The UK gas balance has reached a deadlock for the summer. Resilient UK production, Norwegian imports and baseload LNG imports are overwhelming the market with supply. And with lockdown placing huge pressure on electricity and fuel markets, demand will be weak throughout the summer.
Compounding matters, the UK has very limited storage capacity for injections and is approaching the limits on its ability to export volumes into neighbouring markets.
Put simply, the UK market is running out of space.
Hadrien Collineau, a senior analyst with Wood Mackenzie’s gas team, said: “The industry and power sectors account for most of the UK’s summer gas demand. And both of those sectors have been hit hard by the lockdown. Although restrictions will start to ease, it will be a slow process. Gas demand will take time to recover.
“With most lockdown measures continuing throughout May, we expect that demand will come in 18 per cent below its five-year average. Demand will remain weak through the summer, regularly testing a floor of just 3 billion cubic metres (cm) per month.
“However, UK gas production has been resilient, exceeding 2019 levels year-to-date by 3 per cent. Importantly, UK production at risk from low NBP prices is minimal, as sustained price levels below US$1.5 per million British thermal units would be necessary to shut in production.
“Indeed, many fields with higher operating costs are mature and closer to cessation of production. Earlier shut-in would bring forward high decommissioning costs – something to be avoided in the current cash-constrained environment. For less mature fields, companies will consider the balance between the costs of restarting production versus the costs of maintaining gas flow.
“While UK producers are suffering from low gas prices, we don’t expect any material production shut-ins,” Collineau said.
“Operators are likely to delay non-essential spring and summer maintenance where possible. This could add volumes to the market through to July, but potentially ease the pressure in late-summer.”
He added that exports are reaching their limits. Space in the Irish market is very limited. Meanwhile, the UK is making use of its export capacity to Continental Europe through the two pipelines – IUK and BBL – that connect UK to Belgium and the Netherlands, respectively.
“The UK’s export capacity to continental Europe via the IUK and BBL are booked at 65 per cent and 100 per cent capacity, respectively, for May, and at 48% and 100% for June, respectively,” Collineau said.
“We expect this level of utilisation to be sustained through summer, providing a minimum 1.7 billion cm/month of takeaway capacity.”
The total export capacity to continental Europe is 2.3 billion cm/month. However, a larger NBP discount to TTF would be needed to spur higher flows.
Collineau said: “Typically flowing towards the UK during winters, these pipelines offer a safety valve into Europe during periods of oversupply. In April, utilisation averaged 30% and 75% on the IUK and BBL, respectively.”
Norwegian piped suppliers are adapting to a changing market. Its gas exports to the UK dropped by more than half in April in response to the limited market space. But we believe the low levels of Norwegian imports through summer will not drop lower than 1 billion cm/month.
“But LNG has shifted in the opposite direction,” Collineau added. “Utilisation at the UK’s South Hook terminal has ramped up significantly as it absorbs more Qatari LNG that cannot find a home in premium Asian markets.”
He added that gas storage could be full by early June.
“The UK’s largest and only long-range storage facility, Rough, closed in June 2017. The field contained over two-thirds of the UK’s total storage volumes. Without it, it is more difficult for the UK to meet peak winter demand. It also makes it more difficult to absorb excess volumes through the summer months.
“And as we approach this year’s summer season, storage is already very limited, with inventories more than 60% full. With only 600 million cm of space for storage injections this summer, there’s a risk that storage could be full by early June,” Collineau added.
“With UK summer demand expected to be lower than average and with limits on storage capacity, it’s clear that there is very little space for any additional supplies.
“LNG exporters hoping to place cargoes into the UK market have the most to lose. There simply won’t be any more space.”
Consequently, the UK’s effective regasification capacity will be capped at 2 billion cm/month through the summer – or just under 50 per cent of total UK regasification capacity. LNG exporters desperately looking for market are fast approaching another brick wall.
By: Paul Carthy, Managing Director, Energy Industry Group, Accenture in the Middle East
Our world today continues to weather exceptional circumstances as COVID-19 evolves at unprecedented speed and scale - with no industry entirely immune to its unraveling impact. As governments and organisations quickly found themselves faced with a universal imperative to take rapid action, find solutions, mitigate risks, and adapt to the new normal, they continue to be challenged with navigating uncharted waters and ensuring business continuity.
Industries from manufacturing to food and beverage, and from oil and gas to technology, are all in the same predicament. Faced with their own unique set of hurdles to overcome during this pandemic, the focus remains to protect and empower their people, serve customers’ needs, and ensure business continuity.
To protect their people, organisations across the world have been implementing travel bans and work from home policies. They are restricting entry into offices while re-examining how their workplaces operate, and how their people work, interact, communicate, and deliver. Their top priority through it all is to protect the health and safety of people at their workplaces. To minimise business disruption and ensure employee well-being, organisations have had to act quickly and decisively – every day counts.
Driven by innovation and with years of cloud-based operations to its credit, Accenture’s global workforce of more than 500,000 people are highly distributed, and well accustomed to working in an ‘elastic workplace’ environment. Our vast experience enables us to help organisations in these challenging times tailor their responses according to their individual workplace requirements, allowing organisations to scale and adapt to evolving business needs based on global and local conditions and restrictions quickly and dynamically.
Within a short timeframe, Accenture enables organisations to rapidly modernise and scale up their collaboration capabilities as well as their workforce engagement plans. Based on our research and experience, Accenture’s Elastic Digital Workplace roadmap outlines six dimensions that have proven effective in facilitating a quick and seamless transition to a remote workplace environment:
In the prevailing climate of crisis, decisions not only determine how an organisation operates in the near-term, but also significantly impact how it will operate in the future. Smart leaders will seize this opportunity to take swift action to navigate the crisis to avoid business disruption and potential revenue loss. In doing so, they will forge new levels of trust with their workforce, and position their businesses for greater resilience and productivity in the future.
Each company, industry, and region will have unique needs and requirements for workplace and people management, customer service, data management, and business continuity. However, leaders must prepare for the short-term while also developing new capabilities and ways of working to enable longer-term changes to how they operate seamlessly. The time to act is now.
This monthly column appeared in the May issue of Pipeline Magazine
National oil companies (NOCs) globally are estimated to cut exploration budgets by over a quarter on average in 2020, says Wood Mackenzie.
The analysis is based on announcements and tracking well plans of 11 top spending NOC explorers, including three Chinese NOCs, PTTEP, PETRONAS, ONGC, Rosneft, Gazprom, Petrobras and Pemex. Collectively, their combined original budgets may potentially be reduced by about 26 per cent or US$5 billion to around US$14 billion this year.
Wood Mackenzie senior analyst Huong Tra Ho said: “While the range of exploration budget cuts for the NOCs is slightly more diversified than that of the Majors, conventional exploration remains important for them.
“Most NOCs consistently spent between 12 per cent and 35 per cent of their upstream budgets on exploration, an average of about 17 per cent over the 2015-2019 period. This is significantly higher than the majors’ average spend of 8 per cent of upstream budgets on exploration.”
NOCs with substantial international presence will prioritise domestic activity, with deeper cuts to overseas budget.
Ho said: “Most NOCs on the list carry strong government mandates. Many NOCs prioritise current revenue and contribution to government budgets at the expense of capital investments for the future. A dollar invested at home remains at home in the form of local employment, local services, taxes and government take.”
NOCs with constrained domestic resources could place more strategic importance on exploration compared to those with resource abundance. As organically added resources contribute between 50 per cent and 70 per cent of their production in the next decade, PETRONAS and CNOOC Ltd are striving to protect their exploration plans as much as possible. By contrast, Gazprom and Rosneft have long reserve lives and feel less pressure to rush their exploration plans.
Another key factor to supporting exploration plans is financial strength. With strong balance sheets, Petronas, PTTEP and CNOOC Ltd are more able to continue with most of their high-impact exploration ambitions.
Ho said: “Some NOCs can achieve meaningful absolute savings from exploration cuts, especially if it originally makes up a big portion of the company’s upstream budget. An example is Sinopec, whose exploration spend consistently accounts for a quarter or more of upstream budget; in which case cutting back exploration significantly contributes to necessary savings.
“Exploration budget cuts while necessary today, will impact companies’ future growth and sustainability. Given how important exploration is for the NOCs and their growing share of global new discoveries, these budget cuts are likely short-term measures rather than long-term. We expect NOCs to revitalise their exploration programmes as the sector recovers.”
