North American edition of Tank Storage Magazine by Tank Storage Magazine

North America Edition | Nov 2021 | Volume 17 | Issue 05

BUILDING FOR THE FUTURE

THE COST OF NATURAL DISASTERS

CURBING THE COMPETITION:

Max Midstream’s CEO reveals plans to turn the Port of Calhoun into a rival for Houston and Corpus Christi

Find out about the latest updates coming to API 656 for operations during uncontrollable natural disasters

We take a closer look at Mexico’s fuel import changes and the implications for importers

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UP FRONT CONTENTS

CONTENTS North America Edition | November 2021 | Volume 17 | Issue 05 TERMINAL NEWS 06 North America

19 Tank terminal update

EXCLUSIVE INTERVIEWS 24 Building for the future Max Midstream CEO Todd Edwards tells Tank Storage Magazine about plans to turn the Port of Calhoun into a rival for Houston and Corpus Christi, and the sustainable focus 26 Branching out into renewables US industry infrastructure and supply chain services company Savage continues to grow and diversify after 75 years in business 29 From lasers to tanks Kathryn Clay explains how a love of energy policy led her to the top of ILTA

MARKET ANALYSIS 30 US oil prices tied to two giants: OPEC+, COVID-19 Paul Wiseman looks at what’s driving the latest trends 32 Crunch time US shale drillers keep their powder dry for now, but it remains unclear how they’ll respond in 2022 as the declines in drilled but uncompleted wells (DUCs) and inventories come to bear 34 The outlook for oil storage in a lower carbon economy Columbia University’s Antoine Halff examines the effect of changing policies under the Biden administration

36 Curbing the competition: Mexico’s fuel import changes Eduardo Lopez looks at the implications for importers 38 ILTA adopts – and acts on – ESG principles Kathryn Clay, president of ILTA, looks at new ESG principles and the impacts of fire-fighting foam regulatory changes in the US

TECHNICAL FEATURES 40 The cost of natural disasters Philip Myers and Earl Crochet run through the latest updates coming to API 656 – Aboveground storage tank operations during uncontrollable natural disasters

42 Faster, better, cleaner. How one Canadian company reduced the time required to clean a tank from three months to three weeks 44 Overfill prevention Emerson’s Richard Ireland runs through updates to the API 2350 standard for overfill prevention of atmospheric storage tanks 46 The hazards of petroleum Wayne Geyer looks at the variety of causes in tank fires and explosions, and the importance of awareness 49 Turning sludge into profit HydroCarbon Solutions’ tank cleaning technology generates useable oil from tank sludge 51

Advocating for risk-based inspections in the US Ingrid Pederson looks at the drawbacks of time-based inspections and the improvements gained by switching to risk-based inspections

53 Tank foundation settlement tolerance Atlas Geotechnical’s Doug Schwarm provides a case study on tank settlement from Port Moody in Canada

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UP FRONT CONTRIBUTORS

CONTRIBUTORS North America Edition | November 2021 | Volume 17 | Issue 05

PUBLISHER

CEO EASYFAIRS UK & GLOBAL

Margaret Dunn +44 (0)20 3551 5721 margaret@tankstoragemag.com

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DEPUTY EDITOR Helen Tunnicliffe +44 (0)20 3196 4402 helen@tankstoragemag.com HEAD OF SALES Sophie McKimm +44 (0)20 3196 4356 sophie.mckimm@easyfairs.com

North America Edition | Nov 2021 | Volume 17 | Issue 05

BUILDING FOR THE FUTURE

THE COST OF NATURAL DISASTERS

CURBING THE COMPETITION:

Max Midstream’s CEO reveals plans to turn the Port of Calhoun into a rival for Houston and Corpus Christi

Find out about the latest updates coming to API 656 for operations during uncontrollable natural disasters

We take a closer look at Mexico’s fuel import changes and the implications for importers

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model in sub-saharan africa. introducing the independent storage Oiltanking matola explains how it is

as it explores gas storage. is ensuring greater energy security The sharjah national oil corporation

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IN A CAPTIVE MARKET AN INTERNATIONAL CONCEPT

NEW GAS CHAPTER SPEARHEADING THE UAE’S

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ISSN 1750-841X Aug / Sep 2019 | Volume 15 | Issue 04

Tank Storage Magazine, (ISSN 1750-841X) is published seven times a year (in February, March, May, August, September, October and November) by Easyfairs UK Ltd, 2nd Floor, Regal House, 70 London Road, Twickenham, TW1 3QS, UK. The US annual subscription price is $243. Airfreight and mailing in the USA by agent named WN Shipping USA, 156-15, 146th Avenue, 2nd Floor, Jamaica, NY 11434, USA. Periodicals postage paid at Jamaica NY 11431. US Postmaster: Send address changes to Tank Storage Magazine, WN Shipping USA, 156-15, 146th Avenue, 2nd Floor, Jamaica, NY 11434, USA. Subscription records are maintained at Easyfairs UK Ltd, 2nd Floor, Regal House, 70 London Road, Twickenham, TW1 3QS, UK.

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TERMINAL NEWS

US$4.5 BILLION CLEAN HYDROGEN HUB TO BE BUILT IN LOUISIANA US industrial gas company Air Products is to build a US$4.5 billion (€3.9 billion) blue hydrogen clean energy complex in Ascension Parish, Louisiana, US. The complex, which will be built, owned, and operated by Air Products, will produce more than 750 million scfd of blue hydrogen from natural gas, capturing around 95% of the produced CO2 for permanent storage. Some of the hydrogen produced will be compressed for supply to Air Products’ customers on the US Gulf Coast, via its existing pipeline network. The rest will be used to make blue ammonia for transport around the world, for conversion back into hydrogen. The co-products – liquid nitrogen, liquid oxygen and liquid argon –will also be supplied to customers around the world. The CO2 captured at the facility will be compressed and transported via pipeline to a number of inland sequestration sites, where it will be stored in geologic pore space around 1 mile (1.6 km) below the surface. Air Products has received approval from the Louisiana State Mineral and Energy Board, part of the Louisiana Department of Natural Resources, for the permanent sequestration of the CO2. The project will generate 2,000 construction jobs over three years and 170 permanent jobs, with an expected annual payroll of US$15.9 million. The project is Air Products’ largest ever investment in the US. ‘This is a major industrial investment that will create quality manufacturing

PAGE 06

jobs while limiting environmental impacts, a goal envisioned by my Climate Initiatives Task Force. Carbon capture and sequestration are important to Louisiana’s efforts to reduce carbon dioxide emissions while maintaining jobs and growing our manufacturing base. This project is a clear demonstration of our ability to grow the Louisiana economy while lowering the carbon footprint of industry,’ says Louisiana Governor John Bel Edwards, who announced news of the project alongside Air Products chairman, president and CEO Seifi Ghasemi. Air Products is also building a net zero hydrogen complex in Edmonton, Canada, and a green ammonia production facility joint venture in NEOM, Saudi Arabia powered by renewable energy. ‘In addition to our leadership in grey hydrogen, our Canada project and this Louisiana project make us the leader in blue hydrogen. We also will be the world leader in the production and supply of green, carbon-free hydrogen when the NEOM Project comes onstream. The energy transition will occur in stages, and the megaproject we are announcing today in Louisiana will help the state meet its ambitious goals while providing new sources of blue products for customers in the US and around the globe,’ says Ghasemi. Hydrogen as potential fuel of the future seems to be gaining momentum globally, as governments and companies seek to meet climate targets. Earlier in October 2021, Exolum announced it would build a €2 million green hydrogen production plant near Madrid in Spain, using Fusion Fuel technology, while BP is considering producing green hydrogen at its Kwinana refinery site, which is shutting down. BP is also planning a 1 GW blue hydrogen plant in the UK. The Port of Rotterdam Authority, Koole Terminals, Chiyoda Corporation and Mitsubishi Corporation

are carrying out a feasibility study into commercial-scale hydrogen imports. In the US, clean infrastructure firm Bakken Energy bought the assets of the Dakota Gasification Company (Dakota Gas), including the Great Plains Synfuels Plant in North Dakota, US, from Basin Electric, to form a hydrogen hub.

CALUMET AWARDS SEVEN-TANK CONTRACT TO MATRIX US speciality petrochemicals producer Calumet Specialty Products Partners has awarded a contract for the engineering, fabrication and construction of seven new renewable diesel storage tanks in Great Falls, Montana, US, to Matrix Service. Calumet is developing a renewable fuel plant at its Great Falls site, which is expected to be operational in Q2 2022. The new tanks will support the production of up to 12,000 bpd of renewable diesel from soybean oil feedstock. Engineering for the tank project will be carried out by Matrix Service’s sister company, Matrix PDM Engineering. ‘We are excited to help lead the North America’s energy transition in Montana, the Pacific Northwest, and western Canada. This project will help diversify our nation’s energy sources and reduce our carbon footprint immediately,’ says Bruce Fleming, executive vice president of Calumet. ‘We are pleased to have Matrix Service provide the engineering, fabrication, and construction of our renewable storage tanks for this critical infrastructure project.’

TERMINAL NEWS

VOPAK OPENS GULF COAST INDUSTRIAL TERMINAL Vopak has opened a new industrial terminal on the US Gulf Coast to serve Gulf Coast Growth Ventures (GCGV), a joint venture by ExxonMobil and SABIC for a worldscale plastics facility in San Patricio County, Texas, US. The new terminal, which is 100% owned and operated by Vopak, has a total capacity of 144,000 m3. It is connected to the petrochemical complex by pipelines. The terminal has a 20-year commercial agreement in place.

The multibillion-dollar GCGV project will make use of low-cost US gas. A cracker will produce 1.8 million tpa of ethylene from ethane, which will feed a monoethylene glycol unit and two polyethylene units. Construction began in Q3 2019 and the facility is expected to start up in 2022. ‘We are very excited to have successfully and timely delivered this new industrial terminal to support GCGV in the US. This new terminal fits well into our growth strategy for industrial terminals,’ says Eelco Hoekstra, chairman and CEO of Royal Vopak. ‘We are proud of our expertise and long track record of storing vital products. We have high standards on safety and environmental care and we are looking forward to being part of the Coastal Bend community.’

HOWARD ENERGY PARTNERS NAMED ‘MOST IMPROVED’ BY GRESB US midstream company Howard Energy Partners (HEP) has been named as the ‘most improved’ in the GRESB 2021 Infrastructure Assessment. GRESB (formerly Global Real Estate Sustainability Benchmark) is an index which assesses the environmental, social and corporate governance (ESG) performance of assets including buildings and infrastructure. It is one of the world’s leading sustainability benchmark, used as a comparison tool by investment funds to rate the quality of their investments regarding sustainability. HEP’s assets include natural gas and crude oil gathering and transportation pipelines, natural gas processing plants, liquid storage terminals, deep-water dock and terminal facilities, and rail, terminal and transloading facilities in Texas, New Mexico, Oklahoma, and Pennsylvania in the US and in Mexico.

PAGE 8

TERMINAL NEWS Brandon Burch, executive vice president and chief operations officer of HEP says that the company is proud of the GRESB recognition as it is testament to the company’s ongoing efforts to provide clean, reliable energy. ‘We are proud to celebrate the achievements made by this year’s Most Improved organisations. Your dedication to advancing ESG transparency and performance is helping accelerate the whole industry’s progress towards a more sustainable world,’ says Sebastien Roussotte, CEO of GRESB. ‘ESG transparency and improved performance have never been more important, and it is inspiring to see such a high level of dedication from the industry, particularly when so much has been disrupted by the pandemic this last year.’

REGEN III READY TO PROCEED WITH RE-REFINERY AT OILTANKING GALVESTON US cleantech company ReGen III is to begin front end engineering and design (FEED) work for a used motor oil re-refinery at Oiltanking Galveston County Terminal in in Texas City, US. Oiltanking North America has issued a letter of readiness (LOR) to ReGen III to proceed after the successful completion of work on the pre-FEED/front-end loading (FEL-2) validation. Oiltanking is expecting the final independent report from its engineers, Burns & McDonnell, within the next week, and the LOR states that it will be ready to move to FEED on 18 October 2021. The re-refinery will take used motor oil and re-refine it into clean base oils for the domestic market. The process removes soluble and insoluble impurities to make a final product at least equal in quality to virgin base oils. The process uses less energy than crude oil refining. Oiltanking North America and ReGen III signed a non-binding letter of intent to build the re-refinery in July 2021, with Oiltanking agreeing to lease land at its Galveston County Terminal, and design, construct, and operate storage tanks, loading and unloading pipelines, rail and marine loading and unloading facilities and other logistics assets for the re-refinery.

and other logistics assets. Oiltanking will be responsible for designing, constructing, operating and maintaining the logistics assets. ReGen III and Oiltanking are working towards finalising and signing the longterm ground lease and the site services agreement. ‘As one of the largest independent tank storage providers for gases, chemicals and petroleum products in the world, Oiltanking is successfully active in the engineering, procurement and construction of tank terminals. Our experienced team is working closely together with ReGen III on a tailor-made and cost-effective infrastructure solution for their re-refinery facility at our terminal in Texas City. We look forward to advancing the project as it will provide a much-needed domestic supply of base oils recycled from used motor oil thus, strengthening the circular economy,’ says Dan Withers, director, business development at Oiltanking.

SENTINEL AND EXXONMOBIL FORM HOUSTON PIPELINE JV Sentinel Midstream Texas and ExxonMobil Pipeline Company have formed a joint venture, Enercoast Midstream, to operate crude oil pipelines and transport infrastructure in Houston, US. Enercoast will provide the ‘last-mile link’ for crude, including from the Permian and Gulf of Mexico, into the Houston crude oil market. Sentinel will be the operator of the JV, and has contributed cags for a majority equity position. ExxonMobil meanwhile has contributed a 16” pipeline originating at Webster Terminal with delivery points at ExxonMobil’s Baytown Refinery and Seabrook export terminal,

and a 20” crude pipeline with access to Moore Road station. Sentinel says that it will work to commercialise capacity on the Enercoast system and increase its operating footprint by building or acquiring new pipelines. Tariffs are available on the Sentinel website. ‘We are extremely pleased to establish a joint venture with ExxonMobil to maximise the potential of Enercoast,’ says Jeff Ballard, president and CEO of Sentinel. ‘Sentinel looks forward to the opportunity to serve ExxonMobil and other shippers in the Houston market.’

SUNOCO COMPLETES NUSTAR AND CATO ACQUISITIONS US fuel distributor Sunoco has successfully completed the acquisition of eight refined products terminals from NuStar Energy and Cato, for which it paid US$255.5 million (€215.1 million). The deals to buy the terminals were first announced in August 2021 and were expected to close by the end of the year. Sunoco says it funded the acquisitions with cash on hand and through its revolving credit facility. From NuStar, Sunoco bought the Blue Island terminal in Illinois, Andrews Air Force Base, Baltimore and Piney Point in Maryland, Jacksonville in Florida, Linden and Paulsboro in New Jersey, and Virginia Beach in Virginia. The combined storage capacity of the terminals is 14.8 million bbl. From Cato it bought the 140,000 bbl terminal in Salisbury, Maryland, which and stores gasoline and distillate. ‘These accretive acquisitions significantly expand SUN’s midstream business and enhance its platform for fuel distribution growth,’ Sunoco says in a statement.

The FEL-2 pre-feasibility study aimed to develop cost and schedule estimates, and make any critical decisions that will influence the final design of the storage tanks, loading/unloading pipelines, rail and marine loading/unloading facilities PAGE 9

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TERMINAL NEWS

SHELL CONSORTIUM CHOSEN FOR LIQUID HYDROGEN STORAGE DEMO A consortium led by a Shell subsidiary has been selected by the US Department of Energy (DOE) to demonstrate the feasibility of largescale liquid hydrogen (LH2) storage. The consortium comprises Shell International Exploration and Production, McDermott’s CB&I Storage Solutions, NASA’s Kennedy Space Center, GenH2 and the University of Houston. The DOE’s Hydrogen and Fuel Cell Technologies Office has asked the consortium to show that large-scale tanks, from 20,000-100,000 m3 in capacity, can be feasible and cost competitive at import and export terminals. The project will have a total budget of US$12 million (€10.3 million). DOE has awarded the consortium US$6 million, while Shell and CB&I Storage Solutions will each provide an additional US$3 million. Plans for the project include developing a concept design for the large-scale LH2 storage tanks, and engineering and building a scaled-down demonstration

tank to validate the feasibility of the design and the thermal model for commercial-scale design. The consortium partners each bring unique expertise to the project. Shell International Exploration and Production will provide guidance on hydrogen supply chain and safety. CB&I will advise on engineering, design and LH2 construction storage. GenH2 will design and manufacture one of the world’s most advanced thermal testing devices, known as Cryostat-900. The Kennedy Space Center already has the largest LH2 storage tanks in the world so NASA brings a wealth of experience, and will work with GenH2 on novel testing development. Academics from the University of Houston will develop detailed thermal models of the proposed insulation systems.

The technologies developed as part of the project, including insulation technology, cryogenic testing equipment and thermal model, are expected to have wider, long-term benefits for LH2 applications. The project will help to reduce the cost of clean hydrogen and advance its role in the energy transition, and eventually achieve a global clean hydrogen supply chain. ‘A cost-effective, long-range hydrogen supply chain can have a transformative impact in shaping a sustainable future for energy. Our consortium recognises that this project can become a cornerstone in making that future possible. It’s a sizable engineering challenge – but we have the right people, partners and outlook to deliver this first-of-its-kind LH2 storage technology,’ says Yuri Sebregts, chief technology officer for Shell.

