Oil & Gas Technology - Winter 2020

The new normal is digital

Reinventing the familiar for subsea production The path to a netzero emissions energy business How technology supports the move to integrated energy ISSUE 52

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WINTER 2020

Managing obsolete equipment in oil and gas Innovative solutions to challenging well conditions

Editorial Mark Venables – Editor in Chief mark.venables@cavendishgroup.co.uk Ben Avison – Group Editorial Director ben.avison@cavendishgroup.co.uk Chairman Koos Tesselaar CEO Matthew Astill Managing Director Adam Soroka Advertising Director Mike Smith mike.smith@cavendishgroup.co.uk Expert Advisor Trish Meek, Director of Pro

The new normal is digital

Reinventing the familiar for subsea production The path to a netzero emissions energy business How technology supports the move to integrated energy ISSUE 52

|

Managing obsolete equipment in oil and gas Innovative solutions to challenging well conditions

WINTER 2020

Oil & Gas Technology

Cavendish Group Second Floor Front 116-118 Chancery Lane London WC1A 1PP Tel: +44 (0)0203 675 9530

The oil and gas sector is facing a barrage of challenges primarily led by the impact of COVID-19 and the oil prices war. Oil prices are dropping due to failed agreements on production cuts and the need for chemicals and refined products is slowing from industrial slow-downs and travel restrictions in the wake of this global pandemic.

For the sector this is the third price collapse in 12 years. The industry shock itself down and staged a dramatic recovery after the first two financial crisis but this time around it looks to be different After the first two shocks, the industry rebounded, and business as usual continued. The current situation is a combination of supply shock with an unprecedented demand drop and a global humanitarian crisis.

Players in the oil and gas sectors are struggling with declining demand, ensuring employee safety and business stability, oil price war, and need to focus on building a flexible business model that can lead to long-term resilience as the world comes out

of the coronavirus crisis. As the global oil and gas industry continues to understand the overall effect of the coronavirus pandemic on oil demand and what the future holds, dealing with lower product demand and coming to terms with the fall in prices is a stark reality facing many companies in the coming months.

The International Energy Agency said on June 16, it did not expect oil demand to return to pre-pandemic levels before 2022 due to a slump in air travel. DNV GL has previously predicted oil demand would plateau in 2022. Growing scepticism about long-term global oil demand in a postpandemic world is putting pressure on oil companies to revalue their assets.

Before the onset of COVID-19 it was not envisaged that we would witness the peak in oil demand for another 20 years. However, the wreckage to the economy and the oil and gas sector in terms of demand and policies indicate that this peak with be upon us much earlier than earlier predictions.

Oil and gas companies, weakened by the low level of prices and their volatility and pushed by investors increasingly eager to step in cleaner projects, could consider – more than before – participating actively to the energy transition and turn to products more sustainable than fossil fuels.

The pandemic has created challenges for the oil and gas industry, but it has also given the industry an opportunity to hit pause and reflect on the urgent action needed to build back better for a more fair, sustainable, and resilient future. To enable The Great Reset and to address the needs of all stakeholders, the oil and gas industry must define a new social contract, aligning sustainability to overall corporate strategies, and embracing responsible leadership. By doing so, this sector has the opportunity to contribute towards the energy transition.

Mark Venables Editor Oil & Gas Technology

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Your Vision of that Future With the growing tide of change in Energy, your ability to respond and manage that change means knowing exactly the direction you want to go. Transforming all your critical data to actionable insights means you control your vision of that Future.

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How technology supports the move to integrated energy 6

Updates The latest news from around the globe

20 A net-zero emissions energy business Speaking at Shell’s Responsible Investor Day event, which was conducted as a virtual webcast because of the COVID-19 pandemic, Ben van Beurden, CEO of Shell, spoke about Shell’s new ambition to be a net-zero emissions energy business by 2050.

30 Reinventing the familiar for superior subsea production In 2017, the Brazil National Petroleum Agency (ANP) issued a failure mode alert: stress corrosion cracking (SCC-CO2) triggered by the presence of CO2 in high pressure pre-salt conditions had been identified as the cause of broken tensile armor wires on a certain flexible pipe installation.

24 How technology supports the move to integrated energy As COVID-19 continues to impact global economies, some industries are evolving to identify how to protect or change their business models to suit whatever the future might hold.

33 From Russia with love 28 The new normal is digital 2020 has shown that digitalising the O&G industry is no more a matter of choice, it has become an urge to maintain stable operations while working remotely. That said, operators now have the chance to drive it efficiently and get the maximum value that digital solutions can offer.

The petroleum industry in Russia is one of the largest in the world. Russia has the largest reserves and is the largest exporter of natural gas and the eighth largest oil reserves and is one of the largest producers of oil. Oil & gas Technology spoke to Ekaterina Rodina, Oil & Gas Analyst at VTB Capital, about Russia’s role in the petroleum economy.

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36 Improving sealing capabilities of liner tiebacks to reduce the risk of Sustained Casing Pressure In well completions, the failure of a liner tieback seal is relatively common over the life a well. Reliable solutions such as a Welltec Annular Barrier (WAB) can provide both sealing and anchoring contingency, saving rig time, and reducing operational risks.

40 Managing obsolete equipment in oil and gas Despite innovation in oil and gas technology, some components in the sector have undesirably short life spans. For the oil and gas industry, an unexpected failure is more than a simple business inconvenience.

42 Innovative solutions to challenging well conditions Today, drilling teams face the dual challenge of the oil price drop and a global pandemic; whilst feeling added pressure to make operations more sustainable in-line with the drive for a low carbon future.

46 Managing the cyber risks created by digital transformation The increased digital reliance of the oil and gas sector has led to an increased cyberattack surface across the industry that organisations are scrambling to address. To stay safe operators must learn how to recognise, assess, and mitigate the cyber risks in oil and gas environments.

50 Cost-savings in strategic maintenance The turmoil of reduced prices and the ongoing global pandemic are putting a constant strain on the offshore oil and gas industry. Operators are looking for ways to reduce expenditure at various stages of developments and so analysts are exploring the methods used to date.

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53 Improve oil and gas production and reduce downtime New technologies are required to gain valuable insights and intelligence from the overwhelming volume and complex data sets produced by the Industrial Internet of Things (IIoT).

54 He is just passed his exams but Weldar is no ordinary apprentice.

After two years of practice, testing, and quality checks, Weldar passed his apprenticeship exam, repairing corrosion damage on a plant in full operation. But Weldar, whose nickname is a play on our CEO’s name, is an apprentice with a difference — he is a robot.

56 Letting the drones take the strain Several industries are using drones to improve their operations, with oil and gas one of the sectors testing the technology.

60 Edge computing key to digital transformation The oil and gas industry is ripe for change.

Forward-looking companies believe today’s turbulent market landscape and falling prices provide an opportunity to gain a competitive advantage by harnessing new technologies.

68 Innovation showcase A look at the most innovative new products and services

72 Final word: The growth of global discovered oil and gas resources Despite concerns that Covid-19 could drive down discovered volumes to their lowest levels in decades, exploration activity has been resilient this year.

Oil production costs reach new lows boosting deepwater prospects

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Rystad Energy analysis of oil production costs has revealed that the average breakeven price for all unsanctioned projects has dropped to around $50 per barrel, down around 10 per cent over the last two years, and 35 per cent since 2014. This means that oil is much cheaper to produce now compared to six years ago, with the clear cost savings winner being new offshore deepwater developments.

“The cost of supply curve for liquids now reveals that the required oil price for producing 100 million barrels per day (bpd) in 2025 has been in continuous decline in recent years, with the updated projection showing that an oil price of only $50 per barrel is needed to keep oil production at this level,” Espen Erlingsen, head of upstream research at Rystad Energy, said.

“Previously, in 2014, we had estimated that the required oil price for producing 100 million

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barrels per day in 2025 was close to $90 per barrel, an estimate which we then revised in 2018 to around $55 per barrel.

“The updated curve also shows another key trend. From 2014 to 2018, the cost of supply curve moved to the right. In 2014, we estimated that the total 2025 liquids potential was only 105 million bpd. In 2018, this number had increased considerably to around 115 million bpd. However, since 2018, we have revised down the potential to about 108 million bpd, moving the cost curve to the left.

“The implication of falling breakeven prices is that the upstream industry, over the last two years, has become more competitive than ever and is able to supply more volumes at a lower price. However, the average breakeven prices for most of the sources remain higher than the current oil price. This is a clear indication that for upstream investments to rebound,

oil prices must recover from their current values.”

When it comes to breakeven prices and potential liquids supply in 2025 for the main sources of new production, Rystad Energy data shows that from 2014 to 2018, tight oil and OPEC came out on top.

Back in 2014, Rystad Energy estimated the average breakeven price for tight oil to be $82 per barrel and potential supply in 2025 at 12 million bpd.

Since then, the breakeven price has come down and the potential supply has increased for tight oil. “In 2018, we estimated an average breakeven price of $47 per barrel and a potential supply of 22 million bpd,” Erlingsen continued. “After 2018, the breakeven price for tight oil has continued to fall, reaching a current average of $44 per barrel. However, the potential of tight oil production has dropped from our 2018 estimate.

“Now we estimate that tight oil can potentially supply around 18 million bpd of liquids in 2025.

Update

This drop is due to the sharp reduction in tight oil production during the first half of this year.

The lower activity this year, and a potentially slow recovery next year, will remove tight oil supply from the market.”

Between 2014 and 2018, shelf and deepwater projects experienced a cost reduction of around 30 per cent. However, the lack of new sanctioning during the same period reduced the offshore potential liquids supply for 2025. Since 2018, breakeven prices have been falling for offshore, with deepwater down 16 per cent and shallow water down ten per cent.

This cost reduction puts average breakeven prices for deepwater just below those of tight oil. At the same time, the potential 2025 supply from offshore developments has not changed too much.

This makes offshore a winner out of all the supply sources over the last two years when it comes to cost improvements and supply potential.

Onshore Middle East is the least expensive source of new production with an average breakeven price of around $30 per barrel. This is also the segment with one of the largest resource potential estimates. Offshore deepwater is the second cheapest source of new production, with an average breakeven price of $43 per barrel while onshore supply in Russia remains one of the more expensive resources due to the high gross taxes in the country. Shelf remains the segment with the largest resource potential with 131 billion barrels of unsanctioned volumes.

One of the key drivers of the improved costs and breakeven prices for upstream developments are the lower unit prices within the industry. After the 2015 oil price collapse, oil field service companies needed to reduce the prices they charged E&P companies in order to remain competitive in the challenging market conditions.

For all sources, unit prices dropped close to 25 per cent between 2014 and 2016 but it was tight oil that faced the largest reduction. Since then, the supply segments have recovered differently.

While offshore and conventional onshore supply only saw marginal price increases, tight oil unit prices increased considerably during 2018.

However, given that tight oil activity fell last year and with the Covid-19 inflicted market crisis this year, tight oil unit prices have started to drop again since 2018. For all the main upstream segments, current unit prices have come down around 30 per cent compared to 2014 levels.

BP starts gas production from Qattameya field

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P has started gas production from its latest development offshore Egypt – the Qattameya gas field in the North Damietta offshore concession.

Through BP’s joint venture, Pharaonic Petroleum Company (PhPC), the field, which is expected to produce up to 50 million cubic feet of gas per day, has been developed through a one-well subsea development and tie-back to existing infrastructure.

“By building on bp’s significant existing assets and infrastructure offshore Egypt, we were able to develop Qattameya efficiently and economically,” Karim Alaa, North Africa regional president BP, said. “Creating value through high quality, efficient oil and gas developments is a key part of bp’s strategy.

We see this as a great example of resilient hydrocarbons development.

“We are proud to have brought this project safely onstream through an extremely challenging period. Our team continues to work to support Egypt realising the potential of its energy resources, adding to our track-record of delivery and enabled by our established partnerships with the Egyptian petroleum sector.”

Qattameya, whose discovery was announced in 2017, is located approximately 45 km west of the Ha’py platform, in 108 metres of water. It is tied back to the Ha’py and Tuart field development via a new 50km pipeline and is also connected to their existing subsea utilities via a 50 km umbilical.

BP holds 100 per cent equity in the North Damietta offshore concession in the East Nile Delta. Gas production from the field is directed to Egypt’s national grid.

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Update

Report addresses growing issues Siemens Energy to of hydrogen embrittlement in help Total offshore environments. achieve lowemission goals for largest LNG project in Africa

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illiam Hackett has released an industry report to help minimise the risk of Hydrogen Embrittlement (HE) and Stress Induced Corrosion Cracking (SICC). The report includes guidance on material choices used in topside and subsea lifts, and is seen as a major step forward in increasing awareness for offshore operators of the risks associated with HE and SICC. “There is a real concern across industry regarding the impact of HE and SICC on chains and links used in lift and hoist projects across offshore environments,” Ben Burgess, director of William Hackett Lifting Products, said.

Peer-reviewed by a number of organisations and authorities, the report takes a major step forward to explain the critical impact of HE. Dr Emilio Martínez-Pañeda, Assistant Professor at Imperial College London and a world-recognised expert in hydrogen embrittlement, welcomed the report. While not directly involved in the report’s findings, Dr MartínezPañeda emphasised the challenging nature of hydrogen embrittlement and its important implications: “Hydrogen is famed for causing notorious structural integrity problems that are difficult to predict, and there is a need for new guidelines and solutions.”

“Based on our own experiences of how our products perform offshore, combined with the manufacturing expertise of McKinnon Chain and outcomes of detailed technical analysis by industry partners, we have identified that as material hardness exceeds 39-40 HRC, the risk of HE and SICC increases as the hardness values rise,” Burgess said.

But the issue of HE is not limited to just one type of

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activity. Examples include the failure of G10 welded chain slings in a container fleet in Norway, to the USA where a global oil company had to withdraw a number of lifting appliances and promptly introduced an inspection regime before any future lift work was carried out.

The report also highlights that whilst products may be fully compliant with relevant International Standards, the reality is that when it comes to an offshore environment, they may be wholly unsuitable.

“Meeting the specific International Standards should not be seen as a guarantee that specific equipment is fit for purpose in an offshore environment,” Burgess added.

“Specific environmental and performance considerations for equipment used offshore needs to be a key part of the material specification and selection process.

“To put this into context a Grade 8 master link, when correctly heat treated, will provide toughness, tensile strength and resistance to shock absorption in loading, and at hardness levels that enable the steel in the product to withstand extreme conditions of the offshore environment.”

Correct materials selection is critical, especially when it comes to problems such as HE. Operators need to ensure that despite commercial pressures, the products used in the offshore environment are fully appropriate for their intended use, and that the environmental conditions, mechanical stresses and material susceptibility have all been assessed rigorously.

Dr Martínez-Pañeda noted that while the scientific community has achieved great progress in using simulation tools to predict the behaviour of components exposed to hydrogen, challenges remain and “the materials to be used and the manufacturing process has to be tested and assessed to minimise the risks as much as possible.”

Burgess believes that managing the risks of HE and SICC requires a change of mindset. “The advancement towards higher and higher grades of steel should be treated with caution,” he concluded. “In an offshore environment, procurement and quality assurance policies should include comprehensive details of the material’s properties, as well as standard compliance. Without the proper understanding of the material and its use offshore, the end result is increased risk to operations.”

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CS JV (a joint venture between Saipem and McDermott) recently selected Siemens Energy to supply emissionsreducing power generation equipment and boil-off gas compressors for the Mozambique LNG Project in the Cabo Delgado province on Africa’s East Coast.

The project, led by TOTAL E&P Mozambique Area 1, includes the development of offshore gas fields in Mozambique’s Area 1 and a liquefaction plant with a capacity in excess of 12 million tons per year.

As part of the contract, Siemens Energy will supply six SGT-800 industrial gas turbines that will be used for low-emissions onsite power generation.

With more than eight million total fleet operating hours and more than 400 units sold, the SGT-800 turbine is ideally suited for power generation, particularly in LNG

applications, where reliability and efficiency are critical.

The 54MW turbine rating selected for this project has a gross efficiency of 39 percent. It is equipped with a robust, dry low-emission (DLE) combustion system that enables world-class emission performance over a wide load range.

“Mozambique LNG is the country’s first onshore LNG development project and will play a key role in meeting the increasing demand for energy in the Asia-Pacific, Middle East, and Indian sub-continent markets,” said Thorbjoern Fors, Executive Vice President for Siemens Energy Industrial Applications. “We look forward to helping Total drive toward the lowest possible plant emissions profile and contributing to its goal of delivering clean, reliable energy to customers across the globe.”

Siemens Energy will also supply four centrifugal compressors for boil-off gas (BOG) service. A key feature of these compressors is the inlet guide vane (IGV) system that allows for optimization of power consumption according to changes in operational parameters such as inlet temperature and outlet pressure.

The gas turbines are slated for delivery in the second half of 2021 and the first half of 2022. The delivery of the compressors is scheduled for 2021.

“We’re proud to be part of this important project as a supplier of reliable, field-proven rotating equipment that will help contribute to the long-term economic growth of Mozambique and the prosperity of its citizens,” said Arja Talakar, Senior Vice President, Industrial Applications Products for Siemens Energy.

The equipment order for the Mozambique LNG project comes on the heels of a recent agreement between Total and Siemens Energy to advance new concepts for low-emissions LNG production. As part of the contract, Siemens Energy is conducting studies to explore a variety of possible liquefaction and power generation plant designs, with the goal of decarbonizing LNG facility development and operation.

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Update

Enpro Subsea enables safe removal of attic oil from Brent Bravo’s concrete cells

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unting Energy Services, Subsea Technologies division supporting DeepOcean has successfully completed another campaign in the North Sea using Enpro Subsea’s proven Field Decommissioning (F-Decom) system. The recent campaign on Shell UK Limited (Shell) Brent Bravo concrete structure was completed with no safety incidents, ahead of schedule and within budget.

Enpro’s patented technology enabled the safe access and removal of ‘attic’ oil from concrete storage cells at the base of the Brent Bravo platform in 140m water depth. The system, which on previous campaigns had been deployed direct from platform topsides, was this time deployed from a DeepOcean construction vessel, leading to a significant reduction in operating days per cell.

The F-Decom system is the only field proven system for securely accessing fluids within gravity-based structures (GBS) concrete cells assisting operators to safely meet their decommissioning regulatory obligations to protect Europe’s marine environment.

The project involved Enpro’s offshore engineers and onshore support teams working alongside DeepOcean’s operations and subsea teams onboard the construction vessel, the Maersk Forza. Enpro Subsea’s proprietary solution centres around their patented ‘anchor hub’ technology which mechanically locks into the concrete cell cap and allows a suite of tooling (i.e. drilling, sampling, wireline, pumping) to be compact and lighter, thereby enabling it to be easily installed and operated using work class ROVs and operate within a broad weather window.

This is the fourth such campaign the company has undertaken for Shell to support its ongoing decommissioning programme in the Brent field, located north-east of the Shetland Islands.