After a dip this year, new renewable capacity additions are expected to rebound in 2021, but policy certainty is critical to ensure investor confidence, the International Energy Agency said in its Renewable Market Update report.
The world is set to build fewer wind turbines, solar plants and other installations that produce renewable electricity this year because of the impact of the COVID-19 crisis, marking the first annual decline in new additions in 20 years, according to the International Energy Agency. But their growth is expected to resume next year as most of the delayed projects come online and assuming a continuation of supportive government policies.
Renewable power sources have so far showed impressive resilience despite the disruptions and changes caused by the coronavirus pandemic, with their share of the electricity mix increasing in many markets. But the world is set to add 167 GW gigawatts (GW) of renewable power capacity this year, 13% less than in 2019, according to the IEA’s Renewable Market Update report, which was released today.
The decline reflects possible delays in construction activity due to supply chain disruptions, lockdown measures and social distancing guidelines, as well as emerging financing challenges. But despite the slowdown in new additions, overall global renewable power capacity still grows by 6 per cent in 2020, surpassing the total power capacity of North America and Europe combined.
Next year, renewable power additions are forecast to rebound to the level reached in 2019, with significant support coming from the partial commissioning of two mega hydropower projects in China. But despite the rebound, growth for 2020 and 2021 combined is expected to be 10 per cent lower than the IEA had previously forecast before the coronavirus outbreak. Almost all mature markets are affected by downward revisions, except the United States where investors are rushing to finish projects before tax credits expire. After exceptional growth last year, Europe’s new additions are set to fall by one-third in 2020, their largest annual decline since 1996. A partial recovery is expected next year.
“The resilience of renewable electricity to the impacts of the COVID-19 crisis is good news but cannot be taken for granted,” said Dr Fatih Birol, the IEA Executive Director. “Countries are continuing to build new wind turbines and solar plants, but at a much slower pace. Even before the Covid-19 pandemic struck, the world needed to significantly accelerate the deployment of renewables to have a chance of meeting its energy and climate goals. Amid today’s extraordinary health and economic challenges, governments must not lose sight of the essential task of stepping up clean energy transitions to enable us to emerge from the crisis on a secure and sustainable path.”
Solar PV accounts for more than half of the forecast expansion in renewable power in 2020 and 2021, but its additions decline from 110 GW in 2019 to over 90 GW in 2020. Large-scale solar PV projects are expected to rebound in 2021, but overall installations are unlikely to surpass 2019 levels. This is because of a significantly slower recovery of distributed solar PV as households and small businesses review investment plans. Commissioning delays caused by the COVID-19 crisis have slowed the pace of onshore wind installations this year, but they should mostly be compensated for in 2021, as the majority of projects in the pipeline are already financed and under construction. However, uncertainty remains over projects that had planned to secure their financing this year and become operational next year. The impact of the crisis on offshore wind deployment is set to remain limited in 2020 and 2021, since offshore projects have longer construction periods than onshore ones.
At the start of this year, renewables were already facing challenges in several markets in terms of financing, policy uncertainty and grid integration. COVID-19 is now intensifying those concerns. However, governments have the opportunity to reverse this trend by making investment in renewables a key part of stimulus packages designed to reinvigorate their economies. The priority should be on sectors that offer early opportunities to create jobs and economic activity while developing more efficient and resilient energy systems and reducing emissions. That includes a focus on buildings and transport, which would support both renewables and energy efficiency at a same time.
“The spectacular growth and cost reductions of renewables over the past two decades have been a big success story for global energy markets, driven by innovation in both technology and policies. But continuing cost declines will not be enough to protect renewables from a range of uncertainties that are being exacerbated by COVID-19,” said Dr Birol. “This underlines the critical importance of getting stimulus packages and policy strategies right in order to ensure investor confidence in the months and years ahead.”
The impact of the coronavirus pandemic on renewables extends well beyond the electricity sector. Successful transitions to clean energy will require decarbonising the rest of the economy as well, including transport fuels and the heating of buildings.
The COVID-19 crisis has radically changed the global context for biofuels, which are a key element in the shift to more sustainable transport. The sharp fall in demand for gasoline and diesel also hurts biofuel consumption driven by policies requiring suppliers to blend a set amount of biofuels with fossil transport fuels. Production of biofuels for transport is now expected to contract by 13 per cent in 2020. If a rebound in transport fuel demand occurs in 2021, biofuel production could return to 2019 levels, but this would still be lower than the IEA’s pre-pandemic forecast.
The consumption of renewables for heating is also set to decline in 2020. The recent plunge in oil and gas prices is hurting the cost-competitiveness of renewable fuels and technologies that provide heating. Many planned investments to switch from fossil-fuel heating to renewable or electric alternatives are likely to be postponed or cancelled unless governments introduce stronger policy support.
Commercial and industrial demand for natural gas is declining as most countries around the world impose lockdowns to limit the spread of the COVID-19 pandemic. Rystad Energy estimates global natural gas demand to fall by almost 2 per cent this year as a result of the lower activity.
In absolute terms, Rystad Energy says it expects global gas demand to total close to 3,878 billion cubic meters (Bcm) in 2020, down from 3,951 Bcm last year. In our pre-COVID-19 estimates, this year’s natural gas demand was expected to grow to 4,038 Bcm.
Like oil demand, gas demand is also expected to suffer as a result of the slowdown. However, low prices are shielding gas demand to some extent as the fuel remains more competitive than other sources of energy, especially in the power sector where gas use remains relatively stable in most countries.
“2020 will be the first year since 2009 where there will be no growth in consumption. This will be a hard blow for an industry accustomed to yearly growth rates of more than 3 per cent,” says Rystad Energy’s Head of Gas and Power Markets Carlos Torres-Diaz.
The impact on gas demand has varied substantially from country to country depending on the severity of lockdown measures and factors such as the power mix and industrial activity. Countries with capacity to switch from coal to gas will see less effect from the demand drop.
Italy is one of the countries that have been the most affected by COVID-19, and as a result the government decided to impose a strict lockdown starting in the beginning of March. The average loss in gas demand from the power and industrial sectors has been a staggering 23 per cent over the duration of the lockdown. However, Italy has little coal-power generation capacity, meaning that any reduction in power demand will represent a similar drop in gas-for-power demand as a it is difficult to achieve a reduction in generation from renewable sources.
Other European countries have seen similar effects, with the International Energy Agency estimating a total loss in weather-adjusted gas demand of 25 per cent in France and 19 per cent in the UK.
On the other hand, demand in the U.S. continues to thrive, mostly as a result of increasing demand from the power sector which has compensated for the drop in other sectors. Gas demand from the power sector has averaged 25 billion cubic feet per day (708 million cubic meters per day) over the last two weeks, which is practically in line with last year’s level.
But there have been periods during the current lockdown where demand has been more than 15 per cent above last year’s level. The main reason for this is that gas prices remain very low, and while coal prices have also dropped, gas is still more competitive in power generation. The drop in U.S. power demand has therefore pushed coal out of the generation stack rather than gas.
There are many other countries that also have a large coal-to-gas switching capacity, such as Australia, Germany and South Korea, which could see similar demand responses to the one seen in the U.S.
A lot of uncertainty remains about the actual impact on gas demand. The possibility of new lockdowns, the slowdown in economic growth and the effect of stimulus packages on reactivating commercial and industrial activity could all tip the gas-demand scale.
This uncertainty represents a downside risk for gas demand for the rest of the year. However, Rystad Energy has forecasted natural gas production to be around 4,000 Bcm in 2020 based on the lower investment activity expected across the E&P industry during this year.
Given that global gas storage capacity is very limited and that a lot of the gas production is driven by liquids, producers will push these volumes into the market. This could trigger a demand response to absorb the additional volumes, but this will be very dependent on gas prices remaining competitive to coal. Our forecast is for European gas prices (TTF) to average $3.3 per MMBtu and Asian spot prices to average $3.8 per MMBtu this year, which is below the coal-to-gas switching range in most countries.
Therefore, if coal producers manage to reduce prices further and the steep contango in the gas forward curves remains, then there is a risk of seeing a slowdown in gas demand towards the end of the year.
A new report by DNV GL reveals that hydrogen has surged up the priority list of many oil and gas organisations, taking a primary position in the sector’s decarbonisation efforts.
