Chevron LNG Workers Reject Company Offer, Prepare For Strikes

By Irina Slav - Sep 01, 2023

The union representing workers at two Chevron LNG projects in Australia have rejected a company offer for new pay and conditions, and are now preparing to start industrial action next week unless an improved offer is made.

"Ballot results show that they (Chevron) are out of touch with OA members and haven’t listened to a word spoken in their discussions with members, Reps and the Offshore Alliance," the Alliance—a coalition of two trade unions representing workers in the energy industry—said in a Facebook post cited by Reuters.

Chevron, for its part, said "The vote [that rejected the offer] was part of the bargaining process and an important step which enabled employees to share their views."

The U.S. supermajor operates the Gorgon and the Wheatstone LNG projects offshore Australia. The two together account for about 5% of global LNG supply. Chevron has been locked in a pay and working conditions dispute with its workers for weeks now, while sector player Woodside, the operator of Australia’s largest LNG facility, the North West Shelf, managed to strike a deal and avert a strike.

Because of the disputes, gas prices, especially in Europe, have become extra jittery in the past couple of weeks, highlighting the precarious balance of supply and demand in liquefied natural gas. For now, Europe’s demand is relatively low, as storage is full and consumption is low in the summer months. But a strike at Gorgon and Wheatstone would no doubt lead to a temporary price spike just when Asian buyers begin to step up purchases ahead of winter.

Unless Chevron and the unions come to an agreement, workers at Gorgon and Wheatstone will begin striking on September 7 and continue until September 14, with work stoppages and bans on performing certain tasks for up to 11 hours a day.

By Irina Slav for Oilprice.com

 

Shale Gas Boom Led To Thousands Of Job Losses In Appalachia

By Alex Kimani - Aug 27, 2023,

• Ohio River Valley Institute: the shale gas boom failed to replace lost jobs in the Appalachia steel industry.
• 
  
• Since 2008, the Appalachian region showed a 1.6% gain in employment before those gains upturning into a 2.1% loss, good for the loss of 10,000 jobs as well as a 4.8% decline in the population in 2021.
• 
  
• EIA: peak production in the Appalachia will not be equaled again until 2045.

A fresh study on Appalachian has revealed that the shale gas boom in those regions not only failed to replace losses from the steel industry but actually led to even bigger job losses. The study by Ohio River Valley Institute, a Pennsylvania-based think tank, has examined the economic outcomes for 22 counties spanning Ohio, Pennsylvania and West Virginia, responsible for 90% of Appalachian gas production. The data showed gas production has “deteriorated” and job growth has gone from “meager” gains in 2008 to “an absolute decline”. Since 2008, the Appalachian region showed a 1.6% gain in employment before those gains upturning into a 2.1% loss, good for the loss of 10,000 jobs as well as a 4.8% decline in the population in 2021.

According to the ORVI report, a slowed increase in global demand for natural gas, challenges in pipeline construction to connect the region to areas where oil can be exported and even the war in Ukraine have all contributed to the declines seen in the Ohio Valley.

“This report, its predecessors and struggling downtowns in communities throughout Frackalachia provide overwhelming evidence that the predictions weren’t only wrong, they were the products of deeply flawed and biased analyses. And, more importantly, the reasons why the natural gas boom and its offspring … failed to deliver on promises of economic prosperity are structural in nature, meaning they are not going to change,” the report says.

EIA researchers have predicted that peak production in Appalachia “will not be equalled again until 2045,” while other parts of the country could surpass the region in gas production by 2050.

Source: Bloomberg

But it’s not just Appalachia’s oil and gas sector that’s facing major challenges. Norwegian oil and gas consultancy Rystad Energy has predicted that at least 20% of jobs in drilling, operational support and maintenance could be replaced by robots and automation over the next decade.

According to the energy watchdog, increasing use of automation could eliminate as many as 140,000 jobs in the oil and gas sector by 2030.

