Projected supply and disposition of crude oil

The model now uses the EIA’s projections of production, imports, and consumption of crude oil and petroleum products, for 1994 to 2015 (EIA, Annual Energy Outlook 1996, 1996). The model user specifies a target year, and the model looks up the projected values for the specified year. These projections are used to calculate venting and flaring emissions of associated gas (see below), and energy and emissions from international transport of crude oil and products.

Venting and flaring of associated gas

The calculation of venting and flaring of associated gas has been improved in several ways. First, the base-year data on venting and flaring and oil production, by country, have been updated from 1987 (Table M.7) to 1992 (EIA, International Energy Annual 1993, 1995).

Second, because the EIA now reports crude-oil production, rather than oil production, by country, there is no need to estimate the former from the latter -- the actual crude-oil production data can be input to the model directly.

Third, the fraction of gas that is flared rather than vented now can be specified separately for each crude-oil production region. (Formerly, the same fraction applied everywhere.) On the basis of a re-examination of the original data, and consideration of new data from other sources (e.g., Barns and Edmonds, 1990), I have assumed that 13-20% of all gas was vented rather than flared in the new base year of 1992 (see Delucchi and Lipman, 1996). (The original vented fraction was 6% [p. M-25].)

Fourth, the user now can specify the annual rate of change of venting and flaring (in SCF/bbl) and the fraction that is flared rather than vented, for every region. With this annual rate of change, and the base-year (1992) data mentioned above, the model calculates venting and flaring emissions (in SCF/bbl) for any year from 1994-2015. I assume that the SCF/bbl emission rate remains constant in areas with relatively low rates in 1992 and relatively well developed oil fields and gas markets (U.S., Canada, Mexico, Northern Europe, and the Middle East), and declines slightly in areas with high SCF/bbl emission rates in 1992 and relatively poorly developed gas markets. (The rates in Africa are assumed to decline the most.) I make analogous assumptions for the fraction flared rather than vented. See Delucchi and Lipman (1996) for the actual assumptions.

Fifth, the model now explicitly assigns a source of crude oil to petroleum products. Previously, I assumed that petroleum products from country X were made from crude oil from country X, except that I assumed that products from the Caribbean were made from Central American crude oil (footnote i, Table M.7). Now, the model allows the user to specify the source of the crude oil used to make petroleum products in each country. The model then calculates venting and flaring emissions on the basis of emissions in the country that is the source of the crude oil, (rather than in the country that actually refines the crude into products). The present assignments of sources of crude oil are based on international flows of crude oil, as reported by the EIA (International Energy Annual 1992, 1994).

Sixth, the model contains the EIA’s Reference Case projections of imports of crude oil, light petroleum products (gasoline, diesel fuel, jet fuel, and LPG), and other petroleum products, by exporting region, through the year 2015 (EIA, Annual Energy Outlook 1996, 1996). The model selects the projections for any year of interest, and then calculates the venting and flaring emissions that result from that specific mix of crude oil and product imports.

Seventh, venting and flaring from Federal offshore oil wells has been added. (The EIA data on venting and flaring in the U.S. come from state agencies, which we do not report activity at Federal offshore oil wells.) See Delucchi and Lipman (1996) for further discussion.

As a result of these changes to the structure and input data, estimated venting and flaring emissions have increased modestly, and total petroleum fuelcycle emissions have increased by 0.5% - 1.0%.

Emissions of CO2 removed from raw gas

The model calculates emissions of CO2 removed from "raw" wet gas in the field and at natural-gas processing plants, per cubic foot of dry gas marketed, as follows:

where:

Note that this is an interim calculation, which allocates the CO2 emissions to dry natural gas. In the final calculation of CO2-equivalent GHG emissions, the CO2 emissions are allocated to NGLs as well as to dry NG, in proportion to the energy content of the total output of each.

Emission factors for gasoline and diesel industrial engines

I have input the EPA’s (Compilation of Air Pollutant Emission Factors, AP-42, 1995) revised factors for uncontrolled emissions from industrial engines (Table A.1).

Emission factors for large stationary diesel engines

I have input the EPA’s (Compilation of Air Pollutant Emission Factors, AP-42, 1995) revised factors for uncontrolled emissions of CO, NMOCs, and CH4 from large stationary diesel engines, which are used primarily in oil and gas fields. I assume that NOx emissions from the population are 20% below AP-42’s revised factors for uncontrolled emissions (Table A.1).

