LUMEN provides continuous quantifiable methane detection and real-time cloud-based data for operators
Wireless ground-based and aerial drone-based solutions provide flexibility and cost-effectiveness
Among a range of innovative technologies demonstrated at BHGE’s 20th Annual Meeting
This TED Talk heralds a new era in fighting climate change, from space
Watch this video to learn about a bold, new initiative to combat global warming
EDF and partners are launching a rocket to put a new satellite in orbit that could change the course of global warming in our lifetimes.
MethaneSAT will gather data about a pollutant – methane – that’s warming the planet, and put that data in the hands of people who can easily fix the problem.
EDF President Fred Krupp unveiled the groundbreaking project at TED’s flagship event in Vancouver, British Columbia, as part of The Audacious Project, successor to the TED Prize.
Just the first step will have the same near-term climate benefit as shutting down one-third of the world’s coal-fired power plants.
Fred Krupp, EDF President
Our goal is to cut methane emissions 45 percent by 2025, and the data gathered by this satellite will make that possible. Nothing else will have the same kind of near-term impact at such a low cost.
The power of information
To learn the magnitude of the problem with methane, we collected data with drones, planes, helicopters, even Google Street View cars. It turned out that emissions are up to five times higher than what the government is reporting.
So we didn’t wait for Washington. We published our research, shared it with everyone and saw them take action. Leading oil and gas companies replaced valves and tightened loose-fitting pipes. Colorado became the first state to limit methane pollution. California followed suit, and the public joined in.
By bringing the right people to the table – and leveraging the best of technology, science, data and partnerships – we were able to make the invisible visible, empowering everyone. This enabled us to find new solutions that can be taken to scale and make a lasting impact.
And that’s what the emerging Fourth Wave of environmentalism is all about.
A new industry-led collaborative research consortium will work to advance methane science to better understand global methane emissions and the need for additional solutions.
The Collaboratory for Advancing Methane Science (CAMS) will pursue scientific studies addressing methane emissions from all sectors along the entire natural gas value chain, from production to end use. Studies will focus on detection, measurement, and quantification of methane emissions with the goal of finding opportunities for reduction.
GTI will serve as the program administrator for the effort with initial participants from leading energy companies Cheniere, Chevron, Equinor, ExxonMobil, and Pioneer Natural Resources, and plans to expand participation to include other companies from across the natural gas value chain. Through scientific studies, CAMS will bring together a diverse group of experts from industry, academia, and federal and state agencies to deliver factual data that can be used to inform regulations and policy development.
GTI will manage the overall program, including individual research projects. CAMS members, with input from an independent Scientific Advisory Board, will prioritize and fund research. CAMS will focus on effectively communicating findings to program stakeholders and the general public. Results will be independently published by the research project team in peer-reviewed scientific journals.
“This is an important collaboration between industry, academia, government, and researchers,” said Amol Phadke, vice president, safety and sustainability for U.S. and Mexico operations, Equinor. “It is a great opportunity to work together in understanding emissions across the value chain, giving us a more complete picture of how we can continue to reduce methane from our operations.”
“As a leading energy company, we are committed to continually reducing methane emissions,” said Sara Ortwein, president of XTO Energy, a subsidiary of ExxonMobil. “The right partnerships are critical for success, and participating in CAMS will expand industry learning on solutions that can make a difference.”
“The use of natural gas is already reducing carbon dioxide and traditional air pollutants in the United States and around the world, but further reduction of methane emissions greater amplifies the positive impact of natural gas,” said Chris Smith, SVP for Policy, Government and Public Affairs at Cheniere, the largest U.S. exporter of LNG. “Supporting peer-reviewed science is an important first step as we look for ways to encourage the reduction of methane emissions throughout the domestic natural gas value chain.”
The research will complement recent methane emissions studies sponsored by government agencies and academia, and build on lessons learned from that body of work. New tools and technologies to better detect leaks and characterize emissions will be evaluated, and practical solutions for emissions reduction will be identified.
6/25/18 Des Plaines, IL
In the Paris Agreement of 2015, member states agreed to limit global warming to 2 °C versus pre-industrial levels. This would imply reducing greenhouse gas (GHG) emissions by 80 to 95 percent of the 1990 level by 2050. As industry accounted for about 28 percent of global greenhouse gas emissions in 2014, it follows that these targets cannot be reached without decarbonizing industrial activities. Industrial sites have long lifetimes; therefore, upgrading or replacing these facilities to lower carbon emissions requires that planning and investments start well in advance.
