The new normal is digital
Seven steps to completion heaven Making Digital Transformation a Reality A new view for oil and gas maintenance
| SUMMER 2021
Winds of change Preserving innovation in the era of low oil demand
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Editorial Mark Venables – Editor in Chief firstname.lastname@example.org Ben Avison – Group Editorial Director email@example.com Chairman Koos Tesselaar CEO Matthew Astill Managing Director Adam Soroka Advertising Director Mike Smith firstname.lastname@example.org Expert Advisor Trish Meek, Director of Pro
The new normal is digital
Seven steps to completion heaven Making Digital Transformation a Reality A new view for oil and gas maintenance
Winds of change Preserving innovation in the era of low oil demand
| SUMMER 2021
Oil & Gas Technology
Cavendish Group Second Floor Front 116-118 Chancery Lane London WC1A 1PP Tel: +44 (0)0203 675 9530
Facing a changing world The world is changing and changing fast. What used to be a discussion about peak oil and when it will run out has now turned into one around how much oil and gas can we extract before the energy transition deems it unusable. The essence is what does a net-zero pathway mean for the oil and gas industry? As capital markets and an everwidening stakeholder community demand clarity and action on decarbonisation how can the sector plan to move through this ever-changing landscape. One company that has recently delivered some telling thought leadership on this matter is Wood Mackenzie. A couple of months ago three of its senior analysts, AnnLouise Hittle, Massimo Di Odoardo and Alan Gelder, delivered a view of that future, based on the company’s2 °C ‘accelerated energy transition’ scenario – AET-2. Their analysis has profound implications for the industry and has stoked up a great deal of interest. This insight was followed by more recent work from the IEA when it published its own
scenario, Net Zero by 2050 (NZE). The IEA NZE is aligned with the even more challenging 1.5-degree pathway. One common theme between these two reports is that the world needs to act rapidly if it’s to slow global warming. The world needs no new oil supply in AET-2 – existing resources are sufficient to meet future demand. However, in Wood Mackenzie’s view, exploration and production will play a role in this future, albeit a diminishing one. New projects and new exploration can come into the supply stack if the new resource is lower cost and has lower carbon intensity. According to Simon Flowers, Wood Mackenzie’s chief analyst, no oil company is preparing for the scale of decline envisioned in any of these scenarios. The decline in oil output Wood Mackenzie’s scenario would lead to asset impairments and bankruptcy or restructuring; those long in refining face a double whammy. Portfolios of majors and most NOCs today are largely out of step with a switch to gas. Cash generation from oil and gas this decade will be re-invested in renewables, hydrogen, and CCS to build a sustainable business. Most IOCs and NOCs though do not have the scale or capability to follow this new path. Resource-holding NOCs face pressure to bolster government income; revenue optimisation turns from price support to maximising volume and avoiding stranded assets. One final point from Flowers on investment. He predicts that E&P spend today is already at a 15-year low and would fall rapidly if these scenarios unfold. With pressure on the industry to reduce investment, there is a risk of higher oil and gas prices this decade should the transition take longer to gain traction. Not altogether a comfortable scenario for the oil and gas companies, but one they must navigate if they are to survive.
Mark Venables Editor Oil & Gas Technology
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Winds of change 6
Updates The latest news from around the globe
14 Making Digital Transformation a Reality Miguel Valdez, growth manager, Kongsberg Digital explains how unlocking the value of process data through digital transformation not only offers oil and gas operators huge benefits it is also an essential step for businesses to remain efficient and competitive in the future.
16 Challenges for growing biofuels sector It seems beyond question at this point in the market’s development that biofuels will be a significant factor in the evolution of the transportation and petrochemical sectors, but the space remains in flux, with the winners and losers yet to be declared, As Tom Brown, chief news correspondent, ICIS, explains.
18 A new view for oil and gas maintenance By outfitting their frontline teams with assisted reality wearables, oil and gas companies such as Shell were able to maintain operational uptime during the pandemic.
20 From zero to hero Steven Bruce, product director at Idox explains how automated tag management helps digitalisation to deliver for the oil & gas industry.
24 Protecting pipelines against product loss Pedro Barbosa, industry sector manager pipelines, at Fotech, reviews the current threats to pipelines and explores how advanced distributed acoustic sensing (DAS) technology is helping pipeline operators to protect their assets in extreme terrains.
28 Seven steps to completion heaven Mette Lind Fürstnow, reservoir engineering at Welltec talks us through the various benefits of utilizing a data driven tool to optimise their completion strategies.
30 Winds of change The North Sea Transition Deal has laid down a major challenge for the oil and gas industry. Published in March this year, it calls for the North Sea to become a net zero basin by 2050.
32 The changing face of asset management Oscar Bos, operations director for asset integrity and maintenance optimisation and Grant Allan, offshore integrity manager at Vysus Group reveal the five things they have learnt about asset integrity and maintenance optimisation. 03
34 The investment dilemma Neos Networks examine how oil and gas firms are balancing digital transformation with the transition to renewables
36 Preserving innovation in the era of low oil demand Duncan Nevett, partner at Reddie & Grose explains how the demand for oil may have peaked. What does this mean for innovation in the sector?
38 Innovations in produced water management Produced water poses a growing problem for many offshore production facilities, but new methods of in situ filtration could significantly reduce the costs associated with discharging at source.
40 Decarbonising the energy sector Astrid Poupart-Lafarge, president of oil and gas, Schneider Electric discusses ways to reduce the lifecycle GHG emissions of an offshore compression platform.
42 Ensuring the seal for pipeline safety The US pipeline industry has taken a global leadership position on pipeline safety, with a voluntary performance tracking initiative contributing to detailed information about spills and releases, along with their causes and consequences.
48 Slick data-centric approaches David Rosen, Technology and Customer Leader at TIBCO Software explains why thinking first about data will fuel success in a changing oil business.
50 Gaining new value from inspection As the era of digitalisation takes hold, the value gained from inspection is changing, but is a traditional mindset holding us back? Ranald Cartwright, head of operations for Imrandd, explains. 04
52 Succeeding with Digital Twins It has been said quite a few times, but it bears repeating: 2020 and COVID-19 made the world more digital and more remote controlled.
54 A new direction for directional drilling Andrew Law and Neil Bird of Enteq consider the evolution of directional drilling.
56 Wireless comes of age for gas detection Gas detection and monitoring has long-been a key priority for businesses operating in the UK’s oil, gas, and offshore sectors.
58 What is the future of seismic imaging? Mike Popham, CEO, Stryde explains how the evolution of seismic imaging is heralding a new era for oil and gas exploration.
60 Breathing life into brownfields
Mike Popham, CEO, Stryde explains how the evolution of seismic imaging is heralding a new era for oil and gas exploration.
64 Bringing the connected enterprise to life Mike Corrieri, sales manager, heavy industries, Rockwell Automation talks about the joint venture with Schlumberger.
66 Solar powering the digital oilfield From its origins in the early 1970s when the first pressure and temperature gauges were fitted into subsea wells and data logging via satellite began, the digital oilfield concept has evolved from simple data gathering activity to the automation, control, and optimization of fields.
70 Considerations for oil and gas electrical connectors 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.
4Subsea Secures Three-Year Service Agreement to Monitor West Phoenix Rig
Subsea has been awarded a three-year service agreement with Vår Energi to monitor and analyse wellhead integrity to ensure safe operations for the Balder Future drilling and completion operations. The SWIM service employs retrofittable subsea sensors to measure movement and strain on the wellhead. It applies advanced algorithms and machine learning combined with deep domain expertise to monitor fatigue damage accumulation, well support and structural integrity. The service creates a digital twin of the well and riser systems combined with boundary conditions and updated with sensor data. Sensor data is collected using remotely operated underwater vehicles and uploaded to 4Subsea’s digital service 4insight, which performs advanced analysis on the data. The results are presented as easy-to-interpret insights and dashboards, simplifying the complex analysis and effectively support critical decisions. No extra personnel are required and supported by advanced algorithms and machine learning. In addition, 4Subsea’s domain experts provide a digital service for improved decision support to Vår Energi’s engineering team to ensure safe operations. The same sensors, technology, and algorithms have been adapted to monitor fatigue and integrity on offshore wind installations, demonstrating the versatility and robustness of 4Subsea’s sensor technology and digital services. “We are pleased that Vår Energi has chosen SWIM and 4insight for their drilling and completion operations on Balder Future operations,” Peter Jenkins, chief executive officer of 4Subsea, said. “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.”
After successful offshore trials, Ampelmann’s electric A-type is ready for operations Electric solutions, a lower carbon footprint and a strong commitment to sustainability are sure to be the future of the Walk to Work (W2W) industry. In line with that, Dutch offshore access provider Ampelmann, has announced the launch of an electric version of its signature A-type system. Based on the technology and decade-long track record of its flagship system, the latest iteration of the A-type has seen its traditional hydraulic power train replaced by electric regenerative actuation, decreasing its energy use by more than 80 per cent. This shift in technology does not only contribute to more environmentally friendly operations, but also makes the system significantly lighter, smaller in deck footprint and even quicker to mobilise. The electric A-type is now fully operational after undergoing extensive offshore trials on the Horizon Star vessel in Eneco’s Princess Amalia windfarm. “At Ampelmann, we are committed to driving our industry into a more sustainable future,” said CEO Jan van der Tempel. “The successful upgrade of the A-type to an electric system moves us directly towards that goal. This is a key milestone for our company as we continue to work towards new sustainable innovations.” The benefits of an electric W2W system are mostly two-fold. On the one hand, the electric A-type is smaller and lighter, requiring fewer resources to operate compared to its hydraulic-powered counterpart. Weight is reduced by 40 per cent and energy use by 80 per cent, considerably decreasing the environmental impact of the system without compromising workability specifications. “With the implementation of electric drives, large heavy components of the hydraulic system became redundant, including the 20ft power pack container,” said Diederick Nierstrasz, business developer at Ampelmann. “Clients can expect the same capabilities as the non-electric A-type system, with an even higher reliability and ease of use.” Additionally, Nierstrasz explains that the electric drives have improved the A-type’s accuracy and response time, while also eliminating the noise and vibrations the hydraulic-powered system used to produce. In total, the change to electric actuation has led to an A-type with a smaller footprint, a reduction in weight and no need for an HPU on deck. The weight reduction of around 40% leads to plenty of added benefits as it makes the system suitable for smaller and lighter vessels and allows for higher vessel speeds.
Industry says Sinopec selects Allison there is a transmission for its new clear plan for light workover rig future of oil and gas
he leading representative body for the UK’s offshore oil and gas industry, OGUK, has said that there is a clear plan for the future of oil and gas ahead of a debate in Holyrood later today. Scottish Government Net Zero, Energy and Transport Secretary, Michael Matheson, will set out that the climate crisis is a critical priority for the Scottish Government during the debate. The North Sea Transition Deal, signed in partnership with the UK Government, recognises the crisis is a priority and provides a clear plan for the industry as it works to transform the UK’s energy system to low-carbon and transition its people, jobs, and skills to sustainable alternatives. Announced in March, the Deal will cut UK emissions by 60 mega tonnes (the equivalent of taking 2.5m cars off the road), develop low-carbon solutions like carbon capture and hydrogen that the Climate Change Committee has recognised as key to meeting climate goals, and will produce 40,000 new energy jobs. It also sets out key milestones for the industry to cut its own emissions by 10% by 2025, 25% by 2027 before 50% by 2030 while producing the healthy, domestic oil and gas the UK will need with ever reducing emissions. “The North Sea Transition Deal was recognised by many parties during the election campaign and provides a clear plan for the transformation of our energy, resources, people and skills,” OGUK external relations director Jenny Stanning said. “We will manage a homegrown energy transition, we will continue to provide the energy the UK needs with less emissions, and we will help the UK realise a sustainable future while making a positive contribution to the UK economy. “What we need now is support for our plan and continued recognition from all parties that a fair transition must involve our industry and be shaped by the people and communities who work in it.”
inopec SJ Petroleum Machinery has selected Allison Transmission’s 4500 Oil Field Series (OFS) for its new light workover rig. During oil and gas recovery operations from underground reservoirs, chemical and mechanical processes can affect the wellbore, negatively affecting production and causing surface and downhole equipment to fail. Light workover rigs, which can reach remote oil fields swiftly and handle production emergencies efficiently, are always in high demand. SJP’s latest light workover rig model (GVW at 46 ton) adopts a truck-mounted CNHTC chassis and is equipped with an MC11.40-60 diesel engine rated at 297 kW, coupled to a light and compact Allison Transmission 4500 OFS, which can deliver maximum torque of 1900Nm. The new light workover rig model also carries hydraulic lifting derricks, winches and drilling rigs. “Our latest model, a light truck-mounted
drilling and workover rig, has two main duty cycles: driving the rig to the work site (road mode) to running a second function (work mode), specifically in oil wells that require consistent, durable power and high reliability,” Zhang Bin, vice president of SJP Drilling & Repair R&D Centre, said. “Allison has a wide range of oil field transmissions for different work conditions. The Allison 4500 OFS model can be matched with the biggest engines where it can deliver maximum output torque up to 2237 Nm, while being light and compact. It meets the needs of both duty cycles very well.” Allison’s 4500 transmission is specifically designed for the toughest applications. Allison Transmission’s Continuous Power Technology smoothly multiplies engine torque and transmits without any power interruption. Allison Automatics accelerate with a 14 per cent higher average speed than a manual or automated manual transmission (AMT). They also offer vehicles better control, traction and manoeuvrability on loose terrain. The dual mode operations allow one vehicle to be used for multiple operations. Users simply activate a switch to transfer the function of the transmission. Whether driving to the location or working on-site, Allison transmissions improve productivity and deliver the quality, reliability and durability needed in the toughest situations.
Stena Drilling acquires stake in digital offshore lifting technology company Intebloc
tena Drilling, an independent drilling contractor, has acquired a 30 per cent stake in Intebloc, an award-winning specialist digital lifting technology solutions provider, which improves the safety and productivity of offshore lifting operations. The deal marks another milestone on Stena Drilling’s digital evolution, as it positions itself as one of the most digitally efficient and sustainable drilling contractors globally. With backing from Stena Drilling, Intebloc will accelerate its product development strategy. In addition, the investment will enable Intebloc’s diversification into construction, renewables and the marine sector globally.
“We have benefited significantly from Stena’s feedback in the development of Rig-Ware, which has now been successfully deployed with several UKCS operators and service companies,” Ross McLeod, CEO at Intebloc said. “Much of this has been achieved during the restrictions imposed by COVID-19 and we look forward to continuing our aggressive growth and the launch in Q3 2021 of our next product”. The announcement follows Stena Drilling’s early adoption of Intebloc’s Rig-Ware solution, used for managing and tracking lifting equipment. The system was initially trialled on several Stena Drilling assets and is now being used by the entire fleet to improve offshore safety, reduce the risk of lifting
equipment failures, and enable timely and informed decision making. Colin Dawson, Digital Business Transformation Manager at Stena Drilling said: “The market demands more focus on digital technologies that truly add value. We have identified exponential technologies that accelerate our goal of delivering the most sustainable, digitally empowered service. Intebloc is one of those; its innovation culture and technology roadmap are the reasons why we believe that they can deliver significant improvements in lifting practices not only in upstream oil and gas, but across the entire lifting market. I look forward to working closely with the team on future developments.”
Alpha secures walk-to-work modifications contract at major North Sea wind farm
lpha, a Sparrows Group company, has been awarded a contract to undertake turbine platform modifications in support of a new walk-towork system at a UK east-coast offshore wind farm. An integrated team from Alpha and Sparrows will manufacture and install push-on plates, access gates and handrails to 88 turbine platforms as well as the A-deck platforms on each of its two substations. Once completed, the modifications will enable motion compensated gangways from offshore support vessels to be safely connected to the platforms, allowing maintenance technicians to walk directly from the vessel to the turbine. The new access system will deliver a safer method of personnel transfer while eliminating the requirement for costly and time-consuming crew transfer vessels, thereby reducing CO2 emissions and delivering a greener more efficient solution. “As the number of wind farms in the UK increase and developments move further from shore, walk-to-work systems utilising support vessels are becoming increasingly popular over crew transfer vessels, which involve taking trips to the
field from the shore every day,” Sparrows Group CEO Stewart Mitchell said. “It allows technicians to be accommodated on board the vessel and remain in the field to complete a campaign, negating lengthy daily transit times and maximising efficiency.” Manufacturing activities are already underway at the Group’s facility in Aberdeen with installation on-site at the wind farm scheduled to take place later this year. “Alpha’s experience working in the wind energy industry, combined with our technical capability allows us to complete all stages of this project in-house. Since acquiring Alpha we’ve invested heavily to ensure a large proportion of Sparrows’ offshore workforce are trained to Global Wind Organisation (GWO) standards and have Turbine Safety Rules certification. This ideally places our offshore personnel to work across both sectors and support the team at Alpha, strengthening our offering to carry out balance of plant services on wind turbines. The investment in training our people is in line with our diversification strategy as we continue to support the energy transition by expanding our footprint in the wind energy sector globally.”
