Terry Raddings, Business Development Manager at GE Gas Power Systems, shares insights into GE’s position in the energy ecosystem and highlights customer pain points and experiences.

Watch the full video interview below.

This interview was filmed in November 2022 at Enlit Europe in Frankfurt, Germany

For more information, you can visit the GE Gas Power website here – www.ge.com/power/gas 

The post Evolution and revolution of the energy system – <strong>GE Gas Power</strong> appeared first on Power Engineering International.

The facility in Kassø, Denmark, is intended to progress the decarbonization of the global freight industry by producing 32,000 metric tonnes of carbon neutral hydrocarbon-based fuels per year.

European Energy is applying Power-to-X technology to convert renewable electricity from solar panels or wind turbines, among others, into other forms of easier-to-store energy, namely e-methanol.

The plant will be supplied with power from the adjacent 300 MW solar park owned by European Energy and the company says it “represents the first step in bringing this e-fuel to market at scale to support the maritime and road transportation industries as well as the chemical sector”.

Sulzer Chemtech is providing advanced separation technologies to enable the effective storage of renewable energy. It will deliver two distillation units with a customized design to European Energy’s facility.

These will play an essential role in the plant’s ability to produce e-methanol of extremely high purity for use in combustion engines and for use as a chemical feedstock, for example to produce plastic while requiring minimal energy inputs. 

Half of the total plant output, 16,000 metric tonnes per annum, will be delivered to Danish global shipping company A.P. Moller-Maersk to fuel the company’s first containership capable of operating on green methanol.

The 172 m (564 ft) long vessel will be able to hold over 2000, 20ft-equivalent containers and will sail in northern Europe.

Emil Vikjær-Andresen, head of Power-to-X at European Energy, said: “The success of our operations depends on the ability to deliver high quality e-methanol, meeting demanding specifications, while minimizing the environmental impact of our activities.

“Only in this way can we effectively support the adoption of more sustainable fuels.”

Jacques Juvet, Head of Application and Process Technology for Process Plants at Sulzer Chemtech, added that the project “will have a major impact in driving the transition towards sustainable fuels”.

The post Landmark commercial e-methanol plant to be built in Denmark appeared first on Power Engineering International.

As children, many of us had no clue what we wanted to do when we ‘grew up’. Not so Johan de Villiers.

“From my very first memories as a child, I knew I wanted to be an engineer – it’s something that fascinated me.

“I wanted to know how the world works and use technology to fix problems and make the world a better place.”

And de Villiers followed that ambition with a “passion that has just grown stronger through the years”.

“I was happy to join ABB 25 years ago and I’ve had various roles in the company across many of our divisions and business lines and also had the wonderful privilege to move around the world and experience different cultures and different geographies.”

Currently, home for de Villiers is Abu Dhabi, where he leads ABB Energy Industries’ oil, gas and offshore wind business globally.

Offshore wind may not seem an obvious bedfellow of oil and gas, yet de Villiers is keen to point out their synergies.

“In oil and gas we’ve had multiple decades of experience operating complex assets offshore in harsh environments and open oceans.

“These assets incorporate automation systems, electrical, digital and telecommunication systems that allow connectivity and enable these assets to produce energy safely, reliably and efficiently.

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“These are exactly the skills that we are leveraging and deploying to the offshore wind sector, which in many cases require similar skills, experience, and equipment.”

He says tapping into the oil and gas sector skills set “is a real strength and opportunity, because we know that this is an energy transition and for many years, we will need to maintain oil and gas assets”.

“Otherwise the world can’t continue to operate. At the same time, we’ve got to deploy the renewable power and renewable power assets as quickly as possible.”

Scaling up

For ABB Energy Industries, he says, the ability “to have scale across both these segments is really powerful. And if you have to build it up from scratch, it would be more of a challenge. This is actually a fantastic opportunity to accelerate the deployment of renewable and low carbon technology.”

And when we talk of that deployment, de Villiers is keen to highlight a trend that he is seeing in the development of offshore wind.

The first trend is scaling up. “The offshore wind segment has come a really long way since that very first offshore wind project in 1991 at Windeby, about two kilometres off the Danish coast with a capacity of around 5MW.

“This was followed by a decade of pilot projects around the world that ended in the early 2000s. We then saw 20 years of scaling up with dramatic improvements in utilisation factors that drove cost down.”