In this report, we investigate options to decarbonize industrial processes, especially in the cement, steel, ethylene, and ammonia sectors. We selected these sectors because they are hard to abate, due to their relatively high share of emissions from feedstocks and high-temperature heat compared to other sectors. We conclude that decarbonizing industry is technically possible, even though technical and economical hurdles arise. We also identify the drivers of costs associated with decarbonization and the impact it will have on the broader energy system.
The industrial sector is both a global economic powerhouse and a major emitter of GHG emissions
The industrial sector is a vital source of wealth, prosperity, and social value on a global scale. Industrial companies produce about one-quarter of global GDP and employment and make materials and goods that are integral to our daily lives, such as fertilizer to feed the growing global population, steel and plastics for the cars we drive, and cement for the buildings we live and work in.
In 2014, direct GHG emissions from industrial processes and indirect GHG emissions from generating the electricity used in the industry made up ~15 Gton CO2e (~28 percent) of global GHG emissions. CO2 comprises over 90 percent of direct and indirect GHG emissions from industrial processes. Between 1990 and 2014, GHG emissions from the industrial sector increased by 69 percent (2.2 percent per year), while emissions from other sectors such as power, transport, and buildings increased by 23 percent (0.9 percent per year).
Almost 45 percent of industry’s CO2 emissions result from the manufacturing of cement (3 Gton CO2), steel (2.9 Gton CO2), ammonia (0.5 Gton CO2), and ethylene (0.2 Gton CO2)—the four sectors that are the focus of this report. In these four production processes, about 45 percent of CO2 emissions come from feedstocks, which are the raw materials that companies process into industrial products (for example, limestone in cement production and natural gas in ammonia production). Another 35 percent of CO2 emissions come from burning fuel to generate high-temperature heat. The remaining 20 percent of CO2 emissions are the result of other energy requirements: either the onsite burning of fossil fuels to produce medium- or low-temperature heat, and other uses on the industrial site (about 13 percent) or machine drive (about 7 percent) (see Exhibit 1).
Exhibit 1: Why are the steel, cement, ammonia, and ethylene sectors hard to abate?
Source: IEA data from World Energy Statistics © OECD/IEA 2017 IEA Publishing; Enerdata: global energy and CO2 data; expert interviews
After breakthroughs in the power, transport, and buildings sectors, industrial decarbonization is the next frontier
Global efforts have driven innovation and the scaling up of decarbonization technologies for the power, buildings, and transport sectors. This has led to major reductions in the costs of these technologies. Examples are the recent reductions in the costs of solar photovoltaic modules and electric vehicles. Less innovation and cost reduction have taken place for industrial decarbonization technologies. This makes the pathways for reducing industrial CO2emissions less clear than they are for other sectors.
Besides that, CO2 emissions in the four focus sectors are hard to abate for four technical reasons. First, the 45 percent of CO2 emissions that result from feedstocks cannot be abated by a change in fuels, only by changes to processes. Second, 35 percent of emissions come from burning fossil fuels to generate high-temperature heat (in the focus sectors, process temperatures can reach 700 °C to over 1,600 °C). Abating these emissions by switching to alternative fuels such as zero-carbon electricity would be difficult because this would require significant changes to the furnace design. Third, industrial processes are highly integrated, so any change to one part of a process must be accompanied by changes to other parts of that process. Finally, production facilities have long lifetimes, typically exceeding 50 years (with regular maintenance). Changing processes at existing sites requires costly rebuilds or retrofits.
Economic factors add to the challenge. Cement, steel, ammonia, and ethylene are commodity products for which cost is the decisive consideration in purchasing decisions. With the exception of cement, these products are traded globally. Generally, across all four sectors, externalities are not priced in and the willingness to pay more for a sustainable or decarbonized product is not yet there. Therefore, companies that increase their production costs by adopting low-carbon processes and technologies will find themselves at an economic disadvantage to industrial producers that do not.
