable, as well as possible locations of damage on each asset, should be identiﬁed. Integrity operating window (IOW) tables that support determinations of the corrosion studies and assist with effective mitigation could be included as well. Other technical recommendations, such as material upgrades, are beneﬁcial to the report too.

Quality control/quality assurance factors Accuracy and completeness of corrosion studies are critical to the effectiveness of ﬁxed equipment inspection programmes. Active involvement by reﬁnery inspection, process, and/or operations personnel supporting the corrosion expert helps to ensure the corrosion studies are technically correct and adequately support mechanical integrity (MI) programme requirements. The inspection supervisor should review and approve all completed corrosion study reports for completeness and compliance with company standards and expectations. All other corrosion review team members for each study should also review the completed corrosion review and approve reports for accuracy based on their knowledge and expertise. Traditionally, approvals require a documented signature so that quality assurance is guaranteed. A corrosion expert (often from a third-party contractor) can verify knowledge of process and degradation mechanisms and how determinations will be utilised. They should establish standards from degradation mechanism July 2021 36 HYDROCARBON ENGINEERING

There are various ways in which pitfalls can occur during a corrosion study and lead to less-managed reviews, which can cause greater issues down the line and affect operations once the review is complete and subsequent operational activities take place. A lack of technical and/or institutional knowledge amongst plant personnel is a common pitfall. A corrosion engineer may have little familiarity with their current company’s inspection and corrosion control standards or programming procedures and software. The company may have no peer review and corrosion study services. Owner process data gatherers may require more experienced support to get the right data in the right amount. Critical corrosion review process omissions are another pitfall. No review of critical internal documents like MOCs or past corrosion studies and no review or consideration of industry incidents is a red ﬂag. It is not a good idea for little direct plant data review or to leave process reviews only at PFD level. It is imperative that there is adequate owner team support in data gathering or team meetings. Inadequate capturing of corrosion study meeting discussions is a faulty habit that can lead to a non-fully realised review. Expected corrosion rate assignments can also be an issue. The corrosion engineer may not review and consider plant non-destructive examination (NDE) data and analysis due to initially writing it off as ineffective. Inconsistencies in determined corrosion and the corrosion engineer choosing arbitrary corrosion rates to ‘drive inspection’, with little understanding of impact on risk analysis and inspection planning, can lead to inefﬁciencies and improper review. For degradation mechanism assignments, a corrosion engineer may not consider all potential degradations mechanisms in API 571 or other applicable standards. Criteria for when to assign or not can be inconsistent, arbitrary and not necessarily in line with RAGAGEP standards. Determinations may be made with little or no actual process data, relying on known past practices. This leads to imprecise guidance on assigned degradation mechanisms. An engineer’s consideration of past inspection data may also not adequately consider quality/effectiveness.

Comprehensive and accurate final reports are essential to the corrosion study process as a whole. Errors in the final report may be attributed to inadequate documentation in several critical areas, such as unit premise, alternative operating regimes considered, and team meeting discussions. The report format not being aligned or otherwise conducive for ready extraction of necessary data for inspection analysis and planning purposes should be avoided. Technical recommendations not clearly presented and in a separate section contributes to a poorly organised report. Of course, a final report should be thoroughly reviewed and approved by the owner.

Special topics There are a few special topics to be mindful of when dissecting corrosion study practices. These aspects of the review help to ensure that reviews are conducted as efﬁciently and successfully as possible. For the corrosion expert, all requests should be clear and documented. All operating regimes should be considered, as direct process measurements should always be used rather than judgement or estimates. Wherever possible, modelling could also be pursued for determining or validating the most critical process parameters used in the study. Expected corrosion rate determinations should consider available actual NDE data and analysis of said data. The impact on inspection risk assessment and

planning should always be considered when making determinations. For corrosion study assignments, it is ideal to consider using measured vs modelled critical data wherever possible. Standardising degradation mechanism assignment thresholds can keep tasks organised, and considering likely effectiveness of historic inspections when factoring them into degradation mechanism assignment determinations is useful. Dissimilar metal welds (DMWs) are important to be mindful of. Establish clear guidance for determining degradation potential at locations depending on metallurgies involved and service conditions. It is important to be mindful of thermal and environmental cracking, as well as galvanic corrosion, at these locations. The plant needs to be able to compile a complete and accurate list of all DMWs locations for consideration.

Study up for the best results As corrosion studies can be an involved and daunting task, plants can benefit by working with a third-party provider, such as MISTRAS, to efficiently execute the review. Teamwork, effective communication, and diligent organisation of tasks can truly be the deciding factor of a successful, well-executed and less-managed corrosion study. The effort that is put into reviews is ultimately what operators can expect the quality of the final product to be. When completed properly, corrosion studies are an undeniably essential piece of information to have for risk assessment and inspection planning efforts.

July 2021 38 HYDROCARBON ENGINEERING

Kai Zhang and Renate Ruitenberg, Nalco Water, an Ecolab Company, USA, discuss an innovative non-phosphorus and non-zinc mild steel corrosion control programme for cooling water systems.

hosphorus was recognised globally as the primary growth-limiting nutrient for algae in surface water bodies (e.g. lakes and rivers) in 1972.1 Excessive biomass growth due to phosphorus nutrient in lakes and rivers can cause reduced light penetration, death of algae, and subsequent depletion of oxygen in water, which results in the death of fish and other aquatic life (known as eutrophication).2 In the last 20 years, the phosphorus discharge restrictions from cooling systems have been reinforced to control algae blooms in many large lakes in China. In the US, states such as Ohio, Illinois and Iowa are joining a growing list of states to ramp up efforts to reduce phosphorous discharge and control algal blooms in lakes, ponds, and reservoirs.3 Similarly, the use of zinc is restricted in some regions due to its toxic nature, and industrial producers have started to seek more environmentally friendly treatment solutions, both to comply with the changing legislation and achieve their performance targets. Table 1 summarises the phosphorus (P) and zinc (Zn) restrictions in various countries. More countries and regions have or plan to have tighter control on wastewater discharge to achieve sustainable development. Refineries and petrochemical plants use evaporative cooling systems to control the temperatures of their critical processes and eliminate excess heat. When water evaporates, the salts will concentrate, and without adequate conditioning, both corrosion and scaling will occur. Water treatment chemistries are very efficient in

controlling the occurrence and cost of corrosion, scaling, and biofouling. Historically chromate was used, but this has since been banned as safety and environmental awareness increased. Phosphate (PO4) combined with zinc took over from chromate as key components in corrosion control to extend the run length and asset life. For effective corrosion control, the phosphate concentration needs to be adjusted based on the pH and concentration of chlorides, sulfates and calcium in the cooling water, as well as heat exchanger skin temperature. Precise control of polymer concentration is required in the stabilised phosphate programmes. Meanwhile, eutrophication can result from these inorganic phosphates if sensitive water bodies receive the cooling water blowdown. Changes in makeup water matrices can lead to severe scale or corrosion events if the stabilised phosphate programme is not adjusted appropriately. With the increasing responsibility of sustainable development and industrial users adopting a ‘reduce, reuse and recycle’ strategy to save water, wastewater has been reused in cooling applications. This practice leads to signiﬁcant challenges of corrosion and scaling control with a conventional chemical treatment programme.4 Since the early 2000s, various non-phosphorous programmes have been tried and evaluated for corrosion and scale control in cooling systems. Without phosphate as an anodic corrosion inhibitor, success was achieved at a limited operation window, such as high hardness and high alkalinity. Nalco Water developed a non-phosphorous

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programme based on different chemistry innovations in the past few decades.5 This article presents the latest innovation that delivers on both environmental and performance goals at reasonable treatment costs. The new non-phosphorous programme showed signiﬁcantly improved performance in broad application conditions, from soft water to medium to high calcium and alkalinity waters and water with high chloride content. In addition, this programme application can be further expanded to non-phosphorous and non-zinc application window.