Massive improvements in the supply chain allowed the scale-up and delivery of larger projects around the world, and during this period de Villiers highlights that “the levelised cost of energy for offshore wind dropped by more than 60% and utilisation factors increased from around 20% to well above 40% currently”.

“Today, the levelised cost of energy from offshore wind in most parts of the world are cheaper than new coal, nuclear or gas fired power energy production.

“We have now reached a phase where there is maturing of the segment, optimisation of technology and increasing delivery capacity.”

And this maturing is happening in parallel to the global growth in offshore wind. So what is the impact of this increasing scale? “Turbine sizes are increasing; wind farms are also getting larger; more turbines are used with greater power capacity.

“For example, the 3.6GW Dogger Bank wind farm which will include more than 280 turbines. With that kind of scale, there’s a huge demand for the technology that keeps everything connected, ensuring visibility across these assets. It becomes physically impossible to be present across such a vast array.”

This, says de Villiers, is “one of the most important differences with oil and gas: oil and gas assets are very concentrated and in one location, whereas wind farms are spread across hundreds of square kilometres offshore”.

Optimising through data

Which is where the importance of data comes in.

“We are leveraging the years of experience that we have in offshore oil and gas systems which have been instrumental in enabling safe and efficient operations.

“You can imagine the parallels you can draw between monitoring instrumentation and equipment on an oil and gas platform and the substation on an offshore wind farm. “The function may be different, but you still have monitoring of instrumentation on these assets. You still need to collect the data and transfer that through a reliable telecommunications infrastructure to where you can actually utilise and draw insight from this and process this data.

“And then you need to act on that. It’s at the core of wind farm operation, of generation and transmission of the power.”

Yet de Villiers stresses that “it actually goes beyond that. If you think about it at the feasibility stage, there’s a lot of simulation that has to happen. Data is used to determine if the project is feasible and then how it should be designed.

You need digital tools and all kinds of software models for that. Through operations you need the same. Data is absolutely critical to the operation of wind farms and the deployment of these assets to have reliable instrumentation: automation and electrical systems connected to remote operation centres placing the right data in the right hands so that you can safely and efficiently operate the assets.”

Digitalisation across the board

When asked what kinds of digital platforms are making the biggest impact, he starts with software and digital twins.

“There are several ways in which digital technologies, specifically digital twins, can help, throughout all phases, from design to operations and grid operations.

“As you move through expansions and improvements, you need software models to understand how systems will react and what the best way is to design these things.”

A practical example he cites is the 88MW Hywind Tampen project, a floating offshore wind project in the North Sea that will supply some of the oil and gas platforms operating in the North Sea.

“The idea is that by supplying clean power to these platforms, they can remove some of the gas turbines, thereby reducing emissions from the oil and gas production process.

“In this case, we’ve used our power process simulator, which is a digital twin of the electrical network to enable a whole range of things, including operator training of the electrical control system and testing. It’s basically a replica of the electrical control system to create a realistic real-world environment.

“And this unique solution uses the same human machine interface as the process control system on these platforms. So you get the seamless integration between how you operate the facilities and how the electrical system behaves – it’s a powerful tool for people who design and operate these pilots.”

He says digital twins help make decisions. Another interesting use case he highlights looks at the changes needed on the power grid being supplied. “The simulation enabled the team to understand the effect of wind and the variability in the wind generation that arrives at the platform and the changes they need to make in how they control these gas turbines and the electrical systems on these plants. It could be done seamlessly.

“You can’t run these experiments on the platform – so simulation is powerful.

“It’s important to remember that offshore wind farms are designed to be normally unattended facilities. “We therefore have to deploy sufficiently reliable equipment. If the equipment and the systems that run the wind farm require maintenance, you really defeat the purpose of it.

“The ability to monitor, to access data and to place their data in front of the right people to make the right decisions is critical to operating.”

So would it be fair to say that data is changing the face of maintenance?

“Absolutely. I think there is a broader trend in how we maintain assets in general, whether you talk about mining or pulp and paper, oil and gas production or wind farms. “Industry 4.0 is reducing the cost of sensors, allowing for more reliable communication infrastructure, more powerful processing infrastructure, and developments in cyber security. All of these trends have enabled us to have access to more data.

“When it comes to maintaining assets, data is your friend. The more you know about that asset, the more you can trend the temperatures, the vibrations, all the different attributes that are relevant to that asset.

“It’s about having data, using data, using machine learning to model, simulate and calculate the condition of equipment and then to inform operators what intervention is required at any specific time.”

