By: Denis Voloder, head of Onshore Solutions, Siemens Energy
With the upstream oil and gas industry afflicted by low prices, declining margins and stiffer competition, further exacerbated by the coronavirus pandemic, firms are urgently seeking operational and capital expenditure efficiencies. The companies that are successfully able to adopt and integrate holistic digitalisation solutions, utilising the power of data and advances in Internet of things (IoT) technologies, will emerge from the crisis stronger, leaner and more capable.
With greater application of digital solutions, together with the incorporation of mined data generated from existing infrastructure, oil and gas producers can facilitate the implementation of remote operation capabilities, significantly streamlining processes.
The benefits attributed to remote and unmanned operations include increased reliability and availability of assets, better production efficiency and energy efficiency as well as increased Environmental, Health and Safety (EHS). These are achieved through increased automation, real-time monitoring, real-time intervention, and through the analysis of historical data and trends.
Oil and gas companies have long seen the value in technology and digitalisation and these have proved to be important in advancing data analytics and advanced operational intelligence. But, the key challenge for companies have generally been the lack of commitment to adopt and fully utilise new technologies. The industry has traditionally been conservative, risk-averse and slow to adapt to change, particularly at low points in oil price cycles. This often leads to a lack of systematic implementation and instead a piecemeal approach in technology adoption, resulting in complexity and inefficiency. Rather than using one unified, holistic solution, companies often rely on a diverse array of tools and programs, which are loosely integrated, hindering clear and concise interpretation of data, impeding decision-making and hampering performance.
The successful exploitation of digitalisation to optimise the entire value chain and manage ecosystems, will likely be a key determinator for companies’ survivability in the oil and gas space as CAPEX and OPEX is rationalised amid low oil prices. This requires the ability to marshal a system of numerous diverse, dispersed, complex, interrelated mechanical and digital assets, as well as the ability to transfer data over a network without requiring human-to-human or human-to-computer interaction.
This complexity enables thousands of manual operations to be distilled and refined into a small number of automated processes, managed remotely and with the touch of a button. The potential cost and time savings are immense. Upstream operations and maintenance are among the largest expenses for oil and gas companies. Automating manual portions of that process, like valves and pump control or field reading, can also significantly reduce safety risks, downtime and costs.
We at Siemens Energy believe that a digital transformation begins with instrumentation such as sensors and valves, connected with the equipment over processes, with a high level of automation or maintenance strategy, and concludes in an overarching intelligent view, supplemented by data analytics and protected from cyberattacks. This enables experts to remotely operate production as well as inspect and maintain facilities, securely, from control rooms on the other side of the world. These technologies are proving to be vital in the current environment, where logistics and supply chains are disrupted and severe travel restrictions and social distancing measures are increasingly the norm.
This enables the automation of processes and the implementation of remote operations, which have the potential to mitigate lost-time incidents, health hazards and keep employees safeguarded, all whilst reducing costs. Drones and other robots are increasingly moving into more operational areas, including high-risk areas.
Increased connectivity requires data sharing across equipment and command centres using reliable data exchanges, data storage (locally, or cloud based), as well as cyber security. Digital transformation will require organisations to implement a focused digital strategy. It will also need investment and commitment to revisit and revamp processes, infrastructure and systems; and a willingness to collaborate across the ecosystem.
But, with all this connectivity, organisations face an increased volume of targeted cyber-attacks, malware and ransomware. Due to the strategic importance of the oil and gas industry, companies need to make sure that people – whether they’re contractors or employees - are aware of the cybersecurity vulnerabilities and the processes they need to follow.
For operators, integration of assets means more efficient production optimisation. A universal platform with dashboards and easy to use visualisation is a prerequisite for adaption by a large community in any organisation. Any authorised user can see the exact current state of operations on their desktop or mobile device. With training this allows anyone, from senior management right through to operators, to gain insights about the status of assets and optimization potentials.
The initial CAPEX and training required to build and operate such systems can appear daunting, but the plethora of benefits are easily justifiable. Furthermore, investment and implementation paves the way for when, hopefully in the not too distant future, CAPEX budgets are increased, meaning that new equipment and assets can be seamlessly integrated into a fully digitised oil and gas value chain.
To maximise benefits, integration should be as comprehensive as possible. This means existing assets need to be integrated and although this is typically more challenging, due to the large number of legacy systems each with its own different data definitions, advantages are still available. The incorporation of machine or plant data, into operations and systems analysis, can turn the information into a competitive advantage. The deeper the integration, the better the outcome.
The post COVID-19 world will continue to be characterised by economic uncertainty, ongoing disruption to logistics and supply chains, and low oil and gas prices. Ultimately, the accelerated adoption of digitalisation, technology and remote operations, presents oil and gas companies with a quick and effective way to reduce their OPEX whilst enhancing operations.
This op-ed first appeared in the August issue of Pipeline Magazine
The coronavirus pandemic has already had far-reaching consequences for global energy demand. Lockdown measures imposed around the world shuttered businesses shuttered and severely curtailed freedom of movement. The impact on consumption of fossil fuels and power demand was immediate.
As lockdowns began to ease around the world, demand started to recover. But, the risk of a second wave of coronavirus is increasing, and with it, fresh lockdowns appear likely. These could deepen the global recession.
What would a new wave of lockdowns mean for oil and gas markets? And what are the implications for industry stakeholders?
Dulles Wang, director, Americas gas research at Wood Mackenzie, said: “Our H1 2020 outlook anticipates an oil price rebound as demand starts rising post-coronavirus. However, a second large-scale lockdown would deepen the recession, and possibly delay any rebound in GDP until 2022. This would have a significant impact on the oil and gas sectors.
“In our base case forecast, Brent rises to US$86/barrel annual average in real terms by 2030. In a coronavirus-lockdown second wave (CSW) scenario, this falls to US$70/barrel.”
Wang said that global gas demand has proved to be relatively resilient this year. As lockdowns began to ease, demand began to recover relatively swiftly. But this recovery is inextricably linked to the economic outlook, and a second wave would take its toll.
He said: “Our Global Gas Model Next Generation (GGM NG) shows that a second wave of large-scale lockdowns would result in global gas demand reducing by 4.5 per cent in 2020 (vs 2019).
“Global LNG demand would also fall, putting further pressure on Europe to absorb the LNG oversupply – and causing further delays to LNG projects under construction.
“Pre-FID projects could become even more challenged as the need for new LNG supply could be stalled.
“Low-cost gas production - namely Russian pipeline gas in Europe and Qatari LNG - would be a key driver for prices.
“In North America, LNG under-utilisations could become a recurring theme, with full utilisation not expected until the end of 2020s.
“However, supply flexibility between associated and dry gas plays would absorb much of the demand shock from lower economic activity level.
“Some parts of the supply landscape, such as production from dry gas plays, could be surprisingly unscathed coming out of the second wave of lockdowns.”
He added that fresh lockdowns could prompt a further decline in North American domestic demand, led by the industrial and power sectors.
As power demand is price sensitive, rising gas prices post-2022 are likely to compound the reduction in structural demand caused by lower GDP forecasts.
The energy transition is weighing heavily on industry strategy, and could deter some investment, especially as the sector grapples with tight budgets and low oil prices. Lower 48 operators, for example, were already under pressure when the oil price crashed, and many have since been under significant financial distress.
“A second wave of lockdown measures would only increase the pressure,” Wang said. “Building resilience could be more crucial than ever for many industry players. But U.S. gas producers could be better placed than most to manage this, as the lower oil price – and therefore loss of associated gas production – insulates Henry Hub prices from demand losses.”
However, the overall size of the North American gas market shrinks by 6.5 billion cubic feet per day in the CSW case as Henry Hub rebalances between supply pullback and demand and export reduction.
Wang added: “While subdued tight oil production would provide headroom for non-associated gas producers, ensuring sustained long-term profitability for lower-cost producers, one crucial question remains: can gas producers survive another year of low gas prices?”
By: Boris Ivanov, Founder of GPB Global Resources B.V
The COVID-19 pandemic has led to rising debt levels, spiking budget deficits and slumping oil prices resulting in a slowdown of economic growth and a radical surge in unemployment levels.
The IMF projected the MENA economy to contract by 3.3 per cent in 2020, the biggest slump in four decades in its World Economic Outlook report in April. It said the combined shocks of the virus and low oil prices will shave off $323 billion, or 12 per cent, of the Arab world's economy -- $259 billion of that from the energy-dependent Gulf states alone.
The current employment situation in several countries within the Gulf Cooperation Council (GCC), including Saudi Arabia, the United Arab Emirates, Kuwait, Oman, Bahrain and Qatar have been shaped by oil-based growth to support rapid economic development since the discovery of vast oil reserves in the 1930s, and their subsequent extraction and exportation. While this enabled GCC countries to generate significant wealth to modernise infrastructure, lift living standards and provide a generous social contract to their citizens, the growing level of national unemployment remains one the region’s key domestic policy challenges. COVID-19 has merely exacerbated these pressures.
With oil and gas firms already registering a 19 per cent drop in demand for additional employees in the Middle East, we explore some of the tactics and policy shifts designed to support the labour market and aid its recovery.
