4Subsea to monitor steel catenary risers on Bacalhau field in Brazil Protect against product loss with accurate pipeline monitoring ISSUE 54
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around 75 per cent between 2020 and 2030. Considering average natural gas prices from 2017-2021, almost 45 per cent of current methane emissions from oil and gas operations could be avoided with measures that would have no net cost. Policymakers have at their disposal wellestablished policy tools that have already been demonstrated in multiple contexts to drive these emissions reductions, for instance Leak Detection and Repair (LDAR) requirements, staple technology standards and a ban on non-emergency flaring and venting.
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4Subsea to monitor steel catenary risers on Bacalhau field in Brazil Protect against product loss with accurate pipeline monitoring ISSUE 54
Light and Smart Competitive, profitable, and cleaner
| AUTUMN 2021
Oil & Gas Technology
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Reducing methane emissions As the world’s attention focussed on the two weeks of intensive negotiations at COP26 in Glasgow one of the key topics on the agenda will be the role of fossil fuels in the future energy mix. It is accepted that over time the contribution of fossil fuels will diminish although at what rate it can be reduced is still open to debate. One thing is clear it will still have a part to play for several decades. With that in mind it is crucial that the industry does all it can to reduce its environmental footprint. Fossil fuel operations generated nearly onethird of all methane emissions from human activity. Action on methane is therefore one of the most effective steps the energy sector can take to mitigate climate change. Global methane emissions from oil and gas operations fell around five per cent in 2020 to 76 Mt, mostly due to decreased oil and gas production, and are likely to rebound in 2021. Conversely, the International Energy Agency’s (IEA) Net Zero Emissions by 2050 Scenario requires that total methane emissions from fossil fuel operations fall
Methane emissions are the secondlargest cause of global warming today. They come from a range of anthropogenic and natural sources – in the energy sector, from oil, natural gas, coal, and bioenergy. Due to the near-term warming potential of methane emissions, reducing their level will be critical to avoid the worst effects of climate change. IEA analysis estimates that it is technically possible to avoid around threequarters of today’s methane emissions from global oil and gas operations. Moreover, considering average natural gas prices from 2017 to 2021, almost 45 per cent of these emissions could be avoided at no net cost, as the cost of abatement is less than the market value of the additional gas that could be captured. Despite increasing efforts from industry and policymakers to reduce methane emissions from oil and gas operations, significantly greater ambition is needed to achieve reductions compatible with a net zero pathway. Certain policy measures that have been well established in multiple settings could very effectively put methane emissions on track. Mark Venables Editor Oil & Gas Technology
Oil industry should invest in bio solutions for oil spills 6
Updates The latest news from around the globe
16 Analysis: Ten trends Oil and gas CIOs must be aware of these trends — including accelerating digital innovation, rethinking vendor partnerships, and reacting to climate change — to ensure that their organizations are agile and resilient in an increasingly complex future.
18 Protect against product loss with accurate pipeline monitoring Pedro Barbosa, Product Owner, at Fotech, a BP Launchpad company, looks at the current threats to pipelines and explores how advanced distributed acoustic sensing (DAS) technology is helping operators to best monitor and maintain the integrity of their networks.
22 We have lift-off for drone technology
Gary Cutts, Challenge Director, Future Flight Challenge, UK Research and Innovation explains how drones look set to play a bigger role in the energy sector over the coming decade
25 Follow the four commandments Steve Bruce, product director, Idox explains why engineering document management is crucial for agile offshore operators
28 Non-stop developments Oil and gas Technology spoke to Shuja Al-Ajmi, deputy CEO of Mina Al-Ahmadi Refinery about the Clean Fuels Project
30 Research reveals rapid increase in levels of Industrial IoT maturity According to the new report 81 per cent of oil and gas businesses have accelerated or intend to accelerate their deployment of IoT in response to Covid-19 pandemic. Oil and Gas Technology looks at the reasons behind that increase of velocity.
32 Light and smart
Jesús Fernández, product manager at ZALUX explains the role that lighting can play in improving environmental performance
34 Competitive, profitable, and cleaner Astrid Poupart-Lafarge, president of oil and gas, Schneider Electric explains the role that data plays in optimisation and improving environmental performance
36 Ageing well Neil Ballinger, head of EMEA at EU Automation, explains why implementing a proactive obsolescence management plan is crucial.
38 The new generation of automated domain software for production optimization Across the energy value chain, a new breed of domain software applications is rapidly becoming available. As Halvard Ellingsen, CEO, Turbulent Flux explains these applications are cloud-native and adaptable, with new functionality continuously deployed.
40 Escalating cyber threats Nigel Thorpe, technical director at SecureAge looks at the increase in cyberattacks on energy, oil and gas companies and suggests it’s time for a new approach
42 Are oil and gas and renewables truly worlds apart? James Fisher’s Giovanni Corbetta, Managing Director, James Fisher Marine Contracting, takes a step back for a big picture look at the two sides of the energy transition (ET)
45 Technology focus A look at the most innovative new products and services
48 Final word: Record cash flows and peak uncertainty How will the upstream industry use an incoming $1 trillion price windfall? Should Asian governments be doing more to resuscitate declining gas production? And what is the future for exploration in this region?
Are oil and gas and renewables truly worlds apart? 03
ADC Energy identifies upgrade to reduce rig emissions by almost 5,000 tonnes per year ADC Energy, a specialist provider of integrated rig inspections, has completed a project with a major rig owner which identified that an upgrade to Dynamically Positioned (DP) rigs power systems can reduce carbon emissions by almost 5,000 tonnes per year. Typical DP drilling units operate in HV split-bus, or open-bus, configuration with the power management switchboards operating in silos, using an independent island philosophy. However, this mode from a redundancy perspective requires more engines to be online than may be required for the total operational loads, creating a potentially greater emission output. By upgrading existing rig power management systems to allow for closed-bus mode, which ties the switchboards together, this allows the power plant to run with less engines and optimal loads, therefore delivering a more efficient power source. ADC’s recent project highlighted that DP rigs operating in closed-bus configuration can successfully reduce annual CO2 emissions by 4,800 tonnes per year – delivering a fuel saving of $620,000 per year - while reducing engine running hours by 20 per cent. With the number of engines required to be online at one time lowered, the enhancement also provides operators with greater maintenance schedule flexibility, which can create potential maintenance savings of up to $150,000 per annum. Austin Hay, Director at ADC Energy said: “There is significant pressure on the oil and gas industry to decarbonise current assets and the findings of our recent project effectively highlight how upgrades to existing systems can actively reduce the carbon footprint of operations. “We recognise this enhancement requires considerable investment from rig owners and operators but as the sector continues its efforts to deliver more sustainable operations, this capital is essential to support net zero goals. Existing rigs and vessel are critical components in the energy transition, and we are already working with a number of clients to advise them through this process to ensure that assets continue to operate safely and efficiently with minimal environmental impact.” ADC Energy currently employs 76 specialist personnel across its strategic bases located in Aberdeen, UK; Houston, Texas; Jakarta, Indonesia and Kuala Lumpur, Malaysia.
UK oil and gas sector takes global lead on methane reductions The UK offshore oil and gas industry has made a new public pledge to cut its methane emissions just a month ahead of the landmark United Nations Climate Change Conference (COP26). OGUK, the leading representative body for the sector, has signed its commitment to the Methane Guiding Principles, developed by a coalition of industry, international institutions, non-governmental organisations, and academics. The principles will ensure OGUK and its member companies work to continually reduce methane emissions, improve accuracy of methane emissions data, advocate for policy and regulations on methane and increase transparency in reporting. It is the latest in a series of moves by the body that marks the UK sector as one of the most ambitious in its drive to produce sustainable oil and gas. The announcement comes after OGUK launched an ambitious Methane Action Plan on behalf of the sector – a key action of the North Sea Transition Deal agreed with Government this year. The plan sets out how the sector will reduce potent methane emissions 50 per cent and stop all routine flaring by 2030. It was announced prior to the recent EU-US pledge to cut these emissions 30 per cent by the same year. Industry has been proactive in its drive to bring down all emissions for some time. Global independent E&P company, Neptune Energy, recently partnered with the Environmental Defence Fund (EDF) in September this year to test a first-of-its-kind approach, using drones to enhance methane emissions measurement on its operated Cygnus gas platform in the Southern North Sea. The findings could help establish a more accurate, science-based benchmark for the wider upstream industry to measure methane and identify mitigating actions. Commenting on the principles, OGUK Emissions Improvement Manager Thibaut Cheret said: “Methane has a short lifetime but has up to 80 times the impact on the atmosphere than that of CO2, so it’s essential we drastically cut down on these emissions. “The UK industry is working proactively on this – by 2030, we will have stopped all routine flaring and by 2023, all companies will have their own ambitious methane reduction plans in place. “At current, natural gas plays a major role in meeting global energy demand and will do for some time to come. “Through our commitment to the principles, our Methane Action Plan, and the North Sea Transition Deal alike, our sector will clean up the production of resources that we will continue to need while we move towards a low-carbon energy mix.”
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UK oil and gas industry can lead the way to a low carbon future The UK could be storing 100 million tonnes of CO2 a year under its surrounding seabed by 2050 – equivalent to a quarter of its current annual emissions, according to a report from OGUK, which represents the nation’s offshore oil and gas industry. OGUK’s Energy Transition Outlook report will say that carbon capture and storage systems already in development will cut the industry’s own emissions and enable many other heavy industries to decarbonise, including power stations, cement and steel makers, and chemical manufacturers. The report will say that the rock formations under the North Sea and east Irish Sea have the capacity to hold much more CO2, with a total capacity of 78 billion tonnes. This is about 190 times greater than the UK’s own annual emissions of 400 million tonnes. It will add: “This … creates the opportunity for annual storage of at least 100 million tonnes of CO2 a year by 2050. This will require at least 5 billion tonnes of cumulative CO2 storage capacity to be developed from the total potential of 78 billion tonnes.” The OGUK report will confirm the sector’s own emissions have fallen by 10 per cent (1.8 million tonnes) since 2018 and are on track to achieve its target of a 50 per cent cut by 2030. It follows the publication this week of the government’s Net Zero Strategy which says that carbon capture and storage, linked with mass production of low-carbon hydrogen, will be essential if the UK is to meet its carbon reduction targets.
Hydrogen is a highly versatile fuel which can replace natural gas in boilers and cookers or be used to power lorries and other heavy vehicles for which batteries are impractical. By 2050 hydrogen could comprise 20-35 per cent of UK final energy consumption, the government’s strategy suggests. Such a system would involve splitting natural gas to give hydrogen plus CO2. The hydrogen could be piped into homes and businesses or transported to fuel depots, while the CO2 would be permanently stored in the UK’s new offshore CO2 repositories. The OGUK report will say: “The oil and gas sector has unique experience in implementing and operating large offshore infrastructure projects. This ability and understanding is key for the success of carbon capture and storage.” It will also say that the UK’s oil and gas industry can lead the development of both technologies: “Hydrogen is an important technology opportunity for the UK and is required at scale to achieve national decarbonisation objectives.” “The UK’s offshore oil and gas industry is changing,” Mike Tholen, OGUK’s sustainability director, said. “Our members are breaking ground today on projects and technologies that will revolutionise the UK’s energy systems. Those technologies will remove greenhouse gases, increase our energy security and resilience, and help meet the UK’s goal of becoming carbon neutral by 2050. “They will also create jobs. It means that people from Liverpool to Hull and from Shetland to Southampton could benefit economically from achieving net zero. “Our report also shows, however, that these new technologies will need long-term support and investment, especially in their early years. That means support in both terms of overall policy and in the way they are financed. This is a project that will take some years, but it is also one that will help secure our nation’s low carbon future.”