“Where we see best practice today is where data is used in a collaborative way.

“Cloud infrastructure is certainly enabling a lot and we see more of our customers utilising the cloud to make sure that there’s a data stream from these assets and that these data streams can be accessed by apps and by domain experts as required.”

Changing business models

De Villiers is keen to highlight how business models are also changing to match this digital innovation.

“Coupled with technological innovation, there’s a great opportunity for commercial and business model innovation as well.

“Software as a service and hardware as a service are business models that could be very interesting and that we are exploring with some of our customers.

“I consider the times when you sold a piece of software as a one-off and it didn’t change over the life of the asset or the life of the software. Those days are over: we live in dynamic times and in a dynamic world, and business models need to adjust to that.

And if we remember the young Johan de Villiers who always wanted to be an engineer: what would he say to a child with similar ambitions today?

“This is an incredibly exciting space to be in. From a technology standpoint, there are very cool things that you can work with as we digitalise. I think that’s naturally quite attractive to younger people. There’s the opportunity to make a difference.

We need to power and run the world in a more sustainable way and it’s wonderful to be part of the story and to play a part somehow.”

The post Leveraging synergies between oil & gas and offshore wind to drive net zero appeared first on Power Engineering International.

Stedin started experimenting with the production of green hydrogen and its blending with natural gas as far back as 2007 in a project on the Dutch north coast island of Ameland.

With the results from this and the intent to overcome the hydrogen blending limit – generally regarded around 20% – Stedin then set up a larger trial closer to home in the Rotterdam municipality town of Rozenburg.

Almost a decade on and following a 2018 expansion from the first phase with synthetic methane production, this trial is still running with at least a further year to go, and contributing important knowledge on how DSOs can use the existing gas network to distribute sustainable gases such as green hydrogen safely and reliably.

“Our goal was to show that hydrogen actually works and while one can do a lot on paper, we wanted to put it into practice,” says Tessa Hillen, Energy Transition Analyst at Stedin.

Sulphur free hydrogen

Power-to-gas Rozenburg comprises an electrolyser powered by rooftop solar PV that produces the green hydrogen that is then delivered via a natural gas pipeline for heating in a nearby apartment complex.

Hillen explains that only some adjustments were needed to the pipeline to make it suitable for hydrogen, opening the way for scaling up the approach, anticipated in 2025, to a hydrogen village.

However, she adds that a key step before larger scale conversion – which has become an important focus of the trial in partnership with the French gas DSO GRDF – is odourising hydrogen. Like natural gas, hydrogen is odourless but the current odourant contains sulphur, which is damaging to hydrogen fuel cells.

MORE | Enlit on the Road Rotterdam

“For fuel cells connected to the gas grid, we need sulphur-free hydrogen,” says Hillen.

She also notes that a related aspect under investigation is that of the sulphur residues in existing gas pipelines and how these can be removed.

In partnership with DNV, three odourants were identified: namely, 5-ethylidene-2- norbornene, methyl tertbutyl ether and 2-hexyne, of which the latter appears the most suitable. While its odour is reported as difficult to describe, it was identified by a majority of Stedin employees to whom it was presented as “most distinctive, alarming and similar to [natural gas odourant]”.

Large-scale production

While Stedin continues experiments, individually and in partnership with other DSOs, on hydrogen distribution technologies for residential use (among others), the large-scale production and market input of hydrogen is coming under the spotlight at the Port of Rotterdam.

The port, long known for its innovative approach to new technologies, early on took the decision to become an international hub for hydrogen with a large-scale network across the port complex encompassing imports, production, application and transport to other locations in northwest Europe.

MoUs have been signed with parties across the world, from Chile and Colombia in Latin America to South Africa and Australia, with the import potential estimated from these and other countries at 4Mt of hydrogen annually by 2030 and up to 20Mt by 2050.

Among operators within the port area, the offshore wind foundation provider Sif is leading a project which envisages the installation of a small-scale hydrogen production unit powered by a wind turbine at the company’s Maasvlakte 2 terminal. Longer term the aim would be to scale up the concept for off-grid hydrogen production offshore with offshore wind.

Energy Conversion Park

But arguably the most significant development at the port is the Conversion Park on Maasvlakte 2, on which at least 1GW of hydrogen electrolyser capacity is planned.

And the first company to commit there, Shell, has started developing what is Europe’s largest electrolyser of 200MW.