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Prediktor can help you connect a wider variety of your enterprise ‘Apps’ to speed your ‘Digitalisation’ journey via greater interoperability. Prediktor EDGE ‘Any Historian’ is a componentbased communication interface that provides open-integration functionality allowing the user to interface with ANY legacy historian database and expose that data with OPC UA connectivity. Furthermore, on top of Prediktor’s unique technology stack – Prediktor EDGE Any Historian provides a platform for users to add significant functionality via industry-standard protocol ‘Information Models.’ In return, this provides seamless integration with Corporate software systems such as: • • • • •
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FutureOn integrates next-generation well design with digital twin technology
utureOn has partnered with the cloud-based well planning company, Oliasoft, to launch a new software offering designed to disrupt business as usual across the oil and gas industry, and revolutionise subsea planning. The new integrated solution, Well Assist, provides field planners and drilling engineers with a unique mix of capability, flexibility and insight from the earliest stages of feasibility studies, through to detailed subsea design, and into production. The result is a data-rich, dependable and interactive approach to well planning that maximises cost efficiencies and collaboration while reducing risks and enabling the fastest and most economic path to first oil. The tool combines FutureOn’s next-generation digital twin technologies, including FieldTwin Design 6.0, which bring real-time 3D planning into play from the earliest stages of project feasibility, with Oliasoft’s proven engineering software, which is designed to seamlessly connect every link in the well planning calculation chain. The integrated tool is fully compliant with industry standards and offers the ability to design, visualise, test and accurately cost field concepts from the topside to the target zone via a real-life, immersive subsea experience – all on desktop. Well Assist gives engineers and planners complete control over each step of the field planning and well design journey by providing an information-rich geospatial environment that reflects GIS mapping data, bathymetry and existing infrastructure. The picture is further enriched by proprietary information such as reservoir data, well data and drilling specifics – as well as associated metadata – to create meaningful,
interactive 3D visualization of any potential project including its reach deep beneath the seafloor. “By leveraging the building blocks of subsea design, specific coordinates, incline and azimuth – with the power of digital twin technology and industry-specific algorithms, Well Assist offers an unprecedented level of capability for field planners and drilling engineers,” Jostein Lien, Senior Vice President of Products at FutureOn, said. “The software creates an accurate, interactive and tangible visualisation of subsea infrastructure, offering immediate insight into well design options and enabling better decision-making at the earliest stage.” A crowded field for instance, may require the calculation of realistic separation factors based on 3D locations mapped within a deep borehole, where safety margins need to be increased. Jostein concluded, “Well Assist is ultimately about control over field design from topside to target, over timelines from concept to first oil, over economics from initial investment, through to operations and decommissioning. It will revolutionise field planning and well design by providing sophisticated and proven insight at the earliest stages of any subsea project. In a time of tight margins and increased competition, that is an advantage that no operator can afford to ignore.”
Tech collaborations are enabling oil and gas companies to venture into quantum computing
he prevailing industry downturn from COVID-19 has heightened the need for oil and gas companies to reduce operational costs by improving efficiency. Although classical computers are capable enough in delivering efficiency gains, quantum computers and their optimization algorithms could deliver these gains in a much shorter time, says GlobalData, a leading data and analytics company. Quantum computers are machines that use the properties of quantum physics to store data and perform computations. Theoretically, these machines can complete a task in seconds that would take classical computers thousands of years. The company (or government) that owns the first at-scale quantum computer will be powerful indeed. According to GlobalData’s latest report, ‘Quantum Computing in Oil & Gas’, full-fledged commercial computers are not expected to be ready for approximately another 20 years. However, intermediate versions would be available within the next five to seven years, offering a quantum advantage over classical computers in optimization applications across several sectors, including space warfare, logistics, drug discovery, and options trading. “Oil majors ExxonMobil, Total, Shell, and BP are among the few industry participants to venture into quantum computing,” Ravindra Puranik, Oil & Gas Analyst at GlobalData, said. “Although these companies intend to use the technology to solve diverse business problems, quantum chemistry is emerging as the common focus
area of research in the initial phase. These majors are seeking to develop advanced materials for carbon capture technologies. This could potentially lower the operational costs of carbon capture and storage (CCS) projects, enabling companies to deploy them on a wider scale to curb operational emissions.” Quantum computing is a very specialized field requiring niche expertise, which is not readily available with oil and gas companies. Hence, they are opting for collaborations with technology payers and research institutions who have expertise in this subject. Ravindra adds: “IBM is at the forefront in providing quantum computing tools to a host of industries, including oil and gas. The company has brought on board leading oil and gas and chemical companies, such as ExxonMobil, BP, Woodside, Mitsubishi Chemical, and JSR, to facilitate the advancement of quantum computing via cross-domain research. Besides IBM, oil and gas companies have also collaborated with other quantum computing experts, including D-Wave, Microsoft, and Atos.”
Kongsberg Digital to deliver real-time drilling software to Brazilian major
ajor Brazilian drilling contractor Ocyan has selected Kongsberg Digital’s SiteCom software to provide real-time drilling data from their rigs. “We are very happy Ocyan has decided to use SiteCom for making data available in WITSML,” Kristian Hernes, SVP digital wells, Kongsberg Digital, said. “As an operator, having access to complete, standard data in one system is a prerequisite to digitalize and automate processes in scale. Ocyan’s requirements for real-time data shows the robustness and versatility of SiteCom as a data collection software for the industry”, Ocyan is one the largest drilling contractors in Brazil with an offshore fleet in service for major operators in the area. From now on, their rigs will be using Kongsberg Digital’s SiteCom solution to collect and convert data from different data sources making standard data available for Ocyan´s main data platform Ocyan SMART. Besides the Drilling Control System, rigs are also configured to receive marine data, data from dynamic positioning systems, ocean current meter systems, and will be integrated with third parties for calculating drilling riser fatigue. “SiteCom is helping Ocyan to have a reliable and robust system onboard, connected to multiple sources and different protocols, converting data to WITSML standards
in order to meet our client’s requirements”, Rodrigo Chamusca Machado, technology and innovation manager, Ocyan, said.
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Making Digital Transformation a Reality Miguel Valdez, growth manager, Kongsberg Digital explains how unlocking the value of process data through digital transformation not only offers oil and gas operators huge benefits it is also an essential step for businesses to remain efficient and competitive in the future. However, many digital initiative projects either fail completely or do not deliver the rewards expected. Why is this and what steps can be taken to ensure digital success?
igitisation, digitalisation, and digital transformation are not new to the oil and gas industry. For decades, operators have been adopting new technology and utilising data analytics to try to gain greater efficiency and reliability, increase productivity, and enhance safety. Despite these efforts though, the predicted potential locked within the data has rarely been fully realized. Indeed, according to McKinsey, 70 per cent of complex, large-scale change programmes do not reach their stated goals. Is it
any wonder, therefore, that there is a reasonable portion of scepticism throughout the industry when it comes to discussing digital transformation for the future? Although there have been disappointments in
the past, these need to be overcome to start to truly harness the benefits of digitalisation - and success lies in a fundamentally new operating model with enterprise-wide implementation and cooperation. One of the problems with small digitalisation initiatives or pilot projects, is that the full benefit of data lies in a holistic view of operations. Without an enterprise-wide, global view, efforts to optimise assets and their processes may have detrimental impact elsewhere or fail to consider business-wide goals and strategies. The starting place must be in understanding and defining the true purpose of digitalisation and not treating it as a project using the same equipment and execution plans that have been used for years. This is a new era and requires a new methodology.
Creating an ‘evergreen’ digital landscape for the future For digitalisation initiatives to succeed, a change in mindset and approach are required with high level, enterprise-wide buy-in, sharing, collaboration and coordination. After all, the benefits of digitalisation are not small, they are enormous, and these solutions can and should change the way an entire business operates, from finance to maintenance to operations. By integrating, contextualising, and operationalizing data, individual users have access to a clear digital picture (digital twin) of the whole business and the true value and power of the masses of data being produced across all parts of the business are unlocked. A digital twin needs to incorporate all parts of an asset’s data and should be agnostic to data source and architecture. Looking at systems already in place, from chemical refineries to offshore platforms, much of the work to connect this data is already done. Like oil, however, data requires refining to add value. With the support of advanced analytics which use latest machine learning algorithms, masses of data can be transformed into valuable, meaningful, and relevant business data that will enable faster, smarter decision making and provide valuable input into business strategy. Contextualized data can be analysed to identify patterns and correlations, and, with enough data, the machine learning algorithms will be able to predict scenarios an anticipate operational needs. Overall, the value of a digital twin should not be underestimated. It presents a new way of looking at the life of assets and investments in asset
development that is way beyond the scope of capex, project, or installation. It will mean assets can be handled more efficiently, the value of investments optimised, and asset lifetime maximised.
Getting tangible results from digitalisation Digitalising just one part of an operation instantly limits the impact this technology has to offer. A digital twin presents an opportunity to provide context-specific access and insights into assets for individual users wherever they are. The challenge, however, is to align digital initiatives with tangible results across the organization – and this requires a shift in mindset. Buy-in from stakeholders is also important. Change can be unsettling and is often met with resistance. An open approach is needed to foster collaboration and create understanding about the goals of digital transformation and how it will benefit everyone. This further increases the chances of success as, regardless of geographic location, sharing information helps ensure the right and best decisions are being made. By engaging people at every level from the very beginning of the digital journey, collaboratively developing goals, ambitions, and the reasons behind them, we gain buy-in from teams and a shared commitment to working together for success. We can further create the mindset that digitalization is not finite but an always growing, scaling, and changing ‘evergreen’ solution with new use cases being identified and developed almost every day. With the right digital twin, a partner that understands the needs and challenges of the oil industry, and an enterprise-wide approach, the path towards digital transformation is cleared and new possibilities and opportunities will come to light. A digital twin designed specifically for the needs of heavy industry, such as Kognitwin Energy digital twin, goes beyond just visualizing assets, and supports smarter decision making to benefit the global enterprise.
Summary The time for digitalisation is now. The technology is ready, and the data is ready and waiting. Although success requires an enterprise-wide approach, which may seem daunting, the benefits cannot be ignored. Do not limit the possibilities the technology has to offer; consider what higher-level business challenges you want to solve and connect these to the value of your digital twin. The possibilities are endless and are only really limited by the imagination. The path to success requires a fresh approach, bringing all systems, data, and people together. Through this collaboration, both organizational adoption and digital transformation will be accelerated.
Scale, technology, and feedstocks among the challenges for growing biofuels sector It seems beyond question at this point in the market’s development that biofuels will be a significant factor in the evolution of the transportation and petrochemical sectors, but the space remains in flux, with the winners and losers yet to be declared, As Tom Brown, chief news correspondent, ICIS, explains.
aterials such as sustainable aviation fuels (SAF) present some of the most achievable pathways to reducing the CO2 footprint of difficult to decarbonise sectors like aviation, while materials such as bio-naphtha have potential for the petrochemicals sector as well as transportation. Limited time remains for governments to shift course on energy, production, and economic growth to meet the net-zero targets policymakers have set for the coming decades. A factor that could stand to drive wider deployment of biofuels could be its relative maturity compared to other emissions-reduction technologies, particularly for heavy industry, with around half of the innovations that are likely to contribute to those goal currently not yet in existence or in the development phase, according to the IEA. Many biofuels production technologies are much more established, and some feedstocks such as waste
Power to Liquids (CO2 Feed)
cooking oil already have international trade networks, with material from China, Argentina and Brazil flowing into Europe. The choice of technology, as much as the choice of biofuel, is likely to be a significant determinant of success. Some forms, such as SAF and biodiesel, can be synthesised using a wide variety of technologies, from isomerisation to pyrolysis, while others such as bio-gasoline, have a much more limited range of technological options at present.
FT/Hydroprocessing Alcohol Co processing
The sector remains policy-driven, although consumer interest in alternative-fuel transportation is growing and that balance may shift over the next decade.
In the short-term, the momentum of the space is also dependent on government targets, meaning that some momentum has been lost during the pandemic. Demand and growth Biofuels demand dropped eight per cent in 2020 year on year to 150bn litres, according to the International Energy Agency (IEA), with Brazilian and US ethanol production experiencing the most significant contraction. However, this was slightly less than the overall drop in gasoline and diesel consumption at almost 9 per cent. The coronavirus pandemic has sharpened government attention on more immediate issues than transport sector reform, with Indonesia and Malaysia pushing back biodiesel blending mandates temporarily and Thailand postponing its ethanol-blending mandate indefinitely. Output is expected to return to 2019 levels at least this year, the agency added, but the rebound will be uneven, with biodiesel and hydrogenated vegetable oil (HVO) fuels coming back strongly but US and Brazil ethanol sectors remaining subdued. A factor in this is because ethanol and biodiesel are constrained by total demand (which remains subdued) due to blending limits, while HVO is a substitute for fossil diesel. HVO could be a significant driver in biofuels becoming more mainstream, according to Michael Connolly, senior analyst on the ICIS global refining team. “I think the big change in the market is HVO, because all these other fuels to date are limited by the blending percentage that can go into the finished product, whereas HVO can be 100 per cent of the product. And so that opens room for biofuels to expand,” he said. That in combination with all the regulations/incentives, we are seeing encouraging biofuels is really what is driving a big change in the market. Then you will get co products on the side like the bio-naphthas and LPGs which the petchems firms are going to lap up,” he added. Scaling A key issue determining the winning technologies is that of which feedstocks can best scale to mature-scale market conditions. Whereas the conventional oil and gas sector was always characterised by a near-endless pool of resources, with continuing to discover and exploit them the key technological challenge. Now the biofuels market is growing, and an increasing number of idled or unprofitable refineries are being retrofitted to produce more material, but these new capacities will need to be fed. Total’s La Mede, France, facility is producing up to
500,000 tonnes of biofuel per year, utilising animal fats, used cooking oil and vegetable oils. The company’s Grandpuits refinery is expected to produce up to 170,000 tonnes/year of SAF, 120,000 tonnes/year of renewable diesel and 50,000 tonnes/ year of bio-baphtha for plastics, also based on used cooking and vegetable oil. As these feedstocks are often themselves by-products, either from the service sector, food production or agriculture, they are dependent on factors such a consumer demand, yields and weather. The coronavirus pandemic saw a sharp drop in restaurant demand, meaning that waste oil from that sector became harder to find. Players in the space are largely dealing with this by having supply contracts locked down ahead of time, according to Connolly. “There’s a big feedstock market at the moment but it will become feedstock limited so what you see is all the players who are joining into the market have feedstock arrangements already, they are making agreements either with companies producing used cooking oil, or agro companies that are making vegetable oils or animal fats to secure feedstock supply,” he added. As the sector continues to expand, which it will need to do to meet projected demand, sourcing sufficient feedstocks and successfully hedging against volatility, which is likely to remain more intrinsic to the supply side of the sector than with conventional fuels, will become a greater challenge, to be mitigated with innovation and the growing maturity of supply chains across the globe.
A new view for oil and gas maintenance By outfitting their frontline teams with assisted reality wearables, oil and gas companies such as Shell were able to maintain operational uptime during the pandemic. Globally they are accelerating the use of this new technology and integrating the technology more broadly in their digital transformation planning efforts. Jon Arnold, VP of Sales, EMEA, RealWear, explains more
e have seen significant technological advancements in recent years, including 5G, AI/ machine learning and IoT devices, all of which have played a unique role in fuelling the fourth industrial revolution – Industry 4.0. Such advancements are also having a profound impact on the oil and gas industry, where the automation of traditional industrial practices is driving digital transformation. As a result, we are all seeing the vision of digital oil coming to fruition. Companies now recognise digital as the only way forward. To increase production and cut costs, while honouring their growing environmental responsibilities, oil and gas companies are overhauling how they conduct maintenance, repair, and operations through their deployment of digital technologies; and this includes intrinsically safe assisted reality wearables. By clipping the device onto a hard hat, the head-mounted display enables digital content to be displayed without obstructing their line of sight. The assisted reality solution is hands-free, which is vital for use in an industrial setting where health and safety is paramount and a worker’s hands are required for carrying out a critical task, rather than trying to use an alternative device like a phone or tablet. During the pandemic, the solution became fundamental to many industries - not just oil and gas - because it helped them maintain essential equipment and devices amid strict lockdown restrictions including reduced or even a no-travel policy. Under those challenging circumstances, the technology became immediately pervasive, as assisted reality uses audio and visual technology to provide a ‘see what I see’ experience, which can be shared over the internet with remote, socially distanced colleagues. The technology enabled staff to work from home while still providing knowledge and guidance to
colleagues that were permitted to travel to sites to attend to any problems. By way of example, oil and gas companies such as French Multinational Total utilised the technology at its La Porte Polypropylene Plant during the pandemic. Total’s La Porte plant is the largest single-site polypropylene plant in North America and produces 2.7 billion pounds of polypropylene per year. Given that the plant produces materials used in the making of masks and gowns, it was essential that it remained operational to provide essential PPE and other critical supplies at a time when there were shortages due to ever-increasing demand. As a result of deploying assisted reality technology, the plant was able to continue mass producing the raw materials needed in the manufacturing of essential worker equipment. In Total’s case, field operators used the technology to communicate with remote experts that could be based anywhere across the globe, which played a key role in helping the factory maintain uptime as the pandemic - and demand for PPE - reached critical levels. Other digital oil and gas companies such as National Oilwell Varco, Shell, Saudi Aramco, and Schlumberger also deployed this technology as part of their routine operations. It is easy to understand why; normally, if workers on a rig run into a problem they cannot solve, everything stops. They then wait for an expert to arrive on-site to diagnose the problem and fix it. This process may take several days, but for every hour offline, hundreds of thousands of dollars are lost in productivity. In this instance, assisted reality devices enabled workers to view step-by-step instructions for any task they encountered during a shift. They could view and complete any workflow with a few simple voice commands, and their managers could analyse their work in real-time. In the instance of a pipeline failure, for example, natural gas companies must contact the site maintenance unit to respond immediately. Failure to solve the issue quickly will have a heavy impact on daily work and have potential security and safety risks. Using assisted reality wearables however, the dispatching centre can access real-time information for scientific decision-making and guide the technicians through emergency repairs accordingly. A wearable deployment in this instance can cut downtime significantly. Those are two examples that outline the benefits of having a ‘digital-first, reality-second solution’ on board. To give another more business-case-focused scenario, a skilled workforce will at some stage retire, making way for new technicians. With the remote video capabilities wearables provide, small groups of off-site senior managers are better able to safely mentor junior field technicians who are on-site. With assisted reality devices, the less-experienced workers can perform tasks quickly and safely with the oversight of skilled workers who can be based anywhere, providing them with training, guidance, and support. In such a scenario, companies are adopting technology to empower their new employees, increase productivity, and enhance worker safety long term. So why wearables over ruggedised smartphones, tough tablets or laptops, or smart glass? The fit-for-purpose technology offers a better and more cost-effective solution than both, because it improves worker safety and productivity with no trade-offs. Workers can operate assisted reality wearables hands-free, without the need to remove their gloves in full compliance of safety regulations. And they do not have to look for a place to set the device while they are completing a task, since the technology is compatible with PPE. In recent years, the traditionally conservative oil & gas sector has seen a push to embrace emerging technologies, including assisted reality. While this push was rapidly accelerated by the pandemic, looking beyond it however, oil & gas workers always need a better way to communicate and a better way to share information among themselves, whether they are on the same oil rig or half a world away; given that assisted reality meets their needs safely, effortlessly, and comprehensively, it’s fair to say that the technology is here to stay. In fact, as these majors begin to shift toward sustainability using wind, wave and solar, assisted reality will play a deeper role in our energy future.