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TERMINAL NEWS which is expected to be completed by Q1 2023, will be supported by the long-term commercial agreement with Neste. Neste will store feedstocks for renewable diesel, sustainable aviation fuel (SAF), polymers and chemicals, including used cooking oil (UCO), which it already collects from more than 40,000 US restaurants. The company has an option to further expand the facility if and when required. Neste says that the project will support a ‘more resilient, flexible and sustainable supply chain’, in turn supporting its growing production capacity to meet demand. In the longterm, the partnership with Kinder Morgan could improve the climate benefits and competitiveness of Neste’s products, due to more efficient, less carbon-intensive supply chain operations.

NEW BULK JET FUEL STORAGE FACILITY OPENS IN ST LOUIS

KINDER MORGAN AND NESTE JOIN FOR US RENEWABLE LOGISTICS

A new 3 million gallon (13.6 million L) bulk jet fuel storage facility has opened at St Louis Lambert International Airport (STL) in the US.

US energy infrastructure company Kinder Morgan and Finnish sustainable fuel and feedstock firm Neste are to develop a renewable raw materials supply hub at Kinder Morgan’s facility in Harvey, Louisiana, US.

The facility cost US$50 million (€43.1 million) and was designed and built by engineering firm Burns & McDonnell. It has three 1 million gallon aboveground storage tanks, an 11,000’ (3,353 m) underground fuel transmission pipeline with a leak detection system to deliver fuel to the terminal and five horizontal pumps capable of delivering 1,200 gallons of fuel per minute. The facility also includes a 4,300 ft2 operations building with a control room, offices and vehicle maintenance shop. STL invested an additional US$50 million in other fuelling infrastructure, including hydrant system improvements, a new emergency fuel shut-off system, a hydrant cart test facility, a truck load facility and parking, and new fuelling stations for ground service equipment. The new facility, which has space for an additional 1 million gallon tank, should that be required in future, is double the size of the previous facility, built 60 years ago. Rhonda HammNiebruegge, STL airport director, says that the new facilities will support future airport growth. PAGE 12

Kinder Morgan plans to modify 30 existing tanks, and pipelines, to create segregated storage for raw material for Neste. This will include installing a new boiler to heat tanks and railcars, and infrastructure improvements for rail, truck and marine movements. The work,

Jeremy Baines, president of Neste US says: ‘This clearly shows the positive role America’s existing energy infrastructure can play in creating a sustainable future and fighting climate change. Neste and Kinder Morgan are transforming existing terminal assets into what can be considered green infrastructure, which will ultimately enable more American businesses and cities to power their fleets and supply chains with renewable fuels and other products.’ Kinder Morgan and Neste have previously partnered for sustainable projects, with Neste supplying SAF to San Francisco International airport through a Kinder Morgan pipeline since 2020, more than 1 million gallons so far. Kinder Morgan says that the agreement shows its commitment to offering low-carbon infrastructure solutions. ‘As North America’s largest terminal operator with existing infrastructure including 80 million barrels of storage, 266 docks, 462 truck bays and 6,800 rail car spots, Kinder Morgan Terminals is uniquely positioned to play a leading role in the transition to renewable fuels,’ says John Schlosser, president of Kinder Morgan Terminals.

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TERMINAL NEWS

CHEVRON AND ENTERPRISE TO STUDY CCUS Chevron New Energies, part of US oil major Chevron, and a subsidiary of US midstream company Enterprise Products Partners are to jointly study business opportunities for carbon capture, utilisation, and storage (CCUS). The companies expect the initial phase of the study to last six months. They will evaluate possible CCUS projects that combine Enterprise’s extensive midstream pipeline and storage network with Chevron’s sub-surface expertise. ‘The joint study with Chevron is part of our growing focus on developing and utilising new technologies and leveraging our transportation and storage network in order to better manage our own carbon footprint and provide customers with new midstream services to support a lower carbon economy. Our success in upgrading and repurposing existing assets will be important to the success of any initiative we move forward with,’ says AJ ‘Jim’ Teague, co-CEO of Enterprise’s general partner.

The company immediately initiated its emergency response plan, which included contacting local emergency services. Royal Canadian Mounted Police (RCMP) Alberta, which was amongst the responders, tweeted that the fire had been contained to the tank farm site and that no residences were under threat. It recommended avoiding driving in the area due to smoke. Officers closed the nearby Highway 640 to allow access for emergency personnel and equipment. ‘The fire is out, and we are working with all appropriate authorities to investigate the cause. The safety of our employees, the public and the environment remain our top priority,’ Secure Energy said in its statement to Global News.

PHILLIPS 66 TO BUY PHILLIPS 66 PARTNERS US energy company Phillips 66 is to buy all remaining shares that it does not already own in midstream partnership Phillips 66 Partners. Phillips 66 set up Phillips 66 Partners to operate, develop and acquire primarily fee-based crude oil, refined petroleum products and natural gas liquids pipelines, terminals and other midstream assets. Following the transaction, expected to be completed in Q1 2022, Phillips 66 Partners will become a wholly owned subsidiary of Phillips 66 and will no longer be a publicly traded partnership. Phillips 66 says that the transaction will simplify the governance and corporate structure. The all-stock deal is worth US$3.4 billion, based on the closing price of the companies on 26 October 2021. For each share they hold, Phillips 66 Partners shareholders will receive 0.5 of a share of Phillips 66 common stock. ‘We believe this acquisition will allow both [Phillips 66] PSX shareholders and

FIRE AT SECURE ENERGY’S ALBERTA TANK FARM No casualties have been reported following a fire at Secure Energy’s Elk Point tank farm in Alberta, Canada on 23 October 2021. Secure Energy told Global News that the fire broke out at 2.35pm local time. PAGE 14

[Phillips 66 Partners] PSXP unitholders to participate in the value creation of the combined entities, supported by the strong financial position of Phillips 66,’ says Greg Garland, chairman and CEO of Phillips 66.

OPERATOR ERROR CAUSED US NAVY’S HAWAII TANK FARM LEAK The US Navy has completed an investigation into a leak from its Red Hill fuel tank storage facility in Hawaii on 6 May 2021 and found that it was caused by operator error. Red Hill consists of 20 underground fuel storage tanks, dating back to the 1940s, and there have been longstanding concerns about the integrity of the tanks, particularly as they sit above a drinking water aquifer. However, according to a statement released to AP by the US Navy, an investigation by the Naval Petroleum Office of the Naval Supply Systems Command found that the leak of 1,618 gallons (6,125 L) of jet fuel in May came from a pipeline, rather than the tanks. An operator did not follow the correct procedures to close fuel line valves during fuel transfer operations, causing a pressure surge in in the system, which blew out a part and resulted in the fuel release. In the statement to AP, Navy Region Hawaii said that all but 38 gallons of the spilt fuel had been recovered. The Red Hill storage tanks were undamaged during the incident and all have subsequently passed tank tightness tests. The Navy has now added additional safeguarding measures to prevent recurrence, such as requiring more system operators in the control room during fuel transfer procedures.

TERMINAL NEWS Inter Pipeline board. Brian Baker has been appointed as interim CEO while a permanent replacement is sought, and Paul Hawksworth has been appointed CFO.

ENBRIDGE COMPLETES MODA ASSETS ACQUISITION Canada

BROOKFIELD CLOSES INTER PIPELINE ACQUISITION Brookfield Infrastructure Partners has successfully completed its acquisition of Inter Pipeline. Shareholders representing 99.91% of Inter Pipeline shares approved the agreed arrangement in a meeting on 28 October 2021. After obtaining the necessary shareholder approvals, Inter Pipeline received a final order of the Court of Queen’s Bench of Alberta approving the arrangement.

For each Inter Pipeline share they hold, shareholders elected to receive either C$20 (€13.90) in cash, 0.250 of a class A exchangeable subordinate voting share of Brookfield Infrastructure Partners Corporation, 0.250 of a class B limited partnership unit of Brookfield Infrastructure Corporation Exchange Limited Partnership, or any combination. The takeover agreement was first announced in September 2021, after months of negotiations. Inter Pipeline shares will be delisted from the Toronto Stock Exchange on 1 November 2021. As previously announced, Christian Bayle, Inter Pipeline president and CEO, and Brent Heagy, CFO, have stepped down from their management positions and Bayle has also resigned from the

North American energy infrastructure company Enbridge has closed the acquisition of Moda Midstream Operating from Encap Flatrock Midstream for US$3 billion (€2.6 million). The deal was originally announced in September 2021. Enbridge now has a 100% operating interest in the former Moda Ingleside Energy Center (MIEC), now the Enbridge Ingleside Energy Center (EIEC). The deal also included the 350,000 bbl Taft Terminal, the 300,000 bpd Viola pipeline, and a 20% interest in the 670,000 bpd Cactus II pipeline. ‘The acquisition significantly advances the company’s US Gulf Coast export strategy and connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins,’ says Enbridge in a statement.

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PAGE 15

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TANK TERMINAL UPDATE

TANK TERMINAL UPDATE: NORTH AMERICA Texas, US

VOPAK Products: Petrochemicals Capacity: 144,000 m3 Construction/Expansion/Acquisition: Vopak has opened a new, 100% owned and operated, industrial terminal on the US Gulf Coast to serve Gulf Coast Growth Ventures, a joint venture by ExxonMobil and SABIC for a world-scale plastics facility in San Patricio County, Texas, US. Comment: The Gulf Coast Growth Ventures cracker will produce 1.8 million tpa of ethylene from ethane, to feed a monoethylene glycol unit and two polyethylene units. Construction on the facility began in Q3 2019 and it is expected to start up in 2022.

Montana, US

CALUMET SPECIALTY PRODUCTS PARTNERS Products: Renewable diesel Construction/Expansion/Acquisition: Matrix Service will build seven new renewable diesel storage tanks to support the production of up to 12,000 bpd of renewable diesel from soybean oil feedstock at Calumet’s new facility in Great Falls, Montana, US. Comment: Engineering for the tank project will be carried out by Matrix Service’s sister company, Matrix PDM Engineering.

SUNOCO Products: Refined products Capacity: 14.8 million bbl (NuStar) and 140,000 bbl (Cato) Investment: US$255.5 million (€215.1 million) Construction/Expansion/Acquisition: From NuStar, Sunoco bought the Blue Island terminal in Illinois, Andrews Air Force Base, Baltimore and Piney Point in Maryland, Jacksonville in Florida, Linden and Paulsboro in New Jersey, and Virginia Beach in Virginia. From Cato, Sunoco bought a terminal in Salisbury, Maryland.

Oklahoma, US

USD PARTNERS Construction/Expansion/Acquisition: USD Partners is to build a new pipeline connection to a second 300,000 bbl storage tank at a neighbouring third-party facility at its Stroud terminal in Cushing, Oklahoma, US. The increased connectivity will give the terminal better capability to serve multiple customers and multiple grades of crude oil simultaneously. Comment: The pipeline will be completed in Q1 2022.

GIBSON ENERGY Products: Crude oil and refined products Capacity: 435,000 bbl Construction/Expansion/Acquisition: Gibson Energy is to build a new 435,000 bbl tank at its Edmonton terminal in Canada.The Edmonton terminal currently has a total capacity of 1.7 million bbl. The new tank is expected to enter service in early 2023.

Products: Jet fuel Capacity: 3 million gallons (13.6 million L)

Construction/Expansion/Acquisition: A new bulk jet fuel storage facility has opened at St. Louis Lambert International Airport (STL), designed and built by engineering firm Burns & McDonnell. It has three 1 million gallon aboveground storage tanks, an 11,000’ (3,353 m) underground fuel transmission pipeline, five horizontal pumps, a 4,300 ft2 operations building and fuelling infrastructure which cost an additional US$50 million. Comment: The facility is double the size of the previous facility and has room for another 1 million gallon tank.

Texas, US

ENBRIDGE

PHILLIPS 66

Products: Crude oil

Products: Crude oil, refined petroleum product and natural gas liquids

Investment: US$3 billion (€2.54 billion) Edmonton, Canada

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Investment: US$50 million (€43.1 million)

Products: Crude oil US

St. Louis, US

Construction/Expansion/Acquisition: Enbridge has bought a number of storage and terminal assets from Moda Midstream and financer EnCap, including the 15.6 million bbl Moda Ingleside Energy Centre (MIEC), Flatrock Midstream, the 350,000 bbl Taft terminal, the 300,000 bpd Viola pipeline, and a 20% interest in the 670,000 bpd Cactus II pipeline. MIEC will be renamed the Enbridge Ingleside Energy Center (EIEC). Comment: Permits are in place at EIEC to increase the storage capacity to 21 million bbl and the export capacity to 1.96 million bpd.

Investment: US$3.4 billion (€2.91 billion) Construction/Expansion/Acquisition: Phillips 66 is to buy all remaining shares that it does not already own in Phillips 66 Partners, which it set up to focus on fee-based crude oil, refined petroleum products and natural gas liquids pipelines, terminals and other midstream assets. Comment: Following the transaction, expected to be completed in Q1 2022, Phillips 66 Partners will become a wholly owned subsidiary of Phillips 66.

PAGE 19

TANK TERMINAL UPDATE

Canada

BROOKFIELD INFRASTRUCTURE Investment: C$8.6 billion (€6.8 billion) Construction/Expansion/Acquisition: Brookfield Infrastructure has closed a deal to buy all remaining Inter Pipeline common shares for C$20/share and own 100% of the company, Comment: Brookfield initially launched a hostile takeover offer for Inter Pipeline in February 2021, which was rejected in favour of a rival offer from Pembina, before a new deal was reached.

for the storage of biodiesel, renewable diesel, and feedstocks, and two pipelines and related dock infrastructure, at its marine terminal in Geismar, Louisiana, US. Comment: The capacity will be used by IMT customer Renewable Energy Group (REG), which is expanding its nearby biorefinery to produce 340 million gallons of renewable diesel products annually, with completion due in 2023.

Illinois, us

HARVESTONE GROUP Products: Biofuels

Corpus Christi, US

PIN OAK CORPUS CHRISTI Products: Crude oil Capacity: 1.2 million bbl Construction/Expansion/Acquisition: Pin Oak Corpus Christi has completed a new pipeline connection and 1.2 million bbl of new tank capacity at its Taft terminal in Texas, US for Permian and Eagle Ford crudes. Comment: Pin Oak is now the only company in the Corpus Christi/Ingleside/Taft area that can offer customers direct access to the region’s Permian and Eagle Ford long-haul pipelines and to the Flint Hills Resources, Valero, and CITGO refineries.

Capacity: 400,000 bbl Construction/Expansion/Acquisition: Harvestone Group, a global commodity merchant focussed on biofuels, has bought Gateway Terminals in Sauget, Illinois, US on the banks of the Mississippi River. It is a multimodal terminal with truck, rail, and barge loading and unloading capabilities. Comment: Kevin Stewart, chief marketing officer of Harvestone, says that the acquisition will strengthen the company’s position in key supply chains.

BRENNTAG Products: Chemical solvents Construction/Expansion/Acquisition: German chemical and ingredients distribution company Brenntag bought North American solvents distributor Matrix Chemical, which operates storage tanks at bulk terminals in Houston in Texas, Chicago in Illinois, Vanport in Pennsylvania and Wilmington in North Carolina. Comment: Matrix serves industries including personal care, adhesives, and paint and coatings.

Louisiana, US

IMTT Products: Renewable feedstocks and products Construction/Expansion/Acquisition: IMTT will build six new storage tanks

PAGE 20

HOLLY ENERGY PARTNERS Products: Crude oil and refined products Capacity: 4.5 million bbl Investment: US$758 million Construction/Expansion/Acquisition: Holly Energy Partners (HEP) has bought Sinclair Oil Corporation’s integrated crude and refined products pipelines and terminal assets, including eight product terminals and two crude terminals, and more than 1,200 miles (1,931 km) of pipeline. HEP will also acquire Sinclair’s interests in three pipeline joint ventures – Powder Flats Pipeline, Pioneer Pipeline and UNEV Pipeline. Comment: HEP parent company HollyFrontier Corporation also bought Sinclair’s branded marketing business, renewable diesel business, and two refineries in the Rocky Mountains in the US for US$1.8 billion, forming a new parent company, HF Sinclair Corporation, to trade on the New York Stock Exchange.

Texas, US

ENTERPRISE PRODUCTS PARTNERS Texas, US

JEFFERSON ENERGY COMPANIES Products: 1.9 million bbl

Construction/Expansion/Acquisition: Jefferson Energy will build 1.9 million bbl of new storage capacity at its terminal on the Neches River, in ExxonMobil’s Beaumont, Texas, US refining complex, and five connecting pipelines to allow ExxonMobil to make better use of the existing marine infrastructure. Comment: The expansion work will increase the terminal’s capacity to around 6.2 million bbl.

Products: Ethylene Capacity: 308 million pounds (140,000 tonnes) Construction/Expansion/Acquisition: A subsidiary of US midstream company Enterprise Products Partners has bought Nova Chemicals Corporation’s ethylene storage business and trading hub in Mont Belvieu, Texas, US, the largest in the state, with a 308 million pound underground storage cavern. Comment: Chris D’Anna, senior vice president, petrochemicals of Enterprise’s general partner, says that the acquisition will complement the company’s growing ethylene network.