Solution The novel and cost-effective non-phosphorus cooling water treatment programme was developed to solve the challenges with stabilised phosphate programme. The non-P programme includes a proprietary dual function organic corrosion and scale inhibitor and an inorganic-based corrosion inhibitor. The newly-developed non-phosphorous programme has the following advantages compared to conventional non-phosphorus: Wider application window covering medium to high Ca/alkalinity water, soft water, and high conductivity water with high chloride. Tolerant to both fluctuating make-up water and tower water matrix. Enable operation at higher (8 – 9) or pH dips to 7 with its robust scale and corrosion control. Able to handle high cycles (10) and long holding time index (HTI) (200 hr) application. Automatic dosage monitoring and control of both inhibitors with fluorescence-based technology.

Figure 1. Online Nalco Corrosion Monitoring (NCM) mild steel corrosion rate and cooling water conductivity.

Table 1. Phosphorus and zinc restrictions by countries and regions Country/region Regulation examples

Drivers

China

<0.5 ppm P legislation, non-P cooling treatment required

Algal blooms: human health and drinking water supply risks

Japan

Environmental Impact Study (EIS) may result in non-P, non-Zn in certain areas

Tourism and aquaculture protection

USA

Depending on P-levels from agricultural run-off in water

Eutrophication and phosphate scaling risks

European Union

Water Framework Directive, variable limits

Risk assessment of receiving water body (quality and use)

Saudi Arabia

1 ppm Zn and 1 ppm P discharge limit to Red Sea

Environmental and coral reef protection for tourism

Argentina

Local restrictions P <1 ppm discharge limit

River water protection for drinking water intake

Figure 2. Mild steel (MS) coupons before and after NexGen non-P programme.

July 2021 40 HYDROCARBON ENGINEERING

Case history 1

A major petrochemical plant in China aimed to improve its cooling water treatment both to comply with the Total P legislation (<0.5 ppm P as phosphorus) and achieve asset protection key performance indicators (KPIs) mild steel corrosion rate <0.5 mils per year (mpy) and copper corrosion rate <0.1 mpy. Since its start-up in 2012, Nalco Water applied the very first generation of non-phosphate programme in this system. After nearly 10 years of reliable operation, this cooling system had unexpected contamination of organic compounds and sulfide compounds, leading to high bacterial counts in the cooling water. The high dosing of bleach required introduced high corrosion rates, causing a lower life span of assets and high maintenance costs. The high efficiency biocide chlorine dioxide from PURATETM technology was applied to replace bleach, which substantially reduced the chloride level. The PURATE chlorine dioxide programme is designed to maintain and optimise critical water treatment applications.6 Yet, the existing non-phosphate programme was not robust enough to protect critical heat exchangers. An occasional high corrosion rate was observed due to fluctuation of key parameters, e.g. pH, TOC, conductivity, etc. After switching to the new generation of non-P programme the overall cooling water chemistry was maintained at similar condition with conductivity of approximately 2000 μs/cm (Figure 1). The mild steel corrosion rates were much improved in both online Nalco Corrosion Monitoring (NCM) probe readings (Figure 1) and corrosion coupons (Figure 2). The average corrosion readings by the 3D TRASAR controller NCM probe fell from 1.3 mpy to less than 0.3 mpy. Before the switch to using the new programme, the corrosion coupons showed some localised corrosion. After the switch, general corrosion rate was well controlled below 0.1 mpy without pitting corrosion based on one-month corrosion coupon reading.

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the dynamic changes in the system. Meanwhile, the cooling water system was remotely monitored by Nalco Water System Assurance Centre, allowing actionable data visibility. After starting the non-P non-Zn programme, the overall cooling water chemistry was maintained at similar condition with conductivity around 2500 μs/cm (Figure 3). The mild steel corrosion rates were progressively decreased to less than 0.2 mpy from previous more than Figure 3. Online NCM mild steel corrosion rate and cooling water 0.5 mpy (Table 2). conductivity. Through the onsite automation and remote digital platform, excellent operational reliability in Table 2. New non-P non-Zn treatment results high stress heat exchangers under low flow or high heat flux was achieved with significant savings on total operation Cooling water Target Actual reading parameters cost and productivity increase. The platform was able to: Fully comply with total phosphorus discharge limits. Total phosphorus <0.5 ppm <0.1 ppm Save freshwater consumption by 1 million tpy. Zinc <0.2 ppm Reduce deposition and fouling in heat exchangers, as Chlorides <600 ppm 300 ppm Cl well as maintenance costs. Calcium, as CaCO3

<700 ppm

500 ppm CaCO3

Mild steel corrosion rate

<0.5 mpy

<0.2 mpy

System challenge is high organic contamination from reused process water

With the new generation of non-P treatment programme, the plant was able to: Fully comply with total phosphorus discharge limits and reduce wastewater treatment costs by US$0.5 million/yr. Increase production throughput and profit by US$3 million/yr. Reduce maintenance cost and extend asset lifespan.

Case history 2 A major integrated reﬁnery and petrochemical complex in China adopted enhanced sustainability goals to save more water by reusing wastewater into its cooling system. The Total P discharge limit is <0.5 ppm P as phosphorus and for asset protection the KPIs are: Mild steel corrosion rate of <0.5 mpy. Copper corrosion rate of <0.1 mpy. With the make-up source alternating between river water and reused wastewater, containing high chlorides and high calcium, the assets are posted to high corrosion and scaling stress at the same time. Nalco Water researchers and industrial technical consultants conducted a total plant survey to understand the system challenge including mechanical, operational, and chemical limitations. After a thorough study and pilot cooling tower simulation, a further stretched application window of a novel non-P non-Zn programme was implemented to the system. The critical component of success on this programme was 3D TRASAR technology for cooling automation platform as a stress management system. This technology could control the key parameters in the cooling water system using online monitoring. Based on the real time monitoring, feeding of chemicals was able to respond to July 2021 42 HYDROCARBON ENGINEERING

Conclusion Innovations tailoring the corrosion control treatment to local regulatory requirements have led to a large improvement in both corrosion control and efﬂuent quality, showing that protecting the environment can coincide with reductions in total cost of operation. The new generation of non-P programme combines a proprietary organic dual function inhibitor (corrosion and scale inhibitor) with inorganic corrosion inhibitor to generate a synergistic programme. It has been proved to be effective over a wide range of water matrices, such as soft water, high conductivity water with high chloride, and medium to high calcium and alkalinity water. It provides reliable corrosion inhibition performance without introducing CaPO4 scale stress or phosphorous nutrient for bio-growth. Furthermore, automated programme control through Nalco Water 3D TRASAR technology and System Assurance Centre can handle a dynamic water matrix including reused wastewater. This advanced total solution also enabled corrosion and scale control with non-P non-Zn application in a highly stressed water matrix, which poses signiﬁcant challenges for a stabilised phosphate programme.

References 1.