A challenging landscape
The labour market predicament in GCC countries is characterised by several features; high youth unemployment, low female participation amongst GCC nationals and critically, the fact that foreign labour constitutes most of the workforce.
This imbalance is the result of GCC countries being largely dependent on expatriates to underpin their booming oil economies for several decades. When oil prices fell in the 1980s, GCC leaders realised the crucial need to shift from oil dependent economies to diversified economies. However, this caused yet greater dependence on expatriates, as most GCC nationals preferred to work in the public sector due to its superior employment conditions, causing expatriate employment to rise and eventually account for three-quarters of the total workforce.
To combat this, in recent years, GCC governments have formulated labour market reform strategies to create sufficient employment opportunities for nationals in the private sector, limit dependence on expatriate labour and increase workforce participation. For example, in 2019, Oman blocked foreigners from working in more than 80 job categories. In the same year, Saudi Arabia reserved employment to nationals in several retail and hospitality sectors. GCC governments also enacted taxes and fees to turn foreigners into new sources of revenue, including the establishment of road rolls, excise taxes on alcohol and tobacco and visa renewal fees.
Immediate effects of the pandemic
Since the outbreak of COVID-19, tens of thousands of migrant workers have left or applied for repatriation from GCC countries. Additionally, with scant prospects of re-employment in the current climate, large numbers of highly skilled expatriates have started to return to their home countries. It is estimated that a mass exodus of foreign workers could result in the population declining throughout the Middle East, by around 4 per cent in Saudi Arabia and Oman.
Some GCC countries are using this as an opportunity to readdress their national to foreign worker balance. The UAE for example, enacted new regulations concerning redundant workforces to enable working permit transfer possibilities and gave companies the right to reduce salaries and force employees to take paid and unpaid leave. Saudi Arabia announced they will support national workers but give no support for the foreign workforce. Kuwaiti media has reported around 50 per cent of the country’s foreign workers have had their employment terminated amid calls to reduce the number of expatriates and the Government has announced that it will no longer employ expatriates in the oil sector.
Whilst it is true there is need for these countries to address their national to foreign worker balance, a mass exodus of expatriates will mean a loss of skilled workers, technical expertise and experience.
Approaches for recovery
Firms must do all they can to appear attractive to prospective employees, to bring expatriate workers back to GCC countries and to tempt nationals over to the private sector. Firms should be very aware that their attractiveness will largely depend on how people are treated now, in terms of when they exit, try to renew contracts, or how and when they receive their end-of-service payment.
To ensure they can source workers with the right skills and experience, firms may need to work closely with GCC governments to allow flexibility in a country’s rigid immigration standards, even if only for the short term.
This will need to be supplemented with attractive and secure employment packages, which may mean that policies such as increased taxes on the back of expatriates will need to be revisited or compensated by firms in other ways.
The labour markets in GCC states will experience major changes from the twin Covid-19 and oil crises. Firms will now need to work hard to offset job losses and attract highly skilled workers to ensure they are in the best possible position to withstand this latest downturn.
Policies designed to facilitate economic diversification, shift workforces away from government jobs and into fast-growing new industries outside of oil and a major overhaul of the educational system will all help to build an adaptable workforce and resilient economy.
The pandemic has brought mounting uncertainty on the real impact to millions of people employed in the oil industry. Government responses therefore need to account for the urgency of the situation while embracing short- and long-term perspectives to support economic recovery, restore balance, learn from failures, seize opportunities, and emerge stronger.
Using renewable energy to power liquefied natural gas (LNG) plants in Asia Pacific could reduce emissions by about 8 per cent, says Wood Mackenzie.
Asia Pacific produces over a third of the world’s LNG, but also generates over 50 million tonnes of carbon dioxide equivalent (MtCO2e) of emissions during liquefaction. Australian LNG projects account for over half or 29 MtCO2e of liquefaction emissions from LNG projects in the region.
Many of Asia Pacific’s LNG facilities are located in remote areas, far from the power grid. As a result, feedgas is used to generate electricity to run the plant and fuel the liquefaction process. Typically, 8% to 12% of feedgas is consumed at the plant to run these processes. Older, more inefficient plants, as well as nascent floating LNG (FLNG) vessels operate with far higher losses.
Wood Mackenzie senior specialist Jamie Taylor said: “Three main decarbonisation levers could help reduce emissions at LNG plants, namely operational efficiency, design changes, and the use of renewable energy, which could be sourced from the grid or generated onsite.”
Feedgas is used to fuel gas turbines to generate electricity to power the plant. Replacing these gas turbines with electricity could greatly reduce emissions, assuming the grid power is less carbon intensive. The other option is to install on-site renewable power, in particular solar.
Taylor said: “If a solar plant or a hybrid solar plus battery storage plant is installed at the LNG facility, back-up generators could be switched off and renewable electricity could be used to meet the power load. As costs continue to decline and technology improves, renewable plus battery storage could become an alternative in the future, especially for new LNG plants.
“We are already seeing Australian LNG plant operators examining ways to reduce carbon emissions throughout the value chain. Initiatives are underway at the upstream assets supplying the North West Shelf and QCLNG, and Darwin LNG has installed a battery that reduces the need to run one of the gas turbines.
“Our analysis shows that installing renewable energy generation could reduce emissions at Asia Pacific’s LNG plants by 8 per cent in 2020 alone.”
While LNG has clear benefits over other fossil fuels in power generation, the industry is increasingly scrutinising the emissions intensity of its upstream supply and the production process. Several industry players have set carbon neutrality 2050 targets, and there are indications LNG buyers are looking more closely at the emissions associated with cargoes they are procuring. Stricter project financing criteria, especially from European banks, is another cause for concern for companies developing capital intensive greenfield projects.
But perhaps the biggest driver for decarbonisation is the potential for carbon tax or tighter regulations in both exporting and importing countries. This would significantly impact the already strained project economics post oil price crash.
Taylor said: “A carbon tax is likely to be the biggest driver for LNG projects to switch to renewable energy at the plant or deploy carbon capture and storage to reduce emissions from upstream gas, or both.
“Using less feedgas as a fuel would result in more gas being available to supply either the domestic market or be converted into LNG for exports. Rather than increasing annual LNG output, which would only be possible by debottlenecking the plant, this ‘saved’ gas would be used to extend the plateau LNG production level by a few years. Revenues associated with the resulting extended plateau could reach into several billion dollars longer-term.
“In APLNG for example, installing 60 megawatts of solar in 2020 at a cost of US$60 million increases the remaining value of the project by US$62 million. “This is due to the additional revenues generated from selling the ‘saved’ feedgas. The relative benefits of installing solar are increased further when a carbon tax is considered.”
U.S. horizontal drilling activity in oil basins, which has plummeted due to the COVID-19 pandemic, is not likely to materially recover this year, a new Rystad Energy analysis shows.
Drilling permits, which are increasingly reliable indicators of future activity levels, dipped to a 10-year monthly low this July, with only 454 awards.
July’s drilling permits number is the lowest since September 2010, when horizontal permits in oil basins amounted to 438. But unlike the current situation, activity then was on the increase, while the current downturn is still under way. Comparing to the previous downturn, the lowest count was in January 2016, when only 622 permits were awarded.
Drilling permits have generally been viewed as low quality predictors of future drilling activity, as operators have a tendency to overbuild their inventory of permits. However, the quality of predictions based on permits has improved considerably, as producers have become more disciplined in the current capital environment and market downturn.
After a collapse in permit activity between March and May, June was the first month to see recovery in permits across all oil basins, driven by the Permian. This signalled that the decline in the rig count was bottoming out, with the outlook subsequently stabilizing in July. Permitting activity, however, slowed again in July.
“This signals the continuity of reduced activity levels throughout the remainder of 2020 at the current strip prices. Unless WTI oil prices move towards $50 per barrel in the next few weeks, a rig activity rebound is unlikely before the first half of 2021,” says Artem Abramov, head of Shale Research at Rystad Energy.
An analysis of Baker Hughes data, shows that the horizontal oil rig count in the US declined by 75% from the peak of 620 rigs in early March 2020, and has hovered around the 150-160 range since early-July. Gas-focused horizontal rigs have been flat at 55-60 over the last few weeks, 62% lower than in June 2019. The Permian Basin now accounts for 78 per cent of the total onshore oil-focused rig count, increasing from a share of 62% in February 2020.
A flat rig count absolutely does not imply that there has been no weekly changes in the total. Some weekly changes are always registered from the movement and reallocation of rigs, combined with some operators still continuing to gradually lower their rig programs (e.g. ExxonMobil in the Permian), with others restoring modest drilling operations (e.g. Parsley Energy). The extent of the weekly changes in the last few weeks, however, corresponds to normal fluctuations that are seen when activity levels are steady.
The number of active counties (i.e. counties with at least one horizontal oil-focused rig) in the US increased from 30 to 32 last week. Drilling operations were restored in the Ward, Borden and Glasscock counties (all in Texas and all within the Permian Basin). But Gonzales County in the core Eagle Ford saw the departure of its last active rig. As a result, the active county tally in the Permian increased from 13 to 16, and half of active oil-focused counties in the U.S. are now in the Permian Basin.
