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Tracing anthropogenic carbon dioxide and methane emissions to fossil fuel and cement producers, 1854–2010 [1]
['Heede', 'Heede Climatemitigation.Com', 'Climate Accountability Institute', 'Snowmass', 'Gateway Road', 'Co', 'Richard Heede', 'You Can Also Search For This Author In', 'Author Information', 'Corresponding Author']
Date: 2014-01-22
For tractability, a threshold of ≥8 million tonnes carbon per year (MtC/y) for fossil fuel production was established. This resulted in the identification of 90 entities: 50 of which are investor-owned companies, 31 are state-owned enterprises, and 9 are current or former centrally planned states. Of these 90 entities 56 are crude oil and natural gas producers, 37 are coal extractors (including subsidiaries of oil & gas companies), and 7 are cement producers. Headquartered in 43 countries, these entities extract resources from every oil, natural gas, and coal province in the world, and process the fuels into marketable products that are sold to consumers in every nation on Earth.
Company production records were retrieved from publicly available annual reports from university and public library collections in Europe, North America, Africa, and Asia, from company websites, company reports filed with the U.S. Securities and Exchange Commission, company histories, and other sources. The carbon content of each entity’s annual production of coal, oil and natural gas liquids, and natural gas was calculated using IPCC, United Nations, International Energy Agency (IEA), and U.S. Environmental Protection Agency (EPA) carbon factors to quantify the annual emissions traceable to each entity. Historically complete records were sought from the earliest records available (the earliest is from 1854) through 2010. Where mergers or acquisitions occurred, carbon production and emissions prior to the date of acquisition are attributed to the extant company.
Since the objective of the analysis is to estimate carbon entering the atmosphere, two important calculations are made. The first is for non-combustion uses of hydrocarbon products.
For crude oil and natural gas liquids (NGLs), non-energy uses include petrochemicals, lubricants, road oil, waxes, solvents, and other industrial uses; for natural gas they include fertilizer production and pharmaceuticals; and for coal include pigments, carbon fibers, and steel making. These non-combustion uses effectively store carbon, and thus must be subtracted from the emission calculations. The net storage rates were derived from 1980 to 2010 data on non-energy uses in the United States following the IPCC inventory and carbon storage protocols (Environmental Protection Agency 2012a, b; IPCC 2006). Short-term combustion of petrochemical products such as plastics in waste-to-energy plants, synthetic tires burned in cement kilns, recycled lubricating oils used as fuel (or oxidized in normal use), wax burning, petroleum coke used in refineries, special naphthas volatilized in paints, and other uses are credited back to the oxidation column in determining the final storage and emission rates for each fuel type. The final net storage rates are 8.02 % for liquids, 1.86 % for natural gas, and 0.016 % for coal.
The analysis accounts for the carbon content of each fuel, and therefore the CO 2 released on combustion to the atmosphere. This is particularly important for coal, since producers report physical quantities rather than heating values (i.e., tons, barrels, or cubic feet rather than energy content). The carbon content factors for each fuel follow international guidelines. The carbon content varies most for coal—from ~33 % carbon for lignites to ~72 % carbon for anthracites—and the rank of produced coal is noted when reported. In many cases producers provided scant guidance on heating values or rank of coal mined, instead using generic labels such as “thermal coal” or “metallurgical coal,” in which cases the average IPCC values for these fuels have been applied. (See Supplementary Materials).
Additional emission sources attributable to oil, gas, and coal operations include CO 2 vented from processing of raw (sour) natural gas, CO 2 from gas flaring (typical at oil production sites where gas is stranded), and fugitive or vented methane from oil and gas operations and coal mining. These emission rates were derived from IPCC Tier 1 factors and corroborated with EPA data on CO 2 and CH 4 leakage, flaring, and venting rates (IPCC 2006; EPA 2012a, b), flaring data from the World Bank (World Bank 2012a), and coal mine methane venting rates using data from U.S. and international sources (EPA 2011, 2012b; Stern and Kaufmann 1998; European Commission 2011). Operational emission rates vary across the global oil, gas, and coal industries by country, company, field location, offshore vs. onshore, surface vs. underground coal mining, and decade of production. In all cases, the factors applied to each producing entity are within the ranges proscribed by credible international sources.
The emission factors, methodology, and results are compared to the Carbon Dioxide Information Analysis Center’s (CDIAC) database of global CO 2 emissions from 1751 to the present (Marland and Rotty 1984; Marland et al. 2011). Methane emission rates are compared to the European Commission’s Joint Research Centre’s edgar database of global CH 4 emissions by source from 1970 to 2008 (extrapolated to 2010; Stern & Kaufmann methane data for 1860–1969). (See Supplementary Materials, and Heede 2013). A global warming potential for methane of 21 × CO 2 (100-year time horizon) is used (IPCC 1996).
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[1] Url:
https://link.springer.com/article/10.1007/s10584-013-0986-y
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