A fifth (21 per cent) of senior oil and gas industry professionals say their organisation is already actively entering the hydrogen market, according to a new report published by DNV GL, the technical advisor to the sector. The proportion intending to invest in the hydrogen economy doubled from 20 per cent to 42 per cent in the year leading up to the Coronavirus-induced oil price crash.
Heading for Hydrogen draws on a survey of more than 1,000 senior oil and gas professionals and in-depth interviews with industry executives. The report suggests that recent shifts in the industry’s investment priorities are unlikely to affect the sector’s long-term efforts to reduce carbon emissions.
DNV GL found a significant rise in those reporting that their organisation is actively adapting to a less carbon-intensive energy mix – up from 44 per cent for 2018 to 60 per cent for 2020. Carbon-free hydrogen production, transmission and distribution is now widely recognized as a central component to the oil and gas industry’s decarbonisation efforts.
“Hydrogen is in the spotlight as the energy transition moves at pace – and rightly so. But to realise its potential, both governments and industry will need to make bold decisions,” said Liv A. Hovem, CEO, DNV GL – Oil & Gas. “The challenge now is not in the ambition, but in changing the timeline: from hydrogen on the horizon, to hydrogen in our homes, businesses, and transport systems.”
More than half of respondents to DNV GL’s research in Asia-Pacific (56 per cent), the Middle East & North Africa (54 per cent) and Europe (53 per cent) agree that hydrogen will be a significant part of the energy mix within 10 years. North America (40 per cent) and Latin America (37 per cent) are only a little behind.
The success of a hydrogen energy economy is closely aligned with the future of natural gas, renewable energy, and carbon capture and storage (CCS) technology, according to Heading for Hydrogen.
While hydrogen gas produced from renewable energy (green hydrogen) is the industry’s ultimate destination, analysis shows that the sector can only realistically scale up to large volumes and infrastructure with carbon-free hydrogen produced from fossil fuels combined with CCS technology (blue hydrogen).
DNV GL’s 2019 Energy Transition Outlook, a forecast of world energy demand and supply, predicts that natural gas will become the world’s largest energy source in the mid-2020s, accounting for nearly 30% of the global energy supply in 2050. Natural gas and hydrogen can play similar roles within the global energy system, and the synergies between them – in application and infrastructure – will drive the hydrogen economy.
However, Heading for Hydrogen points to political, economic, and technical complexity in scaling the hydrogen economy.
“To progress to the stage where societies and industry can enjoy the benefits of hydrogen at scale, all stakeholders will need immediate focus on proving safety, enabling infrastructure, scaling carbon capture and storage technology and incentivizing value chains through policy,” said Hovem.
DNV GL is involved in projects spanning all four of these enabling factors, including:
Download Heading for Hydrogen at: dnvgl.com/headingforhydrogen
The COVID-19 pandemic and the low oil-price environment it has created continues to affect global energy markets and activity levels by oil and gas producers. New fracking jobs in the U.S. are not immune to the trend and Rystad Energy expects May to be the month that such activity will hit rock bottom before a recovery begins in the third quarter of 2020.
We estimate that the total number of started frac operations in the country’s Lower 48 states will end up at around 300 to 330 wells in May 2020, down from April’s 337 wells.
Many companies chose to initiate complete nationwide frac holidays for the second quarter, and the remaining frac spreads were released after their last jobs were completed in April, which made the decline in started jobs particularly dramatic last month. Some activity is still going on, and we have so far identified 92 started frac operations in May on a standard-month basis.
“Our most recent conversations with suppliers, service providers and E&Ps indicate that we will probably see activity stay at the current low level for the rest of the second quarter. A modest recovery is expected in 3Q20, but stable WTI oil prices in the low- to mid-$30s are required to see this recovery in selected core acreage positions operated by producers with strong balance sheets,“ says Rystad Energy Head of Shale Research Artem Abramov.
Among oil basins, the Permian is on track to contribute the most to the anticipated decline in May 2020. The Permian saw slower activity reductions in March and April than other oil regions and the decline is now catching up. With more than 40 frac operations already identified, we believe that the Permian will still see more than 100 started frac operations this month (the current base case estimate suggests 124 jobs on a standard-month basis).
The Eagle Ford, Bakken and Anadarko regions all seem to have reached the bottom, and the current monthly trends exhibit a high degree of noise driven by the timing of completion rounds. Our base-case estimate has fracking operations at 34 in Eagle Ford, 20 in the Bakken and eight wells in Anadarko this month.
Niobrara stands out as an outlier as it already has 13 started frac jobs (the base case for the month is 46 wells), half of what was started in all of April. Adjusting for incomplete coverage, if no frac spreads are released, the Niobrara region is on track to see quite healthy recovery in activity this month percentage-wise, though it is still 70% to 75% below the level of fracking seen in February 2020.
Activity is slowing down in the Appalachia basin (May’s base case is at 60 wells), in line with the guidance of major producers who frontloaded their frac schedules for 2020. Declining rig counts also leave little room for acceleration in fracking before drilling activity is restored. The inventory potential of drilled but uncompleted (DUC) wells in the Marcellus and Utica regions has largely been depleted by now.
The Haynesville region shows weak coverage for May so far, so the final estimate suggests that weak fracking from April has extended into the current month. Yet we believe that the running rate of Haynesville activity now should be closer to 15 to 25 wells per month, and it is likely that we will see confirmation of this in next week’s update.
There are no hard numbers yet to illustrate the extent to which the COVID-19 pandemic has affected the oil and gas industry’s digitisation. However, a Rystad Energy analysis of service companies’ earnings calls reveals a clear growth in cost-saving remote work technologies.
Given the limited options of low-hanging cost savings in the current downturn, operators and suppliers are looking towards digital technologies to realize cost efficiencies. For operators whose cash balances are not under short-term strain, the low oil-price environment is an ideal testing ground for new technologies as the opportunity costs of implementing these are lower.
“Despite being positive news for suppliers offering digital technologies, spending by operators may have been accelerated as a result of Covid-19 instead of actual business needs. Growth seems to have mostly centered around remote work, while technologies focusing on optimization of drilling and production seem to have hit some speed bumps,“ says Daniel Holmedal, energy service analyst at Rystad Energy.
Recent earnings calls have given us a taste of how digital technologies have fared during the start of the downturn. Despite recent market events that have forced operators and suppliers to turn their focus towards cash conservation, development on this digital revolution still seems to be relatively robust.
In fact, both Schlumberger and Halliburton noted in their earnings calls for the first quarter of 2020 that the current downturn could accelerate the adoption of digital technologies. This is especially true for technologies that enable remote operations, which remains an area where great cost efficiencies could be realized with more efficient operations.
Covid-19 has already accelerated remote operations due to the movement restrictions imposed in many countries to limit the outbreak. Schlumberger recently deployed its DELFI platform for Woodside so that the operators’ asset team and geoscientists could have full access to their data while working from home.
Schlumberger, in its first quarter earnings call, underlined intentions of doubling down its digital strategy in the years ahead, with over 60% of the OFS provider’s drilling operations in March being conducted remotely. At a more general level, Covid-19 has also paved the path for key decision makers to get more first-hand experience with digital tools. This could eventually increase their willingness to fully buy in on the digital revolution in other parts of their companies.
Halliburton, similarly, noted during its first-quarter earnings call that demand for cloud infrastructure services saw an uptick in April 2020. In late February, Halliburton helped Pertamina deploy a large portion of its processes and applications to the iEnergy cloud, which has allowed for well data to be structured and analyzed to improve drilling performance, increase production and allow for better data-driven decisions along the well life-cycle.
National Oilwell Varco (NOV), one of the largest suppliers within the drilling tools and services segment, also reported updates on its digital technologies in the latest earnings call. Using its TrackerVision augmented reality technology, which streams real-time audio and video, NOV is able to provide instructions on rig repairs remotely.
Despite the growth in remote work digital solutions, not all is well for suppliers of digital technology, warns Holmedal.
“Our activity forecast for 2020 indicates that spending on new technologies in the well services market will come under significant pressure. We expect the number of wells drilled globally this year to drop by 21% from 2019, ending up at around 56,000 wells, with 2,200 of the wells being drilled offshore,“ Holmedal notes.
Service companies also warned of a downturn, with some already taking action such as furloughing some employees related to research and development and cutting back on sales, general and administrative expenses.