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PROFILE MAX MIDSTREAM

BUILDING FOR THE FUTURE Max Midstream CEO Todd Edwards tells Tank Storage Magazine about plans to turn the Port of Calhoun into a rival for Houston and Corpus Christi, and the sustainable focus THE TEXAN ports of Corpus Christi and Houston are hugely important for the export of many US products, but they are increasingly congested. Both are in built-up areas, so expanding to deal with the shipping traffic is difficult at best and impossible in most cases. In 2015, the US Army Corps of Engineers and the Calhoun Port Authority realised that the port at Point Comfort needed to be expanded. In 2020, the plans were authorised by Congress and signed into law. By deepening the Matagorda Ship Channel at Point Comfort, more products can be imported and exported, including concrete, fertiliser, chemicals, bauxite (the world’s main source of aluminium) and oil and gas, among other products. This will in turn lead to economic growth throughout the region and more jobs for local Texans. The only problem was how to pay for such an expansion. That’s where Max Midstream entered the scene. The Houston-based energy company agreed to pay for the construction of the widening and deepening of the channel and thus speed up the process. Why would a US midstream company pay for a general port expansion? Tank Storage Magazine spoke to Max Midstream president Todd Edwards to find out about the company’s plans for oil at the port, which form part of the wider export plans. ‘The Port of Calhoun is located halfway between Houston and Corpus Christi,’ says Edwards. ‘So, when the Army Corps approached the Calhoun Port Authority with a plan to expand this port so that all

PAGE 24

products can be shipped from there, we offered to pay for it.’ The Port of Calhoun has been in operation for around 50 years, but after a major operator pulled out, it has only been running at 30% capacity, so there is no congestion. As well as close proximity to various oil pipelines, the Port of Calhoun has other advantages over its more established neighbours. It is located in a rural area, giving lots of space for expansion, and is closer to deepwater. Edwards linked up with a London-based investor, Azad Cola, who agreed with Edwards’ analysis of the situation and came onboard. Max Midstream and Cola purchased the Seahawk pipeline and terminal in the port from Northstar Midstream, owned by Oaktree Capital, and from there secured an option on all of the land around the port. In December 2020 the US Congress passed the Army Corps’ plan to widen and deepen the port. Within 18 months, Edwards says, the port capacity will be the same as Corpus Christi and Houston and will allow Max

‘The market is going to dictate the direction and we’re going to be prepared for ESG when it becomes mandated, whether that’s in two years, or 20 years’

Midstream to export additional product, as it will be able to serve Aframax and Suezmax ships directly. The wider, deeper channels will of course also benefit the bulk carriers expected to be attracted to the port, which will be able to bring in much bigger freighters. Max Midstream has recently engaged Citibank as its advisor. ‘Citibank is probably the largest advisor in the world when it comes to this kind of work. Ports don’t just come along and to be able to take an existing port and transform it to an export terminal is exciting to everybody,’ says Edwards. EXISTING FACILITIES AND EXPANSION Currently, the Seahawk terminal has 600,000 bbl of storage and four 12” loading arms. Max Midstream is currently building an additional dock specifically for barges, and plans to expand the storage capacity by 2 million bbl. In addition to the Seahawk terminal, Max Midstream owns a 1.5 million bbl terminal in Edna, Texas, which connects directly to the Permian Basin and Eagle Ford oil fields, and is also connected directly to Port of Calhoun by 12” pipeline. This terminal will also be expanded by around 2 million bbl and Edwards says the designs are complete for the new tanks and additional lines to the port. ‘We have a partnership with Cola and we have a design that we’re going to implement that will allow us to secure

PROFILE MAX MIDSTREAM ‘There are major world banks heavily involved with us who are working with us on ESG, and they’re anxious to participate with us because we’re a new port and we can step right in with that. It’s a little expensive right now, there’s no question. As with anything else, when you talk about green, whether it’s building or anything associated with that, the costs are higher, but we want to be a part of it, and we want to be able to say that we are an ESG port,’ he says.

10 unit trains a week at the port. A unit train is 100 cars and each car holds 750,000 bbl. What we have then will be the opportunity to bring in Canadian oil down to Texas and export it from there,’ says Edwards. Max Midstream, in collaboration with Cola, is developing a 100-year plan for the Port of Calhoun, which as previously mentioned, doesn’t just include crude oil, but a variety of other products, to create a global industrial port. The rail opportunities will be key to this. ‘We’re the only port that will have rail capacity on the US Gulf Coast. We’re looking at running four loops around our facility that would give us 35-40 unit trains a week, so we could move products like grains and cement as well as oil throughout various parts of the US. That is a real opportunity that nobody else has,’ says Edwards. Any energy product that will be exported will be offset by an aggressive environmental initiative the port is undertaking.

can offer it for sale through traders, or we can work with third parties to put them in touch with the producers and let their buyers buy directly from the producers. We don’t compete with traders, but we’re here in Texas to work hand in hand with the traders and the majors to ensure that we are purely a third-party company to them and they can utilise our assets. We will never trade against the competition,’ says Edwards. FUTURE-PROOF ESG is on every company’s agenda at the moment, and Max Midstream is no exception. With Calhoun being a newly developed, and developing, port, it’s easy to consider all aspects of ESG from the start, rather than having to adapt. Edwards says that Max Midstream is audited on all three aspects to ensure the company is going in the right direction. The company wants to be the first ESGcompliant terminal on the US Gulf Coast.

Max Midstream is already able to offer carbon neutral oil barrels into the European market, through offsetting schemes such as tree-planting, and is investigating the handling of products for the energy transition, such as ammonia and hydrogen. The company will use renewable electricity from wind and solar to help power its facilities at the Port of Calhoun. And it’s not just the ‘E’ of ESG that Max Midstream is taking seriously. It is carefully examining its governance practices to ensure that it is accountable and will follow the best corporate procedures, and has committed to employ local people and give back to the community it is based in. ‘Does it happen overnight? It doesn’t. No matter what the world says, you can’t just turn a switch on and say this is ESG, but you can build for that future and you can plan for it,’ says Edwards. ‘When the world says it’s time to go that way, we’re there. We can start now. The market is going to dictate the direction and we’re going to be prepared for ESG when it becomes mandated, whether that’s in two years, or ten years, or 20 years.’ For more information: www.maxmidstream.com

‘Calhoun will be a carbon-neutral port,’ Edwards says. NOT JUST TERMINALLING Max Midstream has expanded beyond terminal services, and is the only Texasbased company with offices in Europe, having opened offices in Rotterdam in the Netherlands and Geneva in Switzerland to trade Texas crude and condensate in Europe. Edwards describes the subsidiary as ‘first traders’, who work directly with buyers. As a separate company, the European arm can source crude through Max Midstream directly or through Houston or Corpus Christi, for example. ‘What that allows us to do is that it allows us to work with thousands of producers and we can put that oil directly in our pipeline and in our storage tanks and we

PAGE 25

PROFILE SAVAGE

BRANCHING OUT INTO RENEWABLES US industry infrastructure and supply chain services company Savage continues to grow and diversify after 75 years in business response, environmental remediation, production services and waste management across the United States.

Savage has operated transload and storage terminals for many years and its Savage Transload Network currently consists of about 50 owned and/or operated terminals stretching from the east to the west coast of North America. This year, the company has been engineering and constructing new railports at a rapid pace, partnering with Class I and short line railroads in several instances and focussing on meeting growing market demand in commodityconstrained and transitioning industries. A NEW TERMINAL

SAVAGE, based in Salt Lake City, US, is a global provider of industry infrastructure and supply chain services, and this year celebrates 75 years in business. With nearly 4,500 team members in over 200 operating locations, the privately held company has steadily grown over the years to become a leading provider of transportation, logistics, materials handling, engineering and construction services across North America. BEGINNINGS AND SERVICES A family-owned, professionally managed business, Savage had humble beginnings, starting in rural American Fork, Utah in 1946, when Kenneth Savage purchased a truck with his father shortly after returning home from serving in the US Navy in WWII. In time, his two younger brothers Neal and Luke joined the family business, hauling materials in Utah and surrounding states. The Savage brothers built their business on the principles of integrity, hard work and innovation, values that company leadership continue to champion. Savage now works to optimise supply chains for customers across multiple industries, relying on its team’s expertise in rail services, trucking, marine transportation, terminal logistics,

PAGE 26

materials handling, facility operations and design, build, own, operate and maintain (DBOOM) services. Savage’s operations can be found throughout the US, as well as in Canada, Mexico and Saudi Arabia. Its infrastructure services, delivered though Savage Infrastructure, provide in-plant materials handling and management, and rail, truck and marine services, for large industrial customers. Its agriculture services, delivered through the company’s Bartlett grain and milling business is among the largest US exporters of grain to Mexico. And its environmental services business, EnviroServe, provides emergency

In August 2021, Savage announced a newly completed multi-commodity railport in San Joaquin County, near Stockton, California, that will serve as a gateway for the distribution of renewable fuels into the state of California. The Stockton terminal provides a connection to the BNSF and Union Pacific railroads, and Savage officials describe it as a key link in the supply chain for transporting renewable diesel and biodiesel produced in the Gulf Coast and US interior for use by California and West Coast consumers. Strategically located in California’s Central Valley region, Savage’s Stockton railport includes 20 transload spots and the capability to expand its capacity and services to meet growing market

PROFILE SAVAGE demand. While primarily intended for the distribution of renewable fuels, the facility is also equipped to safely move and manage additional commodities essential to California’s economy. OmniTRAX, a national logistics company, will transport rail cars and service the Stockton railport on its affiliate, Stockton Terminal and Eastern Railroad (STE).

‘This is one of many projects we’re working on to drive innovation in the design of critical infrastructure and optimise the flow of renewable fuels to support sustainable transportation solutions for our customers and communities across the country,’ said Savage Infrastructure sector president Brad Crist. THE DRIVE FOR RENEWABLES The Stockton railport is part of Savage’s plans to lead the buildout of renewable energy assets and services, and is one of multiple projects in development with partners in the agriculture and energy industries. The company is focussed on opportunities to purchase, source and deliver feedstock to renewable fuel producers; provide engineering and construction of terminals and other assets; and drive out inefficiencies in renewable fuel supply chains through efficient logistics and operations management. In October 2021, Bartlett, a Savage Company, announced plans to construct a US$325 million soybean crushing plant in Kansas, capable of handling about 38.5 million bushels of soybeans annually. Soybean meal and refined soybean oil from the facility will provide feedstock used in producing renewable fuels, food products and animal feeds. ‘We’ve seen a dramatic increase in demand for our team’s expertise and experience across our three verticals – agriculture merchandising and logistics, energy and chemical infrastructure, and environmental services – to develop renewable energy projects,’ said Kirk Aubry, Savage president and CEO. ‘Our team has proven we can reduce inefficiencies in renewable fuels markets and create significant value for producers and consumers.’ Jason Ray, Savage executive vice president of business development and engineering, adds: ‘Our breadth of knowledge and experience across multiple industries makes Savage a great partner to drive the expansion of renewable fuels infrastructure and operations. Growing consumer demand and government policies accelerating the adoption of renewable and lowercarbon transportation fuels make this the right time for Savage to expand our involvement in improving the renewable fuels supply chains.’

Savage has operated transload and storage terminals for many years and its Savage Transload Network currently consists of about 50 terminals NOT JUST RENEWABLES Savage has also recently developed other railports capable of handling liquid products, including a new railport in Tooele, Utah, serving the Salt Lake City market, and a railport with transload and railcar storage capabilities being constructed in partnership with Kansas City Southern in Mossville, Louisiana. In Utah, the Tooele railport can safely handle both non-hazardous and hazardous products and transfer materials from trucks to railcars for delivery across the US. The facility includes 45 railcar spots, warehousing, ground storage, conveyor systems and railcar steaming capabilities, and it provides access to Union Pacific rail lines. In Louisiana, Savage’s Mossville facility is nearing completion and will provide a critical link in the supply chains of Lake Charles, Louisiana area refineries, chemical plants and other businesses. When completed, the Mossville railport will include over 70 active transloading spots (expanded from 40 existing spots) for moving chemicals, refinery products and other materials between trucks and railcars. It will also have 600 spots for railcar staging, enabling plants, refineries and other area businesses to store railcars closer to their facilities. The railport also will provide access to moving products into Mexico on KCS rail lines.

MAKING A DIFFERENCE Savage officials say they are committed to doing the right thing for their team members, customers, and communities, and provide opportunities for team members to grow and develop their careers. For years, Savage has supported charitable and educational organisations and initiatives in many communities through its Savage Cares program. The company also strives to foster a diverse and inclusive culture that respects and values everyone’s contributions. Company leaders believe that by building on a strong foundation, Savage will continue to drive positive change and be better tomorrow than they are today. The company’s recent accolades have included being selected as the 2020 Utah International Business of the Year, receiving the 2019 Utah Ethical Leadership Award and being designated as a Military Friendly employer for four consecutive years. Company leadership view this recognition as being a reflection of the entire Savage team’s commitment to doing things the right way and taking ownership for ensuring safety. For more information: www.savageservices.com/savagecompanies/ For business opportunities, contact Jason Ray at jasonray@savageservices.com or +1 801 944 6516.

01 The Stockton railport 02 Savage opens the Tooele railport 03 A Savage rail engine

Savage also handles other dry bulk commodities such as hay, grain, lumber and construction materials.

PAGE 27

Federation of European Tank Storage Associations

PROFILE WOMEN IN TANKS | KATHRYN CLAY

FROM LASERS TO TANKS Kathryn Clay explains how a love of energy policy led her to the top of ILTA A SCIENTIFIC BACKGROUND

Clay has a PhD in physics and an MS in electrical engineering from the University of Michigan. ‘Science is about understanding the world and engineering is about solving the world’s problems. I enjoyed studying science and engineering because I thought it would be great to be a part of those things,’ she says.

DR KATHRYN CLAY is the president of the International Liquid Terminals Association (ILTA), which aims to provide a voice for the liquid terminal industry. Its terminal members come from worldwide, and includes those storing crude oil, petroleum products, asphalt, chemicals, ethanol, biodiesel, vegetable oils, molasses and fertilisers. Companies supplying the industry can also join the association. Clay joined ILTA in 2018, having applied for the position of president in 2017, seeing it as a good opportunity to take a leadership role in an organisation. She runs the organisation, helps to identify the needs of its members and works with the board of directors to set ILTA’s strategic direction. ‘A lot of my time is spent learning what the trends and issues are facing the terminal industry and learning how we can serve our members better. I also spend a lot of time interfacing with government officials on behalf of the terminal industry, letting them know what our priorities are. I am very pleased that we have been able to deliver some real policy successes over the last year. We have been engaged in meaningful discussions with officials at the US Coast Guard and the Environmental Protection Agency to help them understand the perspectives of our member companies and achieve good policy outcomes,’ Clay says. Her favourite part of her job is the opportunity to make a meaningful contribution to energy policy.

She was certainly part of ‘those things’ during her masters programme, when she studies optronics, or optical engineering, under Professor (then Dr) Gérard Mourou. Mourou was awarded the Nobel Prize in physics in 2018, alongside Professor Donna Strickland and Dr Arthur Ashkin, for their ‘groundbreaking inventions in the field of laser physics’. Mourou and Strickland jointly developed a method of generating high-intensity, ultra-short optical pulses, and Clay was involved in the laboratory research. ‘At the time, there were no commercial applications for our research, but today ultrafast laser pulses are used for all kinds of precise high-tech manufacturing that would not be possible otherwise. It is a great example of how science and engineering can bring new innovations and make all of our lives better,’ she says. MOVING INTO POLICY After completing her master’s degree, Clay realised that she wanted to work at the intersection of science and public policy, and began to study advanced battery technologies, which then led her to a position working with the Ford Motor Company. ‘Later, I was selected for a fellowship to work in a congressional office for a year as a science advisor. I enjoyed that work and decided to stay in Washington to continue serving as a kind of translator between science, engineering, and politics,’ she says. ‘I found I really enjoyed being a translator between the science and engineering perspective and the policy perspective.’ Having that combination of a science and political background has certainly helped Clay as she leads ILTA, due to the technical nature of many of the issues facing the industry. ‘It is often challenging for regulators to understand the technical operations and constraints involved. I think one of my

best contributions I am making in my current role is being able to understand both sides, the technical and the political. I know this skill has made a real difference on a number of our issues, ranging from air emissions permitting to process safety management to a transition away from PFAS containing firefighting foams,’ she says. THE NEXT GENERATION The terminals industry is not static, with new developments and technologies coming in all the time. ‘In a carbon neutral future, we can expect exciting developments in hydrogen storage and transport, including utilising carrier liquids such as ammonia. Biofuels will also likely play an important role. And liquified natural gas, while not carbon neutral, will continue to play an important role in allowing countries around the world to displace their reliance on coal and reduce their carbon footprint,’ says Clay. New technologies are already poised to ‘revolutionise’ many aspects of the industry, she believes, including drone usage, innovative detection techniques, increased automation, and the use of blockchain for inventory management. Environmental management and compliance will become ever-more important. One major change already taking place, and one that ILTA is particularly supportive of, is the transition away from PFAS based firefighting foams to fluorine-free alternatives. Key to the future of any industry is, of course, attracting new talent. ‘I think that for any new graduate, it is important to convey that the tank and terminal industry is growing and dynamic. No matter what the energy future holds, we can be sure that bulk liquids will play a major role,’ says Clay. ‘Anyone who wants to be a part of these important developments over the course of a career would be smart to consider a professional role contributing to the tank and terminals industry.’ For more information: www.ilta.org

01 Dr Kathryn Clay

PAGE 29

MARKET ANALYSIS US OIL PRICES

US OIL PRICES TIED TO TWO GIANTS: OPEC+, COVID-19 Paul Wiseman looks at what’s driving the latest trends AS WITH any commodity, oil prices are ruled by two sides of the coin – supply and demand. Energy experts agree that production decisions by OPEC+ are the most important supply side influences, while COVID-19 and concerns about possible variant-induced shutdowns heavily influence demand.

The Chinese, he says, ‘have always been this omnipresent, bullish influence on the market because they’ve been pulling in this crude, and they’ve been putting it into inventories they’ve been building up.’ Since February 2021, however, the Chinese have been dialling back those purchases, to the point of even announcing the sale of some crude in September.

In its August Short Term Energy Outlook, the US Energy Information Administration (EIA) estimated OPEC+ production would average 33.0 million bpd for the second half of 2021. The most recent OPEC+ agreement called for production to rise each month by 400,000 bpd until previous cuts are fully reversed. At that rate, full production would return by Q3 2022.