Robots are already emerging as a popular low-cost alternative in the fast-growing offshore industry, where they are capable of remaining underwater indefinitely and can easily access places that are difficult to reach for human-operated submersibles.

Digital Roughnecks

Scrum master. Cloud architect. Data scientist. Agile coach.

At a time when roughnecks are rapidly becoming an endangered species, demand for skills like these is growing as technology plays an ever increasingly larger role in the oil and gas sector. A younger, diverse class of tech workers holding titles such as user experience designer or data engineer are increasingly replacing roughnecks, roustabouts and other blue collar workers who have normally formed the bulk of jobs in Texas shale or platforms in the Gulf of Mexico.

With oil prices crashing a few years ago, oil and gas companies started making a major push to digitize and automate their operations, allowing complex operations such as offshore drilling in the middle of the ocean in West Texas to be operated and monitored from control rooms in Houston. Consequently, six-figure tech jobs that prize skills such as design, coding, computer system architecture and data analysis over physical prowess have been growing--just not fast enough to replace the tens of thousands being lost in traditional roles.

Robotics have gained the most traction in recent years as they continue to prove their worth in inspection, maintenance and repairs. For example, Norwegian oil and gas giant Equinor ASA (NYSE:EQNR) uses self-propelled robotics arms developed by Kongsberg Maritime to carry out subsea maintenance and repair in confined spaces.

Oil and gas drilling--one of the costliest and most dangerous tasks in oil and gas production--also stands to be upended by robots.

The efficiency and productivity gains are real and not just some ivory tower technological fetishism.

Rystad estimates that using robotic drilling systems can reduce the number of roughnecks required on a drilling rig by 20-30% and lower the annual cost of wages in the sector by more than $7 billion by 2030.

Karr Ingham, economist at the Texas Alliance of Energy Producers, has declared:

"We don't need as many employees to produce record and growing amounts of crude oil and natural gas, and potentially as much as we need. These efficiencies have been coming. They've been in place and growing for some time. All industries do this."

Still, it’s going to be years before digital roughnecks become a common sight in our oil and gas field.

First off, robots are yet to be widely tested in the oil and gas sector and still suffer from limited communication capabilities between units. You can also expect labor organizations to fight tooth and nail to limit further automation and use of robotics, which are likely to come under strict federal safety and environmental regulations.

By Alex Kimani for Oilprice.com

Big Oil's Empty Green Promises

By Felicity Bradstock - Aug 31, 2023

• An analysis shows that just 0.3% of production from twelve of Europe’s leading fossil fuel producers came from renewable energy sources in 2022, and only 7.3% of their investments went toward renewable energy.
• 
  
• Some oil companies, including BP and Equinor, even reduced their investments in renewable energy in 2022 compared to the previous year, despite making ambitious climate pledges.
• 
  
• The International Monetary Fund reported that global subsidies for oil and gas hit a record high of $7 trillion in 2022, indicating a continued preference for fossil fuels over renewable alternatives.
• 
  

Despite big promises, recent reports suggest that international oil majors are doing little to contribute to the green transition when compared to their ongoing investments in oil and gas operations. Studies show that much of Big Oil’s investment in renewable energy operations is going towards PR efforts to promote the green work they are doing, rather than to greatly expand their clean energy portfolios. In addition, oil and gas subsidies hit record levels last year, showing the ongoing preference for fossil fuels over renewable alternatives. 

An analysis commissioned by Greenpeace Central and Eastern Europe has revealed just 0.3% of production from twelve of Europe’s leading fossil fuel producers came from renewable energy sources in 2022. The report showed that around 7.3 percent, equivalent to $7.1 billion, of the 12 companies’ 2022 investments went towards renewable energy, with $88.15 billion in financing for fossil fuel operations. 

