Mikaila Adams
Editor-News
Calls for clear regulatory policies toward a lower-carbon economy are growing. The challenge to provide energy to a bourgeoning world population in a reliable, sustainable way is yet to be solved. Amid the uncertainty, oil and gas companies globally are preparing for decarbonization of varying degrees—working to reduce greenhouse gas emissions and improve the economics of renewable energy projects.
This article will shine some light on various companies that are grappling with reducing carbon emissions while attempting to scale renewable projects.
Greenhouse gas emissions
BP PLC aims to generate sustainable reductions of 3.5 million tonnes/year of carbon dioxide equivalent (CO2e) greenhouse gas emissions (GHG) throughout its businesses by 2025. Improving energy efficiency throughout the businesses supported by new technology, limiting the emissions intensity of methane, and reducing flaring of oil and gas are expected to deliver permanent and quantifiable reductions in emissions, the company has said.
In 2017, BP accredited a program of sustainable emissions reductions achieved across its portfolio. At its Greater Plutonio oil and gas field in Angola, the company implemented a program to reduce the frequency of inspections of the floating production, storage, and offloading vessel used to operate the field. Using a magnetic crawler robot instead of divers led to more than 11,000 tonnes of e being saved in 2017’s final quarter.
At Prudhoe Bay oil field in Alaska, a program to replace gas-powered compressors with electric ones in a flow station helped save almost 70,000 tonnes of CO2e.
In East Texas, BP is optimizing compression by replacing larger compressor engines with smaller ones to match current production levels. Six compressor replacements in 2017 saved 900 tonnes of CO2e. Replacing steam-driven turbines used to pump cooling water with electric-driven pumps at the Whiting refinery in Indiana led the company to save some 5,000 tonnes of CO2e in last-quarter 2017.
A large producer of oil and gas, Norway’s Equinor emitted about 15 million tonnes of CO2e from its operated portfolio in 2017. Emissions reduction measures summing up to about 1.8 million tonnes/year of CO2 by 2016 compared with emissions in 2008, largely through better energy management, technical design, and flaring reductions. The company is accelerating efforts to achieve reductions amounting to a further 3 million tpy of CO2 by 2030 compared with estimated emissions in 2017. The company said it will systematically pursue energy efficiency measures, electrification, and other low-carbon energy sources at its installations.
In 2012, Equinor set a company-wide upstream flaring intensity target of 0.2% by 2020 for its operated assets. It aims to stop routine flaring in its operations by 2030 at the latest, in line with the World Bank’s “Zero Flaring by 2030” initiative. Routine flaring is not used in its Norway operations. Currently Equinor’s upstream flaring intensity for operated assets is around 0.2% of hydrocarbons produced, aligned with its 2020 target and lower than the industry average of 1.3%.
Equinor has progressed its efforts with carbon capture and storage (CCS) investments. To date, the company has captured and stored more than 23 million tonnes of CO2. The company is working to develop new business models to make CCS commercially viable and leading studies on behalf of the Norwegian authorities to develop full-scale CCS in Norway. The concept includes capturing CO2 from onshore industry, transporting it by ships and injecting and permanently storing it 1,000-2,000 m below the seabed.
ExxonMobil Corp. has detailed its GHG reduction efforts in three stages. In the near term, the supermajor is working to increase energy efficiency and reduce flaring, venting, and other emissions in its operations. In the medium term, it is deploying proven technologies such as cogeneration and CCS where technically and economically feasible. Longer term, the company is conducting and supporting technological research. Since 2000, ExxonMobil has spent more than $9 billion to develop lower-emission energy solutions. Of that, $4 billion has been invested in the company’s efficiency and flare mitigation at the company’s upstream facilities, and $2 billion at its refining and chemical facilities.
In 2017, ExxonMobil’s net equity GHG emissions were 122 million tonnes of CO2e. Relative to its 2016 performance, its 2017 emissions decreased by about 1 million tonnes of CO2e. The decrease was primarily driven by flaring reductions in Angola.