Testing confirms CRP Subsea’s Bend Stiffener prolongs the fatigue life of a power cable CRP Subsea and Hellenic Cables have completed dynamic cable testing at the University of Exeter, as part of the EU-funded MaRINET2 research programme. The results show that when tested with a CRP Subsea Bend Stiffener (protecting it against overbending) the power cable survived 3.7 times as many cycles and was on average 72.5 per cent stiffer than the power cable alone. These results highlight the importance of a Bend Stiffener’s presence to extend the fatigue life of the system to be used in future Floating Offshore Wind (FOW) applications. CRP Subsea and Hellenic Cables collaborated to jointly apply for the MaRINET2 programme, as both companies are looking to increase the lifespan of dynamic subsea cables. The testing at the University of Exeter used a dynamic cable designed and manufactured by Hellenic Cables and a Bend Stiffener designed and manufactured by CRP Subsea. The power cable (only) and power cable with Bend Stiffener were individually tested to compare both performance and fatigue. John Duggan, Principal Design Engineer at CRP Subsea, states: “These results are encouraging but expected and explain why the use of a CRP Subsea Bend Stiffener in such a system is critical. The CRP Subsea Bend Stiffener material has undergone an extensive and rigorous material qualification. This along with the comprehensive design methodology, manufacturing, and quality systems have been fully reviewed and approved by Lloyds Register. Our Bend Stiffener is designed to maintain a cable or flexible pipe above a given minimum bend radius in a dynamic application. This, in turn, increases the life of the product by protecting it against damage and fatigue, which can result due to over bending.” John Duggan, added, “It is imperative that we use our 25+ years’ experience of supplying Bend Stiffeners to all the major oil and gas manufacturers, without any failures in service, to support dynamic cable protection for FOW.” George Georgallis, Head of R&D and Cable Engineering for Hellenic Cables commented: “At Hellenic Cables we are always looking forward in collaborating with industrial and academic partners involved in the offshore industry to promote and validate innovative concepts. The positive outcome of the fatigue test of a dynamic power cable coupled with a bend stiffener at the Exeter DMaC facility is very encouraging.” The study is related to one of the key challenges for
Floating Offshore Wind (FOW) developers, which is to ensure the long-term integrity of the dynamic cable, connecting the floating platform to the Offshore Sub-Station. Whilst dynamic cable assemblies are recognised as a key technical risk, the sector is not at a commercial scale yet, this funded research and development support is required to demonstrate and enhance dynamic cable solutions for FOW. Professor Lars Johanning, Project Lead at the University of Exeter, explains: “Floating offshore wind power will be a vital component in achieving global Net Zero targets. It will also have a profound effect on the economy in Europe and globally, creating new jobs in the supply chain and providing a key component for the post-pandemic green recovery. We are extremely excited working with innovative companies in the development of subsystems for the floating offshore industry.” The University of Exeter performed two tests. Firstly, the performance characterisation tests that
involved bending the cable to a 3.7° angle at the headstock whilst holding a constant force of 40 kN, 60 kN and 80 kN at the tailstock at a 10s cycle period. Secondly, the fatigue testing involved bending the cable to 4° whilst holding a constant force of 80 kN. The cycle period was steadily decreased from 10s to 1s (to minimise overall test duration). The test plan was identical between the power cable (only) and the power cable with bend stiffener combination (including the change in cycle period). Bend Stiffeners are used to protect cables and flexible pipelines from over bending at the termination point. Manufactured from an elastomeric material, the Bend Stiffener is suited to the constant wave and currentinduced motion of dynamic installations and can also be used for static applications. The conical shape of the Bend Stiffener provides a gradual increase in the overall stiffness between the flexible pipe, umbilical or cable, and the termination to prevent over bending at the termination point.
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Stena Drilling advances digital transformation
Stena Drilling, an independent drilling contractor, announces it has acquired a minority stake in and formed a three-year technology partnership with SmartChainServices (SCS), a Cambridge-based (UK) blockchain technology start-up. The announcement follows a six-month proof of value project, where Stena Drilling applied the power of SCS’ ClearDapp, a blockchain and smart contract technology, to reduce and eventually eliminate complex transactions related to IADC reporting and payment-for-rig-performance. Now, the companies will work together to further develop smart contract solutions for the energy sector. With aims to automate and execute the payment cycle, the technology partnership will offer the energy industry new contractual models based on milestones such as drilling speed, carbon intensity or fuel usage – all automatically validated through data. “We’re delighted to enter a technology partnership with SCS,” Colin Dawson, digital business transformation manager of Stena Drilling said. “Over the past six months, it has become clear that blockchain smart contract technology has the potential to transform how the energy sector does business. “We have a unique vantage point for this technology development as we continue to advance our own digital transformation. The sector faces tighter scrutiny around ESG
from investors and society as the energy transition takes hold, and smart contract solutions offer a transparent way to demonstrate impact via tracking Scope 1 emissions at the rig, for example. We’re proud to play our part in progressing the sector.” John Hanson, CEO of SCS said: “Stena Drilling is the perfect partner for us, given its world class fleet and forward-thinking approach to digitalisation. There’s a huge opportunity for those in the sector that adopt blockchain technology to reduce admin burden, track transparency and reduce cost. Together, over the next twelve months, we will work very closely with the Stena Drilling team to fundamentally change business models in the energy sector, particularly those based on drilling performance.” The companies are scheduled to trial the ClearDapp solution with live data in Q4 2021, in collaboration with a major oilfield operator. ClearDapp is built on R3’s Corda platform, and in Q1 2022, SCS will deliver per-to-peer transactions via the beta version of Corda’s ‘payment’ module/SDK.
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4Subsea to monitor steel catenary risers on Bacalhau field in Brazil 4Subsea has been awarded a service agreement to monitor steel catenary risers on the Floating Production Storage and Offloadings (FPSOs) on the Bacalhau field in Brazil. The service is delivered using 4insight Subsea Asset Integrity which combines advanced strain and motion sensors to measure vessel motions and riser load with algorithms to calculate pressure and hoop stress, accumulated riser fatigue damage and damage rate to monitor the integrity and risks to steel catenary risers on the FPSO. The digital service is delivered as monitoring dashboards and data fed into Equinor’s data platform for further analysis. The riser monitoring service provided at Bacalhau is an application of 4insight Subsea Asset Integrity, a digital service that continuously monitors the physical integrity of different subsea and offshore infrastructures using retrofittable autonomous sensors and algorithms and machine learning methods optimised for different assets and measurements. The results are presented as easy-to-interpret insights and dashboards, simplifying the complex analysis and effectively support critical decisions. The data is also available through open APIs, which the Operator’s own data platforms can access for further analysis. Peter Jenkins, CEO of 4Subsea, said: “We are pleased to be chosen to monitor the integrity of the risers at Bacalhau. These services have proven to reduce operational risk and costs during complex operations and are great demonstrations of the digital transformation of offshore operations to increase safety.” The same sensors, technology, and algorithms have been adapted to monitor fatigue and integrity on offshore wind installations to monitor the integrity of the construction and cables, demonstrating the versatility and robustness of 4Subsea’s sensor technology and digital services..
DOF Subsea and Ocean Floor Geophysics form strategic alliance TechnipFMC and Talos Energy enter strategic alliance to provide carbon capture and storage TechnipFMC and Talos Energy have entered a long-term strategic alliance to develop and deliver technical and commercial solutions to Carbon Capture and Storage (CCS) projects along the United States Gulf Coast. The alliance combines Talos’s offshore operational strength and sub-surface expertise with TechnipFMC’s extended history in subsea engineering, system integration and automation and control. Cultivated through a shared vision to responsibly deliver CCS solutions that will help to reduce the global carbon footprint, this innovative partnership will accelerate offshore CCS adoption with reliable, specialized CCS systems. Under the alliance, the companies will collaborate to progress CCS opportunities through the full lifecycle of storage site characterization, front-end engineering, and design (FEED), and first injection through life of field operations. This further advances the companies’ leadership in the emerging Gulf Coast CCS market, building on Talos’s recent successful award as the operator of the only major offshore carbon sequestration hub in the United States. Jonathan Landes, President, Subsea at TechnipFMC, commented: “We are pleased to partner with Talos to deliver offshore CCS solutions that will help reduce CO2 emissions during the energy transition. This alliance capitalizes on our collective expertise and TechnipFMC’s position as a system integrator and architect to deliver a reliable industrial-scale solution for CCS.” Bob Abendschein, executive vice president and head of operations at Talos, commented: “We are excited to announce this strategic alliance with TechnipFMC and to work collaboratively as we continue to execute on our strategy to scale our CCS business. Combining the technical expertise of both companies solidifies our market leadership in delivering integrated CCS solutions to lower industrial carbon emissions and create a positive impact in the communities where we work and live.”
Ocean Floor Geophysics Inc. (OFG) and DOF Subsea AS (DOF) have entered a strategic alliance for Autonomous Underwater Vehicle (AUV) services to the global offshore industry. The partnership will effectively leverage the two businesses’ recent collaboration in the development of the OFG AUV non-contact integrated Cathodic Protection (iCP) inspection system and enable the sharing of resources on several pipeline inspection and geohazard surveys. It will also provide the framework for a coordinated response to the increasing demand for AUV surveys. OFG’s iCP technology delivers greater efficiencies during AUV pipeline and infrastructure inspections by allowing for anomalies and the overall system health check to be analysed in near real-time offshore. Its miniaturized electronics also simplify
integration and deployment on light logistics AUVs, ROVs and shallow water active towfish for pipeline, cable, structure, and umbilical inspection. Marco Sclocchi, EVP of DOF North America said: “Since our first project together in 2018 to prove the iCP technology on an AUV pipeline inspection survey, we have found that there is a clear alignment between our two companies in performing safe operations and providing the highest quality data in the market. This alliance will also enhance the global footprint of both DOF and OFG through the coordination of asset utilization enabling us to expand our existing operations.” Matthew Kowalczyk, CEO of OFG added: “DOF Subsea has a proven track record of performing AUV pipeline inspections around the globe and the introduction of iCP into the AUV market removes the final barrier for fully autonomous inspections. We have already worked together to successfully deploy the iCP systems on AUV and ROV projects for major oil and gas operators across three continents and we are excited to continue our work with DOF Subsea to build on this offering.” In addition to the iCP technology, the shared resources will provide the alliance with a full suite of specialized sensors such as a CathX laser and photogrammetry system and HiSAS synthetic aperture sonar on top of the standard sensors capable of performing geophysical and pipeline inspection surveys. The partnership will also allow both companies to better serve and expand their client bases in the offshore energy and seabed mining industries with an emphasis on safety, data quality and increased autonomy.
Pioneering offshore green hydrogen jack-up rig production concept Aquaterra Energy has signed a partnership with renewable hydrogen producer and supplier Lhyfe and offshore drilling contractor Borr Drilling to develop an innovative concept for offshore green hydrogen production in the North Sea. The organisations behind Project Haldane, will develop an industrial scale offshore green hydrogen production concept, through the deployment of an electrolyser system on a converted jack-up rig. Reliable winds far out in the North Sea are an exceptional renewable resource, yet remote locations create challenges around grid connectivity and intermittency of supply. This unique, flexible solution will solve this issue by providing an off take for the electricity produced in the immediate vicinity of the windfarm and aims to use existing platforms, pipelines, terminal infrastructure, and offshore equipment leveraging the existing infrastructure to reduce costs. With governments pushing net zero initiatives forward, this concept offers an alternative deployment of existing assets that provides both a source of green hydrogen and enhances the commercial feasibility of remote offshore wind projects. “With our expertise in complex offshore operations and fleet management, Borr Drilling will leverage its core capabilities to evaluate the adoption of this alternative energy source in an environment with a large untapped potential. While we will continue to work in our traditional drilling market, this project reinforces our ambition to continuously improve the sustainability of our activities and align our service offering with the changing expectations of our customers and stakeholders.” says Darren Sutherland, Director of Operations at Borr Drilling. “Lhyfe is already producing renewable hydrogen in industrial quantities onshore, with a direct connection to renewable energy, pumping sea water and purifying it to feed the electrolysis process. This is hence a production process already considering offshore harsh conditions. Over the last few years, we have also been working on different projects to deploy our production process offshore. Offshore wind offers the greatest potential for sustainable hydrogen production because of the cost effectiveness that can be achieved through scalability and technological innovation. The market is yet to deliver a flexible solution that benefits from the existing infrastructure in the North Sea and Lhyfe wants to be at the forefront of this change by creating a world-first green hydrogen production of this kind,” says Matthieu Guesné, CEO at Lhyfe. “With years of experience in successful delivery of complicated offshore jack up operations, complex structural projects and offshore process systems we are excited to be the interface that brings together the interest of Lhyfe in offshore markets and expands on Borr Drilling’s expertise in jack-up rig equipment. Our unique value here is that we are multilingual in terms of the engineering and operational needs of oil and gas assets, and green energy processing systems. We’re looking forward to taking this from concept to reality,” says James Larnder, Managing Director at Aquaterra Energy. While the concept is still in its early stages, the consortium welcomes any interested parties to submit enquiries.