The report suggests that Big Oil is undermining its climate action through investments in PR stunts rather than real action. So far, many oil and gas companies have published only partial data to skew the bigger picture of their renewable energy operations. Many continue to promote initiatives such as carbon capture and storage (CCS) and carbon offsetting in oil and gas projects, rather than demonstrating their investments in green energy sources. To date, the publication shows there is no sign of a fundamental reorientation of the industry’s core business that would allow it to play any role in the energy transition. 

In addition to the lack of evidence showing any real contribution to the green transition, the report stated that BP, Equinor, Wintershall, and TotalEnergies even reduced their investments in low-carbon or renewable products in 2022, compared to the previous year. This is surprising considering the ambitious climate pledges made by all 12 oil majors in recent years. Most have committed to the target of net-zero carbon emissions by 2050, yet none has published a comprehensive strategy on how it will achieve this goal. Further, most intend to continue investing heavily in oil and gas production beyond 2030. 

Many major oil and gas companies have promoted the idea of “low-carbon oil” in recent years, largely in response to international and governmental pressure to decarbonise operations. Several companies are now moving away from ageing oil and gas projects in traditional oil regions to new projects in largely untapped regions of the world, such as countries in Africa and the Caribbean. Developing new projects in these regions means companies can shape them to be less carbon-intensive than previous operations, by using more efficient production technologies and incorporating CCS activities. This may allow them to continue drilling for oil and gas for longer, as they justify low carbon production as vital to meeting the mid-term energy needs of the world’s population. 

Grete Tveit, the senior vice president for low-carbon solutions at Equinor, recently said the Norwegian major is delivering an “optimised oil and gas portfolio”. She explained, “Fossil fuels will be needed in 2050 but will have to be produced with the lowest emissions possible.” 

In August, Bernard Looney, the CEO of BP, stated that the world needs to invest more in oil and gas production. This is coming from a company that just two years ago wholly embraced the green energy transition, announcing plans to rapidly expand BP’s renewable energy portfolio. Following the Russian invasion of Ukraine last year and the resulting energy shortages, many governments appear to share Looney’s view that fossil fuels are needed to meet the immediate and even mid-term energy needs of the world population, which led to record global subsidies for oil and gas in 2022. The International Monetary Fund stated in a new report that global subsidies for oil and gas had hit an all-time high of $7 trillion in 2022. 

Previous reports on Big Oil’s renewable energy spending have shown how many companies have prioritised their public appearance over investments in meaningful climate action. A 2022 report demonstrated that oil companies were spending hundreds of millions of dollars on marketing and PR to promote a green image that was inconsistent with their climate action. An analysis of 3,421 pieces of public communications materials from BP, Shell, Chevron, Exxon and Total by the non-profit InfluenceMap found that 60 percent of them included at least one “green” claim, with just 23 percent promoting oil and gas. Many of these communications included the promotion of efforts to transition their energy mix to include more renewable energy sources. This is highly disproportional to their investments in both fossil fuels and renewable energy, with many firms overstating their efforts to diversify their energy mix in support of a green transition. 

Despite the promotion of their green investments, an analysis of the annual reports of several oil majors suggests that they are investing little in renewable energy. Although many oil firms have pledged to decarbonise and achieve ambitious climate targets, few have produced clear strategies supporting these aims. Further, most oil and gas companies appear to be spending a vast amount of their money on fossil fuel operations, including ‘low carbon’ oil projects, with little contribution to green energy projects. 

By Felicity Bradstock for Oilprice.com

U.S. Oil Major Is A Big Winner Of Biden’s Climate Funding

By Tsvetana Paraskova - Aug 31, 2023, 

• Occidental Petroleum won one of two grants by the Biden Administration to build the world’s first direct air capture plant in Texas.
• 
  
• The U.S. Inflation Reduction Act increased credit values for carbon reduction projects across the board.
• 
  
• Capturing CO2 from the air is the most expensive application of carbon capture, the International Energy Agency says
• 
  

One of the biggest U.S. oil producers, Occidental, has just won one of two grants by the Biden Administration to build the world’s first direct air capture plant in Texas that would extract carbon dioxide directly from the atmosphere.      

