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Last Updated: January 15, 2020
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As the pressure to act on climate change builds, the industry should consider a range of options.

If the world is to come anywhere near to meeting its climate-change goals, the oil and gas (O&G) industry will have to play a big part (Exhibit 1). The industry’s operations account for 9 percent of all human-made greenhouse-gas (GHG) emissions. In addition, it produces the fuels that create another 33 percent of global emissions (Exhibit 2).

Exhibit 1


Exhibit 2


Several trends are focusing the minds of industry executives. One is that investors are pushing companies to disclose consistent, comparable, and reliable data. Activist shareholders, for example, are challenging US- and Europe-based oil majors on their climate policies and emissions-reduction plans.1 Investors are also increasingly conscious of environmental issues. In the five markets examined by the Global Sustainable Investment Alliance—Australia and New Zealand, Canada, Europe, Japan, and the United States—sustainable investments reached assets of $30.7 trillion in early 2018, one-third of total investment. At September’s UN climate summit, an alliance of the world’s largest pension funds and insurers (representing $2.4 trillion in assets) committed itself to transitioning its portfolios to net-zero emissions by 2050.2

At the same time, renewable technologies have been getting cheaper. In the United States, the cost of solar—both photovoltaics (PV) and utility scale—has fallen more than 70 percent since 2011, and the cost of wind by almost two-thirds. By 2025, they could be competitive with natural gas–based power generation in many more regions.

Other forces are also coming into play. Although there is still no global market, carbon taxes or trading systems cover 20 percent of worldwide emissions, compared with 15 percent in 2017, according to the World Bank.3 Many European governments plan to implement binding GHG emissions targets and are drawing up national energy and climate plans.

Options for the oil and gas sector

To play its part in mitigating climate change to the degree required, the oil and gas sector must reduce its emissions by at least 3.4 gigatons of carbon-dioxide equivalent (GtCO2e) a year by 2050, compared with “business as usual” (currently planned policies or technologies)—a 90 percent reduction in current emissions. Reaching this target would clearly be easier if the use of oil and gas declined. But even if demand doesn’t fall much, the sector can abate the majority of its emissions, at an average cost of less than $50 per ton of carbon-dioxide equivalent (tCO2e), by prioritizing the most cost-effective interventions. Process changes and minor adjustments that help companies reduce their energy consumption will promote the least expensive abatement options.

The specific initiatives a company chooses to reduce its emissions will depend on factors such as its geography, asset mix (offshore versus onshore, gas versus oil, upstream versus downstream), and local policies and practices (regulations, carbon pricing, the availability of renewables, and the central grid’s reliability and proximity). Already, many companies have adopted techniques that can substantially decarbonize operations—for example, improved maintenance routines to reduce intermittent flaring and vapor-recovery units to reduce methane leaks (Exhibit 3). Cutting emissions is not necessarily expensive. An onshore operator found that about 40 percent of the initiatives it identified had a positive net present value (NPV) at current prices and an additional 30 percent if it imposed an internal carbon price of $40/tCO2e on its operations.

Exhibit 3


One option is to implement initiatives that offset emissions by tapping into natural carbon sinks, including oceans, plants, forests, and soil; these remove GHGs from the atmosphere and reduce their concentration in the air. Plants and trees sequester around 2.4 billion tons of CO2 a year.4 The Italian energy giant ENI has announced programs to plant 20 million acres (four times the size of Wales) of forest in Africa to serve as a carbon sink. Other companies are looking at how to fund these offset programs; Shell offers Dutch consumers the possibility of paying to offset emissions from retail fuel. The cost of carbon sinks is uncertain; estimates range from $6 to $120 per tCO2e in 2030, depending on the source and the sequestration target.

Any company can invest in offsets. On the whole, however, upstream and downstream operators have different sets of options at their disposal.