Enpro Subsea engineering director Neil Rogerson said: “The system is well proven, and Shell have previously deployed our F-Decom technology on both their Brent Bravo and Brent Delta platforms. For the 2020 Bravo project, our collaboration with DeepOcean has allowed us to optimise this same low risk system, specifically for working from a vessel, yielding significant operational efficiencies, and increasing value to our client. As a result, we now have extended the track record of the only field proven system, which can be configured to suit a variety AOR (Attic Oil Recovery) decommissioning programmes.”

Roy Nilsen, DeepOcean project manager said. “The attic oil recovery project on Shell’s Brent Bravo platform was a great project for DeepOcean and its success comes from the combination of Enpro Subsea’s F-Decom system and DeepOcean’s expert subsea engineering and WROV capabilities as well as the good collaboration between all parties involved.”

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Petrobras releases highlights on production and sales in 3Q20

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ccording to the latest figures released by Petrobras, its operational performance in 3Q20 was exceptionally good, considering the challenging scenario imposed by the COVID-19 pandemic. Its oil and gas production in Brazil grew by nine per cent in the first nine months of this year compared to last year. The production of the pre-salt fields increased by 32 per cent, while in the other areas, post-salt, shallow waters and onshore, there was a contraction.

It estimates that the average production in 2020 will reach 2.84 MMboed, of which 2.28 MMbpd of oil, with a variation of 1.5 per cent upwards or downwards, exceeding the upper limit (2.5 per cent) of the targets originally announced for the year (2.7 MMboed and 2.2 MMboed).

Higher than expected production growth did not result in excessive inventories, which would be possible given the significant reduction in global oil demand. On the contrary, Petrobras have been working with lower inventories than in the pre-COVID period thanks to the greater integration between production, refining, logistics and marketing.

The contingency scenario for COVID-19 continues to limit the number of personnel aboard the offshore production facilities, leading it to postpone part of the scheduled shutdowns in 4Q20 to the beginning of 2021. However, they were able to carry out maintenance activities, which contributed to increase operational efficiency, operate safely and maintain optimum performance. Another highlight was the success achieved in the inspection campaign for pipelines susceptible to corrosion under tension by CO2 carried out with new technologies and tools, the results of which enabled the operational continuity of gas injection pipelines, reducing production expenses and losses.

The average production of oil, NGL and natural gas in 3Q20 reached 2.95 MMboed, 5.4 per cent above 2Q20. Contributed to this result the growth in production in the Atapu field, with the start-up of the FPSO P-70 and first oil at the end of June, alongside the greater operational efficiency of P-74, P-75, P-76 and P-77, in the Buzios field. The performance of these platforms was supported by the temporary expansion of the oil and gas processing capacity of the units, using spare capacity in power generation and gas compression available until the beginning of gas exports, and by the high production potential of the wells and the reservoir. This enabled the achievement of monthly production records in Búzios, of 615 kbpd of oil and 765 kboed in July and the highest monthly production achieved by a well in Brazil, with the mark of 69.6 kboed from the BUZ-10 well registered in September. In that month, we also had 2 Búzios wells that exceeded the 65 thousand boed mark (BUZ-12 and BUZ-24, respectively with 67.4 and 65.8 kboed). In August, we started the gas flow from P-74.

The Tupi field reached the historic milestone of accumulated production of 2 billion barrels of oil equivalent, 20 years after the signing of the concession contract and 10 years after installing the first definitive production system. It is currently the deep waters field with the highest production worldwide and accounted for 28 per cent of our production in 3Q20. In July, we reached the 150 kbpd production capacity on the P-67 platform, operating in this field. Tupi was also a pioneer in the development of the presalt layer and revealed the existence of a new exploratory model, previously unknown in the world.

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Update

Digital transformation vision enables frontline workers to become agents of change

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VEVA has signed an agreement to help accelerate Shell Global Solutions International’s digital transformational strategy by deploying AVEVA’s cloud software solutions.

AVEVA will provide Shell with its Engineering Data Warehouse technology, which is one of the building blocks of the digital twin. This will enable a common digital thread across engineering, operations and maintenance and the ability to securely deliver information in context from a single source to decision makers across these critical functions.

The technology will enable Shell through its digital twin to drive asset reliability, enhance efficiency and reduce unplanned downtime. The solution will also support in providing actionable insights right from the site operator to the asset leadership team.

The solution supports Shell’s ambition to empower staff across its manufacturing sites and to keep frontline industrial workers safe while ensuring business continuity and operational resilience.

“Empowering workers requires access to all the information as today’s new normal entails remote access to monitor, manage and optimise production facilities,” Johan Krebbers, general manager, emerging digital technologies at Shell, said. “We are already witnessing the benefits of our strategic collaboration with AVEVA through our fully aligned vision for digital transformation.

This has enabled us to conduct operations remotely as well as seamlessly access the necessary applications to provide the insight, guidance and tools to ensure safe, effective and consistent work output, specific to each role.”

The data warehouse brings together engineering information across the lifecycle of the asset, supported by powerful and proven applications that enable visualisation, analysis, prediction and guidance.

“This deployment is part of Shell’s recently announced strategy to deploy digital twin technology across its manufacturing sites,” Ravi Gopinath, chief cloud officer and chief product officer, AVEVA, said. “Implementing new technologies like IIoT, extended reality, and artificial intelligence has huge advantages with the digital twin of an operating environment and this cutting-edge technology is guaranteed to deliver immediate improvements for Shell’s operations.”

Petrobras purchases FPSO P-71 and ponders development plan for Tupi

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fter negotiations with its partners in BM-S-11 Consortium, Shell Brasil Petróleo (25%) and Petrogal Brasil (10%), Petrobras has signed a commitment to purchase platform P-71, subject to the foregoing conditions related to milestones in the unit’s physical progress. It was also agreed to prepare a new Development Plan (DP) for the Tupi field, where the FPSO would originally be used.

Petrobras’ disbursement estimated in the transaction will be $353 million, corresponding to the partners’ share in P-71.

The P-71, in the final phase of construction at the Jurong Shipyard, state of Espírito Santo, of the family of replicants, with a production capacity of 150 thousand bpd, will be allocated in Itapu field.

After the auction of the transfer of rights surplus occurred

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Update

CGG prepares for Nebula phase II, in deepwater Brazil

in November 2019, the production rights of the Itapu field are now fully owned by Petrobras and the allocation of the FPSO P-71 in the field will allow the anticipation of its first oil in about one year.

Due to the new allocation of P-71, the bidding for the charter of the platform that would serve the Itapu project will be cancelled.

With the commitment to sell P-71, subject to the above-mentioned conditions, the partners of the BM-S-11 Consortium in Brazil agreed to prepare a new DP for Tupi, to be delivered to the ANP in 2021.

This initiative seeks to implement complementary production development projects resilient to low oil prices, allowing to further increase the recovery factor of the field, which is currently the world’s largest producer in deep waters and whose accumulated production has already exceeded 2 billion boe.

The acquisition of P-71 and the actions to elaborate a new DP for Tupi are in line with the company’s strategy of concentrating its activities on world class assets in deep and ultra-deep waters.

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GG has announced that Nebula 3D Phase I is nearing completion and acquisition will soon commence on Phase II. Nebula 3D is a large, long-offset BroadSeis survey located in the prospective Campos and Santos Basins offshore Brazil. Phase I covers approximately 17,700 km2 on the southeastern side of the survey area providing 3D data coverage where currently no other 3D data exists.

Phase II covers approximately 10,000 km2 on the northern side of the survey area with underlying broadband datasets that will provide input for dual-azimuth imaging.

The Nebula Phase II dual azimuth data will better illuminate pre-salt events and address significant challenges posed by thick volcanic layers in this portion of the survey. CGG’s industry leading Subsurface Imaging Center in Rio de Janeiro will employ state-of-the-art processing technology including Interbed Multiple Attenuation and proprietary Time-lag FWI to dramatically

improve the velocity model and produce clearer, more focused subsurface images of this prolific pre-salt area.

Commencement of Phase II is expected early December and acquisition will be carried out by Shearwater’s Oceanic Sirius. Fast track results are expected Q4 2021 and final products are expected Q1 2022, which will include a TTI Kirchhoff PSDM, a TTI RTM 45Hz and a LSRTM 45Hz. “The Brazilian Pre-Salt is the largest worldwide oil discovery in the last decades and it is the most important exploration play in the world, highly coveted by all supermajor oil companies and by new players willing to enter in this prospective sector,” Sophie Zurquiyah, CEO CGG, said. “This addition to our already very large 3D multi-client library in the Santos and Campos basins underlines our commitment to offering the industry ultramodern data sets to support optimized exploration and development of the entire pre-salt area.”

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Update

Partnership set to promote AI awareness in energy and industrial sectors

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eyond Limits and The Carnrite Group have announced a multimillion-dollar revenue driving agreement to provide strategic consulting services on the state of AI technologies and innovative use cases for Carnrite’s client base across the globe in the oil and gas, utilities, power and industrials sectors. Additionally, The Carnrite Group will receive IP licensing rights to Beyond Limits’ cutting-edge Cognitive AI technology, providing customers with direct access to Beyond Limits’ solutions.

“This is a very exciting time for Beyond Limits to gain such a valuable partner as The Carnrite Group,” AJ Abdallat, CEO and founder of Beyond Limits, said.

“Through Carnrite’s vast network, we hope to provide valuable guidance and increase awareness of the benefits of AI in critical sectors, including boosting operational insights, improving operating conditions, and ultimately, increase adoption of this next generation technology.”

Many sectors are experiencing a significant surge in demand for AI. This is particularly true in the energy and industrial sectors, where continued commodity price volatility has forced companies to find innovative ways to further reduce costs. The AI market is expected to rise to $7.78 billion by 2024, an increase of 22.49 per cent from 2019.

“The Carnrite Group prides itself on helping clients address complex challenges and make difficult business decisions,” said Al Carnrite, CEO of The Carnrite Group. “Our agreement with Beyond Limits allows us to add their powerful Cognitive AI to our portfolio of consulting services while reinforcing our commitment to offer technologies that create value for our clients.”

Founded in 2014, Beyond Limits leverages a significant investment portfolio of advanced technology developed at Caltech’s Jet Propulsion Laboratory for NASA space missions.

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Groundbreaking new app details every energy resource in the North Sea

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new interactive mapping application that reveals the location of every energy-related site in the UK Continental Shelf (UKCS) is expected to bring real benefits for exploration and the search for carbon storage locations.

The game-changing app shows the proximity of existing oil and gas infrastructure to wind farms, electrical cables and carbon capture and storage (CCS) sites, which will assist in gauging the potential for reuse when decommissioning assessments are being made. It has also provided valuable information in prioritising areas for seismic shooting before a windfarm development is built.

Potential locations for platform electrification, gas-to-wire schemes and green hydrogen production can also be more readily found by using the app.

The map data itself stores details about the infrastructure which, combined with spatial locations, can support a wide variety of activities such as site survey cooperation, area planning, conflict resolution and disaster response.

The Oil and Gas Authority (OGA) has worked with The Crown Estate and Crown Estate Scotland to create the app, which lists over 60 in-construction or active wind, wave and tidal sites on the UKCS as well as recently awarded CCS licences and 489 petroleum licences.

The mapping application , is automatically updated as each of the organisations logs new information and is the first time that the locations of all oil and gas and renewables sites have been presented together. A ground-breaking example of collaboration across organisations involved in Energy Transition.

“This app will be a valuable tool for the energy industry both today and in the coming years,” Nic Granger, OGA Director of Corporate, said. “It is a significant addition to the digital services we already offer through our Data Centre.”

Adrian Fox, Head of Offshore Assets at The Crown Estate, added: “We are delighted to be working in partnership with the OGA on this digital project, making it easier for customers to view vital data about existing offshore infrastructure, which will support the co-ordinated growth of the renewable energy sector.”

Aggreko passes 1GW milestone in flare gas to power generation projects

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ggreko has surpassed 1GW of installed power capacity through flare gas to power projects across the world. This is enough to power one million UK homes every hour.

The energy industry wastes billions of cubic feet of Associated Petroleum Gas (APG) each year in a process known as “gas flaring”, whereby gas released during oil production is burned, releasing carbon emissions into the atmosphere and wasting energy that could otherwise be put to good use. The latest International Energy Agency (IEA) data shows that the volume of gas flared annually is equivalent to the gas demand of the continent of Africa. This results in annual CO2 emissions greater than those which are produced by Spain every year.

Aggreko’s solutions allow oil and gas operators to repurpose this gas to provide power for their operations, saving money on fuel costs and reducing their net carbon emissions. The company has now reached 1 GW of installed power capacity projects using these technologies, which has converted around 9.5 million Standard Cubic Feet (SCF) per mw/h of APG, with a major flare gas to power contract in the Middle East taking it over this threshold.

The IEA has called flared gas a “wasted economic opportunity”, and flare to power technologies are set to grow in popularity as companies and oil-producing nations look to cut carbon emissions. Flare-to-power schemes can help operators to avoid fines and other legislative measures that oil-producing countries are putting in place to discourage gas flaring, while allowing oil companies to set up quickly in areas where access to power could delay operations, including off-grid and remote sites.

“Flare gas to power is an incredibly exciting growth area for us, and an important way for us to help our customers use their resources in the most efficient way,” Stephen Beynon, president of power solutions at Aggreko said. “It is also an effective method of reducing business’ net carbon emissions, and we are proud to be helping the sector as it works to decarbonise. Crossing the threshold of 1GW of installed capacity is just the beginning for Aggreko’s ambition in this area, and we look forward to working with more operators to help them maximise the potential of this currently under-used resource.”

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15

Update

Emerson’s digital transformation technologies support safe operations for new Caspian Sea platform

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merson has been awarded a $14 million contract to provide automation technologies for the new Azeri Central East offshore platform in the Caspian Sea, the latest development in the Azeri-ChiragDeepwater Gunashli oilfield. Emerson will serve as the main automation contractor, providing its Project Certainty methodologies and digital technologies that transform capital project execution to help BP bring this fast-track project onstream in 2023.

Digital twin solutions and cloud engineering services, part of Emerson’s Project Certainty methodologies, will help accelerate project execution. Emerson’s digital twin solution enables virtual testing and system integration while the platform is being built and provides a simulated environment for platform operators to train, helping ensure a safe, smooth start-up and ongoing operational excellence. Cloud engineering reduces engineering costs and time by enabling global teams to collaborate and engineer in parallel, regardless of location.

Emerson will apply its portfolio of automation software and services to help BP achieve greater production and safe operations. This includes Emerson’s DeltaV automation system that controls critical safety functions in addition to wellhead production, drilling and the transfer of oil and gas to the onshore Sangachal Terminal.

Automation technologies also anticipate safety risks and enable remote monitoring, which reduces exposure of people and extends intervals between major maintenance turnarounds. Wired and wireless networks will connect more than 1,000 Emerson measurement instruments to monitor pressure, flow, temperature and pipework corrosion. Emerson will also provide all critical control, emergency shutdown and isolation valves, connected by its digital positioning technology.

“This latest project builds on the successful collaboration between BP and Emerson on the West Chirag and Shah Deniz Stage 2 developments,” said Jim Nyquist, group president for Emerson’s systems and software business. “Our extensive experience helping organisations achieve capital project success has enabled us to become a trusted partner to digitally transform mega projects such as Azeri Central East.”

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Petronas awards multiclient programmes in Sarawak Basin to seismic consortium

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he seismic consortium comprising PGS, TGS and WesternGeco have been awarded a multi-year contract by Petronas through competitive bidding to acquire and process up to 105,000 km2 of multi-sensor MultiClient 3D data in the Sarawak Basin, offshore Malaysia.

This contract award follows an ongoing campaign by the consortium in the Sabah offshore region of Malaysia, awarded in 2016, in which over 50,000 km2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support

Update

Malaysia license round and exploration activity.

The Sarawak award will enable the consortium to position itself in Malaysian seismic exploration and allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province).

“We are very pleased to have received this good news from PETRONAS through Malaysia Petroleum Management,” Nathan Oliver, PGS executive vice president sales and services, said. “Since this same consortium also acquiring MultiClient data offshore Sabah, we have demonstrated the benefit of the MultiClient business model to the Malaysian authorities and provided the oil and gas industry with high-quality seismic data in this prolific hydrocarbon basin. With this new award we are able to expand the MultiClient coverage into the Sarawak region to increase exploration and enhance production activities.”

The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Interested parties should contact the constituent members of the consortium for further details.

ADNOC awards $324 Million contracts to optimise onshore field operations and enhance efficiencies

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DNOC has announced the award of contracts worth $324 million (AED 1.19 billion) to optimize onshore field operations and enhance efficiencies as it continues to invest responsibly to drive smart growth.

ADNOC Onshore, a subsidiary of ADNOC, awarded the three contracts which will see the procurement and construction (PC) of flowlines and wellhead installations across several onshore oil fields in the Emirate of Abu Dhabi. The contracts also include the engineering, procurement, and construction (EPC) of a new bypass system to provide critical backup for the existing crude receiving stations at the Jebel Dhanna and Fujairah export terminals.

The contracts were awarded to Galfar Engineering and Contracting (WLL – Emirates) and Robt Stone (Middle East LLC). Over 70% of the combined award value will flow back into the United Arab Emirates’ (UAE) economy under ADNOC’s In-Country Value (ICV) program, reinforcing ADNOC’s commitment to maximizing value for the nation.

Yaser Saeed Almazrouei, Executive Director of ADNOC’s Upstream Directorate, said: “These awards further highlight ADNOC’s drive to invest responsibly to unlock greater value from our assets and resources and build long-term resilience as we deliver our 2030 strategy. The contracts follow a competitive tender process that ensures that substantial value will flow back into the UAE through our ICV program, reinforcing ADNOC’s commitment to supporting local business and stimulating the growth and diversification of the nation’s economy.”

As part of the selection criteria for the awards, ADNOC carefully considered the extent to which bidders would maximize ICV in the delivery of the project. This is a mechanism integrated into ADNOC’s tender evaluation process, aimed at nurturing new local and international partnerships and business opportunities, fostering socio-economic growth, and creating job opportunities for UAE nationals. The successful bids by the two contractors prioritized UAE sources for materials, local suppliers, and workforce.

Omar Obaid Al Nasri, CEO of ADNOC Onshore, said: “These contracts build on the momentum of our recent awards for upgrades on the Jebel Dhanna terminal and underline our commitment to unlocking the full potential of our assets

and fields to deliver increased value for our shareholders and contribute to ADNOC’s objective to create a more profitable upstream business. The award for flowlines and wellhead installations will help sustain long-term production at our Bab, Asab, and Sahil fields while the award for the bypass system will provide critical backup for the existing crude receiving station connecting our fields and export terminals, to ensure business continuity and resilience.”

The two PC contracts awarded for flowlines and wellheads are split into two parts. The first contract, valued at approximately $71 million (AED 261.2 million), is awarded to Galfar Engineering & Contracting (WLL Emirates). The contractor will procure and construct flowlines and wellhead installations for the ADNOC Onshore Asab and Sahil fields.

The second contract, valued at approximately $168 million (AED 618.2 million), is awarded to Robt Stone (Middle East LLC). The contractor will procure and construct flowlines and wellhead installations for the ADNOC Onshore Bab field.