Occidental, the first U.S. oil firm to pledge net-zero emissions, including the emissions from its products Scope 3, is betting big on direct air capture (DAC) technology to directly remove the greenhouse gas and sell carbon removal credits to corporate polluters. 

DAC is not directly threatening Oxy’s core oil business. It focuses on emissions reductions, not reduction of the currently available energy sources.     

Environmentalists, of course, slam the carbon removal and carbon management efforts of Big Oil, claiming that DAC and carbon capture, utilization, and storage (CCUS) are the next greenwashing tools of companies that don’t want to reduce oil and gas production. 

The Biden Administration, which has angered the oil industry many a time in the past two years with restrictive policies and attempts at too much oversight, is handing out billions of grants as part of the Investing in America plan. It has also significantly raised tax credit values for carbon capture technology with the Inflation Reduction Act. 

And one of the top U.S. oil producers, Occidental, is a winner in both. 

South Texas Direct Air Capture Hub

The U.S. Inflation Reduction Act increased credit values for carbon reduction projects across the board, with the tax credit for carbon storage from carbon capture on industrial and power generation facilities rising from $50 to $85 per ton, and the tax incentives for storage from direct air capture (DAC) jumping from $50 to $180 per ton. The provisions also extend the construction window by seven years to January 1, 2033. This means that projects must begin physical work by then to qualify for the credit.Related: Gazprom Claims It Accounts For Over Half Of Chinese Gas Import Growth

In early August, the U.S. Department of Energy (DOE) announced up to $1.2 billion to advance the development of two commercial-scale direct air capture facilities in Texas and Louisiana. The projects are “the initial selections from the President’s Bipartisan Infrastructure Law-funded Regional Direct Air Capture (DAC) Hubs program, which aims to kickstart a nationwide network of large-scale carbon removal sites to address legacy carbon dioxide pollution and complement rapid emissions reductions,” the DOE says. 

One of the two projects, South Texas DAC Hub in Kleberg County, is being developed by Occidental subsidiary 1PointFive and its partners, Carbon Engineering and Worley. The project will seek to develop and demonstrate a DAC facility designed to remove up to 1 million metric tons of CO2 annually with an associated saline geologic CO2 storage site.  

“We believe this selection validates our readiness, technical maturity and the ability to use Oxy’s expertise in large projects and carbon management to move the technology forward so it can reach its full potential,” Oxy president and CEO Vicki Hollub said. 

Days later, Occidental signed an agreement to buy its partner, Carbon Engineering, a DAC innovator company with which it has been collaborating since 2019.   

“Together, Occidental and Carbon Engineering can accelerate plans to globally deploy DAC technology at a climate-relevant scale and make DAC the preferred solution for businesses seeking to remove their hard-to-abate emissions,” Hollub said. 

DAC: The Most Expensive Carbon Removal Application 

Capturing CO2 from the air is the most expensive application of carbon capture, the International Energy Agency (IEA) says.

The CO2 in the atmosphere is much more dilute than in flue gas from a power station or a cement plant, which contributes to DAC’s higher energy needs and costs relative to these applications.

DAC is currently expensive, but Oxy believes it could bring the costs down, Richard Jackson, President, U.S. Onshore Resources and Carbon Management, Operations, at Occidental, has told the Houston Chronicle.

“The biggest challenge is scale, building million-ton plants at scale, proving that can be done. The market will be there once these products are proven,” Jackson said. 

Wide adoption of DAC needs costs to drop from $600-$1,000 per ton today to below $200 per ton, and ideally closer to $100 per ton, according to David Webb, Chief Sustainability Officer, Managing Director and Senior Partner at Boston Consulting Group (BCG). 

While the Biden Administration’s policies are accelerating DAC plans and pilot projects, technology, costs, and scale need to materially improve for direct air capture to become a profitable industry. 

Critics say DAC and other carbon removal plans are different forms of greenwashing in which polluters, including oil firms, use these technologies as an excuse not to cut emissions from the oil and gas they pump. 