Industrial companies can reduce CO2 emissions in various ways, with the optimum local mix depending on the availability of biomass, carbon-storage capacity and low-cost zero-carbon electricity and hydrogen, as well as projection changes in production capacity
A combination of decarbonization technologies could bring industry emissions close to zero: demand-side measures, energy efficiency improvements, electrification of heat, using hydrogen (made with zero-carbon electricity) as feedstock or fuel, using biomass as feedstock or fuel, carbon capture and storage (CCS), and other innovations.
The optimum mix of decarbonization options depends greatly on local factors. The most important factors are access to low-cost zero-carbon electricity and access to a suitable kind of sustainably produced biomass because most processes in the focus sectors have significant energy- and energy-carrier-related feedstock requirements that could be replaced by one or both of these alternatives. The local availability of carbon storage capacity and public and regulatory support for carbon storage determine whether CCS is an option. The regional growth outlook for the four focus sectors matters, too, because certain decarbonization options are cost-effective for use at existing (brownfield) industrial facilities while others are more economical for newly built (greenfield) facilities.
Since the optimum combination of decarbonization options will vary greatly from one facility to the next, companies will need to evaluate their options on a site-specific basis. To help industrial companies narrow down their options and focus on the most promising ones, we offer the following observations, which account for current commodity prices and technologies (see Exhibit 2):
Energy efficiency improvements can reduce carbon emissions competitively, but cannot lead to deep decarbonization on their own. Energy efficiency improvements that lower fuel consumption by 15 to 20 percent can be economical in the long run. However, depending on the payback times on energy efficiency required by companies (sometimes less than two years), implementation can be less than the potential of 15 to 20 percent.
Where carbon-storage sites are available, CCS is the lowest-cost decarbonization option at current commodity prices. However, CCS is not necessarily a straightforward option for decarbonization. CCS imposes an additional operational cost on industrial companies, whereas further innovation could make alternative decarbonization options (for example, electrification of heat) cost competitive vis-à-vis conventional production technology. CCS can only be implemented in regions with adequate carbon-storage locations, and supportive local regulations and public opinion. CCS has the distinction of being the only technology that can currently fully abate process-related CO2 emissions from cement production.
At zero-carbon electricity prices below ~USD 50/MWh, using zero-carbon electricity for heat or using hydrogen based on zero-carbon electricity becomes more economical than CCS. Electricity prices below USD 50/MWh have already been achieved locally (e.g., hydro and nuclear-based power-system of Sweden) and could be achieved in more places with the current downward cost trend in renewable electricity generation. The minimum price that makes it less expensive to switch to zero-carbon electricity than to apply CCS for decarbonization depends strongly on the sector, local fossil fuel and other commodity prices and the state of the production site.
» At electricity prices below ~USD50/MWh, electrifying heat production at greenfield cement plants is more cost-competitive than applying CCS to the emissions from fuel consumption, provided that very-high-temperature electric furnaces are available.[7, 8]
» At electricity prices below ~USD35/MWh, hydrogen use for greenfield ammonia and steel production sites is more cost-competitive than applying CCS to conventional production processes.
» At electricity prices below ~USD25/MWh, electrification of heat in greenfield ethylene production and in brownfield cement production and usage of hydrogen for brownfield steel production are more cost-competitive than applying CCS to conventional production processes.
» Finally, below an electricity price of ~USD15/MWh, usage of hydrogen for brownfield ammonia production and electrification of heat for ethylene production are more cost-competitive than applying CCS to conventional production processes. This means that electric heat production and usage of electricity to make hydrogen are more economical approaches to decarbonization than CCS in all four focus sectors at this electricity price level.
Exhibit 2: With low electricity prices, cost-based trade-offs will favor more electrification and hydrogen than CCS
Lower costs for capital equipment or process innovations could make electrification or the use of zero-carbon electricity based hydrogen economical at higher electricity prices.
Using biomass as a fuel or feedstock is financially more attractive than the electrification of heat or the use of hydrogen in cement production and at electricity prices above ~USD 20/MWh in steel production. Mature technologies are available for using biomass as fuel and feedstock in steel and as fuel in cement production. These technologies reduce emissions more economically than CCS on the conventional process. Biomass can also replace fossil fuel feedstocks for ethylene and ammonia production. Though this approach costs more than electrification or hydrogen usage, it also abates emissions in both the process and at end-of-life of the product, such as the emissions from incineration of plastics made from ethylene. The global supply of sustainably produced biomass, however, is deemed limited at the global level. Additionally, re-forestation to generate offsets might be a counter use of biomass rather than the shipping and usage in industrial processes.