From zero to hero Steven Bruce, Product Director at Idox explains how automated tag management helps digitalisation to deliver for the oil & gas industry
ometimes it is the smallest thing that make a difference. The ‘discovery’ of the number zero transformed science and maths and paved the way for our current technology-enabled world. Modern epidemiology and GIS (geographic information systems) both have their roots in John Snow’s seemingly straightforward work in 1850s London of plotting cholera cases on a map. Even today, when the impacts of those discoveries are all around us, the transformative effects of seemingly minor changes continue to be seen. Take digital twins as just one example: often cited as one of the ‘hero technologies’ for oil and gas’ digital transformation, but it is the often-overlooked areas – like automated engineering tag management – that help them retain their value.
Digitalisation dream This is something that engineering companies have been wrestling with for some time, as they provide digital twins to their asset-owning clients at the point of project handover. The digital twin, with its
advanced analytics, its visualisations, and advanced communications technology, is expected to provide seamless access to trusted, fail-safe data supported by relevant documentation to operations and maintenance teams throughout the oil & gas sector. In the best-case scenario, a digital twin significantly increases operational efficiency, while reducing HSE and compliance risk – especially valuable in high-risk offshore environments. Operations teams spend less time searching for content and can instead focus on value added
engineering tasks. The prize is a great one: imagine the value of an offshore platform, fully mapped out in such a way, to both those conducting operations and maintenance tasks on-platform, and for landbased engineers. And so, those engineering firms put in expensive and laborious processes for compiling a 3D digital model, that incorporates varying degrees of design and operational data. But, if that is all it is, then what they hand over is not a digital twin. It is an exercise in cartography. They have handed over a map – different in form but not in content to the one that John Smith used as a starting point for his studies in the 19th Century. That can be useful in the right hands – as John Smith himself proved – but the point and potential of a digital twin is surely that the intelligence is built in – not applied from the outside by a brilliant mind.
Missed potential The map is a snapshot of a moment in time. It can be a useful navigational aid, and yield plenty of valuable information about that moment to a welltrained eye. It is not a real-time representation of real-world topography. Such a map cannot drive greater efficiency and safety into the operation of the asset. This map cannot solve the same problems that arise in any scenario where data and documents are out of date. It still takes too long to locate the correct documents or data needed for a routine task and it risks using out of date information in an operational environment – the results of which can be catastrophic for critical oil & gas activity if, for example, a shut-off procedure has changed but not been updated in documentation. We have got to this point because for many, a digital twin is conceived of as a smart-looking replacement for the reams of paperwork that previously accompanied a major asset handover – a technological upgrade rather than a truly digital transformation. Although digital documents and 3D visuals can be valuable, and certainly an improvement on centrally located physical files, this approach really is just dipping a toe in the water of what can be achieved. A digital twin is supposed to be living and dynamic. It is updated in lockstep with its real-world counterpart and offers the user an ever-evolving array of related, updated data at the click of a mouse. It is, in fact, closer to a 4D model with time – and the changes it brings – being the crucial
element that manual processes and basic automations cannot capture. An obvious question then, is how the engineering company can offer an evolving digital record of the asset it has designed and delivered, as well as its ongoing operations, once its team have handed over the keys and stepped back from a completed project. This is where automated tag management comes in.
Manual leftovers For a digital twin to be fully useful, it needs to be ‘tagged’. In other words, every little component or system needs to have a tag attached that associates it with the relevant technical documentation, operational history, maintenance information and all the rest. Traditionally, tagging has been done manually, or subcontracted to a third party to do manually. It is an immense job, whoever does it, and it adds huge amounts of time and expense to a project. Consider a large asset such as a North Sea platform, that will typically have somewhere between 100,000 and 200,000 documents attached to it, which may be associated with 50,000 to 100,000 tags. Even if each document requires only 20 minutes work to extract and validate tags – 10 minutes from the document controller plus 10 minutes from an engineer – that comes to nearly 4,200 days. Even smaller semi-sub platforms or FPSObased projects could produce months’ of delaying and expensive labor. Having spent the equivalent of 11 man-years on tagging, those tags then need to be kept up to date if the digital twin is to remain a reflection of the live asset. It requires repeat tag-extraction and data-gathering projects, either at regular intervals of the asset’s life or during standard project execution. All of that is before we consider the need to prioritise tagging projects such that the most important information and facility-critical data is handled first, or the errors that inevitably occur when manual processes are long, detailed, and repetitive. Given the scale, time, and expense of the task, it is perhaps clearer why digital twins are often not kept live and up to date. The sheer volume of asset documents and data to maintain can be overwhelming. And digital twins have been underachieving as a consequence.
Automated tag management Very simply put, automated tag management replaces these severely sub-optimal
manual processes – and eliminates the problems associated with it. As the name suggests, it automatically scrapes all the relevant tags associated with the asset, and then automatically assigns them to the right data and documentation. The key to success is making data gathering a seamless part of project execution. By using a centralized project collaboration and document control solution that the entire oil & gas supply chain is connected to - data is gathered automatically and on an ongoing basis. As a bonus, it considerably streamlines the task of creating the
digital twin in the first place providing the solid foundations on which the digital twin is built. Automatic tag management is beautifully simple and truly transformative at the same time. Asset owners have reported that the amount of time members of staff in operations and maintenance side spend on locating necessary documents has been reduced by 50 percent, because they are no longer chasing down missing or incorrect tag data. Those achievements are substantial. But if we pan out, we can see there is even more at stake here. There is now a record of failed initiatives and companies wasting millions on projects that have been underwhelming at best. If digital twins and related digitalisation projects continue to underdeliver, it becomes a barrier to further investment and risks stunting progress of a very necessary digital transformation for the oil & gas industry, particularly when considering the digital needs of
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companies looking to demonstrate progress against the backdrop of the energy transition. The promise of digitalisation was always better use of resources, lower costs, greater safety – even improved sustainability. All advances that cannot be ignored. A digital twin and smart project management solution helps realise that, and automated tag management is the unsung hero technology that brings these tools to life.
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Protecting pipelines against costly product loss in extreme terrains Pedro Barbosa, industry sector manager - pipelines, at Fotech, a BP Launchpad company, reviews the current threats to pipelines and explores how advanced distributed acoustic sensing (DAS) technology is helping pipeline operators to protect their assets in extreme terrains.
or pipelines in the most extreme and inaccessible locations – whether that is in jungles, deserts, or mountains – providing continuous 24/7 monitoring of the entire pipeline using traditional measures is extremely challenging. However, this monitoring is vital for oil and gas pipeline operators who are under increased pressure to make cost savings while simultaneously reducing risk across their networks. By ensuring pipeline security and gaining full visibility in remote and difficult-to-access areas, operators can protect their assets as well as the integrity of the pipeline networks to minimise product loss. Statistically, product loss has been mainly caused by pipeline failure - ruptures and leaks caused by corrosion, mechanical damage, etc - or by theft-related events. Failure to monitor
against these threats adequately can easily cost an operator million in lost fuel from leakages and stolen product. Leaks also pose the risk of, and the cost associated with, environmental damage to the surrounding area. In the last decade there have been an average of 675 reported integrity incidents per year in North America alone, with an associated average annual cost of more than USD300 million. Indeed, two incidents, each originating from small orifices, resulted in leaks that went undetected for days;
Statistically, product loss has been mainly caused by pipeline failure - ruptures and leaks caused by corrosion, mechanical damage, etc - or by theft-related events.
A need for speed
more than two million litres of product seeped into the environment. The costs associated with product loss at that volume are estimated to be approximately $1 million, with the final clean-up costs estimated to have been significantly higher – in the region of $100 million in each case. Theft of product from hot-tapping, whereby organised criminal gangs seek to tap into the pipe to syphon fuel to tanks, is also a key issue worldwide. Many regions in the Middle East, Africa and Latin America are home to some of the most remote pipelines globally – located in the heart of extremely inhospitable deserts and forests. Major pipelines such as the East-West Cruel Oil Pipeline, which is a 1,200km pipeline that transports five million barrels of crude oil a day from the Abqaiq oil field on the Persian Gulf Coast to the Red Sea, have been specifically targeted in attacks. Problems with pipeline protection are not unique to the Middle East, though. There have been similar cases in South Africa, South America, the US, India, and Mexico, among others.
Historically, monitoring for leaks has been achieved using internal based systems, such as mass balance and real time transient modelling (RTTM). However, these systems infer the presence of a leak by computing different operational conditions using computational pipeline monitoring (CPM) based systems and, as such, tend to have long detectability times and very low sensitivity to small leaks. As a result, leaks are often overseen, or alarms are raised when large quantities of product have already been lost. In contrast, 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. Right-of-way surveillance for theft detection is also very difficult in remote locations under extreme conditions. Line walkers and aerial surveillance can be useful, but they do not provide continuous detection of events. As a result, large sections of pipeline in remote locations might be entirely unmonitored and extremely vulnerable to accidental damage or even criminal threats for large periods of time. There is a pressing need for a continuous monitoring solution – especially in extreme terrains – that enables operators to detect theft attempts and leaks accurately and quickly, supporting the pipeline operator in its efforts for product loss prevention. In North America there is a common requirement to detect a leak equivalent to one per cent of the flowrate of the pipeline. In a pipeline transporting 100,000 barrels of oil per day, that one per cent 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, and by the time anyone arrives on the scene, hundreds of barrels will have been lost. If criminal activity was at play, the offenders will be long gone. This is especially challenging deep in the jungle where supporting monitoring technology of helicopters and drones will not be able to operate easily or to see through a thick tree canopy. So, speed is of the essence for operators seeking to protect their pipelines and their contents. Pipeline Intrusion Detection Systems (PIDS) using advanced sensing technologies play a key role here.
Distributed Acoustic Sensing as the answer One technology that can monitor pipelines accurately for both leak detection and disturbances relating to attempted theft is distributed acoustic sensing (DAS). Fotech’s LivePIPE II solution uses photonic sensing DAS technology that essentially turns 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. 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.
Accurate leak detection LivePIPE II 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 can 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. 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.
A smart way to enhance security Fotech’s LivePIPE technology has been proven in the depths of the South American jungle. During the Site Acceptance Test of a LivePIPE solution on a pipeline prone to hot tapping and theft, an unexpected signal was detected at a location in the rainforest. The pipeline operator initially
location. Through the intervention, directed by the LivePIPE technology, the drilling was stopped, and subsequent detonation of explosives close to the pipeline prevented - averting what would have been a very serious incident.
Effectively monitoring network integrity
considered it a false alarm, due to the remote position of the section of pipeline. However, Fotech’s engineers insisted that a visit should be made to the site as the detected vibrations had all the characteristics of human activity. At the site, a seismic team were discovered drilling holes in the ground ready for explosives, as part of their exploration activities. Their GPS navigation had malfunctioned and taken them a significant distance away from their intended
Pipeline integrity is one of the biggest priorities for pipeline operators due to the significant environmental damage and vast costs that can result from incidents – whether accidental leakage or malicious theft. However, monitoring in remote and extreme terrains has been a challenge for existing technologies. DAS-based PIDS such as LivePIPE II are becoming an essential part to pipeline safety and security strategies worldwide as these systems help operators to protect their assets effectively against product loss. By gaining real-time visibility of the integrity of their entire pipeline network and across all terrains, operators can protect their bottom-lines while also reducing risk. Thanks to its continuous monitoring, DAS provides a vital layer of additional intelligence, able to detect and to pinpoint the location of multiple threats simultaneously, such as small leaks and third-party interferences. This technology can also work together with existing monitoring measures to complement them, rather than to replace them. By combining information gathered from multiple monitoring and maintenance sensors into an overarching view, only then can operators have a detailed understanding of what is happening on the pipeline at any given moment, and they can respond with confidence to any events before they become major incidents.
Seven steps to completion heaven Mette Lind Fürstnow, reservoir engineering at Welltec talks us through the various benefits of utilizing a data driven tool to optimise their completion strategies
il and gas operators are increasingly shifting their attention onto improving the environmental aspects of operations, with the additional focus of reducing cost. By developing a data-driven value proposition tool, Welltec has been able to calculate and substantiate the advantages of their innovative completion technologies.
Step one: Deliver a simplified and safer design The core of our discussion with operators has for some time been set in the question of how to simplify wells. In the past, that discussion is more likely to have been product-based, but now with the development of a highly detailed cost-benefit tool, this can be discussed over a data-driven and factual analysis. Part of the simplification process could include standardization. Traditionally, some wells are incredibly complicated in design, but we can often pare down, so we have fewer liners. An added benefit is that because there are fewer components involved in some cases, so the well construction will be considerably safer with a reduced level of high-risk activities.
Step two: Reduce the well completion time and lower the cost This step goes hand in hand with the first. Because we are reducing the time that the construction takes – and that means often reducing the time a rig needs to spend on site – that of course delivers reduced costs. The time it takes to complete the well construction is also reduced because we use fewer components and eliminate the need for the cementing process. Although the components we use can sometimes increase the cost of the downhole equipment, by reducing the overall rig time we still
deliver savings on total cost of construction. In all completions, the two high-cost variables are the rig itself and the cementing activities.
Step three: Ensuring a more predictable well construction Predictable well construction is all about reducing risks and unknowns. When we deploy our packer technology (Welltec Annular Barrier (WAB®)) we have a high success rate: we know that we
can set the packer with very few risks. With a cement solution there is considerably less predictability and more substantial risk both in terms of reliability and time. But when quantifying predictability, it is crucial to be able to put verified data and numbers up to be viewed. Now with the cost-benefit analysis tool, we are further improving engagement and it allows us to take a cross-disciplinary approach during discussions with operators. We can now portray the full well
solution scenario in a more complete manner, including operations, products, and technology.
Step four: Reduced environmental footprint Cement is commonly known to be a significant contributor to negative environmental change. It is the most widely used man-made material in existence and the source of around 8% of the world’s CO2 emissions, according to think tank Chatham House. If the cement industry was a country, it would be the third-largest emitter in the world - behind China and the US. In the completion of wells, cementing is introduced to the annular space between the wellbore and casing, or to the annular space between two successive casing strings. By reducing cement and improving the construction timelines we can reduce the CO2 footprint of a project. This has become a far more common consideration of operators over the last few years, with many looking to strengthen their environmental credentials.
Step five: Increased productivity and
net present value Within the cost-benefit tool, we can look at the construction steps along with the time and cost associated with each step. Above and beyond that, we can also include production period of a well. Decline curves can indicate how our solution would have a different production potential than a client’s reference well, and allow us to calculate the Net Present Value (NPV) – this enables us to look ahead of construction and into the long term to include operating costs. We can now also show the benefits and any risks of moving away from an intelligent well completion. Operators may wish to discuss what the additional OPEX costs of having to conduct mechanical shifting in our solutions would be, and we can demonstrate what it means on the cost profile. Often, we can show that it is a good business case and does not damage the NPV. For the simple decline curve, we look two to three years into the life of the well. We adopt this relatively short timeframe because we do not have access to the reservoir modelling data that would allow us to build a bigger picture of the reservoir. That is not to say that our wells only have advantages in their early life, they traditionally perform better than most wells towards the end of life because of the way that we manage risk. The cost-benefit tool has been applied for 18 months, and we have a vision of greater integration with the subsurface. For now, our primary clients are still completing and drilling, and they do not look at NPV the same way as subsurface. For them, it is a focus on cost and time of the well construction.
Step six: Reduced long-term risk Risk and complexity go hand in hand. By reducing complexity, the risk can become more transparent and better understood. Simplifying the well by making it full bore makes it easier to carry out interventions and maintenance. By doing this, we reduce the risk of tools becoming stuck downhole, or of the well failing to perform 10 or 20 years into operation. By utilizing the data-driven methodology in our cost-benefit tool, we account for uncertainty around cost, time, and production. The broader message is that when you take risk into account when designing and constructing a well, you can take control of that risk later in the lifecycle. That could be the maintenance risk that you cannot access the well, but it could also be that we suggest greater segmentation of the well with more zones. For example, if water breaks through, the ability to
close off a particular zone without having to shut off half the well is highly beneficial. Step seven: Reducing the operating cost through a well’s lifecycle This often comes down to a comparison between an intelligent well completion and our flex well with segmented zones. The reliable and flexible solution that we can offer delivers cost-saving benefits throughout the operating lifecycle of the well, especially in terms of reduced interventions and improved well integrity. We believe that by broadening the conversation and delivering data-driven options with full visibility, we can engage the entire value chain of an operator’s team, from drillers through to the sub-surface engineers. The operators are often presented with a wide range of options when it comes to completion systems, and they have varying pressures when it comes to selecting their optimum solution. Today’s cased hole completion systems vary from relatively simple single-zone low-pressure/low-temperature designs to complex high-pressure/high-temperature applications. These types of wells were unthinkable with the technology available 50 years ago. When it comes to discussions with clients where we need to convey the multitude of complexity and risk, we believe we can simplify the choices by presenting exact, fact-based options. There will always be pressure for an operator to opt for the lowest upfront cost without thoroughly investigating the potential for risk or cost overruns during the full life-of-well. However, we believe that by delivering a trustworthy, data-based, and fully costed, risk assessed well design option, operators will be able to make a fully informed decision regarding the best option to take.