PELIPE, M., FULMER, D., SANDU, C., GUO, B., and NGUYEN, K., ‘Novel and Efficient Non-Phosphorous Cooing Water Corrosion Inhibitor’, Cooling Technology Institute, TP 16-50, Houston, Texas, US, (2016). CHISLOCK, M. F., et al., ‘Eutrophication: Causes, Consequences, and Controls in Aquatic Ecosystems’, Nature Education Knowledge, (2013). MAHER, K., and MCWHIRTER, C., ‘Midwest States Target Algae Blooms in Waterways’, Wall Street Journal, (28 September 2018), https://www.wsj.com/articles/midwest-states-target-algae-bloomsin-waterways-1465772363 GILABERT-ORIOL, G., et al., ‘Wastewater reuse for industrial applications in cooling towers’, EMChIE 2015, Tarragona, Spain, (10 – 12 June 2015). XIE, Y., et al., ‘A Novel Non-Phosphorous Cooling Water Treatment Program with Robust Scaling and Corrosion Control’, NACE Corrosion 2019, Paper 13009, , Nashville, Tennessee, US, (24 – 28 March 2019) FALLET, L., and RUITENBERG, R., ‘Biofouling Mitigation’, Hydrocarbon Engineering, (December 2021), pp. 25 – 28.

Berthold Otzisk, Surjeet Kumar and Dr Michael Urschey, Kurita Europe, discuss ammonium salt removal management.

mmonium salt fouling and corrosion are common problems in petroleum refining plants, which cause great damage and costs every year. Ammonium chloride (NH4Cl) and ammonium bisulfide (NH4HS) are corrosive, as a gas, solid, or in solution. Therefore, corrosion protection is one of the major concerns in refinery operations, where these salts are generated through the process itself or are imported from other process units with the feedstock. To avoid stress corrosion cracking, distillation equipment being exposed to ammonium chloride fouling has to be thoroughly washed with an alkaline solution. Ammonium bisulfides are depositing at far higher temperatures compared to ammonium chloride salts and they are more difficult to remove by water washing. Good wash water system designs are required, but sometimes an uncontrollable outlet temperature still causes problems. This is the case when the fluid velocity in condensers is low enough for ammonium salts to settle down in the tubes, causing pitting and under-deposit corrosion. Typical areas for ammonium salt fouling and corrosion are CDU or FCC distillation column top sections, hydrocrackers, feed-effluent exchangers from hydrotreater or catalytic reformer reactors, recycle gas compressors, stabiliser columns, reboilers and overhead sections. When neutralising amines are used for corrosion protection of the overhead section, there is always a risk that some amine-HCl salts may enter the distillation column with the reflux stream again. Amine chloride salts dissociate to amine and hydrochloric acid by thermal decomposition or evaporate as a form of amine-HCl by heating and then may deposit in the overhead system at lower temperatures, causing corrosion problems. Sometimes oil-soluble additives are also used as anti-foulants. Film-forming amines (such as imidazolines) have a dispersing effect at higher treat rates and can therefore mobilise some of the deposited HYDROCARBON 43

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July 2021

ammonium salts. Imidazolines belong to the chemical group of heterocyclic compounds. They have surface-active properties, which limits their use as anti-foulants, as they may tend to form emulsions at higher dosing rates. Being high-boiling active substances, they can also be transported downwards with the condensing product streams. This can negatively affect the product qualities of the side steams.

In systems where even small amounts of salt deposits lead to problems with safety and control valves, online cleaning can achieve great success in a few minutes and restore the old condition as with mechanical cleaning. In systems where large salt deposits have built up over a longer period of time, dosing is carried out over a few days and the deposits are continuously removed from the system. Interestingly, there are process plants where regular Technology water washing removes only small amounts of chlorides The ACF technology is a strong-base chemistry that reacts despite the presence of salt deposits. This can be directly with ammonium chloride, hydrochloric acid, and attributed to the fact that above the salt layer, amine salts. It has three very important properties: high hydrocarbons probably prevent direct contact with the ammonium salt replacement action, high moisture water. When ACF is added to the wash water, the chloride absorption and very low corrosiveness. The strong base concentration in the sour water then increases rapidly. Such ACF displaces the weaker base ammonium from its salts to effects have been observed a few times, where after adding form liquid ACF salts with neutral pH and very low ACF to the wash water, the chloride concentration corrosiveness. Fouled neutralising amine salts in distillation suddenly increased from <10 ppm to >5000 ppm chlorides columns or overhead systems can also be removed by in the wash water. forming liquid ACF salts. ACF technology is used during online cleaning to The ACF reaction product is a quaternary salt remove ammonium chloride, ammonium bisulfide or compound with a very low corrosion potential. In neutralising amine hydrochloride (e.g. MEA hydrochloride). comparison, reaction products of primary, secondary or When large amounts of ammonium salts need to be tertiary neutralising amine salts show a much higher dissolved and removed, it is particularly important to corrosion potential. The organic base ACF directly reacts provide a sufficiently high amount of ACF during cleaning. with strong acids such as HCl or its salts, where already The deposited salts are chemically converted into deposited salts are immediately dissolved into liquid salts. water-soluble ACF salts, which can then be easily removed. There is a stoichiometric ratio of ACF to ammonium salts and one can calculate very precisely how much product is needed for cleaning if the amounts of deposited salts are known. In practice, it has proven useful to apply a ratio of 1:5 or five parts ACF to one part deposited salts as a rule of thumb. When ACF is injected on a continuous basis it prevents the harmful chloride salts from forming and keeps the corrosion potential low. This allows the refinery to operate at low overhead temperatures without fouling or corrosion restrictions. For continuous applications as a Figure 1. Fouled naphtha hydrotreater effluent exchangers. preventive measure, dosing is usually realised in the low ppm range. It is possible to combine ACF together with film-forming amines in one product. Salts can then be removed at the same time and the metal surfaces can be effectively protected against direct acid attack.

Case study 1

Figure 2. Test results from the heat exchanger of the heavy gasoline loop.

July 2021 44 HYDROCARBON ENGINEERING

A reﬁnery observed ammonium salt deposition in the Residue FCC (RFCC) main fractionator column upper trays, overhead system and depropaniser reboiler after commissioning to expand the proﬁtability to crack a wider range of feedstocks. Up to 70 ppm chlorides are regularly measured in the RFCC main fractionator overhead separator drum. During a 2 – 8 hr online water wash,

which must be carried out every two months, up to 13850 ppm of deposited chlorides can then be dissolved and removed with the wash water. However, the water wash is only partially helpful because during this time production is out of spec and the top pumparound flow must be reduced by 20 – 30%. After the water wash, 10 – 15°C heat recovery on the hot side of the circulating heavy gasoline is observed. In a trial lasting several days, an ACF additive was dosed into the inline tube to the heat exchangers of the heavy gasoline loop. The aim of this test was to dissolve the salts and also to achieve 10 – 15°C heat recovery. Wash water was not added at all. For about two hours, 25 l/hr of ACF additive were dosed to fill the dosing line. After that, the dosing was reduced to 4 l/hr. The results and adjustments to the dosing rates during the trial are shown in Figure 2, where one Figure of the heat exchangers was used for monitoring to salts. evaluate the performance. With improved 18°C hot side delta temperature and almost 0.45 bar strongly falling differential pressure, the specified success criteria were clearly exceeded. During the ACF trial phase, the unit throughput did not need to be reduced and only heavy gasoline was sent to slop for reprocessing as a precautionary measure. During classical water wash, heavy gasoline and light gasoline are sent to slop for reprocessing. Other positive effects were an increase in the depropaniser bottom temperature and the reflux ratio. The LCO flow rate to the depropaniser reboiler was reduced as well as the steam flow.