Demand-side measures are effective for decarbonization but were not a focus of this report. Replacing conventional industrial products with lower-emission alternatives (e.g., replacement of cement with wood for construction) would result in significant reductions in CO2 emissions from the four focus sectors. Radical changes in consumption patterns driven by technology changes could further offset demand, such as reduced build-out of roads (and therefore cement) through autonomous driving, reduced demand for ammonia through precision agriculture. Moreover increasing the circularity of products, by e.g., recycling or reusing them can also cut CO2 emissions. Producing material based on recycled products generally consumes less energy and feedstock than the production of virgin materials. As an example, producing steel from steel scrap requires only about a quarter of the energy required to produce virgin steel.
Industrial decarbonization will require increased investment in industrial sites and has to go hand in hand with an accelerated build-out of zero-carbon electricity generation
Completely decarbonizing the energy-intensive industrial processes in the four focus sectors will have a major impact on the energy system. It is estimated that it would require ~25 EJ to 55 EJ per year of low-cost zero-carbon electricity. In a business-as-usual world, only 6 EJ per year would be needed, indicating that, regardless of the mix of decarbonization options chosen, electricity consumption will go up significantly. The transition in the power and industrial sectors should thus go hand in hand. The industrial sector might be able to lower the costs of the power sector transition, e.g., by providing grid balancing, while being a large off-taker that can support increased build-out of generation capacity.
The total costs of fully decarbonizing these four sectors globally are estimated to be ~USD 21 trillion between today and 2050. This can be lowered to ~USD 11 trillion if zero-carbon electricity prices come down further compared to fossil fuel prices (see Exhibit 3). These estimates are based on cost assumptions that do not allow for process innovations or significant reductions in the costs of capital equipment. Furthermore, they heavily depend on the emission reduction target, local commodity prices, the selected mix of decarbonization options, and the current state of the production site. The estimated costs for complete decarbonization of the four focus sectors are equivalent to a yearly cost of ~0.4 to 0.8 percent of global GDP (USD 78 trillion). According to the estimations in this report, about 50 to 60 percent of these costs consist of operating expenses and the remainder consists of capital expenditures, mainly for cement decarbonization.
An analysis of the effects of different electricity prices suggests that decarbonization would have an upward impact on the costs of the industrial products: cement doubling in price, ethylene seeing a price increase of ~40 to 50 percent, and steel and ammonia experiencing a ~5 to 35 percent increase in price.
Exhibit 3: The total costs of decarbonization are highly dependent on the electricity price
Source: McKinsey Energy Insights
Advance planning and timely action could drive technological maturation, lower the cost of industrial decarbonization and ensure the industry energy transition advances in parallel with required changes in energy supply
Governments can develop roadmaps for industrial decarbonization on local and regional levels. Setting such a longer-term direction for decarbonization could support planning for decarbonization by other parties, including industrial companies, utilities and owners of key infrastructure (such as the electricity grid or hydrogen pipelines), and unlock investments with long payback times. Such a roadmap should take a perspective, e.g., on the production outlook, resource availability (including carbon-storage sites), additional resources required (zero-carbon electricity generation, etc.), coordinated roll-out of infrastructure and demand-side measures, as well as the role government would play (e.g., in the development of critical infrastructure).
Adjust regulation and incentives in line with decarbonization roadmaps. Various policy mechanisms could support industrial decarbonization. These might include direct incentives for companies to decarbonize or adjustments to the financial requirements placed on utilities and other companies involved in energy generation and distribution.
Industrial companies should prepare for decarbonization by conducting a detailed review of each facility in their portfolio. Such a review should include the availability of low-cost zero-carbon electricity, zero-carbon hydrogen, biomass, and carbon-storage capacity near the facility as these will differ on a country-by-country basis. Interaction with other stakeholders, such as governments, utilities, and other industrial companies, could help to identify synergies between industrial decarbonization and decarbonization in other sectors or companies, driving targeted innovation and driving down costs. For example, companies in an industrial cluster might benefit from shared carbon-storage infrastructure.