What upstream operators can do

Upstream operations account for two-thirds of sector-specific emissions. Below, we discuss some ways in which oil and gas companies are taking action. The economics will vary greatly, depending on the option and local conditions.

Changing power sources. One oil and gas company is using on-site renewable-power generation to provide a cost-effective alternative to diesel fuel. By replacing generators with a solar PV and battery setup, the company not only reduced emissions significantly but also broke even on its investment in five years. Connecting onshore or nearshore rigs and platforms to the central grid (as opposed to decentralized diesel generation) can also work well: for example, in its drive for electrification, Equinor recently connected its Johan Sverdrup field, which lies 140 kilometers offshore, to the grid. If upstream producers electrified most of their operations, that could add up to 720 tCO2e a year in abatement by 2050, at an estimated cost of $10/tCO2e, depending on local electricity costs.

Reducing fugitive emissions. Companies can cut emissions of methane, a powerful GHG, by improving leak detection and repair (LDAR), installing vapor-recovery units (VRU), or applying the best available technology (such as double mechanical seals on pumps, dry gas seals on compressors, and carbon packing ring sets on valve stems).5 One company replaced the seals in pressure-safety valves, which had been found to be a frequent source of leaks, and then was able to monetize these streams of saved or captured gas. We estimate that reducing fugitive emissions and flaring could contribute 1.5 GtCO2e in annual abatement by 2050, at a cost of less than $15/tCO2e.

Electrifying equipment. One company replaced gas boilers with electric steam-production systems, including high-pressure storage for nighttime steam supply, to support separation units. The project will pay for itself in less than ten years. In many circumstances, there is already a good business case, on purely financial grounds, for combining the use of solar and gas in place of conventional boilers.

Reducing nonroutine flaring through improved reliability. One operator found that 70 percent of all flaring emissions came from nonroutine flaring, mainly as a result of poor reliability. It therefore focused on improving its operations—for example, by carrying out predictive maintenance and replacing equipment. These actions not only reduced emissions but also raised production. Best-in-class operators are making significant strides in reliability thanks to area-based maintenance and multiskilling. Predictive analytics can reduce the frequency of outages to compressors or other equipment.

Reducing routine flaring through improved additional gas processing and infrastructure. While some flaring may be unavoidable, the capacity constraints of infrastructure can lead to more than either companies or the public might want. In the Permian Basin, for example, a record 661 million cubic feet a day (mcf/d) were flared in the first quarter of 2019. Addressing this challenge requires additional gas-processing facilities, as well as gathering and transport infrastructure. The Gulf Coast Express natural-gas pipeline, which went operational in September, will help. An additional 16 billion cubic feet a day (bcf/d) of planned capacity increases on pipelines from the Permian to the Gulf Coast is now under discussion.

Increasing carbon capture, use, and storage (CCUS). While this technology is projected to play only a minor role in the sector’s overall decarbonization, O&G players can still significantly influence its adoption and development. There are 19 large-scale CCUS facilities in commercial operation; four more are under construction and another 28 in development. There are also a number of demonstration and pilot projects. Together, plants under construction and in operation can capture and store about 40 MtCO2e a year. Total CCUS capacity could increase by as much as 200 times by 2050. In this market, the oil industry is well placed to lead because it already uses carbon captured via CCUS for use in enhanced oil recovery (EOR). That oil is also less emissions intensive than the conventionally extracted variety.

A number of countries are looking to accelerate CCUS development. In 2018, for example, the US Congress passed a provision (45Q) increasing the tax credit that power plants and industries can take for either storing or using captured carbon. Congress is considering a bill, known as USE IT, to support the construction of CCUS facilities and CO2 pipelines and to finance research on direct-air capture. The business case for CCUS works only under specific economic conditions, such as tax relief or the imposition of a carbon price. Without some kind of regulatory framework, CCUS does not create value in and of itself.

