“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.
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In 2019, consumption of renewable energy in the United States grew for the fourth year in a row, reaching a record 11.5 quadrillion British thermal units (Btu), or 11% of total U.S. energy consumption. The U.S. Energy Information Administration’s (EIA) new U.S. renewable energy consumption by source and sector chart published in the Monthly Energy Review shows how much renewable energy by source is consumed in each sector.
In its Monthly Energy Review, EIA converts sources of energy to common units of heat, called British thermal units (Btu), to compare different types of energy that are more commonly measured in units that are not directly comparable, such as gallons of biofuels compared with kilowatthours of wind energy. EIA uses a fossil fuel equivalence to calculate primary energy consumption of noncombustible renewables such as wind, hydro, solar, and geothermal.
Source: U.S. Energy Information Administration, Monthly Energy Review
Wind energy in the United States is almost exclusively used by wind-powered turbines to generate electricity in the electric power sector, and it accounted for about 24% of U.S. renewable energy consumption in 2019. Wind surpassed hydroelectricity to become the most-consumed source of renewable energy on an annual basis in 2019.
Wood and waste energy, including wood, wood pellets, and biomass waste from landfills, accounted for about 24% of U.S. renewable energy use in 2019. Industrial, commercial, and electric power facilities use wood and waste as fuel to generate electricity, to produce heat, and to manufacture goods. About 2% of U.S. households used wood as their primary source of heat in 2019.
Hydroelectric power is almost exclusively used by water-powered turbines to generate electricity in the electric power sector and accounted for about 22% of U.S. renewable energy consumption in 2019. U.S. hydropower consumption has remained relatively consistent since the 1960s, but it fluctuates with seasonal rainfall and drought conditions.
Biofuels, including fuel ethanol, biodiesel, and other renewable fuels, accounted for about 20% of U.S. renewable energy consumption in 2019. Biofuels usually are blended with petroleum-based motor gasoline and diesel and are consumed as liquid fuels in automobiles. Industrial consumption of biofuels accounts for about 36% of U.S. biofuel energy consumption.
Solar energy, consumed to generate electricity or directly as heat, accounted for about 9% of U.S. renewable energy consumption in 2019 and had the largest percentage growth among renewable sources in 2019. Solar photovoltaic (PV) cells, including rooftop panels, and solar thermal power plants use sunlight to generate electricity. Some residential and commercial buildings heat with solar heating systems.
Source: U.S. Energy Information Administration, Annual Electric Generator Inventory
Based on the U.S. Energy Information Administration's (EIA) annual survey of electric generators, natural gas-fired generators accounted for 43% of operating U.S. electricity generating capacity in 2019. These natural gas-fired generators provided 39% of electricity generation in 2019, more than any other source. Most of the natural gas-fired capacity added in recent decades uses combined-cycle technology, which surpassed coal-fired generators in 2018 to become the technology with the most electricity generating capacity in the United States.
Technological improvements have led to improved efficiency of natural gas generators since the mid-1980s, when combined-cycle plants began replacing older, less efficient steam turbines. For steam turbines, boilers combust fuel to generate steam that drives a turbine to generate electricity. Combustion turbines use a fuel-air mixture to spin a gas turbine. Combined-cycle units, as their name implies, combine these technologies: a fuel-air mixture spins gas turbines to generate electricity, and the excess heat from the gas turbine is used to generate steam for a steam turbine that generates additional electricity.
Combined-cycle generators generally operate for extended periods; combustion turbines and steam turbines are typically only used at times of peak load. Relatively few steam turbines have been installed since the late 1970s, and many steam turbines have been retired in recent years.
Source: U.S. Energy Information Administration, Annual Electric Generator Inventory
Not only are combined-cycle systems more efficient than steam or combustion turbines alone, the combined-cycle systems installed more recently are more efficient than the combined-cycle units installed more than a decade ago. These changes in efficiency have reduced the amount of natural gas needed to produce the same amount of electricity. Combined-cycle generators consume 80% of the natural gas used to generate electric power but provide 85% of total natural gas-fired electricity.
Source: U.S. Energy Information Administration, Annual Electric Generator Inventory
Every U.S. state, except Vermont and Hawaii, has at least one utility-scale natural gas electric power plant. Texas, Florida, and California—the three states with the most electricity consumption in 2019—each have more than 35 gigawatts of natural gas-fired capacity. In many states, the majority of this capacity is combined-cycle technology, but 44% of New York’s natural gas capacity is steam turbines and 67% of Illinois’s natural gas capacity is combustion turbines.
Countries that are not members of the Organization for Economic Cooperation and Development (OECD) in Asia, including China and India, and in Africa are home to more than two-thirds of the world population. These regions accounted for 44% of primary energy consumed by the electric sector in 2019, and the U.S. Energy Information Administration (EIA) projected they will reach 56% by 2050 in the Reference case in the International Energy Outlook 2019 (IEO2019). Changes in these economies significantly affect global energy markets.
Today, EIA is releasing its International Energy Outlook 2020 (IEO2020), which analyzes generating technology, fuel price, and infrastructure uncertainty in the electricity markets of Africa, Asia, and India. A related webcast presentation will begin this morning at 9:00 a.m. Eastern Time from the Center for Strategic and International Studies.
Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)
IEO2020 focuses on the electricity sector, which consumes a growing share of the world’s primary energy. The makeup of the electricity sector is changing rapidly. The use of cost-efficient wind and solar technologies is increasing, and, in many regions of the world, use of lower-cost liquefied natural gas is also increasing. In IEO2019, EIA projected renewables to rise from about 20% of total energy consumed for electricity generation in 2010 to the largest single energy source by 2050.
The following are some key findings of IEO2020:
IEO2020 builds on the Reference case presented in IEO2019. The models, economic assumptions, and input oil prices from the IEO2019 Reference case largely remained unchanged, but EIA adjusted specific elements or assumptions to explore areas of uncertainty such as the rapid growth of renewable energy.
Because IEO2020 is based on the IEO2019 modeling platform and because it focuses on long-term electricity market dynamics, it does not include the impacts of COVID-19 and related mitigation efforts. The Annual Energy Outlook 2021 (AEO2021) and IEO2021 will both feature analyses of the impact of COVID-19 mitigation efforts on energy markets.
With the IEO2020 release, EIA is publishing new Plain Language documentation of EIA’s World Energy Projection System (WEPS), the modeling system that EIA uses to produce IEO projections. EIA’s new Handbook of Energy Modeling Methods includes sections on most WEPS components, and EIA will release more sections in the coming months.