In the US, ExxonMobil and its subsidiary XTO Energy Inc. established a methane management program that exceeds applicable regulations. The program prioritizes actions at the highest-volume production and midstream sites and includes efforts to develop and deploy new, more-efficient technologies to detect and reduce facility emissions. In the US in 2016, XTO reported 205,000 tonnes (5.1 million tonnes of e) of methane emissions. Specifically for upstream operations, XTO-operated production emissions equate to about 410 methane tonnes per million bbl of oil-equivalent production, an emissions rate of 0.36%. XTO accounts for more than two thirds of ExxonMobil’s methane emissions. Over the next 3 years, the company will voluntarily switch out more than 1,000 high-bleed pneumatic devices for lower or no-bleed devices that can substantially reduce emissions. The company also has implemented an enhanced leak detection and repair program that prioritizes our largest-volume sites and greatest opportunities for emission reductions. Planned events such as liquid unloading will be managed to reduce the release of methane emissions to the atmosphere. Liquid unloading removes liquid that has collected in equipment tubing and prevents natural gas from flowing up through the well. As part of the program, field personnel monitor and remain nearby during the manual unloading process to close all wellhead vents to the atmosphere.
In addition, ExxonMobil continues to evaluate opportunities to upgrade facilities to reduce emissions. This includes research in collaboration with equipment manufacturers to develop state-of-the-art, low-cost, minimum-emissions equipment.
Chevron Corp. is addressing the GHG emissions in its operations and integrating GHG emissions management into the execution of its business activities. Methane from process emissions, vented sources, and combustion sources (including flares) accounted for 5.5% of Chevron’s total GHG emissions in 2017. Fugitive sources of methane comprised 1.6%. In 2017, the company reduced its enterprise wide flare gas volume rate by 18.7%, primarily due to improvements made in equipment reliability in its Australasia, Nigeria and Mid-Africa, and Southern Africa business units.
At Tengizchevroil in Kazakhstan, in which Chevron has a 50% interest, the company achieved a 94% reduction in the volume of gas flared during 2000-10 through projects such as the $258-million gas utilization project.
Since 2008, activities carried out by the Nigerian National Petroleum Corp.-Chevron Nigeria Ltd. joint venture have reduced routine gas flaring by more than 90% in the Niger Delta. The company also has made progress in reducing flare gas volumes in Angola. Its Nemba Enhanced Secondary Recovery Project reduced flaring at the South and North Nemba fields by almost 34 MMscfd of gas in 2016. In total, flare-gas volume rates in Chevron’s Angola operations have been reduced by more than 50% since 2013.
In a February update, Chevron said it has retrofitted or replaced more than 1,000 continuous high-bleed pneumatic controllers from its onshore US facilities with low-emitting or noncontinuous-bleed technologies to reduce emissions. In addition, the company is partnered with Houston-based Rebellion Photonics to develop and deploy gas imaging technology currently used primarily as an early warning system for gas loss of containment. Chevron is currently working with Rebellion to apply its technology to methane detection to enable further emissions reductions.
Royal Dutch Shell PLC has noted that managing its CO2 performance is an important part of its long-term resilience. At its petrochemicals complex in Pennsylvania, the company will use a cogeneration facility to produce both heat and electricity for the plant as well as surplus electricity that will be exported to the grid at a lower CO2 intensity than the regional average. The plant also will have a highly efficient ethylene cracker that will result in top quartile CO2 intensity, Shell said, citing benchmarking specialists Solomon. The plant is expected to begin commercial production early in the next decade.
In Canada, Shell has included measures to reduce carbon intensity at its Groundbirch asset, a tight shale gas operation in British Columbia. These include using electricity instead of gas for the processing plant, using gas instead of diesel to power drilling, and using solar energy to power pumps.
The company actively considers the use of CCS to reduce emissions from its projects. Where CCS is not economically feasible at current CO2 prices, it reports, some projects are designed to be available for future CCS retrofits. Company standards require that operating assets with CO2 emissions of more than 50,000 tpy of CO2e create GHG management plans that seek to improve CO2 performance.
At its Pearl gas-to-liquids plant in Qatar, Shell is using heavy paraffin synthesis off-gas as a fuel to power the plant. Previously flared, this use of the fuel has helped the company reduce overall emissions by 700,000 tpy of CO2.