Counteracting negative effects Reﬁneries have some options to increase the middle distillates and propylene production. However, this often has negative consequences or requires additional capital costs. A common strategy is to adjust the cut points between the naphtha and middle distillates draws in the crude distillation unit, coker unit or FCC plant. This is usually done by reducing the fractionator top temperature, which then inevitably increases the ammonium chloride (NH4Cl) salt potential. FCC units and delayed coker main fractionator towers often show salt fouling. They are particularly sensitive to salt fouling because of the relatively high concentration of ammonia (NH3) and hydrogen chloride (HCl). A temperature reduction of 3 – 5°C can result in nearly three times the salting potential. An FCC main fractionator temperature decrease of 5 – 10°C or more will inevitably lead to a rapid salt fouling with signiﬁcant differential pressure increase. Continuous use of oil-soluble salt-dispersant technologies can help, if the temperature reduction is in the 3 – 5°C range. However, its use is often limited by a certain tendency to emulsify which should be avoided. It has its limits in the case of long-term temperature reductions of more than 5°C, when higher additive dosing rates are necessary and high-boiling hydrocarbon components could enter downstream products (e.g. LCO). Kurita DMax products are water-soluble formulations and counteract these negative effects. Applied with continuous dosing it will ensure stable process conditions

3. Hygroscopicity test with NH4Cl and DMax chloride without significant pressure increase or rising corrosion rates. This achieves higher profits quickly and without extensive conversion work. Kurita DMax products are based on organic hydroxide chemistry. The very strong base provides the full base strength of the hydroxide ion, which is by a factor of 10 – 100 stronger than typical organic amines. Ammonium salt-based deposits are fully dissolved into the process stream. It is a curative treatment, which prevents salt precipitation and corrosion. This chemistry can even be applied at high temperatures. Formed DMax salts have a very low corrosion potential and are highly soluble in water. As an additional benefit they have a very high tendency to absorb the humidity from air or steam addition. The salts are highly hygroscopic, referring to the property of substances to bind humidity from the environment, if free water is not present. Ammonium chloride salts absorb water, but the damp salts are extremely corrosive and plug fractionator trays, piping, and heat exchanger surfaces. The situation is different where DMax chloride salts remain liquid and leave the system with the condensed steam or sour water phase. Figure 3 shows a laboratory test, where dried ammonium chloride and DMax chloride were in contact with ambient air at room temperature. After about 30 minutes the dried DMax salts started to become liquid again, while ammonium chloride salts stayed solid.

Case study 2 To achieve specifications for low-sulfur gasoline or higher LCO yields, modifications and operational changes may be required. This could include undercutting of FCC naphtha, separation of high sulfur naphtha via the heavy naphtha train. Due to lower temperatures and higher concentrations of NH3 and HCl, a build-up of salt deposits may then be observed in the upper section of the FCC main fractionator and upper pump-around circuits. Clogged bottoms and product draw, significantly increased corrosion, loss of fractionation and loss of compressor performance are known problems in that case. HYDROCARBON 45

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Figure 4. Effects of temperature reduction without and with DMax application. An FCC plant wanted to increase the LCO yield as blending material for higher diesel production and at the same time significantly increase the profit for the refinery without major conversion work or time-consuming approach. The simplest way was to lower the cut temperature of the gasoline base material in the main fractionator by 10°C. As expected, a higher product yield was achieved. Relatively quickly, an increase of the differential pressure was observed, which was a result of unwanted salt deposits in the column. The differential pressure rose steadily and after a few days a very sharp jump to a much higher critical level was observed. This mode of operation was then stopped in order to remove the salts and restore the previous operation conditions.

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When the FCC system was running again under constant conditions at a later time, the temperature was lowered again by 10°C, but at the same time an additive from the DMax series was also dosed with continuous treatment. Compared to the ﬁrst observations and experiences, the yield of diesel could be increased again, but now the differential pressure remained constant and no increase in corrosion was reported at a later point in time. For the customer this performance means an economic advantage and it has become an important application.

Conclusion The formation of ammonium salts and their deposits is sometimes difficult to prevent. A well-functioning water wash can help to remove these salts in some cases. The right design then plays a very important role and about 20% of the wash water should not vaporise if possible to avoid acidic dew point corrosion. Deposits in condenser tubes are often difficult to prevent if the fluid velocity is low enough for ammonium salts to settle down, causing pitting and under-deposit corrosion. The use of a chemical treatment programme can help to achieve long run times without the problems discussed in this article.

Helma Hakala, VA TECH WABAG GmbH, introduces an innovative biological process for produced water treatment in Romania.

or oil production, the treatment of produced water has a large influence on the level of environmental protection and economic success. The treatment employed should utilise sophisticated technology that is able to cope with well characteristics that can vary significantly from borehole to borehole. WABAG has built a new produced water treatment plant in Romania. Due to specific oil extraction processes, the produced water contains large quantities of non-biodegradable organic compounds. Therefore, an innovative process was developed for the specific requirements of the oilfield. The design includes physical/chemical and biological process steps, as well as advanced filtration and adsorption technologies, which represents a first in this specific field. This advanced, multi-stage treatment process was tested successfully on the spot over several months, and the plant was commissioned in 2017.

Produced water A major factor in the economic success of oilﬁelds is the treatment of the large quantities of water emanating from production. Every barrel of oil that is pumped is accompanied by six to eight barrels of produced water. It is the largest waste stream generated in the oil and gas industry, and consists of a mixture of different compounds, both organic and inorganic.

The priority of the project in Romania was the reduction of pollutants in the produced water to produce a more environmentally friendly discharge. The main issue was the elimination of non-degradable chemical oxygen demand (COD). For this reason, adsorption using activated carbon technology was implemented which proved to be successful. A three-stage treatment system has been installed comprising a physical-chemical stage, an innovative combination of biological treatment, and adsorption using activated carbon. By incorporating this, the plant effectively decreased the COD in the produced water by 92% to 95%.

New process design Based on the speciﬁc average and maximum values of the incoming water (Figure 1) and the discharge limits imposed on the river, the following concept has been developed for produced water treatment. The main units in the treatment plant design consist of: Two inlet tanks for buffering and equalisation of flow and loads and for oil removal. Two dissolved air flotation units for the removal of suspended solids and oil after adding coagulants and flocculants. Cooling towers for cooling water. Two activated sludge tanks designed as aerobic tanks. Two clarifiers for settling the mixed liquor. HYDROCARBON 47

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Table 1. The produced water raw composition and maximum limits to the river Serial number

Parameter

Unit

Average values of incoming water

Maximum discharge limit for the river

°C

7 – 8.5

6.5 – 8.5

Temperature

Bar

Pressure

mg/l

Total suspended solids (TSS)

mg/l

≤400

Petroleum products TPH

mg/l

350

Total nitrogen (TKN)

mg/l

NH4

mg/l

1.4

COD

mg/l

870

125

BOD5

mg/l

330

Total phosphorus

mg/l

0.27

Filtered residue

mg/l

1152

2000

Chlorides

mg/l

231

500

Dry filterable residue

mg/l

1766

Detergents

mg/l

0.64

0.5

Phenol index

mg/l

≤7

0.3

TOC

mg/l

320

SiO2

mg/l

Alkalinity

mEch/l

14.84

0.1

Turbidity

NTU

250

0.2

Substances extracted with perchlorethylene

mg/l

1.340

Figure 1. Process flow diagram.

July 2021 48 HYDROCARBON ENGINEERING

Four dual media filters for the removal of the remaining suspended solids. 12 activated carbon filters for the final polishing required in order to reach the target COD concentration. One sludge storage. Two sludge dewatering centrifuges. Table 1 shows the produced water raw composition and maximum limits to the river.

Treatment processes and performance The treatment plant was designed for a daily average produced water flow of 8000 m3, using an overdesign factor of 10%, which results in a maximum inlet flow of 366 m3/h. The sequence of process units are as per the process flow diagram in Figure 1.