The scope of work includes residual engineering, procurement, construction, precommissioning, and commissioning of natural oil producer wells and water injection wells at the respective fields. Both contracts are expected to be completed in five years.

The third contract, the EPC awarded to Galfar Engineering and Contracting (WLL – Emirates), is valued at approximately $84 million (AED 309.1 million). It will create a new bypass system to provide critical backup for ADNOC Onshore’s existing crude receiving stations at the Jebel Dhanna and Fujairah export terminals. The project is expected to be completed in 30 months.

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Cyberhawk awarded fiveyear agreement with major LNG producer in the Middle East

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yberhawk has secured a five-year contract with a global LNG producer for the provision of drone inspection, surveying and data visualization services. The contract will see Cyberhawk focus on collecting engineering-grade inspection data from oil and gas assets in the Middle East, onshore and offshore, which will be delivered as detailed inspection reports via Cyberhawk’s drone data visualization software, iHawk.

Established in 2014, iHawk allows asset teams to view up-todate, visual data securely in the cloud. The software improves asset management and decision-making by allowing managers to intuitively access inspection data that highlights where they can monitor defects and degradation, before deciding what action should be taken and when.

The contract with the state-owned oil and gas company was secured by Manweir, Cyberhawk’s local partner, which is working closely with the technology firm to build a strong regional presence and establish in country value for local operators. The agreement allows any local energy operator to enlist Cyberhawk’s technology solutions through this contract, making it the preferred drone inspection and visualization partner in key oil producing countries within the Middle East region.

“This agreement is testament to the high standard of work that Cyberhawk has been delivering in the Middle East region for the past 10 years,” Chris Fleming, CEO at Cyberhawk said.

“By working closely with the client and local authorities, we were able to obtain the Minister of Interiors permit to fly in-country. Our aviation and oil and gas pedigree were an integral part of the selection process and we are extremely proud our track record has been recognised.

“We want to show our client and key regions in the Middle East how drone and visual data technologies can be leveraged to perform remote inspections and digitize assets. This is an extremely exciting partnership, where knowledge will be shared to benefit the local economy and businesses and allow oil and gas producers to thrive in the new digital era.”

Update

FutureOn advances next generation of digital twin solutions for oil and gas

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utureOn has secured an investment from the Bentley Acceleration Fund and established a strategic partnership with US-based Bentley Systems to accelerate the digitalization of the oil and gas industry.

FutureOn and Bentley Systems will combine FutureOn’s award-winning field design application (FieldAP) and its API-centric collaboration platform (FieldTwin) with Bentley’s iTwin platform to provide customers a nextgeneration digital twin solution capable of driving design methodologies in upstream project development for the next decade. Both FutureOn and Bentley platforms use open web standards to facilitate complex integration and customization, and the combined offerings are already being implemented in exploration and production workflows.

“This is a significant milestone for FutureOn which will greatly drive the growth of our business by extending its reach,” FutureOn CEO Paal Roppen, said. “Also, while we will work closely with Bentley we will maintain our neutrality as an independent software vendor with a clear mandate to provide our customers a fully open and standards-driven digital platform. This flexibility supports our customers’ desire for remote collaborative decision making at a critical

time for the oil and gas industry.”

FutureOn emerged from the highly respected 3D visualization agency Xvision with over 20 years of visual engineering experience specifically in the oil and gas subsea domain. In 2019 FutureOn’s FieldAP received the OTC Spotlight on New Technology Award for best software innovation in the oil and gas industry. Most recently, the company has launched the cloud-based data platform FieldTwin, which offers centralized API integrations to many of the leading engineering simulation and data analysis tools. When combined with FieldTwin, FieldAP enables cross-discipline remote collaboration for design and development of subsea digital twins.

“FutureOn has grown quickly and taken an industry-leading position in very short time thanks to bold moves like this,” Roppen added. “Today, digitalization is more important than ever for the oil and gas industry as challenging market conditions persist. Innovative and disruptive technologies such as those we develop alongside Bentley will fill an emerging void.”

Ken Adamson, Bentley vice president, design integration added that the company are excited for this new opportunity to collaborate with FutureOn to provide advanced digital twin technology for the oil and gas industry, and especially for the addition of subsea expertise. “Combining our design, modelling, and analysis experience with FutureOn’s data management and visualization acumen to help build subsea digital twins will enable our users to further enhance their engineering performance, operations and profitability,” he said.

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A net-zero emissions energy business Speaking at Shell’s Responsible Investor Day event, which was conducted as a virtual webcast because of the COVID-19 pandemic, Ben van Beurden, CEO of Shell, spoke about Shell’s new ambition to be a net-zero emissions energy business by 2050.

He sets out the three elements that can, together, combine to allow Shell to achieve that ambition, covering emissions across scopes one, two and three.

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hell has three strategic ambitions - to be a world-class investment case, to thrive in the energy transition to a lower-carbon future and to maintain a strong societal licence to operate. All of them are of equal importance to the future of Shell.

“Being a world-class investment case means being financially robust and resilient,” van Beurden, SAYS. “The importance of that resilience has never been clearer than today, with the twin challenges of COVID-19 and the current exceptionally low oil price putting pressure on even the strongest balance sheets.

“And you can be reassured that we continue to focus tightly on that resilience and financial strength, pulling the levers we need to pull, as hard as necessary, and at the times that it is necessary to pull them. You will have noticed the action we have taken already.”

“That resilience is critical because it is the solid foundation on which we can build. And we wish to build a company that will thrive in the energy transition. This strategic ambition is all about remaining relevant and resilient in a changing global energy system. It is about finding the business value in the energy transition. It is about being a world-class investment case, far into the future.

And our third strategic ambition is maintaining a strong societal licence to operate. Having the support of society for what we do is essential. Without it we cannot be a world class investment case. Without it we will not be able to thrive in the energy transition.

To have the support of society, we must be in step with that society. Being in step with society requires action in many areas. From safety to ethics and compliance. From responsible supply chains to respecting indigenous communities. From transparency to taxes. Shell is active in all those areas.

But it is undoubtedly the case that the biggest long-term question for an oil and gas business like Shell, is the question raised by climate change.”

Society It was only five years ago, in Paris, that the world was focused on an ambition to restrict the global average temperature increase to well-below 2° Celsius. And Shell produced a scenario detailing how the world could achieve that ambition. That scenario, called Sky, laid out a set of measures which would transform the energy system and restrict the temperature increase to around 1.75° Celsius or even 1.5° Celsius with major reforestation. It was a challenging set of

20

measures, but technically possible. However, in those five short years, society has raised its expectations further.

Today, in many parts of the world, the goal is now the tougher Paris aim of no more than 1.5° Celsius. Shell has been listening and has taken a deeper look at the actions that the world could take to achieve such a goal. These actions are, inevitably, more challenging: the time available has shortened, the scale of action needed is even larger and the extent of the global collaboration required is certainly unprecedented.

“But this pathway to 1.5° Celsius is still, just about, technically and economically possible,” van Beurden adds. “Our scenario modelling shows this global pathway to 1.5° Celsius requires the whole of society to have achieved net-zero emissions by around 2060.

“That is not the same as saying that all parts of society have that much time. Those wealthier, more developed countries and regions that can move faster, must move faster. If they do not, then those countries and regions which cannot move so quickly will not have the time they need. The European Union, for example, should achieve net-zero emissions by no later than 2050 if the world is to succeed in restricting warming to 1.5° Celsius. That is, indeed, the EU’s aim. And Shell has built a specific scenario looking at what Europe might need to do to decarbonise energy in the next 30 years.”

The EU scenario identified nine areas for action. Each of them – each of the nine – comes with challenges and opportunities.

“These are the same areas that every part of the world must act in, even if the figures I will give are specific to the EU alone,” van Beurden continues. “The tasks for the EU, all

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“But this pathway to 1.5° Celsius is still, just about, technically and economically possible”

happening at the same time, start with a doubling of the use of electricity. Second, ensure that renewables like wind and solar produce around three-quarters of that power and that burning coal produces none of it. Third, an effective economy-wide carbon price rising to more than 200 euros per tonne in 2050.

“Next, the EU needs to improve its energy efficiency by 45 per cent compared to today. The fifth step is to ensure hydrogen is well used as a fuel for heating and for heavy duty transport, reaching around ten per cent of energy use. And sixth, triple the use of biofuels.

“Seventh is to bring about significant change in consumer and business choices. For example, a clear shift away from short-haul flights and road freight towards rail. Eighth: clean up emissions

BEN VAN BEURDEN

CEO OF SHELL 21

In their words

at source from industry by building an average of two CCUS facilities a month between 2025 and 2050, to capture and store away carbon dioxide. Each of these would need to be as large as the Shell operated Quest facility in Canada which captures and stores away more than a million tonnes of CO2 each year.

“And the final measure: to deal with the 300 million tonnes of CO2 emissions that remain, even after taking all the action I have already mentioned. To do that, the EU could reforest an area of around 85,000 square miles, or 220,000 square kilometres. That is a landmass about the size of Great Britain.

“Obviously, if less action is taken in one area it means more in another. So, only one carbon capture facility a month instead of two over 25 years would, for example, translate into the need for another forest the size of Great Britain. No carbon capture facilities would translate to forests covering the equivalent of the whole of Germany and Italy or almost all of Texas.

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“And, just to be clear, all that action is to decarbonise energy.

Agriculture needs further action. Emissions caused by industries like cement need further action again. So, I hope you can easily see that the scale of action required of society, if it is to restrict global warming to under 1.5° Celsius, is huge.”

Low-carbon According to van Beurden, Shell intends to lead and thrive through this transition to a low-carbon energy future. Shell’s new ambition, is to be a net-zero emissions energy business by 2050, and sooner if that is possible. “Global society, overall, may have until around 2060 to reach net-zero emissions, but Shell recognises that it stands within a section of society that

In their words

needs to move faster,” van Beurden continues. “That is a huge task, a task at least as big as that faced by wider society. And we will work towards it, work towards netzero emissions.

“The first step is to significantly raise the level of ambition we stated two-and-a-half years ago.

At the end of 2017, our Net Carbon Footprint ambition was designed to be in step with a society heading to a world of well-below 2° Celsius. It meant Shell selling more and more products with a lower carbon intensity, such as renewable power, biofuels, and hydrogen. It also meant finding ways to deal with emissions that could not be

avoided, through nature or technology.

“In short, our 2017 ambition meant seeking to radically transform Shell to establish new business opportunities. It meant finding new ways of running a financially sustainable business. Our new ambition still means all of this. But it means moving much faster. Because we have now re-calibrated our Net Carbon Footprint ambition so that it is in step with the large sections of society that want to achieve a 1.5° Celsius future.

“So, from today, Shell’s medium-term ambition is to reduce the Net Carbon Footprint of our energy products by 30 per cent by 2035, instead of 20 per cent. And this means our long-term ambition is now to reduce the Net Carbon Footprint of our energy products by 65 per cent by 2050, instead of 50 per cent.

“I also want to be clear. This ambition is about emitting fewer greenhouse gases on average with each unit of energy we sell. We calculate the emissions created during the lifecycle of our energy products, then we subtract the effect of actions we, as Shell, take to mitigate those emissions, whether through nature to capture CO2 from the atmosphere, or technology to capture and store it away, and that gives us the net emissions associated with our energy products.

We then divide that emissions figure by the amount of energy, in megajoules, contained in the products that we sell.

“But our original ambition did not include the emissions from the production of our non-energy products, like chemicals and lubricants. These were excluded at the time because they are not burned when consumed. But being a net-zero emissions energy business means addressing all emissions from our operations.”

Van Beurden is clear that words are cheap and that over the coming years Shell will be judged on actions and results. “Of course, it is easy to state an ambition, it is much harder to achieve it,” he adds. “We are talking about a fundamental shift for Shell over the next 30 years. And we will be giving you a strategy update in the second half of the year on some first steps.

“But I can say this, for certain that to achieve our ambition, Shell must pivot towards serving the businesses and sectors that, by 2050, are net-zero emissions themselves. It must pivot to serve the businesses and customers of the future, to make Shell a business of the future. Because a society that succeeds in being net zero emissions by 2050 is a society in which there will be no business that is not net zero.

“This is going to take a lot of work. It will not be easy. Some of the necessary technologies – like hydrogen-powered planes, or zero-emissions ships – do not exist yet. And, today, Shell’s business plans will not get us to where we want to be. That means our business plans will have to change over time as society and our customers also will have to change overtime. Ultimately, succeeding in our ambition will mean that, by 2050, all Shell’s own operations and the customers we serve will, in combination, be net-zero emissions. This would be in line with society’s ambition to achieve a 1.5oC outcome, it would be in step with society, and it would be in line with our own strategic ambitions.

Being in step with society is key. It is key to maintaining a strong societal licence to operate.

“If Shell can succeed in its ambition, if we can succeed in becoming a net-zero emissions energy business by 2050, we will truly have succeeded in being an integral part of that net-zero world.

There is no more ambition that we can have than this, to be a core part of the future, a future that society wants and a future that society needs. And that is what being a net-zero emissions energy business means to Shell. That is what Shell now intends to do.”

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Change Management

How technology supports the move to integrated energy

As COVID-19 continues to impact global economies, some industries are evolving to identify how to protect or change their business models to suit whatever the future might hold.

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n the energy industry, the oil and gas sector has seen several quarters of significant change and uncertainty. More broadly, the industry was already mulling a change in operations as it strives to achieve targets for carbon emissions. It is arguable that COVID-19 has just accelerated that change.

For example, BP recently announced a move to become an integrated energy company, stating: “We aim to be a very different kind of energy company by 2030 as we scale up investment in low-carbon, focus our oil and gas production and make headway on reducing emissions. Our new strategy kickstarts a decade of delivery towards our bpNetZero ambition.”

“But as more oil and gas businesses increase their spending on renewables to adopt a similar approach, they continue to face operational challenges to general business activities before considering executing such a change,” Geoff Roberts, director of energy industry strategy, Oracle Construction and Engineering, explains. “These include the need for a change

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management plan as well as management across and between diverse business units, how to find efficiency gains, mitigating risks such as working with new and untested suppliers as well as safety and the increasing importance of data and analytics.”

Change initiatives are further complicated by the impact of the recent pandemic and oil price fluctuations on the supply chain. In April 2020, following a significant drop in the oil price, these concerns were raised by key industry bodies such as the International Energy Agency and Independent Project Analysis, who expressed concerns about how, as demand plummets, the entire supply chain of oil refining, freight, and storage is starting to seize up, making it increasingly difficult

Change management

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“With sensors attached to the workers, it is also possible to emit a progressively louder alarm as a reminder whenever workers are too close to each other,”

Bringing it together

to push new supply into the system―and how project delays are already going to make some suppliers and vendors vulnerable.

“The energy supply chain is shifting from a simple, tried and tested model to a complex and widespread movement of multiple parts,” Roberts explains. “The diversification of the oil and gas business to include a focus on renewables is playing a part in this change. If suppliers struggle in the market, oil and gas businesses have fewer options in supplier selection.

Broadening their business approach into a new area such as renewables adds to this supplier uncertainty.

“Such challenges argue for an acceleration of digital transformation to support a business as it moves through these changes and prepares for the next phase of operations.

Current trends can serve as a long overdue impetus for the industry to evolve its approach and embrace technology.

Advancements such as RFID tagging for material tracking, IoT and artificial intelligence (AI) also provide new opportunities to disrupt traditional approaches and enhance safety and productivity.”

For oil and gas businesses, diversifying into renewables brings several change management challenges, with the challenges perhaps exacerbated by the recent need to work remotely.

Organisations are coping with uncertainty caused by dramatic oil price fluctuations, the rush to survive due to the pandemic, and the need for remote access and visibility across the project portfolio and supply chain. All these underscores the need for new, more effective ways of working. Capital project delivery technology may hold the answer.

“Collaboration in the form of coordinated work using shared project information is key to connect different teams from engineering, operations, procurement through to contractors and suppliers,” Roberts continues. “The most efficient way to enable collaboration is a single, easily accessible platform for all interactions. Such technology improves coordination, communication and, importantly, document control processes with the supply chain as well as between internal teams.

“Amid the shift to renewables, should oil and gas businesses start working with suppliers with whom they have had little experience, this level of project control becomes even more important. Each team should have visibility into changes in the business and how they impact the different players. That means being able to manage information centrally and share appropriately, helping ensure there is clarity and certainty about where each activity is in terms of the project lifecycle.

“Further, with such a diversification of the business, a balanced portfolio is critical. The move to renewables, as well as shrinking budgets and growing risk aversion, means oil and gas companies will manage a larger number of smaller projects.”

To effectively manage growing portfolios, energy organisations need project management solutions that are flexible, mobile, and user-friendly, providing critical collaboration and visibility - and helping to streamline and automate processes. Most transformation journeys require additional controls, and that is what a capital project delivery solution provides.

In terms of capital project efficiency, it is important to have cost and change controls in place in an integrated project controls environment. Again, this is particularly important when there is uncertainty, such as the potential need to change suppliers when shifting to a renewablesbased approach. Eliminating disjointed workflow approaches, such as those associated with spreadsheets or manual data input, in favour of digital workflows further drives efficiency gains.

Risk mitigation, site safety and data analytics Diversifying from oil and gas to encompass renewables will take businesses in directions they may not have been before and will add to the number of capital projects they need to address.

Current restrictions around physical distancing drive a need for both resource optimisation and management at jobsites.

“Preparation for this needs to be in place early, so having an enterprise view on resourcing labour, materials and machinery not only brings efficiencies but also supports planning that minimises the number of workers needing to be on site at any one time. So how does technology support this?

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Change management

Remote visual monitoring of construction sites Roberts explains that in lieu of on-site inspections, project teams have the opportunity to embrace a variety of remote visual tools, including drones, laser scanning, light detection and ranging technology (LiDAR), to remotely monitor the progress, quality, safety and security of their projects. “These technologies both reduce the need for workers to come onsite and enable project teams to revise contractors’ work sequences to physically separate otherwise risky work interactions.

“Site cameras can provide real-time monitoring and security, with fixed cameras increasingly leveraged to enhance remote collaboration between stakeholders while also capturing images and time-lapse videos for regular status updates integrated to scheduling and other project management solutions.”

Physical distancing on construction sites Using AI, site images can be analysed and tagged to identify various indicators of project risk related to safety, productivity, and quality. This technology can identify people working in a group and indicate when individuals may be too close to one another.

“With sensors attached to the workers, it is also possible to emit a progressively louder alarm as a reminder whenever workers are too close to each other,” Roberts concludes. “If there is a confirmed case of COVID-19 on a worksite, an employer can use contact tracing through information captured passively by the worker’s device to gauge who may have been exposed.”

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“Data continues to fascinate the industry. It is challenging to understand how the industry managed without what we now think of as ‘big data,’ particularly considering the level of control, transparency, threat awareness, and accountability it provides.

“Today, the industry appears data hungry with companies keen to know what AI or machine learning (ML) can do for them. For many oil and gas businesses, the data journey has already begun. To see the value in a data approach, they need to explore what data they have across their projects already.