Abu Dhabi National Oil Co. (ADNOC) plans to further reduce GHG emissions by as much as 10% by 2023 and substantially increase its use of carbon capture, utilization, and storage (CCUS) technology. The company touts one of the lowest methane intensities of 0.01%. At the same time, ADNOC has reduced the volume of gas flared by more than 72% since 1995.
The company plans to expand the capture of CO2 from its operations for use in enhanced oil recovery. Starting in 2021, ADNOC will gradually increase the utilization of CO2, reaching 2.3 million tons/year by 2025, by capturing additional CO2 from its gas processing plants and injecting it into different onshore oil fields. ADNOC’s Al Reyadah facility is already capable of capturing 800,000 tons/year of CO2.
ADNOC also plans to invest $1.8 billion by 2023 in projects aimed at flaring and unintended emissions abatement, energy efficiency, and CCUS. The investment is on top of the $2.3 billion spent for the efforts from 2012-17.
Biofuels
Biofuels could potentially play a role in reducing GHG emissions and meeting future energy needs. Companies are working to develop ways to make the technology scalable, sustainable, and affordable.
Shell is active in the development of advanced biofuels made from alternative feedstocks such as waste and cellulosic biomass from nonfood plants. In 2015, Raizen—a joint venture formed in 2010 from the merger of the assets of sugar, fuel, and ethanol derived from sugar from Cosan and Shell in Brazil—opened its first advanced biofuels plant at its Costa Pinto mill in Brazil. In 2017, the plant produced 10 million l. of cellulosic ethanol from sugarcane residues. It is expected to produce 40 million l./year once fully operational. In Bangalore, India, Shell has built a demonstration plant that will turn waste—including food, cardboard, plastics, and paper—into gasoline or diesel that can power cars, providing the final stage for a research and development process to see it can scale-up and support the commercialization. The process, called IH2, has been developed by US-based research center Gas Technology Institute. The IH2 process uses heat, hydrogen, and catalysts to convert large molecules of the sort found in waste into smaller fragments. Oxygen and other contaminants are removed to create two pure elements: hydrogen and carbon. The two are then combined to create hydrocarbon molecules: gasoline, diesel and jet fuel.
BP, too, is advancing biofuels in Brazil—one of the largest markets globally for ethanol fuel—where it produces ethanol from sugarcane. The ethanol has lifecycle GHG emissions that are 70% lower than conventional transport fuels. In 2017, BP’s three sites produced 776 million l. of ethanol equivalent. To better connect its ethanol production with the country’s main fuels markets, BP partnered with ethanol and sugar trader Copersucar to operate a major ethanol storage terminal.
Butamax, BP’s 50-50 joint venture with DuPont, has developed technology that converts sugars from corn into an energy-rich biofuel known as bio-isobutanol. It can be blended with gasoline at higher concentrations than ethanol and transported through existing fuel pipelines and infrastructure. Butamax plans to upgrade the ethanol plant it acquired in Kansas to enable it to produce bio-isobutanol.
In late January, ExxonMobil and Renewable Energy Group (REG) announced a joint research agreement with Clariant to evaluate the potential use of cellulosic sugars from sources such as agricultural waste and residues to produce biofuel. The new agreement with Clariant allows ExxonMobil and REG to further optimize REG’s bioconversion process using previously tested and benchmarked cellulosic sugars created through Clariant’s sunliquid process. Clariant will conduct trials at its precommercial plant in Straubing, Germany, using different types of cellulosic feedstock that will be converted into sugars for conversion by REG and ExxonMobil into high-quality, low-carbon biodiesel.
In 2017, ExxonMobil and Synthetic Genomics announced a breakthrough in joint research into advanced biofuels involving the modification of an algae strain that doubled its oil content without substantially inhibiting the strain’s growth. In May 2018, the companies moved into a new phase in the program that includes an outdoor field study that will grow naturally occurring algae in contained ponds in California. The research will enable the companies to better understand fundamental engineering parameters including viscosity and flow, which cannot easily be replicated in a lab. Results are important to understand how to scale the technology for potential commercial deployment, ExxonMobil said, noting that the program could lead to the technical ability to produce 10,000 b/d of algae biofuel by 2025.