Oil industry should invest in bio solutions for oil spills Biological dispersants enhance the breakdown of the more toxic chemicals in crude oil better than synthetic chemical dispersants, a new study shows. Scientists at Heriot-Watt University in Edinburgh tested how a synthetic and biological dispersant can enhance the breakdown of oil in the ocean. The study was focused on the Faroe-Shetland Channel, a deepwater subarctic region with a lot of oil and gas activity. The study shows that biological dispersants enhance the breakdown of oil pollutants in the event of a spill. “We compared the performance of Finasol, a globally stockpiled chemical dispersant for treating oil spills at sea, and rhamnolipids which are a natural biosurfactant,” Dr Tony Gutierrez said. Gutierrez has studied oil-degrading
bacteria since before the Deepwater Horizon event in 2010, one of the largest spills on record. “We wanted to find out how Finasol affected the response of oil-degrading bacteria and their breakdown of crude oil when compared to this natural biosurfactant,” he said. “When Finasol was used, we saw less of the bacteria that are most important to break down aromatic hydrocarbons, which are the most toxic chemicals in crude oil. “The biosurfactant did not suppress these oil-eating bacteria, so more of the aromatic hydrocarbons were degraded when it was used. Developing technology to cheaply mass-produce biosurfactants like rhamnolipids would give the oil industry a greener, eco-compatible alternative for combatting oil spills rather than using synthetic chemical dispersants.” This research was conducted in collaboration with the Water & Environment Group at the University of Glasgow, where Dr Umer Zeeshan Ijaz is at the forefront of developing DNA based informatics to facilitate microbial community surveys in diverse environments. “With the recent technological advancements in microbial in situ omics data analytics, we are now better equipped to unravel how microbes interact with the environment and can harness their full potential in designing biodegradation and bioremediation strategies,” Ijaz.
Ten Trends Oil and gas CIOs must be aware of these trends — including accelerating digital innovation, rethinking vendor partnerships, and reacting to climate change — to ensure that their organizations are agile and resilient in an increasingly complex future. 16
lobal oil and gas markets are poised between two competing drivers — rising pressure to decarbonize energy provision and increasing demand for energy in developing economies. Executives must find new ways to maintain competitiveness and growth. “The unique stresses of 2020 have elevated three business imperatives for 2021: optimizing business performance, creating new capabilities and strengthening technology foundations,” Simon Cushing, Senior Director Analyst, Gartner, says. “The 10 key trends in this report, individually and in combination, reflect reformation of the industry in the face of complex growing challenges.” CIOs who understand these trends can enable breakout performance that will differentiate them and their organizations in the months ahead.
Trend 1: Enterprise capabilities diverge as new business strategies emerge
As individual business strategies become more nuanced and differentiated, companies will need novel enterprise capabilities to facilitate implementation. For example, refining companies are exploring biofuel and bioplastics production and deepening their presence in regional petrochemicals products. Oil and gas CIOs will need to facilitate these business innovations by incorporating composable architecture principles in the design of the new enterprise architecture.
Trend 2: Accelerating digital innovation is now table stakes for CIOs An increase in discretionary cash flows and strong balance sheets in 2021 are accelerating digital innovation in the oil and gas industry. According to the Gartner 2021 CIO Survey, 87% of CIOs expect their digital programs to increase or stay the same in 2021. This commitment to digital innovation is a relatively new priority for oil and gas companies. In 2019, it was ranked the third-highest priority for CIOs, and in 2014, there was no specific funding allocated to it. According to Gartner, 85% of CIOs in the oil and gas industry have assumed responsibility for creating a change-enabling technical platform and 79% are working to build a stronger change leadership culture in IT. CIOs will need to reorient themselves toward value delivery by introducing service delivery models that replace cost-based IT siloes with valuebased IT products.
Trend 3: Digital twins drive transparency and automation Digital twins can deliver value across the business via the increased integration of internal systems, human activity, and external ecosystems. A digital twin is a virtual representation that serves as the real-time digital counterpart of a physical object or process. Digital twins are trending because of their capacity to improve the performance of business assets. Digital twins improve operational efficiency, prevent downtime, reduce maintenance and maintenance costs, and allow for more effective collaboration between experts and operators.
Trend 4: Comprehensive engineering creates intelligent assets To improve outcomes, such as production efficiency, uptime and yield, oil and gas companies are supplementing traditional monitoring and control systems with additional sensors, cloud-based data aggregation platforms, advanced analytics, and AI. According to the Gartner 2021 CIO Survey, as many as 50% of oil and gas companies plan to increase
investments in analytics, AI/machine learning (ML), automation, IoT and cloud this year. CIOs are responsible for creating intelligent asset capabilities using the increased budgets.
Trend 5: Key vendor partnerships define enterprise platforms Traditionally, oil and gas companies have separate owners for managing IT vendors versus the engineers with whom vendors’ partner. However, COVID-19 pushed CIOs of oil and gas organizations to reconsider traditional vendor engagement. While oil and gas CIOs continue to take a lead in their relationship with large IT vendors, they are also developing more open partnerships with a small number of key vendors in areas such as engineering. The distinguishing characteristic of these vendors is their ability to offer an integrated suite of technologies strong enough to serve as a subplatform for one domain hub within their emerging enterprise platform. “CIOs need to have a strong, but appropriately balanced, voice in managing these partnerships,” says Cushing.
Trend 6: Reliance on AI becomes more widespread and less visible AI/ML are quickly gaining acceptance in the oil and gas industry. Gartner survey data suggests that oil and gas CIOs list AI/ML/analytics and the industrial IoT as the top game-changing technologies in 2021. Several trends in AI technology and approaches promise to increase AI accuracy and deployment speed and reduce data science effort. As more decisions involve AI input, the reliance on AI will become more widespread. CIOs will need to stay on top of AI developments and evaluate and roadmap the development of AI capabilities.
Trend 7: Connected field workers drive efficiency and reliability Many oil and gas companies have sold assets, reduced capital and operating expenditure and shed workers after the events of 2020. The financial and human resource scarcity has compelled organizations to explore opportunities to harness digital technologies in better ways as well as manage risk and improve productivity in difficult conditions. While remote operations are now well established, oil and gas CIOs must focus on increasing adoption of technologies like augmented reality and machine vision, cost-effective wearable location devices and increased connectivity on sites.
Trend 8: Establish a roadmap to avoid carbon management chaos
In the next decade, oil and gas companies will increase their focus on reducing greenhouse gas (GHG) emissions as conversation around climate change become more intense globally. Many oil and gas companies are committing to reducing GHG emissions to net-zero between 2030 and 2050. To make this vision a reality, they have started investing in clean energy solutions such as wind and solar power. CIOs need to provide appropriate IT infrastructure, services, and talent to meet emerging carbon requirements. They must also start due diligence early because the market for these solutions is immature and implementations will be complicated.
Trend 9: Face the challenge of attracting fresh talent Post 2020, talent retention has become a struggle for many industries, and the oil and gas sector is no different. Along with the health and safety challenges that have emerged during the pandemic, the industry is challenged with negative perceptions related to climate change. This makes retention of top talent difficult. CIOs can play an active role in creating an attractive and rewarding place to work in a changing societal and economic context. Oversupply of crude and decreased demand during 2020 hit the global oil and gas industry hard, and the result was mass layoffs across the US as cash flows reduced. The need for digital workers is a new phenomenon for this sector and finding appropriately skilled talent is even more challenging. CIOs will need to reengineer the IT operating model to offer tangible career development based on premium digital skill sets, thereby attracting the right talent to the industry.
Trend 10: Multiple disruptions yield hybrid reformation of IT operating model Disruptive forces such as the cost reductions due to demand-supply challenges since 2020, growing demand for new systems and more IT agility are driving significant changes to IT operating models. While oil and gas CIOs do not expect another year like 2020, they know disruptions will continue in the sector. Oil and gas CIOs are facing a sustained period of constant flux. These organizations need to provide a hybrid IT operating model that balances new and traditional capabilities against a continuously evolving set of business priorities. This will include reskilling the IT workforce, accelerating digital transformation, improving cybersecurity performance, and establishing a composable computing landscape for agility.
Protect against product loss with accurate pipeline monitoring Pedro Barbosa, Product Owner, at Fotech, a BP Launchpad company, looks at the current threats to pipelines and explores how advanced distributed acoustic sensing (DAS) technology is helping operators to best monitor and maintain the integrity of their networks.
il and gas pipeline operators are under enormous pressure to reduce risk across their networks while simultaneously improving sustainability and making cost savings. This can ultimately be achieved through effectively monitoring and maintaining the integrity of the pipeline networks to minimise product loss. Product loss is typically caused by one of two reasons: leaks resulting from pipeline failure through corrosion or mechanical damage or theft-related events. Failure to monitor against these threats adequately can easily cost an operator millions in lost fuel from leakages and stolen product. Leaks also pose a significant risk of, and the cost associated with, environmental damage to the surrounding area. In North America alone, there were 578 reported integrity incidents, with an associated cost of
more than USD335 million, in 2020. For example, in October 2021, more than 550,000 litres of oil spilled into the waters 8km off Southern California after an anchor allegedly caught on a subsea pipeline at a depth of about 30m, ruptured it and dragged it approximately 30m along the ocean floor. According to the US Coast Guard, the section that was dragged was 1.2km long and the tear through which the oil escaped was 30cm wide. The vast amount of oil that leaked into the water is partially down to the Coast Guard’s near 12-hour delay in responding to reports because they didn’t have “enough corroborating evidence”. In another incident in 2020, 1.2 million gallons of product seeped into the environment from a crack in the Colonial Pipeline. There was a leak that went undetected for days and associated
costs are estimated to be approximately USD10.3 million, with at least USD2.5 million expected for the environmental clean-up of the contaminated soil and groundwater. Theft of product from hot-tapping is also a key issue and is a growing problem worldwide. For example, in South Africa in 2020, the stateowned pipeline operator Transnet recorded over 80 incidents of theft and attempted theft after tampering with infrastructure. The company, which operates 3,800km of high-pressure petroleum and gas pipelines, estimated that in one major incident, 60,000 litres of crude oil was spilled into the environment following an attempted theft. There have been similar cases in South America, the Middle East, the US, the UK, India and Mexico among others.
Issues with existing technologies Monitoring for leaks is typically achieved using internal based systems and external based systems. Internal based systems – such as mass balance and real time transient modelling (RTTM) – use computational pipeline monitoring (CPM) to calculate different operational conditions and infer the presence of a leak. However, as such, they tend to have very low sensitivity to small leaks and long detectability times. As a result, leaks are often missed or alarms are raised when large quantities of product have already been lost. Alternatively, external based systems such as Fibre Optic Sensing take direct measurements of different response dynamics associated with the leak, such as the noise produced by the orifice leak. This provides a quicker detection of smaller amounts of product. External based system such as right-of-way surveillance use ground patrols and aerial surveillance are to spot any unusual activity. However they do not provide continuous detection of events. As a result, large sections of pipeline might be entirely unmonitored and extremely
vulnerable to accidental damage or even criminal threats for large periods of time. There is a critical need for a continuous monitoring solution that enables operators to detect leaks and theft attempts more accurately and quickly, supporting the pipeline operator in its efforts for product loss prevention. There is a common requirement to detect a leak equivalent to one per cent of the flowrate of the pipeline in North America. In a pipeline transporting 100,000 barrels of oil per day, that equates to 1,000 barrels. If it takes just six hours to identify a leak, 250 barrels will have escaped. If the leak is in an extremely isolated location, it could be many days before an operator is aware, by which time hundreds of barrels will have been lost. If criminal activity was at play, the offenders will be long gone.
Clearly, speed is crucial for operators seeking to maintain their pipelines and protect their contents. Pipeline Intrusion Detection Systems (PIDS) using advanced sensing technologies are vital here.
Accurate detection in realtime with Distributed Acoustic Sensing One technology that is able to monitor pipelines accurately for both leak detection and disturbances relating to attempted theft is distributed acoustic sensing (DAS). For example, Fotech’s LivePIPE solution uses advanced photonic sensing DAS technology with machine learning to essentially turn a fibre optic cable running alongside a pipeline network into thousands of vibration sensors, able to detect any disturbances along the length of the pipeline. The technology sends thousands of pulses of light along the fibre optic cable every second and monitors the fine pattern of light reflected back. When acoustic or vibrational energy – such as that created by a leak or by digging – creates a strain on the optical fibre, this changes the reflected light pattern. By using advanced algorithms and processing techniques, DAS analyses these changes to identify and to categorise any disturbance. Each type of disturbance has its own signature and the technology can tell an operator, in real-time, what happened, exactly where it happened and when it happened.