They also need to understand what they need data to tell them, and that requires creating a data strategy.

“Before it considers AI and ML, a business should ask itself whether it can even use the data it currently has. If not, it is just adding to the complex pool of information that it already possesses. Either way, the key is to start from within, see what you have, and grow your data approach from there. As with any large, complex undertaking, your data strategy needs a solid starting point. The insights will follow.”

Digitisation

The new normal is digital 2020 has shown that digitalising the O&G industry is no more a matter of choice, it has become an urge to maintain stable operations while working remotely. That said, operators now have the chance to drive it efficiently and get the maximum value that digital solutions can offer.

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t beginning of 2020, most industrial players knew that digitalisation would impact business sometime down the line. They had been presented with these futurist scenarios of end-to-end interconnectedness and complete insight, and yet they had heard of many digitalization projects that failed.

Then a pandemic hit, and despite the challenges, new ways of working have been proven possible. The world was forced to stay at home and conduct their work remotely. People’s everyday lives were flipped upside down, and workers needed to find and learn how to use the solutions that allowed them to do their work efficiently, maintaining stable and safe operations, while interacting with people and the digital world.

For operators who were one step ahead in digitalization, COVID-19 was a catalyst to accelerate the adoption and integration of technologies into their day to day workflow as they experienced the benefits directly. Other operators admit they would have been better equipped to handle their operations if they had been more digitally mature.

In that sense, 2020 has shown the global O&G industry that the time is ripe to start digitalizing.

Digitalisation in Oil & Gas The time to digitalise has come, but what is still preventing the operators from achieving successful digital transformations? Are energy companies working towards digitalisation for their assets? Probably, yes. However, it has not been done most smartly and efficiently so far.

In its survey from 2017, McKinsey asked the industry how effective they are on delivering value due to data challenges. Only seven per cent of organizations said they are highly effective at reaching their primary objectives on data and analytics, and a staggering 48 per cent of respondents said they are neutral or effective.

The case is that energy companies struggle to implement technologies and obtain substantial value due to different challenges. The main pain points include low adoption, non-user-friendly solutions, the disconnection between the technology and business case, long time to capture initial results, and overly large technology programs.

Among the major trends perceived in the industry are the use of digital solutions to enable automation, democratise the data access and enable decision-making. The market indicates that companies will start looking for real bottom-line impact and agile transformations. Concerns on decarbonisation,

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sustainability and cyber-security are becoming crucial as well.

Digital solutions have already yielded opportunities at all levels in the oil and gas industry, notable in the offshore operations where cost is higher. The collection, contextualisation and sharing of data in common user systems do not only enable the companies to break down the traditional silos between different expert groups. As more data are shared and technologies like AI are used, it is possible to unlock new value with large, contextualised datasets, giving teams an improved foundation for decision-making in real-time and a spur for innovating for even more value.

Digital Twin as a digitalisation enabler The path that the industry is taking to boost digital transformation and unlock data value is the form of the digital twin. The term digital twin itself requires some form of elucidation as it is a term that it is over utilised by many vendors for any form of digital visualisation.

Across the vendor and operator landscape, many use the term purely as information repositories.

This often involves a 3D or 2D representation of the facility with corresponding documentation that is fed with data from the IT platform. But it is still a static representation of the facility, a

Digitisation

ability to adapt has showcased to be key, especially in challenging times.

Digitalisation is accelerating in oil and gas and much of the sector is unlikely to revert to legacy working practices. The new normal is digital.

Is your company ready to be part of it?

Kognitwin energy – the dynamic digital twin for Energy sector by Kongsberg Digital Cutting edge technology combined with scalable solutions, Kongsberg Digital can deploy Kognitwin in your asset in the matter of a few weeks.

This means your organisation will start benefiting from Kognitwin enabled digitalisation within weeks rather than years.

Beyond being a virtual replica of your industrial facility, Kognitwin Energy delivers a rich framework for advanced digitalisation and analytics, including a range of applications that can be customised to attend your needs. In August 2020, after many months competitive tender process Shell Global selected Kognitwin delivered by Kongsberg Digital for its global portfolio of assets and capital projects within the Anglo-Dutch energy and petrochemical company’s upstream, integrated gas, and downstream manufacturing business lines.

snapshot in time.

Static visualisations are helpful but insufficient.

The digital twin of an asset can be empowered offering more functionalities. Enabling full virtualisation and describing the current behaviour of the asset the twin becomes alive. In other words, an advanced digital twin besides being a copy of a physical facility, integrates and converge IT and OT, describes the real-time situation and, through Artificial Intelligence, predicts how the facility will behave over time.

Oil and gas operators can take advantage of digital twins to democratize information and knowledge across the assets. Through a scalable and cloud-based solution, data from different facilities around the globe are connected and can be accessed from anywhere and from different teams. Therefore, the twin enables enhanced collaboration and performance, safer operations, and more efficient working.

The path forward Oil and gas operators must digitalise smartly and efficiently. Tools need to be connected to the business strategy and business value. To create effective digital transformation and unlock real value, energy companies must select the right partners to help them at this journey. Agility and

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Subsea

Reinventing the familiar for superior subsea production In 2017, the Brazil National Petroleum Agency (ANP) issued a failure mode alert: stress corrosion cracking (SCC-CO2) triggered by the presence of CO2 in high pressure pre-salt conditions had been identified as the cause of broken tensile armor wires on a certain flexible pipe installation. Relatively common in other applications where carbon steel is subject to high CO2 concentrations, this failure mode was unknown in flexible pipe – and it presented a major challenge for operators in Brazil’s extensive pre-salt fields.

F

lexible pipes have played an important role in Brazil’s history of oil production. No other oil province in the world has applied flexible pipes so intensively as the Campos Basin, for example, where approximately 2,223 km of risers and flowlines have been installed to connect giant fields including Marlim, Albacora and Roncador, in water depths that range from 1,500m to 2,000m.

It’s no exaggeration to say that flexible piping has been crucial to the development of Campos and other basins as viable production sites.

Flexible advantages Of course, flexible piping is not exclusive to Brazil.

Its widespread deployment is down to the many advantages it offers to so many operators. With concentric and unbonded layers, each of which contributes to the mechanical strength and chemical resistance needed to withstand deepwater conditions, flexible pipes were designed to ensure collapse resistance, internal pressure capacity, bending stiffness and axial-load capacity – among numerous other advantages to deepwater operations.

In addition, this unique design gave operators several logistical advantages. Flexible pipes can

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Subsea

be transported on smaller, nimbler and more cost-effective vessels. Manufacture does not require quality-sensitive offshore processes such as welding or field-joint coatings – both of which have, historically, raised concerns about operational integrity.

As the name suggests, they also give operators the luxury of flexibility and enable them to make subtle but important changes at later stages of a project, without incurring severe cost penalties.

Once in production, flexible piping gave operators the option of moving subsea lines and repositioning pipes in response to production needs, or to postpone the exact location of productionwell placement decision. As operators started production and built knowledge of reservoir behavior, that flexibility allowed them to optimize both output and field life.

That ability to be easily recovered, inspected, repaired, re-laid and connected at new sites was key: flexibles proved themselves to be the best way of reducing time to first oil by enabling feasible production in short timeframes, even before reservoir de-limitation and subsea layout consolidation. They reduced the risks of drilling campaigns and delivered associated advantages in

terms of time and cost.

The ANP’s announcement about SCC-CO2 in 2017 therefore had implications for the entire industry.

Addressing SCC-CO2 One short-term option was for operators to reduce their perceived risks by moving away from flexible pipe solutions and adopting rigid pipes instead.

But by doing so, all the flexibility that had allowed Brazil to develop offshore fields efficiently would be lost.

Operational complexity, such as the water depth, bore size, temperatures, pressures and contaminants found in the Santos Basin, requires constant review and development of the technology – in this case, the optimization of subsea hardware, as well as installation and operational procedures.

For this reason, Baker Hughes directed its considerable research and development efforts to the exploration of alternative mitigation measures for its clients in Brazil. In the aftermath of the problem identified in 2017, and while not experienced on its own manufactured pipes, Baker Hughes began work on an extensive program to improve the resilience of the installed fleet and to deliver the next generation of SCC-CO2-resistant pipes.

for six months to simulate severe environmental conditions. When Baker Hughes ran these kinds of tests, wires were exposed to various combinations of contaminants while loaded at stresses close to the yield point.

Understanding the problem

Collaboration and composites

As the ANP report noted, SCC-CO2 is a condition that can induce cracking and even failure in a pipe’s steel wires. However, three conditions need to be present simultaneously for such cracking to take place: environment (water and concentrated CO2); high tensile stress exceeding a critical level; and very high-strength materials that are consequently crack-susceptible. If one of these three elements are designed out, cracking cannot happen. Since environmental conditions and high levels of tensile stress were unavoidable, the improvement had to come from the materials used in pipe manufacture.

Also, critical to developing an improved pipe solution is the knowledge that the SCC-CO2 phenomenon is defined by two stages – nucleation and propagation – and that managing them requires different, but complementary approaches.

In the case of propagation of an existing crack, fracture mechanics can be used to define the remaining life of the asset and mitigation work needed. However, a completely different approach is needed when considering the susceptibility of a pipe to crack nucleation.

In this case, multiple small-scale tests using armor wires taken from commercial products can be run

The lab results showed that it is feasible to design and manufacture a flexible pipe to operate in a SCC-CO2 envelope without incurring any damage.

In fact, the tests showed that, in pipes proposed, designed and developed by Baker Hughes, the initiation of cracking would only occur if the loading on the wires and associated stress was raised to double that experienced in the field.

With the results of extensive testing and labwork as a foundation, Baker Hughes began to develop solutions for its customers. One of the most important steps was to build alliances and partnerships with key material suppliers, test houses, installers and external experts such as the National Composite Centre (NCC) in the UK. This has brought experiences, insights and lessons from other industries to the manufacturing of flexible pipe, adding robustness to the qualification and validation programs.

The outcomes of this work are a new hybrid composite material for pipe manufacturing. The new material offers superior gas permeation performance, but without the traditional metallic layer that is most susceptible to CO2 damage.

Not only does the composite pipe reduce the

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Subsea

concentration of CO2 at the tensile armors, and is not susceptible to SCC-CO2, it is also lighter than standard flexible piping. This reduces installation costs even further and allows operators to deploy risers in a free-hanging catenary, removing buoyancies, accelerating installation time and improving safety.

Recent pipe designs have also included reinforced outer layers to protect against perforation or damage during installation, while all end-fitting ports and seals can be tested against external pressure to prove their capacity in deep water.

A machined area that allows ultrasonic testing inspection for detecting flooding and a visor rated to 2,500m water depth are added to end fittings.

Sensors and models Recognizing that pipes in service were also a concern for operators, new ways of carrying out

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dissections to define initial cracks (the starting point for fracture mechanics) and calculating the service life of installed fleets was also needed.

This required some means of testing to identify whether a given pipe was flooded or not.

Naturally, this is a key challenge for integrity management teams: the pipes are not designed to have this kind of verification performed once they have been installed and bringing a riser or flowline to the surface for verification is incredibly disruptive.

However, it is an area where sensor technology can deliver exceptional results. Baker Hughes’ proprietary sensor technology is now embedded into current risers for pre-salt and work continues developing methods for retrofitting sensors to installed pipe.

Such a system can detect any ingress of water from

the topside into the riser annulus along its full length. It provides continuous monitoring, rather than one-off inspections, without extra vessels or ROVs. It can also cover up to five separate pipes and monitor all riser sections from the FPSO up to a 3,600m range. A database of Baker Hughes’ SCC-CO2 program outcomes also enables quick identification of products that are not susceptible to this damage mode.

Continuing development A team of engineers is now developing comprehensive sets of modeling tools that will be further calibrated by the test results, as well as undertaking a wide range of manufacturing trials in an automatic fiber-tape placement module.

This work will enable the behavior of any pipe structures to be predicted without repeating full qualification testing.

These kinds of testing campaigns will continue in order to confirm that all variables – and any combination of variables – that may influence or trigger the SCC-CO2 damage mechanism – are fully explored, mapped and documented to ensure the industry can develop the mitigation strategies for their particular circumstances.

However, the work in Brazil is part of an even bigger picture. The world’s oil and gas sector faces unprecedented challenges to meet social and political demands for greater environmental responsibility and emission reduction in the face of extraordinary price pressures and capital constraints. There is, as a result, no shortage of speculation about what the new normal will look like: from autonomous operations to extremely efficient, carbon neutral developments.

What is perhaps less widely discussed is the idea that ‘normal’ of any kind will be an increasingly rare phenomenon within the oil and gas sector – or indeed within any industrial sector. Constant innovation, continual development, permanent evolution and a relentless re-assessment of what works and what can be done better, will be the defining features of successful operators and their service companies. Whether it’s the use of advanced sensors, data and analytics, or the modification of manufacturing materials, almost every aspect of the business is open to re-evaluation.

The reality is composite flexibles combined with advanced sensors and conventional pipe design and manufacturing offer a viable way to continue to use flexible pipes in pre salt without concern for SCC-CO2.

Regional report: Russia

From Russia with love The petroleum industry in Russia is one of the largest in the world.

Russia has the largest reserves and is the largest exporter of natural gas and the eighth largest oil reserves and is one of the largest producers of oil. Oil & gas Technology spoke to Ekaterina Rodina, Oil & Gas Analyst at VTB Capital, about Russia’s role in the petroleum economy.

For those who are not familiar can you outline the oil and gas landscape in Russia?

In 2019, Russia (under the OPEC+ crude oil production limitation agreement) produced 11.2mnb/d of liquids (crude oil and gas condensate), roughly half of which was exported. The rest was refined domestically into the oil products, 53 per cent of which was then exported as well. There are six major integrated oil companies in Russia – Rosneft, Lukoil, Surgutneftegas, Gazprom Neft (96 per cent is owned by Gazprom), Tatneft and Bashneft (69 per cent owned by Rosneft), which all together account for 93 per cent of crude production in the country and 74 per cent of its

refining, on our numbers. Oil as well as oil product prices in Russia are predominantly market-based, i.e. can be derived from the export netbacks. There are some regulations (damper mechanism), though, which prevent any tangible motor fuel prices volatility in retail segment.

In gas, the major gas producer not only in Russia, but also globally is Gazprom (479bcm in 2019), the company also owns some 180 thousand km of gas trunk pipelines domestically and abroad.

Gazprom exported 199bcm of gas to Europe (incl.

Turkey) and 35bcm to the CIS countries in 2019.

Also, in 2019 Gazprom started to sell gas to China, the deliveries, we expect, are to grow gradually

from some 4-5bcm this year to 38bcm (which is a contracted annual amount) by 2025. Gazprom has the monopoly on dry gas export from the country.

So-called independent gas producers, e.g. Novatek (c.60bcm of annual dry has production accounting for JVs) and Rosneft (c.55bcm) can export LNG (there are some additional requirements, though).

Novatek is the largest LNG producer in the country (c.19mnt will be produces at Yamal LNG this year, we estimate). The company is in the process of construction of the second LNG plant – Arctic LNG 2 (19.8mnt of nameplate capacity), which is to be launched by lines in 2023-26 as per the company.

Sakhalin Energy (JV of Gazprom, 50 per cent, Shell,

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Regional report: Russia

27.5 per cent, Mitsui, 12.5 per cent and Mitsubishi, 10 per cent) operates another 11mnt LNG plant at Sakhalin island in the Russia’s Far East. Domestic gas prices are regulated (based on the ‘inflation-minus’ approach).

Up until 2019, both, oil and gas sectors’ taxation was revenue-based (the exception are motor fuel excises, which are set in RUB per ton). There were two main taxes – export duties (for oil, different for all the oil products and gas) as well as MET (mineral extraction tax for oil, gas and gas condensate). In 2019, ED and MET for oil together stood at USD 40.2/bbl or 63 per cent of the average oil price for the year. However, there are numerous tax-breaks, which are provided to the oil companies by the state (foe hard-to-recover oils or for the norther territories etc), which contributed a lot to the Russian oils profitability. We estimate that the tax-breaks alone accounted for 78 per cent of the net income and 84 per cent of the FCF of mentioned above six integrated oils last year. This means that taxes is one of the most important parameters to look at when you analyse the sector profitability and the position of the Russian oils at the global cost curve (just to give you an indication, we estimate, that Russian oils are breakeven at some USD 15-17/bbl before taxes).

Starting from 2019 EPT (excess profit tax) was introduced in the pilot mode for a certain number of fields. Some major regulatory change is to be implemented in 2021 with more fields to be moved to the EPT regulations (from the revenue-based taxation) and selected tax-breaks (e.g. for high-viscous oils) to be cancelled.

As a nation does Russia view its oil and gas resources as crucial for its home consumption or a vital export medium?

The majority of Russian hydrocarbons that are produced are exported, so this is a significant source for the oil and gas companies’ financials and the Federal budget income (c.41 per cent in 2019). Of course, energy independence and the ability to provide the country with the energy for development, like motor fuels and gas (in the case of gas, tariffs are regulated, so quite predictable) is also an important factor for Russia. However, the gradual decrease from the dependence on oil and gas as the sources for budget financing is one of the targets announced by the government.

Where are the hot spots in Russia oil and gas?

There have not been that many big discoveries in Russia lately. Therefore, Western Siberia remains the most important region accounting for some 65 per cent of oil and most of the gas production and more than half of hydrocarbon reserves. The Ministry of Natural Resources sees quite a big potential in the Arctic zone estimating oil and gas resources there at 7.3bnt (50bn bbls) and 50 tn cubic meters, respectively. However, so far the region is responsible for around 12 per cent of oil production in Russia.

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How has the current pandemic affected the sector in Russia?

Russian oil companies faced similar problems to those of global majors as a result of pandemic – a fall in oil and oil product prices hit the financial performance, while lower demand as a result of lockdowns also had an impact on operations. Although in general the profitability of the Russian oil and gas companies was affected less compared to the global oil majors due to the tax system set-up with a drop in the oil and gas prices leading to the ED and MET fall, so the state partly shared this with the companies. Also, the negative global developments were partly offset by the local currency weakening as export is a big part of the sectors’ operations, while the majority of costs are RUB-denominated.

What are the technology advances that are having the biggest impact in the region?

Most of the Russian oil and gas reserves are conventional, so historical relatively simple production methods have been used with vertical and inclined well established.

However, all the key crude and gas production techniques such as horizontal wells, hydrofracking, sidetracking etc. are now being implemented in Russia. All of these emerging production techniques are going to be implemented more and more, we are saw the share of horizontal drilling in Russia (compared to straight-forward vertical or inclined wells) grow to 50 per cent in 2019 which was a rise from 33 per cent in 2015, for example. The number of hydrofracks will increase along with the production complexity growth given the gradual

Regional report: Russia

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“There have not been that many big discoveries in Russia lately. Therefore, Western Siberia remains the most important region accounting for some 65 per cent of oil and most of the gas production and more than half of hydrocarbon reserves.”

depletion of the reserve base. However, we believe that the global focus of the oil and gas companies on the digitalization through the use of technologies such as Big Data and AI will also be an important development trend to watch in the industry in Russia.