At its La Mede biorefinery in France, Total SA aims to meet the growing demand for biofuels. Once operational, it will produce 500,000 tpy of HVO-type biodiesel. The La Mede biorefinery project is coupled with a plan for continuous improvement of the facility’s energy efficiency, with the aim of reducing energy consumption by 8% by 2020.
Solar
Investing in solar energy, BP has partnered with Lightsource, Europe’s largest solar development company, which focuses on the acquisition, development, and long-term management of largescale solar projects. Working to help accelerate Lightsource’s expansion worldwide, BP is investing $200 million in the company—rebranded as Lightsource BP—over 3 years and will hold a 43% stake in the company with two seats on the board.
Chevron’s photovoltaic (PV) projects at Questa, NM, and in California’s San Joaquin Valley test and evaluate solar technologies. Project Brightfield, in Bakersfield, Calif., has evaluated seven PV technologies to determine the potential application of renewable power at other company-owned facilities. The company also has invested in five joint venture PV solar facilities, in California, Arizona, and Texas, which, at peak capacity, generate a combined 73 Mw of renewable energy, or enough electricity to power 60,000 homes for a year.
Shell is expanding the deployment of solar PV in its operations. In California, the company is delivering a PV project to provide on-site solar power to the Stockton fuels distribution terminal. In 2018, at its Moerdijk chemicals site in the Netherlands, the company installed a 20-Mw project to provide 3% of the factory’s energy. In Oman, Shell holds a 34% share in Petroleum Development Oman, which is building a 1-Gw solar thermal plant. It will make energy production in Oman less carbon-intensive by using sunlight to generate 6,000 tonnes/day of steam needed in daily operations.
In October 2017, in its first step into the solar industry, Equinor acquired a 40% share in the Apodi Solar plant in Brazil. Commercial operation of the 162-Mw plant operated by Scatec Solar in the municipality of Quixere in Ceara state began in November 2018. Now powering 170,000 homes, the plant is expected to provide about 340,000 Mw-hr/year of electricity. In December 2018, Scatec Solar began construction on the Guanizuil IIA solar plant in the Province of San Juan in northwest Argentina. The $103-million plant—expected to produce 308,000 Mw-hr/year of electricity—will be owned 50-50 with Equinor.
Entering the solar power plant market with the acquisition of a controlling interest in SunPower in 2011, Total has developed and operates solar power plants worldwide. In March 2017, Total started up its first solar power plant in Japan in Nanao on the Noto Peninsula on the country’s west coast. The plant generates enough power to serve 9,000 households through more than 80,000 high-efficiency SunPower solar panels. Following its start-up, the company began work on a new site on the east coast of Japan in Miyako (Iwate prefecture), where it is building a second plant with an equivalent capacity.
Total was selected to build and operate one of Africa’s largest ground-mounted PV solar power plant in Prieska, South Africa. The plant came on line in 2016.
Along with its SunPower affiliate, Total was selected by the South African government to build a ground-mounted PV solar power plant in Prieska in Northern Cape province. With a capacity of 75 Mw-AC, the plant will supply electricity to 75,000 homes.
In partnership with Madar and Abengoa Solar, Total built one of the largest concentrated solar thermal power plants in the world. In operation in the Abu Dhabi desert since March 2013, the 100-Mw Shams supplies over 20,000 homes.
Solar Star, in Rosamond, Calif., is one of the world’s largest PV power plants. Developed by Total’s SunPower affiliate and owned by BHE Solar, the 700-Mw plant, which came on line in 2015, provides solar electricity to 255,000 homes in California via more than 1.7 million ground-mounted high-efficiency SunPower solar panels.
In the Atacama region of Chile, Total’s SunPower affiliate built one of the world’s largest merchant solar power plants. SunPower now operates and maintains the 68-Mw-AC plant, which has been producing electricity for Chile since early 2015. With 160,000 PV modules, PV Salvador supplies electricity to 70,000 homes. The plant is owned by Etrion 70%, Total 20%, and Solventus, 10%.
Wind
Many energy companies are harnessing the power of wind.
Chevron’s Casper Wind Farm, commissioned in 2009, has turned a former refinery site near Casper, Wyo., into an 11-turbine, 16½-Mw wind farm, which, at peak capacity, produces enough electricity to power 13,000 homes for a year.