Finding faults fast LivePIPE technology effectively provides an invisible smart barrier along the entire length of the pipeline, which can accurately detect and alarm leaks of different sizes and their position along and around the pipeline in real time. DAS is able to detect vibrations caused by liquid being forced through a pipeline rupture, or by ground displacement associated with small leaks in pipelines
that would otherwise remain undetected. What’s more, the technology is able to detect and to pinpoint the location of multiple threats simultaneously. If the source of a leak is a tiny orifice, it could easily remain undetected or it could take days for the location of an incident to be identified with existing CPM systems. In the time it would take to locate such a leak, many millions of barrels worth of oil could have been lost. DAS has proven that it can detect leaks as small as 20 litres per minute, raising the alarm in just 90 seconds, by which time only 30 litres will have escaped. This speed is an improvement by a significant order of magnitude to existing technology. DAS can identify oil and gas leaks from many different sized orifices, even as small as 1mm.
DAS in action – enhancing security Fotech’s LivePIPE technology is proven to detect digging and
tunnelling activity effectively before a pipeline is put at risk. For example, in one sophisticated attempt to steal product, a tunnel was dug from a building approximately 20m from a buried pipeline. LivePIPE technology identified and located sporadic and often quiet activity associated with tunnelling over several nights. Working alongside a mass balance system, which located the area to within 500m, the LivePIPE data meant operators were able to reduce the search area to within 10m. The security team were able to find the tunnel easily and quickly.
In another instance, 26 separate hot tapping incidents were detected on a single pipeline during a six month period in India. The majority of these attempts were prevented before product was lost; digging in the proximity of the pipeline was detected and an alarm was raised, providing timely, actionable information for operators to direct their security responses to maximum effect.
Improving network integrity One of the biggest priorities for pipeline operators is network integrity due to the significant environmental damage and vast costs that can result from incidents – whether accidental leakage or malicious theft. Effective monitoring is essential for maintaining network integrity but poses some challenges for existing technologies. Pipeline safety and security strategies are increasingly in need of PIDS based on smart DAS technology as these systems help operators to protect their assets effectively against product loss. Preventing against leaks with the most advanced technologies will enable operators to immediately recognise when an incident has occurred so they can reduce their impact on the environment and as a result operate more sustainably. By gaining real-time visibility of the integrity of their entire pipeline network, operators are also able to protect their bottom-lines while reducing risk. Thanks to its continuous monitoring, DAS provides a critical layer of additional intelligence. This technology can also be integrated with existing monitoring measures to complement them, rather than to replace them. Operators can achieve a full understanding of what is happening on the pipeline at any given moment by combining information gathered from multiple monitoring and maintenance sensors into an overarching view. Only then can operators confidently maintain and respond to any events before they become major incidents.
We have liftoff for drone technology Gary Cutts, Challenge Director, Future Flight Challenge, UK Research and Innovation explains how drones look set to play a bigger role in the energy sector over the coming decade
nce confined to the realms of sciencefiction, the use of drones and other modern small aircraft is becoming increasingly feasible as technology becomes more portable, wireless, and smaller. Already we are seeing drones being used for deliveries, as surveillance systems, and as a tool for search and rescue. This subsector of technology is both future-thinking and already providing tangible, practical solutions across industries. Electric and autonomous flight has the potential to impact every aspect of our lives, presenting a substantial commercial opportunity for those involved. This will span local air-taxis, drone
deliveries and autonomous flying vehicles and therefore requires a convergence of multiple technologies including digital twins, 5G, hardware, software, and display technology. These advancements give forward-looking sectors a unique and exceptional opportunity to be at the forefront of some of the UK’s most exciting technological developments.
A sky-high ambition The revolution in future flight technology is coming. Already we are predicting that by 2030, 25,732 drones will be in use in the agriculture, mining, gas and electricity industries. And this just
represents one section of the UK’s economy. At the Future Flight Challenge, we believe the next decade will be the most pivotal for the integration of new flight technologies. Our predictions show that by 2024 services in the real world will be carried out by drones, providing strong socio-economic value positions. By 2026, these services will become commercially viable, bringing investment, and reducing production costs. And by 2030 drones will be fully integrated into our daily lives, providing services, inspection processes, transport, and economic benefits for all. Transitions to new forms of technologies rely on their integration and development in line with the
dangerous situations. The benefits are clear, but
sectors they are set to serve. If we just take the energy sector for instance, we have witnessed monumental change in how automation technologies are used. What has traditionally been viewed as a dirty and polluting industry is quickly becoming one of the most advanced and forward-thinking parts of the modern economy. The advent of renewable energy sources and the potential of AI and robotics have all placed the energy sector at the forefront of modern technological understanding and application. This is because the relationship between the energy sector and cutting-edge technology is mutually beneficial, with energy corporations often investing in novel tech and nurturing it before applications have been developed.
Stronger, better, faster and safer Drones trump humans in a number of ways, they are lighter, faster, more agile and reduce risk to human life by removing the need to put workers in
relatively speaking drone technology is currently under-deployed in the energy sector. The main potential of future flight technology in this field is in inspection and maintenance; two vital foundations of any asset-owning company. Keeping an eye on the smooth running of a facility and fixing any problem as soon as (or even before) it arises, is crucial to the continual output of energy to the national grid, and the safety of its workers. But in many cases, this is seen as a mammoth task. Oil rigs, gas power-plants, wind and solar farms, and nuclear facilities are some of the most dangerous workplaces on Earth and provide huge logistical challenges for maintenance and inspection. They also take human workers out of harm’s way. The potential dangers in energy are blatant. Oil rigs are continuously battered by storms, high winds, and rain all while being several miles from the shore. Monitoring parts of the rig that are the most exposed and vulnerable is a necessary task that saves lives in the long-run but can put them at risk in the short-term. But now imagine putting that worker in a safe environment, piloting a drone to the highest and most far-reaching parts of the oil rig, safe from any sudden changes in weather or tide. That is the future that drone technology is realising. And there is clear precedent in the industry. Nuclear energy is carbon-free, immensely powerful and becoming increasingly common, but it is not without risk. Automation and robotics are already at work in areas of high radiation, to increase the safety of facility workers, the same principles of automation and robotics can be applied here too. In 2019 it was estimated that 52% of energy and utility companies have multiple artificial intelligence and automation use cases, this industry has always pioneered the use of novel and cutting-edge tech. The structural assets involved in energy production are often vast and, with the onset of certain renewable technologies, can be expansive. Solar farms and wind farms can stretch for miles in each direction and are often placed in rural and hard to access areas so as to avoid nuisance to the public. For this reason, keeping an eye on all parts of wind or solar farm at any one time can be a never-ending job, and a complex one too that involves sending workers several dozen feet into the air on a regular
basis. A drone provides the solution. A small remote-controlled vehicle, loaded with a live streaming camera is ideal for keeping track of the quality and condition of a field of several hundred wind turbines. A vehicle like this, being able to move at speed, can easily accomplish a task in a fraction of the time that it would have taken a human to do. Imagine how much more impressive this will be with a small ‘swarm’ of drones flying in formation under AI-based autonomous control. This is a use case that the Future Flight Challenge is already supporting. So, whether the assets you are monitoring are tall or expansive, or both, a drone is a clear upgrade from more traditional methods of inspection. Ensuring energy from power plants is safely delivered to homes across the country, via power lines and pipelines stretching hundreds of thousands of kilometres in every direction is also a clear application. With the deployment of a small fleet of drones across a vastly expansive network, you can save time, energy and money scanning up and down cables and pipes for leaks, weather-damage or any other issues that can be prevented before they develop into a problem. We are all aware of the implications of climate change and the need for new alternatives to achieve our net-zero goal in carbon emissions. Modern drones are green, or at least have the full potential to be entirely renewable. Drones can be either electric or hydrogen powered. Electric drones are fuelled by the grid, and once the grid is entirely renewable, drones will be too. Hydrogen power also offers an attractive solution. Use of hydrogen as a fuel produces only water as a by-product and will also allow drones to travel faster for longer, ideal for longer tasks. One of the many projects already engaged with the Future Flight Challenge includes HyStYRIAA 2.0 (Hydrogen Storage to Energise Robotics in Air Applications 2.0). Their project is exactly the type which we think will form the basis of future hydrogen-powered unmanned flight.
Integration and collaboration are key to a flying future As drone tech becomes a greater part of our everyday lives in the coming decade, the energy industry must make plans to employ it. Current uptake is lacking, but with the right minds, the right companies and the right innovations, the benefits are there to be reaped. This is why UK Research and Innovation is currently calling on a range of specialists from the energy and technology sector to collaborate in the Future Flight Challenge, to determine how drones are used to survey and manage assets and shape how this new technology is realised in the future.
Follow the Four Commandments Steve Bruce, product director, Idox explains why engineering document management is crucial for agile offshore operators
he offshore oil and gas industry of 2021 is a very different beast to that of previous incarnations. The energy transition exerts external pressure to operate more leanly and greenly, COVID-19 has accelerated a pre-existent trend towards digitalisation and around the world smaller operators are stepping in to buy aging assets from their larger peers to eke out extra profitable years with agile, expert operation. All those trends push towards greater automation in oil and gas, but automating processes is often easier said than done – especially for those leaner, more nimble operators who lack extended internal IT and technology teams. However, that doesn’t mean automation is out of reach for such operators; it simply calls for a smarter approach. A good place to start is by implementing automation in IT processes, such as engineering document management, as opposed to OT (operational technology) processes that involve physical equipment, such as drilling. This reduces the upfront investment required for things like sensors or control units, and reduces the variables to factor in, while still delivering significant returns in terms of process – and therefore cost – efficiencies. Even here though, automation can be easier said than done, so here are four commandments that will clarify and simplify the process.
Look for the bottlenecks and the easy wins An obvious but often overlooked point is that it makes sense to invest in automation where the need is greatest. Most people understand this, of course, but we are often quick to make assumptions on where that need might be and launch into planning – an unscientific approach. Instead, we must spend some time actively looking for the bottlenecks. This means some time spent watching, listening, and questioning. For example, look at documents submitted by partners in the supply chain: how many days on average are they spending with document control? Then how long with the engineers for validation? Does it differ between disciplines – for example are mechanical taking an average of two days to assess documents associated with the riser system while electrical take five? If so, why – is the project more complex for one team or the other, or is it a difference in efficiency? Why does the document control team appear to spend 60% of its time indexing – is that commensurate with the inflow of documents?
Spending some time with analytics and team managers to identify, measure and quantify impacts can uncover the inefficiencies that are really hurting the project, rather than those which are most obvious or visible. However, if starting from a low-base for automation, it can be a risk to immediately launch into the thorniest problems to solve – even if they are among the most important ones. Consider that a failed or serially delayed automation project is not only a waste of resources but could harm the chances of similar future investments being approved. Look for the tasks which are easier to automate. Not those that are so easy as to be trivial, but those which have the potential to make an impact but are more straightforward to deliver.
Joining the dots Imagine a Venn diagram between the costliest bottlenecks and the easiest processes to automate and start by addressing those in the middle. These are likely to be your low-lift, high-impact opportunities for automation.
For example, notifications can be a great candidate for automation. We are all accustomed to automatic notifications on our personal tech devices today, but we don’t typically enjoy the same level of sophistication with engineering document management – despite the stakes being far higher. It is critical the right people are using the right documents at the right time on major projects, especially when offshore. It costs time and money to send engineers out to platforms, and if someone is prevented from doing their job by incorrect documentation and to return at a later-date, that can have major ramifications. In worst case scenarios, work carried out according to incorrect documentation could even create major health and safety risks. So, can an employee be sent an automated notification when a when a document is superseded with revised content, or when a task is about to become overdue? Could their manager be sent one too? What about to external parties in the supply chain? It may sound low-tech, but package engineers spend an inordinate amount of
time chasing suppliers for updated documentation. When project fees and penalties can be tied to hit or missed deadlines, this certainly qualifies as lowlift, high-impact. It can be useful to look at things in terms of shifting human resources from doing to validating. Look at the tasks that are repetitive or have lots of timeconsuming steps that don’t really require complex thought process or that have a well understood or fixed set of rules. Indexing a single document, for example, doesn’t take too much time, so it may not feel like a priority to address. But consider 100,000 documents on a project each with three or four revisions. Then consider having to notify hundreds of people when those documents change or are approved – that does take a lot of time that could be better spent elsewhere.
Translate, don’t replicate A mistake we have seen engineering companies make in the past is to try and cut and paste their existing processes from an analogue world into the digital one. For example, we have seen a company try to replicate its established comment sheet process
digitally. In the past, physical hardcopies had been sent to all relevant stakeholders, who returned them with comments marked-up, with the comments then consolidated manually. In theory you could do the exact same thing with MS Word documents but could does not equal should. In practice, this leads to version control issues and confusion, and a huge amount of time spent consolidating Word documents as if they were paper equivalents. Instead, the process should have been updated in-line with the digital technology’s capabilities – users could easily work in the same document concurrently using tracked changes and comments: a translation of the process into a digital format rather than a strict replication. This may not be an automation process per se, but it is an example of what can go wrong when companies try to simply replicate old processes with new technology, rather than translate them for it.