Schlumberger noted in its first quarterly report for 2020 that discretionary spending and activity was cut towards the end of the quarter in several markets. Lower drilling activity, more shut-ins and stretched balance sheets among operators could hurt spending on digital technologies going forward.
Baker Hughes noted in its earnings call that its Digital Solutions business, which also covers segments outside of oil and gas, saw revenues and margins come under significant pressure during the first quarter.
The COVID-19 pandemic and its devastating effect on global energy investments is set to damage subsea purchases, with demand for umbilical lines expected to fall by 32 per cent to just 713 kilometers (km) of lines in 2020, down from 1,041 km last year, a Rystad Energy impact analysis reveals.
Umbilical demand will not match or exceed 2019 levels until after 2023, our forecasts show, despite definite cost savings in materials. To put these numbers into context, before the pandemic demand for umbilicals was due to slightly decrease this year compared to 2019, but to rebound and exceed last year’s levels from 2021 onwards.
Without accounting for the negative impact of a global economic downturn, we see a cost reduction of approximately 5 per cent taking place from 2020 to 2022 within the umbilicals segment. If on the other hand, both the global recession and oil and gas industry downturn take place simultaneously, our outlook will change drastically. We then estimate a cost reduction of almost 14% over the same time frame.
“This will provide umbilical manufacturers short-term relief regarding their own costs as material prices fall, allowing them to maintain production volumes and recover some of their margins despite cutting their own prices. However, this short-term relief may not last long as the global economy recovers from the Covid-19 pandemic,” says Rystad Energy oilfield service analyst Henrik Fiskadal.
The materials most commonly found in the manufacturing of umbilicals are high-grade stainless steel, carbon steel armor wire, hydraulic hoses, power cables, fiber optic cables and thermoplastic resins. In addition to the materials, engineering labor is the next largest cost input involved in the manufacturing of umbilicals. Therefore, the more complicated and unique is the design, the more strenuous and costly the fabrication and installation processes.
Prices for materials have remained relatively flat since 2014, whilst the service price for SURF equipment has fallen significantly. This illustrates the large cost savings realized by operators since 2014 and supports our belief that operators will not be able to enforce the same cost cuts from 2020 onwards, having exhausted most of the cost cutting potential in the years following the 2014 downturn.
Should we see a global recession, materials such as high-grade stainless steel may decrease significantly in price. However, when the global economy rebounds from Covid-19, material pricing could increase before the oil and gas industry is ready to accept higher prices for umbilicals.
As a result, in addition to our 2020 demand forecast downgrade, we have also revised our umbilicals demand expectations for 2021-2023. In 2021, demand is expected to reach 798 km, growing to 819 km the following year and to 979 km in 2023.
A prolonged decline in demand will always bring storage constraints for fuels that need to be stored and shipped before being consumed. Oil has been hit much more quickly than other fuels by the unprecedented demand destruction caused by COVID-19, with prices plunging to historical lows and storage filling up. Liquefied natural gas (LNG) is next in line, a Rystad Energy analysis finds.
Global LNG supply is forecast to reach 380 million tonnes (Mt) in 2020, 17 Mt higher than in 2019. Demand, on the other hand, is expected to rise only 6 Mt from 2019 to 359 Mt according to our current estimate, as industrial activity has declined due to the pandemic.
The consumption, or demand, is more flexible for LNG than for other fuels as different fundamentals such as weather can rapidly change during the year. If the world faces a colder-than-forecast winter and lockdowns are lifted faster than expected, then demand will see a boost. The opposite could happen if the winter is milder or if resumption of industrial activity sees further delays.
Normally a reasonably oversupplied market is not necessarily a problem as buyers take advantage of the lower prices to utilize more gas for power generation and to store gas/LNG after the winter season. But in 2020, when ample LNG supply is coupled with demand destruction, prices have already hit record lows and storages have already filled faster than usual. Production shut-ins are becoming a realistic possibility.
Europe became the de facto global LNG sink in 2019, when the milder-than-expected winter slowed down LNG demand growth in Northeast Asia. Europe imported about 80 Mt of LNG in 2019, an 80% increase from 2018. In the first two months of 2020, when the coronavirus pandemic hit Northeast Asia heavily, Europe managed to increase LNG imports by 35% compared to the same period in 2019, mainly driven by the UK, Spain and Belgium.
The impact on LNG imports to other European countries has not been as significant as initially expected, however. European demand has been rather resilient to Covid-19 as buyers stock up on cheap supplies: The continent realized a monthly record-high LNG import of 8.9 Mt in March, a 20% year-on-year increase.
Where is the problem? Gas storage space is a key factor for Europe’s ability to absorb excess LNG volumes. At the end of March 2020, about 62 billion cubic meters (Bcm) of gas was in European storage, 16 Bcm higher than in March 2019. If gas storage approaches top capacity at the end of the filling season, as was the case at the end of October 2019 (98% full), European gas inventories now only have space for some 48 Bcm of gas before winter 2020.
Front-month gas contracts at the TTF trading point in the Netherlands have been trading below $2 per million British thermal units (MMBtu) in April, suggesting that gas traders could take advantage of the historical low gas prices and fill Europe’s storage facilities faster than usual. As a result, European storage could reach its limit and LNG cargoes with deliveries in the summer months are at risk of being canceled.
And the continent’s demand is not growing much either. Europe consumed 554 Bcm of natural gas in 2019, 13 Bcm more than in 2018, primarily driven by coal-to-gas switching in the power sector. We expect European gas consumption to remain at the 2019 level, with a possible mild increase in the power sector. Not much, though, as the coal-to-gas switching in is well maxed out.
“Asia is not likely to take up the full slack. Europe will be under serious pressure to absorb LNG, but it looks like this will be tough given storage levels, lower demand, and the cost of sending it there, especially from the US. If global gas prices slip even further in 2020, this could translate into potential LNG shut-ins,“ says Xi Nan, Vice President for Gas and Power Markets at Rystad Energy.
In Asia, the signed term contracts can provide Japan and South Korea with enough LNG, meaning the two countries don’t need much gas from the spot market. Chinese LNG buyers, including smaller players, are able to absorb some excess volumes, but less than the expected levels before the pandemic. India is expected to continue utilizing low gas prices and purchase spot cargoes only when the lockdown is fully lifted.
We still don’t have an end date for when Europe will completely re-emerge from lockdown, and the impact will probably be deeper coming into the summer months. With gas storage tanks already almost filled to the brim, Europe’s capacity to import and actually use the same amount of LNG as in 2019 seems like a tall order, especially if we see another mild winter.
The COVID-19 pandemic will leave not only short-term, but also long-term scars on the oil market. Even though the world is currently facing what is arguably the largest oil glut ever recorded, the tables will turn dramatically in coming years.
The lack of activity and investments currently planned by cost-conscious E&P firms, combined with an inevitable rebound in global oil demand, is set to cause a supply deficit of around 5 million barrels per day (bpd) in 2025, Rystad Energy calculates, with prices seen topping $68 per barrel to balance the market.
In our base case scenario, global demand for liquids in 2025 will reach around 105 million bpd. Before the COVID-19 pandemic, Rystad Energy expected supply to slightly exceed demand. However, due to the steep curtailment of investments and activity that the current crisis has brought this year, Rystad Energy now estimates that the downcycle in the upstream industry will remove about 6 million bpd from production forecasts for 2025.
To fill this gap, Rystad Energy believes that some of the core OPEC countries, like Saudi Arabia, Iraq and UAE, will be able to ramp up production. In total these countries might fill 3 million to 4 million bpd of this gap. The remaining shortfall will most likely be filled with volumes from US tight oil. To achieve this, prices may move above our current base case, which currently stands at an average price of $68 per barrel in 2025.
“The current low oil price has tightened the medium-term supply and demand balance considerably. Despite high growth in tight oil, oil production outside the OPEC Middle East countries is expected to stay flat over the next five years. As demand is expected to recover, the core OPEC counties will need to increase their supply significantly or the market will face even higher prices than our base-case forecast,” says Rystad Energy Head of Upstream Research Espen Erlingsen.
Global E&P activity is poised to fall dramatically this year as upstream companies try to cope with the challenging market conditions, resulting in conventional project sanctioning activity falling to a 40-year low and tight oil investments dropping by almost 50 per cent this year. The impact of the lower activity levels varies depending on the supply segment.