Libya’s oil blockade is now entering its seventh month and the war-torn country’s oil output is hovering at just 100,000 barrels per day (bpd) instead of the pre-crisis 1.2 million bpd.
Without a peaceful solution on the horizon, Rystad Energy is further pushing back its expected restart to the fourth quarter of 2020, a change that will help reduce the expected global production surplus to just 58.6 million barrels, or to about one-third of our previous forecast.
In the most optimistic of scenarios, Libya’s 2020 exit production rate will be between 700,000 and 800,000 bpd. But this estimate itself carries downside risk: once oil production comes back on line, it would take Libya another three to four months to ramp up production to hit the 1 million bpd mark.
The damage is not just limited to the short term. The prolonged blockade has negatively impacted both infrastructure and oil wells, so the eventual ramping-up of production will demand capex spending on rehabilitating wells and pipelines. For this purpose, Libya’s National Oil Company (NOC) estimates that between $500 million and $1 billion is needed just to reach the pre-blockade levels of 1.2 million bpd.
It is not only oil output that has languished. Libya’s production capacity itself has lost between 100,000 bpd and 150,000 bpd due to the ongoing blockade, according to our estimates. If this deadlock is not resolved in the next few months, we might see it dropping by an additional 200,000 to 300,000 bpd. This puts the country’s desired oil production level of 1.5 million bpd even further out of reach.
“Our latest global liquids balances report still suggests there will be a shift towards a surplus from August and for the ensuing three months, but it is less precarious than previously estimated and developments in Libya have a lot to do with this revision,“ says Bjornar Tonhaugen, Rystad Energy’s head of Oil Markets.
In July, before the change in our Libyan production forecast, we calculated the accumulated global surplus to about 170 million barrels between August and November. August’s implied surplus is now seen at just 0.1 million bpd and September’s at 0.3 million bpd. October, the month with the largest contribution to the glut, will see an imbalance of 1.4 million bpd. The surplus will then be limited to 0.1 million bpd in November, before demand takes the lead from December.
We are now also reducing our supply expectations for OPEC heavy hitters such as Saudi Arabia, the UAE, and Kuwait as we expect slower ramp-up phases given the wobbly demand recovery outlook ahead. Significant upward revisions were applied to Canada, as oil sands projects are exhibiting a rather resilient recovery in production.
Back in Libya, production at the Messla oil field resumed in July 2020. NOC unsuccessfully attempted to lift the force majeure on exports of oil and partially restarted oil production from Messla, which ramped up to 30,000 bpd (still only half capacity) and remains the only onshore producing asset. Waha Oil also reportedly restarted partial oil production from its Gialo oil field around the same time but was forced to shut down again.
If Messla remains on line in August we estimate its oil production will reach 30,000 bpd, although 10,000 bpd will go to a local refinery and the rest will go to storage. On a country level, we estimate production to be between 100,000 and 110,000 bpd. But if the deadlock continues, we believe Messla would go offline due to storage constraints and as a result, Libya’s oil production would regress to between 80,000 and 90,000 bpd, similar to the lows seen during April to June 2020.
“The force majeure has effectively taken off 800,000 to 900,000 bpd of light sweet crude from the market and is providing some relief to Brent prices which are already under stress due to the market imbalance. When Libya’s oil production comes on line, it will increase competition for the light sweet grades trading in Asian and European markets,“ Tonhaugen concludes.
Oil markets have returned to relatively stable ground with Brent prices within a narrow US$40-$45 per barrel range and could conclusively pass the $50 per barrel mark in the second half of 2021, according to Roger Diwan and the IHS Markit Energy Advisory Service.
The IHS Markit Brent price outlook has been revised upward to an average price of $42.35/bbl in 2020 and $49.25/bbl in 2021—up $7.09/bbl and $5.25/bbl, respectively, from the outlook in May.
Emerging bruised and battered from the worst of the COVID-19 outbreak, oil markets are now at a delicate pivot point as they transition to phase II of the IHS Markit Three Phases of Oil Markets Recovery.
“The record cuts set in motion in May and June by Saudi Arabia and its OPEC+ partners played a pivotal role in accelerating the improbable rebalancing of global oil markets. With demand recovering from April lows and after giving markets an extra month to find their footing, these exporters have now moved from managing the immediate surplus of the crisis towards managing the recovery,” added Roger Diwan, vice president financial services, IHS Markit.
Phase II of the recovery (the “just-in-time oil market” phase) is a delicate transition phase in which surplus inventories are worked down in parallel with rising supply as spare supply capacity returns from Vienna Alliance and North American producers.
OPEC+ and the United States are bringing back over 4 MMb/d of production in July and August. Meanwhile, the global demand recovery is showing clear signs of plateauing and Chinese crude buying has begun to soften.
Barring a large second wave of COVID-19 cases driving widespread economic shutdowns, IHS Markit expects Brent will stay within a $40-$47/bbl price band on average over the next four quarters.
This stabilisation period will make way for the more structural stage of the recovery process, wherein the progressive normalization of demand and OECD commercial stocks allows a return of most spare capacity in Russia and in the key producing countries in the Gulf. This could start as early as the second half of 2021, when Brent prices could conclusively pass the $50/bbl mark.
“The recent display of restored harmony among OPEC+ heavyweights Saudi Arabia and Russia illustrates that the strategic debate within the group over price levels and market share has time to run.
“As long as prices hold in the current range, demand concerns will likely help keep the agreement on course. When prices surpass $50/bbl, potentially lifting capital spending in the United States higher, that is when changes to the tenor of the discussion, and the divergence of interest could start to play out,” said Diwan.
Gas output from the Permian Basin is expected to rebound relatively quickly in the second half of 2020 and will remain robust for years to come, Rystad Energy projects.
However, the low-investment environment created by COVID-19 will likely postpone approvals for important key pipelines which may necessitate increased flaring from 2023 onwards.
In the second half of the year, and into 2021-2023, Rystad Energy expects Permian gas production will see a rapid boost assuming a US$45-$50 WTI environment, which is our base case. In the short-term, the reactivation of curtailments is expected to push basin-wide gas output back to 11.4 billion cubic feet per day (cfd) in September, although further growth might be delayed until mid-2021 when activity is expected to recover substantially.
Regardless, gas output in the Permian is expected to return to record levels by late-2021, reaching 16 billion cfd by the end of 2023. This represents a downward revision of 2 billion cfd compared to our 2023 year-end view prior to the COVID-19 pandemic.
There has been limited news flow on the development of new gas pipelines in recent months, but we remain confident that both the Permian Highway Pipeline (PHP), which originally announced an in-service date of 1Q21, and the Whistler project, which announced an in-service date of 3Q21, are both moving ahead.
Earlier this year, Kinder Morgan faced some regulatory obstacles which have delayed the originally planned in-service date for the PHP. Additionally, in the current environment, the regional supply-demand balance does not require the immediate completion of the pipeline. Even if modest delays occur, Permian’s dry gas production potential will be able to wait for the pipeline to be completed until late-2021. Meanwhile, the Whistler pipeline has recently received new funding, which confirms that project-related work on the pipeline is occurring.
For other pipelines, however, serious concerns about feasibility remain and many projects have been delayed or put on hold. According to an April announcement the Pecos Trail evaluation is now on hold, and the Permian to Katy (P2K) pipeline also appears to be inactive. Tellurian has continued to advertise its future global gas market hub around Driftwood LNG, the Permian Global Access pipeline, but the likelihood of any investment decisions in the short-term remains low from our perspective.
On paper, the nameplate outbound capacity of all takeaway pipelines with local consumption (assuming the completion of the Whistler and PHP) will reach 17.5 billion cfd in 2022, enough to accommodate the increasing gas production in the basin through the mid-2020s. However, the future of utilization rates on the Permian-Mexico pipelines (Roadrunner, Comanche Trail and Trans-Pecos) remains uncertain.
While the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline was finally completed and started service in June 2020, providing better connectivity between northern Mexico and Guadalajara, it might take several quarters (if not years) to see a significant increase in West Texas-Mexico gas exports, relative to the total capacity of outbound pipelines.
In May 2019 through April 2020, West Texas-Mexico gas exports fluctuated in the very narrow range of 0.58 billion to 0.67 billion cfd. The Trans-Pecos pipeline, specifically, flowed at around 170 million cfd in the first four months of 2020; only in the last few days have we recorded a jump in daily flows towards El Encino, with throughput surpassing 300 million cfd.
In the most optimistic scenario, we consider an increase in West Texas-Mexico exports to 1.5 billion cfd throughout 2H20-2021. However, in our lower case, exports remain flat at 0.7 billion cfd. Finally, in 2H19-1Q20 we frequently observed that pipelines flowed at rates exceeding nameplate capacity by up to 10 per cent. This is considered to be unsustainable in the long-term.
“Regardless of the state of West Texas-Mexico exports, we conclude that in a $45-$50 WTI world, there will be a need for new gas takeaway projects from the Permian as early as 2023-2024. If these projects are not approved early enough, the basin might end up with another period of degradation in local differentials and potentially increased gas flaring,” says Rystad Energy’s Head of Shale Research, Artem Abramov.