“It’s a shiny technology that would allow the world to avoid making hard decisions about energy use and continue business as usual,” Andrew Logan, a senior director at Ceres, the non-profit coalition advocating for sustainability, told Bloomberg.

Climate groups are not convinced that carbon removal deals, in which companies capturing CO2 sell credits to polluters to offset their emissions, would accelerate global emissions reduction.   

For example, the European Commission’s proposed Carbon Removal Certification Framework (CRCF) “leaves many important questions unanswered and vital issues unaddressed, and could usher in an era of greenwashed and money-wasting carbon removals,” non-profit think tank Carbon Market Watch says. 

In the EC’s draft regulation, “there is a risk for the framework to be turned into a greenwashing exercise and provide another excuse for big polluters to avoid cutting their emissions,” according to WWF.      

By Tsvetana Paraskova for Oilprice.com

The Completion Of This Mega Refinery Is Crucial For China

By Simon Watkins - Aug 29, 2023

• The finalisation of Oman’s Duqm refinery complex is a strategic step for China and Iran.
• 
  
• The 230,000-bpd Duqm refinery project is crucial in China’s plan to build up a petrochemicals presence in the Middle East.
• 
  
• As it now stands, the Duqm refinery will soon function alongside the US$4.6 billion Liwa Plastics Project.

Oman has an importance to China and Iran that goes way beyond its relatively small oil and gas reserves (only around five billion barrels of oil reserves and about 24 trillion cubic feet of gas). Crucial to both countries is Oman’s geographically-strategic position, with long coastlines along the Gulf of Oman and the Arabian Sea offering unfettered equal access to the markets of the West and the East. According to a senior source who works closely with Iran’s Petroleum Ministry spoken to by OilPrice.com, China’s long-held objective is to secure control over Oman to have mastery over all the key crude oil shipping route chokepoints from the Middle East into Europe that avoid the Cape of Good Hope route (more expensive and more nautically challenging) and the Strait of Hormuz route (more politically sensitive). This is fully aligned with Beijing’s broad strategic goal encapsulated in its ‘One Belt, One Road’ multi-generational power-grab project. 

China already has effective control over the Strait of Hormuz through the all-encompassing ‘Iran-China 25-Year Comprehensive Cooperation Agreement’, as first revealed anywhere in the world in my 3 September 2019 article on the subject and as analysed in full in my new book on the new global oil market order. The same deal also gives China a hold over the Bab al-Mandab Strait, through which crude oil is shipped upwards through the Red Sea towards the Suez Canal before moving into the Mediterranean and then westwards. This has been achieved as it lies between Yemen (the Houthis having been long supported by Iran) and Djibouti (over which China has also established a stranglehold).

Related: Chevron Evacuates Gulf Of Mexico Oil Platforms As Hurricane Idalia Approaches

China has another use for Oman, which is to enable its core Middle Eastern partner, Iran, to finally build out its liquefied natural gas (LNG) business into a world-scale operation. The plan is for Iran to utilise at least 25 percent of Oman’s total 1.5 million tons per year LNG production capacity at the Qalhat plant. Such an idea was originally part of the broader co-operation deal made between Oman and Iran in 2013, extended in scope in 2014, and fully ratified in August 2015 that was centred on Oman’s importing at least 10 billion cubic metres of natural gas per year (bcm/y) from Iran for 25 years through an underwater pipeline. That deal was to have begun in 2017, at which time it was worth around US$60 billion. The target was then changed to 43 bcm/y to be imported for 15 years, and then finally altered to at least 28 bcm/y, also for a minimum period of 15 years. The land pipeline of the project that would move gas from Iran’s supergiant South Pars and North Pars fields in the first instance would comprise around 200 kilometres of 56-inch pipeline to run from Rudan to Mobarak Mount in the southern Hormozgan province. The sea section would include a 192-kilometre section of 36-inch pipeline along the bed of the Oman Sea at depths of up to 1,340 metres, from Iran to Sohar Port in Oman.