For tight oil (including NGL) the impact on production is rather immediate, and we have reduced our 2020 forecast by close to 1.9 million bpd. The dramatic reduction in new tight oil wells will also have a long-term impact, as fewer wells will be available for production. For 2025 our total tight oil production forecast is revised to 18 million bpd, or 2.7 million bpd lower than our pre-crisis estimate.
The COVID-19 pandemic represents the biggest shock to the global energy system in more than seven decades, with the drop in demand this year set to dwarf the impact of the 2008 financial crisis and result in a record annual decline in carbon emissions of almost 8 per cent.
In a new report, the International Energy Agency provides an almost real-time view of the COVID-19 pandemic’s extraordinary impact across all major fuels. Based on an analysis of more than 100 days of real data so far this year, the IEA’s Global Energy Review includes estimates for how energy consumption and carbon dioxide (CO2) emissions trends are likely to evolve over the rest of 2020.
“This is a historic shock to the entire energy world. Amid today’s unparalleled health and economic crises, the plunge in demand for nearly all major fuels is staggering, especially for coal, oil and gas. Only renewables are holding up during the previously unheard-of slump in electricity use,” said Dr Fatih Birol, the IEA Executive Director. “It is still too early to determine the longer-term impacts, but the energy industry that emerges from this crisis will be significantly different from the one that came before.”
The Global Energy Review’s projections of energy demand and energy-related emissions for 2020 are based on assumptions that the lockdowns implemented around the world in response to the pandemic are progressively eased in most countries in the coming months, accompanied by a gradual economic recovery.
The report projects that energy demand will fall 6 per cent in 2020 – seven times the decline after the 2008 global financial crisis. In absolute terms, the decline is unprecedented – the equivalent of losing the entire energy demand of India, the world’s third largest energy consumer. Advanced economies are expected to see the biggest declines, with demand set to fall by 9 per cent in the United States and by 11 per cent in the European Union. The impact of the crisis on energy demand is heavily dependent on the duration and stringency of measures to curb the spread of the virus. For instance, the IEA found that each month of worldwide lockdown at the levels seen in early April reduces annual global energy demand by about 1.5 per cent.
Changes to electricity use during lockdowns have resulted in significant declines in overall electricity demand, with consumption levels and patterns on weekdays looking like those of a pre-crisis Sunday. Full lockdowns have pushed down electricity demand by 20 per cent or more, with lesser impacts from partial lockdowns. Electricity demand is set to decline by 5 per cent in 2020, the largest drop since the Great Depression in the 1930s.
At the same time, lockdown measures are driving a major shift towards low-carbon sources of electricity including wind, solar PV, hydropower and nuclear. After overtaking coal for the first time ever in 2019, low-carbon sources are set to extend their lead this year to reach 40 per cent of global electricity generation – 6 percentage points ahead of coal. Electricity generation from wind and solar PV continues to increase in 2020, lifted by new projects that were completed in 2019 and early 2020.
This trend is affecting demand for electricity from coal and natural gas, which are finding themselves increasingly squeezed between low overall power demand and increasing output from renewables. As a result, the combined share of gas and coal in the global power mix is set to drop by 3 percentage points in 2020 to a level not seen since 2001.
Coal is particularly hard hit, with global demand projected to fall by 8 per cent in 2020, the largest decline since the Second World War. Following its 2018 peak, coal-fired power generation is set to fall by more than 10 per cent this year.
After 10 years of uninterrupted growth, natural gas demand is on track to decline 5 per cent in 2020. This would be the largest recorded year-on-year drop in consumption since natural gas demand developed at scale during the second half of the 20th century. The massive impact of the crisis on oil demand has already been covered in detail in our April Oil Market Report.
Renewables are set to be the only energy source that will grow in 2020, with their share of global electricity generation projected to jump thanks to their priority access to grids and low operating costs. Despite supply chain disruptions that have paused or delayed deployment in several key regions this year, solar PV and wind are on track to help lift renewable electricity generation by 5 per cent in 2020, aided by higher output from hydropower.
“This crisis has underlined the deep reliance of modern societies on reliable electricity supplies for supporting healthcare systems, businesses and the basic amenities of daily life,” said Dr Birol. “But nobody should take any of this for granted – greater investments and smarter policies are needed to keep electricity supplies secure.”
Despite the resilience of renewables in electricity generation in 2020, their growth is set to be lower than in previous years. Nuclear power, another major source of low-carbon electricity, is on track to drop by 3 per cent this year from the all-time high it reached in 2019. And renewables outside the power sector are faring less well. Global demand for biofuels is set to fall substantially in 2020 as restrictions on transport and travel reduce road transport fuel demand, including for blended fuels.
As a result of these trends – mainly the declines in coal and oil use – global energy-related CO2 emissions are set to fall by almost 8 per cent in 2020, reaching their lowest level since 2010. This would be the largest decrease in emissions ever recorded – nearly six times larger than the previous record drop of 400 million tonnes in 2009 that resulted from the global financial crisis.
“Resulting from premature deaths and economic trauma around the world, the historic decline in global emissions is absolutely nothing to cheer,” said Dr Birol. “And if the aftermath of the 2008 financial crisis is anything to go by, we are likely to soon see a sharp rebound in emissions as economic conditions improve. But governments can learn from that experience by putting clean energy technologies – renewables, efficiency, batteries, hydrogen and carbon capture – at the heart of their plans for economic recovery. Investing in those areas can create jobs, make economies more competitive and steer the world towards a more resilient and cleaner energy future.”
By: Michael Stoppard, chief strategist for global gas, IHS Markit
The COVID-19 pandemic has led to lockdowns across the globe and severe downgrades for short-term macroeconomic indicators. A major re-evaluation is needed for the supply and demand of each traded commodity and LNG is no exception.
It is clear that natural gas demand will be negatively affected, overall. But IHS Markit expects LNG demand to show impressive resilience. IHS Markit has downgraded our estimate for total LNG demand in 2020 by 14.4 MMt—or 3.8 percent relative to our ‘pre-COVID outlook. Nevertheless, IHS Markit expects LNG demand to still register a slight annual increase with 2020 volumes projected to be up 4.4MMt year-on-year. LNG demand has risen each year since 2012.
It is pipeline gas more than LNG that feels the full brunt of reductions in gas demand. The price of pipeline gas is often less directly linked to oil price movements than LNG because of time lags and other formula in long-term contracts. IHS Markit projects that overall gas demand in the main LNG importing markets will decline 4 per cent relative to 2019. However, approximately two-thirds of the demand reduction is expected to come from reduced pipeline supplies (primarily in Europe). Another one third is expected to come from reductions in indigenous production.
Just how competitive LNG will be relative to other sources of supply varies from region to region and depends on the composition of supply.
Key Insights on LNG Competitiveness by Region:
Europe sits at the intersection of a strong global LNG supply push and a local gas demand collapse. Gas demand has been revised down from 550 to 497 Bcm for 2020. Nevertheless, IHS Markit continues to project rising and record levels of LNG imports in 2020. In the first quarter, LNG had already seen record volumes and pipeline supplies were down. This trend away from pipeline supply will continue as buyers are opting to receive less pipeline gas as allowed by their contracts and instead favor low priced LNG.
Mainland China’s gas demand for 2020 has been downgraded from 327 Bcm to 312 Bcm. Despite weak oil prices, gas pipeline contracts from Central Asia are expected to be the most expensive source once delivered to demand centers on the Chinese coast and are expected to take the biggest hit. Russian pipeline supplies from the north through the Power of Siberia pipeline can supply the northeast more competitively and are still expected to ramp up as planned. Space remains for LNG imports to increase 2.5 MMt in 2020.
India is often seen as a potential absorber of low-cost LNG, especially now that there is surplus regasification capacity. However, the economic impact of COVID19 and lockdowns now makes this unlikely in the next couple of years. New indigenous production is still forecast to come on in the middle of the year which is unlikely to be shut in. LNG volumes may decline modestly.
Competition between pipeline and LNG will play out differently across Southeast Asia. In Thailand, for example, the bulk of reduction in supply is likely to be from piped gas since it is more expensive compared to LNG. By contrast, in Singapore LNG demand in 2020 is likely to be at minimum contracted levels, with some additional spot.