Given the conservative investment philosophy of midstream companies and the WTI strip remaining around $40 for the year, it is highly possible that any new pipelines will be approved too late, resulting again in a situation with insufficient infrastructure.
According to a new report by Wood Mackenzie, oil products demand in Asia Pacific is expected to fall by 1.8 million bpd year-on-year in 2020. But oil demand growth in Asia has still a long way to run. By 2040, the region’s oil demand is expected to rise by 25 per cent (9 million bpd) to 44.8 million bpd compared to 2019.
COVID-19 and a pessimistic economic outlook will have a near-term impact on oil demand and the refining sector in Asia Pacific. But in the long-run, demand continues to be robust driven by a future demand for mobility and petrochemicals. The region will account for over half of global oil demand growth by 2040.
Wood Mackenzie research director Sushant Gupta said: “Although demand continues to grow, the rate of growth in the next 20 years is less than half that of the past 20 years, primarily because of higher fuel efficiency, penetration of electric vehicles and displacement of oil in the transport sector.
“Oil demand growth is also increasingly reliant on petrochemical feedstocks, which could grow by over 5 million b/d from 2019 to 2040. China accounts for the bulk of this growth, because of an expansion in steam cracking and growth in propane dehydrogenation (PDH) and aromatics production capacities.
“So, the big challenge for refiners in Asia is to meet the growing deficit in petrochemical feedstocks. This year we will see close to 3 million b/d of feedstock shortage, but by 2027 this deficit could grow to 3.8 million b/d. Middle-East, which is a traditional exporter of petrochemical feedstocks to Asia, will not be able to meet the shortages in Asia fully, and we expect a growing reliance on imports from long-haul markets such as US and Europe.”
With a growing shortage of petrochemical feedstock and a growing demand for gasoline, Asia could also see a structural shortage of gasoline in the long run. Gasoline demand rises by close to 2 million bpd between 2019 and 2040. Unless additional refinery capacity and appropriate refinery configurations are built to focus on light-products, both petrochemical feedstocks and gasoline will continue to be short.
In contrast, as diesel/gasoil demand growth in China slows down, the region is expected to see a large surplus of diesel/gasoil, reaching 1.5 million bpd by 2027.
Gupta added: “Asia faces a dual challenge of meeting its shortages of light-products and finding export markets for its surplus middle-distillates. This imbalance means refiners need to rethink on their export markets, future refinery capacity and configurations, and the future types of petrochemical feedstocks.
“Overall, Asia’s product balances are opposite to Europe – light-distillate importer and middle-distillate exporter - so there is a natural synergy, with the challenge being their geographical separation. But, deficits in Asia present opportunities for West to East trade to grow further and meet part of Asia’s growing demand.”
To align with a shift towards petrochemicals, many refiners in Asia are moving towards a deeper integration with chemicals. Gupta added that a successful integrated site should find an optimal zone where the site is competitive for feedstock generation and for converting feedstock into chemicals.
In the long run, Asia Pacific needs more refining capacity to meet demand, but the required rate of capacity additions is expected to be half that of the past 20 years. Wood Mackenzie expects refining margins to recover in the longer term to support refinery capacity investments in Asia, but an over-build in Asia will mean more rationalisation in Europe.
Finally, as the demand growth centres in Asia shift from China to India and Southeast Asia, these regions will be required to take the lead in building new refining capacity.
Hit by the COVID-19 downturn, the oilfield service market is not likely to rebound to last year’s activity level until 2023 according to a Rystad Energy analysis. However, suppliers could diversify some oil and gas capabilities and replace up to 40 per cent of 2019’s revenue by servicing the renewable markets.
Rystad Energy analysed the activity of the top 50 oil and gas suppliers, which together earned $220 billion in upstream revenue in 2019, $100 billion of which originated from well services and commodities.
Many services provided by well-focused suppliers will be challenging to deploy in the context of energy transition operations, especially fracking services, OCTG and drilling services and tools. However, the top contractors providing engineering, procurement, construction and installation (EPCI) services – which earned around $55 billion in 2019 from the oil and gas industry – will find it easier to apply their competencies towards the green shift.
“Around $90 billion, or 40 per cent of the revenue from the top 50 players in the global service market, could potentially be replaced by energy transition projects, such as clean energy infrastructure and renewable energy production development services. However, the supply chain industry must also look to avenues outside of the energy transition to stay afloat,” says Rystad Energy’s Head of Energy Services Research Audun Martinsen.
Market opportunities abound
In terms of market opportunities, most traditional oilfield service suppliers are looking to expand into low carbon segments, meaning technologies or services aiming to reduce or prevent emissions from oil and gas extraction and production. This can be done by offering more efficient operations and digital solutions. This is a space where most suppliers, regardless of current exposure in the service market, have a role to play.
Another emerging market within the energy transition is clean energy infrastructure, where suppliers can provide services to support blue and green hydrogen infrastructure, carbon capture and storage, or energy storage in general. This is a market where engineering houses, fabricators and equipment manufacturers will find big opportunities for growth and for synergies.
A third option within the energy transition is to supply the end-to-end development and operations of renewable power generation itself, for example by developing solar power plants, wind parks offshore and onshore, and geothermal energy. The solar energy supply chain is highly fragmented and has become essentially out-of-box, yet the wind market offers great potential for offshore contractors to support the development of offshore wind.
However, the risk and investment required for expanding into other energy markets beyond oil and gas will not be feasible for all oilfield service providers.
In terms of growth opportunities, the clean energy market represents a fast-growing industry. The installed capacity of all utility-scale global renewable energy assets has doubled every fifth year since 2010, and will total 1000 gigawatts (GWAC) in 2020, comprised of 600 GWAC of onshore wind capacity, 284 GWAC of utility PV capacity and 34 GWAC of offshore capacity. By 2025, we expect this number grow by at least 50 per cent to 1500 GWAC, potentially reaching 1800 GWAC of global capacity in our high case.
Due to economies of scale and cost deflation, operator’s investment towards asset development will grow slower than capacity, but still much faster than the oil and gas market. In Europe for instance, investments in offshore wind will exceed offshore oil and gas investment as soon as 2022. Geothermal energy is also getting broader attention in the market, especially in Europe.
Mapping service relevancy
Rystad Energy has mapped out the relevance of existing oilfield service business offerings in the context of emerging energy transition markets. Within the scope of our analysis, we see that those oil and gas segments which will return to 2019 market levels by 2023 are those that are most agile – those that are able to support both the diversification of O&G offerings towards the energy transition, and at the same time, those that will continue to see high growth from traditional O&G operations.
The SURF, and the maintenance, construction and installation segments rise to the top in this regard, emerging as the most nimble service segments.
SURF represents the market for subsea cables and pipelines, and the installation of these mechanisms. As a key segment for the development of deepwater oil and gas operations, particularly the high growth markets of Brazil and Guyana, Rystad Energy believes the SURF segment will be on track to surpass 2019 market levels in 2023. In addition, SURF services will be in demand for both floating and grounded offshore wind – the fastest growing renewable energy segment.
Similarly, the skillset of the maintenance, construction and installation segment is applicable to the emerging energy infrastructure market and to renewable energy production in general. This segment is also expected to win big in as the oil and gas market recovers, as the segment has a major focus on LNG development, which many E&Ps have favoured in recent years.
The energy transition is likely to be more challenging for well-related services, such as rigs and well services, even though geothermal energy – a potential consumer of these services – is gaining momentum around the world. Geothermal projects typically are comprised of two to six wells per project. However, the 1,000 geothermal wells which might be drilled every year going forward will not be sufficient to compensate for falling oil and gas well services demand, which we anticipate will only decline from a high of the 70,000 oil and gas wells drilled last year.
Therefore, the sectors that are, by nature, less agile in shifting towards the green revolution would be wise to focus on reducing emissions by way of digitalisation and by developing automation and emissions control technologies.
By: Vinodkumar Raghothamarao, Director Consulting, Energy Wide Perspectives & Strategy, IHS Markit EMEA
Energy companies operate in dynamic and complex environments, where they face constant challenges especially in terms of supply and demand. Energy companies have been adopting digital technologies for years, helping to increase the recovery of fossil resources, improve production processes, reduce costs and improve safety. Within the offshore energy sector, the need for digitalisation and advanced communication systems is greater given the platforms’ remoteness and isolation, harsh sea conditions, strong and unpredictable winds, water, extreme temperatures, and distance from the shore The energy industry is known to be a heavy user of reliable, secure, and resilient networks for providing seamless communications for their daily operations. Routine operations alone require transmission of an insuperable volume of data and reports on logistics, supply, production etc.