BP is one of the largest operators of renewable energy businesses among its peers, with 11 onshore wind farms in the US with a gross generating capacity of some 1,800 Mw. The company directly operates 10 wind farms in Colorado, Idaho, Indiana, Kansas, Pennsylvania, South Dakota, and Texas while holding an interest in a separate wind facility in Hawaii. In 2018, BP partnered with Tesla to install a high-storage battery at its Titan 1 wind farm in South Dakota. The project is a potential step forward in the performance and reliability of wind energy.
Shell, in partnership with Innogy SE, and Stiesdal Offshore Technologies AS (SOT), made final investment decision in February on the TetraSpar floating foundation demonstration project, which will be tested offshore Norway in 2020. Its modular layout consists of a tubular steel main structure with a suspended keel. It is expected to offer important competitive advantages over existing floating wind concepts, with the potential for leaner manufacturing, assembly, and installation processes with lower material costs. Shell increased its share in the project to 66% from 33%. Innogy retains 33% and SOT is contributing with its modular TetraSpar concept and holds the remaining shares (1%). As technology partner, Siemens Gamesa Renewable Energy will provide the wind turbine and required services. The partners will be part of a project team that will gain detailed, practical insights into the construction, installation, and operation of the TetraSpar concept as well as detailed performance data.
In another venture, Shell, through Mayflower Wind Energy LLC—a 50-50 joint venture of Shell New Energy US LLC and EDPR Offshore North America LLC—will work to complete a site assessment plan and initiate formal development efforts for a wind farm that, subject to a positive final investment decision, could be operational by the mid-2020s.
Mayflower Wind was declared the provisional winner of one of three lease blocks up for grabs in the online offshore wind auction concluded Dec. 15, 2018, by the US Department of the Interior’s Bureau of Ocean Energy Management. With its $135-million bid, the venture hopes, once constructed, the lease area could accommodate a total generation capacity of 1.6 Gw, enough to power more than 680,000 average homes each year.
Another provisional winner in Massachusetts’ wind lease sale is Equinor, whose total US offshore wind portfolio has the potential to power more than 2 million homes. The company submitted a winning bid of $135 million for the opportunity to explore the potential development. In December 2016, Equinor won the federal lease auction of 80,000 acres south of New York and east of New Jersey and is currently developing projects in the area for the offshore-wind markets in both states: Empire Wind in New York and Boardwalk Wind in New Jersey.
In addition, Equinor is involved in various wind projects worldwide, including four in the UK and one in Germany. In December, Equinor exercised an option to acquire a 50% interest in the offshore wind development project Baltyk I in Poland from Polenergia. The deal is a follow-up to one struck earlier in the year by which Equinor acquired a 50% interest in Baltyk II and Baltyk III.
While three of its UK wind farms employ conventional, bottom-fixed turbines, Hywind Scotland employs floating wind turbines. As much as 80% of the of the total potential for offshore wind power is believed to be in deep water, the company has said. The farm consists of five 6-Mw turbines with a total installed capacity of 30 Mw, and a transmission voltage of 33 kV.
The 88-Mw Hywind Tampen offshore wind project off Norway could become the world’s first project to use wind turbines for electrification of oil and gas installations. Equinor and its partners in Gullfaks and Snorre oil fields in the Norwegian Sea are considering the use of floating wind turbines to supply electrical power to the platforms. Norway’s industry NOx Fund has agreed to provide as much as $67.8 million in support for the project, and a final investment decision is possible this year, Equinor said. Snorre and Gullfaks partners also have applied for support from Enova’s program for full-scale innovative energy and climate measures.
In February, Equinor let two related contracts. Wergeland Base in Gulen Industrial Harbour in Sogn og Fjordane was signed for assembly of the floating Hywind Tampen wind turbines before they are transported to the field. The licensees are currently maturing the project towards any investment decision and no work will begin prior, Equinor reported. Kvaerner was signed to study the design and construction of floating concrete substructures for the project.
With a combined capacity of 88 Mw from 11 floating turbines with individual capacity of 8 Mw, Hywind Tampen could meet about 35% of the annual power demand of the Snorre A and B and Gullfaks A, B, and C platforms, lowering CO2 emissions by more than 200,000 tpy.