Walk before you run Walk before you run could be considered the overarching commandment of the set, and it may be a lesson you’ve already read into the above. However, there are more ways this rule applies to automation. One is in respecting the human. What looks like the most efficient route to a more automated future on paper may not be the best one. Those who are working with newly automated processes and systems need to trust them to make best use of them. That confidence may take time to build. So think about how to implement the automated
process. Perhaps to start with, the engineering department should validate every other document, before then reducing to one in every three, then one in five. This may mean a lot of doubling up and inefficiency at the start, but a great boost to productivity over time. Then, once a good number of processes are automated and operating smoothly, and employees are enjoying the benefits of being able to spend more of their time on high-value tasks, it is time to consider what running might look like. This is where today’s buzzwords like ‘AI’, ‘digital twin’ and ‘automated offshore platform’ come into play. Only by this point, with solid foundations for automation in place, they won’t be buzzwords but tangible and achievable opportunities for further improvement. For example, perhaps AI algorithms can be trained to check the symbols used on engineering drawings and notify project leads of any discrepancies. Of course, there may be some companies with the ambition, capital and expertise to launch immediately into a root-and-branch digitisation and automation overhaul in one swoop – Equinor certainly made headlines when it did so in 2018. For most of us, however, no matter how tantalising the prospect of automation might be, the concept can be daunting, and we’re rarely able to start from a blank slate, instead having to adapt existing structures and processes piece by piece. By following these four commandments however, automation should quickly begin to feel more achievable.
Refining and Processing
Non-stop development Oil and gas Technology spoke to Shuja Al-Ajmi, deputy CEO of Mina Al-Ahmadi Refinery about the Clean Fuels Project Oil and Gas Technology: With the completion of Clean Fuels Project, Kuwait National Petroleum Company (KNPC) enters a new phase. How do you view this achievement? Shuja Al-Ajmi: The Clean Fuels Project (CFP) is a quantum-leap in Kuwait National Petroleum Company (KNPC) history. It is the cornerstone of the company’s business development and the embodiment of its vision in adding value to Kuwait hydrocarbon resources. The Project improves the company’s environmental performance and provides the local and international markets with highquality petroleum products. Oil and Gas Technology: Tell us about the importance of the Project? Shuja Al-Ajmi: The main aim of the project is to increase KNPC refining capacity. Mina Abduallh (MAB) capacity is now 454,000 bpd and Mina Al-Ahmadi (MAA) is 346,000 bpd, with total refining
Refining and Processing
capacity 800,000 bpd. Both are now one single integrated and highly flexible refining complex able to meet the market variables. Producing high-quality products requires advanced refining technologies, and we have now more hydrocracking and hydrotreatment units. We have introduced the latest technologies as licensed by major world licensors, such as Haldor Topsoe, Flour, UOP Honeywell, ABB Lumus, Chevron Lummus Global, Axens, Shell Global and DuPont. We know that we must be more competitive. This mega project maximizes our plant complexity, reliability, availability, energy efficiency and safety levels. And with high operational excellency, we shall have much less un-scheduled shutdowns. These factors reduce our production costs, and hence stronger competency. We shall add more value to our national resources as we have now more ARD units to boost our conversion rate so that the low economic value of high-Sulfur residues and heavy fuel oil, currently constitutes approx. 24% of the total production, will be converted into high value quality products. Oil and Gas Technology: How does the project cope with the increasing environmental stipulations? Shuja Al-Ajmi: Environment has been our main concern. Most of the Project’s huge budget of KD 4.6 billion (US$15.2 billion) is dedicated for building new units to produce cleaner fuels. As the environmental and product quality regulations are more tightening, our products are now consistent
with international standards, such as Euro-4 and Euro-5. For example, the Sulfur content in Gasoline has been cut down from 500 ppm into 10 ppm, and in Gasoil (Diesel) from 5,000 ppm into 10 ppm. With the low content of SOx, NOx, and other impurities, we are more competitive to enter new markets. We are also supplying the local market with low-sulfur Gasoline, Diesel as well as Fuel oil for power stations. Hence, the environmental impact will be greatly reduced. Oil and Gas Technology: Any special difficulties faced during construction? Shuja Al-Ajmi: Over 54.5 thousand workers were involved in this massive effort. The management of such a huge number was a challenge, especially with the outbreak of Covid-19 pandemic. In late 2018, we had torrential rain that caused wide damage and caused delays in our works. Oil and Gas Technology: How do you see the future now? Shuja Al-Ajmi: We are proud of the completion of the project, a milestone in the history of the Kuwaiti refining industry. We are well on our way to be a world-class leader in oil refining, and for Kuwait vision to be a hub for the oil industry.
Research reveals rapid increase in levels of Industrial IoT maturity According to the new report 81 per cent of oil and gas businesses have accelerated or intend to accelerate their deployment of IoT in response to Covid-19 pandemic. Oil and Gas Technology looks at the reasons behind that increase of velocity.
esearch by Inmarsat reveals a rapid increase in the maturity level of the industrial Internet of Things (IoT) across the oil and gas sector since the start of the Covid-19 pandemic. Respondents, including exploration, extraction, and distribution businesses, reported that Covid-19 has demonstrated the importance of IoT to their businesses, with many accelerating IoT deployments in response to the pandemic. According to the research, adoption has seen huge progress from 2020 to 2021. 74 per cent of oil and gas respondents have now fully deployed at least one IoT project, with 44 per cent having achieved this in the twelve-month period from the second quarter of 2020. Of the remaining 26 per cent of oil and gas respondents that have not yet adopted IoT in any form, all of them are either currently trialling it, or plan to deploy or trial at least one IoT
project in the next two years. A further 81 per cent of oil and gas respondents indicated they have, or they intend to accelerate the adoption of IoT in response to challenges related to Covid-19. This figure includes 51 per cent who have already accelerated IoT adoption to respond to Covid-19, versus 17 per cent who will accelerate over the next twelve months and 13 per cent who will accelerate beyond the next 12 months. The 51 per cent that have already accelerated IoT adoption are less likely to state that Covid-19 has negatively impacted their
Commenting on the research, Mike Carter, President of Inmarsat Enterprise said: “The rapid increase in IoT deployments over the last few years highlights the considerable progress global industry has made to overcome some of the world’s most challenging forces. It is particularly interesting, though logical, that Covid-19 has further catalysed businesses to increase their reliance on Industry 4.0 technologies, and particularly the industrial Internet of Things, to maintain business continuity. Those businesses implementing IoT technologies ahead of their competition and across their value chains are those who stand to win in the long-term. “While our findings point to IoT driving significant uplifts in efficiency, sustainability and safety across global supply chains, there are areas where organisations can make improvements to draw the optimum benefits from the technology. Connectivity, data management, skills shortages, security threats and investment levels remain challenges as the world’s production and supply chains become increasingly digitalised and intertwined. “Inmarsat’s global ELERA network is inspiring new possibilities and enabling organisations from all sectors to access IoT anywhere. Ideally suited to the rapidly evolving world of IoT, our industry-leading narrowband network provides global reach, extraordinary resilience, and the fastest speeds, along with the smallest, low-cost terminals in their class. Organisations looking to accelerate their IoT deployments need look no further than Inmarsat and our global partner ecosystem – the widest of any satellite provider – to solve their IoT connectivity needs.” The Inmarsat Research Programme report ‘Industrial IoT in the Time of Covid-19’ launches today. The report focuses on measuring IoT maturity of global industry during the Covid-19 pandemic and the rise of digitalised production and supply chains. It analyses several key themes such as adoption, connectivity, data, skills, security and investment. The report is based on the interviews of 450 global respondents across the agriculture, electrical utilities, mining, oil & gas, and transport & logistics sectors in early 2021, a year after the start of the pandemic. Respondents were drawn from businesses with at least 250 employees from the Americas, EMEA and Asia-Pacific who were responsible for delivering IoT initiatives at their respective organisations. As part of the research, Inmarsat is also offering businesses the opportunity to measure their IoT readiness versus the respondents in the survey, using their free IoT maturity tool.
ability to operate, demonstrating a link between IoT and business continuity during the pandemic. Additionally, over half (52 per cent) of respondents in the sector indicated that business and operational challenges related to Covid-19 have underlined the importance of IoT. Commenting on this acceleration of IoT in the oil and gas sector, Damian Lewis, Market Development at Inmarsat said, “The oil and gas sector has a history of innovation, and our research reveals that the pace of IoT adoption in the industry has significantly increased as a result of the pandemic. The sector is now relatively advanced in its adoption of IoT, demonstrating the importance businesses are attributing to the technology as a way to respond to both Covid-19 and wider industry challenges. In a sector where so much activity takes place in some of the world’s most remote and inhospitable conditions, this accelerating rate of IoT adoption reflects the need that oil and gas businesses have to increase their ability to monitor, manage and automate remotely.”
Light and Smart Jesús Fernández, product manager at ZALUX explains the role that lighting can play in improving environmental performance
or oil and gas facilities, lighting accounts for a significant proportion of energy costs and a notable toll on maintenance overheads. However, smart lighting, using latest LED technology, presents an ‘easy win’ opportunity for sites to save money, improve lighting quality, and increase sustainability. Lighting with smart movement and daylight sensors, combined with a proper management system, will automatically adapt to changes in light and activity. This means lights are not left on if they are not needed, optimizing the use of electricity, and helping improve sustainability performance. Compared with traditional fluorescent lighting, modern LED technology on its own reduces energy consumption by around 70 per cent. Combined with smart sensors, however, sites are looking at savings of up to 85 per cent in lighting running costs. In turn, this equates to not only a quick return on investment, but a lower overall carbon footprint. Additional sustainability and reduced cost of ownership are further facilitated through the integration of wireless communications and internal sensors within lighting fixtures that can predict maintenance requirements. Smart luminaires can include sensors to monitor the temperature and electrical parameters to give warning if a failure is imminent. This not only ensures enhanced reliability with reduced chance of unexpected failure, but also means maintenance activities can be fully optimized, reducing time and cost overheads of the system. Many oil and gas applications have harsh environments, and locations may make operation and maintenance more challenging. First, luminaires must be certified under EX and IECEX standards (among others). This is mandatory. Then, luminaires must also ensure safe operation. For longevity, however, their construction should also be resilient to corrosive substances, including chemicals and salt. Harsh environments may additionally require wide operating temperatures. Alongside EX and IECEX certifications for Zone 1 or Zone 2 installations, latest LED luminaires can operate at up to 75°C, use innovative PMMA housing materials to make them
resilient to corrosives, and provide gas tight seals to ensure sophisticated electronics are not damaged by any corrosive atmospheric gases that may be present. Very few manufacturers can guarantee this high specification. Supplying luminaires that operate at 75°C is particularly rare, but one provider who has the capability is the protected lighting specialist, ZALUX, with its Made in Europe explosion proof luminaires.
Easy upgrade, long life Upgrading lighting is not a difficult win. Ageing installations often need to upgrade electrical devices and the benefits of taking this opportunity to upgrade conventional lighting to new LED technology with smart control will deliver better
lighting efficiency, greater resilience to extreme temperatures, lower energy consumption, and reduced maintenance. Indeed, the expected return on investment is within two years. Traditional luminaires have a typical operating life of around 10,000 hours. LED technology offers 10 times this, which equates to around 20 years of operational life. Other considerations include recyclability. Modern plastics, such as PMMA, used in new lighting fixtures are 100 per cent recyclable. Unlike fluorescent tubes, they also do not contain mercury, which is difficult to dispose of and dangerous to the environment. In fact, legislation is moving to stop the manufacture of fluorescent tubes because of the impact they can
have on the ambience. By using modern plastics, luminaires also become much lighter and easier to install. In addition to the ease of installation, wireless technology allows traditional installations with non-dimmable luminaires to be updated with new dimmable fittings without the need of rewiring. So, this is a great benefit in refurbishment projects and increases their profitability. The installations also get the advantages of predictive management, better use of the light and energy savings.
A brighter future Ultimately the question of upgrade to modern LED technology to meet lighting needs offshore and onshore is not a question of ‘if’ but ‘when’. The longevity of traditional luminaires is waning and there are so many benefits to be gained from upgrading, for operators, workforce, and the environment. For oil and gas applications, new luminaires need to be holistically designed. To do it, eco-design techniques are applied to analyse the impact of the luminaire during its lifecycle in terms of environmental impact and carbon footprint. They must also include relevant safety certification – EX and ICEX standards, among others – but they should also address the need for: • Fully optimized energy consumption with the latest LED technology, which have a high energy efficiency. • Reduced installation overheads with necessary
lighting electronics and modern plastics is required. It is only by combining these areas of expertise that the longevity, reliability and efficiency of the luminaire can be assured in harsh and often dangerous environments, including hazardous areas or those with risk of explosion.