Inlet tanks Two inlet tanks have been designed, each with a total usable volume of 1600 m3 where oil-water separation and solids settling take place owing to density differences and the hydraulic retention time of more than 4 hours. The separated oil is discharged into the slop oil tank (8 m3) and recovered slop oil is transferred to the oil storage facilities. Up to 4000 m3/day can be re-injected into the water disposal reservoir for emergency measures.

Chemical treatment and dissolved air flotation The physical chemical stage (two lines) consists of a coagulation tank, a flocculation tank, and a dissolved air flotation (DAF) unit (including its own internal recirculation system). A mix of the inlet tank effluent, internal recycled used water and polluted rainwater, in addition to the excess sludge from the activated sludge tanks, are treated and directed to the inlet tanks. In order to improve suspended solid and hydrocarbon separation,

coagulants and ﬂocculants are mixed with the produced water stream. The separation process in the DAF unit is enhanced by recirculation and compressed air dissolution. Figure 2 shows the quality of produced water before and after chemical treatment.

Inlet pumping station and cooling system After the DAF unit, the temperature level of the produced water is approximately 55°C. In order to cool down the water to an appropriate maximum temperature of 35°C in the activated sludge tanks for biological treatment, the inlet pumping station pumps a partial stream of the produced water into the cooling system, which accordingly reduces the temperature in the tanks if it is >35°C (measured online). The cooling system consists of three cooling towers with enhanced airﬂow for maximum efﬁciency during the summer.

Figure 2. View of the cooling towers.

Activated sludge system For biological treatment, it was additionally decided to remove carbon concentrations by means of specifically adapted microorganisms. The variations in loading have a resultant effect upon the process air, optional nitrogen nutrient dosing, and the simultaneous nitrification/denitrification requirement. In case of insufficient availability of nutrients for biomass growth, the dosing of urea as a source of nitrogen and phosphoric acid for phosphorus can create adequate biomass living conditions.

Clarification Following biological treatment, the produced water flows by gravity to the downstream clarifiers. The two rectangular type tanks each have a volume of 480 m3. In order to increase the specific settling surface, lamella packages are installed in the clarifiers. The clarified water is sent upwards to the dual media filtration units by the intermediate pumping station.

Figure 3. Biological treatment.

Dual media filters Four dual media filters are installed upstream of the final granular activated carbon (GAC) treatment step in order to minimise the total suspended solids load. Gravel and anthracite have been chosen as filter media as they exhibit excellent separation efficiency. Each filter has a bed volume of 14 m3.

Activated carbon adsorption In order to reduce the remaining COD and phenol to the required effluent limits, an activated carbon adsorption stage has been installed. This system consists of four lines in parallel operation, each of which has three filters in series (two actuated, the third in standby mode). Each filter has a bed volume of 43 m3 activated carbon.

Sludge treatment All sludge streams in the produced water treatment plants are collected and thickened in the DAF unit 5%.

Figure 4. View of the cooling towers.

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Table 2. Design parameters for the biological stage Serial number

Parameter

Unit

Minimum

Maximum tender book

Pilot tests

Design

BOD5

mg/l

200

330

200

TKN

mg/l

NH4

mg/l

1.4

Table 3. Produced water quality before and after GAC filtration Serial number

Parameter

Unit

Inflow to GAC filtration

Outflow of GAC filtration

COD

mg/l

260

Maximum 125

Phenol index

mg/l

0.5

Maximum 0.3

From here, the sludge gravitates to the sludge buffer tank with a storage capacity of 2.5 days and a total volume of 200 m3. It is also used as a feed tank for the downstream sludge dewatering by centrifuges. The sludge ﬁlter cakes have a maximum residual water content of 70% and are disposed at a landﬁll.

Conclusion The plant treats a maximum of 360 m3/h of wastewater comprising the following main components: Storage and equalisation tanks. Coagulation/flocculation.

DAF. Cooling towers (55°C down to 35°C). Biological treatment (activated sludge process). Lamella clarifiers. Flocculation and dual media filtration (DMF). GAC filtration for extended COD removal. Sludge dewatering (two phase centrifuge). Service water station.

WABAG completed the produced water treatment plant in Romania in 2017. Since then, it has been in continual operation and successfully meets all required standards. Therefore, the plant makes a substantial contribution to environmental protection. The purpose of the related regulations is to protect and enhance the environment to the fullest possible extent both now and for future generations in accordance with the respective Romanian and European regulations. The plant operator is obliged to reduce the levels of water, air, soil, noise, and toxic substance (e.g. sludge) pollution. The government authorities have drawn up technical standards and environmental regulations, as well as control compliance on site at regular intervals. The GAC technology (ﬁltration, loading, unloading) used represents the largest fully automatic system implemented in Romania to date.

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Anne Himmelberg, Aron Katz, and Victor Hoffman, John Zink Hamworthy Combustion, USA, assess vapour control options and introduce a suitable technology where vapour combustion technology is selected.

apour control equipment is used to control the release of volatile organic compounds (VOCs). VOCs can be harmful to the environment if released into the atmosphere, as they are chemical precursors to ozone and smog formation. Worldwide, a wide breadth of regulations require that the VOCs be captured or destroyed to prevent their release. Technologies utilised to control VOC emissions are typically classiﬁed into two main categories. Vapour recovery units (VRUs) capture VOCs and turn them back into a liquid product (Figure 1), whereas vapour combustion units (VCU)

destroy the VOCs through combustion (Figure 2). Each technology has its own beneﬁts and shortcomings. For certain applications, VRUs are the greenest form of emission control. Unlike VCUs, VRUs do not produce nitrogen oxide (NOX) or carbon monoxide (CO) and do not require a supplemental fuel gas for efﬁcient operation. While VRUs are very green, they are not suitable for all applications. VRUs utilise activated carbon for VOC removal. Activated carbon is not chemically compatible with all VOCs including, but not limited to, strong oxidisers such as ketones and aldehydes. These compounds can cause heat-ups in the HYDROCARBON 51

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carbon media which can increase the risk of hydrocarbon autoignition in the carbon bed. Activated carbon also has difficulty capturing small volatile molecules, such as methane. VCUs have the benefit of being able to simultaneously handle a larger range of VOCs compared to VRUs. Other than being green, VRUs have the economic benefit of recovering vapour and turning it back into a liquid product. In certain applications, selling the recovered liquid product can lead to a significantly positive return on investment. Complications with the recovered product can also lead to a

shortcoming of VRUs. Typically, all of the vapour sent to the VRU gets recovered into a single liquid product stream. In applications where high purity is required for the recovered product, mixed loading may not be suitable. VCUs can better handle mixed loading because the vapour is destroyed rather than recovered. Other than component and process compatibility, a major reason for a VCU to be selected over a VRU is capital cost. VRUs have a significantly larger capital cost compared to VCUs. This difference in capital cost is increased for vapour streams containing less than 6% hydrocarbon. Such units often require a vapour saturation step to allow the VRU to effectively recover the product. This pre-treatment device increases the overall size of the VRU significantly. Where vapour combustion technology is employed, the John Zink Hamworthy Combustion NOxSTARTM VC System is an excellent vapour control technology. The system maintains or improves upon many of the benefits of a traditional VCU, including offering destruction efficiency (DE) up to 99.99% and CO emissions as low or lower than 0.015 lbs/million Btu, while also achieving ultra-low NOX emissions.

Controlling NOX

Figure 1. VRU process.

Figure 2. VCU process.