Winds of change can blow in favour of North Sea’s oil and gas industry The North Sea Transition Deal has laid down a major challenge for the oil and gas industry. Published in March this year, it calls for the North Sea to become a net zero basin by 2050.
o achieve its net zero ambitions, the government has set what many see as being ambitious targets for the oil and gas sector such as reducing the level of production emissions by 10 per cent by 2025, rising to 25 per cent by 2027 and to 50 per cent by 2030. For assets which cannot meet those targets, the financial impact of increased emissions penalties through carbon taxes could be crippling, potentially pushing them towards earlier than planned decommissioning and threatening the UK oil and gas industry’s role in homegrown energy supply. Green infrastructure developer, Cerulean Winds, says it
has the answer. The developer has unveiled an ambitious plan which would accelerate the decarbonisation of North Sea oil and gas assets through an integrated 200-turbine floating wind and hydrogen development. Founded by Dan Jackson and Mark Dixon, who have more than 25 years’ experience working together on large-scale offshore infrastructure developments in the oil and gas industry, Cerulean Winds can produce green power to electrify most of the UKCS’ oil and gas assets and dramatically reduce emissions. North Sea assets currently produce 18 million tonnes of CO2 emissions a year. If it gets the go-ahead before the end of the year, Cerulean says its scheme could more than halve those emissions from 2025. The ability to electrify those assets as well as future production potential from 2025 would give
oil and gas companies the capability to reduce their emissions well ahead of abatement targets. In a recent report, the European Technology and Innovation Platform on Wind (ETIPWind) and WindEurope said that electrification is the most cost-effective way to decarbonise Europe’s economy. Cerulean agrees and says the availability of 100 per cent green power at a price below current gas turbine generation through a self-sustained scheme, with no upfront cost to operators, will result in considerable savings. Currently generating electricity by gas on platforms ranges from £70 to £130 per MWh; the Cerulean scheme is targeting a maximum of £70 per MWh. The proposed Cerulean development involves more than 200 of the largest floating turbines located at sites to the West of Scotland and in the Central North Sea with 3GW per hour capacity feeding power to the offshore facilities. An excess 1.5GW per hour would be diverted to onshore green hydrogen plants. But the ability to proceed with the proposal hinges on a decision from Marine Scotland. The company has made a formal request for seabed leases, asking that the Scottish and UK governments make an “exceptional” case to deliver an “extraordinary” outcome for the economy and environment. A favourable decision, says Cerulean, must be made by Q3 this year to progress the scheme to meet the timescales set out in the North Sea Transition Deal. “Timing is absolutely crucial in this,” said founding director Dan Jackson. “Everything hinges on those leases being granted, even conditionally, by this autumn so we can move ahead on schedule. “The risk of not moving quickly on basin-wide decarbonisation would wholly undermine the objectives set out in the North Sea Transition Deal. The UK is progressing the energy transition, but a sense of urgency and a joined-up approach from government and regulators, as well as industry, is essential to enable rapid decarbonisation of oil and gas assets. “This is the only project currently in the pipeline that can deliver these results within the timescale. It we don’t get the go-ahead, then there’s nothing else out there that can work across the whole of the UKCS in time to get even close to those targets, let alone meet and exceed them.” Cerulean has undertaken the necessary infrastructure planning for the scheme to ensure the required level of project readiness, targeting financial close in Q1 2022. Construction would
start soon after with energisation commencing in 2024. An Infrastructure Project Finance model, commonly used for major capital projects is being adopted. Société Générale, one of the leading European financial services groups is advising Cerulean Winds. Allan Baker, Global Head of Power Advisory and Project Finance commented: “The Cerulean UKCS decarbonisation project has the potential to meet all of the basin’s transition needs by reducing oil and gas emissions as quickly as possible whilst also introducing large scale green energy. We are pleased to be supporting the leadership on what is a transformational proposition for the UK.” Corporate finance advisors to the energy industry Piper Sandler are also advising. Tim Hoover, Managing Director, Project Finance Investment Banking at Piper Sandler added: “The Piper Sandler investment bankers in the UK and in the US have partnered with Cerulean’s leadership over the last year to develop the UKCS decarbonisation model and we are pleased that it is now at the regulatory approval stage; it is a scheme that understands the needs and requirements of the financial markets to make it bankable.” The Cerulean leadership team already has Tier 1 stakeholders in place to deliver the development and it has engaged the financial markets for a fully funded infrastructure construct. Last month, it named NOV, one of the largest providers of marine equipment and wind vessel
designs in the world, as the first of its delivery partners for the fabrication of the development, establishing NOV as the exclusive provider of floating and mooring systems. The company is not disclosing who its other Tier 1 stakeholders are at this stage, but say they are some of the largest providers in the world, with the scale and capacity to deliver this project. Cerulean estimates that if the project goes ahead, 160,000 oil and gas jobs can be safeguarded and 200,000 new roles within the floating wind and hydrogen sectors will be created within the next five years. Dan Jackson added: “We have a transformative development that will give the UK the opportunity to rapidly decarbonise oil and gas assets, safeguard many thousands of jobs and support a new green hydrogen supply chain. “The recent controversy and scrutiny over West of Shetland oil and gas developments emphasised how important it is to move quicky. To give new developments the go-head to proceed if they’re going to be adding to the already unacceptably high level of emissions contradicts government objectives. “We are ready to deliver a self-sustained development that will decarbonise the UKCS and be the single biggest emissions abatement project to date. This’ll not only benefit existing developments but would enable new developments to come from a starting point of zero emissions.”
The changing face of asset management Oscar Bos, operations director for asset integrity and maintenance optimisation and Grant Allan, offshore integrity manager at Vysus Group reveal the five things they have learnt about asset integrity and maintenance optimisation 32
sset integrity and maintenance optimisation will be more crucial than ever as the global economy moves into the net-zero and post-Covid age. Over the past 12 months, we have seen the world and how we approach everything change dramatically including the universe of asset integrity and maintenance optimisation. Asset integrity and maintenance optimisation is ever expanding; hard-won experience combined with next-generation solutions will help the industry gear up to tackle the challenges, and grasp the opportunities, of the coming decades. Decisions will of course always be made in the long-term interest of any asset – how, where, and when to inspect, based on international standards and codes and resulting in a plan that meets operational requirements. And while the requirements of the post-Covid, net-zero economy will often
require new thinking and fresh perspectives, the valuable lessons learned over many decades must not be forgotten. That is why the key elements that drive successful asset integrity, established by experts working at the leading edge of the industry, are more important than ever before.
1. Oil and gas . . . and much more Like many companies, Vysus Group, previously Lloyd’s Register Energy, has had a long and mutually beneficial relationship with the oil and gas industry. The demands of operating in some of the harshest environments on earth require the expertise and experience inherent in a top-class risk-based inspection and reliability centred maintenance services. The horizons of the sector, however, extend further. The same robust practices that make asset integrity and maintenance optimisation services so crucial to oil and gas also extend to any business with capitalheavy assets. This includes refineries and FPSOs, but also the downstream petrochemical sector including the manufacture of fertilizers, solvents and other high-risk materials, as well as essentials such as paint, rubbers and plastics. Furthermore, crucial and growing parts of the global economy have long tapped into integrity and inspection services to manage and safeguard complex industrial assets. These include but are not limited to food production, breweries and distilleries, large-scale transport including railways and ferry networks, and utility and network infrastructure.
2. Nothing stays the same New challenges within the world of asset integrity and maintenance optimisation, as well as the opportunities those offer, cannot be ignored; the skills honed in mature industries have much to offer on the cutting edge. The drive towards increased electrification of the economy and the expansion of renewable energy is a particular growth driver. These technologies have the same maintenance and integrity issues as more established sectors and can benefit from the continuity provided by best practice. The desire to keep in operation assets and systems beyond their originally intended useful design life has seen a steady increase over the last years with a steep incline in the last 12 months making asset integrity management more and more crucial to continued profitable operations. Offshore and onshore wind, the hydrogen economy,
utility-scale solar, network heat, charging infrastructure and battery technologies – the new markets across green energy production, supply and storage continue to multiply. The independent space sector is also a growing business area and further evidence of the sorts of capital-intensive, asset-heavy industries putting their shoulder to the wheel of the global nextgeneration economy. Adaptability and application of existing expertise in safety, reliability and economy will fuel that journey. At Vysus Group, we stand by ready to support.
3. Skills are skills A workforce forged in the age of oil and gas has been reshaped and refocused to tackle the ever-changing demands of asset integrity and maintenance. Experience across pumps, fluids, compressors, and piping will if anything become more not less crucial over time; reliability engineers, integrity engineers, corrosion engineers and other specialists will bring their high-level training to bear on new applications, new thinking and new technologies. Our customers are also changing, and there is of course an inherent responsibility to grow and adapt along with them. As energy companies continue to diversify, Vysus Group is ready to support that evolution; for new industries taking root on the global stage, tried and tested methodologies can extend proven expertise to a whole new class of assets.
4. Savings are not always about costs An asset performing at its best creates optimal returns over time in the safest possible
environment; Risk Based Inspection (RBI) and Reliability Centered Maintenance (RCM) are tools to achieve those ends but should not be considered as some kind of ‘deploy and forget’ solution. Integrity management is a choice for the life of an asset, a commitment to gather as much information as possible to make the decisions necessary to maximise reliability over a project lifecycle – this is the heart of keeping risk as low as reasonably possible. It is possible that more rather than fewer inspections will be required over time, that the detailed insight provided into how an asset behaves in its environment prompts choices that in the first instance can sometimes require investment rather than an instant cash saving. However, what is constant from the process is the resulting increase in reliability, availability, the higher level of safety achieved, the optimised performance ensured, the reputation enhanced and preserved – all of those represent a substantial and long-term return on any upfront investment.
5. Laying foundations for future solutions Expertise is evergreen; it does not go out of style, maintaining its value over time and justifying the related level of investment. This is especially important to remember in the world of asset integrity and maintenance optimisation. Skills honed over nearly a century working with leading global industries have never been more important. The new technologies with the potential to transform our world are subject to the same requirements for reliability, safety, and stewardship as those that came before.
The investment dilemma Neos Networks examine how oil and gas firms are balancing digital transformation with the transition to renewables
urbulence seems to be an unshakeable characteristic of the oil and gas sector. Geopolitical tensions, technological innovations and changing consumer preferences combined with growing demand in developing economies, all make for ongoing uncertainty in the market. With this knowledge, deciding how best to invest in technology for a more profitable and stable future can be a daunting prospect. However, there are two stand-out areas that are vying for investment, with companies facing similar pressures to focus on digital transformation, and the clean energy sector. Digital transformation is undeniably a key challenge and has been ongoing for some time, with companies striving to unlock maximum value through digitisation. Many businesses have already made significant progress, but investment in advancements such as the Industrial Internet of Things (IIoT) and remote monitoring will still be required for many. Meanwhile, oil and gas companies are also investing more and diversifying into the renewables space as they face rising pressure to decarbonise energy provision. And yet, concerns remain that a greater focus on future energy transition may undermine the profitability of businesses, a subject of worry for many in the industry. A key stumbling block that oil and gas businesses must overcome when planning investment in digital transformation or cleaner energy, is integrating new technologies and platforms into the existing network. Looking to partner with
expert service providers can offer a solution for companies struggling with these operational challenges.
Shifting to digital Digitisation remains an important goal for organisations in the sector due to its potential to produce outstanding increases in performance, efficiency, and reliability through technologies such as Artificial Intelligence (AI), Cloud and Internet of Things (IoT). For example, AI can use pattern recognition, image analysis and natural language processing to enhance operational and business efficiency, and significantly reduce margin for error. Digital transformation also allows companies to be more agile and responsive, vital in ensuring resilience in uncertain and volatile markets. The potential gains in performance can be seen in the estimates that digital transformation could unlock up to $2.5tn of value from society and industry, over the next decade. The World Economic Forum identified four key ways in which digital transformation will facilitate this return on value: 1. Data-driven digital innovation Real-time data points will enable greater automation and advanced analytics and modelling. Furthermore, smart, and immersive technologies (including AI, Augmented Reality (AR) and chatbots) will ensure connected worker applications, fostering multidisciplinary working and productivity. 2. Innovative engagement models Customer services will be enhanced with digital platforms, and omnichannel experiential services
can evolve, bringing more value and satisfaction to core customers. 3. Integrated digital platforms Utilising AI to bring together disparate data sources will enhance the widespread balancing of real-time supply and demand throughout a supply chain. Digital tools will also enable rapid information transfer via blockchain, making operations quicker and more efficient. 4. Energy digitalisation Using digitalisation to conduct monitoring with greater accuracy will enable companies to offer optimised choices to consumers around energy, customising the consumer experience and offering
under rising pressure to meet decarbonisation targets and diversify into the cleaner renewable energy space. Companies have responded with significant investments in the field, with estimates that the most prominent players in the oil industry will spend over $18bn on specific renewable energy products from 2020 to 2025. Investment has already been in motion for a while. For example, Equinor, Shell and Total have already contributed towards the $685m ‘Northern Lights project’. This is the world’s first CCS (Carbon Capture and Storage) network, facilitating the capture and storage of up to five million tonnes of carbon dioxide in an offshore saline aquifer in the North Sea. Total is one major player committed to decarbonisation, with a target set to become net-zero in Europe by 2030. Total has invested in Seagreen Wind Energy, having last year acquired a 51% share in the offshore wind farm located off the coast of Angus in the North Sea firth. The company’s timeline anticipates investing up to £2bn per annum in low-carbon electricity by 2020, increasing to 20 per cent of CAPEX by 2030. The ROI of six per cent on Seagreen that Total are expected to receive is also expected to contribute in covering off revenue deficits caused by the oil price crash triggered by Covid-19.
Both or nothing
more options and capabilities. The World Economic Forum also suggested some broad challenges which have proven to be obstacles to digital transformation amongst companies, including legacy regulatory frameworks, insufficient standardisation, minimal ecosystem collaboration and talent gaps. Despite these barriers, many companies are forging ahead with the adoption of digitalisation. The Axora 2021 Innovation Forecast: Oil and Gas survey of senior decision makers worldwide found that 55 per cent reported that they were at an ‘advanced stage of implementation’ for digital transformation, and 89 per cent said they invested more in digital transformation over the past year in comparison to previous years.
A cleaner future Faced with mounting incentives to digitise, oil and gas businesses are also
While digital transformation has long been a priority for the oil and gas industry, it has been demonstrated that the cleaner energy transition presents an equally, if not even more, profitable, and future-proofing investment. With the benefits of these two areas of investment being pertinent, oil and gas companies must find the means to invest in both to secure their future. In fact, prioritising one area can aid the other, with digitalisation one of the most significant enablers of the global transition to cleaner energy. It must also be recognised that investing in these priorities demands leading edge network infrastructure and high-capacity connectivity, to deliver the robust, resilient, and rapid service required for optimal operations. When looking forward, oil and gas companies would be wise to partner with experts in the telecommunications field, as well as the energy sector, to ensure they are receiving the best possible value from their noteworthy investments.
Preserving innovation in the era of low oil demand Duncan Nevett, partner at Reddie & Grose explains how the demand for oil may have peaked. What does this mean for innovation in the sector?
he transition to clean energy is well underway. In the UK, new legislation is accelerating the shift away from fossil fuels and increasing innovation into renewable energies. The government has released an ambitious ten-point plan to facilitate the green industrial revolution. It has also already set aside £12 billion to invest in renewable initiatives that will support the creation of up to 250,000 green jobs. However, two thirds of global electricity supplies still come from fossil fuels, and according to a recent BP report, global demand for oil has reached its peak. This does not mean that the oil industry will disappear overnight. In fact, from a patent perspective, we are seeing more patents being filed in the oil and gas sector than ever, superseding renewable energies such as wind and solar by a significant margin. The race is on for Oil and gas companies to innovate to survive. So, how can companies turn this into an opportunity to emerge as a frontrunner and protect their innovations while the clean energy industry is still evolving?
The complex situation for Oil and gas In addition to the transition to green energy, in recent years the oil and gas industry has been experiencing a number of challenges that have impacted its profitability. Most notably, price volatility. The price of a barrel of oil has oscillated over the last decade with Brent Crude Oil ranging from as little as $30 per barrel to $100+. This volatility in price has come at the same time as depletion of oil reserves that are relatively cheap and easy to extract from. It’s true that new reserves continue to be discovered - but they are often impacted by issues such as harsh terrain, or are considered “unconventional oil” such as oil
sands which, until recently, were seen as prohibitively costly to extract from. In the past, success in the oil and gas industry was largely due to careful management of risk and capital. However, remaining profitable in such a challenging energy market is becoming increasingly difficult and the focus has shifted to innovation in order to stay competitive. So, as oil becomes harder to extract, prices become more volatile and global demand for green energy grows, the Oil and gas sector must consider how to stay profitable, and survive in a cleaner, more sustainable future.
Going green Many Oil and gas companies are re-evaluating their business models and examining where they fit in, in a more sustainable energy-driven world. BP’s report shows that global demand for oil is set to decrease by 10% this decade and by as much as 50% over the next 20 years. This has led BP to set out bold plans to transition to net-zero emissions by 2050 – as an “integrated energy company”, rather than an oil major. The company has announced plans to cut oil production by 40% and ramp up low-carbon spending to $5 billion annually by the end of the decade. Many in the industry have announced similar plans to boost investments in clean energy. Shell has taken a slightly different path, announcing ambitions to become the world’s largest power company, and setting new targets for electric-car charging, carbon capture and storage, and electricity sales. This shift away from pure fossil fuel reliance in the Oil and gas sector perhaps explains why patent filings in core fossil fuel technologies are growing at a slower
rate than those in renewable technologies, such as wind and solar. However, a slowdown in patent filings for fossil fuel specific innovations does not mean that Oil and gas majors have given up patenting entirely; on the contrary, a closer examination of patent filings from Oil and gas companies reveals a more complex picture of how major players are looking to futureproof their businesses.