In Latin America we expect that low LNG prices and lower hydro reservoirs has the potential to increase the cargoes to Argentina and Brazil. Bolivian pipeline prices will struggle to compete with the low LNG prices. In Brazil specifically, reduced imports of Bolivian gas in the Northern region and newly inaugurated regasification capacity open a space for increased LNG volumes.
In Mexico, LNG imports have been substantially reduced owing to fierce competition from U.S. gas flowing through new pipelines. LNG still has a narrow stronghold in stranded areas in the West where U.S. gas cannot yet reach because of pipeline project delays.
As the number of new cases of coronavirus starts to slow across Europe, many countries are reviewing their current restrictions. In many cases, lockdowns have been extended, but there are also moves to ease restrictions in some markets.
As a result, while milder weather and an oversupplied market are still putting gas demand under significant pressure, signs of demand recovery are slowly emerging.
Murray Douglas, from Wood Mackenzie’s European gas team, said: “The full impact of coronavirus on gas demand will depend on the length and depth of lockdowns and restrictions. If current coronavirus restrictions persist for three months, we now estimate that 17.6 billion cubic metres (bcm) of demand will be lost across seven of Europe's largest gas markets: Germany, UK, Italy, France, Spain, Netherlands and Belgium.
“This compares to a pre-coronavirus full year gas demand forecast of 371 bcm in 2020 for these markets, which together account for 70 per cent of European gas demand.”
Italy was the first European country to impose strict coronavirus containment measures. A country-wide lockdown was implemented on 10 March, followed by closure of non-essential services from 12 March with non-essential industry closing from 23 March.
Italy is forecast to experience Europe’s largest loss of gas demand as a result of the outbreak – reaching 4.4 bcm under three months of lockdown.
However, while the nationwide lockdown has been extended to 3 May, some small retailers have re-opened and some manufacturing has returned.
Douglas said: “Our analysis already shows a clear rebound in gas and electric demand over the last week – though still well below pre-coronavirus levels. Of course, the lasting effects of a weaker Italian economy will still have to be factored in even beyond the lifting of lockdown.”
He added that demand is down across Europe, to varying degrees.
“In Germany, Europe’s largest gas market, industrial demand initially proved relatively resilient. However, this has lost momentum since country-wide social distancing restrictions and lockdowns in some states were introduced. Overall, demand is set to drop by 3.5 bcm if the current restrictions last for three months.
“In the UK, the second-largest gas market, electricity demand has reduced by 14% since the start of the lockdown. As coal is uncompetitive in this market, lower electricity demand poses a disproportionate risk to gas. We currently expect 2.6 bcm of lost gas demand if the lockdown lasts for three months.
“Gas production in Europe has not yet been significantly impacted by the spread of coronavirus.
“European gas producers have delivered only minimal adjustments so far.
“Supply changes have been driven by other factors, including legacy decline and mild weather.
“Operators are focused on limiting the impact of the virus on production by delaying non-critical maintenance and adapting workforce patterns so that they can continue producing,” he said.
However, with European hub prices remaining low, some operators will face challenges in covering even their short-run marginal costs. For now, some of Europe’s legacy pipeline suppliers are falling below 2019 levels.
Douglas added: “By the end of March, Europe had a record 57 bcm gas in storage, further weakening an already oversupplied summer market. Attention is turning to Ukraine’s gas storage facilities as a potential solution. Additionally, we are likely to see increased pressure on LNG suppliers to the European market – most notably from the US.”
U.S. oil production of at least 300,000 oil barrels per day (bpd) will be shut during May and June, according to a Rystad Energy analysis of early communication from US oil producers.
It is unclear how much of this is due to the Covid-19 pandemic and the related drop in demand, but one thing is certain: more production is likely to be taken offline due to the low oil prices.
Analysing communication by Continental Resources, Cimarex Energy, ConocoPhillips, PDC Energy, Parsley Energy and Enerplus Corporation, we estimate that oil production cuts in May and June 2020 could amount to 300,000 bpd, an increase from about 100,000 bpd of cuts projected for April 2020.
Several producers have specifically mentioned production declines as a result of well shut-ins, while others did not specify whether production curtailments would come naturally as a result of a reduction in new wells put on production, or from shut-ins of already producing wells.
Rystad Energy currently estimates that shale producers will try to deliver on announced cuts as much as possible by reducing the number of new wells put into production. Thus, base decline could provide a material portion of the reported cut. However, given typical shale operational patterns, the decline in started jobs that began in March will result in a lower number of wells put on production in May, which ultimately will not lead to a drop in peak production until June.
Therefore, given the severity of the current market situation and the significant production curtailments announced already in April, shale producers are also likely to implement well shut-ins to bring the market into balance.
Continental Resources (CLR) stands out as having taken the most drastic action thus far. We expect about 69,000 bpd in reductions from Continental in April, followed by a cut of almost 150,000 bpd in May and June 2020. More companies are likely to follow with similar actions over the next few weeks.
ConocoPhillips (COP) is another large producer that has recently announced significant production curtailments across its portfolio in the Lower 48. The company mentioned 125,000 barrels of oil equivalent per day of gross output will be curtailed during the month of May. This is estimated to amount to around 60,000 bpd of oil net to the company.
As with Continental, the Bakken play is anticipated to be one of the primary regions for production cuts. ConocoPhillips also said it would be addressing the need for production curtailments month-by-month, hinting that cuts could easily be prolonged into the future. We currently estimate that a similar level of production curtailment might be enacted in June as well.
Cimarex Energy has elected to cut its May output by 30% or around 27,000 bpd due to the weakness in realised prices. Similarly, PDC Energy plans to reduce its May and June output by up to 30% as a result of production curtailments. The company also assumes that a certain level of reductions will be maintained in the third quarter and eliminated by the fourth quarter. The production cut for PDC Energy is thus estimated at 27,000 bpd in May and June 2020.
Even though Parsley Energy (PE) has not provided a clear statement on how much it plans to curb production over the next few months, its chief executive officer Matt Gallagher mentioned in early April that the company has begun to shut in 400 “lower-producing wells” in response to current market conditions. We estimate that such shut-ins could account for about 20 per cent of Parsley Energy’s output, or 22,000 bpd from April to June.
Finally, Enerplus Corporation (ERF) said it started to temporarily shut in selected wells across the Williston basin. The company's April production is expected to be modestly impacted by shut-in activity, but Enerplus currently expects to shut in more production in May in response to weaker oil pricing. We thus expect cuts to at least double in May and June.
“The estimated cuts from companies which have already made statements will be spread across the Lower 48 states, but production in the Williston basin will likely be affected the most. The Bakken play accounts for a high share of combined output, closely followed by Permian Delaware. Yet given the single-digit wellhead prices seen in the region recently, and overall commerciality, the shut-ins in Bakken are likely to be more pronounced,” says Rystad Energy’s vice president North American Shale and Upstream Veronika Akulinitseva.
Another key Bakken producer, Whiting Petroleum, recently filed for Chapter 11 and we anticipate its oil production could decline more quickly than previously assumed.
Digital transformation of new and existing pipelines using modern edge controllers provides rich new data access helping users improve operations says Denka Wangdi, Emerson
For industrial use cases, the concept of digitalisation often goes hand-in-hand with the term industrial internet of things (IIoT). IIoT includes all manner of smart digital devices that store critical data locally, including “edge controllers”, which are able to monitor conditions, communicate to other systems, and even perform control.
Edge controllers are the modern answer for providing reliable industrial control and enabling modern IIoT-capable data communications. Pipeline operations are ideal candidates for this type of digital transformation.
Pipelines ready for change
Pipeline projects over the years have typically implemented the programmable logic controller (PLC), remote terminal unit (RTU), and supervisory control and data acquisition (SCADA) technologies available at the time of installation. Many pipelines have been updated incrementally as the originally installed versions of these technologies became obsolete.
But over 50 per cent of pipelines operating today were installed in the 1950s and 1960s (Reference 1). With so much legacy hardware out there, signiﬁcant and useful data is often trapped in remote locations, waiting to be freed up and acted upon. Not only is the data difficult to attain, but the accuracy of the data is also questionable since previous pipelines weren’t equipped with condition monitoring equipment.
When the opportunity arises to update pipeline automation, or to perform a new design, end users need to preserve the robust operating characteristics of existing systems while taking full advantage of the latest digital transformation opportunities. Additionally, they would like to future-proof their systems to the greatest extent possible. Edge controllers are the answer for meeting these challenges, while providing additional beneﬁts.