July 2021 52 HYDROCARBON ENGINEERING

Low NOX vapour destruction in a petroleum products terminal setting presents many technical challenges. A variety of techniques often employed in ultra-low NOX process burner designs cannot be utilised in vapour combustion service. For example, in contrast to process burners, the waste gas in VCU service tends to be available at very low pressure, resulting in a poor amount of energy available for mixing. Additionally, the flow rate and composition of the waste gas can vary considerably. In terminal and marine service, hydrocarbon vapours can fluctuate from very lean to very rich, they may have an inert balance gas or air as a balance gas (non-inert), and they may span an extremely wide range of flow rates necessitating high turndown capability. To understand how the technology produces lower NOX than traditional VCU technology, it is important to understand how the most prevalent, individual NOX compounds in the combustion process are formed. NOX derived from the combustion process comes from three distinct categories: Thermal NOX, Fuel NOX, and Prompt NOX. Thermal NOX is the largest contributor to NOX formation in the combustion process and is defined as NOXthat is produced from the combustion air which contains atmospheric nitrogen (N2) and oxygen (O2). N2 and O2 in the combustion air are further

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Figure 3. NOX, CO vs theoretical air graph.

Prompt NOX is formed in a fuel-rich environment and is defined as NOX formed in the initial portion of the flame zone when fuel and air react. For example, when methane (CH4) is exposed to high heat, it is initially broken into CH/CH2 plus some hydrogen (H) radicals. This CH and CH2 then combine with N2 to form HCN and NH, which now act as fuel-bound nitrogen: N2 + CH → HCN + N N2 + CH2 → HCN + NH By combusting the fuel in a lean environment (air rich) the Prompt NOX process is reduced. This effect can be seen in Figure 3. In most applications, Prompt NOX is much less than Thermal NOX. With an understanding of the three mechanisms of NOX formation, it is apparent that the critical factor in NOX reduction is the reduction of peak flame temperature in an air rich environment, thus reducing the reactivity of the molecules involved, allowing them to more readily convert directly to carbon dioxide (CO2) and water vapour (H2O).

Designing a low NOX system

Figure 4. ZULE® Flare System. broken down into N and O radicals with the addition of high heat, which is above 1300°C (2370°F).1 These N and O radicals can produce NO as follows: O + N2→ NO + N N + O2 → NO + O N + OH → NO + H By reducing the peak flame temperature, NOX formed from the Thermal NOX process is reduced. Fuel NOX is defined as that NOX produced from nitrogen that is chemically or organically bound in the fuel, such as ammonia (NH3) or coal. When the nitrogen-bound compound is exposed to high heat, the N radical is broken from the molecule and readily attaches to an O radical. Once NO is formed, it is also possible to further combine with an N radical to form N2 at low oxygen concentrations in the flue gas: Fuel N + O2 → NO + O Fuel N + NO → N2 + O Since fuel-bound nitrogen compounds are not typically present in VCU applications, targeting the reduction of NOX formation resulting from fuel-bound nitrogen by operating at lower oxygen concentrations in the flue gas is not a viable solution for NOX reduction in this application. July 2021 54 HYDROCARBON ENGINEERING

Building upon these principles, the NOxSTAR VC System is an adaptation of a similar John Zink technology, the ZULE® Flare System, which was first introduced to the landfill industry in 1999 (Figure 4). Gas from the anaerobic digestion process which forms landfill or biogas is produced at a relatively constant flow rate and chemical composition, primarily methane and carbon dioxide. The ZULE Flare System operates by precisely mixing air with biogas based on a fixed methane concentration, pre-combustion. The primary challenge of safely and reliably adapting this system to the vapour control market is the variable flow rate and composition inherent to the vapour control applications. To overcome this challenge, a NOxSTAR VC System utilises a total hydrocarbon analyser to measure and control the total hydrocarbons present, ensuring a consistently lean concentration of the waste gas just before combustion. By controlling the air and hydrocarbon mixture precisely, the technology can dynamically adapt to varying flow and composition while also optimising the combustion temperature, helping to ensure that destruction efficiencies are met (Figure 5). Altogether, a NOxSTAR VC System can attain NOX emissions as low or lower than 0.02 lb/million Btu in most applications whereas traditional VCUs may only achieve NOX emissions down to 0.12 – 0.15 lb/million Btu. Like traditional VCUs, the high heat capacity and significant turndown of the system often allows multiple types of streams to be combined into a single end control device. This can eliminate the need to stage multiple end control devices, making regulatory compliance testing much easier, all while achieving the same performance standards.

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Figure 5. NOxSTAR VC System.

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The versatility of this technology also extends itself to multiple fuel gas types and many services including ship/barge loading, truck/railcar loading, and tank venting applications across crude, refined, petrochemical, and renewable product markets alike. Understanding that operational personnel in these markets place an extremely high demand on the safety and availability of the vapour control system, the NOxSTAR VC System design places a similarly high priority on achieving these goals. John Zink employed computational fluid dynamics (CFD) analyses to help ensure even burner duct distribution and system self-diagnostics to avoid operation in unsafe conditions. Implemented for decades now, users of traditional vapour combustion systems have come to depend on their end control device to be there when it is needed because, simply put, they just run. Among many others, some of the more common features and benefits include the fact that they are proven in a multitude of services and applications, they can handle a wide range of process conditions, they do not require special fluids or materials, and they completely hide the flame while combusting hydrocarbons in a safe and controlled manner.

Conclusion Due to several potential technical or commercial constraints, vapour recovery technology cannot be universally employed to control VOC emissions. The system discussed in this article is a robust solution and a logical choice for applications requiring low NOX and high destruction efﬁciency (less than 0.02 lbs NOX/million Btu, less than 0.015 lbs CO/million Btu, and destruction efﬁciencies of up to 99.99%).

Reference 1.

https://www3.epa.gov/ttncatc1/dir1/fnoxdoc.pdf

Enver Karakas and Stephen Ross, Elliott Group, USA, discuss how the use of cryogenic liquid expanders in gas liquefaction enhances plant efficiency.

iquefaction is the preferred method for efﬁcient transport and storage of compressible gases. Storage of LNG requires cooling the gas to cryogenic temperatures under atmospheric pressure. To illustrate the difference liquefaction makes, methane in a liquid state under atmospheric pressure has a density of 428 kg/m3 at a cryogenic temperature of -165°C (-265°F). This is about 600 times greater than methane in a gaseous state under atmospheric conditions (20°C, 1 atm). For a given

volume of a storage tank or transportation tanker, this equates to 600 times more mass of methane. High-pressure liqueﬁed gas was conventionally expanded using a Joule-Thomson (JT) throttling valve to reduce the ﬂuid pressure to an acceptable level. Replacing the traditional JT valve with a cryogenic liquid expander can increase LNG production. For this reason, cryogenic liquid expanders are an important part of every new LNG liquefaction plant, and are widely used in single-phase

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applications to enhance the overall efﬁciency of the LNG liquefaction process.