Governments, industrial companies, and research institutions can support innovation and the scale-up of promising decarbonization technologies, which is required to reach full decarbonization of the industrial sector. Innovative decarbonization technologies could potentially lower the costs of the industry transition. Governments can support the development of innovative decarbonization options, including the scale-up of global markets, e.g., in certain types of biomass, or the introduction of innovative processes to lower implementation costs. Overall, decarbonizing industrial sectors requires collaboration across governments, industrial players, and research institutes, similar to the effort that led to the cost reduction and scale-up of renewable energy generation.
McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.
About the authors
Occo Roelofsen is a Senior Partner, Arnout de Pee is a Partner, Eveline Speelman is an Associate Partner, and Maaike Witteveen is an Engagement Manager in McKinsey’s Amsterdam office. Dickon Pinner is a Senior Partner in McKinsey’s San Francisco office and Ken Somers is a Partner in McKinsey’s Antwerp office.
 Feedstocks are the raw materials that companies process into industrial products. High-temperature heat is defined in this report as a temperature requirement above 500 °C.
 Based on IEA data from the World Emissions Database © OECD/IEA 2018, IEA Publishing; modified by McKinsey.
 Breakdown of emissions is defined by the use of various reports and datasets, most importantly IEA, Enerdata, heat and cooling demand, market perspective (JRC 2012), and sector energy consumption flow charts by the US Department of Energy combined with input from experts. Activities up and down the value chain are not included in these numbers and could lead to additional emissions, e.g., transportation of fuel to the production site or incineration of ethylene-based plastics at end of product life.
 Other innovations can be non-fossil-fuel feedstock change (e.g., alternatives for limestone feedstock in cement production) and other innovative processes (e.g., reduction of iron ore with electrolysis).
 At the current state of technology, process emissions from cement production can only be abated by a change in the feedstock. Alternatives for the conventional feedstock (limestone) are not available (yet) at scale. Hence, decarbonizing cement production currently relies on CCS.
 The zero-carbon electricity price should be the average wholesale industrial end user price, so including, e.g., transmission, distribution, and storage costs.
 Electrification of very-high-temperature heat (>1,600 °C) required in cement production would require research, as these temperatures are not yet reached in electric furnaces.
 Process emissions from cement production cannot be abated by a fuel change and therefore require CCS, irrespective of electricity prices.
 These total costs include all capital and operational costs on industrial sites, but exclude other costs, e.g., build-out of zero-carbon electricity generation capacity.
 Conventional prices assumed are: cement USD 120/ton, steel USD 700/ton, ammonia USD 300/ton and ethylene USD 1,000/ton.
Increased awareness of methane’s impact on the environment is leading to increased monitoring for methane leaks. In order to reduce the amount of methane emitted into the atmosphere, we need better detection technologies. Last summer, EDF collaborated with the world’s largest oilfield service company – Schlumberger – to test a variety of stationary and hand-held technologies to detect methane leaks from equipment in the upstream oil and gas sector. To learn more about how technology and innovation can help solve the methane problem visit business.edf.org.
Published on Mar 29, 2018
What is the GEDS Certificate?
A multidisciplinary certification that:
Provides the analytical tools and frameworks necessary for assessing and addressing the long-term social, economic, and environmental impacts of oil and gas projects.
Introduces “best-practices” for creating energy projects that benefit all stakeholders (communities, companies, governments) in developing nations and new production regions.
Teaches students the historical and structural origins of the “Natural Resource Curse” as it manifests in different regions of the globe, and how to plan for and mitigate its effects.
Because the technical expertise of companies and governments has traditionally been focused on the efficient discovery and extraction of oil and gas resources, the skills required for developing energy projects that are sustainable and beneficial to all stakeholders (communities, companies, and governments alike) have not always been prioritized in training for an oil and gas career.
The Graduate Certificate in Global Energy, Development, and Sustainability (GEDS) provides students with such skills, imparting them through a unique, multi-disciplinary curriculum focused on the petroleum industry and its impact on societies. Classes are designed and taught by UH faculty and local/international energy experts with long academic, industry, and civil society/NGO experience. The certificate is one-of-a-kind, providing critical and timely knowledge, theory, and skill sets from fields such as business, economics, global oil and gas history, anthropology, environmental law/policy, international petroleum law, human rights law, political science, industrial occupational psychology, human resource management, corporate social responsibility, and risk analysis.