With an output of up to 60,000kg of green hydrogen per day, the electrolyser will be powered from the Shell-Eneco 759MW Hollandse Kust (Noord) offshore wind farm, which is also under construction, and is expected to become operational in 2025.

Notably, the wind farm – which is due to be operational by the end of 2023 – will include a supplementary floating solar array to improve the reliability of the output, particularly in the summer when the wind strengths tend to be lower.

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The hydrogen will be supplied to Shell’s nearby Energy and Chemicals Park in Pernis, where it will replace some of the grey hydrogen usage and partially decarbonise the production of fuels and other products as well as being directed for heavy transport use.

“With this programme we are focussed on renewable power and electrification in the port and we want to help the companies to decarbonise by ensuring all the elements are there,” says Randolf Weterings, Electrification and Hydrogen Manager.

Actions include developing access to sufficient renewable power to produce the green hydrogen and providing an open access pipeline infrastructure for local producers and users with connections to national and international networks to support the development of the hydrogen market.

“The unique thing about Rotterdam is that all the elements of the energy transition are very close by in the port area. We can access renewable power from offshore wind, we have the terminals that connect Europe to countries across the globe and we have the large-scale industry that can use the hydrogen,” says Weterings.

Lijs Groenendaal, Shell’s Hydrogen Business and Project Development Manager, explains that the new electrolyser, Holland Hydrogen 1, is a significant step-up from the current megawatt scale electrolysers.

“We need to learn how to build and operate it and produce hydrogen safely and this will be a huge challenge,” she says.

“There needs to be a regulatory framework and there’s going to be a whole ecosystem of hydrogen developments and so all of the 150 parties involved will need to collaborate to make it happen.”

She also describes the project, as the first, as “an enabler”, both with its scale as well as with its lead in the development of the port’s offshore power connection and the first to commit to using the HyTransPort open access pipeline. This should enable other developers not only within the port but also more widely in Europe to “fast follow”.

Sustainable development

Groenendaal says that a key focus of the development is on sustainability, starting from the design with a visually appealing look in tune in the port area. the surrounding natural area.

“The architects have worked hard and put in research and innovation so that all the resources – energy, water, air, biodioversity, materials – will have to be clean or cleaner when leaving the building than when entering it.”

For example both air and water will be purified on a scale previously untested.

“Rotterdam is where it all comes together,” concludes Groenendaal. “We believe in the energy transition and we think green hydrogen is going to play a large role in decarbonising our fuel products and mobility. In Rotterdam we’ve got the demand and supply – the customers and production – in one place, so it’s a unique spot to build all the infrastructure.”

The post Rotterdam fuels its own energy transition with hydrogen appeared first on Power Engineering International.

This solar PV plant will be the second one linked to the Bir Rebaa North (BRN) oil field facility aimed at decarbonising the facility’s hydrocarbon production. It will be added to the existing 10MW solar PV plant launched in 2018.

The goal of the Solar Lab is to test different solar PV panels in extreme irradiation conditions and analyse the data to identify the most efficient technologies. The Lab will be open to universities for research purposes, ultimately promoting the development of renewables in Algeria.

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Eni CEO Claudio Descalzi said in a statement: “Decarbonising our legacy businesses is a pillar of Eni’s net-zero strategy, and today we celebrate the strong alignment between Eni and Sonatrach towards carbon neutrality. Our shared vision is also the basis of the joint effort to ensure security of supply for Italy and Europe, leveraging Algerian gas resources. Algeria and Italy have been trusted partners for decades and will continue to work together towards a just, sustainable and pragmatic energy transition.”

These initiatives are in line with Eni’s wider decarbonisation plan that also includes venting monitoring and zero routine flaring projects, energy efficiency and green hydrogen initiatives. The company aims to add another solar PV facility at the Menzel Ledjmet East Project production complex, also in the Berkine Basin, with construction expected to begin in 2023.

Webcast Recording | Green is the new black: Oil & gas and the race to energy efficiency

According to the International Trade Association, Algeria has the tenth-largest proven natural gas reserves globally and has the world’s third-largest untapped shale gas resources.

It also ranks sixteenth in proven oil reserves and exports roughly 60% of its total production (600,000 barrels per day). According to Algeria’s national oil company, Sonatrach, about two-thirds of the Algerian territory remains underdeveloped or unexplored, with an estimated 100 undeveloped discoveries.

The post Eni launches solar lab and PV plant to decarbonise oil operations in Algeria appeared first on Power Engineering International.