Edge controller solutions
Modern edge controllers are robustly packaged, and they physically appear to be much like traditional PLCs and RTUs (Figure 1). The difference is that an edge controller incorporates a real-time operating system (RTOS) for deterministic direct control—much like a PLC or RTU—and adds a general-purpose operating systems (OS) like Linux for performing advanced computing and communication tasks. The RTOS and general-purpose OS are completely independent from each other in hardware and software, but they can be conﬁgured to carefully and securely interact with each other using industry-standard OPC UA communications.
The RTOS portion of an edge controller can easily accommodate any traditional control logic. In fact, users can simply use an edge controller as a PLC replacement, reserving the more advanced capabilities for future implementation. However, the real beneﬁts of digital transformation are realized when the general-purpose OS is brought into play.
Extensive process data can be gathered, stored, and analysed right in the general-purpose portion of the edge controller. Advanced algorithms and logic can be executed, with results securely transmitted to the RTOS portion of the controller as needed to implement responsive low-latency control.
Or, the general-purpose OS can securely communicate information up to supervisory systems for further evaluation. The general-purpose OS is provided with modern developments lacking in many conventional components, such as a ﬁrewall for security. Furthermore, it is equipped with IT-aware communication protocols like MQTT, which are optimal for the low-bandwidth telemetry connections usually available to pipeline operations.
Expanded access to digital intelligence, whether peer-to-peer in the ﬁeld or up to an on-premises or internet-based cloud, helps operators make better decisions and work collaboratively, representing a cultural beneﬁt delivered by digital transformation.
Edge controllers are well suited for meeting many other pipeline-speciﬁc challenges. Because of the all-in-one nature of edge controllers, end users can enhance basic control schemes with closely integrated on-board visualization options. Operators and maintenance personnel beneﬁt from the detailed operational and diagnostic information made available this way.
Leak detection and corrosion monitoring are key operational challenges faced by pipeline operators, who need to be informed of these situations in a timely manner, while avoiding the expense of deploying personnel if there isn’t actually a problem. Edge controllers can provide the information necessary for good alarm management to address these and other issues.
Some of the latest instrumentation systems for these conditions can provide extensive data—which can only be acted on responsively if the information is communicated up to the operations and maintenance team. Edge controllers connect to these sensing systems with traditional I/O wiring, or with more advanced serial or network communications, and act as the gateway for this information. They also perform data logging to identify slow-moving changes trending toward a problem, and carry out other preprocessing, such as ﬁltering, to minimize the chance of false alarms.
From an operational standpoint, surge control can be a big issue for many pipeline operations. Edge controllers make it possible to improve the situation by enabling each local controller to better interact with upstream and downstream stations, and to responsively coordinate operations with a central control room. With more data and computational power available, users now can implement advanced surge control automation schemes.
The New or Retroﬁt Digital Transformation Answer
The ﬂexibility to apply edge controllers to any new or existing pipeline automation system is important in many applications. Edge controllers can improve upon classic PLC and RTU implementations by adding to basic control functionality with integrated monitoring, data processing, and visualization features. Additionally, edge controllers can be seamlessly added to existing automation systems to add IIoT capabilities without disrupting current operations.
Pipeline operators are becoming aware of the beneﬁts offered by digital transformation, but they may be cautious about how to proceed. Edge controllers are a logical step to bring IIoT advantages into any operation while preserving existing investments. Using edge control devices and IIoT concepts, end users can solve many problems and improve pipeline operations.
Reference 1: Guest Post. (2016, December 20). Over 50% of the nation’s pipelines were constructed in the 1950’s and 1960’s. Retrieved on
1/13/2020 from https://www.valuewalk.com/2016/12/50-nations-pipelines-constructed-1950s-1960s/ .
This feature appeared in the April issue of Pipeline Magazine
Nadia Saleem writes about why diversity in the workforce is of paramount importance in the current market condition as companies look to cope with crisis management, capital spending cuts and diminished demand
As the energy industry looks to cut costs, jobs and delay projects to cope with the current low oil price exacerbated by the diminished demand due to the COVID-19 outbreak toll on economies around the world, the signiﬁcance of a more diverse and inclusive workforce becomes increasingly important.
According to diversity studies done by Boston Consulting Group (BCG), diverse companies are 35 per cent more likely to beat industry, 10 per cent most inclusive large companies show 2.3 times greater cash ﬂ ow per employee, most diverse companies derive more than 36 per cent more revenue from innovation than the least and companies in top quartile for women board members outperform those in bottom by 66 per cent on return on invested capital.
Jarand Rystad, CEO of Rystad Energy said in an interview with Pipeline Magazine: “Any management team more equally represented would be a better management team in terms of operations and business development.”
He said that oil and gas is still a very male dominated industry that has struggled to attract and retain women.
However, he said there are examples of exceptions. “In Norway, which is a big oil nation, we have 2-3 upcoming energy companies that have female leaders – this are a big inspiration for younger women. But still there is a long way to go from the recruitment and development perspective,” Rystad said.
In the Middle East, which is an important petroleum region, there is even less of a gender balance, with the exception of a few countries, he added, which could partly be the reﬂection of the local culture.
Although there have been moves from energy companies towards building a more diverse culture, it has not met targets and more needs to be done, analysts say.
Shelly Trench, managing director and partner at BCG says diversity is not only a social obligation but a business imperative.
“We have seen progress –the percentage of women within the workforce has increased signiﬁcantly, with leading companies such as BP, Petronas and Shell having around 30 per cent women in the workforce. Within the region (Middle East), a few ﬁrms are recognised as having best practices of strengthening the female workforce in oil and gas globally with around 30 – 50 percent. However, there is more that can be done as the general range of female workforce within the region is around 5 – 10 per cent.”
Although the region overall is not achieving the set targets, within the last 12 months there have been signiﬁcant steps taken by players to make a more diverse workforce, she said.
David Clark, group energy director at Lloyd’s Register said that as an industry, everyone needs to try harder to improve the workforce diversity.
“We are getting better and I think part of the opportunity is not only in terms of diversity in gender, but also greater diversity in culture and thinking. We have already seen how this can be improved by moving people around different regions and bringing in fresh perspectives to geographic areas. By connecting teams across multiple regions, we can see the diversity of thinking and broader creativity that can be brought to bear on the daily challenges we face in any one region,” Clark said.
In order for companies to achieve set targets or to even begin to hold diversity a matter of signiﬁcance, high-level consciousness needs to prevail.
“We need a very conscious effort from the board to search for and recruit women at middle and top management level to achieve a gender balance, said Rystad. “We can make the management conscious on processes, because we have unknown biases that very often impact hiring and promoting decisions.”
Meanwhile, BCG’s Trench laid out a few key action points;
“Companies need to mainstream diversity and become transparent about targets to align themselves with international benchmarks. Within the region, because most companies are not listed, there is little transparency on details of workforce diversity. Without performance based reports, we don’t move ahead, she said, while highlighting the below points;
- Critical mass needs to be sought in all businesses – not only the support functions such as HR and ﬁnance. Focus on diversity and inclusion as a corporate strategic priority with the board and executive committee. This cannot be owned by HR only.
- Use technology or AI to eliminate bias from decision-making when it comes to recruitment
- Use allies and sponsors to support women’s network, such as where men are encouraged to take up parental leave and have ﬂexible working policies. Best practice companies are offering global parental leave policies for secondary caregivers: 4 weeks in companies like Bloomberg and DuPont to 26weeks in others like Volvo and Facebook.
- Provide career support for women, which can come in the form of sponsors for high potential staff, which includes advocating for employee advancement.
Lloyd’s Register’s Clark said we need to do more in terms of communicating the range of opportunities and activities that we have in the sector; the types of jobs that we have to do and the environments that people work in.
“A large part of our workforce has been able to develop a fulﬁlling and rewarding career without ever having to go to work in coveralls or ﬂ y out to a rig in a remote location.
We need to leverage the broader proﬁle of our global business, and take time to engage with different areas and different sectors to promote what we do, how we work and, in our case, why Lloyd’s Register is unique as a business. We need to explain why our culture, values, purpose and intent make us different to our competitors, and how as a business we need the new talent and new skills to help us develop the solutions needed for tomorrow,” he said.