CCUS costs $20/tCO2e for selected processes in the oil and gas sector but as much as $100 to $200/tCO2e in other industries, such as cement. One undertaking to watch is the Clean Gas Project in northern England, where a consortium of six oil and gas companies is building what could be the first commercial natural-gas plant with full CCUS capacity.

Rebalancing portfolios. Operators are starting to take a close look at their upstream portfolio choices. The highest-emitting reservoirs are nearly three times more emissions intensive than the lowest. For example, complex reservoirs—highly viscous, in deep or ultradeep water, compartmentalized, or high pressure and temperature—may be at a structural emissions disadvantage. They may therefore become increasingly unattractive to develop in the future.

What downstream operators can do

Downstream operators are exploring many of the same ideas, such as energy efficiency and the electrification of low- to medium-temperature heat and energy. But they have distinctive options as well.

Energy efficiency. Efficiency is a factor in every part of the industry, of course, but new downstream-specific technologies can make a big difference. Waste-heat-recovery technology and medium-temperature heat pumps in refineries, for example, reduce the amount of primary energy used in distillation. One company saved €15 million in capital expenditures by forecasting its required steam usage hour by hour and incorporating this into a thermodynamic model to determine the required specifications for replacement equipment.

Green hydrogen. Hydrogen production through electrolysis has become both more technically advanced and less expensive. Bloomberg New Energy Finance estimates that the cost of hydrogen could drop as much as two-thirds by 2050. Using renewable energy rather than steam methane reforming (SMR) to power the electrolysis could offer refineries a way to reduce emissions—a result known as “green hydrogen.” An alternative, “blue hydrogen,” uses SMR plus CCUS. The attractiveness of the different technologies depends on the local economics—in particular, the availability of cheap storage capacity for CCUS or cheap renewable electricity.

Green hydrogen is not a speculative technology in oil and gas. Shell and ITM Power, a UK-based energy-storage and clean-fuel company, are building the world’s largest hydrogen electrolysis plant at a German refinery, with support from the European Union. Revenue will come from selling hydrogen to the refinery, which will use it for processing and upgrading its products and for grid-balancing payments to the German transmission system. That business model justifies the installation.6

High-temperature electric cracking. In refining, several pilot projects use electric coils (instead of fuel gas) to provide heat. The technology is still at an early stage and small in scale. Moreover, the economics are sensitive to the price of electricity compared with gas and to the options for selling the fuel gas. Those economics improve if investment is coordinated with the natural investment cycle to support additional capital expenditures—and, of course, if power can be purchased or generated under favorable financial terms.

Greener feedstocks. Replacing some conventional-oil feedstocks in refineries with biobased feedstocks or recycled-plastic materials (initially, through pyrolysis or gasification) would also reduce emissions—not only Scope 1 but also, to a large extent, Scope 3 emissions. In an increasingly decarbonizing world, this may extend the lifetime of refining assets.


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EIA expects U.S. energy-related CO2 emissions to decrease annually through 2021

In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts year-over-year decreases in energy-related carbon dioxide (CO2) emissions through 2021. After decreasing by 2.1% in 2019, energy-related CO2 emissions will decrease by 2.0% in 2020 and again by 1.5% in 2021 for a third consecutive year of declines.

These declines come after an increase in 2018 when weather-related factors caused energy-related CO2 emissions to rise by 2.9%. If this forecast holds, energy-related CO2 emissions will have declined in 7 of the 10 years from 2012 to 2021. With the forecast declines, the 2021 level of fewer than 5 billion metric tons would be the first time emissions have been at that level since 1991.

After a slight decline in 2019, EIA expects petroleum-related CO2 emissions to be flat in 2020 and decline slightly in 2021. The transportation sector uses more than two-thirds of total U.S. petroleum consumption. Vehicle miles traveled (VMT) grow nearly 1% annually during the forecast period. In the short term, increases in VMT are largely offset by increases in vehicle efficiency.