You are invited to access the latest Europe Energy Talks – available online – which was hosted in Frankfurt, Germany, where experts discuss the challenges and opportunities of the energy transition in view of the expanding energy crisis in Europe.

Siemens Energy and Enlit Europe collaborated to host the Europe Energy Talks, where key players including BASF, EnBW, Shell, Uniper, and MVV participated.

Together, the panel explored how we can ensure energy security and affordability – and still accelerate the journey to net zero.

Moderator:
Kelvin Ross, Editor-in-Chief of Enlit Europe

Welcome address:
Ariel Porat, Senior Vice President, Head of Hub Europe, Siemens Energy

Panel:

Marcus Adlon, Managing Director | MVV Green Heat GmbH
Dr. Hannah König, Head of Procurement | EnBW
Dr. Holger Kreetz, COO Asset Management | Uniper
Jens Müller-Belau, Managing Director Energy Transition (Germany) | Shell
Christoph Schuette, Managing Director | Siemens Energy Germany

The energy transformation requires all of us to face some uncomfortable truths.
Join Siemens Energy to talk about them! 

The post On Demand: What is Europe’s role in the energy transition? – Europe Energy Talks appeared first on Power Engineering International.

While the global energy market is facing the impact of geopolitical and environmental challenges, we must continue to take action to move towards a greener future.

Process electrification could be the solution for oil & gas majors to accelerate energy transition in its portfolio and operations.

Process electrification is a major trend driven by greenhouse gas regulations and an increase in fundings for projects such as the LIFE Clean Energy Transition in Europe.

However, electrification of hard-to-abate industries is often considered as a threat to natural gas.

At the same time, this electrification can be hindered by the intermittent nature of renewable power and peak demand electricity prices.

Webcast 9 Nov | Green is the new black: Oil & gas and the race to energy efficiency

The way round this is to change this binary of ‘gas vs electrification’ approach and instead, anchor the role of gas as a transitional and complementary energy.

Electrification of various processes in industry has already started developing. It covers the electrification of mechanical drives such as compressors or pumps in industrial applications like FPSO, LNG and pipelines, as well as the electrification of various heaters or boilers in refineries and petrochemicals and hybrid process applications.

Electrification brings benefits in terms of efficiency, maintenance, and uptime. In some cases, the endgame is also to switch from fossil fuel, usually natural gas, to decarbonized electricity supply.

For example, it is possible to make industrial processes sustainable by integrating renewable energy into industrial facilities and as a result reducing scope 1 and 2 emissions.

With electrification helping to achieve sustainability targets, major industries are adopting a flexible, partial to full electrification approach.

With the development of new digital offers, it is possible to manage the complexity of growing electrical infrastructure such as electrical demands increasing to 4x-10x than base load (before process electrification) and at the same time generate significant OPEX savings by managing various electrical power sources within the facility which include a mix of renewables, conventional and utility.

There is an opportunity here for natural gas to position itself as a flexibility enabler – for accelerating the trend of electrification and securing its future. Concepts to manage hybrid power mix are introduced, which can help end-users to achieve sustainability targets and OPEX goals in parallel.

Studies conducted by McKinsey indicate about 44% of energy consumption in industrial applications is fuel consumed for energy, and this ration can be much higher on some O&G applications.

Up to approximately 400 degrees Celsius, electric alternatives to fired heaters are commercially available. Electric heat pumps for low- and medium-temperature heat demand and electric-powered mechanical vapour recompression (MVR) equipment for evaporation are already used on some industrial sites.

Electric furnaces for industrial heat demand up to approximately 1,000 degrees Celsius are technologically feasible but are not yet commercially available for all applications.

North Sea’s oil & gas landscape ideal for energy transition – report

There are already many references in the glass industry (temperatures in the 1100°C range). BASF is developing petrochemical cracking furnaces that reach 850 degrees Celsius and is planning to have them in their facilities within six years.

Electrifying compressors by large electric motors (10MW and more) with variable speed drive (VSD) system is becoming increasingly common.

The most critical point in this journey is electrical power availability. Will it be sourced externally or in-house? And can it be penetrated with clean energy or high efficiency combine cycle power plants with carbon capture, utilisation, and storage (CCUS)? This would also improve the environmental impacts through zero or limited emissions.

Striking the balance on commercial aspects (electricity economics) is critical as electricity prices can impact the economics of process electrification.

For example, in a remote gas field, the most practical solution may be to use gas direct drive or central gas turbine generation powered by project gas.