This deal was intended to allow for the completely free movement of Iranian gas (and later oil) via Oman, running out through the Gulf of Oman and then into the world hydrocarbons markets. The route was designed to allow Iran the same sanctions-free flows that it was operating via Iraq, as also analysed in my latest book on the global oil markets. Given the potentially sanctions-busting nature of the project, though, the U.S. included the prevention of this Iran-Oman LNG project in its efforts to stop Iran from expanding its hydrocarbons export routes into the booming market of Asia. Before the Saudi Arabia-led blockade of Qatar erupted in 2017, the U.S. offered an alternative for Oman, which was that it increased its uptake of gas from Qatar. This would come via the Dolphin Pipeline running from Qatar to Oman through the UAE, or in LNG form, but Oman refused. Oman’s desire to re-energise the plans for the Iran-Oman gas pipeline was also fanned at that time by the UAE’s demands for an increasingly large fee for allowing the transit of gas from Iran through its waters, again part of the U.S. strategy to persuade Oman to take its gas from Qatar.

Following the recent China-brokered resumption of relationship deal between Iran and Saudi Arabia, as also analysed in my latest book, the UAE’s willingness to be utilised by the U.S. in its fight against this planned new network of pipelines appears to have evaporated. As highlighted by OilPrice.com in May, a major new gas pipeline being planned will run along a 2,000-kilometre corridor via Oman - and the UAE - through the Arabian Sea and into India. This will allow gas to be gathered in from Oman and the UAE themselves, and from Iran, Saudi Arabia, Qatar, and Turkmenistan. These countries together have, by very conservative estimates, just under 2,895 trillion cubic feet (tcf) of gas reserves - Iran 1200 tcf, Qatar 858 tcf, Saudi Arabia 333 tcf, Turkmenistan 265 tcf, UAE 215 tcf, and Oman 24 tcf. Critically as well, although there will be one major pipeline running from the Middle East to India in the first instance, several other extensions of this pipeline plan are readily available. As also analysed in full in my new book, finished plans for an Iran-India pipeline and an Iran-Pakistan pipeline – both of which could be extended to China – have long been in place. 

This said, it was the US$8.5 billion 230,000-bpd Duqm refinery project – and ancillary projects (another US$10 billion or so) – in which China first saw the best route to win favour in Oman, and thereby seek to establish control over key regional oil transport routes. The problem Oman encountered in the mammoth Duqm undertaking was that building up a petrochemicals presence, as the project is intended to do, requires a lot of upfront spending ahead of being able to generate returns further down the line, and this left a massive gap in its finances. Already accounting for around 90 percent of Oman’s oil exports and most of its petrochemicals exports to that point, China was quick to leverage this to sign a US$10 billion investment in the Duqm refinery project - just after the implementation of the nuclear deal with Iran at the beginning of 2016, in fact. The focus of this Chinese money initially was on completing the Duqm refinery, but it was also expanded to include financing for a product export terminal in Duqm Port and the Duqm refinery-dedicated crude storage tanks of the Ras Markaz Oil Storage Park. More Chinese money was also funnelled towards the construction and building out of an 11.72 square kilometre industrial park in Duqm in three areas - heavy industrial, light industrial, and mixed-use.

According to the plans, all of which will be ready within the next five or so years, in the light industrial zone there will be 12 projects, including the production of 1 gigawatt (GW) of solar power units, and of oil and gas tools, pipelines and drilling equipment. The mixed-use sector will focus on projects designed for the tourist trade, including the construction of a US$150 million hotel on a 10-hectare area, US$100 million to build a hospital, and US$15 million towards a school. The heavy industry sector will also see 12 projects, dealing with the production of commercial concrete, building materials and related industries, production of glazed glass, methanol and other chemicals. In addition, the site will cater for steel smelting, aluminium production, production of vehicle tires, building materials for protection against water and corrosion, extracting magnesium from seawater, and various chemical-aromatic projects. 