Background In principle, gas liquefaction is a refrigeration process based on the Carnot cycle, first described by French physicist Sadi Carnot in 1824. Carnot discovered that the efficiency of a heat engine depends upon its input and output temperatures. The lower the final resultant temperature, the lower the Carnot efficiency will be, as more energy input is necessary to achieve the end temperature. Consequently, more energy input is required to reduce the temperature of a fluid by one degree at a relatively lower temperature than is required to achieve the same reduction at a relatively higher temperature. When applied to a gas liquefaction process, the Carnot efficiency of the process is proportionally lower for fluids having a lower liquefaction temperature since more energy input is required. In 1895, German engineer Carl von Linde invented the first continuous process for gas liquefaction. This process was based on repeating the cycles of gas compression, pre-cooling of the compressed gas in a heat exchanger, and expansion of the

Table 1. Comparison of outlet process conditions for JT valve vs cryogenic liquid expander Process inlet condition (typical) Mass flow rate (million tpy)

Mass flow rate (kg/hr)

342 466

Inlet temperature (˚C)

-160

Inlet pressure (barG)

100

Inlet pressure (MPaA)

10.1013

(kg/m3)

429.07

Inlet density

Inlet enthalpy (kJ/kg)

19.95

Process outlet condition (typical) JT valve (enthalpy is constant)

Liquid cryogenic expander

Outlet pressure (barG)

1.5

Outlet pressure (MPaA)

0.251

Outlet temperature (˚C)

-155.85

-161.45

Isentropic efficiency

85%

Outlet enthalpy (kJ/kg) 19.95

0.323

∆ enthalpy (kJ/kg)

19.63

0 3

Outlet density (kg/m )

414.1

422.5

Total isentropic power (kW)

1867

Generator outlet power (ekW)

N/A

1755

Total efficiency (%)

Additional cooling with expander (˚C)

5.6

∆ density (kg/m3)

8.35

Amount of production grain

July 2021 58 HYDROCARBON ENGINEERING

compressed pre-cooled gas across a JT throttling valve. This process yields the desired result, but unfortunately consumes a high amount of energy, making it commercially unattractive. The main purpose of cryogenic liquid expanders in a natural gas liquefaction process is to further reduce the temperature of the liquefied gas without going through the Carnot refrigeration process. Cryogenic liquid expanders extract the internal energy of the process fluid by expanding the liquid from high pressure to the required low pressure. During this process, the cryogenic expander converts the static pressure energy to kinetic fluid energy, and further into mechanical torque and electrical energy/work where it is ultimately removed from the system. With the extraction of work from the cryogenic fluid in the form of electrical energy, the thermodynamic internal energy (enthalpy) is reduced, resulting in a lower discharge temperature.

JT throttling valves vs cryogenic liquid expanders As previously discussed, LNG liquefaction requires that high pressure is reduced by expansion to an acceptable storage pressure. LNG storage tanks are not designed to withstand pressures over 300 – 400 mbarG. Storage tanks are very large in size compared to a typical cryogenic pressure vessel, and can have an average height of 40 m with an internal diameter in excess of 100 – 200 m. Once the process gas is liquefied, the pressure must be reduced so that it can be safely stored without impacting the integrity and the construction of the large storage tanks. Prior to the development of liquid cryogenic expander technology, process pressure was reduced via JT throttling valves. During expansion through the JT valve, unlike with expanders, there is no change to the thermodynamic internal energy (enthalpy). This process is called isenthalpic expansion in thermodynamics. For liquefaction of hydrocarbons, such as methane, propane, and butane, it was not until 1995 that the first generation of liquid cryogenic expanders were implemented.1 A liquid expander works similarly to a gas expander. Both gas and liquid expanders reduce the enthalpy of the fluid, one in the gaseous phase and the other in the liquid phase. With the reduction in enthalpy, the fluid temperature is reduced even further, which helps the refrigeration. The output is a more condensed and denser fluid. Table 1 shows the expansion process of pure methane prior to entering the storage tank in an LNG liquefaction plant with total process flow of 3 million tpy. The table compares expansion via the JT valve vs a cryogenic liquid expander. Liquid expanders can have 81 – 89% isentropic efficiency.2 A production gain of 2% is calculated for the complete liquefaction process based on the lower temperature attained by the liquid cryogenic expander, which operates at 85% isentropic efficiency. This equates to a total production gain of 60 000 tpy of additional methane for a 3 million tpy liquefaction plant. Figure 1 is the pressure vs enthalpy plot for pure methane. It shows the expansion process based on the inlet and outlet conditions listed in Table 1. Figure 1 shows the temperature and enthalpy reduction across the liquid expander. In addition to the LNG production increase, cryogenic liquid expanders provide the benefit of electrical power generation. Table 1 shows that for every 3 million tpy of pure

methane production capacity, 1.755 MW electrical power can be recovered. In comparing liquefaction plants with and without liquid expanders, the main differences are as follows: In a new plant, for a given liquefied gas output production, the liquid expander allows for installation of less power generation, smaller gas compressors (propane, ethylene, methane, or mixed refrigerant depending on the liquefaction process), smaller gas expanders, and smaller heat exchangers. In an existing plant – or a new plant with given sizes of power generation, gas compressors, gas expanders, and heat exchangers – the liquid expander increases the liquefied gas output production.

Expander design concept The high-pressure liquid stream at the end of the traditional liquefaction process enters into the pressure vessel of the liquid expander, passes through each hydraulic component, and exits under low pressure through the top section, as shown in Figure 2. The hydraulic assembly consists of three stages, each with fixed geometry nozzle vanes and a radial inflow Francis-type reaction turbine runner. The nozzle vanes convert the fluid’s static pressure energy into rotational kinetic energy, and the runner converts the resulting rotational energy into shaft torque. The electric generator and the hydraulic assembly are mounted on a common shaft. The generator converts the shaft torque into electrical power. The generator is submerged to the process fluid to eliminate the need for a mechanical shaft seal and electric generator hazardous area certifications. Since there is no oxygen within the process fluid, there is no possibility of igniting the highly explosive fluid. Cryogenic power cables transmit the electrical power from the generator to the external power grid.

Figure 1. Pressure vs enthalpy (P-h) plot of pure methane, showing

expansion via a JT valve and liquid expander for comparison purposes.

Conclusion Cryogenic liquid expanders can improve a liquefaction plant’s process efficiency and production rate. They allow for a 2 – 3% production gain and should be considered for all new and existing plants.3 Existing liquefaction plants that use older technology can also benefit from an expander retrofit as lower production costs will enable these plants to remain competitive with the newer installations currently operating or under construction. The production costs for liquefied gas are invariably lower with a liquid expander than without one.

References 1.

Figure 2. Elliott typical three-stage upward flow cryogenic liquid expander.

July 2021 60 HYDROCARBON ENGINEERING

2. 3.

VERKOEHLEN, J., ‘Initial Experience with LNG/MCR Expanders in MLNG-Dua,’ Proceedings GASTECH 96, Volume 2, Vienna, Austria, (December 1996), ISBN 1874134162. KARAKAS, E. ‘Turbine Specific Speed,’ LNG Industry, (December 2015). KIKKAWA, Y. and KIMMEL, H. E., ‘Interaction between Liquefaction Process and LNG Expanders,’ Proceedings 2001 AICHE Spring National Meeting, Natural Gas Utilization Topical Conference, Houston, Texas, US, (April 2001).

Vincent Higelin, Fives Cryomec AG, Switzerland, discusses two factors that should be considered while designing LNG installations with cryogenic pumps.

ost issues that can occur in LNG cryogenic pumps are the result of cavitation, which is primarily caused by an insufﬁcient net positive suction head (NPSH) and ﬂuid shocks. Experience shows that the second factor is due to inadequate pump cool-down procedures and installations. Understanding these two problems is essential to prevent cryogenic pumps failure and improve their reliability for end users and operators.