However, it will not help to achieve reduction in carbon emissions. Electrification of an asset, such as a refinery, should be seen as a long-term journey where you need the right support during the main stages.

The benefits of this longer-term electrification go beyond greenhouse gas emission reduction. Electrification allows better control, and thus drives higher efficiency. It lowers maintenance costs with better MTBF, it enables remote operations, and it allows the monetization of grid balancing in the case of grid connection.

Five digital trends for the oil & gas sector

But electrification does not mean killing natural gas. When connected to a utility grid and/or a renewable power generation farm, there are times in the day or the year where electricity may be abundant and cheap, and other times where it will be very expensive and where the utility might be struggling to supply priority customers.

Being able to flexibly shift between gas-fired heaters and electric heaters can be a great opportunity to optimise energy bills and greenhouse gas emissions and monetize energy source flexibility.

In some other applications, such as floating production, storage and offloading (FPSO), the push for electrification will be mainly driven by efficiency and improved controls. A larger power generation and electric motor-driven compressors will be more flexible and reliable than many smaller gas turbines each driving a single mechanical load.

Full to partial electrification of processes can be achieved with three options, the first being heat pumps instead of reboilers and condensers. Second is electrical heating instead of steam or fuel-fired heaters and third is electrical motors instead of steam or gas turbines.

In all cases, greenhouse gas emissions are reduced, and equipment efficiency is improved.

The key considerations for electrification should integrate partial and flexible electrification in order to develop an accurate electrical power, steam and fuel gas model, as well as simulate every realistic operating scenario, perform reliability and availability study to compare figures with base case and, tabulate benefits in operating cost, energy efficiency and emissions.

In a greenfield scenario, it is advisable to explore the potential of partial or full electrification during the initial design stages by ensuring that all foreseeable factors have been addressed and considered up front.

Existing industrial facilities which currently use thermal energy to meet their process heating requirements, can typically reach 50% electrification with available technology.

ABOUT THE AUTHORS

Eric Koenig is Strategy VP Energies & Chemicals at Schneider Electric.

Shailesh Chetty is Technical Leader Energy Management at Schneider Electric.

The post How process electrification can complement natural gas appeared first on Power Engineering International.

The three countries on which the reports focus, UK, Norway and Denmark, are all economically reliant on North Sea oil and gas. However, the skills, resources and knowledge shared by these countries could create a global blueprint to accelerate the phase-out of oil and gas in the North Sea and beyond.

According to the reports, in order to capitalise on these resources, clear pathways for a clean and just energy transition alongside changes in attitudes and sound governance are essential.

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The report makes several generalised recommendations to support the energy transition; including:

• Support for innovation and investment in renewables and low carbon technologies to replace oil and gas – both as an energy supply and as a revenue stream
• Targeted support for technologies such as renewables and hydrogen, which could create new economic opportunities, deliver green growth, and support communities that rely on the fossil fuel sector for their livelihoods

Each country report outlines recommendations based on the country’s unique challenges and opportunities:

Norway’s energy transition

In Norway, the oil and gas sector employs 6% of the workforce, which contributes to the economy, but also to a quarter of the country’s CO2 emissions each year.

The report suggests that the Norwegian government focus on shifting attitudes, which report author and board member of UN Global Compact Norway Heikki Holmås suggests is highly possible.

“In Norway, the oil and gas industry runs deeply through the economy and society, particularly for communities supported by employment in the sector. Phasing out North Sea oil and gas will have a substantial impact on the country and there is not yet consensus on how we achieve our 2050 net zero targets.

“It is however likely that a consensus can be established around strong investment in offshore wind and CCS together with a net zero commitment for all oil and gas extraction. Through tripartite dialogue, the government can deliver strong and ambitious policy that accelerates a clean energy transition in the North Sea, supports Norwegian communities and protects against future fossil fuel crises.”

The report recommends policy makers set out a bold strategy, developed in partnership with businesses and civil society, a union that could see Norway install up to 50GW of wind power by 2050.

Denmark’s energy transition

Denmark has a clear vision for phasing out fossil fuel extraction by 2050 and the OGT findings show that a phase out by 2040 or even as early as 2034 is achievable.

Professor Brian Vad Mathiesen of Aalborg University said in a statement: “There is a unique window of opportunity to accelerate the clean energy transition in Denmark, by already phasing out most of Danish oil and gas exploration by 2034 and at the very latest, by 2042. Such a move is not only possible, it is less costly than anticipated, when considering that production volumes gradually diminish.”