Technology and innovation are at the heart of many of these efforts and in certain “pockets of excellence” are helping to reduce facility costs by 5–15 per cent, lower operating costs by 10–70 per cent, and raise production efficiencies by 5–20 per cent. Now with the oil prices low, the time has come to evaluate, adapt and embrace new technological initiatives. 5G is one of the leading communication technology initiative driving the tectonic shift within the energy industry. To date, mobile technology has progressed from a predominantly people-to-people platform (3G) toward people- to-information connectivity on a global scale (4G). 5G can leverage and extend the research and development (R&D) and capital investments made in prior mobile technologies to advance mobile to a platform that delivers the much-needed ubiquity, low latency, and adaptability required for future uses. 5G will make possible new classes of advanced applications, foster business innovation, and spur economic growth.
5G mobile networks represent the next major phase of mobile telecommunications standards beyond the current 4G Long Term Evolution (LTE) standards. 5G technology will do far more than usher in new service opportunities for mobile network operators (MNOs). Indeed, IHS Markit expects 5G will act as a catalyst that turns mobile into a robust and pervasive platform that fosters the emergence of new business models and transforms industries and economies around the globe.
Initially, 5G deployments are centering on enhanced Mobile Broadband (eMBB) and fixed wireless access applications. eMBB addresses the human-centric use cases for access to multi-media content, services, and data. In addition to eMBB, 5G builds upon earlier investments in Machine to Machine(M2M) and traditional IoT applications to enable significant increases in economies of scale that drive adoption and utilization across all sectors. Improved low-power requirements, the ability to operate in licensed and unlicensed spectrum, and improved coverage will all drive significantly lower costs within the MIoT. This will, in turn, enable the scale of MIoT and will drive much greater uptake of mobile technologies to address MIoT applications such as
Mission Critical Services (MCS) represents a new market opportunity for mobile technology. This significant growth area for 5G will support applications that require high reliability, ultra-low latency connectivity with strong security, and availability. This will allow wireless technology to provide an ultra-reliable connection that is indistinguishable from wireless to support applications such as autonomous vehicles and remote operation of complex automation equipment where failure is not an option.
MCS represents a potentially huge growth area for 5G to support applications that require high reliability, ultra- low latency connectivity with strong security, and availability, including:
5G will drive improvements across the entire oil and gas lifecycle, from upstream developments to refining operations to transportation, to real-time monitoring of assets such as drill rigs and pipelines, to remote operations and surveillance.
For instance, Houston-based Infrastructure Networks has been installing gear and building 5G capabilities as part of an effort to create the first 5G-enabled oil drilling site in the Permian Basin. Big carriers such as Verizon, Sprint, T-Mobile and AT&T are also taking measures to improve oilfield connectivity, deploying 5G to key spots in the Permian Basin and the Gulf of Mexico.
Edge computing technology can be used for remote pumping and distribution sites, connected through 5G networks to a main automation system. This helps with the monitoring and communication of pipelines to identify irregularities and discrepancies in data in real-time. Thus allowing automation control systems to respond immediately to take action against problems. While many of these sites currently have limited forms of connectivity, such as cellular or satellite, this type of infrastructure would need to be updated to handle the data volumes required for 5G.
In addition, 5G has the potential to serve several IoT use cases for the oil and gas industry like asset tracking and monitoring, gas detection and prevention, predictive and preventive maintenance, etc
Utilities can benefit from the MIoT and MCS capabilities of 5G for smart metering and smart grid automation. Currently, smart metering deployments are enabled by a range of different cellular, mesh, and wired technologies. 5G’s ability to support private networks, use licensed and unlicensed spectrum, and radio hopping/mesh renders it a flexible, multi-purpose technology for both greenfield and replacement deployments. Alongside the general economies of scale, the deep coverage and low power characteristics of 5G will enable utilities to benefit from automated meter reading (reducing the need for manual readings or inspector visits), more accurate customer billing, and fraud prevention.
There is an ongoing trend for renewable energy, such as solar or wind, to be integrated onto the grid; however, the fragmented and irregular nature of this supply makes integration complex. 5G, alongside analytics that can identify the optimal time for different sources of energy to come on to the grid (i.e., managing supply and demand), can enable automated real-time grid switching.
Using deep learning and IoT, new predicting and monitoring technologies for the oil and gas industries have emerged that could completely transform them. Being able to predict what’s coming and see beyond what’s currently seen allows companies to deal with potential problems before they happen, saving them time, money, and bad publicity. A future where we’re surrounded by artificial intelligence incorporating deep learning and IoT is imminent. Going forward, the impact of ML and AI has already been realised in the industry. Early adopters are taking advantage with a head-start in the competition to protect their assets. Tightening research and development budgets are prompting oil and gas firms and their suppliers to think differently about both how they source new technologies and where they direct scarce resources. These evolving technology approaches are likely to outlast the current downturn and could lead to real changes in companies’ overall business strategies.
This column first appeared in the July issue of Pipeline Magazine
DNV GL has launched an international industry consortium in collaboration with Dutch glass production expert company Celsian to develop the technology required for a gradual transition from natural gas to hydrogen as a fuel in energy-intensive industrial production processes.
A major challenge for energy-intensive industrial production processes, for example in the glass, food and ceramic sectors, is to make existing heating processes carbon-free. As electrification is often not an option, a fast and sustainable route to reduce the carbon intensity for industrial heating processes is to substitute natural gas by hydrogen.
“Existing burner and burner control technology to decarbonise industrial production processes are not yet market-ready, despite great interest and the advantages of hydrogen as a low carbon fuel in high-temperature industries. Our programme aims to have new burner concepts available within two years,” said Sander Gersen, project leader, DNV GL – Oil & Gas.
The two-year programme is a unique collaboration in the introduction of hydrogen as a fuel for industrial use, aiming to contribute fundamental improvements to existing industrial heating processes to make the gradual transition from natural gas to hydrogen fast and cost-efficiently.
The industry consortium comprises more than 30 private and public partners throughout the hydrogen value chain, including industrial end users, technology suppliers, fuel suppliers and traders, gas transport companies, knowledge institutes and the Dutch government.
“Together with our partners, we are looking at how we can best integrate new technology in industrial processes and hydrogen value chains. At the same time, we are gathering data and practical experience by conducting field demonstrations in various industrial environments. Right now, we are laying the foundation at DNV GL’s laboratories in Groningen. Subsequently, we will prepare for a field demonstration where the new technology is integrated into the industrial production processes of participating companies” said Johan Knijp, country manager DNV GL - O&G Netherlands.
The transition from natural gas to hydrogen
Three important principles must be considered when switching from natural gas to hydrogen. Firstly, it is crucial that product quality is not affected. Therefore, in the first phase of the research strong emphasis is on understanding heat transfer from the hydrogen flame to the product. Secondly, security of supply during the transition is important - in other words, an end-user always wants to be able to switch back (temporarily) to natural gas. Finally, the solution should be relatively easy and cost-effective to integrate into existing installations.
The programme's proposed solution to reduce the carbon intensity of industrial energy consumption builds on the fuel adaptive burner concept recently developed by DNV GL and burner system manufacturer Zantingh. Where a traditional burner is only suitable for 100% natural gas, the fuel transition adaptive burner can handle any mix of natural gas and hydrogen. An installation equipped with this new burner concept is prepared for any change in the natural gas/hydrogen mix that will be offered in the coming years while maintaining safety, reliability and low emissions.
From ambition to reality
Nationally and internationally, there is a lot of attention on hydrogen and its role in the energy transition. Both governments and private companies are investing significantly in this technology. In a recent survey of more than 1,000 senior oil and gas professionals conducted by DNV GL, one in five (21 per cent) of the respondents revealed that their organisation is already actively entering the hydrogen market, and more than half (52 per cent) expect the gas to form a significant part of the energy mix within a decade.
“Hydrogen is in the spotlight while the energy transition is moving at pace - and rightly so. But to realize its potential, both government and industry will have to make bold decisions. 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,” said Liv A. Hovem, CEO, DNV GL - Oil & Gas.
"To reach the level where societies and industry can reap the benefits of hydrogen on a large scale, all stakeholders will need to pay immediate attention to demonstrating safety, enabling infrastructure, scaling up technology and stimulating the development of value chains through policy,” Hovem added.
The first field demonstration is planned at Nedmag in Veendam (Netherlands), where magnesium salt is processed using high-temperature processes. Preparations for this test have already started. By the end of 2020, an oil stove at the plant will be to run on hydrogen obtained from the nearby Gasunie Hystock hydrogen production plant in Zuidwending.
COVID-19 has dealt a massive blow to the energy industry, and national energy companies in the Middle East must pursue bold structural cost-reduction measures to mitigate the impacts and emerge stronger from the crisis, according to a new report by Boston Consulting Group (BCG).
The report, titled ‘Procurement post COVID-19: A new reality for national energy companies’ explains how companies must act now to balance near-term supply chain management urgencies and redesign the supply footprint and supply capabilities.
BCG conducted the 2020 National Energy Operator Survey in April and May 2020 to understand the COVID-19 related supply chain challenges encountered by these companies. According to BCG findings, 75 per cent of participants have encountered supply disruptions that have impacted operations and national energy companies have taken several prudent measures to safeguard the supply chain during this time of crisis. First and foremost, many have focused primarily on supply chain de-risking – 92 percent of BCG’s survey respondents have set up COVID-19 response teams, more than 75 percent of these are already engaging with key suppliers, and close to 70 per cent have identified alternative suppliers for critical materials and increased inventory and monitoring. Secondly, most teams have initiated quick-win cash and control measures – 90 per cent of respondents are actively negotiating down prices of metal-based items as commodity metal prices fall, while 70 per cent are either considering or already working on reducing discretionary spend and repurposing existing wherever possible to defer future purchases.