Future-proofing with Patents If we look to patent filings in the sector, we can see that Oil and gas companies are increasing their innovation and patent activity in the area of extraction and drilling, whilst also more actively patenting in green energy sectors. This two-prong approach has the benefits of: firstly, improving the way oil and gas can be accessed and extracted from a range of terrains, thus leading to a more efficiently and reliably obtained energy source; and secondly, opening up the potential for growing future revenue streams as the transition to green energy continues. For example, patents related to extraction techniques such as hydraulic fracturing have been particularly prominent in the oil and gas industry throughout the past decade. This technology, along with horizontal drilling can enables the extraction of large oil and gas reserves trapped in shale and other source rock formations. Companies such as oilfield service majors, equipment manufacturers, suppliers of proppants and compositions, supermajors, and large E&P independents have filed nearly 1,000 hydraulic fracturing related patents since 2006. This demonstrates that despite the transition away from fossil fuels, Oil and gas companies haven’t given up developing innovations in extraction technologies, because there’s still an ongoing need for cost-efficient and reliable ways of obtaining these raw materials. On the other side of the coin, patent filings show that many upstream Oil and gas companies are diversifying and investing in sustainable and renewable energy solutions, whilst others are utilising more environmentally friendly technologies such as carbon capture and storage (CCS) for enhanced oil recovery, as well as converting natural gas into hydrogen and capturing the CO2 released to produce a renewable fuel that could be used in home heating, industry and in the future, even ships and planes. By way of example, in 2020 alone Chevron, Saudi Arabia Aramco and Total had over 150 European patents published in
a technology sector the European Patent Office label as being “for mitigation or adaptation against climate change”.
IP Considerations As Oil and gas companies seek to transition away from fossil fuels to renewable energy, they must consider how filing patents for innovative clean technologies early on, can protect their profits in the long-run, and ensure a strong footing in future markets. Whilst larger Oil and gas players have been diversifying their patent portfolios for years, smaller oil and gas companies may not have previously seen patenting as worth the reward. However, it’s more urgent than ever for this approach to change. For the first time, disruptive enterprises and start-ups have an unprecedented opportunity to knock major players off the top spot by monetising their innovations first and making their technologies essential to the future energy landscape. Patenting has long-term financial benefits and doesn’t have to be expensive in the initial stages thanks to funding initiatives and the capacity to spread costs through tactical filing strategies. The transition to green energy therefore doesn’t have to signal the end of oil and gas companies. As long as businesses adapt their expertise, adopt new processes and protect their innovations, their operations can remain commercially viable for years to come.
Innovations in produced water management ease the burden of legislative compliance for upstream operations Produced water poses a growing problem for many offshore production facilities, but new methods of in situ filtration could significantly reduce the costs associated with discharging at source.
pstream operations currently face a barrage of increasingly complex challenges: Wood Mackenzie report that development spend will remain 30 per cent below pre-pandemic levels for the rest of 2021, pressure to reduce carbon emissions continues to grow and there is still a lot of uncertainty around near- and long-term demand for oil.
Environmental regulations Tightening environmental regulations will be the final straw for many upstream projects, but there is no getting around the fact that legislation designed to curb the environmental impact of oil and gas operations is becoming increasingly stringent. This is particularly true of legislation surrounding the discharge of produced water. Just last month, US democrats tabled a bill that sought to reclassify produced water as hazardous waste, which would change the requirements for its disposal and make it much harder to dispose of using traditional techniques. Operators working in the North Sea, the Celtic Sea, the Bay of Biscay, the Iberian coast or the wider Atlantic will also know about the regulations put in place by OSPAR, which state that produced water cannot be discharged back into the sea if it has a hydrocarbon content greater than 30ppm. Fail to meet these exacting standards and your operation risks the scrutiny of OSPAR’s Offshore Industry Committee (OIC). You may be forced to helicopter samples of your produced water back to a certified lab for testing - a costly and time-consuming process that imposes a significant burden on stressed operations - and operators who fail to lower the hydrocarbon content of their produced water may be asked to transport it to on-shore facilities where it can be treated under the supervision of the OIC’s technicians.
Treating produced water Unfortunately, traditional methods of treating produced water in situ can be just as expensive.
Some producers may find that they can inject a small amount of their produced water straight into underground reservoirs, but a significant volume of produced water needs to be treated using inefficient floatation units, dissolved air precipitation techniques or expensive chemical solutions that must be stored and mixed on-site, an option that necessitates the employment of specialist personnel, which can rapidly inflate the running costs of offshore facilities. Some operations also ship or truck their produced water to commercial treatment facilities scattered across the globe; but this can be prohibitively expensive for remote installations or production facilities that produce large volumes of contaminated wastewater. In total, ReportLinker estimates that $8.1 billion was spent on the treatment of produced water in 2020, and this number is set to rise as wells age, legislation becomes more stringent and the cost of treatment increases.
Innovative water treatment technology But new innovations in filtration technology may provide a more cost-effective solution to this increasingly complex problem. Separo (formerly Solids Control Services) has been working on the development of their SepSORB filtration vessels capable of lowering the hydrocarbon content of produced water from well in excess of 100ppm to below 30ppm in a single pass. While that is a level low enough to meet the requirements for on-site discharge into any sea currently subject to environmental legislation, the system is proven to reduce levels to as low as 3-5ppm in some instances. These filtration vessels are relatively small and lightweight; weighing less than 10 tonnes and taking up less than 15m² of deck space once installed. This makes them a good fit for spacelimited environments like offshore installations, where room for equipment is always at a premium.
Effective hydrocarbon reduction To date, more than 100 of these filtration vessels have been installed on platforms in the North
Sea but Andrew Crutchley, Separo’s chief operating officer, is quick to point out that they could be deployed to almost any facility on the globe. “They’re a very scalable technology.” he says. “You can build them to spec in a matter of weeks and deploy them in a matter of days so there’s none of the back and forth associated with more traditional produced water solutions. “We recently deployed a SepSORB system on a platform owned by an E&P client operating in the North Sea. The client in question was struggling to bring their produced water under the required 30ppm set by OSPAR and their team were keen to solve the problem without incurring the significant costs associated with onshore treatment. “We flew in a team of our own engineers and installed the vessels in situ before training up some of the installations core crew on the necessary safety checks and monitoring. Each filter vessel can handle between four and twenty cubic metres of water per hour, which was enough to bring all the produced water from this facility down to approximately 3-5ppm in a single pass, but there is always the option to add more vessels in situ if needed. “It’s a green solution too. The filter media can be shipped back to shore after use; cleaned and reactivated so there’s minimal waste.” As we move towards a future that promises to bring increasingly stringent and invasive regulations to bear on produced water management, advanced filtration technology could provide a much-needed lifeline for struggling upstream operations. Scalable filtration technologies could also lend a new lease of life to operations conducted on aging oil fields, where the volume and contamination of produced water can fluctuate rapidly. Unlike chemical filtration, they can be ramped up or down to cope with sudden spikes in demand; allowing offshore operations to stay agile and responsive in these uncertain times and reducing the need to always keep specialised personnel on-site.
Decarbonising the energy sector Astrid Poupart-Lafarge, president of oil and gas, Schneider Electric discusses ways to reduce the lifecycle GHG emissions of an offshore compression platform
he oil and gas industry is vital to ensuring the world’s energy transition, yet the production and transformation processes represents 15 per cent of the overall industry footprint according to the IEA. It is also one of the most energy intensive industrial processes. In recent years, Schneider Electric has embarked on the journey to help decarbonise the energy sector with the help of data, software, efficiency, and green electrons. The company’s mission is help create a more sustainable and efficient energy industry with new sources of clean energy. There has been a lot of talk in the industry about Green Premium especially since Bill Gates has been more vocal about this topic in recent months. The Green Premium concept does a great job in highlighting cost as the key barrier to adopting cleantech. But the main risk lies in ensuring government and industries can distinguish between technologies and solutions that will never be suitable for mass deployment versus those that can potentially make a significant and immediate impact, once scaled up. Our belief is that ambitious environmental considerations must be embedded in all processes, products and business decisions. We are committed to facilitating meaningful change. Today, more than 75 per cent of Schneider Electric’s product sales come from Green Premium solutions that offer superior transparency and environmental stewardship, as well as improve resource-efficiency throughout an asset’s lifecycle. This includes the efficient use of energy along with the minimisation of CO2 emissions, water, air, and other natural resources, putting us on the right path to a Net Zero future. When it comes to the oil and gas sector, we can go further. I believe that Net Zero upstream facilities are the future for the oil and gas industry. It is something that is already possible today, with the solutions we have now. The first step to that Net Zero future is changing the sector infrastructure and best practices to future-
proof them for 20-30 years to come. Schneider Electric, together with McDermott and io Consulting, released the findings of the ‘Net Zero Upstream Facility’ study in March 2021. It reveals that for a minimal total expenditure ‘Green Premium’ increase of 2 per cent, the solution operational emissions of oil and gas operators could be reduced by a staggering 76 per cent, while embedded carbon (CAPEX emissions) could be dropped by 17 per cent. This can be achieved through a high mix of renewable grid power, SF6-free switchgear, designing out the flare system and the so-called fugitive emissions, encouraging remote operations and increasing staff safety. The core of the study was the development and evaluation of five alternative concepts to identify the optimal solution for reducing the lifecycle GHG emissions of the reference case facility - an offshore compression platform located 100+ km from shore in a water depth of 100+m. The platform is sized to process a maximum capacity of 650 MMSCFD of gas with no provisions for condensate treatment and removal or produced water treatment and removal. The platform has full utilities and support systems. The intent was to develop a facility that has minimal carbon intensity. This is achieved using power from the mainland grid, a grid that is partly based on renewable power generation, and the use of equipment and instrumentation that minimises/eliminates potential leaks or venting requirements. Ten years from now, one positive thing 2021 will be remembered for is how the concept of Net Zero became a mainstream activity that reshaped the economy. The pivotal shift that has made this more sustainable future possible is the rapid acceleration of digital. Though corporate action has spurred progress in addressing climate change, to date only 23 per cent of Fortune 500 companies have made public climate commitments to meet by 2030. This is surprisingly low given the awareness of the potential consequences of climate change on our planet as well as future generations. As Secretary-General of the U.N. António Guterres pointed out in a speech in September 2019, “the climate emergency is a race we are losing, but it is a race we can win”. There are many green alternatives available today for the oil and gas industries that reduce costs and more than pay for themselves over their lifespan. As we undergo the energy transition, it’s important to invest in decarbonizing the oil and gas sector as the costs have proven to be marginal in comparison to the benefits. When you consider that 80 per cent of all carbon emissions are due to energy consumption, and 60 per cent of the way we manage energy is inefficient, the scale of the task of changing the ways we create, manage and use energy to reach Net Zero is significant, but so are the potential benefits. As an industry, we must empower key players to make sustainable energy choices that reduce GHG emissions in a sustainable and affordable way and don’t cost the planet.
Ensuring the seal for pipeline safety The US pipeline industry has taken a global leadership position on pipeline safety, with a voluntary performance tracking initiative contributing to detailed information about spills and releases, along with their causes and consequences. Lessons learned from this pioneering exercise are relevant to pipeline operators across the globe, says Richard Smith of AESSEAL, and sustainable and costefficient solutions are available to one of the most common root causes of spills and releases. 42
he US has perhaps the biggest pipeline network in the world, with over 190,000 miles, or 300,200 km, of liquid petroleum transmission pipelines moving crude oil, gasoline, diesel fuel and other petroleum products. The American Petroleum Institute (API) and the Association of Oil Pipe Lines (AOPL) have demonstrated their support for enhanced safety and environmental protection through the Pipeline Strategic Data Tracking System (PSDTS). The PSDTS, a key element of the oil pipeline industry’s Environmental and Safety Initiative, invites all operators – regardless of membership of the API or AOPL - to voluntarily submit data on spill and release incidents to help the industry better understand their causes and effects and provide operators with a foundation of knowledge to foster improved performance standards. To date more than 40 operators, representing around 70 per cent of oil pipeline mileage in the US, have chosen to participate. They report on regulated crude gathering lines as well as all pipeline systems and facilities under the regulatory oversight of the US
“…based on large amounts of raw data; therefore, determining the solutions to the root causes needs further individual operator investigation.”
Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). This data, collected via the Pipeline Performance Tracking System (PPTS), will be used to support the APIAOPL goals of the Pipeline Safety Excellence Strategic Plan. It can be considered sufficiently robust, and therefore of relevance to, the wider global pipeline industry. Among its key findings the PPTS highlighted the main cause of facility releases on liquid petroleum transmission pipelines as equipment failure. Pumps were the leading cause of the equipment malfunction, with pump shaft seals highlighted as the primary cause. In 2015 releases due to equipment failure accounted for over half of the releases reported, and the number of incidents was shown to have risen consistently since 2010. The API’s PPTS Advisory on Facilities Piping and Equipment clearly states that the findings are: ‘…based on large amounts of raw data; therefore, determining the solutions to the root causes needs further individual operator investigation.’ So what actions are available to the pipeline operator with a commitment, as well as a responsibility, to maintaining high standards of safety and contributing to international environmental standards whilst also responding to the demands of maintaining operational reliability and cost-efficiency? For many decades, the industry has used single end face mechanical seals for pump shaft sealing. Under normal operating conditions these seals have a small amount of weepage, which migrates across the seal faces. This normal leakage is diverted via a drain port in the gland plate. The amount of normal leakage is a function of the seal size, pressure, operating speed & properties of the fluid being pumped. In recent decades, most of the pipeline industry has adopted a simple leakage detection system which pipes the normal leakage to an external collection reservoir and then to a sewer system (or central collection system). The external collection reservoir, via a combination of orifice plate and level switch, can provide indication of excessive seal leakage due to seal wear or failure, thus enabling operators to safely shut down pumps. However, there are still some operators around the world that do not have any leakage detection. This is potentially disastrous in remote pump facilities.
Figure 1 API Plan 65a
In 2004 the leakage detection systems used by the pipeline industry were officially recognised within the API Mechanical Seal Standard 682 and referred to as piping plan 65. However, various operators and manufacturers have had significant interpretations of these leakage detection systems, ranging from highly engineered pressure vessels to simple homemade oil cans. In 2014 the API standard provided more detail regarding the design volume and materials of construction. In terms of containment these systems are limited by the fact that the only form of containment in a failure event is a bushing, which serves to arrest the flow and breakdown pressure. Typically, in the pipeline industry, bushings are fixed with relatively large clearance. In event of very high leakage this will not contain the pumped fluid, which will then be released to the environment – if the pump is shut down and or not isolated the volume of leakage could be significant. Figure 2 illustrates a typical rotating spring seal design that has been the workhorse of the pipeline industry for probably over 40 years. Also, with lighter hydrocarbon services these systems do not provide any containment of vaporising
Figure 2 – excessive leakage from single seal with fixed bushing leakage, which could be a volatile organic compound (VOC) or volatile hazardous air pollutant (VHAP). It is worth comparing practices in the pipeline industry with comparable industries such as petroleum refining and petrochemical manufacturing. For hydrocarbon streams containing light components, in the US refineries are required to inspect for leakage of vapour phase using an organic vapour analyser (OVA) to measure the concentration of vapor emissions adjacent to the seal; if high readings persist then seals need replacement. Currently pipeline operators have no such requirements. Many refinery operators would not use single seals for such services. Reduction in emissions best safety practice prescribes those single seals would be considered unsuitable for use. The requirement would be for a dual seal with significantly greater levels of process fluid secondary containment. So, it would be fair to say that the pipeline industry lags refinery petrochemical manufacturers’ best practice. The PPTS Advisory acknowledges the wide variety of reasons that might lead to those failures. These include the actual type of seal used and the materials it is constructed from, as well as external factors such as excessive heat, high vibration, excessive friction caused by poor lubrication and/or dry-running, and incompatibility between the materials of construction of the seal and the commodity being transported.
To establish and effectively tackle the root causes of equipment failure it makes sense to focus on all elements of pipeline equipment maintenance and operating standards. A review of the existing sealing systems and the leakage detection strategy is a key component. Advanced mechanical seal solutions have been developed in recent years which demonstrate improved durability under difficult applications such as oil pipeline pumping, water injection and boiler feed duties, and are proven to deliver reliability and cost-efficiency. They have been tested to extremes beyond their rated capability and involve cutting edge technology: • A stationary multi-spring design facilitates even face loading and improved seal face stability in the event of pump casing alignment issues. Mounting these springs within the gland plate remote from the pumped fluid avoids seal face hang up on heavier crudes in low temperature environments, improving reliability and reducing cost of ownership. • Finite Element Analysis (FEA)/ Computational Fluid Analysis (CFD) and hydrodynamic algorithms have been used to optimise the monolithic seal face design to maintain a stable sealing conditions across a range of operating conditions. • Monolithic seal faces minimise the effects of
pressure distortion under high pressures and maintain flatness in the face of temperature fluctuations. • Sculpted lug drive improves torque transmission. • Most modern quality mechanical seals are compact and can often be retrofitted to legacy machines, in many instances it is possible to incorporate higher levels of secondary containment. Single seals fitted with dual bushings in the gland plate with close clearance segmented bushings can provide improved levels of liquid containment in the event of seal failure. In 2014 the API 682 Standard published piping plan 66A, which incorporates some of these features and can offer significant improvements in containment.
Unpressurised dual seals using a secondary mechanical seal will improve the containment of vapour phase emissions in both normal operation and failure events. There are a number of technologies available. Secondary seals can be either liquid lubricated or dry running. There are a number of piping plan options available for example or piping plans 52 or 76/75. More sophisticated auxiliary systems will be required.