The report recommends the Danish government develop a detailed transition plan which accelerates clean tech roll out and compensates for revenues lost due to fossil fuel phase-out.

Energy Transitions Podcast: The North Sea – Axis of decarbonisation

Professor Vad Mathiesen added: “Vital to achieving a possible 2034 goal, and stimulating the necessary green innovation, is a clear and holistic strategy for all oil and gas sector actors, a high level of policy advice, transparency and public involvement.

“That’s why we are calling for an independent committee to support the government deliver a robust and clear pathway outlining concrete, practical actions to end oil and gas exploration well before 2050.”

UK’s energy transition

The UK has ambitious decarbonisation targets, however, the OGT report suggests climate compatibility checkpoints are currently at risk due to the energy crisis, as the government looks to increase oil and gas exploration in the North Sea.

Dr Kirsten Jenkins, lecturer at The University of Edinburgh and report author stated: “There is a risk that the current energy price crisis and exponentially rising consumer bills will be used to legitimate new oil and gas developments in the UK; developments that would take place at the very moment when investments should be channeled away from fossil fuels and towards transformative, low-carbon supply and demand-side change.”

However, the OGT’s UK report suggests a clear roadmap delivered through stronger devolved governance to ensure net zero ambitions, could instil market confidence, reduce market volatility and deliver ambitious decarbonisation.

The post North Sea decarbonisation needs a clear vision and an attitude change appeared first on Power Engineering International.

To learn more about how bedrock can aid decarbonisation, PEi’s Pamela Largue spoke to John King, CEO and co-founder of Hyperlight, a systems engineering company over a decade old and originally focused on generating biofuels from algae.

The concept of Geological Thermal Energy Storage

Hyperlight’s system is based on Geological Thermal Energy Storage (GeoTES) technology, a hybrid geological solar power plant that uses existing oil drilling infrastructure to store carbon-free thermal energy underground in massive quantities.

King explained that clean energy is stored underground at oil well sites and can be extracted and converted to electricity whenever needed using traditional geothermal power generation technologies.

Geological thermal energy storage is currently being investigated to decarbonise the hard-to-abate oil and gas sector in California, but King states, “it can be deployed wherever you have sun and sedimentary formations with or without oil.”

California, explains King, is a perfect canvas to develop and deploy this technology due to its strong public policy framework and a market large enough to encourage deployment at scale.

Given California’s 100,000 enhanced oil recovery wells (EOR), Hyperlight estimates the statewide potential storage capacity of its technology to be the equivalent of one billion Tesla Powerwalls, with energy production potential over 100TWh annually, exceeding the output of all the natural gas power plants in California combined.

However, Hyperlight is looking to expand far beyond the borders of California.

The world is moving towards greener energy which makes storage more important than it has ever been, stated King, in light of the intermittent nature of renewables and the corresponding need for flexibility.

Said King: “In terms of ensuring grid reliability, when the sun isn’t shining, eight-hour batteries are great, but you still need weekly, monthly and seasonal storage”.

Taking advantage of existing infrastructure: Enhanced oil recovery sites

EOR involves steam being injected into the ground to produce oil. The oil and gas sector has spent billions optimising thermal efficiency techniques in the process, such as replacing natural gas fired burners with solar power to create steam for EOR operations.

According to King, this is a big part of the reason why Hyperlight has focused the last decade on maximising and monetising process heat.

A great deal of the thermal energy injected into the ground remains there for several months, creating a synthetic geothermal resource, said King.

“Coupled with CSP, you have a very predictable, reliable source of heat and you can stick a power generation cycle on the back end of this and generate power very efficiently.

“This provides an effective decarbonisation pathway for oil and gas. When the wells dry up, the heat is still there allowing power generation to go on indefinitely.”

Explaining the potential scale of this solution, King explains that there is a massive volume of bedrock. “In California alone, underneath the 100,000 wells that are producing, there’s six cubic miles of rock”.

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King explained how Hyperlight, in collaboration with US-based National Renewable Energy Agency (NREL), has worked to maximise CSP coupled with geothermal resources.

Enter the platform called Tectonic Sun, which stores months’ worth of solar energy in the geological formations at EOR sites.

Said King: “Tectonic Sun transforms the wells into renewable energy resources that enable power generation which can be switched on at any time and generate for as long as needed.”