“National energy companies need to consider structural cost reduction exercises. The majority of companies we surveyed have not yet initiated those changes; only less than 30 per cent of respondents are working with their functional counterparts to identify alternative materials, reduce demand, and cancel non-critical procurement,” said Arun Bruce, managing director and partner, BCG.
BCG analysis indicates that most service providers to the energy industry will likely experience cost deflations in the range of 20-30 percent over the next 12 months. This will be driven by declining demand due to steep CAPEX cuts, commodity price drop, salary/wage reductions, and financial distress within the supplier ecosystem which leads to reduced overheads and profit margins. CAPEX-related services and materials such as drilling and OCTG would see prices fall by 20 per cent to 30 per cent in the next 12 months. OPEX-related services will see marginal price declines while savings on OPEX materials including piping valves and fittings could be in the 5 per cent to 15 per cent range. However, there is an underlying need for caution since excessive bargain hunting could permanently damage the supply chain by forcing financially distressed suppliers out of business
Furthermore, as per the BCG study and analysis, the future of supply chains will be centered on three major objectives: supply security, cost efficiency and supplier innovation. To rebound and move forward, BCG has proposed five key levers that companies should adopt while pursuing these three objectives:
“Although crises are known to cause significant economic strain, they also provide opportunities for growth and companies that flourish during downturns share common traits of preparation, preemption, growth orientation, and lasting transformation,” said Cristiano Rizzi, Managing Director and Partner, BCG. “Based on the 2020 National Energy Operator Survey and our independent analysis, we are confident that the supply chains of national energy companies will recover and rebound. But in order to achieve objectives in this regard, several key levers must be utilised to ensure they act in earnest, starting right now.”
By: Paul Carthy, Managing Director – Energy Industry Group, Accenture in the Middle East
The oil and gas (O&G) industry is no stranger to supply and demand shocks and has weathered more than a dozen such jolts over the past four decades.
In the run-up to the COVID-19 pandemic, the oil and gas industry was already amid considerable disruption. Sector returns were under pressure, the capital was flowing away from the industry, and decarbonization headwinds were strengthening to capital increases. Most of the supply-side shocks, excluding 2014’s bump, were the result of sudden supply pullbacks as a reaction to geopolitical unrest. On average, the impact of these market-tightening tremors lasted anywhere between one and six months. Fluctuating demand was primarily due to macroeconomic contraction and was closely connected to more astronomical volatile economic cycles - in terms of size and duration.
However, despite the turbulences the industry has endured over the years, two uncharted global events took set to shape a new and perhaps, even more, disruptive market:
The confluence of these two shocks creates an unprecedented situation and is, therefore, difficult to anticipate. However, if we piece together the various elements of supply and demand in light of these events, it appears that their impact could last well into 2021, with a disproportionate influence on US oil production. Overall, it is likely that we are in for a turbulent 2020, and a lukewarm 2021 in which commodity markets will be under considerable pressure. Given the imminent worldwide recession, it’s hard to see any winners in this scenario, with producer nations, investors, O&G companies, and green/new energy businesses all set to lose.
Simultaneous demand contraction and a concurrent ramp-up in supply are unprecedented. We are in uncharted waters, and it isn’t clear who will win this game of brinkmanship. In this context, we can expect current low prices to prevail and quite possibly drop even further if OPEC+ continues to pursue the flood-the-market approach. This will destroy demand and result in oversupply.
Furthermore, in this scenario, resources became more abundant, the market more competitive, and alternative energy sources more prevalent, lowering the bar for alternatives to specific sources of O&G supply. The downstream sector that served as a cushion in 2014/15 for the industry at large, and specifically, for pure-play refiners and international oil companies (IOCs) as a result of improved margins, cannot be a savior in this cycle. The potential for higher margins will be blunted by reduced volumes as a result of the economic contraction that is set to occur.
As for natural gas, the onset of a global recession will affect demand, though not as much as for oil. However, supply adjustment will be limited, and even associated gas reduction is set to take time, resulting in the continued risk of lower prices. Regardless, this price risk will be more subdued than oil as the gas market was already fending off a market glut before the pandemic hit.
Still, once the global economy stabilises and growth returns, we need oil and gas to sustain development and drive prosperity in the developing world, and to meet the needs of more than two billion people, who will join the global population.
Also, while the logistics involved in oil and gas extraction have improved considerably since the last supply shock in 2014 - by up to US$10-US$20 per barrel – ultimately, the full-cycle breakeven economics of the marginal barrel will set the equilibrium price. And, that breakeven price is still in the high US$50s to low US$60s per barrel. Markets can stay irrational temporarily, but in the long run, fundamentals will prevail.
Challenging times call for intelligent measures - both traditional and non-traditional. The industry has pulled itself out of many shocks and proven skeptics wrong in the past (think peak oil that preceded the 2014 supply renaissance and disruption). However, it is now faced with concurrent disruption at an existential, system-wide, and best-in-class player level – these are risks that will truly test its tenacity and durability. While little can be done to counter the inevitable, making difficult but informed decisions and following a strategic roadmap will help oil companies to endure the downturn and anticipate the next peak.
This column first appeared in the July issue of Pipeline Magazine
Westwood Global Energy Group has released research estimating FPS contract awards will rebound to $13bn annually from 2021-24, underpinned by an anticipated average oil price of $60/bbl from 2022.
In the short-term, Westwood expects FPS engineering, procurement and construction (EPC) contract awards to reach a total of just over $5 billion 2020 – a 59 per cent decline from 2019’s ~$13 billion– assuming a base oil price of $37/bbl in 2020. The new research is a 73 per cent reduction compared to Westwood’s pre-COVID outlook.
1Q 2020 saw two key FPS EPC contract awards (Sangomar FPSO and Anna Nery FPSO [LOI in 2019]), accounting for approximately $2 billion of FPS EPC value and 170 kbpd of additional liquids production capacity. Other key FPS EPC contracts still expected to be awarded in 2020, include Equinor’s Bacalhau unit and Petrobras’ Mero 3, accounting for over $3bn in EPC spend and 400 kbpd of additional liquid production capacity.
Mark Adeosun, senior analyst, Offshore at Westwood Global Energy Group commented: “While the impact of the pandemic has hit FPS EPC contract awards significantly this year, the industry is in a much better place than the downturn of 2016 based on order intake so far, as well as the healthy backlogs of FPS contractors stemming from 2017-2019 activity. Despite this, the overall impact of COVID-19 on the FPS market represents a step backward for an industry which had expected 2020 to be a bumper year in 4Q2019”.
Longer-term, over the 2020-24 period, probable FPS EPC contract awards are estimated at $56 billion – including 40 FPSOs, 9 FPSS and 7 FLNG systems. The outlook for the latter, however, looks increasingly difficult, as low spot prices and looming overcapacity threatens the attractiveness of potential future investments.
Adeosun adds: “Over the next five years, Latin America will account for nearly 42 per cent of probable FPS awards – totalling an estimated $24 billion. Brazil is expected to dominate investment, as international oil companies ramp up activity and Petrobras commits to the development of its pre-salt discoveries. Outside Brazil, Guyana will contribute two additional orders to the forecast in addition to the Liza Unity and the Prosperity FPSO that are currently being built in Singapore (Topsides) and China (Hull).”
The research has been developed using its PlatformLogix solution, which covers global fixed and floating production facilities with data on more than 13,000 units.
The COVID-19 pandemic has stymied oil and gas activity, a phenomena which has now affected the drilling market both in terms of wells drilled and in terms of related demand for drilling equipment.
A Rystad Energy analysis shows the number of drilled wells globally is expected to reach around 55,350 this year, the lowest since at least the beginning of the century.
The decline is a staggering 23 per cent fall from 2019’s number of 71,946 wells. Our forecast, which extends to 2025, does not find it likely that last year’s number will be met or exceeded within the considered time frame. Drilled wells are expected to partly recover to just above 61,000 in 2021, as governments ease travel restrictions, boosting oil demand and prices. Then numbers will rise further to just above 65,000 in 2022 and remain just below 69,000 until the end of 2025.
North America is likely to be most affected, with the country’s rig count already down to historic lows just a few months into the downturn. Although modest recovery is possible in 2H20, drilling activity will remain more than 50 per cent below the levels seen at the same time last year.
From the 55,350 wells to be drilled in 2020, 2,238 are offshore and 53,112 onshore. Before Covid-19 struck, Rystad Energy had expected total wells to rise year-over-year to 74,575, of which 2,896 would be offshore wells and 71,679 onshore wells.
“Both new wells and drilling lengths will be pared down as E&P’s scale down investments, affecting the entire supply chain associated with these services. This includes drilling tools, which will decline by 35 per cent in 2020 compared to 2019,” says Reza Hassan Kazmi, energy services analyst at Rystad Energy.
