Join NrgEdge to View Member's Profile. It's Free
Fill up your particulars with:
Fill up your particulars with:
At a time when most of the news in the North Sea is about exits – ExxonMobil has just sold its unoperated upstream assets in Norway and ConocoPhillips has departed the UK section of the North Sea – there are still sparks of brightness in this long-mined offshore area. Equinor’s Johan Sverdrup field which contains some 2.7 billion barrels of oil equivalent has started up, two months ahead of schedule and US$4.3 billion below original cost estimates.
When it hits peak production, this new ‘North Sea giant’ will produce up to 660,000 b/d of crude oil, accounting for a third of all oil production in Norway. When complete, the Johan Sverdrup development will be one of the largest in the Norwegian Continental Shelf. It is a shot in the arm that Norway’s industry needs right now. Equinor has had a good track record in making new discoveries over the past two years, but they all mainly small and cannot outweigh declining production elsewhere. John Sverdrup is very different. Discovered in 2010, Johan Sverdrup straddles two separate production licences, discovered as Avaldsnes by Lundin Petroleum and Aldous Major South by Equinor and the field was renamed to its current form in 2012. Equinor holds a 42.6% stake in the field, with Lundin Norway, Petoro, Aker BP and Total constituting the rest.
The project has been championed as a model of the lower-cost, innovative thinking approach that the Norwegian upstream has taken since the 2014 downturn of the oil and gas industry. With first oil already flowing, it will help reverse the steady decline in Norwegian oil production, which fell to 1.65 million b/d in August, down 3.9% m-o-m and down from the all-time peak of 3.4 million b/d in 2011. Prudence paid off; green-lit in 2015, Equinor and its partners managed to secure significant discounts on services and equipment, resulting a break-even cost of less than US$20/b. The location of John Sverdrup is also crucial; believing the Norwegian Continental Shelf to be fully explored, activity has shifted to the Barents Sea. But though there are some big fields in the Barents coming onstream, exploration there has generally underperformed. So the field has been seen as a cause for hope, discovered in a mature basin 160km from Stavanger that was thought to be completely tapped out
Interestingly, John Sverdrup also has wider implications beyond the oil industry. With production set to reach 440,000 b/d by mid-2020, it will contribute about US$100 billion to the Norwegian state coffers over 50 years. It will inject additional fuel into the Norwegian Oil Fund – the country’s sovereign wealth fund – that recently decided to jettison upstream oil stocks (while keeping downstream oil stocks). This illustrates a dichotomy: while Norway as a whole is supportive of clean energy, oil & gas remains a crucial backbone of the country’s economy. So while the conversation around the North Sea will still centre around decommissioning and departures, Johan Sverdrup is proof that there are still (big) pockets of opportunity underneath these cold waters.
Johan Sverdrup:
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
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.
Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)
Note: Click to enlarge.
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.