What sort of investment or collaboration is Russia seeking?

Russia, I believe, is open to any sort of cooperation with the international peers – companies participate in the following: Joint exploratory projects e.g. Equinor continues its works at North-Komsomolskotye field in the JV with Rosneft Production e.g. Exxon, Total, CNPC, Sinopec, ONGC, Mitsui and numerous other companies are invested in the Russian oil and gas upstream assets Downstream e.g. Novatek attracted international investors to its Arctic LNG 2 Infrastructure e.g. JBIC is considering investments in the storage and transshipment facilities at Kamchatka together with Russian RDIF Which western companies have had the best success in working in Russia?

French Total cooperates quite successfully with Novatek owning almost 19 per cent of the

Russian gas company as well as 20 per cent and 10 per cent in Yamal LNG and Arctic LNG 2 projects. There are also three PSAs in Russia – Skhailn Energy (mentioned above), Sakhalin 1 (Exxon, 30 per cent – operator of the project, SODECO, 30 per cent, Rosneft and ONGC by 20 per cent) and Kharyaga (20 per cent owned by Total). Shell also works very successfully with Gazprom Neft in the SPD 50x50 JV. It was founded in 1996.

We think that most of the international companies, which used to operate in the Russian OFS sector (e.g. Weatherford), were quite successful. Unfortunately, quite a large part of operations of the international OFS companies were cancelled after sanction were imposed in 2014.

How do you see the future developing both in the short and long term?

Short-term development trends will, of course, depend on coping with the COVID-19 as it provides a lot of pressure on the immediate oil (i.e. oil products) demand, and also the supply side, i.e. the OPEC+ reaction function, and therefore, the prices. Long-term development is to be defined by the consequences of COVID-19 such as a cut in E&P capex by global oil and gas companies and changes in the demand habits for example people might opt to fly less in the future. Another important thing to consider is the ecology concerns and fight against global warming, which defines the decisions of the oil and gas companies all over the world as well as consumption patterns under the move to carbon-neutrality.

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Completions

Improving sealing capabilities of liner tiebacks to reduce the risk of Sustained Casing Pressure (SCP).

In well completions, the failure of a liner tieback seal is relatively common over the life a well. Reliable solutions such as a Welltec Annular Barrier (WAB) can provide both sealing and anchoring contingency, saving rig time and reducing operational risks.

Sustained Casing Pressure (SCP), also referred to as Sustained Annular Pressure (SAP), affects almost a third of wells globally and is present within multiple annuli. Since 2009, the cost of well integrity to operators has been in excess of $75 billion, which has provided the impetus for the industry to focus on and rework international standards related to the management of oil and gas well integrity.

SCP is defined as measurable pressure at the wellhead that is present in any well annulus, which rebuilds after being bled down, and is not caused solely by temperature fluctuations or artificially applied pressure. SCP can occur due to several reasons, including but not limited

36

to casing leakage, improper mud displacement prior to the primary cementing, influx of gas as the cement transitions to solid, etc. A common cause of SCP is the migration of gas or fluid from a high-pressured subsurface formation through a leaking cement sheath which may have cracked during the life of the well. The cement sheath often forms part of the primary or secondary well barrier and a leak through it could manifest in one or more casing annuli of the well.

SCP compromises the integrity of oil and gas wells posing several risks which are not limited to environmental, safety, operational, contamination of groundwater or major

blowouts. The occurrence of any of these will incur very high remediation costs and significant damage to the reputation of operators. The occurrence of SCP may directly contribute to the release of methane to the atmosphere which is a significant environmental challenge that must be avoided.

Overcoming the challenges Challenges of running production casings are increasing as wells are drilled deeper and with more complex trajectories. To overcome challenges associated with these well geometries, production casings are often installed with a cemented liner and liner tieback

Completions

The failure of the tieback seal is relatively common over the life of the well and on occasion during the completion of the well.

This failure is typically challenging and usually results in an expensive workover operation.

Due to the relatively high failure rate, operators may include a contingency sealing method within the annulus as back-up to the PBR and seal stem. A further alternative is to provide anchoring of the liner tieback string to prevent movement of the seal stem and hence preserve the seal integrity.

Cases from the field

string. A liner tieback may also be utilised to deliver higher performance casing to surface, increased flow capacity, or could be run during a workover program when the integrity of the intermediate casing string is in doubt. When installing a liner tieback, the seal stem at the toe of the liner tieback string is stung (placed) into a Polished Bore Receptacle (PBR) at the top of the liner to achieve pressure isolation from the bore of the liner tieback to the annulus.

The PBR and the seal stem are required to achieve well integrity over the life of the well to prevent fluid or gas leakage into the “B� annulus creating SCP. The liner tieback string will expand or contract in length due to variations in temperature or pressure that may occur over the life of the well. The PBR and seal stem must be able to accommodate the movement of the liner tieback string, whilst maintaining the seal over the life of the well. Due to the downhole conditions and the cyclic movement, the seal tends to degrade, leading to SCP.

Case 1 – A client operating in the Gulf of Mexico was looking for a sealing contingency to the PBR and seal stem for the liner tieback. The operator had previously used swell packers run on the liner tieback string, or cement within the annulus above the PBR and seal stem. A swell packer is an isolation device that relies on engineered compounds to expand and form an annular seal when immersed in certain wellbore fluids. The compound in these packers may swell with either oil, water, or combination of both. Swell packers are typically used for zonal isolation within open hole environments where sealing is neither critical nor required for the life of a well.

Sealing and anchoring However, in relation to this case it is worth noting that the swell packer takes some time to swell, usually 20 to 30 days after the liner tieback string is placed into the PBR. Furthermore, the swell packer is not able to provide the necessary force required to anchor the assembly, which makes the solution incomplete as the movement of the liner tieback string will cause the PBR and seal stem to eventually leak. Also, depending on the downhole conditions, the swell packer may be starved of enough quantities of the specific wellbore fluid required to fully expand.

For a cemented contingency, prior to running the liner tieback string, a plug is set within the top of the cemented liner. The liner tieback string is then run into the well and landed just above the PBR. A cement slurry is then pumped and displaced down the liner tieback string and into the annulus. After the cementing operation is completed, the liner tieback string is placed

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into the PBR with the cement providing an anchoring solution when it cures.

This is usually a high risk and expensive operation because of the several opportunities for failure.

The cement will provide anchoring thereby stopping the movement of the liner tieback string; however, it will not be able to provide the required sealing over the life of the well due to factors such as limited volume, contamination, over displacement etc. Furthermore, as the well goes through temperature and pressure cycles, the casing will expand and contract thereby degrading the cement. The cement provides good anchoring, but it cannot be relied upon for life of well sealing to prevent SCP. Resolving the challenge Best practice would require the contingency swell packer or cement to be pressure tested from below (being the direction of pressure from the bore to the annulus), with a seal and seal bore connected, this is not possible.

Alternatively, a pressure test can be performed by applying pressure to the B annulus from above. However due to the time required for the swell packer to swell, or for the cement to cure, this pressure test is normally not feasible.

To resolve the challenge in this case, the client is considering the use of a Welltec Annular Barrier (WAB) for deployment to anchor the liner tieback string and prevent the seal stem from moving within the PBR. When the liner tieback string is placed into the PBR, pressure is applied from surface to expand the WAB. Even though a WAB can provide the required seal, for this specific application the client only requires the anchoring functionality. A tube run through the WAB connects the annulus above to below the WAB to equalize the pressure thereby eliminating any concerns regarding trapped fluid between the WAB and the PBR. The anchoring capabilities of the WAB in this application will ensure that there

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Completions

will be no movement of the seal stem within the PBR, thereby maintaining sealing integrity over the life of the well with the liner tieback string anchored to the casing above the PBR. Case 2 – Elsewhere, Welltec has successfully deployed a combined sealing and anchoring solution using a WAB for a client operating offshore, East Malaysia. From previous wells, the operator had identified a high risk in relation to the ability to obtain a test at the 9 5/8” liner PBR and stem seal, which

would require the tieback to be pulled and re-run in the event of a leaking system.

Sealing and anchoring This specific operator had previous experience with WAB technology expanded in wet cement in open hole as a secondary means of assuring

the integrity of the well (cement assurance). The operator was aware of its robustness, versatility in the range of hole size coverage, and qualification to ISO 14310 V0. Following productive discussions and a detailed risk assessment exercise, a WAB was successfully applied as contingency in case the PBR and seal stem of the liner tieback leaked over the life of the well. In this case, the full sealing and anchoring capabilities of the WAB solution were utilized, with the product mounted on the 9 5/8” casing located directly above the seal stem of the liner tieback string maintaining a full-bore internal diameter.

When a plan comes together The liner tieback string was run into the well and pressure tested. The prior risk that had been identified of a leaking PBR and seal stem, unfortunately occurred. However, due to the diligence and foresight of the operator, the pre-installed WAB on the 9 5/8” casing was expanded by applying surface pressure in incremental steps up to 4,500 psi. Given that the PBR and seal stem were leaking, the WAB was tested from below i.e. from the direction of exposed well pressure and confirmed to hold the pressure successfully. This enabled the operator to progress with the completion operations without the need to pull the liner tieback string.

The robustness of the WAB, the ease of expansion, reliability, and its ability to seal and anchor saved the operator a significant amount of rig time and reduced operational risks, while providing a life of well solution. This technology has proven to be a reliable solution for future operations where sealing assurance of the liner tieback is required.

The seamless integration of a WAB to a liner tieback string is a welcome addition to the drilling and completions toolbox, improving operational efficiency, and managing the associated risks during the construction of oil and gas wells.

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Managing obsolete equipment in oil and gas Despite innovation in oil and gas technology, some components in the sector have undesirably short life spans. For the oil and gas industry, an unexpected failure is more than a simple business inconvenience.

Here Neil Ballinger, head of EMEA at automation equipment supplier EU Automation, explains the importance of managing obsolescence in oil and gas.

I

t is well known that downtime in oil extraction is amongst the most expensive in any industry, with one hour costing up to $1 million in lost revenue, fines and maintenance activities. What is more, the associated safety, environmental and reputational concerns also add to that cost.

Many oil and gas manufacturers often find the industrial automation equipment they use is no longer made by the original equipment manufacturer (OEM). The fast-paced nature of the automation market means that instead, some OEMs will focus on producing newer models and improved versions, leaving older

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parts to become obsolete.

In fact, the Health and Safety Executive (HSE) has previously said that, “Whilst there is significant investment in new infrastructure, much of the existing infrastructure is ageing and has been exposed to a harsh environment and heavy usage. Approximately 50 per cent of offshore platforms are beyond their original design life. As higher temperature, higher pressure reserves are exploited the challenge to asset integrity increases.�

This means that, when an obsolete part breaks down, these companies only really have two choices: buy a new system or source a spare.

Preparation The first step in managing obsolescence is for organisations to identify the goals of the obsolescence plan, whether it is to save money, improve efficiency or simply to educate the workforce on obsolescence maintenance. Often, a successful plan involves the combination of all three goals.

Oil and gas companies should focus on clearly defining roles, responsibilities, processes and review cycles in an obsolescence management plan. The key to doing so is to have a forward-thinking attitude and anticipate the needs of a system. The aim is to foresee all eventualities and plan for them.

Next, conducting research to determine which parts are most at risk and why they are at risk can help identify a cost and time-effective plan. It can also help steer buying decisions in the long-run.

By investing the time to assess a system and predict which components may become obsolete and need replacing, companies

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will not be struggling for a solution down the line when the problem occurs. This will reduce downtime, save money and uphold reputation.

Lastly, companies should ensure the strategy is implemented on a daily basis. Often, this will involve an employee adding obsolescence management to their set of general responsibilities. The company should also implement the obsolescence management aspect into compulsory company training and set a strict procedure for what happens when an industrial part breaks down, with obsolescence management at the forefront.

Strategic obsolescence management comes with a number of key benefits, namely anticipating and mitigating the risk of costly redesign cycles and rapid assessment of where and how component obsolescence impacts the system supportability.

The ability to identify secondary sources and alternate parts in advance are also benefits of good planning, benefits which allow companies in oil and gas to minimise the risk of obsolescence. Finally, thorough obsolescence management establishes guidelines on how systems should be modified during design refreshes and allows better management of stock, inventory and spares.

Compliance rules Considering obsolescence does not just help oil and gas companies maintain critical systems at an affordable price. It also helps them keep up with the latest changes to regulations.

In October 2019, the EU introduced its latest Ecodesign Regulation (EU) 2019/1781, which outlines new energy performance requirements for a variety of motors and variable speed drives. From July 2021, all electric motors with a power output from 0.12 kW – 0.75 kW must meet the IE2 energy classification. Motors from 0.75 kW – 1,000 kW must be IE3 rated.

From July 2021, the exemption of using an IE2 motor with a Variable Speed Drive (VSD) will also be removed. From July 2023, increased safety, explosion-protected Ex eb motors from 0.12 kW – 1,000 kW and single-phase motors of 0.12 kW and up must be IE2 rated.

Three-phase motors with 2, 4 or 6 poles of 75 kW – 200 kW will need to meet the superpremium-efficiency IE4 classification.

Considering that a simple electric motor costing a few hundred pounds will consume many tens of thousands of pounds worth of electricity from cradle to grave, creating a plan and sourcing these parts ahead of time will ensure that businesses are compliant when the rules come into force.

However, this doesn’t mean that you have to buy new parts. Sourcing reconditioned parts from a reputable supplier, that comes with the same warranty and certification, can deliver a significant cost saving when it comes time to upgrade parts and should form a key part of your obsolescence strategy.

Supplier flexibility Oil and gas companies should look for a supplier that does not rely on their warehouse alone, nor on those of a handful of preferred manufacturers. A good supplier will employ multi-sourcing tactics that ensure there is an entire network of manufacturers and distributors available to supply each type of component. This ensures that when a customer in a mission critical marketplaces an order, the supplier can pick and choose the product with the best price and quickest delivery option.

The threat of downtime, loss of revenue and the cost of finding replacements for obsolete devices in oil and gas certainly makes investment in innovation-led initiatives attractive. Upgrading the entire system may seem like a good idea, but it is not always the best choice.

To be truly innovative means more than being an early adopter of the newest technology; you need to be able to support your growth with strong foundations and functional legacy systems. Managing obsolescence effectively will allow you to evolve your business at a sustainable pace, enabling you to innovate whilst delivering a quality service.

07

Completions

Innovative solutions to challenging well conditions, through COVID-19 and beyond Today, drilling teams face the dual challenge of the oil price drop and a global pandemic; whilst feeling added pressure to make operations more sustainable in-line with the drive for a low carbon future.

42

Completions

Tools, says. “Technology is not only important in helping reduce emissions but will also be critical for operators seeking to locate and access remaining reserves.

“With drilling activity ramping up, and a drive to make activity as efficient and environmentally friendly as possible, operators must ensure they are prepared to meet this global demand.”

Tackling complex wells with confidence

A

s a result of the volatile market and virus, many offshore and onshore drilling projects have been delayed or postponed indefinitely. The current state-of-play may look bleak; however, the future outlook is far more positive. Recent reports indicate that drilling activity is set to grow in 2021.

Rystad Energy has predicted that the total worth of final investment decisions (FIDs) will double next year and exceed pre-pandemic levels from 2022. Total global oil and gas project spending is expected to bounce back to around $100 billion in 2021, primarily supported by offshore projects but onshore projects will also see a boom.

In parallel, we can expect a greater emphasis placed on the energy transition as the pressure bears down on companies and countries to meet the ambitious net zero targets by 2050. “Global demand for a safe, secure energy supply means oil and gas will remain part of the future energy mix, however drilling hydrocarbons must happen as efficiently as possible, and with net zero in mind,” David Stephenson, CEO of Deep Casing

As the pandemic introduces strict measures and restrictions on travel and social distancing, drilling project teams have found themselves under strain to maintain schedules and budgets. In particular, complex well projects already have a tendency to overrun, and that is without throwing a global pandemic into the mix.

“Wells are becoming longer and more extensive to drill, making it harder than ever to reach target depth in a well that can have torque and drag issues,” Stephenson says. “This has seen ExtendedReach Drilling (ERD) become the preferred method to maximise reservoirs in a single wellbore.

“However, ERD presents its own challenges.

Horizontal wells having a lateral extent of greater than 6000ft are generating more problems when compared with shorter lateral wells of 20005000ft. The need for ERD, and the ever-growing challenges it brings, is driving a surge in industry demand for innovative technology that will support drilling projects at a time where finding oil is anything but “easy”, and operators are faced with post-COVID-19 considerations such as the need for remote operations.”

Efficient, reliable technology is not only the key to locating reserves in challenging well conditions but can help to reduce emissions. “Technology can lead to powerful results,” Stephenson says. “We recently ran our turbine-powered completions tools, Turborunner, with Shell Sarawak in Malaysia in three wells to support the energy major’s offshore oil exploration and production, and

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“With drilling activity ramping up, and a drive to make activity as efficient and environmentally friendly as possible, operators must ensure they are prepared to meet this global demand.”

offshore gas production in the region. The project totalled six wells, split out into two phases, with three wells being drilled per phase, and the first phase completed in February 2019.

“The second phase of the project presented a number of challenges with complex tight spots in all six wells, as well as loss zones, making the run problematic. Without the correct technology, issues could arise such as equipment damage, significant downtime, additional trips and open hole exposure leading to the project overrunning and the operator facing increased costs. As a result of Covid-19, these problems were amplified by operator and local government social distancing rules and regulations.”

For the well-established oil and gas industry, volatile and often high-risk environments are commonplace, but the COVID-19 pandemic has added to the HSE considerations in an unprecedented way. “On this project we were able to support Shell Sarawak despite challenging conditions heightened by Covid-19,” Stephenson explains. “This was through collaboration and a strategic partnership.

Harnessing the power of digital for remote project planning With offshore and onshore drilling projects expected to see a boom in 2021, and the pandemic showing no sign of slowing down, global operations teams will need to adapt to a new way of working. This will mean putting in place strategies and processes that take the restrictions on overseas travel into consideration whilst allowing the company to capitalise on international opportunities.

“In addition to building on-the-ground alliances, technology can offer a solution to these new limitations and ensure projects are planned and executed effectively around the world,” Stephenson adds. “According to EY’s 2020 Oil and Gas Digital Transformation and the Workforce Survey, oil and gas executives have increased

43

Completions

investment in digital technology by almost 60 per cent due to the global pandemic, and almost half said this was due to low oil prices.

“Whilst working with Shell on this project, our technical operations team in Aberdeen, Scotland, were able to offer remote support and monitoring services to the operator during all tool runs. By eliminating the need for international travel, Shell was able to safeguard its people, reducing the risk

of the virus spreading, and removing any potential downtime if a team member was required to quarantine, whilst ensuring a high level of communication and technical support was maintained throughout the project.

“It looks like we are not alone in recognising the power of technology. The EY report states that 93 per cent of oil and gas companies are currently using remote monitoring technology to drive efficiency and add value across the supply chain. We can expect this trend to continue as global drilling teams leverage digitisation to help meet the energy demand, as safely as possible.”