EX quick fit accessories, long cables for direct
connection to junction boxes, and wireless
Latest lighting solutions are an easy win in the battle for sustainability. The combination of highly efficient lighting technology, smart control and sensors, mean every aspect of the luminaire can be fully optimized. Combined with careful selection of materials to produce a safe, highly robust, and fully recyclable housing solution, and a design that is easy to install and maintain, the benefits simply cannot be ignored.
technology. Also, with smart controls, less installation costs thanks to a simpler, more flexible and faster commissioning. • Reduced maintenance costs by avoiding unnecessary inspection and providing intelligent, predictive information to engineers over wireless communications. • Be light and robust, ensuring they are easy to handle and install and can withstand the rigours of heavy industry application thanks to high degrees of protection against impacts or presence of chemicals. • Consider all aspects of sustainability, starting on the products design phase, from manufacturing carbon footprint, through optimized energy efficiency, to the use of fully recyclable materials at end of life. To meet all these requirements, proficiency in both
The future Lighting solutions continue to be developed to offer increasing efficiency, reduced manufacturing carbon footprint and to consider latest materials, including biodegradable options. For today, the gains in efficiency and environmental protection are already huge, but manufacturers are not standing still and are looking for even greater savings and sustainability to ensure we all have a brighter future.
Competitive, profitable, and cleaner
Astrid Poupart-Lafarge, president of oil and gas, Schneider Electric explains the role that data plays in optimisation and improving environmental performance
fter a year that started with the biggest pandemic in more than 100 years which had the impact of dropping oil prices into negative values, we have been seeing a slight recovery in 2021. Oil prices recently reached over $70 and are starting to re-animate the upstream business again. Access to capital, public image, corporate resiliency, workforce efficiency, portfolio diversification, TOTEX (total expenditure) reduction and the shift to renewables are not new challenges to the industry, but 2020 amplified the demands of the stakeholders in upstream onshore exploration and production. So, what is the answer to the acceleration of these challenges? Digital transformation is the key to reach CAPEX and OPEX optimisation, uptime and to reduce time to first oil. And the digital solutions put in place to optimize operations and increase yield also increase efficiency and use less resources which support sustainability efforts. All the above appeal to a new generation of digitally capable and environmentally conscious workers as well as offering increased agility and flexibility to the potential need of remote workers. At the end of the day, digitalisation is addressing the key needs of the upstream market to deliver
greater energy and process efficiency.
A shift towards a more efficient model thanks to data analysis Empowering the workforce, through complete coverage of the asset lifecycle, to make data-driven decisions that reduce risk, improve operational performance and optimise production throughout the entire project and asset lifecycle will enable upstream operators to keep pace with the demands placed on the industry. Data-driven decision making is defined not only by collecting data, but also by how and if it is used
information for better operational decisions. The creation of micro grids with digital intelligence to assure quality and reliable power. The use of clean energy like solar and wind will create the path to reduce emissions. But going into decarbonisation is much more than this. We must plan our future operations, going from low emissions operation to net zero facilities. You can start by planning your future asset: • Feed studies to build & deploy CO2 assessment methodology. • Negotiate power purchase agreements for renewable electricity sourcing. • Ensure secure power for emergency situations with UPS and BESS (batteries energy storage systems). • Develop your digital plan with remote operations leveraging digital twin for controls and asset performance management. • Define CO2 emissions targets, looking at UN Sustainable Development Goal 13 (Climate Action). Clearly setting your sustainability KPIs and develop a sustainability performance tracking monitor in making crucial decisions. It means being able to analyse any asset for real performance compared to the expected or most optimised performance and having the right information to define the best time for maintenance throughout the operating life. Also, being able to determine what good looks like so you know how to operate and maintain that equipment for optimum performance. Going further with data driven analysis, the use of AI machine learning concept allows failure predictive analysis. That means, prediction of possible failures based on the equipment conditions of operations or performance. The use of an intelligent algorithm analysing the data, can provide earlier alerts when performance is starting to deviate or deteriorate and will avoid costly failures. EcoStruxure solutions allow connectivity everywhere, power and process integration, and a TOTEX approach.
Looking at the long-term value of investment decisions The TOTEX approach is about spending money to achieve outcomes regardless of its CAPEX or
OPEX. This is the foundation of the approach we call EcoStruxure Power and Process, which breaks down silos and delivers real time information of common assets. Electrical power management and process automation have long been designed and operated independently, but IoT and digitalization have enabled a level of connectivity to manage these two domains differently in the future. To boost efficiencies and cut costs, oil, gas, and petrochemical companies have begun to consolidate their automation and electrical operations.
How are digitalisation and IA technology already helping performance? Globally, the implementation and uptake of AI is on the rise because the availability of data is in abundance and the number of connected devices is growing exponentially. AI and machine learning can be used in several ways. Firstly, to actively manage the asset lifetime to optimise intervention schedules. Secondly, to optimise the production of the wells by reducing unplanned downtime as well as maximising oil volumes. Thirdly, to capture and automate expertise from senior operators through
How can decarbonisation be achieved?
You probably heard that a key driver for decarbonisation is electrification. But to be successful, we need power availability, power reliability and power quality, which only can be achieved with a secure source of energy and an energy efficient monitoring & control system, using existing technologies, from sensors to predictive maintenance, machine learning applications and the use of power advisors. This enables failure prediction and availability of real-time and reliable
time for the Oil & Gas industry which is being
When it comes to digitalization, this is an exciting completely transformed to a more efficient, resilient, cleaner, sustainable and people focused industry. Whilst the net zero ambitions set out by the European Commission are ambitious, urgent action is needed to reduce greenhouse emission substantially in the coming years. If Oil&Gas companies leverage the latest technology and digitalize their operations, we have the best chance of being able to meet those net zero goals.
Ageing well Neil Ballinger, head of EMEA at EU Automation, explains why implementing a proactive obsolescence management plan is crucial.
apid technological progress can be a double-edge sword. On the one hand, emerging automation technologies allow us to gather real-time production data and optimise processes more efficiently than ever before. On the other, the continuous development of new products and solutions means that components can become obsolete more quickly. Unexpected breakdowns can have disastrous consequences in safety-critical industries, like oil and gas. Financially speaking, failed components can quickly translate to millions in lost revenues. Environmental disasters can also result from equipment failures or malfunctions and are responsible for 20 to 40 per cent of all oil spills. That is why managing the life cycle of equipment is key to safeguarding operations. Fierce competition, volatile prices and increasingly stringent regulations have pushed many oil and gas companies to keep their assets in operation for longer-than-anticipated periods of time. Therefore, the sector has been relying on ageing assets for quite some time, with an increased risk of failures due to material degradation, corrosion and fatigue. Add extreme environmental conditions and the pressure on companies to reduce maintenance costs, and you have a perfect mix for repeated breakdowns.
The cost of obsolescence While breakdowns occur in any industry, the mismatch between the expected lifespan of oil and gas systems and the increasingly rapid pace of innovation in automation technologies means that obsolescence is becoming a huge challenge.
Continuous advances in automation technology push original equipment manufacturers (OEMs) to discontinue some of their components to make room for newer models, even if the previous version is still used in systems across the world. This means that when an obsolete component breaks, oil and gas manufacturers essentially have two choices: to source a spare part from a supplier that specialises in obsolete components, or to commission an entirely new system.
The benefits of sourcing obsolete The good news is that obsolete doesn’t mean useless or outdated. Since new automation parts are launched on the market every day, components that are still perfectly functional and relatively new can be classified as obsolete, simply because the OEM has discontinued them or is no longer in business.
If they still perform adequately and are compliant to the latest safety and environmental regulations, there is no reason to invest in a costprohibitive systems overhaul. Sourcing a like-forlike obsolete spare is not only cheaper, but also ensures seamless integration with the existing infrastructure and can prevent implementation risks associated with changes to the system. Sourcing obsolete components also means that employees who are familiar with the existing structure won’t need to be briefed on the new components or potential risks associated with their implementation. Additionally, in heavily regulated sectors such as oil and gas, a lot of paperwork and red tape are required for any possible component upgrade. Since redesigning and requalifying processes can cost companies huge amounts of time and money, sourcing a likefor-like obsolete spare part is, by far, the easiest and most convenient option.
Planning ahead Once they understand the advantages of buying obsolete and are aware of the risks that come with ageing assets, oil and gas manufacturers should plan ahead and rely on a solid obsolescence management plan. To effectively plan for the future, the first step is to know the present state of equipment. That’s why a comprehensive system audit is essential to assess the lifespan of machinery and compare lifecycles with the life expectancy data provided by the OEM. The second step is risk analysis. By creating a risk assessment form, plant managers can evaluate which assets are more critical, whether the components are still on the market or if compatible products are available. Since a failure of these components would impact the functionality of the overall system, timely replacement might be the best option to avoid unplanned downtime. The next phase involves forming partnering agreements with a reliable supplier that specialises in obsolete components; ideally one with a proven record of serving customers in the oil and gas industry. At this stage, it’s important to rely on suppliers that have a
diverse and agile supply chain, which doesn’t over-rely on a specific location or provider. Since obsolete parts can be scarce, it’s also crucial that suppliers are able to source them worldwide regardless of where they are located. That’s why a supplier with a global headquarters, a worldwide network of providers and, ideally, native speakers to help negotiate prices, is your best bet. Lastly, all data collected during the equipment audit should be recorded and stored safely. This information is invaluable, and collating it into an easily-understandable format could save precious time in instances of breakage. This doesn’t necessarily mean investing in an elaborate database. Instead, a clear spreadsheet detailing the conditions of critical parts, the likelihood of them breaking down, and contact information for suppliers that have the parts in stock, can be enough. This data should be reviewed regularly, and then updated if necessary. By incorporating obsolescence management into their maintenance plans, oil and gas companies can minimise the impact of breakdowns, eliminate last-minute repair costs and keep assets operational for as long as possible.
The new generation of automated domain software for production optimization Across the energy value chain, a new breed of domain software applications is rapidly becoming available. As Halvard Ellingsen, CEO, Turbulent Flux explains these applications are cloud-native and adaptable, with new functionality continuously deployed.
or real-time production optimization, we need novel methodologies that can integrate traditional physics-based modeling with machine learning techniques. Such true hybrid models are powerful as by combining the strengths of both approaches, new and fully automated real-time systems can deliver more accurate, scalable, and cost-efficient insights. The outcome significantly improved efficiency of hydrocarbon production for operators! And as we know, efficiency is what our industry demands in the years to come.
digitalization wave opens a window of opportunity for a new breed of cloudnative domain software. Such software solutions are developed and optimized for reaping the benefits of cloud environments in relation to distribution, scalability, and elasticity. Emphasis must be put on novel software for sustainable practices and for production optimization.
The window of opportunity for new software
Within the production domain, operators have made significant investments
Let’s take a step back and review how the window of opportunity for new software has evolved. Over the last decade, the market environment for operators has changed dramatically. Initially, we saw a focus on production growth in an environment where the world’s demand for hydrocarbons grew steadily and oil prices were high. It then turned to a focus on production efficiencies and cost reductions in a much more challenging market environment and lower oil prices. Lately, the focus on sustainable operations and carbon-effective production has become a firm requirement and key driver for operations and investments. Equally so, over the last decade the IT industry has made giant leaps forward. With the digitalization wave and the rapidly increasing amount of data which has become available to the operators, cloud-based thinking has become the new norm - also in our industry. As with previous step-changes in IT, this means that legacy software tools developed for outdated and localized IT infrastructure will find it difficult to keep up on innovation and in transitioning. The rapidly changing oil & gas market environment combined with the
The new generation of domain software tools for production optimization into IIoT, including connected sensors from oil & gas production systems. This data is now made available for flexible consumption from cloud-based data platforms. Having the data infrastructure in place, the operators’ focus turns towards understanding how data is best utilized in order to create value. The industry needs to move beyond bespoke POCs, which rarely make it into regular operations. It is now about embracing commercial software, feeding off these data platforms, at scale. What should you expect from such cloud-native software solutions? They should be: • cloud platform agnostic • extremely fast to deploy with a high degree of automation • run in real-time and utilize data to the fullest • a living asset model - an always up-to-date representation of the asset • a part of open technology, connectible through public API’s
Turbulent Flux Technology Values
Hybrid modeling assures unmatched capabilities There are two distinct approaches which are often set against each other – first-principal physics and machine learning. In Turbulent Flux we acknowledge that both approaches have their strengths and weaknesses. We know the optimal approach is a
liquid. And the best possible accuracy for the 3-phase well rates are attained when combined with a machine learning model which accurately predicts the water and oil ratio. The solution is a hybrid model orchestrated in one system, which accurately predicts all three phases irrespective of constantly changing operating conditions.
combination of the two - a hybrid model of the production system. For us it is a prerequisite to utilize the first-principal physics available from the production system at the core. They provide both predictive and extrapolating capabilities. In addition, machine learning has significant benefits when it comes to scalability, speed, and data input flexibility. In our solutions the two approaches feed off each other to leverage their respective strengths. Consequently, this hybrid approach offers unmatched capabilities that only the combination of the approaches can assure.