When looking at drilling tools, we include blowout preventers (BOPs), downhole drilling tools, drill bits, drill pipe, jars, drill collars and other drilling tools except downhole pumps used for artificial lift, under the generic service segment.
Drilling length, another key driver for drilling tools, especially for drill pipes, drill collars, heavy-weight drill pipes and drill bits, is also estimated to drop by 25 per cent this year before improving in 2021. At a more granular level, such as the regional or country level, the percentage decrease in wells will not always result in a proportional reduction in total drilling lengths, as drilling depths per well could greatly vary between different regions and countries.
From the demand standpoint, we expect that onshore and offshore purchases for drilling tools will drop from $16 billion in 2019 to $10 billion in 2020. Besides North America, Africa and Russia will be the biggest contributors to this loss, where purchases will drop by 36 per cent and 27 per cent respectively this year.
Russian operators are likely to delay the drilling of new wells on mature assets to ensure compliance with agreed production cuts, while Sonatrach will cut back most of its spending on projects such as Hassi Messaoud and Tin Fouye-Tabankort. In the medium term however, as major E&Ps resume developing their lineup of offshore projects in Africa, we expect the demand for drilling tools (especially for drilling risers) to increase.
Overall, onshore markets are expected to recover as early as 2021 and grow at a rate of 7 per cen annually towards 2025, while offshore markets will see some highs and lows and will maintain an overall flattish level towards 2025.
Despite the overall stagnant growth, Brazil, Australia and China will continue to offer exciting opportunities in the short term with 20 per cent to 40 per cent growth prospects for offshore drilling in these countries while the United Kingdom, Guyana and Mexico look promising in the medium to long term. The United States remains the hotspot for spending on drilling tools onshore, while Norway is expected to top the list for offshore drilling tools spending.
In the onshore market in the U.S., more than 80% of spending on drilling tools will be spent on shale drilling. The Permian and the Appalachian basins will drive 60% of total shale spend on drilling tools followed by some conventional activity in other basins. Off the coast of Norway, Troll, Balder/Ringhorne and Johan Sverdrup will drive the demand for drilling tools.
By: Joko Priatmoko, Technical Support Consultant, Aramco Chemicals Company
Oil and chemicals markets have been severely impacted by COVID-19, but the pandemic has caused a spike in demand for some petrochemical products. While there can be few winners in the fight against coronavirus, polymers in particular have proven their resiliency, worth and value in confronting the infection. This has led to rising demand for healthcare products, flexible packaging for food and e-commerce goods, as well as Personal Protective Equipment (PPE). The two key polymers to have an impact in this area are polypropylene (PP) spunbond and polymethyl methacrylate (PMMA).
In the hygiene and healthcare sectors, the global need for items such as PPE, syringes, vials, wipes, medical cartridges, surgical masks and gowns has led to a surge in demand for products like PP spunbond non-woven fabric. One forecast predicts the spunbond non-wovens market will grow from $12.7 billion in 2018 to $18.3 billion by 2023, a Compound Annual Growth Rate (CAGR) of 7.6%. PP is likely to be the largest and fastest-growing segment in the global spunbond market, with personal care and hygiene forecast to be the biggest and fastest-growing end use segment.
There has also been significant interest in PMMA, otherwise known as acrylic, for new types of applications. This coincides with rising demand for protective shields to restrict the spread of the virus in public transport, offices, commercial stores, hospitals and pharmacies. PMMA lends itself to this purpose because it can be sterilized without impacting appearance or transparency, creating an ideal barrier between supermarket cashiers and shoppers, or between taxi drivers and passengers.
This signals a new use for PMMA sheets, for which higher COVID-19 demand is offsetting weaker consumption in the main automotive and construction sectors. In fact, PMMA has emerged as the most sought-after polymer in 2020, ahead of polycarbonate (PC) or polyethylene terephthalate-glycol (PET-G). Shields made from PMMA may well be a common sight moving forward: literally becoming part of the furniture in the post-COVID-19 new normal. This would in turn support further long-term growth potential.
Single-use plastic bags and disposable plastic bags, criticized for their environmental impact, also have a role to play with coronavirus-conscious retailers and consumers. Before the COVID-19 outbreak, sustainable packaging was on every Fast-Moving Consumer Goods (FMCG) company’s agenda. However, a shift towards more plastic packaging to help manage infection has altered the landscape - at least for the near future.
That is supported by higher demand for plastic packaging in general. The pandemic has shut down restaurants and food-service outlets, sparking a shift to grocery purchases. There is also a preference for online shopping over visiting public malls and high-street shops, increasing parcel shipments. Health precautions also demand more stringent protection for medical supplies. Such changes in behavior will not disappear overnight. As a result, the global packaging market is projected to grow from $909.2 million in 2019 to $1.0126bn by 2021, at a CAGR of 5.5%. The most optimistic forecasts suggest a CAGR of up to 9.2% over that period, while the least optimistic predict a CAGR of 2.2%.
However, plastics manufacturers face lower demand for engineering plastics in particular due to reduced production of vehicles and equipment. This is particularly the case in the automotive, construction, electrical and electronics sectors. PMMA producers have been able to offset this due to rising demand for shields, but sales of other products such as Nylon 6 - the waterproof material used to make machine parts, airbags, carpets, ropes and hoses – have suffered.
Yet despite temporary disruption, conventional demand for products is expected to return as businesses resume production with the easing of global COVID-19 restrictions. The new normal therefore presents a new opportunity for the petrochemicals sector, which has already been singled out by the International Energy Agency as the main driver of oil demand over the next decade and beyond.
That is why, at Aramco, we remain committed to expanding our petrochemicals business as part of a long-term goal to increase our downstream portfolio and capture more value from the integration and diversification of our operations, in particular in Asia. It is a strategy which inspired Aramco’s recent purchase of a majority interest in SABIC - a deal that ushers in a new era of innovation and value creation across the hydrocarbon chain and will propel Saudi Aramco as a leading global petrochemical supplier for decades to come.
By: Sverre Alvik, Energy Transition Program Director, DNV GL
The coronavirus pandemic will have a dramatic impact on energy supply and demand in the short term and will have lasting impacts once the pandemic dissipates. However, that will in itself do little to advance the world’s progress towards the Paris climate ambitions.
Energy use is strongly linked to economic activity, which has, and will continue to be, significantly impacted by the novel coronavirus pandemic: Our energy forecast is predicated on IMF’s longer outbreak scenario, where World GDP will shrink 6 per cent in 2020. The lingering effects of the pandemic will take the wind out of the sails of the world economy for many years – reducing World GDP in 2050 by 9 per cent, relative to pre-pandemic forecasts. Even with slower growth, however, by mid-century the world economy will still be twice its size today. In contrast, energy demand will not grow. In 2050, it will be about the same as it is today, in spite of a larger population and world economy. This is largely due to significant improvements in energy intensity, but also due to the effects of COVID-19.
An 8% drop in energy use
Before the pandemic, we predicted total global energy demand in 2050 at 456 exajoules (EJ), (Global energy demand using the latest historical figures was at 424 EJ in 2018.) Our modelling now shows that the pandemic will reduce energy demand through to 2050 by 8 per cent, resulting in energy demand in 2050 at almost exactly the level it was in 2018.
Improvements in energy intensity will remain the most important factor in reducing energy demand in the coming decades, and the contraction due to COVID-19 comes on top of this. That is as a result of the brakes applied to economic activity generally by the pandemic, as well as some specific sectoral impacts. Lasting changes linked to COVID-19 are mainly behavioural in nature and include the impact of the pandemic on the transport sector, especially aviation, but also on less office work and changed commuting habits, which will result in transport energy use never again reaching 2019 levels. Demand for manufactured goods globally will need almost four years to recover to 2019 levels, and the energy-intensive iron and steel industry, impacted inter alia by lower demand for new office space, may never reach its pre-pandemic heights.
On the face of it, this appears to be good news for decarbonisation – transport remains heavily oil dependent and iron and steel is one of the key so-called ‘hard to abate’ sectors, relying as it does to a large degree on hydrocarbons to supply high-heat processes. Declining demand in these sectors is one of the main reasons for the price weakness in hydrocarbons, with widespread write-downs in oil and gas assets. It appears likely that oil has already reached a supply plateau that we forecast to occur in 2022, prior to factoring in the effects of the pandemic.
It is certainly not game over for hydrocarbons, and especially not so for natural gas, which we forecast to take over from oil as the largest energy source in this decade. However, the reduced return on capital and the increased volatility in fossil fuel prices is making many investors look at these assets in the post-COVID world with a greater degree of caution; they may also now regard renewables assets more favourably, even though the pandemic is placing a temporary check on the expansion of renewable sources of energy. Renewables have first place in the merit order of the power mix due to their very low operating costs, and short design and construction times. These assets are therefore more robust, and we predict a slightly faster recovery of the non-fossil capital expenditure in the next couple of years than will be the case for fossil energy.
Limited long-term effects on the climate
With the earlier than anticipated plateauing of oil and the continued rapid decline of coal use, our forecast shows that CO2 emissions most likely have already peaked (in 2019).