As it now stands, the Duqm refinery will soon function alongside the US$4.6 billion Liwa Plastics Project (LPP) industrial complex, also near the Oman Oil Refineries and Petroleum Industries Company’s Sohar refinery in the Special Economic Zone at Duqm. The final part of Oman’s vision of building an Omani integrated refining and petrochemical business, is the 290-kilometer-long Muscat Sohar Product Pipeline for transporting refined products. The US$336 million pipeline connects the refineries of Mina Al Fahal and Sohar to an intermediate distribution and storage facility at Al Jifnain. Split into three sections - 45 kilometres between the Mina Al Fahal and Al Jifnain Terminal, 220 kilometres between the Sohar and Jifnain Terminal, and 25 kilometres between the Al Jifnain Terminal and Muscat International Airport – the project is integral to the delivery of more than 50 percent of Oman’s fuel via the state-of-the-art storage facility in Al Jifnain. For China and Iran, all these facilities will be extremely useful in their day-to-day business. But incalculably more useful in multiple ways will be the fact that they have secured control over this vital global strategic hub of Oman.

By Simon Watkins for Oilprice.com

Viewpoint: Quantum computing and the nuclear industry

29 August 2023

A research project has highlighted the potential for quantum computing to deliver significant benefits for the design and operation of radiation facilities in the nuclear, medical and space industries, as Professor Paul Smith, Jacobs ANSWERS Technical Director, explains.

(Image: Paul Smith/Jacobs)

Modelling radiation transport is fundamental to nuclear physics and plays a part in everything from reactor design and operation, fuel fabrication, storage, transport, decommissioning and geological disposal. Beyond nuclear power and decommissioning, it plays a vital role in nuclear medicine, the space industry, food irradiation and oil well logging.

Monte Carlo codes are the reference method for creating simulations and solving equations to understand the way in which physical energy is transferred by the absorption, emission and scattering of electromagnetic radiation - known as radiation transport.

The codes are designed to model and understand the movement and interactions of radiation particles (such as photons, neutrons, or charged particles) as they travel through different materials and interact with various structures.

There are two main approaches to solving the equations for radiation transport. In the deterministic approach traditional numerical methods are used to solve the mathematical equations - this involves a number of approximations. The alternative Monte Carlo approach involves simulating the paths of individual particles which involves less approximation but for some applications is prohibitively slow. In such cases it is used to produce high-fidelity solutions to test the accuracy of deterministic solutions which although more approximate, can be arrived at more quickly.

The ANSWERS Software Service, part of Jacobs, led a project to explore the potential benefits of quantum computing in accelerating Monte Carlo methods.

Supported by the UK’s National Quantum Computing Centre’s SparQ programme, which supports research into new applications, this project aimed to investigate the advantages of leveraging quantum computing instead of conventional digital computing to improve the runtime of Monte Carlo methods, making them more competitive.

ANSWERS provides and supports the MCBEND and MONK 3D Monte Carlo codes which are widely used worldwide for radiation shielding, dose assessments, nuclear criticality safety and reactor physics analysis. For example, ANSWERS software is used to support the design and safety case production for transport flasks for radioactive materials.

Several processes contribute significantly to the computational cost of performing Monte Carlo radiation transport calculations including random number generation, nuclear database searches, ray tracing and the Monte Carlo process itself. Quantum algorithms are available or under development for each of these processes. Quantum random number generation has the clear advantage of generating truly random numbers, based on truly random quantum processes, whereas traditional computational methods are only capable of generating pseudo random numbers or quasi random numbers which can be subject to subtle correlations that can introduce bias into calculation results.

Whereas digital computers work with bits of data that are either 0 or 1, quantum computers work with qubits – two-state quantum-mechanical systems that can be in a superposition of the 0 and 1 states. For example light may be horizontally or vertically polarised (try looking at an LED television through glasses with polarised lenses and tilting your head at different angles). If an individual photon of light is polarised at 45 degrees to horizontal it may be thought of as being in a superposition of the horizontal and vertical states.