Hybrid Modeling for Virtual Flow Metering
Know your well rates For effective production optimization, any production system requires an understanding of the productivity of each step in the production process. An oil & gas production system is not an exception. Therefore, real-time access to multiphase flow rates from all wells and pipelines on an asset is of critical importance. With this information, operators can react immediately. Even more importantly, they can pro-actively optimize operations and avoid deferred or even lost production. A trial-and-error Hybrid Modeling – acknowledging that both approaches have strengths and weaknesses
approach to production optimization is no longer satisfactory. For the best possible outcome, it is essential that one can address the full operating envelope throughout the life cycle of the asset. To deliver the
So let us look at a concrete use case where our FLUX Virtual Flow Meter is
most accurate live well rates for effective production optimization, we in
used to deliver real-time well rates for gas, oil and water. A pure physics-
Turbulent Flux are convinced the best approach is through hybrid, transient
based solution can deliver very accurate measurements for gas and total
Escalating cyber threats Nigel Thorpe, technical director at SecureAge looks at the increase in cyberattacks on energy, oil and gas companies and suggests it’s time for a new approach
The energy and utilities sectors are very much a part of our critical national infrastructure and vital to national security. While installations are at threat from physical attacks, and natural disasters such as floods and earthquakes, it is the increasing threat of cyber attacks from criminal and state-sponsored terrorist groups that that have hit the recent headlines. According to international insurer Hiscox in its 2021 Cyber Readiness Report, the UK energy sector comes top of its Cyber Threat Ranking Table by industry and suffered the highest median losses. Just how big these losses can be was highlighted on 7 May this year, when there was a cyber-attack on Colonial Pipeline, a firm headquartered in Georgia USA that supplies about 45% of the petrol and diesel used on the east coast. The company says that it transports over 100 million gallons of fuel daily across an area spanning Texas to New York. Colonial paid the hackers, who were an affiliate of a Russia-linked cybercrime group known as DarkSide, a $4.4 million ransom shortly after the hack. The hackers had stolen nearly 100 gigabytes of data and threatened to leak it if the ransom wasn’t paid.
While the biggest and most high-profile attack on a pipeline, it wasn’t the first. Earlier this year, the US Cybersecurity & Infrastructure Security Agency (CISA) issued reports detailing a history of attacks against pipeline operations. At the same time, President Joe Biden signed an executive order aimed at boosting defences, having warned that attacks on CNI could lead to a ‘real shooting war’. If you want to grasp the true potential for devastation from a cyber attack on an energy installation, you have to go back to 2009 when Stuxnet - a highly sophisticated computer worm developed by joint US and Israeli Intelligence, was deployed against the Natanz Nuclear Facility in Iran. It targeted centrifuges used to enrich uranium, instructing them to spin out of control and eventually break. Over a few years, about 20% of Iran’s centrifuges were
destroyed and caused the Iranian nuclear program to be set back by years. Closer to home and to underline that going green does make you immune from hackers, personal data on all 270,000 customers of Scotland-based renewable energy supplier People’s Energy were stolen in at the end of 2020. New research published in May 2021 from Veritas Technologies found that more than half of the utility industry’s companies suffered a cyberattack last year. The survey of 75 IT decision-makers also showed that nearly 64% of them suggest their organisation’s approach to dealing with cyberattacks could be improved. Ransomware attacks seem to be one of the biggest threats that the UK utility sector faces – so it’s all about the data. For cyber criminals, ransomware is a low risk, high reward activity, with a virtually unlimited supply of potential victims. And the arrival of Ransomware-as-a-Service (RaaS) only serves to lower the bar to entry and increase the scale and volume of attacks. Ransomware attacks were also described as the key cyber threat facing UK businesses and organisations, by Lindy Cameron, the head of the National Cyber Security Centre (NCSC) in the recent annual security lecture to the Royal United Services Institute (RUSI) defence and security think tank. In her speech, Lindy Cameron stressed the importance of UK businesses and critical national infrastructure continuing to build its cyber resilience to stop attacks from reaching their targets. But here lies the problem. Like most industries, the energy and utilities sectors have traditionally approached cyber security by trying to stop the cyber criminals and hackers getting in. Yet history tells us that it is impossible to stop every cybercriminal all of the time. The Colonial breach was the result of a single compromised password for a virtual private network account, which allowed employees to remotely access the company’s computer networks. So, if we can’t keep the cyber criminals out nor trust
the people around us, we must rethink the traditional ‘castle and moat’ methods of protection and adopt a data centric approach, where security is built into data itself. Full disk encryption will protect structured and unstructured data when it is at rest on a hard disk or USB stick, which is great if you lose your laptop but is of absolutely no use in protecting data against unauthorised access or theft from a running system. Data therefore needs to be protected not only at rest, but also in transit and in use, on site or in the cloud. But this is no easy task. In the 2020 IBM and Ponemon report, 67% of respondents said discovering where sensitive data resides in the organisation is the number one challenge in planning and executing a data encryption strategy. Data classification technology is often used to identify ‘important’ or ‘sensitive’ data, but the report found that 31% cited classifying which data to encrypt as difficult. Then there is the question of where you set the ‘importance bar’? Even seemingly trivial information can be useful to a cybercriminal, since they are adept at amalgamating small pieces of data to form a bigger picture, to build a spear phishing attack for example.
A universal approach So why is it that the accepted norm is to encrypt only the ‘most important’ or ‘sensitive’ data? The problem is that traditionally, encryption has been considered complex and costly and detrimental to performance and productivity. But with advances in the technology and fast processing speeds, seamless data encryption can now be used to protect all data – structured and unstructured. This way, classification for data security purposes becomes irrelevant and stolen information remains protected and useless to cyber criminals. This approach also works with legacy systems, which are outdated but still do an essential job. Legacy systems were not designed to be exposed to public networks, but as staff, customers and suppliers need direct access to business processes, new online services have been built on top of this ageing technology. But when connected to the outside world, legacy system data - such as customer details, company operational data and intellectual property - becomes vulnerable as it travels from silo, through web-based applications to end users. But by protecting the data itself, these risks are mitigated. Having seen the potential for massive disruption and damage, there is no doubt that the cyber criminals and statesponsored terrorist groups have the energy and utilities companies in their crosshairs. So, unless we can take a different approach to cyber security and data protection, we can expect more trouble ahead.
Are oil and gas and renewables truly worlds apart? James Fisher’s Giovanni Corbetta, Managing Director, James Fisher Marine Contracting, takes a step back for a big picture look at the two sides of the energy transition (ET)
hat does ET, the 1982 American science fiction film, have in common with ET, the seismic structural shift redressing the demand for a more sustainable energy system? On the surface, not a lot. Initials aside, tales of a suburban family befriending a stranded extraterrestrial seem like a far cry from the current pressing and very real challenge of reducing our reliance on fossil fuels as an energy source. However, as tempting as it is to place oil and gas and renewables in their respective boxes, let’s take a second to look at the bigger picture. What if, instead of focusing so much on the differences, we look at what connects these two together? Perhaps to the chagrin of the radical supporters on both sides of the spectrum, is there something to be gained from searching for the similarities? Much like ET and Elliott, there is a binding force that becomes difficult to ignore.
Oil and gas expertise Offshore renewables, and their infrastructure as we know it today, would simply not exist if it wasn’t for oil and gas. The technology propelling us towards a green power future exists because of the decades of innovation that has come before. That’s not to say that the renewables sector doesn’t have its own bespoke technology driving development – in fact, it’s one of the fastest growing, most digitally literate industries on the planet. But when it comes to the rapid deployment of cleaner offshore energy, oil and gas has a lot to answer for. With a long-standing legacy in offshore
construction, James Fisher has had the privilege of being at the forefront of ocean innovation since its inception 174 years ago. From the transportation of coal, through to supporting the construction and operations of offshore wind turbines, energy has always been at the centre of its activity. So, we know from experience that there is nothing to fear from this next era of change. Oil and gas platforms out in the North Sea are not suddenly going to pull up and head back to shore to make way for their turbine replacements – for one, decommissioning is an expensive process. These costs vary region to region, but a comparison last year from Rystad estimated that removing a steel platform in the North Sea would cost around $22.35 million – and that’s excluding its subsea infrastructure. South East Asia rate approximations are a little more palatable at $9.08 million, but a significant amount, nonetheless. Secondly, there simply is not the infrastructure to run the world entirely off of renewable resources, yet. Current growth rates of 15 – 20 per cent indicate that this could be a reality by 2050. So, with the case for the energy transition well and truly made, and the world (mostly) on board, there is a universal responsibility to pull together and ensure that it happens in as safe, sustainable, and
swift a way as possible.
A change of focus As oil and gas companies of all sizes begin dipping their toes in the proverbial renewables pool, they are bringing with them a set of processes, technology, and expertise that, for their clean energy counterparts, has proven to be useful on more than one occasion. One example is the trend for offshore wind developers to start building further afield to expedite construction. This has several benefits. For one, permitting disputes are all but wiped out – the further offshore a wind farm is located, the less likely it is to encroach on a prized surf spot or disrupt the view from a wealthy world leader’s golf course. However, building offshore has its own unique set of challenges – challenges that the oil and gas sector have been navigating for decades. Building in deeper waters requires a different style of engineering – at depths where it becomes unfeasible for fixed foundations, turbines need to float. While there has been much talk about the viability of these floating farms, they are now widely agreed to be the solution to ambitious offshore wind targets. And much of the technology needed for these farms, while described as new, isn’t a million miles away from floating oil and gas platforms, with the first floating production storage and offloading system (FPSO) built in 1977 on the Shell Castellon field in the Spanish Mediterranean. With a floating platform – everything is more dynamic which means that tasks such as anchoring the platform in deep water and managing the export cables are subject to significantly more forces than traditional near-shore windfarms.
Time for floating wind It is perhaps unsurprising then that the bids submitted in July for the world’s first largescale floating offshore windfarm, located in the North-East of Scotland, have come from Royal Dutch Shell in partnership with Scottish Power. This combination of expertise, an oil and gas veteran with decades of North Sea wrangling under its belt, partnering with a firm that’s about to become the UK’s largest offshore wind developer, sends a powerful signal to the global energy circuit.
It also signifies the start of a potential growth trend – combined oil and gas and renewables projects. We are already seeing some oil and gas platforms that are themselves powered by renewables, so it’s not too much of a stretch to envision the opposite. Perhaps a wind farm that uses an active offshore oil and gas platform as its offshore hub, or a carbon capture and storage project co-located with wind. As mentioned, while the consensus is that the energy transition is a necessary and universally net-positive move, there is still an undercurrent of unease when we are essentially asking an entire industry to cease many of its existing operations – operations which provide a livelihood for many families globally. Combine this with a post-pandemic pessimism and you can understand how, for some, the outlook is a little bleak. However, as experts such as James Fisher can attest to, while perhaps diametrically opposed politically speaking, the jobs in oil and gas and renewables aren’t mutually exclusive. The maintenance requirements for a floating oil and gas platform are very similar to a floating wind farm – checking connections, cleaning, valve replacement. Looking slightly further afield, pilots of helicopters and vessels will still be very much in demand, as will commercial divers and thirdparty contractors of other offshore services. Now, granted, oil and gas platforms don’t have blades. However, with the first field of floating farms unlikely to come online until 2023, there is plenty of time to plan and finesse training and qualification programmes.