There is also the possibility that after more than a year of buying, China’s own storage is nearing capacity. Smith added that market pundits say the Chinese ‘make the weather’ because they are such a big influence on oil markets.

This worldwide level, attained largely by the oil cartel’s supply restraints, has slowly reduced US crude oil storage levels since US tanks were filled almost to overflowing in Q2 2020. That flood, caused by a combination of a worldwide demand drop from COVID shutdowns combined with a colossally ill-timed Russo-Saudi price war, plunged WTI prices into negative territory in April 2020. While most doubt that single barrel changed hands at that price, the mere January February March April idea shocked the industry worldwide. 2020 9,734 8,686 8,711 8,739

PAGE 30

12.0 11.5 11.0 10.5 10.0 9.5 9.0 8.5

2020

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2021

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Smith, in fact, credits a Chinese bargainbuying spree in Q2 of 2020 for saving the market from its COVID-induced oversupply and price collapse, along with supply reductions resulting from realisations by the Russians and Saudis that their price war was doomed.

China crude imports (source: Kpler)

China Crude Imports (source: Kpler)

Matt Smith, lead oil analyst for the Americas at Kpler, says: ‘The Chinese have really dialled back on their crude purchases. This is something that we haven’t seen for many years.’

And while concerns about further COVID-19 shutdowns due to new strains in India and elsewhere are restraining enthusiasm, at least one expert sees demand more at the mercy of a buying behemoth – China.

A few rumblings to the contrary might bubble under the surface, however,

May June July August September October November December 10,496 11,340 10,871 10,533 10,581 9,729 10,075 8,331 9,494 9,152 9,155 8,373 8,878

Fe br ua

THE INFLUENCE OF CHINA

‘The real question is, what will happen next year,’ Brady continues. He sees little change in strategy for 2022, with cash flow continuing to be king.

‘The dynamics that regulate US crude oil production would be the third influence,’ he says.

ar y

10,277

Another supply side factor includes the US’s own oil industry, says Aaron Brady. Brady is executive director of oil market research for IHS Markit, a global research and consulting firm.

Ja nu

10,750

THE INFLUENCE OF THE US OIL MARKET

Million bpd million barrels per day

10,652

One factor in US production is the pressure producers are under from investors to rein in spending, because they were spending more than they were taking in for years and years on acquiring acreage and drilling new wells. This allowed them to grow production, Brady says, but investors received no cash returns, adding that in the new reality, ‘investors have revolted against that and forced these shale companies to change their ways.’ This newfound capital discipline has slowed production growth. In fact, because of the precipitous decline curve in most unconventional wells, many experts feel the lack of drilling may not only prevent growth, it could actually cause a loss of production as existing wells decline.

‘The reason they’re doing that,’ Smith believes, ‘is because they’re trying to have an impact on the oil markets. Because they’re the largest importer, they’re the ones that drive prices.’

It also estimates worldwide production at 98.9 million bpd – a level which has proved healthy for West Texas Intermediate prices, holding them either side of US$70 (€59.60) per barrel for months.

2021

Over the last 5-10 years US production grew at a record pace, achieving record levels and making it the world’s number one producer. Brady observes that in 2020, COVID-19 reset production at lower levels. US production peaked at approximately 13 million bpd, dropping to near 11.5 million per day by mid-2021.

MARKET ANALYSIS US OIL PRICES

During the depths of the COVID downturn, producers not only stopped most drilling, they actually shut in a number of producing wells because of the storage crisis. As demand slowly recovered and a drawdown of storage began, producers first reopened producing wells. The next step was to complete what had become a backlog of drilled, uncompleted wells (DUCs) reaching the thousands. Since much of the cost of a new well is in the drilling, completing DUCs adds much less cost than drilling new wells. This provided an economical way to quickly increase production. Experts have seen that DUC supply dwindle in recent months, making producers revisit their drilling plans. There seems to be little unity on the future of drilling among producers. In September 2021, Chevron president Mike Wirth told Bloomberg interviewers he expects prices for oil, natural gas and LNG to remain high for the foreseeable future as producers remain dedicated to cash flow instead of drilling. Brady adds that a steady price near US$70 per barrel could give producers the ‘best of both worlds.’ They can return some cash to investors while investing money in growth, at least in a limited fashion. Other supply issues include Hurricane Ida’s almost complete shutdown of Gulf of Mexico offshore production. Platforms, gathering hubs and refineries were still struggling with repairs and power outages in mid-September taking more than 1 million bpd off the market. Possible lifting of sanctions on Iran imposed due to violations of nuclear restrictions also lurks just under the surface. While negotiations between the Biden administration and Iran are unlikely to be completed in 2021, Brady notes that Iran has a large fleet of tankers offshore already loaded. Should sanctions be lifted, he believes they could quickly pump 1 million bpd into what has been a carefully balanced market. DEMAND Demand began to recover in the second half of 2020, Brady observes. ‘It was sort of tentative at first, slow and steady, but really this year is where we’ve seen a mass spike in demand,’ he says, crediting vaccinations and the lifting of lockdowns around the world.

US crude oil stocks

600 550 500 Million bbl

according to a Reuters report. The news service quoted a stakeholder in Texas and North Dakota fields as saying: ‘Spending in 2022 will have to be higher just to sustain volumes enjoyed in 2021 and I think in general Wall Street is aware of that.’ How many producers take that track in 2022 will merit observation.

450 400 350 1

10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 Week

5-yr range

2020

Tired of more than a year of various restrictions, more people are travelling, at least by car. Air travel is still far from recovered, but gasoline demand is back, and diesel demand has been pretty strong, Brady says. ‘We are still at 95% of pre-pandemic levels, with a huge gap in the aviation business,’ says Claudio Galimberti, senior vice president of analysis for Rystad Energy, an independent energy research and business intelligence company. He is responsible for tracking energy demand in both short and long term, along with oil prices and energy transition issues. Headquartered in Oslo, Norway, Rystad has offices around the world, including Houston, Texas. Using satellite imagery, Rystad monitors and analyses worldwide vehicle traffic activity daily. ‘What is shows is that, on a global level, traffic is stable between 93 and 95%,’ he says, adding that current numbers are similar to those of September 2020. In January and February 2021 traffic levels dropped to 82-83%, returning to 93% in April, where they have remained relatively unchanged. In absolute numbers, worldwide demand dropped from 100 million bpd prepandemic, to a low of 75 million bpd in April and May of 2020. Drops in production from OPEC+ and the US gave the market 12 consecutive months of stock drops, strengthening prices into the US$70 range.

2021

median

disease –are basically at zero in the US, Galimberti says. While domestic travel is basically wide open, international restrictions are still largely in place. A factor whose influence on demand is difficult to quantify is the rising interest of investors in – environment, social and corporate governance (ESG) policies. Galimberti doesn’t believe that ESG is affecting oil prices in the short term, but on the other hand, oil prices affect investors’ oil and gas investments. ‘When oil prices are low, typically money managers own a short position on oil. And when oil prices are high and increasing, they tend to have net long positions,’ he says. With price wars in the past, OPEC+ is now closely watching the production throttle, working to maintain the supply/ demand balance – and steadying prices in the process. For more information: Paul Wiseman is a US-based freelance oil and gas writer. Contact fittoprint414@gmail.com.

01 US crude oil stocks, week by week 02 China crude imports (source: Kpler)

‘We have 3 trillion bbl of storage right now,’ Galimberti says, adding, ‘The fiveyear average is about 2.8- 2.85 trillion.’ A loosening of restrictions on travel and public gatherings is releasing pent-up demand. The COVID-related stringency index – gauging the levels of restrictions designed to limit the spread of the

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MARKET ANALYSIS US SHALE

CRUNCH TIME US shale drillers keep their powder dry for now, but it remains unclear how they’ll respond in 2022 as the declines in drilled but uncompleted wells (DUCs) and inventories come to bear, says Johannes Van Der Tuin

INCREASING GLOBAL oil demand has started to revive US hydrocarbon production, but any recovery is nascent at best and – as with other areas of the global economy – the pandemic accelerated trends within the US shale patch that had already been at work prior to 2020. As the latest round of US earnings calls highlighted, management teams and investors remain focussed squarely on free cash flow. ‘Capital stewardship’ had already become the watchwords for US exploration and production (E&P) executives before COVID-19 and remains so today. Additionally, environmental, social and governance (ESG) pressures continue to ramp-up from investors and are likely to stick around for the foreseeable future, particularly given the change of administrations in Washington. As a result, after the last year and a half of market tumult, management teams are understandably gun shy about forward-looking capital expenditures and aggressively raising production, instead preferring to live off their dwindling drilled but uncomplicated wells (DUC) inventories, pay down debt, and focussing on returning cash to shareholders.

PAGE 32

Given the current rate of completions, however, the test will come as we move into 2022, when corporates are likely to have exhausted their inventory of DUCs. Management teams will then need to decide whether to increase capex proactively or wait to see if lower production results in higher oil prices and more organic cashflow – some of which could then be reinvested into the basins. A NASCENT RECOVERY US Energy Information Agency (EIA) data show that crude and condensate

After the last year and a half of market tumult, management teams are understandably gun shy about forward-looking capital expenditures and aggressively raising production

production have yet to really turn the corner in every major US shale oil basin except for the Permian. Liquid hydrocarbon supply remains more or less depressed in the Niobrara and Williston, but West Texas oil output is already back up to around 4.8 million bpd according to the latest US government projections. Even in the Midland region though, rig activity remains sedate and growth is being driven more by completions, with the number of active fracking crews above 120 for the first time since the start of the pandemic. Perhaps unsurprisingly given their track record of overproduction, private companies in the Permian are the only E&P segment that has been raising its Permian rig count substantially, with now over 200 active rigs in basin. The side effect has been lower aggregate average well productivity, given that privates tend to have weaker type curves, bringing down overall basin performance – a trend that is likely to continue over the short-term. Management teams for the publicly traded international oil companies

MARKET ANALYSIS US SHALE (IOCs) and independent E&Ps are still a bit more cautious on the need to raise their rig counts and capex, relative to their private peers. Travis Stice, the CEO of Permian producer Diamondback Energy, articulated this sentiment during the company’s Q2 earnings call, saying: ‘As we look at supply and demand fundamentals, oil supply is still purposefully being withheld from the market and we continue to believe that there’s not a call on US shale production growth.’

The bottom line is that the structure of the US shale market is changing, potentially raising the weighted average of break-even prices, and reducing the risk of overproduction

A POTENTIALLY TIGHT 2022

after DUC inventories become depleted – likely in 2022.

With a conservative spending mindset firmly in the driver’s seat at many publicly traded E&P companies, instead of drilling new wells, executives prefer to rely on their existing, but rapidly dwindling, surplus Permian DUC inventories – loosely defined as the number of DUCs above and beyond the average working level required for smooth ongoing operations. That strategy can work through the balance of this year, but at the current rate of completions, it threatens inventory exhaustion in the first half of 2022 unless new capital is deployed or well productivity improves dramatically.

In the meantime, publicly traded oil companies would prefer to nurse their balance sheets, paying down debt and returning cash to shareholders via dividends, special dividends and share buybacks. And with billions of dollars in callable debt likely to be paid down through the end of the year in order to reduce leverage, executives have more than enough uses for their cash, other than ploughing it back into production. SHIFTING CORPORATE INCENTIVES

Spending additional capital, however, will likely require higher oil prices. CEOs have made commitments to increase investor returns and will be loath to proactively raise capex in lieu of higher organic cash flows, which would risk the wrath of shareholders.

Undergirding the change in tune from executive teams, and lowering the likelihood of a short-term return to exuberant US shale liquids growth given current market circumstances, has been a structural shift of incentives over the last couple of years.

Some companies have even gone so far as making explicit reinvestment commitments, such as the Permian behemoth Pioneer Natural Resources, which promises to only spend 50% - 60% of cash flow on new production in 2022 as of early August strip prices.

Even prior to the collapse in early 2020, the investor base in oil and gas had shrunk. Years of capital destruction and poor returns in the shale space had alienated many generalist asset managers, as reflected in the roughly 70% decline in total net-returns of the S&P Oil & Gas Exploration & Production Select Industry Index since mid-2014.

Overall, publicly traded US independent E&P capex guidance through the end of the year hovers at around US$35 billion (€29.6 billion), only slightly above 2020 levels, with little likelihood of any increases unless market circumstances change materially over the next few months. Of course, if the recovery in global oil demand stalls due to a COVID variant, such as Delta, or OPEC increases production above current commitments, oil prices may stay relatively muted, reducing the need for additional US shale capex this year and next – per the fears of E&P management teams, many of which feel they were burned by OPEC in 2020. Alternatively, though, the bull case of rising oil prices and an increasing ‘call on US shale’, could spur companies to raise spending reactively, resulting in higher rig counts and ultimately rising US production, but this is only likely to occur

As a direct result, investors continue to agitate for consolidation within the US upstream – a process that was accelerated last year due to financial pressure but is likely unfinished. Most notably, this included mergers between high quality names (read: Parsley and Pioneer) as well as the acquisition of corporates with excellent acreage positions (such as Concho Resources). This has reduced the number of operators and, potentially, animal spirits. Shareholders hope it will also result in better capital management, higher returns and – implicitly – higher oil prices. ESG mandates have also added to investor pressures. Large asset managers such as BlackRock are increasingly laying down the gauntlet on behalf of their customers, pushing corporates to reduce scope 1 and 2 emissions. A process that will require greater internal compliance

and controls within the E&P business, this generally favours companies with scale and tends to encourage consolidation. Firms that cannot make the adjustment will, and are, facing a higher cost of capital, which again threatens to erode their competitiveness. Simultaneously, the change in US administration last January will likely result in a further shift in the regulatory environment – particularly focused on methane emissions and greenhouse gas (GHG) disclosures – increasing investor scrutiny and compliance costs further. A heavier regulatory burden for the E&P sector would potentially be more easily borne by large companies, erecting higher barriers to capital for subscale drillers overtime. IMPLICATIONS FOR FLOWS AND STORAGE The bottom line is that the structure of the US shale market is changing, potentially raising the weighted average of breakeven prices, and reducing the risk of overproduction that we saw in the earlier stages of the development of US shale. As a result, aggregate US onshore lower-48 oil production is likely to incrementally increase by only around 400 – 500 kb/d in the second half of 2021. The biggest driver will be the Permian, which should constitute roughly 70% of all production growth and might in fact reach new highs by the end of Q4 2021 or in Q1 2022. Growth will be hard to sustain at the current rate through 2022, though, if rig activity doesn’t pick-up towards the end of this year. Otherwise, the exhaustion of the DUC inventory will weigh down US shale production next year, causing it to underperform a possible further 800,000–1 million bpd year over year increase by December 2022. Regardless, the dramatic pipeline buildout prior to 2020 means that the current Permian takeaway capacity of roughly 8 million bpd should be more than ample over the next year, even if inbasin production reaches well above 5 million bpd in 2022. The futures curve is also likely to stay backwardated into next summer, with local demand, refinery runs and exports continuing to outstrip production growth, obviating most over-supply risks for US storage capacity for the next 12 months. For more information: This article was written by Johannes Van Der Tuin, an independent consultant and freelance energy writer based in New York City, US.

PAGE 33

MARKET ANALYSIS US ENERGY POLICY

THE OUTLOOK FOR OIL STORAGE IN A LOWERCARBON ECONOMY Columbia University’s Antoine Halff examines the effect of changing policies under the Biden administration JOE BIDEN’S election to the US presidency in 2020 has ushered in a period of renewed momentum for climate policy both in Washington and beyond. In a U-turn from Donald Trump’s climate scepticism and rejection of the Paris Accord, President Biden from his first day in office has embraced a bold climate agenda, vowing to pursue an all-of-government approach to combatting climate change. Countries and companies around the world have greeted Washington’s return to the Paris fold with a flurry of net zero targets and bold decarbonisation plans – a trend perhaps accelerated by the COVID-19 pandemic. The potential implications of this green wave for the oil storage industry are momentous. Any drastic shift in the composition of the fuel mix, any bid to move away from fossil fuels in favour of renewable energy and clean electricity, is bound to have significant effects on the role of oil storage in our energy system. Yet the consequences of such a shift are not necessarily those one might expect. Energy policy debates tend to focus on the two opposite ends of the supply chain – on the need to reduce upstream investment in fossil fuels and shift downstream energy use towards lowcarbon fuels and electricity. But they give

PAGE 34

the midstream sector relatively short shrift. The current US policy debate is no exception: there are more calls to stop fracking, close down coal mines, electrify cars and ban ICE vehicles than to reinvent oil storage. Yet storage and transportation play a critical role in the incumbent energy system, and as such are bound also to play a pivotal role in any effort to overhaul it. THE NEED FOR ‘CLEANER’ STORAGE On paper, moving away from fossil fuels means less demand for oil inventories and more demand for ‘cleaner’ forms of energy storage: LNG storage to support low-carbon marine bunkering and longhaul trucking, hydrogen storage, biofuels tanks, and of course electric batteries. There is certainly some of that. The IMO rules that drastically reduced the sulphur standard of marine fuels in 2020 offer a preview of the task at hand: as ships switched from high-sulphur to lowsulphur fuel, so too did storage demand at port terminals move from one type of tanks to another. Part of the marine fuel storage infrastructure had to be converted accordingly.

