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“Despite oil price downturns, the shale revolution and OPEC market share wars, offshore continues to thrive and has much to offer the future,” Audun Martinsen, head of oilfield services research at Rystad Energy, said in May, commenting on the independent energy research and consultancy’s findings that the offshore oil and gas sector has tremendous room for further growth. 

Offshore exploration, greenfield and brownfield development, decommissioning, and maintenance and operations are all set to create trillions of U.S. dollars of opportunities for the services sector in the future, according to Rystad Energy. 

Following a muted offshore market in 2015 and 2016 after the 2014 oil price crash, offshore project sanctioning has recently started to pick up, and may be on track for a bumper year this year, Rystad said in an analysis in January. Back then, the consultancy forecast that offshore sanctioning could reach US$123 billion in project commitments in 2019, with the Middle East leading in shallow-water project sanctioning and South America leading in deepwater projects.

More recently, in July, Rystad Energy said that this year’s offshore oil and gas project sanctioning had already exceeded US$50 billion in commitments, signalling that the industry has the potential to reach US$123 billion in project commitments, surpassing the US$78-billion worth of projects sanctioned in 2014, when the price of oil started to crumble.

“With offshore free cash flows at nearly record highs, E&P’s are betting big on new projects. Offshore project sanctioning in 2019 looks ready to reach heights not seen since the $100 barrel of oil,” Matthew Fitzsimmons, VP of Oilfield Service Research at Rystad Energy, said in July.

The consultancy ranked the top ten offshore projects in terms of capital commitments sanctioned between 2014—when oil prices were still at US$100 a barrel in the first half of that year—and 2019. Here they are ranked in descending order:

1. Saudi Aramco’s Marjan expansion offshore Saudi Arabia

The Marjan increment programme is an integrated development project for oil, associated gas, non-associated gas, and cap gas from the Marjan offshore field, worth a total of US$12 billion. The development aims to boost the Marjan Field production by 300,000 barrels of oil per day (bpd) of Arabian Medium Crude Oil, process 2.5 BSCFD of gas, and produce an additional 360 MBCD of C2+NGL. The development will entail a new offshore gas oil separation plant and 24 offshore oil, gas, and water injection platforms.

2. Equinor’s Johan Sverdrup Phase 1 offshore Norway

Next on Rystad’s rankings comes the Johan Sverdrup Phase 1 development project in Norway’s section of the North Sea. Johan Sverdrup is one of the five largest oil fields ever to be discovered on the Norwegian Continental Shelf (NCS). The project—with expected resources estimated at 2.7 billion barrels of oil equivalent—is also one of the most important industrial projects in Norway for the next 50 years.

Production start-up is scheduled for November 2019, and daily production during Phase 1 is estimated at 440,000 bpd, with peak production expected to reach 660,000 bpd. Investment in Phase 1 is estimated at 86 billion Norwegian crowns, according to Equinor, or around US$11 billion as estimated by Rystad.

3. BP’s Argos (Mad Dog Phase 2) in the US Gulf of Mexico

The operator BP and co-owners BHP and Union Oil Company of California, an affiliate of Chevron, approved the US$9 billion final investment decision on the Mad Dog 2 Phase offshore project in early 2017. BP has worked with co-owners and contractors to bring down the originally estimated cost of US$20 billion and slashed costs by 60 percent. The Mad Dog 2 project includes the Argos platform with the capacity to produce up to 140,000 gross barrels of crude oil per day through a subsea production system from up to 14 production wells and eight water injection wells. Oil production from the new floating production platform is expected to begin in late 2021.   

4. Equinor’s Johan Castberg in the Barents Sea

Equinor’s development plan for the Johan Castberg field in the Barents Sea was approved in 2018. The US$6-billion project has recoverable resources estimated at 450-650 million barrels of oil equivalent, while Equinor and partners have changed the concept to halve expenditures and make it a profitable development.

The field—currently the largest subsea field under development in the world, according to Equinor—consists of a production vessel and a comprehensive subsea system, including a total of 30 wells distributed on 10 templates and 2 satellite structures. Johan Castberg is scheduled for first oil in 2022 and it’s profitable even at an oil price below US$35 a barrel, Equinor says.  

5. Saudi Aramco’s Berri expansion project offshore Saudi Arabia

Aramco’s Berri increment programme worth around US$6 billion aims to raise the offshore field’s production by 250,000 barrels of Arabian Light Crude per day. Once completed, the planned facilities will include a new gas oil separation plant in Abu Ali Island to process 500,000 bpd of Arabian Light Crude Oil, and additional gas processing facilities at the Khursaniyah gas plant to process 40,000 barrels of associated hydrocarbon condensate. The expansion project includes a new water injection facility, two drilling islands, 11 oil and water offshore platforms, and nine onshore oil production and water supply drill sites.