Transferable skills In the IEA’s recent net-zero pathway report, they estimate that the fossil fuel production job losses equating to 5 million could be offset by the creation of 14 million new positions by 2030. This is by no means insignificant and, while only time will tell if there is a sense of optimism to be found in the ‘green recovery’ – job creation, particularly in times of uncertainty, is a welcome respite to those who have lost jobs during the pandemic. This will almost certainly extend to those oil and gas
professionals whose skills and knowledge are vital to the acceleration of this emerging sector. As with an extra-terrestrial landing in a domestic setting, it is natural to focus on the differences – the ‘us and them narrative is all too familiar’, and one which we all defer to. But searching for common ground is also pervasive. When we look at the energy sector as a whole, it is connectedness in the face of a disjointed and challenging political backdrop – there is a symbiosis in this narrative of reliance, empathy and connectedness. Renewables have landed – and, far from phoning home, they are with us to stay. The reality is that demand for oil and gas will start to wane, and, in recognising this, we are already seeing big oil and gas majors prepare for this shift. For those of us lucky to work across both sectors, we see the benefits of this crossindustry collaboration. The time to fear change is over – instead, we should look to harness the similarities and work towards a common goal of bolstering our global energy system for a better, more sustainable way of life.
SPM Oil and Gas launches KOP AM20 series gate valves
Halliburton launches DS365.ai Halliburton has released DS365.ai cloud service to help customers accelerate their digital transformation with intelligent automation. DS365.ai delivers industry specific artificial intelligence (AI) and machine learning (ML) models to enhance productivity, operational efficiency, and increase asset value. DS365.ai runs on the OSDU Data Platform and uses the interoperable and scalable architecture of iEnergy Cloud. This allows citizen scientists, data engineers and data scientists to design, develop, and deploy AI models at scale. Users can rapidly train pre-built ML models, or create and deploy solutions to enhance subsurface, drilling and production workflows. Users can consume these models as standalone microservices, or in DS365.ai applications such as assisted lithology interpretation, seismic engine and real-time well engineering. “We are excited to introduce DS365.ai, an industry first approach to quickly extract insights from data silos at a time when data scientists need domain specific accelerators to deepen insights and operations require data science investments to scale and interoperate with existing tools,” said Nagaraj Srinivasan, senior vice president of Landmark, Halliburton Digital Solutions and Consulting. “The DS365.ai models deliver operational value across dozens of successful projects for customers of all sizes.” With over 70 projects and more than 60 AI/ML models deployed at scale, DS365.ai provides a rapid return on investment. Examples of generated value include a national oil company that predicted artificial lift failure, which saved $4 million across 60 wells. Additionally, an IOC in Latin America deployed an ML seismic conversion methodology to reduce uncertainty that led to a 70 percent reduction in modelling cycle time.
SPM Oil & Gas in Dubai has launched its new KOP AM20 Series Gate Valves. The KOP AM20 Series Gate Valves dramatically reduce NPT and the risk of catastrophic well loss while lowering inventory costs. The KOP AM20 Series Gate Valves allow and shutin flow for every operation of the wellhead, tree system and choke and kill manifolds — from drilling and completion to pumping and production. The KOP AM20 Series offers unprecedented safety by ensuring a gas-tight seal from pressures as high as 10,000 psi to as low as 50 psi. An advanced coating guards against high wear, corrosion resistance and low friction factors for low operating torque. The KOP AM20 Series also meets stringent requirements and is qualified for API 6A Annex PR2F, API 6FA fire test, API 6AV1 sand slurry test, extended low gas pressure hold test, endurance cycle test and sea water corrosion test. The actuated KOP AM20 Series surface safety valves are qualified to Annex F PR2F, API 6FA and API 6AV1 Class II. The KOP AM20 Series features a simplified design that is not only smaller and lighter for greater cost savings but also provides part interchangeability to simplify inventory requirements. The KOP AM20 Series withstands harsh conditions for more than 600 endurance cycles—representing a 60-year lifespan—without grease injection. The KOP AM20 Gate Valves increase the maintenance period by 50 percent as compared to other gate valves in the market. This will reduce valve maintenance cost by at least 50%. “Our new KOP AM20 Series Gate Valves enable operating companies and drilling contractors to satisfy today’s well integrity qualifications while lowering their assets’ life cycle costs, enabling them to more effectively compete in the marketplace,” said Ronan Le Gloahec, president of SPM Oil & Gas Eastern Hemisphere.
Silixa and NexTier launch IntelliStim frac monitoring and diagnostics system Welltec launches new Well Tractor Welltec has launched a fully revised and transformed design of the pioneering Well Tractor conveyance solution: Well Tractor 212 CVT, equipped with Continuous Variable Tractoring technology. The new CVT system automatically maximizes speed and power at all times, optimizing every conveyance run, making operations faster and more efficient than ever before. Commenting on the launch of the CVT, Welltec VP Sales & Marketing, Alex Nicodimou said: “The Well Tractor remains a key service that we provide, it’s the foundation of everything that we do in conveyance and a solid base for our powered mechanical interventions platform. It’s what started the entire domain of interventions on wireline.” “Now our engineers are bringing something special to the market that will ensure we continue to lead in conveyance solutions.” In addition to the new Continuous Variable Tractoring system, the new Well Tractor offers a whole host of innovative functionality and performance features, including a heavily revised electronics package that is rated to higher temperature demands within a more robust architecture. It also allows for full two-way surface control, that can send commands to the tool downhole and receive
diagnostics back at surface. Traditional conveyance platforms are driven hydraulically by a pump, and in many cases, that downhole hydraulic pump is a shared asset that powers multiple wheel sections downhole. The Well Tractor CVT is configured so that each wheel section has its own power unit. These new hydraulic units and wheel sections are shorter and more powerful than ever before, resulting in a system that operates as multiple individual tractors downhole with inherent redundancy, without compromising on overall length. In the event that any one section meets a restriction of any kind, the other sections remain free to power themselves without any detrimental effect. Well Tractor CVT is the next phase in development of Welltec’s conveyance technology – building on more than 25 years of knowledge and experience, it promises to be just as transformative as the original.
Silixa and NexTier are pleased to announce that its recently launched IntelliStim monitoring, and diagnostics system has been awarded its first project for a major operator in the Mid-Continent region. The proprietary IntelliStim system enables Silixa and NexTier customers to remotely monitor every aspect of the fracturing operation in real time, empowering decision makers – whether at the wellsite or
remotely – with precise control to make on-the-fly adjustments to optimize completion performance. From pre-job treatment design to offset well monitoring and stage-by-stage performance assessments, all surface and downhole activities will be accessible using a single, consolidated interface and easily accessible via the customer’s existing data portal. “By combining AI-driven digital control, integrated completion services and real-time performance assessments in a single package, the IntelliStim system is a truly unique offering,” Robert Drummond, president, and chief executive officer of NexTier, said. “It gives you an overall level of wellsite quality control and efficiency you’ve never been able to achieve until now. And when you compare the nominal investment of our IntelliStim enhancements against what you’d normally pay for these kinds of insights and potential gains in production, I’m certain that operators of all sizes will want to use it on every frac job.” The IntelliStim system uses Silixa’s Carina Sensing System, which incorporates a Constellation fibreequipped sensing wireline cable to cost-effectively monitor fracture growth and cluster efficiency to assess frac-design performance in real time. With the ability to be repeatedly deployed in multiple offset wells and retrieved by a NexTier wireline truck, this proven Silixa intervention solution achieves the most accurate measurements and highest signal-to-noise ratio in the industry, which enables operators to identify events farther from the wellbore and deeper into the reservoir.
Optiq Schlumberger fibreoptic solutions launched Schlumberger has launched Optiq Schlumberger fibre-optic solutions, which deliver multidomain distributed sensing capabilities for a wide range of applications and environments across the energy industry. Optiq solutions provide continuous and instantaneous measurements, and when coupled with Schlumberger’s broad digital offering, deliver actionable insights leading to greater operational performance, efficiency, and reduced environmental impact. “With our recent technological advancements, we have improved access to fibre-optic solutions, enabling the energy industry to harness the full power of this game-changing technology,” said Aparna Raman, president, Reservoir Performance, Schlumberger. “Optiq solutions are providing customers with greater subsurface understanding and improved production systems performance—all while reducing operational footprint and carbon intensity.” Optiq solutions now span the full range of deployment options: permanently installed behind casing or on tubing, exiting through dry or subsea trees, along pipelines, and on to other midstream and downstream infrastructure; or temporarily deployed via Schlumberger fibre-optic coiled tubing, slickline, or wireline conveyances. Integrated with Schlumberger’s leading digital capabilities—including intelligent end-toend workflows, edge processing, and cloud-native applications—Optiq solutions enable the large volumes of data associated with fibre-optic measurements to be processed up to 18 times quicker than current industry practices and unlock a range of applications from borehole seismic to production and stimulation monitoring, well integrity and leak detection. Customers can then leverage Schlumberger’s industryleading domain expertise to act on insights faster. Optiq solutions are represented within the Schlumberger Transition Technologies portfolio, which helps customers minimize emissions and reduce energy consumption while simultaneously driving efficiency, reliability and performance. For example, the Optiq Seismic fibre-optic borehole seismic solution reduces data acquisition time by up to 99%, significantly reducing associated energy consumption and carbon emissions. The Optiq Seismic solution has been used to acquire more than 70 vertical seismic profiles (VSPs) in more than 17 countries. In the Gulf of Mexico, the solution was used to record 3D VSPs in four producing wells, saving 88 days of acquisition time and reducing CO2e emissions by estimated 7,537 metric tons when compared to conventional methods.
Record cash flows and peak uncertainty Shaun Findley, European director of product and purchasing at oil and gas connector supplier PEI-Genesis, discusses some of the key factors to consider when choosing connectors for oil and gas applications.
ow will the upstream industry use an incoming $1 trillion price windfall? Should Asian governments be doing more to resuscitate declining gas production? And what is the future for exploration in this region? In previous upcycles the pattern has tended to be the same – higher revenues and cashflow lead to rising upstream spend. But the energy transition has upset the outlook for oil and gas producers, changing the rules of the game for not only international oil companies (IOCs), but also national operators and host governments. Crucial decisions will be required on capital allocation, the pace of decarbonisation and future energy policy. “At current Brent prices the upstream industry will generate a wall of cash,” Kavita Jadhav, research director, Wood Mackenzie, said. “We estimate the 42 largest IOCs will generate a windfall of over US$1 trillion if prices keep tracking above a US$50/bbl industry planning price. But how to invest this bounty? US$80/ bbl oil gives companies options, and a chance to do it all – return cash to shareholders, maintain oil and gas investment, and accelerate investment in low carbon opportunities. The current upcycle presents a golden opportunity to reposition for a very different future.” The energy transition has created unprecedented uncertainty over long-term oil and gas demand, changing stakeholder expectations and company strategies. Creating a business model that is both resilient and sustainable is the challenge.
One dilemma is creating an upstream business that is profitable but also decarbonising. “Carbon now represents an existential threat,” Jadhav added. “The value at risk from just Scope 1 and 2 exposures of the world’s top IOCs is huge.” Using our Emissions Benchmarking Tool, Wood Mackenzie estimates that under a US$150/tonne carbon price, the world’s 38 largest IOCs would drop US$465 billion in value, or 27% of their total value. A temporary windfall, alongside higher global oil and gas prices, also raises important questions for governments across Asia. Falling domestic gas production increases exposure to international LNG markets and pricing. Spot LNG prices in Asia have more than quadrupled over the last few months to over US$30/mmbtu. As security of supply concerns reverberate around the globe, should Asian governments be doing more to resuscitate declining gas production? “It may seem counter-intuitive and unpopular to talk about incentives for upstream investment at a time when IOCs are set for record profits, but a declining share of that upstream spend is being invested in Asia,” Angus Rodger, research director, Wood Mackenzie, added. The current shortfall between Asian gas production and demand is nearly 5 million boe/d. With production on a downward trajectory and demand looking robust – due to both coal-to-gas switching and the need to back
up intermittent renewables capacity - that gap looks set to hit 17 million boe/d by 2040. This means Asia will continue to be the engine room for rising global LNG demand over the next two decades. While this is great news for LNG producers, it will increase domestic governments’ exposure to global price swings and supply risks. “But Asia isn’t gas resource short,” Rodger said. “Across Asia Pacific over 90 billion boe of resources is currently considered commercial and is currently onstream or under development. Another 47 billion boe is currently discovered but uncommercial. We have significant resources that are stranded due to high carbon footprints or unattractive fiscal terms.” The same challenges apply to the current suite of pre-FID gas projects across the region. Many have high levels of CO2 content, challenging economics, long lead-times and often a substantial history of delays and false starts. Other barriers to progress include above ground risks and relatively high government take. Asia Pacific is well-positioned, with ample infrastructure giving rapid, low cost access to hungry gas markets. “And it can be done. Of the 32 billion boe that has been discovered with the drillbit across Asia Pacific over the last decade, a quarter is already onstream,” Harwood added. “Much of these resources, such as large shale and tight gas discoveries in onshore China, were enabled by ready access to major pipelines combined with government incentives.”
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