Decarbonising marine transport – a far greater challenge than desulphurisation – takes this overhaul to the next level. The goal here is no longer simply to shift from one grade of oil to another but to replace oil storage with an altogether new infrastructure: LNG and hydrogen bunkering facilities, and perhaps charging infrastructure for short-haul electric vessels. Oil bunkers would be expected to fall into disuse. SHARP DISRUPTIONS Yet there is another, less intuitive side to the effects of the energy transition on liquid storage, at least in the short to medium term. In an economy that remains in practice stubbornly fossilfuel dependent, but where investment in fossil-fuel production capacity is increasingly discouraged, the importance of fossil-fuel storage, in particular oil storage, becomes paramount. The so-called energy ‘transition’ is a misnomer. What the market faces instead is a series of sharp disruptions, whether due to the effects of global warming or to our efforts to contain it. The road to net zero is a bumpy one: climate policy moves in fits and starts, utility-scale solar and wind capacity gains are lumpy and

MARKET ANALYSIS US ENERGY POLICY disruptive, consumer habits first evolve slowly then quickly… Not to mention the future ‘game-changing’ effects of assumed but still elusive ‘breakthroughs’ in electricity storage. With so many wild cards, uncertainty rules. MORE IMPORTANT THAN EVER In this increasingly unpredictable environment, tank storage is more important than ever. Moving to a greener fuel mix means facing an exponentially more complex energy system – one where arbitrage opportunities play out not just across time and location spreads but across the energy mix as well. With inter-fuel competition heating up as highly variable renewable fuels account for a growing share of the mix, demand for incumbent fuels becomes more volatile. Large weather-driven swings in solar, wind and hydro availability spill over into fossil fuels, sending demand for oil, natural gas and even coal on a roller coaster – even as production capacity for these fuels becomes increasingly constrained by lack of investment and stranded-asset concerns. Just in the last two years, the oil market has experienced record swings in oil demand, and thus in oil inventories: first at the beginning of the pandemic, when the global lockdown – compounding the effect of the brief Saudi-Russian price war – came close to testing storage capacity. And more recently as shortfalls in solar, wind and hydro generation combined with a stronger-than-expected economic recovery caused inventories precipitously to draw down. Only 18 months ago, US traders were concerned that crude stocks at the Cushing, Oklahoma storage hub might overflow. Those same tank farms have now dropped to lows unseen in years. Far from driving oil stocks out of the picture, the transition to a lower-carbon fuel mix thus increases their relevance. Swings in oil demand are getting too wide and unpredictable for production easily to adjust. With supply increasingly constrained, it is storage operators that are the first responders in balancing supply and demand. REDUCING EMISSIONS But the decarbonisation drive is also affecting liquid storage in other ways, notably via direct demands on the oil industry to reduce its greenhouse gas footprint and stomp out leaks from its operations. Methane emissions, practically a nonissue at COP 21, have moved to the top of the agenda. The US government and the EU have joined hands to launch the Global Methane Pledge, an international

initiative to slash methane emissions by 30% by 2030 that might well become one of the highlights of COP 26. The fossil fuel industry is a leading source of anthropogenic methane emissions, and the midstream segment accounts for many of these incidents. At the time of writing, the US Environmental Protection Agency was said to be putting the final touches on new methane regulations mandated by Biden since his first day in office. Meanwhile the EU is pushing ahead with its Methane Strategy. Liquid storage operators will come under mounting pressure to reduce their methane footprint. Luckily, methane tracking technology has greatly evolved and is now empowering operators not only to cost-efficiently and effectively cut fugitive emissions, but also to document their progress in doing so. Here too, the decarbonisation agenda could paradoxically give the tank storage industry and the broader oil and gas sector a new lease on life, by helping them reduce their greenhouse gas footprint and deliver the largest reduction in heattrapping emissions since the Industrial Revolution. Technology that was at best in its infancy during COP21 is now mature and available to let storage operators remotely monitor their facilities, detect and eliminate leaks from their operations, and document their progress in quasirealtime in a transparent, trusted and verifiable way. NEW DATA TECHNOLOGIES The unprecedented level of transparency granted by new data technologies is not limited to methane emissions. In the last few years, remote sensing tools have made great strides in lifting the veil of confidentiality that had long shrouded the oil and gas sector. This extends in particular to oil inventories, which satellites, drones and planes can now

track in quasi-realtimes, allowing market participants an exhaustive yet granular view of global oil stockpiles that until recently would have seemed way out of reach. As the energy system, both in the US and beyond, appears on the verge of deep transformation, so too is the tank storage industry facing a period of disruptive change. While in a lower-carbon economy the market share of oil and gas is expected to be eventually reduced, in the shorter term the importance of tank storage in helping balance an increasingly unpredictable market looks set to increase. With the growing market share of renewables increasingly subjecting oil and gas demand to sharp swings, the optionality value of oil storage is on the rise. Meanwhile, new demands for decarbonisation, combined with the unprecedented transparency provided by remote sensors, are changing the environment in which oil storage operates. These changes too will only serve to make tank storage more relevant and socially acceptable, by helping to increase the accountability of operators for their emissions, optimise arbitrage trading and empower stakeholders to better deal with an increasingly turbulent market. For more information: Antoine Halff is an adjunct senior research scholar at the Center on Global Energy Policy, Columbia University and chief analyst at Kayrros, an energy data analytics company he co-founded in 2016. Email: amh140@columbia.edu.

01 US Capitol and Capitol Hill, Washington DC, US 02 Aerial view of Harbor Bridge from Bayfront Science Park in Corpus Christi, Texas, US with tank farms and wind turbines behind.

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MARKET ANALYSIS MEXICO

CURBING THE COMPETITION: MEXICO’S FUEL IMPORT CHANGES Eduardo Lopez looks at the implications for importers government was obliged to shelve its new rules.

UPON GAINING power in 2018, the administration of Mexican president López Obrador launched a vociferous and strident rhetorical war against the private sector, most notably in the energy industry. The president’s ire has been directed mainly at Mexico’s energy opening, made possible in December 2013 by a long-awaited yet long-delayed constitutional reform. A salient feature of this reform was to impose a modicum of competition on the former state-owned monopolies (Pemex in the oil industry and CFE in electricity) through so-called ‘regulatory asymmetry’, which forced both companies to relinquish some of their existing market positions in order to allow the participation of new, private players. Predictably, both companies lost market share in different businesses. Pemex, in particular, has faced strong downstream competition – in logistics (the importation and distribution of liquid fuels) and retail (service stations). Indeed, private companies now control roughly 50%, 30% and 25% of Mexico’s total diesel, gasoline and jet fuel imports, respectively. Moreover, over one third of all service stations now display non-Pemex flags. Yet, instead of welcoming the fact that the energy sector as a whole was gradually

PAGE 36

but markedly improving after decades of a stifling state monopoly, the current government chose early on to ‘defend’ its battered state-owned companies (pompously called ‘productive state enterprises’ since the 2013 reform). Thus, the administration recently launched a number of actions aimed at reverting, de facto if not de jure, the energy reform, both in hydrocarbons and electricity – though not always successfully. ISSUING NEW RULES With regards to the downstream oil sector, the government’s incendiary rhetoric morphed into formal hostilities in December 2020, when the Energy Ministry (SENER) and the Economy Ministry (SE) jointly issued new rules governing fuel import permits. The government decreed that, from then on, permits would no longer last 20 years, but only a maximum of five, and could be renewed only once. However, a number of private companies immediately challenged the ruling, arguing it unduly and illegally superseded the constitutional reform of 2013 and jeopardised long-term investments. A tribunal agreed in February 2021 (under the concept of amparo, whereby the acts of the executive are suspended), and the

The administration’s response to this rebuff was to propose, a month later, a constitutional amendment to overcome the legal ineffectiveness of enacting a simple ruling. This constitutional reform aims again at private fuel import and storage permits, which would now be easily suspended or abolished on the basis of vague and arbitrary motives (‘national security’ or ‘energy security’, to name but a few) and then eventually passed on to Pemex. It remains to be seen, however, whether the proposed amendment sails through Congress, as the president lacks the required majority in both chambers. Moreover, enacting such changes would invite widespread international arbitration against Mexico, as they would infringe several key trade treaties, among them the US-Mexico-Canada agreement (USMCA), the Trans-Pacific Partnership (TPP) and the Economic Cooperation Agreement with the European Union (EU-Mexico FTA). The government’s third attempt to force a change with regards to fuel imports came in June 2021, this time by revisiting general trade rules, which are updated annually by the tax administration (SAT). Private companies are now forbidden to trade (import and/or export) fuels and petrochemicals via a different location for which they were initially authorised. In particular, logistical operations are no longer allowed in offshore terminals, only in ports, allegedly to fight unspecified ‘corruption’, which has been this administration’s leitmotiv to justify its many crusades against the heritage of its ‘neoliberal’ predecessors. To add insult to injury, SAT exempted Pemex from these new rules and relinquished several import permits from a handful of companies, including several large ones, a few weeks later. FURTHER CHALLENGES As before, however, these changes are being challenged in court and are likely to be suspended or rejected, since they – again – blatantly contradict domestic competition rules and the various trade

MARKET ANALYSIS MEXICO treaties already alluded to. Private companies are in effect being sidelined and deprived of the operational flexibility and efficiency required to respond to changing market conditions. Aside from the legal challenges, the aggressive resource nationalism espoused by the president – and enthusiastically promoted by his acolytes in charge of energy policy – is simply unrealistic. Pemex is far from being the industrial beacon that would guide and support both the country’s economy and its future, as the administration’s populist and demagogic discourse would have it (looking back with nostalgia at the 1970s, when Mexico’s major oil discoveries occurred). Rather, Pemex is an over indebted, inefficient and poorly managed company that is becoming a fiscal time bomb for the country’s public finances, and unable to meet the country’s rising domestic oil product demand at competitive prices without incurring in huge loses. WHAT NEXT? Putting obstacles in the path of private fuel importers will do little to boost supplies and curb retail prices – which are becoming a political liability, since

the president stridently promised, as a candidate, to more than halve them. Clearly, domestic refining will not compensate imports, regardless of the government’s narrative (existing refineries are literally falling apart for lack of maintenance, crude slates not adapted to refinery configurations, runs are ruinously low and the project to build a new refinery is increasingly looking like a gigantic white elephant).

suspended imports on a short-lived nationalistic élan or, most probably, a huge increase in domestic prices as logistics would arguably become more complex and hence more expensive. That alone should force the government to reconsider. Most likely, though, a return to a more rational, fact- and cost-based energy policymaking in Mexico will have to wait for a less ideological and confrontational administration.

Should the latest regulatory changes prosper, the likely result would be a repetition of the shortages that occurred in December 2018, when Pemex briefly

For more information: Eduardo Lopez is an independent oil market economist based in Mexico City.

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PAGE 37

MARKET ANALYSIS REGULATORY UPDATE

ILTA ADOPTS – AND ACTS ON – ESG PRINCIPLES Kathryn Clay, president of the International Liquid Terminals Association (ILTA) looks at new ESG principles and the impacts of fire-fighting foam regulatory changes in the US

for terminals to be a part of the solution for our shared goals. We convey to these policymakers what we see every day – that ILTA member companies are committed to providing safe, secure, efficient and environmentally responsible services to energy and fuel supply chains. Liquid terminals are a critical link in getting liquid products – like gasoline, diesel, chemicals and liquid foods – in the hands of the ultimate consumer. Terminals connect modes of transport and enable economic growth at home and abroad.

AS THE terminal industry’s leading advocate in the US, the International Liquid Terminal Association (ILTA) is focussed on building a strong brand in Washington as we expand our advocacy efforts. Since the Biden Administration’s arrival earlier this year, ILTA has gone to work to educate new political appointees and career officials charged with regulating our industry. We have helped them to understand the challenges facing our industry and the opportunities PAGE 38

ILTA shares how our industry supports sustainability goals. Whether it is through improving the energy efficiency of their facilities, practicing sound water resource management, or conducting proactive dialogue with their neighboring communities, ILTA member companies are working to integrate sustainability into their business models. COMMITTED TO SUSTAINABILITY The commitment that ILTA member companies have to sustainability is apparent in other ways as well. Terminal

companies are increasingly investing in renewable energy projects such as hydrogen production and solar installations. One innovative approach involves installing solar panels on the roof of tanks. This not only reduces greenhouse gas emissions, but also offsets energy costs for the facility. I am excited to share that the ILTA board of directors voted to approve a set of environmental, social, and governance (ESG) principles. The principles are the result of an industry-wide dialogue over more than six months. The ILTA ESG principles are truly the result of contributions from across our ILTA community, demonstrating how much corporate sustainability is on the minds of terminal industry professionals. The principles are publicly available on the ILTA website, and see boxout, left. NEW PROPOSALS ON FIRE-FIGHTING FOAMS ILTA is being guided by its principles in how we approach environmental policy. This includes our efforts to contribute to solutions related to the use of per- and

MARKET ANALYSIS REGULATORY UPDATE polyfluoroalkyl substances (PFAS). These man-made chemicals are used widely throughout many industries, including in most fire-fighting foams. Our society’s reliance on them is also one of the most widely discussed environmental challenges of our day. Many of the bulk liquid products handled by ILTA member companies, including fuels and certain chemicals, demand special precautions due to their flammable properties. While high-hazard events at terminals are rare, it is vital that when they do occur the terminal industry maintains its full ability to ensure worker and public safety. For decades, the tank storage industry has relied upon firefighting foams containing PFAS to protect communities, workers, commodities, and infrastructure from potentially dangerous fire hazards. Unfortunately, proposed legislation in a number of states could hamper and possibly prevent proper firefighting efforts in high-hazard situations. Currently, no procedures for use of fluorine-free foams are certified for large tank fires like those that can occur at liquid terminal facilities. ILTA recognises the potentially serious health effects of PFAS exposure and firmly supports a safe, strategic, wellmanaged transition to fluorine-free foams. ILTA also recognises that significant barriers must be addressed to achieve a complete, industry-wide transition to these alternatives. Terminal operators face a number of requirements for fire preparedness and response that are not common in municipal firefighting contexts including large-scale events, deep tank fires, and alcohol-type fires. With unique expertise in the application of firefighting foams at liquid terminals, the ILTA membership has offered to serve as a resource to the US Environmental Protection Agency’s (EPA’S) PFAS Council. Transitioning to fluorine-free foams will involve other challenges as well. Currently, we lack practicable methods to destroy PFAS or permanently dispose of existing stocks of firefighting foams. Terminal operators will need clear guidance on how to dispose of their existing stocks to make room for alternative foams and to ensure all eventual contamination risks are mitigated. Regulators and stakeholders will also need to establish cleaning practices for equipment previously used to deliver PFAS based foams. ILTA believes that transitioning to fluorine-free foams will require collaboration between regulators and industry stakeholders, including terminal owners and operators, firefighters, foam manufacturers, and disposal vendors. We share the goal of developing

strategies to safely phase-out firefighting foams containing PFAS, while ensuring that the safety of firefighters, workers and communities. We also support believe it is crucial to provide a timeline that allows us to adequately develop fluorine-free foams, application equipment, and requisite standards through bodies such as the National Fire Protection Association and Underwriter Laboratories.

I am looking forward to the work ahead as ILTA continues to represent our industry to regulators, and to continue to support the sustainability objectives of our member companies.

01 Kathryn Clay

ILTA ESG PRINCIPLES ENVIRONMENT 1. Overall environment commitment We embrace our responsibility for environmental stewardship through the use of conservation and sustainable practices. 2. Water management principle We believe in using sound water management practices to the benefit of our surrounding communities including spill prevention and control measures. We believe the modest water usage levels at terminals should still be efficient, with reuse and recycling where practical. 3. Air quality principle We strive to maintain air quality for the communities in which we operate. In addition to meeting requirements for air emissions standards, as an industry we will continue to review new technologies and procedures for further emissions monitoring and reductions. 4. Climate change principle We support policy that encourages new technologies to reduce greenhouse gas emissions and improve energy efficiency, promoting innovation and the competitiveness of our industry. SOCIAL 1. Safety principle We support a culture of continuous safety improvement, always with zero injuries as our goal. The safety and well-being of our employees, contractors, and communities is a top priority. 2. Community engagement principle We actively work to build trust and foster collaboration with neighboring communities and other stakeholders. 3. Diversity, equity, and inclusion principle We are committed to creating and attracting a diverse and inclusive workforce. We make our employment decisions without regard to age, colour, disability, gender, gender identity, race, religion, sexual orientation, or veteran status. GOVERNANCE 1. Ethical conduct principle We believe it is important to develop and adopt a business code of conduct to promote a high standard of behaviour for employees, executive officers and directors with regards to ethics, compliance and human rights. 2. Grievance reporting and non-retaliation principle We enable employees to direct questions and concerns regarding safe, secure, and responsible operations to the appropriate company resource, and work to ensure that any individual reporting a suspected violation is not subject to retaliation of any kind. ESG PLEDGE As an organisation, ILTA pledges to support these ESG Principles and to guide, inspire and share resources with its members for the benefit of the global community.

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TECHNICAL API 656

THE COST OF NATURAL DISASTERS Philip Myers and Earl Crochet run through the latest updates coming to API 656 – Aboveground storage tank operations during uncontrollable natural disasters DURING THE first six months of 2021, there have been eight separate billion-dollar weather and climate disaster events across the US. The eye-opening plot in Figure 1 shows the magnitude of problems associated with natural disaster events, referred to as ‘natech’, which means ‘natural hazard-triggered technological event’. Natechs can occur any time natural disasters interact with petroleum or chemical storage facilities and their local associated societal infrastructure. A recent stretch of extreme cold weather in Texas was a good example of a serious natech. In this event important energy infrastructure was knocked out resulting in numerous problems and unfortunately, loss of life. As a current natech example on the west coast of the US, extreme heat is creating unprecedented wildfires threatening infrastructure, homes and lives. Certainly, the recent floods in China’s Henan Province are producing numerous serious natechs.