Unlocking efficiency through simple innovation With operators under more pressure than ever to deliver on squeezed budgets, it is important that value is added at every stage of the well life cycle. “We have worked to develop a suite of technologies in well construction, well completion, and casing removal and abandonment for drilling teams that are looking for simple, enabling and reliable solutions,” Stephenson continues. “We believe innovation comes in many forms, and quite often improving a known and trusted method offers more value than inventing a new one. From decades of previous oilfield service experience, our team has been involved in past operations that have used conventional methods across the well life cycle, including cut and pulling, perf and wash, and pilot milling.

“Witnessing several failed attempts to complete operations on time and within budget, our team is driven by one common goal: to make drilling operations smoother by using simple innovation. Focussed on maximising operator ROI, our engineers constantly push the technological boundaries to make these projects safer, more economic and environmentally friendly for the wider oil and gas sector.”

44

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Managing the cyber risks created by digital transformation within the oil and gas industry The increased digital reliance of the oil and gas sector has led to an increased cyberattack surface across the industry that organisations are scrambling to address. To stay safe operators must learn how to recognise, assess, and mitigate the cyber risks in oil and gas environments 46

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s a sector of critical importance, any interruption to computing systems relied upon by the oil, gas and energy sector could have a severe effect on the nation’s economy and affect citizens’ daily lives.

“It is no secret that a cyberattack could end up denying citizens access to basic services, while governments worry about potential impact to gross domestic product (GDP),” Barak Perelman, VP, operational technology, Tenable, says.

“Beyond the immediate consequences, any loss of data or theft of intellectual property would also have consequences to operations, which may not materialise until a much later date.

Unlike other sectors, even a small technical glitch could not only pose a threat to data but could have physical impact, both

Cybersecurity

on the business’ infrastructure but could also pose a risk to life.”

Over the past few years, the oil and gas industry’s reliance on digital platforms, devices and systems has increased exponentially. “While embracing new technologies can benefit efficiency, output, and the bottom line, this has led to the convergence of IT, which utilise servers, routers, PCs and switches; and operational technology (OT), encompassing programmable logic controllers (PLCs), distributed control systems (DCSs) and human machine interfaces (HMIs), which run physical plants,” Perelman adds. “The merging of these two previously siloed environments extends the attack surface, while making cybersecurity threats harder to detect, investigate and remediate.”

According to a study conducted by Forrester Consulting, 96 per cent of UK organisations have experienced one or more business-impacting cyberattacks in the last 12 months. As if that was not significant enough, the majority (65 per cent) of security leaders say some of these attacks involved OT systems.

IT/OT convergence It is true that IT’s cyber hygiene issues have slowly been improving thanks to technical developments.

However, the same cannot be said for OT environments where security traditionally relied upon limited and/or restricted connectivity. “As we continue to connect our OT infrastructure, threat actors are seeing more possibilities to exploit vulnerabilities and exposures in legacy equipment,” Perelman explains. “The rapid adoption of 5G, particularly within IT and OT, will further this convergence with IT teams and attackers both looking for ways to navigate the mass distribution and interconnectivity - some for legitimate, others nefarious, purposes. The sheer speed and reach of 5G will connect businesses beyond recognition, but that could be a dangerous combination in terms of a successful cyberattack.”

A further complication is that cyber breaches that start on one side of the converged infrastructure can laterally creep to the other, from IT to OT and vice versa. “It is also important to recognise the significant difference in IT and OT life cycles,” Perelman adds. “While IT infrastructures can be updated regularly, OT infrastructures often persist for years, even decades.”

handle the pressure of compelling business arguments, all while the energy industry is under increasing national and international scrutiny.

“Most energy organisations encounter similar challenges when trying to balance all of these different priorities,” Perelman says. “One of the most prevalent challenges for oil and gas is the

zero-downtime tolerance policy, given the business criticality of the systems. There is just no simple or quick process to shut down a system to fix a vulnerability. But a utility business also cannot afford to risk a vulnerability being exploited that could damage the plant or even threaten life.

“Another key challenge for the oil and gas sector

Oil and gas challenges Oil and gas security teams are faced with shrinking resources, an expectation to understand and

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Cybersecurity

is that these plants are often structured around legacy technologies, designed for static devices, prioritising process functionality and safety. It is also likely that some of the infrastructure will be as old as the plant itself. This means that a full inventory of assets, maintenance and change management records may not be current or be missing altogether. Without crucial data, such as model number, location, firmware version, patch level, backplane detail and more, it is impossible to adequately protect these systems.

“As modern industrial plants increasingly connect countless machines, devices, sensors and more to the Internet, the number of touch points that are open to vulnerabilities continues to grow by the day.”

security, and have begun to implement measures to ensure they are protected.

For example, the NIS Directive is the first piece of EU-wide legislation with a focus on cybersecurity. “It outlines how businesses deemed to be Operators of Essential Services (OES) need to identify, manage and reduce their cyber risk,” Perelman explains. “However, implemented in 2018, the threat landscape has evolved significantly since. As a result, the EU Commission has launched a public consultation on a proposed revision to the Directive, providing an opportunity to clarify minimum cyber hygiene standards, consider the expanded threat landscape, new threats such as OT risks, and bring standards to critical sectors across the EU.”

Closing the breach

Taking back control

Governments have recognised that the reliability and continuous operations of each nation’s critical infrastructure, such as the energy sector, is vital to national

Oil and gas organisations need to prioritise gaining a single view of IT and OT environments. This single pane of glass view will help illuminate potential attack

48

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“Focus should be on the exploitable vulnerabilities affecting these devices and services.”

vectors and asset blind spots that may have eluded traditional security strategies. “Since it is impossible to secure assets that you may not even know exist, having a detailed inventory of OT infrastructure that can be automatically updated as conditions change is essential to protecting industrial operations,” Perelman says. “Since most attacks target devices rather than networks, it is also essential to utilise a solution that actively queries and provides security at the device level.”

In 2019, over 20,000 new vulnerabilities that affected both OT devices and traditional IT assets were disclosed, yet fewer than half of these vulnerabilities had an available exploit. “Security teams should only prioritise the threats that pose an actual rather than theoretical risk, but they can only do this with full visibility of the assets that are critical to the organisation’s ability to function,” Perelman continues. “Focus should be on the exploitable vulnerabilities affecting these devices and services.”

Facing increased threats The previously mentioned Forrester study found that organisations with security and business leaders who are aligned in measuring and managing cybersecurity as a strategic business risk, deliver demonstrable results. “Given the potential impact of any damage, executive leaders and company boards also need to understand the cyber threats their organisation faces,” Perelman concludes.

“This is particularly true this year, and looking ahead to the coming months, as we navigate the world out of a global pandemic.

“The research also showed that across all industries, businessaligned security leaders are eight times more likely to be highly confident in their ability to report on their organisations’ level of security or risk. This is due to having a holistic understanding of the organisation’s entire attack surface, with the ability to use a combination of asset criticality and vulnerability data when prioritising remediation efforts than their siloed counterparts.

While this is undoubtedly crucial for any industry, it is a particularly vital process for the critical nature of the energy sector.”

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N O R M E T. C O M

Maintenance

Cost-savings in strategic maintenance The turmoil of reduced prices and the ongoing global pandemic are putting a constant strain on the offshore oil and gas industry. Operators are looking for ways to reduce expenditure at various stages of developments and so analysts are exploring the methods used to date.

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nalysis carried out recently by Lloyd’s Energy found that forty per cent of maintenance work carried out by Floating Production Storage and Offloading (FPSO) vessel operators is unnecessary. Most of the reduction in expenditure in recent years was due to a variety of factors including strategic planning, more efficient maintenance management and the increased and improved implementation of technology according to a further Rystad Energy study. This shows that care is being taken to identify more structural cost savings rather than focusing on short-term wins as has been shown in previous downturns.

Long term cost cutting Efficient resource management is crucial to long-term cost-cutting strategies. Modern IT software makes data-based planning more effective. One issue remains, however: conflicting data is often being entered into the software. Data on wastefulness of ineffective maintenance strategies is prompting a review of methods and more interest in outsourcing of smaller projects. Regular inspection and maintenance of equipment is one area where the mis-matched data is causing issues. Flag, class and country regulations and operator’s standards often do not overlap with OEMs guidelines which do not account for the everchanging nature of offshore projects. OEM’s guidelines which are inadequate when projects are different from ‘the norm’ can cause difficulties and overspend. The costs add up during the lifetime of a project and the redundant work not only does not improve the safety of the operations, but it may also delay inspection and maintenance of equipment that requires it. The resource exhaustion multiplies with rising number of unexpected repairs and other ‘firefighting’ measures coming into play.

Improved equipment and operational philosophies coupled with the global cost-reduction requirements are leading many industry professionals to take a fresh look at their maintenance procedures to lower operational costs.

Adapting to conditions Reflex Marine, as a global provider of essential logistics equipment, has always appreciated the importance of adapting the inspection and maintenance (I&M) guidelines to the true usage and needs of the offshore industry (see example I&M schedule for WAVE-4 attached).

Reflex Marine’s personnel transfer equipment is designed to last with many units still in service after more than ten years. A carefully developed inspection and maintenance schedule is crucial to ensuring safety of the device while at the same time ease of introducing the correct procedures into the operator’s standards.

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Maintenance

Offshore personnel transfer by crane is a cost-efficient method of crew transfer but it is also recognised for safety, with Reflex Marine’s carriers having the best safety record in the world. This impressive result is made up of excellent engineering, high-quality materials and careful equipment testing. The testing program that Reflex Marine use for their carriers was modelled on methods used in the automotive industry to ensure the equipment remains safe and effective in the hostile offshore environment.

Philip Strong, CEO and Technical Director, described the process: “A modern car provides a secure environment that can protect passengers from impacts. A transfer device can do the same and guard against the human factors that contribute to most incidents. Such verification is in essence, bio-mechanical, not just mechanical – in other words, it is not just necessary to understand the response of the device to certain load conditions, one must also understand the likely responses of the human body to the same loads. Bio-mechanical studies are based on statistical methods for analysing the responses associated with different physiologies, the long and the short and the tall, so to speak.”

Focusing on the client is at the core of Reflex Marine’s vision: prioritising safety of passengers during transfer but also understanding the wider operational needs and the nature of offshore projects.

Global experience Procedures, pre-lift planning, communications and operational training can all play a significant role in reducing risks. Suppliers of marine equipment should apply their diverse global experience to help clients evaluate and mitigate risk relating to a wide range of operating scenarios by providing clients with knowledge, training and the ongoing support needed to use the product safely and efficiently. Reflex Marine has been sharing knowledge and best practices with clients around the world for over 25 years. This expertise and the quality of products are recognized by industry leaders globally such as MODEC, Equinor, Total, and many more.

Reflex Marine is the only supplier of personnel crane transfer devices that has developed I&M standards and procedures to help operators use the equipment with confidence no matter where they are in the world. The I&M schedules have been developed based on an evaluation of risks, the environmental conditions and, most importantly, the stresses on the parts depending on usage. Similarly to the automotive industry, this means that equipment should be serviced as and when needed to ensure safety of the passengers. Reflex Marine make it an easy process for their units to be kept operational at all times, minimising maintenance downtime of the projects. Their Approved Service Centres have trained technicians available in various locations around the world for onshore or offshore servicing jobs.

At work in Angola

WAVE-4 personnel transfer carrier for 4 standing passengers used during transfers on Saipem 7000

Long-term rental of personnel transfer equipment is another solution provided by Reflex Marine to simplify the operations while providing a reliable, durable crew transfer method with a high operating window. This model, which includes regular upkeep of the units together with servicing and replacements parts, was chosen by Seacor Marine for regular crew transfers offshore Angola. Recognising the benefits of this model, the company has recently upgraded from the original range FROG-9 carriers to new and improved FROGXT10 10-passenger carriers.

To further simplify the processes of looking after this safetycritical equipment in the light of the global pandemic, the company has recently introduced an option of online training to crews around the world which can be conveniently delivered via a webinar. This is an important step towards the customers to help them ensure safety of crew transfers at all times in today’s challenging conditions.

Many operators appreciate cost-savings achieved through regular maintenance. Total, who use Reflex Marine carriers for crew transfer around the world from Gulf of Mexico to Africa and Asia, are diligent in their practice of servicing personnel transfer carriers and replacing the parts according to OEM recommendation. However, where complete procedures are not specified by operators, there

51

Maintenance

WAVE RECOMMENDED INSPECTION AND MAINTENANCE SCHEDULES Usage Category No of Transfer lifts per year

Critical Part Replacement 2 Pre use check

Visual Inspection

Wire Rope Lifting Assembly Replacement

Load Test

Unit Replacement

Post Load Test Visual Inspection

Contingency < 50 Routine < 50 - 1000

Examination

Prior to E very Use

Heavy < 1000 - 40003

6 months

12 months

12 months

48 months

12 years

6 months

12 months

12 months

24 months

10 years

3 months

12 months

6 months

12 months

8 years

1 This may be extended subject to a ‘condition & service assessment’ carried out by Reflex Marine or an Approved Partner 2 Only applies to critical parts marked ‘consumable’ Notes 3 When exceeding 4000 lifts, please refer to the Ultra-High Usage section (4.6) for further inspection guidance In the event of heavy impact,a detailed examination should be carried out to ensure intergrity beefore conducting any further lifts Recommended inspection and maintenance schedule for Reflex Marine’s WAVE-4 personnel transfer carrier

are still other companies which forgo this practice resolving to servicing only when issues occur. Victor Borges, Lloyd’s Register’s expert on FPSO maintenance optimisation comments: “To break the cycle of ‘firefighting’, operators need to adopt a risk-based approach to maintenance, allowing them to cut unnecessary spend, free up resources and reduce the maintenance backlog.

Understanding the balance between the cost of failure and the cost of maintenance can help operators focus the right resources on the right equipment at the right time”. All offshore operators and contractors could benefit from implementing this advice.

Increased focus on cost-saving strategies during the global downturn in the offshore market has once again sparked hope for a shift in attitudes from ‘firefighting’ to employing measures for long-term structural benefits. Investing in durable and cost-effective equipment over cheaper alternatives, as well as more effective, datadriven maintenance strategies are recognized for the lasting gains they can deliver. The industry is exploring new ways and suppliers are joining in with innovative solutions. The challenges of today shall ultimately help the global industry improve and move forward into the new, postcrisis future.

52

WAVE-4 personnel transfer carrier for 4 standing passengers used during transfers on Saipem 7000

Improve oil and gas production and reduce downtime New technologies are required to gain valuable insights and intelligence from the overwhelming volume and complex data sets produced by the Industrial Internet of Things (IIoT).

T

hrough the application of advanced machine learning, Toumetis helps to derive value from data across the operational value chain, ensuring plant and operational managers optimize workflows from manufacturing machinery to end-to-end industrial processes, allowing you to control, share and monetize data in revolutionary ways.

Facing downward commodity prices unseen in decades, staying competitive in the oil and gas industry is tougher than ever. Battling low margins and high risk, petroleum enterprises need to reduce downtime, optimise operations, and stretch the value gained from every dollar of Capex and Opex invested. All the while, they need make operations safer, often in some of the most rugged, far-flung work sites imaginable.

Though already a highly automated and connected industry, oil and gas enterprises today continue to be challenged with a deluge of data from their instrumented assets. So how do companies capitalise on this onslaught of information to optimise operations? The lloT provides a key to unlocking hidden value and unprecedented productivity gains from the reservoir to the refinery. power generation.

Oil and gas operators estimate that roughly 60 per cent of maintenance labour results in no action, and that a three to five per cent improvement in performance is achievable through process optimisations. Toumetisâ&#x20AC;&#x2122; industry-proven machine learning solutions predict the performance of industrial assets to enable proactive maintenance and identify anomalies to optimize production processes.

Unlike traditional analytics projects that are dependent on limited, high-cost data science

expertise, Toumetis solutions bridge the gap between traditional operational technologies and big data so oil and gas organisations can rapidly transform massive lloT data into profitable business outcomes, reduce the complexity of managing oil and gas assets and operations and accelerate the delivery of tangible performance improvement Oil and gas organisations can increase margins by improving production uptime and throughput and optimizing asset performance. Leveraging your abundant lloT data, Toumetisâ&#x20AC;&#x2122; advanced machine learning solutions enable oil and gas organizations to transform business operations and enable new revenue by optimising asset maintenance to drastically reduce labour while also reducing unnecessary cost, risk and downtime. It facilitates predictive asset maintenance - identify failure patterns and predicts problems with high-cost machinery (rotating equipment) to reduce costs and improve budget allocation. It also delivers process improvements by identifying anomalies to improve operation and production quality while increasing bottom line financial performance.

53

Innovation

He is just passed his exams but Weldar is no ordinary apprentice.

After two years of practice, testing, and quality checks, Weldar passed his apprenticeship exam, repairing corrosion damage on a plant in full operation. But Weldar, whose nickname is a play on our CEOâ&#x20AC;&#x2122;s name, is an apprentice with a difference â&#x20AC;&#x201D; he is a robot.

54

Innovation

The answer was corrosion.

“Tonnes of metal corrode away in industrial installations and must be continuously monitored and rectified to maintain safe operations. If we could take a welding robot out to the equipment, as opposed to taking the equipment to the robot, we could achieve considerable savings,” Morten adds.

In response to sceptics, he hunkered down on the sofa with his laptop to do his own research. There are thousands of welding robots on the market. Surely there must be a model that could be adapted to his idea.

And he found what he was looking for on Finn.no, Norway’s eBay equivalent.

“The Migatronic company was selling a welding robot called CoWelder. Small and light.

This was exactly what I was looking for. I immediately called them, on a Sunday evening, and the salesman happened to be available.”

W

eldar’s creators are the team at Tjeldbergodden, a robot manufacturer in Jutland, Denmark — and mechanical engineer in Equinor, Geir Morten Vikan. And together they have just created a piece of industrial history.

For the first time ever, corroded metal on a pipeline has been repaired on site, using welding, while the pipeline was in use — a potentially dangerous, so-called hot operation.

Colleagues were initially sceptical “I might have a little Gyro Gearloose in me. I’ve always been interested in mechanical challenges,” admits Geir Morten Vikan, with a laugh.

The scent of fumes from welding and angle grinding is one of his earliest memories. His grandfather’s workshop was one of his favourite places growing up. He has been a gearhead since childhood.

Morten has been a mechanical engineer at the methanol factory at Tjeldbergodden since it received the first gas from the Heidrun field in the 1990s, first as a Reinertsen employee and later as an Equinor employee. Many of the things that eventually solved problems in the plant were first conceived and tested in his own basement workshop at home in Dromnes in Aure municipality — so he is well known for his problem-solving skills.

But when he first launched the idea for Weldar, colleagues at the plant were sceptical.

Found the basis for Weldar on Norway’s eBay He explained his idea of using a welding robot in the plant — doing repair work on plants in operation — but a lot of people thought he was overly ambitious. “They kind of shook their heads. But that is what keeps me going. Looking for new solutions where others just see problems.”