The GEDS Certificate is of benefit to those working or intending to work in the energy sector – including industry professionals, government officials and regulators, members of civil society or NGO activist/policy groups, energy consultants and financial advisors. Graduate students who are interested in energy, sustainability, and global or domestic energy policy are invited to apply as well.
Join us as we work to chart a course for a sustainable energy future, one that will benefit all stakeholders and help navigate the transitions to come!
The world is demanding more energy every day to support growth and prosperity. At the same time, it’s demanding energy with fewer emissions. At BP we’re taking on this dual challenge across all of our business activities. We’re growing our business, providing more energy to the world. And at the same time, we’re reducing emissions in our operations, improving our products and creating low carbon businesses. This is how BP is helping the world transition to a low carbon future. As part of this, we are setting some new and important targets. Head to bp.com/energytransition for details.
Published by BP on Apr 16, 2018
Decommissioning, Featured 1, International, Offshore Operations, OFFSHORE OPERATIONS, Sustainability, Technology
The Asia Pacific region is set to follow the North Sea in increasing its decommissioning activity over the next decade. Indonesia, Brunei, Malaysia and the rest of the region is home to 833 installations that are on or over 20 years old – the average life expectancy of offshore assets. But with so much of the region’s infrastructure under threat from decommissioning, many have questioned the impact to the environment.
A thought piece by the National University of Singapore (NUS) singled out the importance of rig to reef in this context back in 2012. In this blog, we explore what could be done in the region to both keep the integrity of the sea bed and complete decommissioning applications as efficiently as possible.
Rig-to-reef (RTR) is the practice of converting decommissioned platform infrastructure into artificial reefs for the seabed. The practice has already proved popular in the Asia Pacific when the storm-damaged Baram-8 in Malaysia was made into an artificial reef. Despite there being no current RTRs in place in the region, there is sure to be an appetite as decommissioning work increases.
Rigs prove popular with sea life, especially as they become an integral part of the seabed over their 20-30 year life span. An OCS report that focussed on the Gulf of Mexico in 2000 stated that fish densities were 20-50 times higher around the platforms than anywhere else in open water – a true sign that artificial reefs work.
PROS OUTWEIGH THE CONS
While operators may look towards asset life extension techniques to keep relevant rigs operating, those who are set to decommission will be pleased to know that the pros outweigh the cons in terms of implementing RTRs with old assets.
Despite potential navigational issues around the Asia Pacific region, operators creating RTRs could benefit from being more environmentally friendly, increasing fisheries in the field, and potentially negating costs such as rig disposal. The question on whether RTRs would be welcome in the region are so far undecided and confusing by governing bodies, according to the NUS.
GIVEN THE GREEN LIGHT
In her presentation for the National University of Singapore, Youna Lyons highlighted the large discrepancy between governing bodies and law in the Asia Pacific region that meant operators looking to RTRs would be left confused as to whether they could undertake a project after decommissioning.
“(While) international law does not prevent the re-use of rigs as artificial reefs, provided that it does not compromise the safety of navigation, IMO guidelines (on the matter) are inadequate. A paradigm shift is needed in the approach.”
The biggest issue seems to be the safety of navigation around such artificial reefs by shipping traffic. That aside, the law states that rigs can be re-used, it is just a case of where they will be able to be positioned.
RIG TO REEF IS VITAL
In summary, the presentation reveals how vital rig to reefs can be for both operators and environment. While operators can potentially save money, and enhance the environment they’ve extracted from, the seabed and sea life can see drastic increases in activity if the manmade reefs are positioned well – as long as governing bodies and local authorities agree, Asia Pacific could benefit from more RTRs in the future.
THE INCREASE OF DECOMMISSIONING
As operators around the world review their aged assets, in the current climate it is no surprise to see decommissioning projects beginning on non-profitable rigs. In the Claxton Engineering Decommissioning Case Study Pack, you will learn how the Claxton team have already helped operators on their decommissioning projects and helped to save time and money too.
To find out more about the free offshore Decommissioning Case Study Pack, and to get your hands on a copy, click here.
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