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A glance at Figure 1 quickly shows an increasing trend in both the number and the cost associated with US natechs. It also shows that the lion’s share can be attributed to severe storms and tropical cyclones or hurricanes. DEVELOPING GUIDANCE Work on natechs began in earnest with the Joint Research Center (JRC), which is a knowledge and science service that supports EU policy, as well as organisations like the United Nations Office for Disaster Risk Reduction (UNDRR), which is the UN’s focal point for disaster risk reduction. Numerous papers began to appear in the early 2000s and continue to this day, primarily authored by Europeans. In August of 2017 the category 4 Hurricane Harvey deluged areas of southeast Texas, resulted in major flooding and 68 deaths. It cost society US$125 billion (€107 billion). A chemical incident was initiated by the flooding at an organic peroxides storage

facility in Crosby, Texas. The US Chemical Safety Board (CSB) investigated this incident and called for industry to develop guidance related to natural disasters. As a result, in 2019 the Center for Chemical Process Safety (CCPS) published CCPS Monograph: Assessment of and planning for natural hazards, which was prompted by the request of the CSB to develop guidance for the combined natural disaster events and hazardous material releases. The American Petroleum Institute (API) Subcommittee on Aboveground Storage Tanks (SCAST) decided that it would be useful to address natechs issues related to petroleum storage facilities. Storage tank incidents caused by natechs are one of the most serious contributors to the problem, since they store large volumes of hazardous materials and are relatively ‘fragile’. The American Chemistry Council (ACC) is participating, along with other organisations, in the development of a new publication, API 656, that will specifically address storage tanks and natech.

TECHNICAL API 656

Figure 17. Distribution of storm-triggered Natech events by the type of structure (lightning triggered accident excluded)

Process equipment; 11; 22%

kinds of products into tanks to maintain compatibility and quick return to ‘normal’. API 656 will provide easy to use charts that show what is needed in a manner that is suitable for assessing and planning for hundreds of tanks at once at a refinery, chemical or petroleum storage terminal.

Even with the best of planning, design criteria can be exceeded, and API 656 will cover the basic concepts of resiliency for storage facilities. Resilience is the ability to prepare for and adapt to changing conditions and recover Storage; rapidly from disruptions. Resilience is 40; 78% Source: JRC both about the affected company or organisation and the community and Source: JRC stakeholders that it affects. One of the most beneficial aspects of resilience ADDING VALUE TO is to assume that the safeguards are EXISTING PRACTICES overwhelmed igure 18. Distribution of storm-triggered Natech events by the type of structure (only accidentsand then to seriously triggered by rain is and flood) You may ask how natech different examine the consequences and from the years of work the petroleum determine what can be done to mitigate/ and chemical industries have put into recover from failure. For example, there improvement of environmental, safety may be multiple simultaneous releases improvement, and incident reduction, and/or fires; emergency response including the comprehensive standards may be delayed or not available due to such as the Process Safety Management evacuation orders, loss of highways and and fully developed design rules roads, the need to release hazardous covered by API standards and others chemicals such as ammonia or chlorine such as ASCE-7. as was the case in the 1999 Turkey Kocaeli earthquake incident, or other There are many ways that API 656 will domino affects. add significant value to existing practices when looking specifically at natech avoidance and mitigation. Codes and standards, as well as best practices, are typically based on mean recurrence intervals (MRIs) which can Source: JRC be exceeded. For example, many areas subject to flooding are using a 100-year flood criteria. This criterion yields a 26% chance of exceeding that flood designation over a 30-year period. Other criteria specified by ASCE7-16 range up to nearly 2,500 years. Facilities may 22 wish to use other more uniform and appropriate criteria and these are not well-addressed currently. Most facilities have a long history of upgrades and changes that can span decades. This means that older parts of the facilities were designed and constructed with older and possibly obsolete designs, methods, and construction techniques. This is particularly true, for example, with seismic design and construction practices for storage tanks. API 656 will show how prudent owners/operators should consider this issue. During hurricanes and storms there are multiple effects including flooding, rain, wind, moving water and even breaking waves in coastal regions. During these times, facilities scramble to get oil to ballast their tanks. But most do not know how much oil is required and react by putting more ballast than is actually needed. This results in a shortage for everyone and the inability to get the right

API 656 will incorporate the principles in its scope as outlined by the National Institute of Standards and Technology (US Dept of Commerce). Useful information can be found at https://www.nist.gov/system/

files/documents/2019/04/03/ nist_community_resilience_12_page_ brochure.pdf. A SPECIFIC RESOURCE While there are many general documents, data sources, and papers relating to the assessment and understanding general natech, it is clear there is a need to specifically address storage tank facilities in the context of natech. A tentative organisation for the document is give in this figure: The first draft has been completed and it is expected that this publication will be available in 2022. For more information: Philip Myers (phil@pemyconsulting.com) and Earl Crochet (earl@crochetmc.com) are the co-chairs of API 656. Contact them directly to learn more. Notice: the view and opinions expressed in this paper are strictly the authors and do not represent the opinions and perspectives of API or any other organisation.

01 US billion-dollar disaster events 1980-2021 (CPI-adjusted) 02 Distribution of storm-triggered natech events by the type of structure (only accidents triggered by rain and flood source)

API 656 PETROLEUM AND CHEMICAL STORAGE FACILITY NATECH Contents

Appendices

Initiator Datasheets

• Front matter (forward...)

1. How to start natech assessment

Lightning

• Scope

2. Decision and risk concepts

Tsunami

• Introduction • Codes criteria for natural hazard severity • Retrospective code criteria • Grandfathering

3. Exceedance and MRI 4. Hurricane flood and wind 5. Excess floating roof rain

Seismic Hurricane Flooding (riverine and coastal) Tornado Landslide

6. Resiliency (to be written)

Extreme high temperature

• How to start

7. Secondary containment

Ice storms

• Resiliency

8. Initiator datasheets

• Secondary containment

Wildfire

9. List of questions

Volcano

• Motivation • Planning

• Concluding remarks

Extreme low temperature Droughts

10. Annotated bibliography

• Appendices

Table 1: Structure of API 656 Tank Natech

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TECHNICAL TANK CLEANING EQUIPMENT

FASTER, BETTER, CLEANER. How one Canadian company reduced the time required to clean a tank from three months to three weeks CANADA-BASED Radical Robotics is an explosion-proof robotics company, specialising in tank cleaning using a combination of automated robotic tools and revolutionary software.

Its equipment is used for the likes of ConocoPhillips, Suncor, Imperial Oil, Enbridge, Syncrude, Meg Energy, Syncrude, CNRL CO-OP, CNRL, Cenovus, Shell, Connacher Oil and Gas and Pembina Pipeline to name a few. Radical Robotics provides a range of tools, from its flagship high-pressure robotic cannons to its Radical Software VantageSuite, which guides customers from the initial planning phases of a job right through to completion. The company also offers a range of new innovative products such as a new circulating management tank for solids removal during the seep process, its explosion proof 4 inch injectable robotic camera and its new high pressure robotic vessel cleaning system. All its products are exclusively distributed via Precise Tank Cleaning Tools. ‘Precise was formed specifically to distribute our products as we needed to ensure a distribution network we could trust,’ explains Dustin Kos, CEO of Radical Robotics. Although the products are mainly distributed across North America,

Precise has recently added a marketing representative in Malta to begin focussing on both Asia and the Middle East. At the same time Radical Robotics is expanding its manufacturing facilities to meet current demand. Flagship high pressure water cannons Radical Robotics’ manway cannons provide a much higher flow and impact

force than anything else available in the market today,’ Kos explains. They run 180° on 2 axis and supply up to 530 gpm at 300 psi creating an impact force of 498 lbs with a range of up to 150 ft. The Radical manway cannons also have an advanced totally automated control system with many features not available elsewhere. Using the high-powered lighting and 4k camera capabilities (mounted on the cannons) it allows the operator to focus the cleaning activities on specific areas viewed in real time. ‘This is one of the only fully robotic class one/div one robotic camera available today,’ Kos says. The camera allows the operator to provide the client with accurate updates and live recordings or images of the work being performed for future reference. ‘A major feature of our products is the remote access capability,’ explains Kos. ‘This allows end-users to see in real time what is actually going on and to aid in the decision-making process.’ All of Radical Robotics’ products are designed to work in challenging conditions. ‘We have eliminated the heavy and hard to manhandle umbilical hose and cabling commonly used in these types of products and designed a much more versatile hose and cable system with ‘daisy chain’ capability. This means you run your hose and cables from the last tool, not from the main command centre,’ adds Kos.

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TECHNICAL TANK CLEANING EQUIPMENT jobsite, Kos adds. ‘Sharing this with your customer gives them the confidence in your plan for the job. And lastly, allowing the model to work in real time with information being garnered from the flow measurement systems, gives yet another set of eyes into the process.’

REDUCING DOWNTIME Radical Robotics understands that reducing downtime is critical to its customers. ‘We have managed to achieve a 75% time reduction compared to traditional tank cleaning methods and by using a 3-6 man crew rather than a 10-15 man crew,’ Kos explains. ‘It takes a company just one day to set up our equipment and (omit we can) clean tanks in hours, rather than days.

CREATING A VIRTUAL TANK One of the biggest differentiators between us and our competitors is our constant product development,’ Kos explains. ‘In the past robotics weren’t seen as particularly reliable, so up until recently we’ve been focusing on improving the tools to reduce any potential downtime. Now that has been achieved, the focus has shifted to focusing on artificial intelligence. By being able to see what’s inside the tank you can improve the speed and efficiency of the tank clean. One of the company’s biggest innovations is its interactive 3D tank management

RACICAL ROBOTICS’ CURRENT OFFERING: • Robotic Manway Cannons • Automated Tank Sweeps • Automated Track Machines • Robotic Vessel Cleaning Tooling • Robotic Lighting and Camera System • Fully Automated Circulation Management Tanks

system, which allows for the creation of an accurate 3D model of the customers tank or vessel and can even be expanded to include the whole site as well. ‘Imagine sitting at a computer screen and placing all the nozzles and tooling before the job begins, as well as all structures or equipment in the area,’ Kos says. ‘You will see any obstructions which may impact the flow rate or impact force. From this you can determine ahead of time any areas that may need extra attention and make alternate plans in order to deal with these problem areas. ‘You can then run the model again and see how it actually works. You can keep making adjustments and running the models until your confident you’ve got it right.’ Being able to visualise not just the piece of equipment being cleaned but also being able to perform a complete site layout for site management purposes is a major step in efficient pre-planning. ‘Using all this knowledge and simulating the process gives the ability to solve problems before you arrive at the

As an example it used to take Canada -based waste management specialist GFL Environmental over three months to clean a tank,’ Kos explains, ‘using our technology they can complete this in less than three weeks.’ Kos firmly believes that tank cleaning is not a ‘one size fits all’ approach. The company offers a variety of tools to accomplish each project efficiently and believes offering a complete cleaning package, incorporating artificial intelligence, is the key to success. For more information: www.radicalrobotics.ca For Distributer contact: www.precisetools.ca

01 Rear compartment command centre 02 Control room command centre 03 Manway cannon 04 Six inch sweep

• Independent Camera and Lighting Systems • Universal Command Centre complete with the Radical Robotics Interactive Tank Management System. • Portable Mini Control Stations complete with the Radical Robotics Interactive Tank Management System.

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TECHNICAL API 2350 UPDATE

OVERFILL PREVENTION Emerson’s Richard Ireland runs through updates to the API 2350 standard for overfill prevention of atmospheric storage tanks

THE DOMINANCE of the US in hydrocarbon extraction, refining and transportation is supported by the existence of ample, efficient and safe hydrocarbon-storage facilities. The American Petroleum Institute (API) is the recognised standards development organisation for every aspect of the hydrocarbon supply chain. Keeping the precious liquid inside the pipeline or inside the tank is of utmost importance for safety and low environmental impact.

Class I or II liquids and also wheeled vehicles containing the same.

API 2350 is the standard (of minimum requirements) for overfill prevention in atmospheric storage tanks. The standard (formerly referred to as a ‘Recommended Practice’) is now in its 5th edition. Upon the release of Edition 4 in 2011, RP 2350 was elevated to a ‘Standard’ to stress the importance of overfill prevention in the fuel supply chain. We can now explore the re-visitation of the standard in the newly released Edition 5.

Terms, definitions and acronyms

SCOPE OF STANDARD The API 2350 standard is written to apply to all storage terminals with API 650 (atmospheric) tanks that contain NFPA

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Generally (with some exceptions) it does not apply to tanks of 1,320 US gallons (4,997 L) or less, LPG or LNG storage tanks, tanks covered by PEI RP 600 (Overfill RP for shop-built tanks), or dedicated pipeline relief tanks. MAJOR COMPONENTS OF THE STANDARD As always, getting on the same page with the glossary of terms is a good place to start. I highly recommend a read-through of this section. This can eliminate misunderstanding of such terms as ‘attendance’ versus ‘monitoring’ for example. Overfill prevention system (OPS) The OPS portion of the standard is the realisation of the standard with references to the various annexes for more detailed information on implementation.

Annex sections The API-2350 standard can be summed up by the above two sections. Annexes A through G are almost acting as an important, built-in reference library containing detailed information, calculations and examples to provide guidance to the owner/operator wishing to comply with the standard. Most of the annex information is for informative purposes where some are more prescriptive (or normative). SUMMARY OF THE OVERFILL PREVENTION PROCESS (PRACTICE) 4.2 Requirements for a management system Based on many more-recent overfill incidents, it was determined by the industry that poor procedures significantly increase the possibility of an overfill incident. Thus, it has been determined that requiring the tank owner/operator to develop a satisfactory ‘management system’ which clearly outlines operating procedures, tank data, alarm setpoints, calibration data etc.

TECHNICAL API-2350 UPDATE This must be implemented, but edition 5 provides no real prescriptive guidance and relies on the owner/operator to review the full section 4 practice and determine what needs to be designed and implemented that works best for their facility. 4.3 Requirements for a risk assessment The science of assessing risk comes down to one basic formula – RISK = CONSEQUENCE x PROBABILITY API 2350 does not prescribe exactly how to go about performing a risk assessment at your facility. There are three very informative annexes provided to guide the owner/operator: 1. Annex E – An informative overview of risk assessment techniques. 2. Annex F – Considerations at the transporter/owner interface (transfers) 3. Annex G – Informative description of categorisation of tanks for a risk assessment. The owner/operator may choose to use this method of categorisation for risk assessment, which elevates the annex to become a ‘normative’ requirement as part of edition 5. 4.4 Defining operating parameters When do ‘bad things’ happen? This question should be answered before hydrocarbon liquid is allowed flow into a tank. Each tank has certain vital statistics, such as the ‘critical high level’ where liquid spills from the tank. These important levels of concern (LOCs) must be determined for each tank in the facility. Annex D provides a detailed approach to determine these parameters. The method of terminating flow (manual or automatic) is also a factor in this section. If ‘automatic overfill prevention’ (AOPS) is the chosen method, then Annex A is followed. Response time (from alarm sounding to flow termination) also needs to be determined by the owner/ operator or otherwise conform to very conservative LOC levels that could effectively decrease useable storage capacity of the tank. API states that a 3’ minimum liquid level safety margin below ‘critical high’ be maintained in any implementation of the OPS. 4.5.1 Procedure for operations The most important factor in preventing overfill incidents is operational planning and awareness. Relying solely on instruments, sensors and systems to guide you or save you requires very sophisticated and pricey safety integrity level (SIL) rated gear that most facilities

The API 2350 standard is written to apply to all storage terminals with API 650 (atmospheric) tanks that contain NFPA Class I or II liquids and also wheeled vehicles containing the same find unaffordable. It makes much more sense to implement clear and deliberate operating procedure for all aspects of a product receipt. Pre-planning for the receipt, establishing activities that need to be addressed before the receipt arrives. The same for the period during receipt and documenting the completion. Abnormalities and emergencies can arise. Procedure needs to be in-place as to how to handle these events (This should be clearly defined in the management system). Training and drill procedures should be implemented and practiced. 4.5.3 Procedure for testing, inspection and maintenance of OPS equipment We all know the saying ‘Trust but Verify’ and this portion of the OPS walks the owner/operator through the procedures and frequency requirements for verifying (AKA proof-testing) the important sensors and systems in the overfill prevention safety loop. Varying types of sensors are discussed in Annex C with differing testing procedures and testing intervals associated to each type. Annex H provides owner/operators with informative considerations when deciding on a proof-testing regime. 5.1 Types of overfill prevention systems There are basically two types of overfill preventions systems for receipt termination: 1. Manual overfill prevention systems (MOPS) – Flow is terminated by a manual valve or an actuated valve that is closed by a manual operation. 2. Automatic overfill prevention systems (AOPS) – A closed loop of sensors and logic solvers that determine the overfill condition and automatically terminate flow. Wireless technology in the OPS – The goal of the standard is to make overfill prevention a priority with owner/ operators. It also recognises economic barriers such as high installation costs due to lack of wiring infrastructure at many facilities. Edition 5 points to the use of modern, digital wireless networks

as an acceptable means of deploying overfill prevention utilising International Electrotechnical Commission (IEC) and Industry Standard Architecture (ISA) network standards now widely available from major device manufacturers. Owner/operators need to determine based on the result of their risk assessment, which system provides adequate operation by lowering risk, lowering response time or all of the above. If AOPS is chosen, Annex A becomes a prescriptive part of implementation of these systems. 5.2 Tank category criteria One of the main outcomes of the risk assessment is proper categorisation of the tanks within the facility. It is important that the criteria for category determination and the categories themselves make sense across the industry, from facility to facility. Annex G provides informative guidance on determination of tank category. Considerations in determining are for example: • How is the facility attended? Fully? Partially? • Where are the levels monitored? Locally? Remotely? • How are alarms monitored and handled? The overall operational complexity of the facility must be taken into considerations as well. CONCLUSION Not only does our industry count on us to operate in a safe and environmentally friendly manner, our fellow citizens and our families do not give us permission to do otherwise! The API 2350 standard is one of many very important industry standards that were developed by the industry and for the industry. We are fortunate to have the ability of a great amount of procedural self-governance versus being ruled with a bureaucratic heavy hand. The concept of overfill prevention is very simple but there are many things to consider before implementing a system within a facility. API 2350 attempts to frame these considerations into clearly understandable concepts and provide informative examples as a guide. Edition 5 has further focussed the task on the most important aspects of the standard and allows each owner/operator to determine methodologies that best suit their operating culture. For more information: Richard Ireland is from Emerson Automation Solutions, Rosemount Tank Gauging North America.