Morten’s original idea for what eventually became Weldar had been conceived back in 2018, during work on so-called additive manufacturing – often called 3D printing. The question was, was there some way to scale up this technology to solve even bigger problems — potentially benefitting Equinor as a whole?

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“They kind of shook their heads.

But that is what keeps me going.

Looking for new solutions where others just see problems.”

Pioneering cooperation with the supplier The company representative showed up at Tjeldbergodden a few days later, with a quizzical smile. Their robot was designed for small-scale production, but Geir Morten wanted to take it apart, install it in the plant and use it for much higher volumes and over a much longer period of time – preferably 20 consecutive hours, non-stop. That is a tall order.

Oddbjørn Grøseth, who represents Migatronic in Central Norway, confirms that his initial doubt gradually turned to confidence. “Of course, it was exciting to hear from Equinor back then. But we were surprised when Morten told us what he wanted to use the robot for. We have delivered a million welding robots over the years, but we have never seen anything like this. Our developers were very sceptical, but now they are very enthusiastic. I would never have thought that we would be where we are now. It’s been an incredible journey for all of us,” he says.

Edgar Glomnes, technical safety lead at Tjeldbergodden, was also a sceptic. “Welding represents a source of ignition, so I shook my head. But ignition needs a source, a flammable medium and oxygen. A welding robot does not need oxygen. So a welding environment, where oxygen is replaced with nitrogen, can open up new opportunities,” he says.

“They had to be convinced, says Geir Morten. I contacted one of our skilled welders here, Håvard Gjelen, and then we organised a trip to their headquarters at Fjerritslev,” he says. ”Eventually, some of our greatest sceptics have now become some of our most eager supporters,” he says.

Welding three-to-four times faster A welding robot welds three to four times faster and with higher precision and predictability. The robot can access places that are inaccessible to humans, it can work without breaks and can be controlled by welders at a safe distance. There will still be a need for certified welders, but they can have a better, safer work environment.

Repairing equipment without having to shut down production can result in cost savings of real magnitude. The repairs done during a shutdown represent approx. three times the expense of those possible during normal operations. And no production means no revenue.

Two years have passed since Morten found what he was looking for on Finn.no. Two years of trial and error, testing welding advice, 3D-scanning; programming and more programming. Technical and security challenges have been discussed and resolved in close collaboration with metallurgical expertise at Rotvoll, Sintef and the Equinor pipeline.

Weldar has passed his apprenticeship exam. Now the method must be quality-assured, documented and certified according to strict requirements. Equinor’s operating and maintenance community, both onshore and off, are paying close attention.

The method can result in enormous cost savings and simultaneously improve safety and working environment conditions for welders.

Weldar was named after the Equinor CEO, but Weldar has no intention of retiring. His career has only just begun.

55

Automation

Letting the drones take the strain Several industries are using drones to improve their operations, with oil and gas one of the sectors testing the technology.

U

nmanned aerial vehicles - UAVs or, more commonly, drones - have become integral to the oil and gas industry over the last few years owing to their increasing usability as technology has advanced. This is bolstered further by falling hardware costs and easing government regulations. The industry’s steady transition towards digital transformation using sensors, cloud computing and the Internet of Things (IoT) is providing an added impetus to drone usage.

Drone adoption in the oil and gas industry initially revolved around strategic deployments for remote monitoring and surveillance of assets during regular operations and in emergency situations. Recent advancements in sensing and imaging technologies are enabling drones to be deployed in a wide range of settings for performing inspection and predictive maintenance of critical infrastructure.

Drone makers are also collaborating with oil and gas companies to develop custom drone platforms

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that can be equipped with different types of data collection technologies for obtaining realtime insights.

The future for inspections Drone-based inspections tend to be quicker and more cost-effective, which is a key driver for oil and gas customers. “The traditional methods of access would be to use scaffolding or rope access technicians,” Xiang Wong, Inspection Manager at Cyberhawk, explains. “Erecting and

Automation

dismantling scaffolding is often extremely costly, potentially hundreds of thousands of pounds for large areas, and makes this technique unjustifiably expensive when other solutions exist. For both scaffolding and rope access it can take weeks, if not months, to complete full inspection scopes.

“These safety benefits do not come with a high price tag – in fact, it is the opposite. By conducting inspections in a fraction of the typical time required, there are huge cost savings on offer, often into millions of dollars for large inspection campaigns.

Also, the oil and gas industry by its nature is risk adverse and safety is paramount, drone inspections reduce safety risks, so it is an attractive option compared with traditional methods, such as using rope access or scaffolding.

Using this airborne technology to inspect assets reduces the need to send personnel into dangerous areas, or have people working at height for extended periods of time. Drones can fly in hard-to-reach confined spaces, often without need for human entry. This means equipment such as pipe racks, vessels and storage tanks can be easily and safely inspected both visually and thermally.

assets has grown massively over the last decade and is predicted by ResearchandMarkets.com to grow by a further 60% over the next five years.

Collecting complex data Using drones for surveying allows for complex and intricate inspections of assets, resulting in detailed imagery of even the smallest defects, with less

Overcoming scepticism Looking back over the past five years, many oil and gas businesses were sceptical about the quality of the data they may receive after a drone inspection, or even if it was a safe option. In addition, in such a conservative sector many operators are not comfortable being the first to adopt a new technology or approach, but they are happy to be the second once it has been proven.

“As the technology advances, we can capture more accurate data safely and this has resulted in an acknowledgement across the industry that it is reliable and robust,” Wong adds. “Over the years the quality of data we can gather has drastically improved. As a result, we have seen oil and gas companies embrace the benefits of drone inspection.

“Today, businesses are under a huge amount of pressure due to COVID-19 restrictions. They are having to maintain critical inspection work with limited manpower, and with the health and safety regulators becoming more flexible around the need for an on-site presence during inspections, we are seeing a further rise in inspection services being delivered remotely. In fact, the use of drone technology for inspecting offshore oil and gas

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Automation

potential for human error. A drone can capture overview and standoff shots, as well as close visual inspection imagery, allowing asset managers to effectively gauge the context and extent of any areas of damage.

For the oil and gas industry, drones are commonly used to capture visual data used to digitise offshore assets. The images of the assets are captured during routine inspection campaigns and can be used to build a highly detailed 3D digital twin of the asset. “We have seen demand for this increase this year as asset operators look for ways to reduce the manpower needed offshore to limit potential exposure to the coronavirus pandemic,” Wong says. “3D models allow engineers to inspect the facility and plan maintenance virtually, meaning repairs are focused and minimal time is spent on-site.

“The ability to inspect, analyse and plan repairs remotely is even more beneficial in current times, as this allows companies to maintain social distancing and keep their workforce safe, whilst maintaining the safety and integrity of the assets and driving productivity.

Over recent years there has been significant advancements in data management that which has led to increased efficiencies and allowed operators to gain more value from data. “At the same time, we have seen a rapid increase in the volume of data customers have access to. For many oil and gas operators it is a challenge to process, store, assemble and search through large amounts of data.

Gaining industry confidence When drones were first introduced to the sector over a decade ago there was a need to instil confidence in asset operators in terms of drone safety, as well as demonstrate the quality of data that could be captured. Operators wanted assurance that they would get the same level of detail from a rope-based inspection.

“As the offshore oil and gas industry is an extremely hazardous environment, it was important to demonstrate that we understood healthy and safety considerations, and our field teams would comply with operator procedures and regulations,” Wing continues. “We were able to overcome these initial reservations. Firstly, many of our team members have come from an oil and gas background, and are highly knowledgeable about the HSE considerations offshore, and are by nature very risk aware. We were able to demonstrate that we understood the market and planning considerations in early discussions with prospective customers.

“Secondly, we believe it is important to ensure our pilots are trained to the highest standards. Our pilots are trained to understand why they need to get the right data in the right way – every time.”

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Adding intelligence to data There have been significant advancements when it comes to the way that data is captured and processed. An important trend is automation. “At Cyberhawk we are now creating our own AI models based on our in-depth engineering expertise,” Wong says. “We believe it is important to provide insights that can inform decisions with the data we capture, so we use an engineering perspective to ensure we provide our customers with the insights they need most to add real value to their operations. Deploying sensors in the oil and gas sector is not new, but there’s now an interest in network-attached systems that are very quickly and easily deployed.

“With greater volumes of higher quality data being captured, we are also seeing opportunities for improved 3D visualisation. The key to an effective 3D presentation of an asset is to not only contextualise the asset condition in real time, but to also provide a tool that can accurately plan remedial work required and maintain the asset. In other words, 3D

Automation

traditional manned delivery methods, which can include the use of cargo vessels, there is still work to do to make the technology more cost competitive and accessible to the wider energy industry. It also has a payload capacity of 50kg which limits the cargo that can be transported. If the technology can accommodate heavier cargos one day this could be a game changer for supplying offshore rigs.

Finally, methane detection has proven remarkably successful. Shell for example is using satellites to locate methane leaks and then deploying drones with gas sensors to pinpoint exactly where the methane is coming from.

Drones in action

visualisation gives the operator a better idea of how good is good, how bad is bad in the grand scheme of things and allows them to use that quantifiable information to plan a more cost-effective maintenance campaign.”

In terms of innovations in drone technologies, we recently saw the Schiebel Camcopter S-100, a mini-helicopter UAV developed by Nordic Unmanned, carry out a long-range unmanned flight to supply a 3D printed component to a rig off the west coast of Norway for Equinor. At a flight range of 100km each way, this was a world-first in terms of scale of an unmanned aviation delivery.

Although this is positive for the environment as drone operations have a 55 times lower carbon footprint than

Shell is one company which is embracing drones and digitalisation globally. Earlier this year, the supermajor awarded Cyberhawk a five-year, multi-million-dollar contract to use iHawk as its next generation visualisation software platform for all onshore, offshore and subsea assets, as well as all global construction projects.

“We have been a key supporter of Shell’s digital transformation strategy since 2012 and our collaborative, progressive relationship has been a key enabler in the evolution of iHawk,” Wong adds. “Managing complex infrastructure, particularly in the energy industry, cannot be based on a one size fits all approach, so we work closely with iHawk clients in this sector to ensure our software is fit-for-purpose, and doesn’t stand still.”

Unfortunately, a lot of drone technology available today is limited by the battery technology. If there was a breakthrough in battery technology and had access to more powerful energy sources, it would transform the way drones are used. This would allow drones to stay connected 24/7 via IoT technology and allow for around the clock asset surveillance, meaning remote inspections would identify defects early on.

“Unmanned drone operations will become the norm,” Wong says. “We can expect more R&D to make it possible to transfer heavier goods using unmanned drones and perform complex tasks such as advanced NDT inspection and fabric maintenance.

“We have already seen Amazon pushing for an airspace corridor which would allow the e-commerce giant to use high-speed aerial drones to deliver goods from their warehouses straight to the consumer’s doorstep. These would fly robotically with virtually no human interference.

This would support social distancing so it may be an innovation that we see accelerated in the coming months as non-essential shops remain shut and online orders increase. It will be interesting to see how this application could be transferred to the offshore oil and gas sector in years to come.”

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Digital transformation

Edge computing key to digital transformation The oil and gas industry is ripe for change. Forward-looking companies believe todayâ&#x20AC;&#x2122;s turbulent market landscape and falling prices provide an opportunity to gain a competitive advantage by harnessing new technologies.

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Digital transformation

R

ecently oil and gas operators have begun to emphasize digital transformation, which started with real-time monitoring and remote equipment operation. This change was then followed by an increased application of modern data science techniques such as machine learning, artificial intelligence (AI), and the Internet of Things (IoT) to extract actionable insights from the data.

According to Jeffrey Ricker, founder and CEO, Hivecell pulling data and analyzing it are two very different things. For context, a typical oil rig has 30,000 sensors, generating a tremendous amount of data.

In fact, a report from Cisco estimates that a standard oil platform generates up to 2TB of data every day, most of which is time-sensitive as it pertains to platform production and drilling-platform safety.

“Once this data is pulled, less than one percent of it is currently being used for decision-making, with most going unanalyzed and unused,” Ricker says. “This unused data could help increase production efficiency, create a safer workplace for employees, or help better the environment.

“Companies also assumed that they would simply be able to publish all of the data to the cloud. While technologies such as cloud computing have been touted as solutions, these still rely on the data being transmitted. It would take 12 days to push just one day’s worth of data from the 30,000 sensors on an oil rig to the cloud, wasting time and valuable resources.

Companies using IoT, AI, and machine learning soon realized that it is impractical to move all the raw data to the cloud for analysis. Not only will quality suffer due to latency, but the costs in bandwidth can be tremendous. These companies need to move compute power from the cloud back to the edge, as close to the data source as possible, otherwise known as edge computing.”

What is edge computing Edge computing is a new type of compute power that exists between smart technologies and the cloud. This solution

allows companies to harness the power of business-relevant data, cut costs, and manage their data remotely.

A study from Gartner estimates that by 2025, 75 per cent of data will be processed outside the traditional data center or cloud, making the industry ripe for implementing edge computing. “Edge computing can harness growing in-device computing capabilities to provide deep insights and predictive analysis in near-real-time,” Ricker says.

“This increased analytics capability in edge devices can power innovation to improve quality and enhance value.”

Richer believes there are six primary reasons why edge computing is vital for industrial operations: bandwidth, cost, reliability, security, compliance, and latency.

Bandwidth: When companies first began discussing IoT, most assumed that all the data would go directly to the cloud, but it was grossly underestimated how much data would be produced. Some data is so large that it is not feasible to move it from its source to the cloud. The key is to do the initial analysis of this data at the edge, and then send the valuable data.

Cost: Moving large amounts of data across the Internet and storing it in the cloud can be expensive. The price is especially vexing when the raw data does not provide any value for a business. Costs add up quickly when pulling from thousands of sensors or locations, making it imperative to solely pull the business-relevant data.

Reliability: System safety or business continuity may demand local processing of data to avoid possible network outages. There is also the failure of cloud services to consider. Companies may still face disruption in business with reliable edge computing, but it will not be because the network was unavailable.

Security: Some data is considered too sensitive to move across the Internet, even if encrypted and in a virtual private cloud (VPC). The cloud may not be an option if a company cannot trust its value to a third party.

Compliance: Many countries have regulations that dictate where and how data can be stored, which prevents the use of cloud computing. If a company has multiple locations that cross country lines, it becomes especially difficult to communicate data or find common themes and issues.

Latency: In some situations, the network latency of moving data to the cloud and back again is impractical or even dangerous. Data cannot move faster than the speed of light, which is 186,000 miles per second, equating to

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Digital transformation

1 millisecond of delay for every 60 miles. Distance is not the only factor. The switching between routers across the network can be far more significant. Round trip messaging on a cellular network may take 200 to 800 milliseconds, a delay that is intolerable for machine decision-making.

Edge Computing for Oil and Gas There are many parts of the oil and gas industry that make the business case for edge computing even more compelling. Like any other industrial resource, oil and gas companies are keen on maximizing production to maximize revenue. However, according to McKinsey, benchmarks reveal that the typical offshore platform runs at approximately 77 percent of its maximum production potential. Industry-wide, this shortfall represents around 10 million barrels per day, or $200 billion in annual revenue.

“Every minute of every day is worth money, given the opportunity cost of lost drilling time or failed equipment,” Richer adds. “If the data information extracted from the edge is collated, calculated, and decided upon locally, the drilling operation could save or garner millions of dollars. Maintenance costs are also lowered: predictive maintenance reduces the risk of significant damage to drilling equipment.

Data can be used to predict maintenance windows for equipment, which allows for planned downtimes of much shorter durations, a few hours compared to a few weeks.

“Likewise, it can remove the need for a technician to take time out of their day to visit the site to address issues, which can also be beneficial from a safety perspective. The ability to remotely deploy, fix, and troubleshoot can lower insurance and corporate liability that would otherwise rise when technicians need to travel to far-off, sometimes dangerous, locations both onshore and offshore.

“Costs savings do not only come from reduced downtime. With the data being analyzed at the edge, network costs are minimized since it does not travel back to the data center. Additionally, decisions can be made in a fraction of the time, partly due to the length of the data journey being shortened

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because those terabytes can be processed locally.

But product transactions and supply chain decisions will have to be more flexible to act on the new information coming directly from the infrastructure and drills.”

The industry’s challenge is to extract actionable business insights from this data to enable operations to run more efficiently. Leveraging AI with edge computing in IoT applications transforms this data to deliver real-time operational intelligence directly where needed.

“Edge computing will play a vital role in evolving IoT deployments within the oil and gas industry, and it will continue to grow in the coming years,” Richer concludes. “Its technology has already proven useful for early adopters who are reaping its rewards. As data becomes increasingly important to drive business decisions, its value will increase exponentially.

Ultimately, capturing, storing, and processing data locally with simple, protected, and autonomous devices will become critical.”

White Paper: Asset Management in the Oil & Gas Industry

How technology can help with competitiveness in the Oil & Gas industry

FingertipÂŽ Knowledge where itâ&#x20AC;&#x2122;s needed

Oil and gas continues to be a major part of the energy mix for most countries.

Although it is widely accepted that all countries need to reduce their carbon emissions, there are still major energy-hungry sectors, such as transport and home heating, where there is no clear route to lower carbon.

Oil and gas continues to be a major part of the energy mix for most countries. Although it is widely accepted that all countries need to reduce their carbon emissions, there are still major energy-hungry sectors, such as transport and home heating, where there is no clear route to lower carbon.

In fact in the medium term, technologies such as gasfuelled power generation will have an increasingly important role to play, as electricity requirements increase. And increasing government research spending on carbon-capture technology makes it more likely that oil and gas will continue to be an important part of our energy mix for many decades to come.

Oil and gas remains an important sector for the UK economy; generating £17bn in income, supporting a workforce of over 300,000, and the associated investment is substantial - £5bn was invested in assets and corporate acquisitions last year. In fact industry forecasts predict that oil and gas will still be vital for: • Fuelling transport across the world • Generating power on demand • Heating & industrial usage It also expected to supply two-thirds of the domestic energy market over the next 20 years.

As in any industry, there are cycles, and there is no doubt that the oil and gas industry has been under some pressure over the past few years. This is because major suppliers are competing to drive prices down, and demand has been hit severely by the Covid pandemic.

This has caused many businesses in the sector to look carefully at their overheads.

The recently announced merger of North Sea operators Premier Oil and Chrysaor is expected to be the first of many in the sector, with organisations looking to reduce their back office and maintenance costs through mergers.

Businesses throughout the sector have been seeking ways to improve efficiency, and unit operating costs in the UK are now almost half what they were in 2014.

One of the ways cost efficiencies have been achieved is through deferred maintenance programmes. By offsetting non-critical spending around maintenance and operations, organisations have been able to reduce costs substantially. However, deferring critical maintenance can have serious implications. The crack in the North Sea Forties pipeline disrupted production in the region.

This demonstrates why an effective asset management programme is essential – to ensure that businesses can achieve cost efficiencies, while still retaining operational excellence.

With the cost of replacement often far exceeding effective maintenance, having a robust enterprise asset management (EAM) system is essential for any oil and gas business.

Ensuring an effective asset management system Oil and gas operators often sweat their assets to: • Increase production • Extend their working life • Ensure assets are in optimum condition This helps to avoid production equipment failures or unplanned outages.