In early July, Saudi Aramco awarded 34 contracts worth a total of US$18 billion for the engineering, procurement and construction of the Marjan and Berri increment programmes.

6. Equinor’s Johan Sverdrup Phase 2 in the North Sea

Norwegian authorities approved in May 2019 Equinor and partners’ development plan for the second phase of the Johan Sverdrup field development. Capital expenditure is around US$5 billion and start-up is planned for the fourth quarter of 2022. In addition to the construction of a new processing platform (P2), phase 2 development will also include modifications of the riser platform, five subsea systems, and preparations for power supply from shore to the Utsira High in 2022.

7. Shell’s Appomatox in the US Gulf of Mexico

Shell’s Appomatox development in the Norphlet formation in deepwater Gulf of Mexico was not only sanctioned but also brought to production between 2014 and 2019. The estimated US$5-billion development was the first-ever Jurassic play to start production in the US Gulf of Mexico in May this year, with an expected production of 175,000 barrels of oil equivalent per day (boed).

The Shell-operated Appomattox floating production system opens a new frontier in the deepwater US Gulf of Mexico, Shell says, adding that Appomattox has realised cost reductions of more than 40 percent since taking FID in 2015. “Appomattox creates a core long-term hub for Shell in the Norphlet through which we can tie back several already discovered fields as well as future discoveries,” said Andy Brown, Upstream Director, Royal Dutch Shell.

The next two offshore projects in Rystad Energy’s rankings are located offshore the United Arab Emirates (UAE), each worth some US$5 billion for development of sour gas, and expected to take FID in 2019.

8. ADNOC’s Hail (Sour Gas) project offshore the UAE

At the beginning of 2019, the Abu Dhabi National Oil Company (ADNOC) awarded work for the dredging, land reclamation, and marine construction to build multiple artificial islands in the first phase of development of the Ghasha Concession. The Ghasha Concession consists of the Hail, Ghasha, Dalma, Nasr, and Mubarraz offshore sour gas fields. The project is expected to take 38 months to complete and will provide the infrastructure required to further develop, drill, and produce gas from the sour gas fields in the Ghasha Concession.

9. ADNOC’s Ghasha (Sour Gas) project offshore the UAE

Commenting on the initial work on the projects, UAE Minister of State and ADNOC Group CEO, Dr. Sultan Ahmed Al Jaber, said:

“This award accelerates the development of the Hail, Ghasha and Dalma sour gas offshore mega-project, which is an integral part of ADNOC’s 2030 smart growth strategy. As one of the world’s largest sour gas projects it will make a significant contribution to the UAE’s objective to become gas self-sufficient and transition to a potential net gas exporter.”

10. Total’s Gindungo offshore Angola

Total, operator of Kaombo, currently the biggest deep offshore development in Angola, started up in July 2018 production from Kaombo Norte, the first Floating Production Storage, and Offloading (FPSO) unit. Kaombo Norte and the other FPSO, Kaombo Sul, are developing the resources from six different fields—Gengibre, Gindungo, Caril, Canela, Mostarda, and Louro—offshore Angola.

In April 2019, Total started up production from Kaombo Sul, bringing the overall production capacity to 230,000 bopd, equivalent to 15 percent of Angola’s production. The associated gas from Kaombo Sul will be exported to the Angola LNG plant as part of Total’s commitment to stop routine flaring.

Oil Gas offshore OPEC Rystad Energy Saudi Aramco Equinor Norway BP USA Gulf of Mexico Saudi Arabia North Sea Shell ADNOC Total UAE
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Renewables became the second-most prevalent U.S. electricity source in 2020

In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.

In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.

Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.

We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.

monthly U.S electricity generation from all sectors, selected sources

Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.

July, 29 2021
PRODUCTION DATA ANALYSIS AND NODAL ANALYSIS

Kindly join this webinar on production data and nodal analysis on the 4yh of August 2021 via the link below

https://www.linkedin.com/events/productiondataanalysis-nodalana6810976295401467904/

July, 28 2021
Abu Dhabi Lifts The Tide For OPEC+

The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.

How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.

The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.

The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.

On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.

But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.

For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.

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Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Worries about new Covid-19 infections worldwide dragging down demand just as OPEC+ announced that it would be raising production by 400,000 b/d a month from August onward triggered a slide in Brent and WTI crude prices below US$70/b
  • However, that slide was short lived as near-term demand indications showed the consumption remained relatively resilient, which lifted crude prices back to their previous range in the low US$70/b level, although the longer-term effects of the Covid-19 delta variants are still unknown at this moment
  • Clarity over supply and demand will continue to be lacking given the fragility of the situation, which suggests that crude prices will remain broadly rangebound for now

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July, 26 2021