Figure 3 Cross Section of modern design pipeline seal with gland plate mounted springs and dual close clearance bushing]
In a seal failure event, leakage rate downstream of the inner bushing is restricted, pressure is reduced as the leakage flows under the bushing. The leakage then passes to a drain cavity – an outer bushing captures liquid leakage and diverts liquid to a drain port. Another benefit of this arrangement is that pressure will increase upstream of the inner bushing; a transmitter is installed into the gland plate that can detect this pressure build up and activate an alarm. There is also no requirement for an external vessel, just simple pipework routing leakage to a sewer or central collection. Plan 66A offers a significant step forward over the traditional plan 65A and, without the complexity of the external collection reservoir, provides a costeffective upgrade retrofit solution.
Figure 5 Modern design pipeline seal with gland plate mounted springs and secondary containment seal
Pressurised dual seals with API plan 53B probably provide the most security, with the added benefit of continuous seal condition monitoring. With this arrangement both the inner and outer seals are lubricated by a barrier fluid that is maintained at a higher pressure than the pump liquid.
Figure 6a Modern design dual pressurised pipeline seal This makes the seal virtually independent of the pump liquid and can even be operated with no pump liquid. As the barrier fluid is at a higher pressure it is not possible for pump leakage to migrate to the atmosphere. These types of seals are beginning to be specified by the best-in-class pipeline operators. Again, a more sophisticated auxiliary system will be required than a single seal.
Figure 6b Pressurised auxiliary system 53Bseal
Improved levels of secondary containment are now available to pipeline services. Overall the global pipeline industry remains behind the curve in responding to the new market. Installed legacy equipment can provide safe reliable performance, however many have sealing devices in place that have not changed much since the 1960s there is scope for improvement. Outdated seal applications have been a mainstay of the pipeline industry over decades – a period in which legislation around environmental performance has advanced significantly, while optimising operational efficiency and driving down costs has become a necessity as well as a desire. The pipeline industry needs to review risks and implications of seal-related spills and releases. Take as an example a 1,0000 mile stretch of pipeline that a maintenance crew must keep operational. That pipeline might typically have ten pumping stations, each containing three to four pumps, with each pump containing two seals. That’s 60 to 80 seals per 1,000 miles of pipeline - or 60 to 80 individual risks of causing pump failure and the subsequent cost of work hours, operational downtime and equipment repair or replacement. Whatever the whys and wherefores, has the pipeline industry been caught napping when to comes to one of the most common causes of spills and releases? There is much work ahead and no regulatory changes are likely within the next five years. But the API and AOPL members have already demonstrated a keenness to contribute to advancing environmental and safety standards in their industry. The American Petroleum Institute is reviewing the scope of its equipment sealing standard, which was primarily written for refinery and petrochemical operators. In the future the expanded scope and application guidelines are likely to provide pipeline operators across the globe with recommended best practices. There is clear evidence that advanced modern sealing solutions selected with appropriate piping plans can significantly reduce the risk of spills and releases. It should therefore be incumbent upon the industry to investigate existing practices and look to invest in technology that brings benefits in terms of both the environment and the bottom line.
Installed legacy equipment can provide safe reliable performance, however many have sealing devices in place that have not changed much since the 1960s there is scope for improvement.
Slick data-centric approaches will help oil firms to prosper David Rosen, Technology and Customer Leader at TIBCO Software explains why thinking first about data will fuel success in a changing oil business
n the winter of 2017 The Economist boldly claimed that ‘The world’s most valuable resource is no longer oil, but data,’ thus branding a hallmark on the then-emerging notion that future wealth and prosperity will be extracted from databases, files, communication streams and other digital sources rather than rigs and platforms. But the truth of the matter is that data and oil are married by symbiosis. That is, without data, there can be no oil, or at least no modern oil industry. Today, the most advanced users of data can be found not just in Silicon Valley, but less ballyhooed locations such as the Niger Delta or East Timor. Oil prospecting in 2021 drills deep into data sets that are as rich as the commodities they tap and as complex as the myriad products and fuels derived from carbon. COVID-19 has lowered global oil consumption by 8.1 million barrels per day,
according to the International Energy Agency and in 2021, where everything is in a state of perpetual flux, energy producers face a confusing and morphing set of challenges. Demand for “black gold” has lagged in recent years but is showing signs of a bounce-back even as experts question the longevity and strength of its future and as the search for new oil reserves becomes tougher. But, whether you’re an oil bull or a bear, this is a market desperate for embedded intelligence and a data-centric approach. Oil exploration is often described as one of the biggest industrial bets in the world: you place massive stakes but, if you win, the prize of a significant reservoir will yield vast profits. But to win that bet, the sector must first explore and refine the vast data volumes that lie in big data.
Let us focus for a moment on the upside and consider some points in favour of those pursuing a data-enabled future. • There has never been so much data. It comes at us from every angle and the world’s store of data doubles every two years. • Data types have never been so varied. Today, most of the data we consume and create does not lie in structured formats like the columns and rows of a database or spreadsheet but in unstructured forms: documents, photographs, audio, video, web pages and many others including data we once saw as useless, such as machine data. • We can analyse data faster than ever, even in something like real time, thanks to in-memory systems, vast processing power, utility-like platforms such as cloud and rapid advances in communications, including wireless. Data ubiquity and velocity are powerful phenomena that are changing the world but they are useless (or, worse, misleading) if they are not yoked to workflows, processes and systems that let organisations get to the truth fast, check its veracity and move on to next actions. So, how does this translate into the real world of oil exploration? Well, data impacts every activity from exploration to fulfilment. It means using sensors and autonomous vehicles and devices for exploration and drilling, analysing seismic and micro-
seismic data, creating 2D and 3D models for visualisation, improving reservoir characterisation and simulation, reducing drilling time, optimising production pumping, superior asset management and logistics… the list goes on. And here is another thing: this is not just a case of data everywhere, it’s also about people everywhere. That exploration in the Niger Delta and East Timor will be shuttling data via the cloud to people who can make best use of it wherever they are in the world, in offices and increasingly in homes. If we can only join the dots between smart data and smart people, the step we take is so much bigger. Oil companies need to follow the narratives of other sectors and accept that they too need to be digital at heart, employing scientists, engineers and business leaders who understand digital possibilities. The oil industry has always generated vast reserves of data, but by utilising data-driven insights, it now has the ability to look forward too and work smarter in an industry where the gushers of profitability can no longer be taken for granted and where internet and technology companies are capable of equal or greater scale. Like many sectors, the oil industry has previously only had the ability to look backward and use the past for insight, but now is the time for leaders to adopt a forward-looking, predictive analytics approach, investing to become forensic and less risk-prone. Precision drilling, streamlined processing, and business-wide efficiencies are needed and they are needed now because the time when new discoveries covered lax processes is going. Uncertainty is nothing new to the oil industry; the sector has faced macroeconomic challenges, conflicts, and changes in consumer behaviour before. But the mandate for sustainability, a growing awareness of the negatives of fossil fuels and the rise of viable alternative energy sources means that those organisations that have a data-centric core will be able to adapt, explore new opportunities, and develop a future pipeline of business possibilities.
Ready to react? Gaining new value from inspection The oil and gas industry has a long history of performing asset inspections which, over time, has become synonymous with safety. As the era of digitalisation takes hold, the value gained from inspection is changing, but is a traditional mindset holding us back? Ranald Cartwright, head of operations for Imrandd, explains.
whole market exists to serve the inspection needs of the oil and gas industry, ready to catch defects and failures before they impede safety and operations. Yet inspection can be costly, time consuming and in many cases, inefficient. What do we mean by inefficient? Let’s take pitting as an example. When you’re inspecting a pipe for pitting, based on material science, fluid service, and a host of other factors, pitting is more likely to occur in certain areas, so you target your inspections accordingly. However, if the inspection returns a clean bill of health, can you really be confident that this result is reflective of the pipe’s overall condition and that risk has been managed effectively?
Without 100 per cent coverage, a lack of defects and failures in your inspection regimes could be down to luck. However, while complete 100 percent inspection will likely deliver ultimate confidence, it’s a time consuming and expensive approach that few operators are in a position to undertake for every single threat – and it is also no longer the only option. While risk-based inspection (RBI) methods go some way to focus inspection efforts, as digitalisation takes hold, more intelligent and efficient approaches are becoming available which is changing the way value is derived from inspection. With traditional methods, asset and integrity managers only gain value from inspections when they identify a defect or failure; therefore, many inspections return no value. With a data-driven approach to asset integrity management, all inspection outcomes provide a return.
The value of data Most operators are familiar with the benefit of running statistical analysis on traditional inspection data to inform their asset integrity plan. The latest iteration of this approach takes it a step further; collating leading real-time (or near real time) data from existing operational sources such as process conditions (temperature, pressure etc.) to create a degradation model of an operator’s assets. The predictive integrity management plan produced is based on event-driven inspection whereby inspections are primarily motivated by changing process or environmental conditions, for example, scenarios which may indicate accelerated corrosion, wall thickness loss, degradation or fatigue issues. Every inspection
carried out helps to validate the model’s assumptions about the degradation of each asset and fills in data gaps, thus building a more robust model and methodology by which inspection and integrity activities are enacted. Operators can confidently focus their resources on areas where changing conditions require real-life validation to ensure risks remain understood, and so every inspection effort made provides value to the asset team. While using a data model will see most operators expend a similar amount of inspection effort, the model continuously validates the need for those inspections while significantly improving their return on investment too. Even with assets nearing end-of-life there are benefits – anecdotally, operators using IMRANDD’s data model AIDA see a typical return on investment in less than a year and cost savings in a matter of weeks or months. The are many immediate benefits of this new style of integrity management. Leveraging real time data means that engineers no longer need to wait until an asset is beginning to degrade to assess condition. This change in strategy can have a significant impact on profitability as well as lengthening an asset’s lifespan. And it can also help operators better achieve overarching business goals such as their commitment to operating sustainably and responsibly; for example, by reducing flights, optimising resources and/or reducing fugitive emissions. What’s more, most operators will have data readily available which simply needs to be extracted and analysed in a different way to enable the integrity team to be more planned and
effective in managing plant maintenance.
The spirit of regulation Despite the obvious benefits, it can be quite difficult for asset and integrity managers to move away from the traditional mindset – not least because of the way industry sees safety and standards as one and the same. This gives little room or incentive for teams to innovate more efficient ways of managing integrity. The principle of these standards is to reduce the risk of operation to as low as is reasonably practical (ALARP) however, if operators aren’t using readily available digital technologies that can further reduce risk with more robust justifications to do so – can we genuinely say ALARP is being achieved? It seems that a shift in perception is still required for industry to recognise the inefficiency of relying on only historic data and lagging indicators. Inspection results are only truly valid on the day they are taken, then some reports are not processed for weeks or even months – putting the operator at risk of making decisions based on out-of-date information. On the other hand, using real-time data enables asset and integrity managers to react quickly to potential issues before they occur, in much the same way that rotating equipment is treated. You’d never wait to see if a turbine has developed a crack because by then it would be too late. Instead, the model is constantly assessing the data to generate early warning signs so that timely interventions can ensure safety. In the spirit of regulation, if we are being responsible as an industry, we should constantly strive to go above and beyond the existing standards. With all the data that is available to us, that spirit is now digital and IMRANDD’s predictive modelling and machine learning solutions are a prime example of data analytics tools that do just that, pushing industry to achieve more. With the ability to gain insights that enable operators to rapidly react to changing operating conditions, asset and integrity managers have the opportunity to manage static assets more proactively, leading to reduced failure and reduced impact. It is not an incremental improvement that tools such as IMRANDD’s bring, they are an order of magnitude better than the traditional approach that’s been employed for the past 20 to 30 years and are redefining what we mean when we say as low as is reasonably practical.
Succeeding with Digital Twins: Think big, start small and scale fast It has been said quite a few times, but it bears repeating: 2020 and COVID-19 made the world more digital and more remote controlled.
or the energy industry, digital twins changed from a nice to have, to a need to have to remain relevant and competitive. Companies who aspire to succeed through this journey should consider the following pillars. Let us start with digitalization.
Digitalisation: Enabling business and enhanced performance During the pandemic business continuity has dominated the agenda and digital twins played an important role. Due to the physical distancing, having all data available and easily accessible through twins helped businesses to not only better understand how they are operating, but also remotely monitor and improve operations using data analytics, simulation, VR/AR, and digitalised workflows to ensure that continuity.
Companies that were digitally ready have thrived. The digital twin technology has moved beyond just visualisation and into a representation of the asset’s physical reality and its dynamic behaviour reflecting the status of the asset in real-time. That said, digital twins enable frontline operators, engineers, and remote workers to become fully integrated, through data and work processes,
transforming and optimising the operations and maintenance philosophy of the assets. An important element in digitalisation is embracing a value-driven digital strategy, that is aligned with the business roadmap and focused on leveraging productivity, reliability, and performance of facilities.
Collaboration: Unify data, knowledge and people The trouble with modern operations is not a lack of data, it is a lack of knowledge. Why? Organisations are siloed, and it is not part of their core goals to share data. Even if the organisation aims for good communication and establishing a best practice database, the company’s data infrastructure rarely supports that lofty goal. So, because of that, and because off-the-shelf software rarely plays that well with others, companies contend with islands of information each under the specific control of a department, a business unit, or a piece of software. And this even assumes that IT has the resources – insight and business understanding – to understand and support the business’ priorities. Collaboration goes beyond unifying data; it is also about unifying people. To provide that, an industrial work surface is needed. Digital twins provide an understanding of industrial assets, representing all the connected objects in a facility to give a more complete view of the data and operations. While operators have solid domain expertise and understand every detail of their business and challenges, technology partners bring their industrial software expertise for a faster deployment of solutions that bring together data, processes and people and delivers quicker ROI.
Decarbonisation: Answering the industry challenges The energy sector is under tremendous pressure to operate in a more sustainable, cost-efficient, and lower-cost manner. Digitalisation and digital twins are one of the critical paths to get there. It is key to first understand that data and access to data do not remove emissions. However, giving your employees access to the right data to act based on insights to optimize energy or chemical usage or even curbing the behaviour of the employee by linking their tasks to the carbon footprint of operating assets does reduce emissions. All these workflows and advanced analytics are available in digital twins today and cumulatively have an impact on reducing emissions.
Scalability: think big, start small, scale fast. For the global energy industry, then, digital twins will
provide more agility, better decisions, and a significant reduction in energy consumption. Every decision will be based on simulations to eliminate as many variables as possible. Maintenance will be streamlined, leading to less downtime and what are sometimes catastrophic failure modes. Greener energy at less risk and cost may be a big promise, but it is attainable. How, though? Assuming a mix of brownfield and greenfield assets across geography and applications, digitalization seems unsurmountable, but it is a possible reality indeed. It will not happen overnight, and here, the movement brings clarity. As companies get started and progress, the picture becomes clearer and clearer. Simply find a low-hanging fruit and start small, then scale it fast. As the industry embraces this disruptive technology, it is imperative that the digital twin is linked to a tangible, scalable business case to ensure long term adoption and sustainability of the technology. Your company possibly already started ‘Thinking big’. Now the time to act and ‘Start Small’ has come. Are you ready to embark on this journey? Kognitwin Energy has moved from proof of concept to proof of scale. Combining cutting edge technology with scalable solutions, Kongsberg Digital can deploy a dynamic digital twin Kognitwin Energy in your asset in a matter of a few weeks. This means your organization will start benefiting from this technology within weeks rather than years. Open, data-driven, and scalable, Kognitwin Energy offers easy access to data from anywhere at any time nurturing collaboration and innovation. Beyond being a virtual replica of your industrial facility, the dynamic digital twin delivers a rich framework for advanced digitalisation and analytics that enables performance optimization and fast-track digitalisation. In 2020, after a successful implementation at the Nyhamna facility, Shell Global selected Kognitwin delivered by Kongsberg Digital for its global portfolio of assets and capital projects within the Anglo-Dutch energy and petrochemical company’s upstream, integrated gas, and downstream manufacturing business lines.
A new direction for directional drilling Andrew Law and Neil Bird of Enteq consider the evolution of directional drilling
It has been a quarter of a century since Rotary Steerable Systems (RSS) displaced mud motors as the energy industry’s premium directional drilling tool of choice, and the basic design has incrementally been improved upon over the years. But the fundamental approach has remained unchanged. The technical and commercial realities of today’s broad energy landscape – and specific directional drilling market – demand that an alternative be added to the RSS roster. Let’s explore why that need exists and how it can be met.
Different demands The energy industry of 2021 looks very different to anything that’s come before. With the energy transition as a backdrop, a lower-for-longer oil price environment has forced both operators and service companies to squeeze their operations for every ounce of efficiency they can.’ The geography of the industry is changing too. The Middle East remains a juggernaut and the US shale strength continues but around the world operators are looking again at previously unattractive or uneconomic plays and re-evaluating their feasibility. To make these plays economic means keeping an iron grip on the cost per barrel. In that respect, traditional pad-and-piston RSS designs can be frustrating. By nature of their design, they are prone to excessive wear which eventually inevitably entails downtime. In a competitive industry with downtime as a major performance metric, that is not just frustrating – it’s damaging, both to reputation and the bottom line. However, there is no avoiding it. Any system that steers by pushing a pad against the borehole wall is going to be subject to powerful forces, and if it is not direct wear of the pads that causes the problem, it’s torsional vibration of the drill bit. Over the years, resourceful engineers have fine-tuned designs to reinforce the technology or reduce the effect of those forces, but it’s an unavoidable drawback of existing RSS systems. This is a potential cause of failure that can result in downtime at any moment, eroding already-thin margins. At the same time, just as oil producers are keeping an eye on production cost per barrel, gas-focused producers are trying to manage cost per cubic foot. Touted as a ‘bridging fuel’ between the hydrocarbonbased old world and the renewable new one, demand for gas has seen sustained increases world-wide. Abundant supplies and the emergence of the US as an LNG super-exporter mean this has not translated into high prices however, and margins for gas production remain thin. In certain basins, such as Hainesville, gas producers must similarly look for a more reliable RSS option with the added difficulty that these are often in high-temperature environments, and traditional RSS designs aren’t necessarily designed to perform well in these circumstances.