Establishing an effective asset management strategy requires an organisation to ensure they have effective processes for the assets (whether it is buy, build, operate, maintain, renew or dispose).

Enhancing your asset management system

There are a number of EAM systems used by oil and gas companies, including IBM Maximo, SAP and Oracle.

Deploying new technologies means that oil and gas companies are able to achieve greater efficiencies. They also allow management to: • Reduce budgets • Improve resourcing levels • Decrease operating costs

Considering new technologies

The world of asset management has become far more sophisticated. EAM’s ability to both interact with external systems and to use the data it holds more effectively means that it eliminates the siloed approach of distancing itself from the rest of the business.

EAM systems help organisations to:

One example of technology used by systems such as IBM Maximo is the ability to create a digital twin - in effect a virtual simulation of the asset, which can be used to improve the efficiency of predictive maintenance. This has been successfully trialled in the utilities sector, where power generators used predictive analytics and machine learning to calculate maintenance regimes that would:

• Cut costs

• Minimise downtime

• Reduce wastage

• Prevent asset failure

• Increase efficiencies

• Increase revenue generation

Whichever core system is used though, recent advances in technology mean that asset management systems are now far more sophisticated than they once were.

• Demonstrate compliance & safety

It is also possible to contain an engineering model, similar to the Building Information Modelling (BIM) models used on large infrastructure projects, within the asset management system. In addition to asset data it includes photography, location and performance data – whether for a refinery, offshore structure or pipeline.

The advantage of holding this information within the asset management system is that it can be shared with engineers and technicians out in the field, so that data being collected and collated is done in real-time. This is particularly relevant for those involved with critical maintenance and where automatic flags/warnings for explosive conditions or volatile environments can then be acted upon immediately.

Working in remote or volatile environments Working in remote locations and/or in a volatile environment is not unusual for many engineers looking after the company’s infrastructure and assets. Being able to access the central asset management system therefore contributes significantly to:

Data added on mobile devices can include:

• Ensuring health & safety compliance

• Digital and ‘written’ signatures

• Creating more effective business practices • Maintaining accurate ‘live’ data In addition, some EAM systems, such as IBM Maximo, enable integration with software running on mobile devices, such as Peacock Engineering’s Fingertip. Mobile devices can be housed in ATEX-compliant cases, allowing engineers to operate in highly volatile environments.

Combining the main asset management system with a mobile solution (such as IBM Maximo with Fingertip) allows both the on-site engineer and the head-office team to be completely updated in real time, which is particularly useful in critical maintenance situations.

• Specific job details • Exact locations using GPS • Images

What the future holds

With the current economic uncertainty and the increasing macro-economic challenges, focusing on cost-savings, streamlining business processes and developing capitalefficient strategies are essential.

The huge advances in technology in EAM systems in recent years, means that they can be a key component in: • Identifying maintenance savings • Minimising costly failures • Creating more effective business practices All of these contribute to helping the organisation achieve a competitive advantage, for a sustainable existence.

More information To find out more please contact us: Peacock Engineering Ltd

About Peacock Engineering Peacock Engineering Ltd was established to deliver a diverse range of Asset and Service Management solutions to asset intensive industries.

t: +44(0)20 3356 9629 e: info@peluk.org w: peluk.org Peacock House, Bell Lane Office Village, Bell Lane, Little Chalfont, Bucks, HP66FA, UK

Fingertip® Knowledge where it’s needed

Our consulting team is made up of long standing IBM Maximo professionals, each with an average of 12 years’ experience in the product and who, together, have amassed over 400 man-years of Maximo systems implementation experience.

From this knowledge and practical application, a proven and trusted process-driven methodology has emerged. With the methodology in place, the ongoing challenge is to improve delivery efficiency and provide affordable solutions, using a mix of services and systems provisioning models, to meet a broad range of industry verticals.

Reflex marine

Wellgrab simplifies fishing operations with new Electric Release Fishing Tool

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ellgrab has secured Research Council of Norway funding to support the launch of its new innovative fishing tool, the Wellgrab Electric Release Fishing Tool (WERFT). The WERFT has performed two operations in 2019 with WERFT version 1. The next generation WERFT version 2 is scheduled to be launched in Q1/Q2 2021.

The WERFT consists of a basic module and an accompanying tool pack with several special features. The innovative concept combines several functions into one tool. With

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a combined control and communication system, it enables safer and more cost-effective fishing and pulling operations. Further, by pairing digital capabilities with a versatile, multifunctional tool, the WERFT drives safer and more cost-effective fishing operations.

Current mechanical tools are often operated by the service operator pulling up or running down the wireline to which the tool is attached. When the geometry of the well is complex, this mechanical control is not precise causing unwanted misruns or failure. Designed to increase safety, the WERFT is controlled and activated from the surface meaning that at the touch of a button, the operator can easily connect to or from any object that must be fished out. The tool is applicable for retrieving plugs, all fishing operations and for relocating

Innovation showcase

downhole assemblies.

“As a team of innovators, we realised there was a functionality gap in the market and worked hard to deliver what is a genuine game changer,” Geir Magne Johnsen, CEO, Wellgrab, said. The technology pairs digital capabilities with a versatile, multi-functional tool, and will drive safer and more cost-effective fishing operations as a result.”

PARKER’S SCFF COUPLINGS AVOID LOSS OF FLUID AND HELP PROTECT THE ENVIRONMENT Parker Hannifin is expanding its FlatFace offering with the SCFF series. The SCFF series of couplings offers users several benefits ranging from low-leakage decoupling to the avoidance of air entrapment during coupling. The couplings, which are tested in accordance with ISO 7241-2, are easy to clean and very flat.

Whether being used in mobile hydraulics, transport, or the oil and gas industry, SCFF couplings are very resistant to vibrations and other forms of mechanical stress. The processes of coupling and decoupling are also fast and reliable: due to the inclusion of an ACME thread, no fluid escapes during these stages. The reliability of this system is enhanced by the swivel function together with the unique locking sleeve to avoid accidental disconnection.

SCFF plugs are available with pressure eliminator. Thanks to this innovative technology, it is possible to connect couplings in the presence of accumulated or residual pressure without any problems. A miniature valve automatically relieves the pressure in the connecting phase.

SCHLUMBERGER INTRODUCES STRATABLADE CONCAVE DIAMOND ELEMENT BIT Smith Bits, a Schlumberger company, has introduced the StrataBlade concave diamond element bit that improves the rate of penetration (ROP) in a wide range of rock types, while withstanding impact damage often associated with drilling interbedded formations.

“The StrataBlade bit is the latest addition to our threedimensional cutting elements portfolio, which expands our holistic drilling solutions offering and enables operators to enhance overall drilling performance in challenging formations,” said Jesus Lamas, president, Well Construction, Schlumberger. “With the introduction of this new technology operators can improve ROP, increase overall drilling efficiency and reduce well construction costs.”

The StrataBlade bit incorporates new geometry Strata concave diamond elements across the bit face, which increases cutting efficiency and results in higher instantaneous ROP with the same operating parameters.

In deep lateral wells where weight transfer to the bit is a challenge, the StrataBlade bit drills with higher ROP when compared with traditional PDC bits with flat cutters.

Improved cutting efficiency also means a better torque response at the bit for conformance to directional plans.

The StrataBlade bit has undergone field testing in North America, specifically in the Haynesville Shale and the Appalachian Basin. In the East Texas Travis Peak and Cotton Valley formations, the StrataBlade bit enabled an operator to eliminate two bit runs while drilling to 10,000-ft measured depth with an average ROP increase of 28 per cent compared to direct offset wells. In the Marcellus Formation in north-eastern Pennsylvania, the StrataBlade bit drilled an 8 ¾-in section with a measured depth of 3,149 ft in under 12 drilling hours. The operator achieved an on-bottom ROP of 264 ft/h, resulting in a 15 per cent improvement compared with average offset runs with other PDC bits.

CGG GeoSoftware continues innovation with new reservoir characterisation technology CGG GeoSoftware has released new versions of its cloud-ready reservoir characterisation and petrophysical interpretation software with innovative enhancements that boost performance and improve usability.

Jason Workbench 10.2 offers enhanced display options, upgraded QCs and monitoring, and more user-friendly interfaces. The Python machine learning ecosystem contains additional basic and advanced sample scripts and Jupyter notebooks, making it even easier for clients to build their own workflows. Optimizing performance continues to be prioritized, particularly within its geostatistical reservoir characterization technology.

The new features and functionality of HampsonRussell 10.6 include an interactive radon analyser, an AVO interpretation crossplot template, improved convenience in retrieving inversion models, greater parameter flexibility and a new inversion algorithm.

PowerLog 10.2 for petrophysical interpretation now offers improvements in handling big data, performance enhancements, and data preparation automation for patching curves. A complete automated log editing workflow is available through a collection of modules which includes Outlier Detection, Log Patching, and Synthetic Curve Generation. As a critical part of PowerLog’s patented workflow, Outlier Detection enables users to detect data spikes and anomalies and then replace bad data with patches or synthetic curves. The resulting high-quality curve data is essential in generating accurate interpretations, pore pressure predictions, and for use in seismic inverse modelling.

Capabilities in the Rock Physics software have also been enriched with new rock physics models, regression, curve fitting and an enhanced interface.

InsightEarth 3.6 now has new features, including the recently announced WellPath interactive well path planning technology. The WellPath QuickPlan workflow automates planning for

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Innovation showcase

large multi-well pads or platforms and builds all well plans simultaneously.

SYNECTICS’ 4K CAMERA RANGE DELIVERS HAZARDOUS-AREA SURVEILLANCE FOR OIL & GAS

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Synectics’ COEX camera stations are used in over 50 countries to secure and safeguard oil and gas assets operating in extreme conditions — from refineries, plants, and pipelines to offshore marine vessels and platforms. Projects protected by COEX cameras include the world’s largest gas-to-liquids plant and the most sizeable floating liquified natural gas facility ever built.

DRESSER NATURAL GAS SOLUTIONS LAUNCHES MULTIPOINT INJECTION FOR TEXSTEAM PUMPS Dresser Natural Gas Solutions (Dresser NGS), a provider of measurement, instrumentation and piping solutions to the natural gas distribution and transmissions markets, has launched a multipoint injection controller adjustment for its Texsteam pumps, through its Industrial Products Group (IPG).

Texsteam multipoint injection will be used in oil and gas wellhead chemical injection operations to distribute chemicals from a single chemical injection pump to multiple injection points.

Jeff Raynal, general manager, Dresser NGS IPG, said, “Texsteam multipoint injection offers increased flexibility by enabling users to distribute different flow rates to various end points with one pump head and a simple controller. This lowers capital spends by reducing the amount of equipment required for chemical injection. Instead of needing four pumps for four different wellheads, the operator will now be able to inject four wellheads with just one pump.”

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“With the lower oil price expected to increase P&A activity in the UKCS, we are offering a technology that won’t add rig time but will provide long-term barrier assurance to operators as they decommission assets.”

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Synectics has unveiled details of its new COEX 4K camera range. The launch makes Synectics the first technology specialist to guarantee +70°C certification and 4K capabilities for fixed, PTZ, and TriMode models. The COEX range offers the most comprehensive suite of camera stations on the market for hazardous-area (and safe-area) applications.

The global provider has a wellestablished reputation for specialist camera technology innovation based on customer-focused design, pioneering the world’s first explosion-proof (Ex certified) thermal camera in 2002.

The COEX camera range delivers outstanding image clarity, audio support, region of interest encoding, and cybersecurity essentials, including 802.1x port-based network access control, HTTPS web interface, and encrypted media streaming.

Fully compliant with ONVIF Profile S and T requirements, they integrate seamlessly with existing video management systems, including Synergy, and provide advanced video streaming options.

Synectics’ COEX 4K cameras also offer advanced, simultaneous multi-streaming of footage in H.264 and H.265 encoding formats providing triple-stream for 4K and quad-stream for TriMode variants.

This feature has some compelling benefits for customers seeking to maximize bandwidth and minimize storage costs.

All COEX camera stations, including the new 4K models, are manufactured from corrosion proof, electro-polished 316L stainless steel, and are performance tested before dispatch. With a certification temperature range from -55°C to +70°C, they provide continuous, reliable image capture in all lighting, weather, and operational conditions.

Innovation showcase

The Texsteam multipoint injection system works to a maximum operating pressure of 2500 psi with the solenoid assembly having only 10W power consumption. The electrical junction box is explosion-proof, dust-ignition proof, and raintight certified. The solenoid valves are Class I and II Groups C, D, E, F & G, Division 1 and 2. The multipoint system is used with the Class 1, Div 2 iCIP Solar package.

ACOUSTIC DATA LAUNCHES HIGHEXPANSION RETAINER FOR REALTIME METAL ALLOY BARRIER VERIFICATION Acoustic Data have developed a new slickline deployed high expansion retainer for cement and metal alloy plug and abandonment (P&A) applications. In the case of new-generation metal alloy plugs, the HEX-Retainer can be integrated with the company’s SonicGauge Plug Verification System (PVS) for realtime long-term barrier integrity monitoring purposes.

The SonicGauge PVS uses wireless communication in the form of acoustic telemetry to transmit downhole pressure measured below the barrier to surface, or alternatively, in deep-set applications, to a SonicReceiver unit that can be permanently installed above the plug or deployed via slickline, as required. The integrated HEX-Retainer solution has been designed to be runin-hole via a single slickline run and is compatible with a broad range of tubing and casing diameters.

Guy Mason, CTO at Acoustic Data said: “With the lower oil price expected to increase P&A activity in the UKCS, we are offering a technology that won’t add rig time but will provide long-term barrier assurance to operators as they decommission assets. Safety is our number one priority, and this solution gives operators the confidence to know that any plugged well is maintaining well integrity while complying with regulatory well monitoring requirements.”

The announcement follows the company’s launch of its new remote deployment model for its SonicGauge System to overcome travel restrictions relating to COVID-19. The solution enables operators to self-install a real-time wireless downhole monitoring system without requiring specialist engineers onsite.

The SonicGauge has been deployed more than 150 times and has 100+ years of accumulated downhole monitoring time globally.

MECHANICAL WELLHEAD CUT Baker Hughes has announced the successful launch of Terminator, its vessel-deployed subsea wellhead cutting system.

Using a first-of-its-kind mechanical wellhead removal method, the Terminator system has already proven its capabilities by successfully cutting a subsea wellhead from an abandoned exploration well owned by Wintershall DEA in Norway.

Baker Hughes worked with Wintershall DEA to cut the subsea wellhead from an abandoned exploration well in 360-metre water depth in only 35 minutes. By comparison, alternative abrasive cutting methods could take as long as five or six hours for the cut alone. The Terminator system can be deployed from a vessel and uses a mechanical cutter, rather than water jet cutting methods of conventional systems, to eliminate associated risks with high pressures. In addition, the system can reduce offshore personnel by two-thirds compared to conventional systems, requiring just two people instead of the typical six for water cutters.

The Terminator system can reduce fuel consumption with its 100-horsepower motor and is also smaller and lighter compared to the original 1000-horsepower abrasive water cutting system typically used on similar types of vessel-based operations. The Terminator technology is another example of Baker Hughes’ commitment to leading in the energy transition by helping customers decarbonize oil and gas operations.

The total operation with Wintershall DEA, from deck deployment to laying down the Terminator system, took just two and a half hours – saving the operator up to 12 hours compared to conventional systems. After the cut was complete, the subsea wellhead, conductor and spudcan were removed immediately in a separate run from the same vessel.

BAKER HUGHES’ TERMINATOR SYSTEM ACHIEVES INDUSTRY’S FIRST VESSEL-DEPLOYED SUBSEA 71

Final word

The growth of global discovered oil and gas resources Despite concerns that Covid-19 could drive down discovered volumes to their lowest levels in decades, exploration activity has been resilient this year. Found resources already exceed eight billion barrels of oil equivalent (boe) and are projected to settle at around 10 billion boe by year-end, Palzor Shenga, senior upstream analyst, at Rystad Energy reveals.

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bout 3.75 billion boe, or 46 per cent of total discovered volumes, are gas while liquid volumes are estimated at 4.31 billion boe. Yet-uncounted resources in finds like Sakarya in Turkey point to additional upside, meaning that 2020 will avoid returning to the multi-decade low seen in 2016 at just 7.7 billion boe.

The 73 new discoveries announced this year (through October) are evenly split between land and sea with 36 onshore and 37 offshore. Russia leads in terms of discovery volume, with 1.51 billion boe, while Suriname comes second with 1.39 billion boe and the UAE follows third with 1.1 billion boe.

Of the offshore volumes, which account for slightly over three-quarters of discovered resources, 33 per cent was found in ultra-deep waters, 38 per cent in deepwater areas and 29 per cent in shallow waters. Looking at the timing of the discoveries, the third quarter was the weakest with about 2 billion boe of new finds, compared to about 2.7 billion boe during each of the first two quarters.

Global oil and gas operators will chase plenty of additional volumes in wildcats planned for the final two months of the 2020, although some may not be completed until early 2021 and will therefore add to next year’s tally. We believe discovered volumes are likely to settle at around 10 billion boe.

Oil and gas companies’ exploration plans have included prospects with higher chances of success in mature areas, as well as high-risk, high-reward wildcats in frontier regions, resulting in some game-changing offshore discoveries. The willingness to invest in high-risk probes proves that E&P

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companies are not shying away from frontier basins – if prospects are promising enough.

Companies have experienced exploratory success in emerging plays in countries including Suriname, Guyana, South Africa and Turkey, as well as in proven mature regions such as Brazil and Norway.

Ranking companies by discovered volumes shows that Russia’s Gazprom is in the lead, ahead of Total and Apache. The latter two have found around 960 million boe and 700 million boe respectively of net recoverable resources this year, mainly thanks to three major discoveries in Block 58 off the coast of Suriname.

We expect that only about 4.5 billion boe of the 8 billion boe discovered so far this year will be produced by 2040, and in coming years annual discovered volumes are likely to settle at a new normal of around 10 billion boe per year.

We see two main reasons for this trend. First, oil and gas players are streamlining portfolios and exploration strategies and will scrutinize prospects more closely than before, thereby reducing the number of wells that will be drilled. A more stringent selection procedure for drill-ready prospects means that only the ones with the highest chance of success will see a spinning drillbit.

Second, companies will be less willing to drill high-risk wells in environmentally sensitive frontier areas, both for financial and environmental reasons. As a result, the full petroleum potential of areas like the Alaskan Arctic, Foz do Amazonas in Brazil and the Barents Sea may never be unlocked.

While fewer wells will be drilled, we expect improved data access and digitization will help operators pinpoint successful prospects with more accuracy. Today a large portion of exploration data is restricted. However, increasing access to data and the growth digital platforms will enable exploration teams to rapidly discover and access basin-scale data, and manage exploration opportunities using data sharing across multi-disciplinary teams.

Increasing use of digitization will reduce costs and make exploration procedures more standardized, and data sharing and collaboration means each operator will need to drill fewer wells to understand the subsurface. This will lead to higher productivity per well drilled.

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