This allows quantum computers to process many states in a single operation, increasing their processing power exponentially and achieving complex problem-solving which is impossible on digital computers. In practice, many quantum algorithms offer a quadratic advantage over traditional digital computers - for example, a quantum algorithm may achieve in 1000 operations what would take a million operations using a traditional algorithm.

There are certain scenarios where digital computing surpasses quantum computing. For instance, due to the specific ordering of nuclear databases (from lowest energy to highest energy), binary searches offer an exponential advantage over the quantum Grover search algorithm.

One of the biggest challenges faced by quantum computing at present is the presence of quantum noise. Being microscopic, quantum systems are very delicate.

Any interaction with the surrounding environment can change the state of the system, for example changing a qubit from state 0 to state 1 or vice versa. Random interactions with the qubits effectively add an element of noise to the answers obtained from a quantum computer. The project used Lucy, the Oxford Quantum Circuits computer, and was successful in demonstrating the effectiveness of new techniques for the reduction of quantum noise. This is currently an area of intense research activity.

The project partners - Jacobs, National Quantum Computing Centre (part of UK Research & Innovation), Oxford Quantum Circuits, National Nuclear Laboratory, Sellafield Ltd, and the University of Cambridge - note that there are promising signs that quantum algorithms could transform the computational aspects of ray tracing and Monte Carlo radiation transport simulation, but further research is needed to evaluate their applicability.

 

Atucha II returns to service after completing repairs

30 August 2023

Argentina's Atucha II nuclear unit is delivering power again after the successful completion of repairs prompted by the October 2022 inspection discovery that one of the four internal supports of the reactor had detached and moved from its design location.

The Atucha site (Image: Nucleoeléctrica Argentina)

After the discovery, the unit was shut down and an interdisciplinary team worked to diagnose the situation and decided to extract the separator and carry out the repair remotely without needing to dismantle the reactor, shortening the expected repair time from four years to 10 months, Nucleoeléctrica Argentina said.

The company said that "after evaluating the situation, it was decided that the best option to extract the separator through the channel was to cut it into four parts ... it was also resolved to preventively reinforce the welding of the three separators that were still mounted to avoid future damage".

The detached separator was 14 metres inside the reactor, so new tools needed to be designed to adapt to those conditions, including a cutting tool, holding tool, gripper, a basket within which to extract the piece as well as lighting and vision tools to monitor the manoeuvre.

To test the tools and train and prepare for the cutting and extraction manoeuvres a full-scale model of the sector of the reactor in which the intervention was carried out was designed, manufactured and installed - the tank used to represent the moderator tank was the same one used as a mock-up to test the tools and rehearse the manoeuvres that allowed the historic repair of the Atucha I reactor in 1988.

The cutting of the separator took two weeks in total, and once it was completed the extraction tool was introduced "which allowed each of the cut separator pieces to be held and placed in the basket tool for removal from the reactor". The welding of the remaining supports took six days.

Nucleoeléctrica Argentina said that it worked with other suppliers in the country to create the necessary tools, and said: "The completion of this challenge not only marks a new milestone for the Argentine nuclear industry, but also confirms the country's scientific-technological capabilities to carry out complex engineering projects. In this way, the experience acquired by Nucleoeléctrica in this repair will allow the country to export knowledge and tools for use in other nuclear power plants in the world."

Argentina's nuclear sector has three pressurised heavy water reactors with a total generating capacity of 1641 MWe across the Atucha I, Atucha II and Embalse power plants. Atucha II's first grid connection was in 2014 - construction began in 1981 as a joint venture of Argentina's National Atomic Energy Commission and Germany's Siemens-Kraftwerk Union but work was suspended in 1994 with the plant 81% complete. It was restarted in 2006, entering commercial operation in May 2016.

Researched and written by World Nuclear News