Built differently What can be done though, if this is an unavoidable facet of RSS design? The answer is to take a new direction for directional drilling, omitting pads and pistons in favour of a simple, stronger collar, and decoupling the steering mechanism from damaging torsional vibration.
This is achieved by using internal hydraulic pressure differentials to create side-force at the bit for geo-steering, rather than pushing against the borehole wall to change direction. The approach uses Bernoulli’s principle of fluid dynamics, which can commonly be observed in the generation of lift force on hydrofoil, but which has not previously been applied to downhole applications. The advantage of this approach is that, by internalising the steering mechanism, a completely plain collar design is possible while achieving true at-bit steering, decoupling the mechanism from torsional vibration, and removing any pads or external profusions that might be subject to excessive wear. Most of all though, the design is mechanically simpler – elegant, even – compared to anything possible
with traditional RSS design, which increases reliability and therefore reduces downtime.
A different market landscape It is not just the technology that has been overdue a shake-up when it comes to the RSS market though; the market itself has become (conversely) overcommoditised and under-competitive. Taking the US as an example, there are a number of engineering firms offering RSS tools to the market, with high quality engineering honed over many years. The country’s backbone of independent service companies buy or lease RSS tools as necessary from these companies. However, the market lacks enough independent alternatives. To support a healthy ecosystem of independent service companies with genuine options to choose from, that must be rectified. And that imperative is extending into new markets, too. In the Middle East, National Oil Corporations (NOCs) are looking to bolster local content and incountry manufacturing. Unlike traditional RSS tools, the independent status
and simple engineering of an internally pressuresteered RSS allows for the majority of manufacture and repairs to be conducted incountry, in line with national strategies. Around the world, independent service companies are underserved by independent RSS options. Giving them that independent alternative – an alternative that offers greater reliability and cost-efficiency – could
be genuinely transformative for many: an internal pressure differential steered RSS could elevate many into a new league of contracts. As lateral lengths increase across the industry, there is going to be demand for RSS tools which can achieve smoother bores with lower tortuosity. In other words, there is ample room for an alternative to traditional RSS tools without having to rip up the rulebook and start again – the market functions best when it can choose from a range of technologies, from a range of suppliers, to best suit the job at hand. And that’s the new direction for directional drilling that needs to be taken.
Health & Safety
Wireless comes of age for gas detection Gas detection and monitoring has long-been a key priority for businesses operating in the UK’s oil, gas, and offshore sectors. But despite increasing attention by the Health and Safety Executive (which made reduction in the risk of offshore hydrocarbons a priority in its 2019/20 Business Plan) and by industry, there has arguably been relatively little innovation in the space. Until now, that is, as Megan Hine from Draeger Marine and Offshore explains.
Health & Safety
ireless technology may have become ubiquitous in most people’s lives for quite some time, but it’s only relatively recently (the last six or so years) that it has become a viable option for gas detection and monitoring for the oil, gas and offshore sectors. The reasons for this coming of age are, broadly, split into two key areas. Firstly, industrial wireless technology has seen significant advances in recent years. Whilst the early adoption of wireless gas detection developed a poor reputation for patchy coverage and unreliable connections, data communications are now guaranteed; a crucial component for effective wireless monitoring systems, and which allows for detection of gas to be communicated reliably and in real-time using an ISA 100 industrial wireless system. This system is guaranteed to be secure and is specifically designed to carry small data packages, of around the size of 10 text characters, within a specified timeframe and with complete reliability. Secondly, there has been considerable progress when it comes to innovation in relation to device power consumption. Battery life has historically been a significant issue for wireless gas detection, but some of the more recent advances in technology have resulted in step-change reductions (in some cases by orders of magnitude) in power consumption, and this has been critical in offsetting more powerhungry functions which have otherwise advanced device functionality. The result is that battery life has improved considerably, with certain devices on the market guaranteeing up to two full years of battery life, compared to only a few months in the early days. The cumulative impact of this, and other minor, innovation has been significant, and importantly, comes at a time when many legacy (wired) gas detection installations are now desperately in need of updating. Two or three decades after the UK’s first wired gas detection devices were introduced, both the technology and key
drivers for monitoring have evolved. Environmental issues related to methane detection could soon rank alongside ongoing safety concerns around explosion risk etc, and standards around coverage and numbers of devices have also changed. Often, it is the inflexibility of hard-wired networks to respond to these sorts of changes, plus the vast costs involved in replacing cabling, that is now prompting operators to explore wireless alternatives. To prove the flexibility of wireless gas detection, it is now possible to rent a compliant fixed gas detection system for shortmedium term coverage. The ability to do away with the miles of cabling, which often has a life span of just 10-15 years, is a major advantage of wireless technology. Although the outlay for a wireless device may initially be higher, when the saving on cabling alone can be three times the cost of the wireless device, it’s not a hard decision. Flexibility is another key advantage – if for any reason a device is found to have been ineffectually-placed, or an additional device is required, there is no need for new and potentially disruptive groundwork or cable re-routing. Installation and commissioning costs for wireless systems are typically a quarter that of a cabled system, and Equinor has published figures outlining installation cost savings with wireless detectors are approximately 60 per cent for an offshore installation, and 80 per cent for an onshore installation. One of the final – and perhaps most substantial – advantages of wireless technology is the fact that no site downtime is required. Wireless devices are intrinsically safe, so can be installed on live sites, offering a huge additional cost saving. Challenges do remain; and arguably the key barrier to adoption remains education and changing the poor perceptions around the technology, which still persist. However, despite these challenges however, the significant savings (reports of 60-80% overall savings are not uncommon) are contributing to an accelerating pace of adoption. Recently the largest wireless gas detection network ever seen in the North Sea was completed, which employs 120 wireless devices across a remote seven square mile site, and there is little doubt that this sort of project will become more commonplace as greater awareness develops and the full potential of the technology is realised.
What is the future of seismic imaging for energy? Mike Popham, CEO, Stryde explains how the evolution of seismic imaging is heralding a new era for oil and gas exploration
il and gas is an industry at a turning point. While crude prices are starting to recover from a dip in 2014, they may never return to the heights hit in the 2000s, necessitating the streamlining of operator budgets and accurate forecasting of project yield. At the same time, public pressure and the changing climate have pushed many oil majors to publicly commit to reducing exploration and production in general while also significantly decreasing the environmental impact and carbon footprint of their operations. Modern oil and gas exploration hinges on a full understanding of the subsurface. Before any project is set up, the first step is to assess the depth of a potential reservoir and identify underground rock formations that could aid or hinder drilling. Seismic acquisition or measuring sound waves propagating through different layers of the subsurface, is the most popular and effective method in oil and gas for imaging the subsurface and has recently undergone a wave of innovation. This is making seismic surveying faster, more costeffective, and less harmful for the environment. As we come to the centenary of the first ever seismic experiment, we look back on some of the key developments in this technology that have enabled oil and gas’s growth and the exciting role seismic imaging must play in the energy transition.
A century of seismic imaging Before seismic, oil wells were primarily drilled in a very trial-and-error approach, often with known wells less than 100 metres deep. In 1921, a small team of geologists performed the Vines Branch experiment. This was the first trial of “reflective”
or “active” seismic acquisition, wherein an active source such as dynamite creates shockwaves that ripple through the subsurface and can be picked up by surface sensors called geophones that are spread throughout the site. Following the success of this experiment, oil and gas operators quickly adopted the use of seismic acquisition for exploration projects and have spent the past century investing in new technology to revolutionise seismic imaging. Predominantly, a large focus has been on less destructive and more costeffective sources, such as vibroseis trucks on land and air guns underwater.
Revolutionising land seismic with nodes In addition to the source, the past decades have seen significant strides made in receiver technology to
make seismic safer, faster, and cheaper for new oil and gas exploration. One of the key breakthroughs recently has been the development of wireless nodes, rather than legacy cabled systems. Cabled systems present several failure points throughout the length of cable, leading to significant “down time”, and are also extremely bulky and unwieldy. As a result, they require very large numbers of people and vehicles to deploy and operate in the field. To utilise cabled systems in forests, jungles or scrubland, operators and contractors using cabled systems must often spend weeks clearing lines in the environment to allow movement of this cumbersome equipment, presenting a particular health and safety risk, as well as causing significant, lasting harm to the environment. Wireless nodes are more compact than cabled systems, enabling operators and contractors to lay out more receiver points over a single site with fewer people and far fewer vehicles. The smaller form factor also reduces the risks and environmental damage associated with line clearing. However, until recently, even wireless nodes were bulky to the extent that a high number of people and vehicles would still be required to
conduct a typical land seismic acquisition. This means that sadly, line clearing is still commonplace. In a step that has further revolutionized seismic imaging, the latest generation of nodes are significantly smaller and lighter than any other node in the market. For example, the lightest node on the market is now Stryde, a 13x4cm cylindrical geophone receiver with a weight of 150g. This represents a paradigm shift in an industry where 1kg is standard and the lightest alternative node at this point in time is four times as heavy. By reducing the size and weight of nodes, operators can now lay out far denser receiver spreads. Like increasing the number of pixels in a digital photograph, increasing the density of receivers generates a much better-quality picture of the subsurface and provides a greater understanding of its attributes. The size and weight of the latest generation of nodes enables the set-up of high-density seismic surveys while keeping the number of people and vehicles needed lower. In oil and gas, using prototype versions of these ultra-light nodes, the world record for land seismic trace density was set by ADNOC in the UAE in 2019. 50,800 nodes were used by 36 people to make halfa-million deployments in less than 53 days, achieving a staggering trace density of 184 million traces/km2. Beyond the benefits of more accurate subsurface imaging, the trend toward smaller and lighter nodes helps oil and gas companies meet ambitions to reduce scope I emissions and the environmental impact of exploration. In addition to further reducing the need for environmental clearing, smaller equipment can be laid on-foot and transported in a single pickup truck, reducing the need for multiple large, heavy vehicles per seismic survey and simplifying costly permitting especially in populated areas.
Seismic imaging for new energy solutions The energy transition and global calls for widescale decarbonisation present a myriad of challenges for the oil and gas industry – but also several opportunities. No other industry is as well-placed to leverage its in-depth knowledge around seismic imaging to enable the widescale construction of carbon capture and storage facilities (CCS). With CCS in place, oil and gas majors can manufacture blue hydrogen from natural gas, continuing to fuel the world while reducing scope II and III emissions. However, to-date, effective CCS site development and monitoring has been prohibited by excessive costs. Seismic technology is key for not only identifying initial drilling locations, but also monitoring projects to ensure carbon is staying sequestered. The new generation of light nodes has removed this cost barrier once and for all. Carbon Management Canada recently worked with seismic technology providers STRYDE and Explor to identify opportunities for seismic acquisition to facilitate the development and operation of CCS projects. In this trial, Stryde’s Nodes were used in combination with Explor’s PinPoint source to map out and monitor the subsurface for CO2 injection without the need for clearing the area or compromising on data quality. The one km2 field test has delivered a new world record of over 256 million traces / km2. CCS is just one of many avenues the oil and gas industry can take to leverage its expertise in geophysical technology for the energy transition. From geothermal energy to structural engineering for new renewables and hydrogen capacity, the oil and gas industry’s early lead in seismic technology puts it in good stead to support the future of green energy..
Breathing life into brownfields: innovation to extend asset life Brownfields expansions have always been an available option – but new technology and a commitment to reducing total expenditure have changed the way the industry thinks about and executes life extension projects, says Alistair Mykura, Senior Product Manager, Life of Field, Subsea Production Systems, Baker Hughes.
020 was another tough period for the oil and gas sector. A time in which demand was rapidly quashed, wholesale prices even went temporarily negative, and uncertainty escalated. As always during a downturn, the call went out to explore the possibility of extending the life of existing assets, reinvigorating brownfield sites and driving further efficiencies into production by doing more with less. Consequently, there is a great deal of interest in production control systems for brownfield extension, rapid tiebacks, and solutions for equipment upgrades. That interest reflects a wider trend in the industry. Market reports suggest that the trend for smaller tie-back projects, smaller wells, and fewer well developments was well underway before the pandemic struck, a trend that is reflected in our
own experience at Baker Hughes. We are seeing an appetite for these projects from IOCs, major operators, and the independent operators. Giant projects with multi-year timelines are a rare beast these days as operators look for rapid returns in the face of searching questions from investors and a five-year outlook that is as difficult as ever to predict. Strict operating parameters have always been the spur to technological and operational innovation within our industry. However, there is inevitably a lag between the onset of an industry-wide challenge and the availability of proven solutions to address it. That is not necessarily the case this time round, with the outcomes of the previous innovation cycle already available for immediate deployment. Furthermore, this innovative thinking has gone
beyond the scope of technological advances, and embraces the way that solutions are developed, the way they are made available, execution strategies – and the way suppliers and operators work together.
Realising the benefits In terms of both capital investment and time to revenue, the theoretical advantage of extending existing asset life over developing greenfield sites are very clear and substantial. However, technological challenges exist and are summarised here: System downtime during change over. This • is the big one: excessive downtime extends time to revenue and will seriously impact cost benefits of undertaking upgrades or tieback projects. Seamless integration
of new technology with older systems requires solutions that are designed for backwards compatibility with a broad range of original equipment manufacturers (OEMs). Robust obsolescence management. Systems will become obsolete. That is inevitable in any industry where innovation takes place. With the pace of innovation in computing, software and electronics accelerating then naturally instrumentation and control systems are more prone to this than other mechanical pieces of equipment. However, in good product designs obsolescence can be foreseen and therefore managed, so that any upgrades are harmonized and seamlessly integrated with existing systems. When the opportunity comes to upgrade, the latest software and communication systems can be added that enhance the performance and diagnostic capability of the system. System reliability. All systems involved in asset life extension must be built for reliability and be designed to maximise uptime. Since longevity is crucial to ensure proposed benefits are achieved. The right technology for the field, the asset and the business goal are
needed to mitigate risks around equipment reliability; and because no two projects are identical, that requires a 360-degree project analysis from the outset. To give this some real-world context, consider the specific issues around integrating new communications and power into existing production control system. Adding new communication signals to an existing umbilical could disrupt signals from both old and new systems – making both less effective and efficient. However, the information needed to avoid disruption is the intellectual property of the installing OEM. When a third party is working on overlaying new communications, commercial sensitivity can prevent a full understanding of legacy equipment – and the solutions it will therefore support.
There are two main options available in this situation: a time-division multiplexing (TDM) solution, which in effect allows systems to take turns to use available bandwidth; or a frequency-division multiplexing (FDM) solution, which enables two systems to use different frequency bands at the same time. Both TDM and FDM are only made possible by the right modem, and this is where developments made over the past few years come into their own. Both low-speed copper modems and multi-band copper modems are now making both multiplexing solutions possible; and because they are designed with reliability, equipment life and easyinstall in mind, they help address the challenges outlined above.
The TOTEX calculation At an operational level, the challenge is about ensuring that total expenditure (TOTEX) for the lifetime of the extended asset is kept as low as possible, without compromising availability or extending downtime during installation. The quality and robustness of the underlying technology naturally has a key role to play in lowering TOTEX: reducing time between failure, lowers production loss and decreases maintenance costs following installation and commissioning. But reduced TOTEX goes beyond reliability: it is also about a design and execution mindset that leads to overall cost reduction for operators. For example, investments made by suppliers like Baker Hughes, have created a portfolio of structured products, consisting of configurable parts that are reused in different systems, which can unlock opportunities to lower TOTEX. Developing products in this way offers several advantages to operators: •
It ensures that solutions are available and proven at the right technology readiness levels (TRL), by using technologies that are already qualified and proven.
I t provides manufacturing and supply chain efficiencies with more standardized materials, processes • It reduces the project lead times because there is less variability to manage thus optimizing project delivery and reducing schedule creep. Most of all, it reduces the associated costs such as nonrecurring engineering, software-engineering hours, and upfront systems engineering. This is particularly pertinent to brownfield sites, where these costs make up a substantial
proportion of the overall expenditure. In addition, structured products also result in a lower CO2 footprint for the project itself due to process step and materials reduction coupled with more compact, modular solutions. However, all tie-back and life extension projects are field-specific. The health of the reservoirs, current production
levels, previous efforts at production enhancement, and the likely life left in the field are all factors that inform technology selection and optimisation. That, in turn, requires not just technology expertise or even deep knowledge of the field, it also requires a closely collaborative relationship between supplier and operator.
A tie to the future The right technology with the right execution strategy can therefore enable faster system design, faster equipment delivery, and ultimately a shorter timeto-revenue. This integrated approach is what we call Subsea Connect. By offering integrated services and solutions, starting at concept evaluation and involving design from the reservoir up, we are eliminating interfaces and the friction that comes with them. In so doing we can unlock value, accelerate schedules and reduce TOTEX. However, the real unifying factor here is the vision and technology development needed to manage the future needs of the industry as it faces the social, economic and political demands for decarbonisation. Reliability, longevity, and innovation all play their part in achieving this goal. For example, with a future-first mindset, a system refresh that includes digital and electrification solutions could be preferable to an initially proposed upgrade. Some of our clients have already replaced ROV operations with electric actuators while others have retrofitted electric actuation to manifolds and chokes, which has led to a much faster response time and optimised the TOTEX of their tie-back projects. At Baker Hughes, this future vision is a fundamental part of our design and execution processes. The work we have done over the past decade and the investments we have made are in the service of ensuring our industry remains technologically advanced and relevant in the face of these broader societal changes.