Emissions of methane from coal mining.

In Appendix M of Volume 2 (DeLuchi, 1993), I estimated that coalbed gas was generated at the rate of 380 SCF/ton (Table 5), and that 5% of this was recovered and used as a fuel, and that another 5% was flared rather than vented. Since that estimate was made, several comprehensive studies of methane emissions from coal mining have been completed. On the basis of those studies (e.g., Thakur et al., 1996; EIA, Emissions of Greenhouse Gases in the United States 1987-1994, 1995), I have re-estimated the baseline emission rates, and projected changes through the year 2015. I assume that the SCF/ton emission rate from underground mines increases slightly, on account of mines getting deeper, but that the amount of gas recovered and used as a fuel also increases. The new parameter values, and the calculated results for the year 2015, are shown in Table XVI. See Delucchi and Lipman (1996) for further discussion.

The new calculated overall leakage rates (see Table XVI for the year 2015) are substantially lower than the rate assumed in the original report (Table 5), and as a result, CO2-equivalent emissions from coal mining have declined by almost 30%, and from the coal-to-electricity fuelcycle by about 2%.

Evaporative emissions of VOCs and CH4 from the crude oil cycle.

The CO2-equivalent of evaporative emissions of VOCs and CH4 from the production, transport, and storage of crude oil have been added. These emissions, in g-CO2 equivalent/106-BTU product, are estimated as:

These do not include evaporative emissions of gasoline from gasoline marketing, or venting and flaring emissions of associated gas, which are included already are in the model.

The addition of these emissions increases CO2-equivalent GHG emissions by only about 0.1 g/mi in the gasoline fuelcycle. (The emissions are added to the "feedstock recovery" stage.)

Energy used in mining

The Bureau of the Census’ 1992 Census of Mineral Industries reports data on fuel and electric energy consumed at establishments that recover coal, oil and gas, uranium. (These data are not available in hard copy; they are available only as a spreadsheet file, from the Census’ web site www.census.gov.) In Tables F.1, F.2, and F.3 (coal), G.1 and G.2 (natural gas and natural-gas liquids), H.1 and H.2 (petroleum), and I.1 and I.2 (uranium) of Volume 2 (DeLuchi, 1993), I use the Census data from the 1982 and 1987 Censuses of Mineral Industries to estimate the energy used to recover coal, gas, oil, and uranium. I have done the same with the 1992 Census data, following the methods presented in Volume 2 (DeLuchi, 1993).

The original model called for two kinds of inputs: the total amount of process energy used to recover a BTU of feedstock, such as coal, and the percentage distribution of that recovery energy among the different kinds of process energy, such as diesel fuel and electricity. This has been changed: the model now calls for one set of input data: BTUs of each kind of process energy (diesel fuel, gasoline, electricity, gas, etc.) per ton of feedstock (coal, crude oil, uranium, or natural gas) produced. The new method has three advantages over the old. First, it requires only one set of input data. Second, because the amount of process energy required for recovery is related directly to the mass of the feedstock, but not necessarily to the energy content of the feedstock, it is better to project recovery energy per ton or cubic foot of feedstock than per BTU. Third, the new method calls for projections of the amount of each kind of process energy used per ton of primary feedstock produced (e.g., BTUs-electricity/ton-coal), rather than for distribution of the total process energy among the different kinds. This is superior because one can project the BTU/ton amounts on the basis of the historical data for 1982, 1987, and 1992.

Using the data from the 1982, 1987, and 1992 Census of Mineral Industries, I have estimated the actual amounts of BTUs of each kind of process fuel used per ton of coal, crude oil, uranium, or raw natural gas. On the basis of these estimates, I have projected the BTU/ton energy requirements for each kind of process fuel and feedstock. Generally, if a trend was evident from 1982 to 1992, I assumed that it would continue; if no trend was evident, I assumed a mid-range value biased toward 1992.