The development roadmap for this technology is called “Tectonic Sun Alpha” and will see Hyperlight pursue heat-only and power generation projects.

“The Tectonic Sun platform is an incremental improvement, where we are keeping the high-quality surface heat of 300 to 400 degrees centigrade. Then we split the heat, keeping some at the surface and sending most of it into the rock.

“When we bring that produced fluid back to the surface it’s at 120 C, and we recombine it with the high-quality heat we kept at the surface. This allows for super heating at the surface, ensuring higher efficiencies during power generation.

“You’re increasing the quality and efficiency of what you’re doing and getting more bang for your buck out of your power cycle investment.”

A startup with a few decades of experience

Hyperlight considers itself a hybrid between a startup and a scaleup. Said King: “We started out as an algae company, then we pivoted over to be a CSP company.

“We have had an opportunity to demonstrate our ingenuity and grit, to navigate a very challenging environment and still advanced the technology.

“We have done that and now have a transformative market application.”

The company is currently focused on project finance and securing an offtake agreement with a credit-worthy offtaker.

“Then the goal is to overcome the hurdles associated with a first-of-its kind technology, focusing on second iterations and scaling up projects,” added King.

For now Hyperlight plans to take its place in the global fight against climate change, making use of an enormous battery beneath our feet to provide clean electricity and aid decarbonisation as far afield as possible.

The post What does bedrock have in common with a billion Tesla Powerwalls? appeared first on Power Engineering International.

In order for the industry to resist the rising pressure and succeed, it needs to adopt a digital-first approach. Digital innovation is key for mitigating the oil and gas crisis and working more efficiently.

Here are the latest digital trends and innovations that will drive the future of the oil and gas sector.

Robotics & automation

In order to promote safety while working under pressure at an oil and gas site, it’s important to reduce manpower and make use of robotics and automation. Additionally, this will increase efficiency and the speed of operations, and lower the risk of human errors.

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According to Frost & Sullivan, the global gas and oil automation market is growing exponentially in attempts to recover from COVID-19 and meet the increasing demands for efficiency, safety, and sustainability.

It is expected to reach £18.69 billion by 2025, which is a 43% increase since 2020. It is also growing at a compound annual growth rate of 7.5%.

Safety first – digital equipment testing

Oil and gas sites can pose a significant safety threat to workers. While there might be certain safety procedures, such as eliminating hazards and providing Personal Protective Equipment (PPE), they’re not the most robust safety solutions.

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Quality analysis that adopts quick and efficient solutions is best suited for providing regular safety examinations of systems and preventing incidents.

For example, Enerpac’s Safe T™ Torque Checker validates and tests the exact torque equipment used on-site, such as pump, wrench, and hose, to give an accurate digital read-out. That way, it instantly validates the performance and safety of the entire system, thus minimising errors and incidents.

Big data analytics tools

Large volumes of data generated every day are a major part of the daily operations in the gas and oil industry. Data is extremely important as it provides great insight into both production and performance, which then feeds into optimisation processes and the development of AI-driven algorithms and models.

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Nevertheless, this data often tends to be unstructured. That’s where big data analytics tools can help structure and analyse data, in order to streamline complex operational processes and reduce costs.

Laser scanning and 3D printing

One of the major issues oil and gas companies are facing is the extended downtime associated with the sourcing of complex, customized stand-alone parts. This is causing significant losses of revenue.

Laser scanning of every part of the impeller 3D models, accompanied by 3D printing metal fabrication can reduce the downtime by months and help optimise operations.

3D printing doesn’t require tooling and can replicate lightweight structures with complex internal components. This is a great solution, especially for low-volume projects.

Substructural simulations

Companies often have difficulties monitoring the structural integrity of offshore assets and subsurface.

3D modelling and substructural simulations can provide real-time data and visualisations. This offers greater accuracy, information about potential issues, and ways to minimise planning time.

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Data is collected through sensors on the ring and analysed using cloud-based solvers. This can help establish risks that can impact the safety of the reservoir, as well as provide a new perspective on structural design.

Jumping on the digital innovation wagon can significantly help oil and gas companies mitigate the current challenges and stay afloat in a competitive market.

Not only that, but the current digital trends can help increase the efficiency of operations, provide better worker safety, and reduce costs. This is all while continuously innovating how to improve processes and technology.

Joanne O’Donnell is HR Manager at HTL Group.

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The post Five digital trends for the oil & gas sector appeared first on Power Engineering International.