Winter temperatures in New England, which were colder than normal in 2019, led to increased petroleum consumption for heating. New England uses more petroleum as a heating fuel than other parts of the United States. EIA expects winter temperatures will revert to normal, contributing to a flattening in overall petroleum demand.

Natural gas-related CO2 increased by 4.2% in 2019, and EIA expects that it will rise by 1.4% in 2020. However, EIA expects a 1.7% decline in natural gas-related CO2 in 2021 because of warmer winter weather and less demand for natural gas for heating.

Changes in the relative prices of coal and natural gas can cause fuel switching in the electric power sector. Small price changes can yield relatively large shifts in generation shares between coal and natural gas. EIA expects coal-related CO2 will decline by 10.8% in 2020 after declining by 12.7% in 2019 because of low natural gas prices. EIA expects the rate of coal-related CO2 to decline to be less in 2021 at 2.7%.

The declines in CO2 emissions are driven by two factors that continue from recent historical trends. EIA expects that less carbon-intensive and more efficient natural gas-fired generation will replace coal-fired generation and that generation from renewable energy—especially wind and solar—will increase.

As total generation declines during the forecast period, increases in renewable generation decrease the share of fossil-fueled generation. EIA estimates that coal and natural gas electric generation combined, which had a 63% share of generation in 2018, fell to 62% in 2019 and will drop to 59% in 2020 and 58% in 2021.

Coal-fired generation alone has fallen from 28% in 2018 to 24% in 2019 and will fall further to 21% in 2020 and 2021. The natural gas-fired generation share rises from 37% in 2019 to 38% in 2020, but it declines to 37% in 2021. In general, when the share of natural gas increases relative to coal, the carbon intensity of the electricity supply decreases. Increasing the share of renewable generation further decreases the carbon intensity.

U.S. annual carbon emissions by source

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
Note: CO2 is carbon dioxide.

January, 21 2020
Latest issue of GEO ExPro magazine covers Europe and Frontier Exploration, Modelling and Mapping, and Geochemistry.

GEO ExPro Vol. 16, No. 6 was published on 9th December 2019 bringing light to the latest science and technology activity in the global geoscience community within the oil, gas and energy sector.

This issue focusses on oil and gas exploration in frontier regions within Europe, with stories and articles discussing new modelling and mapping technologies available to the industry. This issue also presents several articles discussing the discipline of geochemistry and how it can be used to further enhance hydrocarbon exploration.

You can download the PDF of GEO ExPro magazine for FREE and sign up to GEO ExPro’s weekly updates and online exclusives to receive the latest articles direct to your inbox.

Download GEO ExPro Vol. 16, No. 6

January, 20 2020
Your Weekly Update: 13 - 17 January 2020

Market Watch   

Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b

  • Tensions in the Persian Gulf have abated, but not disappeared, as both the US and Iran stepped back from going to war; the buck, so far, has stopped with Tehran’s retaliation to the US assassination of its top general with a barrage of missile strikes at US bases in Iraq
  • The underlying situation is still fragile, with the Iranian population swinging from supporting the government to protesting its accidental downing of a commercial Ukraine Airlines plane; with the risk of war easing, crude prices have fallen back to their pre-crisis levels
  • However, American and foreign oil companies have pulled their staff from crude fields in northern Iraq and Kurdistan, including Chevron, as the oil industry in Iraq monitors the risk – and consequences – of military action
  • In precaution, oil tankers have begun boosting their rates once again to haul crude through the Persian Gulf, with quoted rates now at their highest level since the 2019 attacks on ships passing through the narrow straight
  • Although political tensions remain fresh, Saudi Arabia said that OPEC and the OPEC+ club were instead focused on using their window of production cuts to reduce excess oil stockpiles to levels ‘within the contours of 2010-2014’
  • In the US, not only is shale output staying strong, but production in the US Gulf of Mexico also made history, exceeding 2 mmb/d for the first time ever in 2019, beating the previous high recorded in 2018
  • Worries about the health of global oil demand persist… although the US and China signed a Phase 1 trade deal, the agreement is more about halting escalation of the trade war than repairing inflicted damage; a slowdown in Chinese economic growth could lead to oil demand growth halving in 2020 in China according to CNPC
  • The US active rig count fell for a second consecutive week, losing 15 rigs – 11 oil and 4 gas – for the 17th weekly decline of the past 20 weeks; losses in the Permian were once again high, shedding a total of 6 rigs
  • Crude oil prices should remain rangebound with Brent at US$63-65/b and WTI at US$57-59/b, as the market retreats back to its ever-present worries about demand while geopolitical risk premiums scale back