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TECHNICAL EXPLOSIONS

THE HAZARDS OF PETROLEUM Wayne Geyer looks at the variety of causes in tank fires and explosions, and the importance of awareness EXPLOSIONS and fires in the petrochemical industry capture headline news locally, nationally, and globally depending on the severity and location. Best practices with safety in operations and management are essential to avoid injury and death. Unfortunately, far too many incidents continue to take place. The wide information available today via the internet makes it seem that explosions and fires are becoming more frequent. Whereas before the turn of the century, most incidents captured by headline news were contained to national incidents. A recent review through the internet revealed a surprising number of incidents globally, many of which would have never been heard about twenty years ago. Many petrochemical products are rated as either flammable or combustible. For example, gasoline and ethanol are classified as flammable liquids by the fire safety codes. Diesel, heating oil, and kerosene are considered combustible liquids. Flash points, or the temperature at which their vapours will ignite, determine their rating. The lower the flash point, the more flammable and dangerous the liquid and its vapours become.

Credit: Contra Costa County Fire Protection District

TANK MISHAPS The Steel Tank Institute (STI) used to produce a monthly newsletter entitled Tank Mishaps. STI did not always have the details behind what caused the fire or the explosion, only the news story that was published. With every issue, STI would print this little explanatory introduction: ‘By learning about the misfortunes of others, it is STI’s hope to educate the public by creating a greater awareness of the hazards with storage and use of petroleum and chemicals. Please refer to the many industry standards and to the fire and building codes for further guidance on the safe operating practices with hazardous liquids.’ This article will be no different. By writing about incidents that have taken place recently, the hope is that the reader obtains a greater awareness of the hazards of the petrochemical industry. Safety moments, safety procedures,

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Credit: Contra Costa County Fire Protection District

TECHNICAL EXPLOSIONS safety clothing, safety rules, etc. do not simply exist because a safety manager says so. The consequences of a fire or explosion from improper handling or storage of flammable and combustible liquids is too great – with huge property losses, business devaluation, disruption in supply, and the greatest of unfortunate consequences – injury and death.

NUSTAR IN CALIFORNIA In 2019, before the COVID-19 pandemic, a very significant explosion occurred in Crockett, California, US. NuStar Energy owned a tank farm that included two ethanol storage tanks, each with a capacity of 250,000 gallons (946,353 L). A huge explosion occurred at one of these tanks, so great, that the top of the tank lifted off and landed upon an adjacent ethanol tank, causing it to explode also (Figures 1 and 2). The fire could be seen over a great distance, and the explosion scared many people from the local population who lived near the NuStar facility, some thinking there was a seismic event. Several stories came out after the event, such as allegations that the tanks were built without the local authority’s inspection or permit, structural deficiencies, and damaged valves had not been replaced. But the reports given much later stated that either static electricity, or a spark inside the tank vapour space, coupled with the flammable vapours given off by the ethanol and oxygen intrusion through the vent opening, set off the fireball, with the spark possibly caused by inadequate grounding with equipment used in the storage operation. Fortunately, no one was killed. Over 1.5 million gallons of fire-fighting foam and water mixture were used to contain and extinguish the fire. The two tanks completely collapsed. Words don’t adequately describe the massive fireball that can be seen in videos of the incident. The video of the tank roof flying through the air is available at https://youtu.be/ AN4MfaWJRGo. THE DANGERS OF TORCHES AND WELDING On 19 May 2020, a crew was performing maintenance in a tank farm on Pelican Island in Galveston, Texas, US, near a branch campus of Texas A&M. There was a welding operation occurring near a 2 million gallon crude oil tank. According to a law firm with an interest in such incidents, ‘there was an explosion and fire enveloped the area.’ Two of the welding crew were injured and hospitalised. Fire fighters applied foam to extinguish the flames. The

Credit: Contra Costa County Fire Protection District

footage is available at https://youtu.be/ mIE39dK8djY. I found it to be of interest that another fire occurred at a crude oil tank farm on Pelican Island in 2012. Many from the industry do not view asphalt tanks as being flammable, but a fire in Ennis, Texas in 2018 suggests that due care and following best safety practices are required with asphalt operations also. A five-person contractor crew was hired to retire a damaged asphalt tank. The damaged tank shared a catwalk with another tank. The crew started using a cutting torch on the catwalk, resulting in a tank explosion. Inside Climate News was quoted to say that over a dozen asphalt and #6 bunker oil tanks exploded. Many industry participants view asphalt as relatively benign. But hydrogen sulphide gas can form when certain hydrocarbons are heated to high temperatures, with production of asphalt being one such application. A rule of thumb is that 1 ppm of hydrogen sulphide in the liquid phase of asphalt correlates to 400 ppm in the vapour phase. Some asphalts can produce over 30,000 ppm in the vapour phase in a confined space such as a storage tank. Safety regulations limit hydrogen sulphide exposure to workers to less than 10 ppm, with the potential of death at 700 ppm. Hydrogen sulphide is also flammable, as well as various chemical additives. Both the Pelican Island crude oil tank incident and the Ennis asphalt tank involved welding or cutting torch operations near storage tanks in operation. Regardless of the petrochemical in storage, at terminal operations, all work involving flames must be first tested for flammable vapours in the atmosphere where the work is to be done.

REFINERY EXPLOSIONS In the past few years, there were also some significant explosions at refineries. In Indonesia, on 29 March 2021, a lightning strike caused an explosion and a resultant tank fire that spread to other tanks at a refinery owned by state oil company Pertamina. 1,000 people had to be evacuated. Five people were seriously injured, fifteen were reported to have slight injuries, and one death resulted from a heart attack. On 26 April 2018, the Husky Energy Refinery in Superior, Wisconsin, US, experienced a major explosion. Workers shut down a fluid catalytic cracker (FCC) to allow periodic inspection and maintenance work. The FCC uses heat and a solid catalyst to break down, or crack, heavy hydrocarbons into smaller hydrocarbons, which can then be blended into gasoline. Slide valves control the catalyst between the reactor, with hydrocarbons, and the generator, which has air. To avoid the air to get mixed with the hydrocarbons and prevent explosion, the slide valves maintain a catalyst level between the reactor and the generator, which acts as a barrier. To initiate the shutdown of the FCC unit, the workers closed the two slide valves. But unbeknownst to the workers, a valve stem was eroded and could not hold and maintain the catalyst as a barrier. This allowed the catalyst to flow through to the generator. Further, this allowed air from the generator to flow backwards through the valves to the reactor. The air continued to flow backwards until it reached equipment downstream of the reactor containing flammable vapours. At this point, the air and flammable vapours mixed, and a large explosion resulted. Debris was hurled everywhere. One large piece travelled 200’ (61 m)

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TECHNICAL EXPLOSIONS companies, national testing laboratories, regulators, safety organisations, and petroleum equipment. The NFPA 30 Code was first published in 1906, and it is reviewed and normally updated every three years. In the US, OSHA created and oversees regulation of flammable and combustible liquids. Other countries have similar organisations as NFPA, such as the Association For Petroleum & Explosives (APEA) in the UK, and regulatory bodies.

Credit: Environment Agency

and pierced a large hot asphalt storage tank. This allowed the asphalt to escape the tank. The asphalt travelled over a containment berm and caught fire. The fire travelled along the pooled asphalt surrounding the crude oil storage and the FCC. People were evacuated as far as 5 miles (8 km) from the refinery, and 36 Husky employees and contract workers sought medical treatment. Asphalt tank fires are difficult to extinguish, but the local fire emergency responders were able to extinguish the fire in a matter of hours, instead of days. A great animation of this incident was produced by the US Chemical Safety Board at https://www. youtube.com/watch?v=3RFDKpwdbEA. SMALL TANK EXPLOSIONS Thus far, the incidents described in this article took place on large field erected storage tanks. But small shop-fabricated storage tanks incidents prove that explosions, death, and injury are not just limited to tanks storing millions of gallons of petrochemicals. A couple of large explosions took place at petroleum service stations where the public fills their vehicle with petrol. Information was almost non-existent with a couple of these events, but the videos of the incidents are worth a million words. If these explosions do not cause industry workers to respect and fear the dangers of petroleum, nothing will. An underground tank exploded in Madinah, Saudi Arabia in 2019. Customers filling their cars with fuel can be seen to drop the nozzles and run away as fast they could. Others got into their cars and drove away as fast as they could. With 35 years in the business, I have never seen an underground tank explosion like this incident! The footage is available at https://youtu.be/Bgv_E6dGUZQ.

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A large fuel station explosion was reported in Bayda, Yemen on January 30, 2021, resulting in two deaths, 90 wounded, and 20 critically wounded, with many cars and homes destroyed. Another explosion in Novosibirsk, Russia occurred while a fuel tanker was unloading its contents. Flammable liquid tanks in confined spaces, such as in vaults, provide some of the most hazardous conditions of all. Two explosions in vaults at service stations in Virginia and Pennsylvania resulted in numerous fatalities recently. In one situation, an employee tried to remove accumulated groundwater that seeped into the concrete vault while flammable vapours (and perhaps liquids) were present, using a non-hazardous rated shop-vacuum and a common workshop electrical extension cord, and also without the use of liquid or vapour sensors to establish the hazards – while a truckload of fuel had been just delivered. SLAMMING THE MESSAGE HOME The national fire codes have very demanding requirements for fuel tanks in concrete vaults due to the potential for spills and flammable vapours becoming contained in a vault, and creating an explosive environment, especially if an ignition source becomes present. I have served on committee of the NFPA 30 Code for 35 years. This is the National Fire Protection Association’s (NFPA) Code on Flammable and Combustible Liquid Storage, adopted by many jurisdictions and authorities by regulation, to assure safety during storage, transport, handling, and operation of these dangerous liquids. The committee is composed of experts from the petrochemical industry with experience in storage and operations, insurance

Flammable and combustible liquids entail significant built-in energy by their chemistry. When the right mixture of flammable vapour and oxygen combine in conjunction with a flame source, KABOOM, explosions and fire can result. I hope you, as the reader of this article, already know of the hazards, but maybe this article slams one important message that you will not forget. Explosions at petrochemical facilities create tremendous damage, and injury or death. It is imperative that workers at petrochemical facilities respect the dangers that exist with flammable and combustible liquids and vapours, especially work involving a flame source and the presence of oxygen. Welders and acetylene torch users must use care and always check for flammable and combustible atmospheres before beginning work. Train workers, no matter how insignificant the task may be while in the presence of hazards. Monitor the air for dangerous vapours. Get special permits in confined space or when performing work near flammable and combustible liquid storage or operations. Follow important codes and regulations. Share the videos to help workers understand the hazards. It could save a life some day! For more information: Wayne Geyer is a professional engineer who has served on the NFPA 30 Flammable and Combustible Liquids Code since 1986, and was the executive vice-president of the Steel Tank Institute for over 30 years. He gave a talk on this subject at the NISTM Aboveground Storage Tank Conference and Trade Show held from 31 August–2 September 2021 in Florida, US.

01 The build-up to the fire at NuStar’s terminal in Crockett, captured on CCTV 02 The aftermath of the NuStar Crockett fire 03 The Buncefield fuel depot disaster on 11 December 2005 is widely thought to be the biggest peacetime explosion ever in the UK, and was caused when an unleaded petrol tank was overfilled and a resulting vapour cloud ignited. 20 tanks were destroyed.

TECHNICAL TANK CLEANING

TURNING SLUDGE INTO PROFIT HydroCarbon Solutions’ tank cleaning technology generates useable oil from tank sludge BORN IN oilfields of West Texas back in 2004, HydroCarbon Solutions (HCS) has been cleaning aboveground storage tanks one at a time for the past 17 years. Bringing environmentally friendly technology and non-person entry to the hazardous job of crude oil tank deposition cleaning, HCS has seen the demand for their services double in that time. ASSET RECOVERY TECHNOLOGY The tank cleaning fluid used by HCS un-bonds the paraffin wax by converting it back into liquid oil which can be more easily removed. HCS has products for oil wells, pipelines, storage tanks and barges. The technology can mitigate risks to both the environment and onsite personnel, while recovering lost revenue for crude oil asset owners and operators. The tank cleaning technology is the result of 20 years of work on hydrocarbons and waxes by HCS chemists. HCS believes that its tank cleaning technology is the easiest and most effective way to generate additional revenue from crude oil sludge, as it converts it back into an on-spec crude which is ready for market. The technology has been tested by several major oil company laboratories, which have found no adverse effects on the base crude oil or equipment such as storage tank liners.

TABLE 1: HOW IT WORKS Deposition reducing chemical

Conventional method

Liabilities turned into assets – unwanted sludge is now a saleable crude oil product

Loss of inventory – and revenue with no merchantable asset

The HCS process requires minimal third-party equipment and personnel

High expenditure on specialist equipment and additional personnel

Significant reduction in costly out-ofservice time for cleaning, inspections, repairs and maintenance

Tankage out-of-service for extended time periods through labour-intensive cleaning

Treats sludge accumulation and protects against water corrosion and paraffin build-up Non-person-entry reduces risks to on-site crews by limiting exposure to hazardous confined spaces

Workforces repeatedly exposed to hazards from confined spaces and toxic environments

then flashing off the light ends. HCS developed a paraffin treatment that saves time and cost, keeps the rods clear of paraffin, and migrates downstream to keep everything flowing. Valves and provers work more efficiently as well. Storage tanks The HCS process offers a unique solution to accumulated crude oil tank bottoms. This means limited hazardous substances need to be extracted after the process is complete and no personnel need enter the tank until after the hazardous material is gone. HCS cleaning fluids are added to the tank and mixed, and the newly-converted oil can be sold. The tank can be returned to service if this is a preventative maintenance exercise, or prepared for full API 653/EEMUA 159 tank inspection.

OPPORTUNITIES FOR PROFIT HCS has found that owners and operators of oil wells, storage tanks, barges, or pipelines which use its technology can profit from the process, as the value of the newly recovered crude oil is far higher than the initial cost of using any of the treatments. HCS estimates that typically, for every US$1 spent on a chemical treatment there will be a return of US$5-8 in saleable crude oil, depending on market prices. For most tank farms, the savings are in tank cleaning costs, and HCS estimates that for every US$1 (€0.85) spent on the cleaning chemicals, a tank farm will save US$3 in cleaning expenses. The cleaning process can take as little as one month.

Hazardous waste disposal process worsens environmental impact

Pipelines APPLICATIONS Oil wells The HCS process can be used to treat paraffin downhole to eliminate hot oiling. The treatment saves on heating oil and

HCS has been optimised for the treatment of asphaltene and paraffinic wax in oil pipelines. Small amounts of HCS can be added to keep pipelines free of asphaltene and paraffinic wax buildup. The process maintains the internal

PAGE 49

TECHNICAL TANK CLEANING

diameter of the pipe, thus maximising design flow rates, by reducing pipeline drag, and avoiding costly out-of-service time. This is more prevalent in some older oil field operations where the reservoir temperature has dropped. The build-ups of asphaltene and paraffinic wax means that operators must increase the frequency of pigging, which can be a costly exercise. HCS offers a low freeze point pipeline cleaner suited to low temperature installations

and reaches the pour point wax crystals start to appear and become solid at room temperature. These aromatic hydrocarbons are important because they prevent the crude’s larger, straight-chain hydrocarbons from interacting with one another and forming Van der Waal bonds. These bonds lead to the larger molecules clumping together, ultimately leading to an increase in viscosity and the formation of waxes and asphaltenes - or sludge.

Crude oil barges HCS cleaning technology is suitable for use in crude oil barge compartments. When a small quantity of the product is added to the crude oil cargo, it will homogenise with the asphaltene and paraffinic wax in-transit to its home port by the natural agitation of the waves. This enables the extraction of asphaltene and paraffinic wax as a saleable product at the destination port. HOW IT WORKS HCS works by restoring fluid characteristics to high-viscosity crude oil sludge, separating the contents into three-phases: the constituent crude oil, water, and inorganic solids, such as sand, grit and metals (BS&W).