The energy intensity of the recovery stage, in BTUs of process energy per BTU of feedstock produced (as shown in Table 3 of Volume 1), now is calculated by dividing the projections of BTUs of process energy per ton of feedstock by the projected energy content of the feedstock in BTUs per ton. Because the BTU/BTU energy intensity now is the product of BTU-process-energy/ton-feedstock and ton-feedstock/BTU-feedstock, it properly reflects projected changes in the energy content of the feedstock, due perhaps to declining quality. (Recall that in the original, BTU/BTU was input directly.)

In most cases, the changes discussed above to the structure and input data of the estimation of GHG emissions from mining have only a minor effect on overall fuelcycle emissions. However, fuelcycle emissions from the oil recovery stage have increased by 20%, although this results in less than a 1% increase in fuelcycle g/mi emissions, because emissions from recovery are a minor fraction of the total. GHG emissions from the natural-gas recovery stage have declined slightly. In the case of methanol made from natural gas, the overall effect is a 1% reduction in total lifecycle GHG g/mi emissions.

Documentation of miscellaneous parameter values

1). As mentioned above, the data on fuels and electric energy consumed at mining establishments in 1992 is provided in a spreadsheet available from the Bureau of the Census website. The spreadsheet shows the physical quantity of coal, distillate fuel, residual fuel, natural gas, gasoline, and electricity consumed, and the dollar expenditure on "other" and "undistributed" fuels. ("Other" fuels are coke, LPG, wood, and other minor fuels. Expenditures on "undistributed" fuels are those by establishments that did not report the quantity of individuals fuels consumed, or were not mailed a survey.) Thus, in order to have a complete accounting of energy use by mining establishments, one must estimate the energy content of "other" and "undistributed" fuels, on the basis of the dollar expenditures on these fuels. For "other" fuels, I simply multiply the total expenditures by the Census’ estimate of the average 106-BTU/$ energy value of "other" fuels -- 0.210 in 1992, according to Roehl (1997). I assume that "undistributed" fuels should be distributed to all of the specific fuel categories (except electricity) in proportion to reported expenditures; that is, I assume that the distribution of undistributed fuels is the same as the distribution of reported distributed fuels, where the distribution is with respect to expenditure. (The Census actually makes the same assumption, except at the level of all expenditures in all mining industries [Roehl, 1997], whereas I make this assumption for each industry in the mining sector.)

2). Many fuel data are not disclosed by the Census, so as not to reveal information about individual companies. Some of these data can be back-calculated on the basis of higher-level totals, but most cannot. I have estimated the ones that cannot.

3). I have revised historical data on the production of uranium concentrates in 1987, on the basis of new EIA data (Uranium Industry Annual 1996, 1997). Also, I now use total production from mines, rather than total product shipped. I have assumed that in 1982, 1987, and 1992 censuses, uranium mining alone consumed 95% of the fuels and electricity reported for the uranium/radium/vanadium industry as a whole. Finally, I have assumed that uranium’s share of energy use in metal-mining service industries is equal to the ratio of uranium-mining energy to all metal-mining-energy. (All of these assumptions are relevant to the estimate of BTUs-process-fuel/ton-uranium historically, which estimates serve as the basis of my projection.)

5). The energy intensity of natural gas recovery is represented as BTUs per ton of marketed production. Marketed production is equal to gross withdrawals from wells (excluding lease condensate) minus: nonhydrocarbon gases removed, gas used for repressuring, and gas vented and flared. Put another way, marketed production is equal to dry natural gas plus the natural gas liquids originally contained in the total gas stream. Because marketed production is the output of the field production stage, and the input to the natural-gas processing stage, it is the appropriately related to the process energy used in field production.

The energy intensity of natural-gas processing is represented as BTUs per ton of wet gas processed. Because all natural gas liquids must first be recovered with the gas stream, and then extracted from the wet gas at a processing plant, the final energy ratio of interest, BTUs-process-energy/BTU-NGL-delivered, is equal to BTUs/ton-marketed, and BTUs/ton-processed, multiplied by the NGL heat content (tons-NGL/BTU-NGL). However, because some marketed production is dry enough to bypass the processing plants and go directly to consumers, the ratio BTUs-process-energy/BTU-NG-delivered is equal to BTUs/ton-processed multiplied by the ratio of the gas output of processing plants to total dry gas production, and then by the heat content of dry gas (tons-NG/BTU-NG).