Bringing the connected enterprise to life for oil and gas companies Mike Corrieri, sales manager, heavy industries, Rockwell Automation talks about the joint venture with Schlumberger
he ambition to operate as a connected enterprise has taken firm root across a range of sectors, yet the oil and gas industry has, to some extent, been behind the curve. This can be attributed to some unique challenges, such as the remote and often harsh operating environments of oil and gas production, that have made the process of digitally transforming operations more difficult. Today’s oil and gas businesses operate in a volatile environment with profit margins under continual pressure. While demand is subject to fluctuation, the cost of supplying oil and gas products remains within their control. This has made priorities around optimising assets, improving operating efficiency, minimising capital expenditure, and reducing operating costs ever more pressing. It is with this dedicated focus and purpose that we launched Sensia in 2019. A joint venture between Rockwell
Automation and Schlumberger, Sensia helps oil and gas leaders to meet these priorities and bring the idea of the Connected enterprise to life.
Unifying Sensing, Intelligence and Action Sensia is a unique entity in the oil and gas sector. The company combines the automation capabilities of Rockwell Automation and the petrotechnical expertise of Schlumberger to
enable the delivery of scalable automation and digital solutions across the entire oil and gas supply chain. As a standalone organisation, the venture seeks to be the leader in digitally enabled oil and gas integrated solutions and provide complete lifecycle and process automation solutions from the reservoir to the refinery, including industry-leading oilfield technology and expertise. Drawing on this blend of capabilities, Sensia unifies sensing, intelligence, and actions to optimise decisions and dramatically reduce the time and interactions between detection, diagnosis, and resolution. The combination of offerings from the two parent companies represents a significant opportunity to create value and better serve the oil and gas market through digitally enabled scalable solutions.
Five Ways Sensia Supports the Connected enterprise In a fragmented sector comprised of multiple vendors and service providers, Sensia can offer customers a solution to challenges unique to the oil and gas sector. These challenges can be broken down into five key areas across which Sensia is unmatched in its ability to support oil and gas companies, with the principal goal of improving operational efficiency and lowering costs. 1. Integration of assets at any stage of the lifecycle The lifecycle of oil and gas fields and production facilities can span several decades and involves multiple stages, from initial production through to the eventual decommissioning process. Usually, assets in different stages operate concurrently in a field, and it is not uncommon for oil and gas companies to work with multiple vendors across this lifecycle. This can make integrating those assets in a connected production environment difficult, ultimately impacting the ability to improve operations. Sensia is attempting to rectify this and promote communication and integration between the various stages. It unifies the sensing, intelligence and action processes from reservoir to refinery, streamlining the process in a more effective manner than before. Working with one entity across these stages creates vast benefits in operational certainty, uptime and output. 2. Control costs and protect margins Businesses thrive on predictability. The major challenge for oil and gas companies is the volatile environment, driven by unpredictable macroeconomic forces that make the sector prone to sudden shifts in demand. While producers have little control over the market, they can control their margins and costs. Sensia can support them in this goal, drawing on the
expertise of both Rockwell Automation and Schlumberger to realise process efficiencies and deliver end-to-end well-to-refinery services. Using connected mechanical systems and other networked devices, operators can take more precise action to realise efficiencies and reduce the risk of waste. 3. Enable a data-driven approach to automation Sensia specialises in sensors and measurement technology with intelligent automation. It marries Rockwell’s expertise in automation and analytics with Schlumberger’s oilfield services experience. With the new offerings, Sensia enables producers to carry out operations via automated schedules while also connecting the various pieces of equipment with software. These connected operations can work together while gathering more data from sensors and field devices, offering insights into how efficiencies can be improved. This provides operators with greater control in order to improve oil and gas production while cutting down on manual interventions. 4. Improve analytical capabilities Oil and gas companies have typically collected a lot of data but have been unable to use it effectively to significantly improve operations. This data typically has a short half-life, meaning there is an urgent need to draw real-time insights as close to the source as possible to diagnose issues and realise its value. Sensia’s IoT platform helps companies gain a holistic view of operations. This helps inform better decision making, drive efficiencies and enact improvements based on the quality and application of the collected data. Acquiring the data is an important first step but finding actions they can take from the analysis is key to sustained success. 5. Improve maintenance and extend the lifecycle of assets The time-bound nature of oilfield operations and the cost of downtime have contributed to an unhealthy custom of running down assets with minimal emphasis on maintenance. This approach not only increases the risk of downtime in the short term, but also accelerates the need for replacing worn-out equipment. Sensia offers full lifecycle support. This starts with getting the system right in the first place, then having the expertise to keep it running effectively and efficiently. The use of remote technologies also helps in this regard by reducing the requirements for manual intervention and personnel on site, which often means that potential issues can be diagnosed and resolved earlier. This approach extends the life of these assets so that more value can be gained from investments. As technology advances, Sensia offers migration solutions to improve the efficiency of operations on an ongoing basis. Greater than the Sum of its Parts Sensia brings together two companies with a rich history in the oil and gas sector to offer a unique solution, spanning unified sensing, intelligence, and action solutions. Uniting Rockwell Automation’s history of providing control systems to skid OEMs, highly regulated control and safety systems to operators, which are most recently augmented by our suite of digital solutions, alongside Schlumberger`s vast petroleum process, measurement and well technology experience creates a formidable combination. Together, we help customers overcome performance challenges, find efficiencies across the lifecycle of their assets and be better equipped to navigate the volatile industry landscape.
Solar Powering the digital oilfield From its origins in the early 1970s when the first pressure/temperature gauges were fitted into subsea wells and data logging via satellite began, the “Digital Oilfield” concept has evolved from simple data gathering activity to the automation, control, and optimization of nearly every process involved upstream (exploration, development, and production) and midstream (transport and storage). Initially adopted for offshore, deep-water facilities where the extremely remote and hazardous nature of operations made automation an asset, Digital Oilfield technology is expanding rapidly into all facets of onshore operations. New technologies have transformed the concept from simple data acquisition and monitoring to a fully digitized management system, one that frees-up valuable engineering resources for analysis, planning, and implementation activities rather than reading screens and
watching gauges. Key elements of a Digital Oilfield today include (but are not limited to): • Data management • Process automation • Drilling and production optimization • Control and monitoring • Sensors and instrumentation • Pipeline integrity, including cathodic protection • Robotic drilling and “smart wells” • Security • Lighting (fields and platforms) • Safety management Of the many definitions of what exactly constitutes a “Digital Oilfield,” one of the simplest is “the sensors, telecommunications networks, simulation and optimization, and robotics, coupled with advanced condition monitoring and computational power, which enable major changes to working methods.”
What are its advantages for Oil & Gas operations? Those working method changes drive real-world results. Recent industry reports indicate that Digital Oilfield implementation can deliver on the average an 11% bottom line improvement and 7% increase in productivity. One report highlighting a major oil producer as a case study credits Digital Oilfield adoption with saving the company some $200 million in capital operating expense (CAPEX); one example mentioned was reducing the time it took to check pipeline integrity from seven days manually to just 30 minutes using Digital Oilfield automation technology. As operators make up for lost time in the postpandemic environment, they are discovering that the digitization of the oilfield is essential to unleashing productivity by freeing up resources for more productive purposes. As a result, the modern Digital Oilfield represents a direct response to industry demand for increased production and decreased downtime, through process optimization and remote management. All this is why the Digital Oilfield market is expected to reach an estimated $28.5 billion USD over the next five years.
Solar electricity in the Digital Oilfield
Solar-powered Remote Terminal Unit (RTU) at a pumping site using a Morningstar HazLoc-rated SunKeeper controller. Courtesy of SunWize
Globally there are well over 2 million miles/3.2 million kilometers of oil & gas pipelines, the longest of which stretches over 5,400 miles/8,700 kilometers. The oil & gas extraction sites they support total over 65,000 worldwide, with some 9,000 offshore. The sheer size and scope of this network means that many operations occur in locations far removed from any electrical grid—yet on-site electricity is needed for every mile of pipeline and at every wellhead and terminal, to provide critical power for the monitoring, control, process automation
and production optimization functions that comprise the Digital Oilfield. Diesel and gas generators initially provided a solution at extraction sites, but as Digital Oilfield technology expanded across pipeline networks installing, running, and supporting more and more generators became less practical due to two reasons: they require regular maintenance and periodic teardowns which are expensive, and they must be refueled which further increases operating costs (OPEX). A third liability with generators is that, as a source of noise and emissions pollution, their very use compromises any “oilfield greening” initiatives important to operators today. For these reasons operators with remote powering needs have embraced renewable energy for on-site electricity generation, and solar. Solar’s value proposition for the Digital Oilfield stems from the fact that, unlike generators, solar requires no fueling. Equally important, unlike both generators and wind turbines, solar electric systems have no moving parts and therefore no need for costly regular maintenance or “teardowns.” Along with solar’s inherently higher reliability and significantly lower OPEX, the CAPEX side can be offset by new, advanced technology batteries for energy storage for 24/7 operation, particularly lithium-iron/phosphate (LiFePo) types which are both safe and, because they can last 10x longer than conventional batteries in off-grid solar systems, can “pencil out” more economically than other battery types over the long term. Also, unlike generators and wind turbines, solar is unaffected by environmental extremes. In fact, solar panels or modules become more efficient and work better the colder it gets. This can be maximized to great effect in a field installation through advanced charge controlling
Operational areas where solar electricity is most applicable to Digital Oilfield processes
technology such as Morningstar’s TrakStar MPPT (maximum power point tracking) which effectively extracts every possible Watt from a system for running a load for storage for later. Equipped with the right batteries for the application, solar can function equally well under harsh conditions at sea, in deserts, on mountaintops, and even at the poles.
Using solar electricity to power the Digital Oilfield Nearly any off-grid powering scheme can be upgraded to solar electricity.
Because the many different Digital Oilfield applications and environments out there mean that there are hundreds of possible system configurations and specifications, the detail, design, and components needed are best discussed with a professional system integrator with solar expertise. The following are a few general guidelines applicable to any industrial off-grid solar electric system equipped with energy storage. Solar electric system types, like electricity itself, comes in two “flavors:” AC (alternating current) and DC (direct current). Since solar electricity produced by modules or panels is DC, these systems are usually simpler and can be used to power and control DC loads and charge batteries without the need for any power conversion. If the system to be powered had AC components, an inverter is added to provide DC-AC conversion. Because the module-produced solar electricity must be controlled and regulated to charge batteries and power loads safely and effectively, the “heart and brain” of an off-grid solar electric powering system is the solar charge controller. Depending on the system design and capacity, solar charge controllers can vary in battery bank voltage from 6V to 48V (depending on the type of batteries) and with solar input power capacities typically ranging from 200W to over 3,000W; for larger systems multiple charge controllers are usually specified. For all the brand and model diversity, charge controllers come in essentially two types: • PWM (pulse-width modulation): simple and cost-effective, PWM controllers are basically a switch that “throttles back” solar electricity to prevent battery overcharging. They are ideal for locations with very consistent sunlight, minimal shading, and no physical space limitations. Typical uses are with pole-mounted 36 or 72-cell solar panels which are typical in smaller industrial systems. • MPPT (maximum power-point tracking): while more costly and complex, they have the advantage of maximizing solar array output in areas where it can widely “swing:” in cold climates where solar modules are actually more efficient, or where shading or inconsistent sunlight
Solar electric system implementation on the Digital Oilfield
affects solar “harvesting.” They work by balancing voltage and amperage to find the optimum blend for the panel’s output. MPPT controllers are better suited for larger arrays as well as the new PERC (passive emitter) technology higher-output solar cells. Morningstar MPPT controllers have the added advantage of proprietary TrakStar™ technology, based on patented algorithms that enable them to harvest solar energy even more effectively. MPPT controllers can convert all available solar energy into electricity, while PWM controllers typically “throw away” some of it—but in areas of strong, consistent sunlight that is less of a concern. The point being is that there is no inherent quality difference between PWM and MPPT controller technology. It’s simply a matter of which is the right tool for the job. With the solar charge controller doing the heavy “electronic lifting,” the rest of the off-grid industrial solar powering system is comprised of usually three elements: • Solar panels or modules and racking/masting to support them • Batteries for energy storage. Most used are advanced lead acid (sealed gel or valve-regulated AGM), with both lithium iron-phosphate and nickel-cadmium becoming increasingly popular depending on the application • An enclosure with suitable breakers, connectors, and possibly additional load-management or communications electronics on board
Solar in Hazardous Location (HazLoc) applications For oil & gas and other uses where hazardous gasses and liquids might be present (such as mines), having the proper certifications for use in hazardous locations is critical. A hazardous area is defined as one where three fundamental components are in place: 1. A flammable substance: a. Gas, vapor, or liquid b. Dust c. Fibers 2. An ignition source: spark, open flame, excessive heat, etc. 3. An oxidizer: oxygen present in the open air With that, there are three primary ways to prevent an electronic device from causing an explosion 1. Explosion-proof: isolate or protect from an explosion through an explosion proof device or enclosure
2. Intrinsic safety: design and build to remove the possibility of a spark or other source of ignition (i.e., by keeping operating temperature low) 3. Isolate the explosive substance from anything that could possibly ignite that material (not always possible) Morningstar ProStar and SunSaver charge controllers are designed around intrinsic safety principles, to meet HazLoc certifications. In selected models that includes: • Fanless design—many charge controllers, and nearly all higher-powered ones, use cooling fans to get rid of excess heat during operation. But in addition to their inherent reliability and efficiency issues, cooling fans require airflow around hot internal components to work and exposing the controller’s innards to potentially hazardous vapors. Removing the fan removes the hazard—which Morningstar does across its entire product line. That’s accomplished through advanced electronic and mechanical design for superior thermal management, and a hallmark of Morningstar engineering. • Encapsulated components—selected Morningstar models have internal components sealed in superior-grade epoxy plastic, to further insulate them from hazardous and extreme environments. • Designing to HazLoc standards—all internal circuitry and external connections are designed for intrinsic safety, to eliminate sparks or overheating that could cause ignition of hazardous gases. Besides the superior control of energy, the integrated design and construction of Morningstar products reflects enhanced safety in all aspects, to prevent risk factors accumulating • Comprehensive and ongoing testing and evaluation to rigorous HazLoc standards, to ensure safety and compliancy and achieve the necessary Quality Assurance Notifications and Registrations required for HazLoc certification. When it comes to charge controllers and other critical components, it’s vital for
Solar electric array with Morningstar controllers powering oilfield lighting in the desert, for Kuwait Petroleum Corporation. Courtesy EcoSol Energy Systems
system planners to be aware of the agencies and certifications behind a fully compliant, safe solar electric powering scheme: • North America: UL (Underwriters Laboratories) and CSA (Canadian Standards Association). Compliant devices will have an ETL label, which (summarized) means that they meet the UL/CSA standards for Class 1/Division 2 (areas where explosive concentrations of gasses, vapors and liquids are not normally present but may accidentally exist) and Groups A-D substances (which include Acetylene, Hydrogen, Propane, Gasoline and Methane among others). • Rest-of-World: IECEx (International, various agencies) and ATEX (Europe, also various agencies). Their Zone system is roughly comparable to the Class/Division scheme in North America, with Zone 2 approval applicable to areas where an explosive atmosphere is unlikely to occur under normal conditions except for short periods, from propane, ethylene, or gasses and vapors of equivalent hazard. Morningstar ProStar and SunSaver controllers meet
both UL/CSA and IECEx/ATEX standards, and the Morningstar SunKeeper controller (used in small, single panel systems). meets U/CSA. In addition, both standards also have operating temperature requirements and the devices are rated for safe operation to the maximum ambient temperature marked while not exceeding the surface temperature limit designated, i.e., 212° F/100° C (which is boiling water) for T5.
Morningstar’s line of ProStar (upper) and SunSaver (lower) solar charge controllers with UL/CSA and IECEx/ATEX Hazardous Location certifications, widely used in on and offshore oil & gas operations around the globe.
Considerations for oil and gas electrical connectors 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.
hen we think of oil and gas missions, we tend to imagine huge offshore rigs or donkeys in the middle of the desert swinging tirelessly. Smaller components like electrical connectors are often overlooked, but crucial tasks like drilling or extractions would be impossible without them. Here From extreme temperatures to flammable and explosive environments, electrical connectors used in oil and gas applications face their fair share of challenges. So, what factors should be considered when choosing a connector that can overcome these challenges and keep oil and gas applications running at peak efficiency?
Environmental considerations When choosing connectors for oil and gas missions, there several key factors that should be considered. First, consider the different Zones connectors will be used in. In the Dangerous Substances and Explosive Atmosphere Regulations 2002 (DSEAR), Zone 0 is defined as a constant explosive environment, Zone 1 indicates there is often an explosive atmosphere and Zone 2 is indicative of a rarely explosive atmosphere. The UK Health and Safety Executive (HSE) explains, “the primary purpose of zoning is to facilitate the proper selection and installation of apparatus to be used safely in that environment, taking into account the properties of the flammable materials that will be present”. In a worst-case scenario, it is possible that electricity running through connectors could become an ignition source if it meets flammable liquids and gases in the environment. For this reason, all connectors used in explosive atmospheres must comply with the IECEx international standard which governs the
installation and use of electrical equipment in these environments.
Connector features Next, consider any additional features that will improve efficiency. For example, powering down systems to disconnect equipment, possibly in hazardous environments, can be very timeconsuming and negatively impact productivity. This can be overcome by installing connectors that have hot disconnect capabilities, allowing you to disconnect and reconnect equipment without powering the entire system down.
Another way to maximise efficiency is to consider the connector’s ease and speed of assembly. PEIGenesis supplies connectors that can withstand the challenges of the oil and gas industry, such as the Trolex Falcon 25 series which is best known for its rapid mate-and-lock mechanism and has an assembly time of only a few minutes. PEIGenesis is also an ATEX-approved assembler of the Amphenol Star-Line EX and Amphe-Ex, which are arguably the most popular oil and gas connectors in the world due to their sturdy design and plethora of configuration options.
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In this issue: - The new normal is digital - Making Digital Transformation a Reality - Challenges for growing biofuels sector - A new view f...
Published on Aug 26, 2021
In this issue: - The new normal is digital - Making Digital Transformation a Reality - Challenges for growing biofuels sector - A new view f...