The value of the newly recovered crude oil is far higher than the initial cost of using any of the treatments

Paraffin is an alkane hydrocarbon with the general formula (CnH2n+2). Paraffin or paraffinic petroleum derivatives include paraffin oils and paraffin wax. Paraffin wax consists of alkane mixture where chain length ranges from 20 ≤ n ≤ 40 range. The hydrocarbon chains are found in both straight and branched forms. As the temperature of certain crude oils drops

Unlike the aromatic hydrocarbons, the HCS additive is not itself volatile. It has a flash point of 97°C, meaning it remains in the crude without evaporating, preventing the formation of the longchain hydrocarbon clumps that lead to sludge deposits. In short, HCS mimics the behaviour of the lost aromatic components of the crude, but without evaporating at normal atmospheric temperatures, so the paraffinic wax does not reappear. For more information: Contact HydroCarbon Solutions for more information or to arrange a free consultation. Jack McLean at jmtankman@gmail.com or +1 506-962-3064 Chris Hastings at chrisfhastings@icloud. com or +1 832-392-7158 www.hydrocarbon-solutions.com

01 Test sample of 10-year-old dehydrated tank bottom (sludge) 02 Even after 4 months, the mixture of dehydrated sludge, HCS tank cleaner and additional crude oil is still in liquid form with no signs of the wax reforming

PAGE 50

TECHNICAL INSPECTIONS

ADVOCATING FOR RISK-BASED INSPECTIONS IN THE US Ingrid Pederson looks at the drawbacks of time-based inspections and the improvements gained by switching to risk-based inspections

POLITICAL OBSTINACY frequently cancels new pipeline projects while the energy demand continues to grow. This dichotomy is requiring existing infrastructure to be maintained longer and pushed harder. At the same time oil price crashes and a global pandemic have squeezed maintenance budgets. The conservatism built into American Petroleum Institute (API) Standard 653: Tank Inspection, Repair, Alteration and Reconstruction, can result in some aboveground storage tanks (AST) taken out of service more frequently than necessary while following a time-based inspection schedule. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has incorporated by reference the 2008 edition of API 653 excluding section 6.4.3, thus disallowing risk-based inspections (RBIs) for ASTs for any owner/operator that is federally regulated in the US. TANK INTEGRITY MANAGEMENT PROGRAMMES The purpose of a tank integrity management programme is to maintain the condition of the tank so that it remains operable. Ensuring safe operation also

minimises unplanned outages and maximises the value gained from the asset. Tank bottom evaluation cannot typically be assessed while the tank is in service, thus this tends to be the driving factor in internal inspections, also known as out-of-service (OOS) inspections. One method of improving the efficiency of an integrity management plan is to incorporate risk in the evaluation of a tank’s inspection interval. An RBI approach can be used to compare the risk trend of a tank against a risk target to determine whether an internal inspection is required earlier or later than the timebased approach currently allowed by the Code of Federal Regulations (CFR) for all Department of Transportation (DOT) regulated ASTs. Risk can be leveraged directly as part of a risk-based inspection programme with discrete risk targets or limits. Alternatively, it can be utilised as one of multiple criteria in a risk-informed inspection program which incorporates the risk while allowing for other inputs. An example of what RBIs for ASTs might look like can be taken from API RP 581, Risk-based Inspection Methodology. This RBI modelling provides semi-quantitative calculation methods to determine inspection plans. API RP 581 combines probability of failure (PoF) model and the

consequence of failure (CoF) combined to provide a risk ranking. Inputs into the PoF model include construction data, basic operating data and inspection results. PoF is typically flat for a leak failure mode until minimum allowable remaining thickness (MRT) is reached, at which point it becomes exponential. Both MRT and the repair threshold are inputs into the 581 model. The repair threshold is dependent on what the owner/operator sets their reinspection interval at within the maximum allowed by API 653. REASONS FOR NON-INCLUSION PHMSA declined to incorporate the latest edition of API 653 in their 2015 Federal Register ruling1. Rather this ruling retains API S653–2001 (3rd edition, December 2001), with the exception of section 6.4.3, ‘Alternative Internal Inspection Interval.’ PHMSA stated they have excluded section 6.4.3 because of concerns that the RBI procedures described in section 6.4.3 of the standard do not require adequate or consistent assessment factors for establishing an alternate internal inspection interval. Operators utilising an RBI program for their ASTs only had two years to comply with the 2015 ruling. This change caught

PAGE 51

TECHNICAL INSPECTIONS many operators by surprise and created a significant challenge to schedule internal inspections in such a short time frame. An OOS maintenance project can easily take three to six months to execute on large tanks as well as have a significant impact on operability of the pipeline(s) due to the reduced storage capacity. OOS maintenance also requires extensive safety measures as workers are sent into confined spaces. This ban on risk assessment is specific to ASTs abiding by API 653. PHMSA requires risk assessment in high consequence areas. CFR § 195.452 ‘Pipeline integrity management in high consequence areas’ states that an operator must do risk analysis to evaluate likelihood of a pipeline release and must take measures to prevent and mitigate consequences of a pipeline failure.’2 The intent of DOT incorporation of industry standards as per The National Technology Transfer and Advancement Act of 19953 directs Federal Agencies to use voluntary consensus standards and design specifications developed by voluntary consensus standards bodies rather than government-developed technical standards. This should oblige regulators to adopt the latest editions of these standards. API technical standard committees are continuously reviewing and revising standards to make them better, as new technology is developed, lessons learned, clarifications requested, etc. The Canadian Standard Association’s Z662: Oil & Gas Pipeline Systems standard doesn’t necessarily keep up with the latest editions of API 650, API 653, etc. However, it includes a note in Section 2.1: ‘This Standard refers to the following publications, and where such reference is made, it shall be to the edition

listed below, unless the user finds it more appropriate to use newer or amended editions of such publications.’ UTILISING RBIS How could owner/operators regulated by the DOT and interested in optimising tank maintenance utilise risk-based inspection techniques? Industry advocacy needs to have clearly defined objectives, demands and targets (e.g., who has the power to make the change). Advocacy efforts must be both logical and flexible to achieve the desired result. Five components to include in an advocacy framework: 1. Knowledge transfer, such as conferences or training. 2. Industry benchmarking – activities to support benchmarking with industry peers to set targets and/or compare against, (e.g., industry metrics, as low as reasonably practicable (ALARP) levels, recommended practices, standards and guidance, etc.). 3. Best practices including activities to integrate the reliability framework within internal management systems. 4. Regulations and standards: This could include challenging regulators to follow the latest editions of major industry standards, formal requests to change regulations, influencing and improving codes and standards and awareness of applicable codes and standards.

standards to be adopted, or other advocacy efforts, tank inspection interval setting needs to improve beyond the simplistic time-based methodology used today. With the extreme difficulty of building new pipelines in North America existing infrastructure needs to be managed more efficiently than ever, optimising inspections while reducing risk of incidents. A risk-based programme is needed to achieve both these goals. References 1. Pipeline Safety: Periodic Updates of Regulatory References to Technical Standards and Miscellaneous Amendments, May 2015, https:// www.federalregister.gov/documents/2015/01/05/2014-30336/ pipeline-safety-periodic-updates-of-regulatory-references-to-technical-standards-and-miscellaneous 2. CFR § 195.452 ‘Pipeline integrity management in high consequence areas’ states that an operator must do risk analysis to evaluate likelihood of a pipeline release and must take measures to prevent and mitigate consequences of a pipeline failure’, December 2000, https://www.ecfr.gov/ current/title-49/subtitle-B/chapter-I/ subchapter-D/part-195#195.452

5. Internal metrics to drive corporate behaviours and culture (e.g., industry metrics, performance targets, ALARP levels, other benchmarking inputs).

3. The National Technology Transfer and Advancement Act of 1995, Pub. L. 104-113, March 1996, https:// www.nist.gov/standardsgov/national-technology-transfer-and-advancement-act-1995

Regardless of special permit submissions, petitioning for the latest

For more information: This article was written by Ingrid Pederson P. Eng, engineering specialist, facilities integrity storage at Enbridge.

Disclaimer: Any information or data pertaining to Enbridge Employee Services Canada Inc., or its affiliates, contained in this article was provided to the authors with the express permission of Enbridge Employee Services Canada Inc, or its affiliates. However, this article is the work and opinion of the author and is not to be interpreted as Enbridge Employee Services Canada Inc, or its affiliates’, position or procedure regarding matters referred to in this article. Enbridge Employee Services Canada Inc and its affiliates and their respective employees, officers, director and agents shall not be liable for any claims for loss, damage or costs, of any kind whatsoever, arising from the errors, inaccuracies or incompleteness of the information and data contained in this paper or for any loss, damage or costs that may arise from the use or interpretation of this article.

PAGE 52

TECHNICAL TANK SETTLEMENT

TANK FOUNDATION SETTLEMENT TOLERANCE Atlas Geotechnical’s Doug Schwarm provides a case study on tank settlement from Port Moody in Canada ANNEX B.1.2 of API 653 Tank Inspection, Alteration and Repair sets the stage for this case history by stating ‘[re]-levelling of a sizable tank is expensive and rather difficult to achieve. Thus, a decision to re-level a tank is a crucial one and relies very much on the proper interpretation and evaluation of the monitored settlement data.’ Tank 42 at Pacific Coast Terminals’ facility in Port Moody, British Columbia, Canada, provides an unsurpassed example of the settlement tolerance of above-ground welded steel storage tanks and how proper interpretation and evaluation can avoid unnecessary costs and downtime. The tank measures 120 ft in diameter and 60 ft high (37 m x 18 m) and is on a conventional crushed rock ringwall with a cone-up bottom. The tank is designed for canola oil service (Gs=0.92), so the maximum bottom plate pressure is 3,400 lb/ft2.

to retain an expert tank engineering consultancy for an independent analysis. Interestingly, the settlement data during the 44-day hydrotest interval were presented in tabular form, not graphically as shown in Figure 2. The first step of the analysis was to present the data using tools very familiar to tank inspectors and engineers. The hydrotest monitored settlement at 12 locations around the periphery and points 4 and 10 are diametrically across from each other, an observation that would be crucial to the detailed analysis. API 653 FOUNDATION SETTLEMENT TOLERANCE A brief overview of tank foundation settlement may be appropriate before describing the analysis and mitigation that allowed the tank to be placed in service. Foundation settlement can be interpreted as the sum of total, planar, and non-planar differential:

HYDROTEST SETTLEMENT Figure 2 shows the elevation surveying results for two points around the Tank 42 periphery during the pre-service hydrotest. The red line indicates the water level, which was held at 13.5 m for about six days before being increased to the 18.0 m design depth for an additional 10 days.

• Total settlement is the amount of settlement that can be applied equally at all points. • Rigid planar tilt of a circular tank base, when unrolled onto the abscissa of the graph, is represented as an optimum cosine curve. • Non-planar differential is the excursion above and below the optimum cosine curve. That third component, differential settlement away from a tilted plane, is the important one. Differential settlement induces shear that deforms the shell away from cylindrical, potentially causing floating roof problems and, if severe enough, overstressing the welds and steel. Importantly, API 653 places no limits on uniform or planar-tilt settlement. Assuming that piping connections are relieved and that the deeper liquid level on the downside remains within design limits, stresses in the tank shell are nominally unchanged for almost any

Total uniform settlement of 44 mm (about 2 in) was not unexpected for the waterfront site. However, settlement of up to 12.5 in at one point was much more than the design team had expected. The maximum tilt between points 4 and 10 was 11 in, enough to cause significant concern about the tank’s integrity. The design engineer undertook a rigorous engineering analysis of the settled tank that employed numerical simulation using four different software packages. Rather than offering improved understanding of Tank 42’s fitness for service, the models yielded improbably diverse results ranging from moderate yield to almost certain tank failure. Obviously, the tank had not failed, and the shell appeared only slightly deflected. The difference between the model results and observable conditions prompted Pacific Coast Terminals PAGE 53

TECHNICAL TANK SETTLEMENT Figure 2 shows the elevation surveying results for two points around the Tank 42 periphery during the pre-service hydrotest. The red line indicates the water level, which was held at 13.5 m for about six days before 02 being increased to the 18.0 m design depth for an additional 10 days. 0

-3 -6

-8 -14

-16 -18 -17-18 -18 -18 -20 -18 -19 -19 -20 -19 -20 -22 -22 -23

-27 -28 -28 -32 -32 -32 -33 -33 -34

-37 -39 -39 -40

-47

−50

-42 -44 -41

-37

-30 -29 -30 -29 -31

-32

Monitoring Point 10

-76

−100

-102 -106

-118 -120

-143 -144 -152 -154 -160 -162 -167 -170 -177 -183

−200

-200 -205

Water Height (m)

Settlement (mm)

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-219 -225 -237 -240

−250

Monitoring Point 4

-262 -273

-283 -291 -297

-301 -299 -300

-298 -300

-307 -317

-322 -322

-317 Ultimate Settlement 410 mm

−350

0 10

25 30 Elapsed Time (days)

Figure 2 - Tank 42 Differential Settlement

Total uniform settlement of 44 mm (about 2 in) was not unexpected for the waterfront site. However,

settlement of up to 12.5 in at one point was much more than the design team had expected. The credible amount of uniform and rigid for-Service methodology, these data maximum tilt between Points 4 and 10 was 11 in, enough to cause significant concern about the tank’s planar tilt settlement. allowed an early conclusion that the integrity. tank remained within API 653 limits The design engineer undertook a rigorous engineering analysis of the settled tank that employed for foundation settlement. The review numerical simulation using four different software packages. Rather than offering improved understanding SETTLEMENT MITIGATION teamdiverse concluded almost certainly of Tank 42’s fitness for service, the models yielded improbably resultsthat ranging from moderate could beshell placed in service with yield to almost certain tank failure. Obviously, nottank failed, and the appeared only slightly Plotting out the hydrotest elevation data the tank hadthe deflected. The difference between the model results and observable conditions prompted Pacific Coast manageable repairs. yielded a clear indication of planar tilt with Terminals to retain an expert tank engineering consultancy for an independent analysis.

almost no differential above or below the Point 4, the lowest around the periphery, Interestingly, thecurve. settlement data3during thethe 44-day hydrotest interval were presented in tabular form, not optimal cosine Figure shows had been settling at a rate of about graphically as shown in Figure 2. The first step of the analysis was to present the data using tools very results bottom scan, which 5 mm/day when the hydrotest endedthe and familiarof tothe tankinternal inspectors and engineers. The hydrotest monitored settlement at 12 locations around confirms the tank tilted about 16 in across from periphery that and Points 4 and 10 are diametrically observation that would bethe theeach loadother, was an removed. Extrapolating crucial to (point the detailed analysis. from 90° 10) to 270° (point 4). It data suggested that several more inches also revealed that the initial 15 in (374 mm) of planar tilt would occur after filling the cone-up centre had settled to about 6 in. tank with canola oil. It was decided to pre-induce this settlement by re-filling Even though the review was being the tank with water for an additional few performed using API 579 Fitness-

PAGE 54

Before placing the tank in service, the internal columns were adjusted to match the settled distance between roof and floor and the piping connections were adjusted to match the settled nozzle elevations. By good fortune, the largediameter nozzles happened to be on the ‘minimal settlement’ side of the tank. The columns and the piping were both set a little high or a little long anticipating modest long-term additional settlement.

-251 -253

−300

weeks. After the remaining settlement had reduced to within tolerable limits, the tank was drained and re-scanned to confirm that the extra several inches of settlement continued to be almost perfectly planar.

5-YEAR PERFORMANCE Tank 42’s first 5-year in-service inspection was completed in January 2019. Figure 4 shows the history of settlement for each foundation monitoring point around the tank chime. Pairs of points are assigned matching colours as a way to emphasise how truly planar the tilt has remained. Over its first five years of service, Tank 42 has settled up to 19 in, with differential of 17 in across the diameter. Differential settlement away from the optimal cosine curve continues to be inconsequential. Figure 4 shows the January 2019 foundation settlement curve. In over 30 years evaluating tank foundation settlement problems, the author has never encountered a similar occurrence of almost perfect planar tilt. External scans indicate that the shell is up to 8.54 in out of plumb over its 60 ft height, a tilt of 1.2%. The tilt is noticeable to observers standing in the optimal location. For comparison, at its maximum, the leaning tower of Pisa tilted

TECHNICAL TANK SETTLEMENT standards helped avoid an unnecessary re-levelling and allowed the tank to be placed into service with minimal delay.

04 0

Hydrotest November 2014

Point 1 Point 2 Point 3 Point 4 Point 5 Point 6

−50

Point 7 Point 8 Point 9 Point 10 Point 11 Point 12

ACKNOWLEDGEMENTS

−100 Monitoring Point 4

−150

373 mm

−250

431 mm

−300

Water Height (m)

Settlement (mm)

−200

This paper grew out of a presentation at ThinkTanks21, an industry event sponsored by Ranger Inspection and PEMY Consulting. The author is grateful to Phil Myers and Alex Romanow for inviting us to present. Bill Thiessen and Andre Olivier at Pacific Coast Terminals deserve our appreciation for recognising the value of sharing this case history with other operators and engineers.

−350

For more information: −400 Monitoring Point 10

Water Load June 2015

−450 −500

29 January 2019

4 November 2014

200

400

600 800 1000 Tank Service Duration (days)

1200

1400

1600

Figure 5 - 5-year Foundation Settlement

Over its first 5 years of service, Tank 42 has settled up to 19 in, with differential of 17 in across the diameter. Differential settlement away from the optimal cosine curve continues to be inconsequential. 3.9 m over its 55.9-m height, slope of settlement curve. exhibited exemplary management Figure 6 shows the January 2019 afoundation In over 30 years evaluating tank when foundation settlement problems, author has never encountered a similaraoccurrence of almost perfect 6.98%, almost 6 times morethe tilted than they authorised detailed engineering planar tilt.42 shell. the Tank assessment and, when that assessment

SUMMARY The planar tilt that affects Tank 42 demonstrates the resiliency of aboveground welded steel storage tanks. Foundation settlement is often unavoidable, but tilt of this magnitude could not have been anticipated. Pacific Coast Terminals

returned results inconsistent with observed conditions, retained an expert for a careful interpretation and evaluation of the monitored settlement data. The guidance in API 653 Annex B represents over 50 years of collected industry wisdom about operating safely in the face of difficult foundation conditions. Familiarity with, and effective use of, the

Doug Schwarm, PE, GE, PEng, is Chief Engineer at Atlas Geotechnical, a foundation engineering consultancy serving heavy infrastructure clients throughout North America and the Pacific. In 30 years supporting the oil and gas industry he has sorted out tank foundation problems from Fort Mac to Pascagoula, Newfoundland to Guam. www.atlasgeotechnical.com

01 Tank 42 at Port Moody, BC 02 Tank 42 differential settlement 03 Tank floor settlement (Figure from Novlum) 04 Five-year foundation settlement 05 Interpreted foundation settlement curve (Figure from Novlum)

PAGE 55

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North American edition of Tank Storage Magazine

Articles inside

Turning sludge into profit

Advocating for risk-based inspections in the US

The cost of natural disasters

The hazards of petroleum

Overfill prevention

Branching out into renewables

From lasers to tanks

Tank terminal update

Building for the future

Crunch time

North America

ILTA adopts – and acts on – ESG principles

The outlook for oil storage in a lower carbon economy