Additionally, when going out to market looking for new talent, we need to turn to different sectors, he added. “For example, we recently brought in a new ﬁnance director who has come from the infrastructure industry, so she has no direct experience in oil and gas, or the wider energy sector. We took time to ﬁnd someone with the right proﬁle for us now, which included a different mix of experience to bring into the team, because we believed it would help us to grow successfully in the future,” Clark said.
Investments to improve diverse culture
BCG’s Trench said if companies were to focus investments on the subject, these should go into leadership time and visible commitment.
“This should be a strategic agenda of the leadership team just like any other priority.
In order to ensure they understand the importance of diversity, CEO involvement is necessary. Where companies are not involving CEOs, diversity shift does not happen,” she said.
Additionally, she said companies can make monetary investments on critical infrastructure and program. Different investment can be made depending on the maturity of company - this should be a company-speciﬁc strategy, not industry wide as different companies have different diversity requirements, she added.
The COVID-19 pandemic has ravaged global oil demand and, coupled with the extremely low price levels brought on by the wide supply surplus, is likely to cause the largest monthly drop in fracking activity ever recorded in the US, a Rystad Energy analysis shows.
We estimate that the total number of started frac operations will end up below 300 wells in April 2020; close to 200 in the Permian and less than 50 wells each in Bakken and Eagle Ford. This translates into a 60 per cent decline in started frac operations between the peak level seen in January to February 2020 and April 2020, as the majority of public and private operators implement widespread frac holidays.
In March we observed an extreme 30% monthly decline in the number of started frac jobs in these three major oil basins, a fall from 807 in February to just 550. Also, nationwide fracking activity, on a completed jobs basis, might have already declined by around 20% in March 2020, according to our estimates.
“With such a rapid decline in fracking already visible, very little activity will be happening in the oil basins during the remainder of the second quarter of 2020. The natural base production decline, which we have seen as an absolute floor for production, therefore becomes an increasingly relevant production scenario,” said Rystad Energy Head of Shale Research Artem Abramov.
If we assume that no new horizontal wells are put on production from April 2020 onwards, total LTO production will decline by 1 million barrels per day (bpd) by May, 2 million bpd by July and by 3 million bpd by October to November, with the Permian Basin accounting for more than half of nationwide base decline.
US light oil operators, which are now announcing voluntary production curtailments, will try to deliver on these cuts as much as possible from the natural production decline, as opposed to shut-ins of producing wells (though some of the marginal, least economic volumes are being shut in, too).
The magnitude of the base decline for U.S. LTO sounds extreme in the context of what we see for other supply sources globally. But ironically, the steep decline is actually too late to save prices; despite the oversupply issue, standard operation patterns prevent operators from simply turning the faucet off. These days Permian wells require about two months from the moment frac operations start until they produce first oil, and require about three months before they reach peak output.
Hence, the decline in started jobs which began in March will result in a lower number of wells put on production in May, which ultimately will lead to a drop in peak production in June if normal operational patterns are maintained.
“On the demand and storage side, the market is already moving through its toughest challenge yet, and the WTI front-month sell-off emphasized how broken the physical market might be already. We are therefore concerned that significant production shut-ins will be required in the next few weeks to bring the market into the balance in a brutal manner,” added Abramov.
In addition to our standard analysis of frac activity, based on incomplete FracFocus reporting in recent months and empirical reporting delay adjustment factors, we are now rolling out a brand new way of filling the gaps left by official reporting. We have begun using satellite data to systematically monitor more than 40,000 permitted and drilled locations across the US, continuously identifying the presence of any activity taking place.
Our methodology is based on monitoring the equipment intensity on each pad or permitted location and then analysing the evolution of this intensity over time to identify the main pre-production activities in each well life cycle, from pre-spud to main drilling and fracking.
Wood Mackenzie’s latest research shows that up to 150 gigawatts (GW) of wind and solar projects across the Asia Pacific could be delayed or cancelled over the next five years (2020 – 2024), if the coronavirus-led recession extends beyond 2020.
This is equivalent to pushing back the Asia Pacific renewables construction pipeline by nearly two years.
Wood Mackenzie research director Alex Whitworth said: “The extent of the coronavirus impact on Asia Pacific markets is key to the future growth of the renewables sector.
“Over the last five years (2015 – 2019), the Asia Pacific region accounted for over three-quarters of global power demand growth, while leading the world in wind and solar capacity installations.
“The coming months will be crucial to determine if the region is moving towards a rapid recovery or extended recession future.
“Key indicators to monitor include power demand growth, credit terms for renewables projects, cost competition between renewables and fossil fuels and government support including stimulus for renewables markets.”
Wood Mackenzie projects that a two- to three-month power demand disruption with strong recovery would lead to 380 Terawatt hour (TWh) of power demand lost in Asia Pacific this year. However, if the coronavirus is not brought under control and markets go into major recession, approximately 1,000 TWh of demand could be lost by 2023. This is equivalent to about two years of growth in the region.
Prior to the virus outbreak, global investors had been active in Asia Pacific renewables projects, offering developers access to cash at competitive rates of interest. However, if the coronavirus outbreak evolves into a financial crisis, funding may be harder to secure, leading to reduced competitiveness of renewables.
Whitworth said: “In our base case outlook, the impact on wind and solar installations in 2020 can be offset by stronger growth and support policies in 2021. But if the situation worsens, renewables projects in Developing Asia* could be heavily impacted by increased financing costs, as well as forex risk due to high capex share of costs. A 10% increase in weighted average cost of capital could lead to an 8% increase in levelised cost of electricity (LCOE) in renewables.”
Another factor determining the competitiveness of renewables is the comparison of the LCOE of renewables vis-a-vis fossil fuels. While generation costs of new solar and wind plants across the Asia Pacific have fallen by 54% and 29% respectively in the last five years, Whitworth said that in a recession scenario with lower fossil fuel prices, renewables would only become competitive with coal-fired power plants in most of the Asia Pacific beyond 2025.
He added: “This is where government support is important. China and other key governments have strongly supported renewables with subsidies and preferential dispatch policies leading to massive growth in installation projects over the last five years.
“But as the scale of renewables investments grow, governments have begun to lower or cancel subsidies and expose renewables projects to market forces. Given the potential impact of the coronavirus outbreak, governments may need to rethink the timelines for withdrawing support, and the timing of energy transition plans.”
By April 2020, in response to the coronavirus, some governments have been willing to extend subsidies for delayed wind and solar projects. For example, Vietnam’s Ministry of Industry and Trade proposed a two-year extension of FiTs for wind to 2023, while China is discussing extending subsidies beyond the 2020 planned cut-off. However, these policies are likely to affect the existing project pipeline rather than new projects.
Whitworth said: “In an extended recession scenario, we expect governments to become overwhelmed with more pressing economic priorities, making it difficult to support the renewables sector with stimulus measures.
“There will be limited support for investment in the power sector because of overcapacity caused by demand slowdown. Governments could also take actions to control energy markets and prices which would impact profits and cashflow of power assets.”
*Developing Asia refers to India, Vietnam, the Philippines, Thailand, Indonesia, and Malaysia.
Nandakumar Premchand, director at GlobalData, gave his view following the news that the West Texas Intermediate (WTI) May futures nosedived 300 per cent to as low as almost negative $40 in early trades on 20 April 2020.
"This being the last day of the expiry of the May futures, ETFs such as US Oil, other fund houses and traders were forced to liquidate their positions.
“COVID-19 and its containment measures across the globe have meant that the demand for oil has gone down by 30 per cent. Though OPEC+ decided to cut production by 10 per cent by 9.7 million bpd, that will only take effect in May. Saudi has already lined up shipments for the United States. Given this and the storage space in the US fast filling up, we are looking at massive storage issues in the months to come.
“The WTI June futures were trading at around US$22. Taking note of the fact that ETFs like the USO will not take a physical delivery of oil, the strategies adopted by traders for the June expiry will be closely examined. With many feeling that the 10 per cent production cut wasn't enough in the current times, it will be interesting to see if there are further production cuts or if the FED intervenes in some fashion to douse the fire.
“Oil prices at these levels and the lack of demand will mean that we could be looking at pandemonium next month, especially if the lockdown extends beyond May. With companies signing up for floating storage tankers globally to store excess oil, even this option will cease to exist shortly.”