Headlines of the week

Upstream

  • Guyana’s success is now extending to its neighbours, with Total and Apache announcing a ‘significant’ oil discovery at their Maka Central-1 well in Suriname’s Block 58, which lies adjacent to the prolific Stabroek Block
  • BP has agreed to sell its operating interest in the UK North Sea’s Andrew assets – including the Andrew platform as well as the Andrew, Arundel, Cyrus, Farragon, and Kinnoull fields – along with its 27.5% non-operating interest in the Shearwater field to Premier Oil for some US$625 million
  • Liberia will kick start its next offshore licensing round in April 2020, offering nine blocks in the Harper basin, one of the few offshore regions in West Africa that remains unexplored and undrilled
  • Equinor has extended the life of its Statfjord assets beyond 2030, with plans to commission up to 100 new wells over the next decade, deferring decommissioning with a goal of maintaining current output levels beyond 2025
  • After Murphy Oil, Petrofac and ExxonMobil, Repsol is the latest major considering an upstream exit from Malaysia, covering assets that include six development blocks and the major Kinabalu oilfield in Sabah
  • Senegal’s government has approved Woodside’s offshore Sangomar Field Development, which will involve the drilling of 23 subsea wells and a FPSO with the capacity to process up to 100,000 b/d of crude
  • Equinor has announced plans to reduce greenhouse gas emissions from its offshore fields and onshore plants in Norway by 40% by 2030, 70% by 2040 and to near zero by 2050 from 2019 levels

Midstream/Downstream

  • Shell is reportedly seeking buyers for its 144 kb/d Anacortes refinery in Washington state, which would be its third North American sale in two years after divesting its Martinez refinery in California and Sarnia refinery in Ontario
  • Shell has announced plans to increase its share of the Mexican fuel market to 15%, which would require considerable growth in its network of 200 fuel stations in 12 states that currently represent 1% of the market
  • Occidental Petroleum plans to reduce its holdings in Western Midstream Partners – acquired as part of its controversial takeover of Anadarko – to less than 50%, potentially removing up to US$7.8 billion of debt

Natural Gas/LNG

  • Sempra Energy and Saudi Aramco have signed an agreement that will see the Saudi giant play a bigger part in the planned 22 million tpa Port Arthurt LNG project, following an existing agreement to purchase 5 mtpa signed in May 2019
  • Kuwait Petroleum Corp has agreed to purchase 3 million tpa of LNG from Qatar Petroleum for 15 years beginning 2022, with Kuwait remaining one of the few countries in the Middle East that remain neutral to the Saudi-Qatar standoff
  • ExxonMobil has signed an agreement with midstream company Outrigger Energy II to build a 250 mmscf/d cryogenic gas processing, gathering and pipeline system in the Bakken’s Williston Basin in North Dakota
  • The Larak gas field in Sarawak has achieved first gas, operated by SapuraOMV Upstream as part of the SK408 PSC that includes the Gorek and Bakong fields, with output planned to be processed into LNG at Petronas’ Bintulu complex
  • Russia’s TurkStream natural gas pipeline – connecting Russia, Turkey, Bulgaria and eventually Serbia and Hungary - has officially begun operations, delivering up to 13 bcm of Russian gas that can be rerouted from the Ukraine route
January, 17 2020