Insufficient NPSH The NPSH is an important topic for cryogenic ﬂuids, especially LNG, which have boiling points of less than -150˚C. The NPSH can be deﬁned as the difference between the pressure of the liquid gas under normal vapour pressure and the actual pressure at the pump inlet. This difference is the liquid head, less the losses due to heat generated and of pressure through the piping, valves, etc. It often happens that the NPSH

available on-site is not sufficient for the pump to operate. In summary: NPSH(a) = subcooling of the liquid which is provided for the pumping system (a = available). NPSH(r) = necessary subcooling that a pump needs to prevent any cavitation (r = required). Both cavitation and fluid shocks can be direct evidence of a lack of NPSH at the pump inlet. Consequently, the higher the NPSH requested by the pump is, the higher the risk of cavitation problems (which affect the lifetime of the pump) and fluids shocks when the pump is rotating at high speeds with the presence of gas bubbles. These fluid shocks can cause shaft deformation and failure as well as impeller damage. These problems are particularly dangerous when the pump is used for LNG applications. In short, cryogenic pumps can normally work only when the NPSH is sufficient. When there is a lack of NPSH at the pump HYDROCARBON 61

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inlet, cavitation will become evident and a distinctive noise will be heard. This noise increases when cavitation gets stronger. In general, this noise is also accompanied by vibrations, which tend to unbalance the shaft and cause faster wear and tear on parts, including motor bearings.

Figure 1. Standard inducer.

Therefore, cavitation can also have other immediate negative consequences on pumps, such as vibration and instability.

How to decrease the NPSH requested by a pump The first step is to install a standard inducer at the suction, which will improve the velocity distribution to the impeller. The conventional inducer will improve the NPSH(r) of the pump by about half, but for some applications, such as distribution and process pumps, this device is not sufficient to provide adequate protection against cavitation, loss of prime, and fluid shocks. Fives Cryomec AG’s Cryomec® Supercharger helps to bring NPSH(r) close to 0. This has been achieved following intensive hydraulic research and testing with liquid nitrogen. The technology provides a velocity distribution that remains constant with practically no turbulence. The flow changes direction due to centrifugal forces and moves smoothly through the spiral channels of the Cryomec® Supercharger. This is different from using a conventional inducer where the pumped liquid suffers turbulence (which may lead to gas bubbles in front of the pump). A standard inducer is shown in Figure 1. Under cavitation condition, the gas bubbles are accumulating at the front of the inducer (turbulence area in light blue) as the cross-section area of flow is reduced (white arrow). In front of the inducer, the volume (Va) is large between the pump suction flange and the inducer, thus reducing the NPSH(a). As cryogenic pumps cannot be operated under cavitation, there will be a premature wear on the pump parts. Under the same condition, if the pump is equipped with the Cryomec® Supercharger (Figure 2), it allows a better aspiration towards the impeller as the flow is continuously aspirated into it (larger cross-section area of flow: white arrow). The conical shape optimises the flow direction and head losses are reduced within this technology compared with the inducer. Moreover, as the ‘dead’ volume (Vb) in front of the Cryomec® Supercharger is significantly reduced, there is no accumulation at the front of the device. Thanks to this device, which is available for single-stage pumps, priming is easier, and the pump lifetime will be enhanced. Moreover, it helps to reduce installation costs as elevated tanks are not required. To conclude, the NPSH(a) (available from the tank for the pump) must be present inside the inducer and impeller: [NPSH(a) > NPSH(r)] both before the pump start and during the pump priming. In addition, it must always be kept for a smooth running.

Inadequate installations and pump cool-down procedures

Figure 2. Cryomec® Supercharger.

July 2021 62 HYDROCARBON ENGINEERING

Pumps for cryogenic liquids, especially LNG pumps, are generally considered to be delicate to operate, and an efﬁcient cool-down requires detailed and critical procedures. Pump failures due to the cool-down procedure can lead to major problems and cause safety concerns for end users and operators. There are various points associated with the piping design and operation of cryogenic pumps. Therefore, it is important to check the following parameters: What is the length of the suction line to the tank?

Is the return gas line connected upwards to the tank without syphon? Is there piping stress in hot or cold conditions? Is there enough slope for the suction vent and bypass lines? Is the minimum pump cool-down time followed, including the entire suction line cool-down?

Best practices to minimise risks of pump failures: configuring the lines In any case, it is important to properly cool-down the cryogenic pump before start-up with the best configuration for the lines. The suction line is of particular importance as it is the most frequent cause of priming and pumping difficulties. The suction line must never be horizontal. It must always have a continuous slope, either upward or downward from the storage tank to the pump, with the pump located as near to the supply tank as possible. The line size is also important. A line that is too small will create excessive friction loss, while a line that is too large will unnecessarily increase the heat inleak. The suction line must be as short as possible, well insulated, and sharp bends should be avoided. On the contrary, its diameter should be as big as the pump inlet, or slightly bigger. A strainer or filter should also always be used in the suction line to ensure an extended pump lifecycle and to minimise the danger of accidents due to contamination, particularly in LNG systems. Additionally, the suction line must be equipped with a pressure relief valve (safety valve) to prevent any possible damage to the pump and its

shaft sealing system, due to excessive suction pressure. It is important to ensure that all piping lines are adequately supported, and it is essential to install compensators or ﬂexible lines at the pump ﬂanges. The bypass and return gas lines must never be horizontal or have a downward slope. They should always have a continuous upward slope from the pump so that there can never be any low points in which gas can be trapped and create a liquid lock.

Figure 3. Example of an LNG loading system with manual valves.

Figure 4. Example of a Cryomec VSMP with the three-way valve (PV 20).

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The ideal slope for these lines is approximately 100% (45˚) with 10% (approximately 5˚) recommended as minimum. Piping stress can be avoided or reduced through the installation of ﬁx points. A pipe ﬁxed point is a very rigid support (without any elasticity) blocking the pipe in the three axes (clamping capable of sliding on the pipe is forbidden).

Case study As mentioned previously, experience shows that the majority of problems are caused by an inadequate pump cool-down procedure and, sometimes, by operators failing to ensure that the pump has been fully primed. For this reason, systems that automate the pump cool-down priming have huge operational advantages, especially if such systems are competitive compared to an installation designed for manual operation. Fives Cryomec AG has developed a system incorporating an optimised three-way valve, which operates automatically. This valve is directly mounted on a skid after the pump outlet. Figure 3 shows an example of an LNG loading system with manual valves. Prior to start-up, it is important to check that the discharge valve 7 on the discharge line is completely closed and reduce the opening of the bypass valve 10, so that during start-up the pump is at minimum ﬂow and not at full ﬂow. When the pump has started up, it is mandatory to regulate the discharge pressure to the value required by adjusting the bypass valve 10.

Once the pump ﬂow rate has been established, the ﬂow is switched to the delivery line by opening the discharge valve 7, while at the same time closing the bypass valve 10. The opening and the closing of valves on a cryogenic centrifugal pump installation must always be slow and gradual (approximately 5 sec.). Figure 4 presents an example of an LNG loading system with the three-way valve (PV 20). The discharge valve 7 and the bypass valve 10 are replaced by one single pneumatic valve, PV 20, which is automatically controlled by the temperature sensor TE3 (PT100 used for cool-down supervision). To conclude, the manual operation of discharge and bypass valves for pump cool-down and priming is eliminated, which avoids any possibility of abnormal pump failure due to an operator’s error.

Conclusion The elements detailed in the article show that many parameters have to be taken into account to avoid premature wear, gas development, instability, and vibrations in cryogenic pumps, especially for LNG applications. The Cryomec® Supercharger developed by Fives Cryomec AG, Fives a Group subsidiary specialised in the design, manufacture, and maintenance of cryogenic pumps, has proven reliable to ensure safe functioning of the pump for operators and end users alike.

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Hydrocarbon Engineering July 2021 issue

Articles inside

Vapour control options

Expanding LNG options

Embracing biology

Optimising LNG installations

Advanced column internals for fouling towers

It’s cool

Removing the ‘art’ from state-of-the-art

Mercaptan scavenging revisited

SRU thermal stage revamps

Eco-friendly corrosion control

The ins and outs of corrosion studies

World news