Again, this appears to be good news from a climate goals perspective – but the longer-term decline in emissions is not significantly accelerated by the pandemic. Even with peak emissions behind us, and flat energy demand through to 2050, the energy transition we forecast is still nowhere near fast enough to deliver the Paris ambition of keeping global warming well below 2°C above pre-industrial levels. To reach 1.5-degree target, we would need to repeat the decline we’re experiencing in 2020 every year from now on.
To put this in perspective, the COVID-19 impact on energy demand only buys humanity another year of ‘allowable’ emissions before the 1.5°C target is exhausted (in 2029) and a couple of years before the 2°C warming carbon budget is exhausted (in the year 2050).
It should also be acknowledged that emissions have been declining in the first half of this year for the wrong reasons. The coronavirus pandemic is exacting a heavy and tragic toll on lives and livelihoods, increasing poverty and hunger and reducing growth prospects for those that need it most. There is a potential for a much more just and sound energy transition that does not cause the harm and disruption associated with the COVID crisis.
In our forthcoming Energy Transition Outlook (2020), which we will release in early September, we explore many of the technology solutions that can help to close the gap between our forecast global warming outcome and the Paris ambitions. Our view remains firmly that humanity already possesses the technology and knowhow to deliver on Paris. We also have the capacity to modify our behaviours and habits, and in this year’s Outlook we take a renewed look at energy-related behavioural change, and explore where and how COVID-19 may permanently change our habits.
However, the key to reaching the Paris goals remains policy: the political choices and policy delivered around the world that encourages the correct behavioural changes and enables the right technical solutions to scale.
Policy also represents the main uncertainty as to whether the pandemic will speed up or slow down the energy transition. It is unclear whether the enormous COVID-19 economic stimulus packages being lined up by governments will be spent wisely on renewable energy sources, or expeditiously on fossil sources in the hope of bringing larger numbers of people back to employment more rapidly. There are signs now of both directions being pursued, with strong regional variations. Our assumption is, therefore, that globally, the sum of the stimulus packages will not significantly impact the energy mix – but that remains an assumption. Time will tell.
Global discoveries of conventional resource volumes reached just 4.9 billion barrels of oil equivalent (boe) in the first half of 2020, Rystad Energy estimates, the weakest-performing first half of the 21st century. The resource volumes were 42 per cent lower and the number of discoveries was down by 31 per cent compared to the same period in 2019.
The average monthly discovered volumes so far this year are estimated at 810 million boe, a 34 per cent drop from the same period last year. This year could be on track to repeat the 2019 predominance of gas discoveries, with 55 per cent of the volumes discovered so far being categorised as gas. The top five largest discoveries account for about 68 per cent of the total discovered volumes.
The monthly average was pulled down primarily by June, which only saw three small onshore discoveries, adding around 16 million boe in discovered volumes. January and May were the most successful months in 1H20 due to significant discoveries such as Jebel Ali in the United Arab Emirates, Maka Central in Suriname, Uaru in Guyana and 75 Let Pobedy in Russia.
“Last year we saw the highest volumes of discovered resources since the last downturn. Based on the large number of high-impact exploration wells planned for this year, 2020 was meant to follow the same path. But then Covid-19 struck and the oil market crashed in 1Q20, resulting in delays and cancellations as operators cut budgets,“ says Rystad Energy’s upstream analyst Taiyab Zain Shariff.
Russia, South America and the Middle East account for about 73 per cent of the total discovered resources so far in 2020. Africa and Australia seem to have taken a back seat this time, with less than 1 per cent of the total discovered resources. It is also interesting to note that close to 70 per cent of the resources were discovered offshore.
There were a total of 49 conventional oil and gas discoveries during the first half of 2020, of which 27 were announced during the global lockdown and travel restriction period. While these travel bans and the associated logistical issues didn’t have much of an effect on projects in the testing and completion phase, they did cause delays for projects in the initial and ongoing drilling phase that required crew changes. This could be one of the reasons for the lower number of discoveries in May and June.
A total of 14 high-impact wells (HIWs) have been completed so far this year. Of these, three have resulted in medium-sized to large discoveries, nine were dry or had uncommercial hydrocarbon shows, while results are still pending for the remaining two. It is estimated that the wells that have come up dry targeted cumulative estimated pre-drill resources of more than 2.5 billion boe.
Drilling was in progress on an additional four high-impact wells as we passed the half-year mark, though the SAX01 well on BP’s Shafag-Asiman block in Azerbaijan has been temporarily suspended due to the COVID-19 travel bans. Another 11 high-impact wells are expected to be drilled before the end of 2020, including key wells in the Suriname-Guyana basin, Southern Africa, Timor-Leste, Norway and the frontier areas of Russia.
“Although we look forward to these wells being spudded before the end of this year, a few delays may still arise because of Covid-19-related logistical issues that may come up as a result of the expected second wave of the pandemic,“ adds Shariff.
The in-progress and planned high-impact wells have the potential to add up to 5.0 billion boe to the global tally. But with the unpredictable oil markets, and operators’ budget cuts on top of the COVID-19-related logistical issues, oil and gas exploration faces major challenges. It is estimated that the global offshore exploration activity this year might reach its lowest point in 20 years, with discovered volumes falling even lower than they were in 2016.
Without a major acceleration in clean energy innovation, countries and companies around the world will be unable to fulfil their pledges to bring their carbon emissions down to net-zero in the coming decades, according to a special report released today by the International Energy Agency
The report assesses the ways in which clean energy innovation can be significantly accelerated to achieve net-zero emissions while enhancing energy security in a timeframe compatible with international climate and sustainable energy goals. The Special Report on Clean Energy Innovation is the first publication in the IEA’s revamped Energy Technology Perspectives (ETP) series and includes a comprehensive new tool analysing the market readiness of more than 400 clean energy technologies.
“There is a stark disconnect today between the climate goals that governments and companies have set for themselves and the current state of affordable and reliable energy technologies that can realise these goals,” said Dr Fatih Birol, the IEA Executive Director. “This report examines how quickly energy innovation would have to move forward to bring all parts of the economy – including challenging sectors like long-distance transport and heavy industry – to net-zero emissions by 2050 without drastic changes to how we go about our lives. This analysis shows that getting there would hinge on technologies that have not yet even reached the market today. The message is very clear: in the absence of much faster clean energy innovation, achieving net-zero goals in 2050 will be all but impossible.”
A significant part of the challenge comes from major sectors where there are currently few technologies available for reducing emissions to zero, such as shipping, trucking, aviation and heavy industries like steel, cement and chemicals. Decarbonising these sectors will largely require the development of new technologies that are not currently in commercial use. However, the innovation process that takes a product from the research lab to the mass market can be long, and success is not guaranteed. It took decades for solar panels and batteries to reach the stage they are at now. Time is in even shorter supply now.
Notably, the report highlights the importance of making sure crucial clean energy solutions are ready in time for the start of multi-decade investment cycles in key industries. Doing so could create huge markets for new technologies and avoid locking in vast amounts of emissions for decades to come. If key technologies become available by 2030 to take advantage of the next round of plant refurbishments in heavy industry, nearly 60 gigatonnes of carbon emissions could be avoided.
Another issue is that many of the clean energy technologies that are available today – such as offshore wind turbines, electric vehicles and certain applications of carbon capture, utilisation and storage – need a continued push on innovation to bring down costs and accelerate deployment.
Around three-quarters of the cumulative reductions in carbon emissions that would be needed to move the world onto a sustainable path would come from technologies that have not yet reached full maturity, according to the IEA report. For example, it would require rapid progress in new battery designs that are still at the prototype stage now to shift long-distance transport from fossil fuels to electricity.
But the public and private sectors are currently falling short of delivering the innovation efforts to back up their net-zero ambitions – and the Covid-19 crisis is threatening to further undermine projects around the world focused on developing vital new energy technologies.
“A recent IEA survey revealed that companies that are developing net-zero emissions technologies consider it likely that their research and development budgets will be reduced, a clear sign of the damage that the Covid-19 crisis could do to clean energy innovation,” Dr Birol said. “Now is not the time to weaken support for this essential work. If anything, it is time to strengthen it.”
To help guide policy makers at this challenging time, the IEA report offers five key innovation principles for governments that aim to deliver net-zero emissions while enhancing energy security:
In particular, the report highlights issues requiring immediate attention in the context of the Covid-19 crisis, such as the importance of governments maintaining research and development funding at planned levels through 2025 and considering raising it in strategic areas. It stresses that market-based policies and funding can help scale up value chains for small, modular technologies with overlapping innovation needs like new types of batteries and electrolysers, significantly advancing their progress.
“Together with the Sustainable Recovery Plan that the IEA presented last month, this innovation report will provide the foundation for the IEA Clean Energy Transitions Summit on 9 July,” Dr Birol said. “The Summit will be the most important global event on energy and climate issues of 2020, bringing together more than 40 government ministers, industry CEOs and other energy leaders from countries representing 80% of global energy use and emissions. The aim is to build a grand coalition to help drive economic development and job creation by accelerating transitions towards clean, resilient and inclusive energy systems.”