“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:
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.
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.
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.
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.
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.
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 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.
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 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.
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.
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.”
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.
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