Enhanced Oil Recovery Applications of CO₂ Capture Technologies

During 2012 Williams investigated prospects for early deployment of CO₂ capture technologies for which storage is carried out in conjunction with CO₂ enhanced oil recovery (CO₂ EOR). In so-called miscible flooding, injected CO₂ dissolves in oil, reducing its viscosity and facilitating oil flow to the well bore. When the crude oil is recovered, the CO₂ released from the oil is captured and re-injected to extract more oil. After repeated CO₂ recycle, nearly all of the purchased CO₂ ends up being stored in the reservoir from which the crude oil is recovered.

Two of the CO₂ EOR-related projects gave focused attention to the relative economics of alternative CO₂ capture technologies for mature technologies—so-called N^th-of-a-kind (NOAK) plants. The third explores an innovative subsidy mechanism for capture technology cost reduction from first-ofa-kind (FOAK) cost levels through experience (learning by doing) in CO₂ EOR applications.

 

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NCC Study of CO₂ Capture for coal energy conversion and storage via EOR

In October 2011 Energy Secretary Chu asked the National Coal Council (NCC) to prepare for him a report on CCS for coal via CO₂ EOR. The NCC invited Williams to participate in this study, and he was given the lead responsibility for the report’s analyses of synfuels and synfuels/electricity coproduction, and analyses comparing the economics of all capture options. Williams persuaded the NCC study team to consider natural gas as well as coal in considering synfuels and coproduction systems and to consider co-processing modest biomass amounts (< 10% on an energy basis) with both feedstocks in early-mover projects.

Important findings of the NCC report based on Williams’ internal rate of return on equity (IRRE) analyses for NOAK versions of present-day technologies are (for an assumed oil price of $90/bbl and no price on greenhouse gas emissions):

•  The only power-only option offering attractive an IRRE is a post-combustion capture retrofit for an existing coal power plant when such a system is located near a CO₂ EOR site.
• Synfuel and coproduction plants located practically anywhere in the US could compete in CO₂ EOR markets (even distant markets) if an adequate CO₂ pipeline infrastructure were in place.

The latter led the NCC study group to its major finding that it is technically and economically feasible to increase US crude oil production via EOR using CO₂ captured at coal plants from the current level of 280,000 bbls/day to 3,600,000 bbls/day by 2035.

The NCC study stressed the strategic importance of deploying first-of-a-kind (FOAK) projects for promising capture technologies as needed first steps toward realization of the identified opportunities. However, because FOAK capture projects are already going forward for pre-combustion, postcombustion, and oxycombustion capture technologies, the only new FOAK project recommended by the NCC study is for a plant selling CO₂ for EOR that coproduces synthetic transportation fuels and electricity based on coprocessing a modest amount of biomass with coal. The NCC study argued that the coal industry and the Energy Secretary should work together to find a way whereby such a plant could be financed, built, and demonstrated at commercial scale.

 

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Recycle vs. coproduction system configurations for providing synfuels

The Capture group has previously analyzed synthetic fuels production for NOAK plants based on both: (a) the Fischer-Tropsch liquids (FTL) process to produce diesel fuel and gasoline from coal (CTL) and from coal/biomass (CBTL), and (b) the methanol to gasoline (MTG) process to produce gasoline from coal (CTG) and from coal/biomass (CBTG) via methanol as an intermediate product. System configurations that recycle unconverted syngas to maximize liquid fuel output were analyzed, as well as system configurations that provide electricity as a major coproduct.

During 2012 Williams extended these analyses to CO₂ EOR applications for synfuel options involving CO₂ capture, to explore relative profitabilities of recycle and coproduction configurations. The expectation when the work started was that at sufficiently high oil prices recycle will be the more profitable; the analysis is aimed at identifying breakeven oil prices for both FTL and MTG systems, and for both coal only and coal/biomass options.

When only coal is a feedstock: When only coal is the feedstock, it makes sense to consider plants of equal capital cost in comparing recycle and coproduction configurations. For FTL it was found that recycle is more profitable than coproduction at crude oil prices higher than about $100/bbl (with no price on GHG emissions)—but also that profitabilities are comparable over a wide range of oil prices (e.g., $80 to $120/bbl). In contrast, for MTG there is no oil price at which coproduction is more profitable than recycle.

When biomass is coprocessed with coal: Because biomass is typically more expensive than coal, coprocessing biomass can be cost-effective only under a carbon mitigation policy. It makes sense to compare systems with equal inputs of scarce biomass and offering equal carbon-mitigation benefits as measured by the greenhouse gas emissions index (GHGI)¹ . Here IRRE values are estimated for two FTL options and two MTG options that coprocess enough biomass to reduce GHGI to 0.17, assuming a $50/t GHG emissions price – see Table 1. The modeled biomass is switchgrass, the growing of which does not require good cropland.

For MTG systems, recycle is more profitable than coproduction for crude oil prices greater than about $80/bbl. For FTL systems, coproduction is always more profitable. This finding arises from the greater percentage of feedstock carbon stored as CO₂ for coproduction (65% vs 54%). The corresponding greater negative CO₂ emissions from photosynthetic CO₂ storage implies a smaller biomass input percentage (24% vs 38%) to realize the targeted GHGI, which in turn implies a lower average feedstock cost. Also, coproduction enjoys scale economy benefits as a result of the assumed equal biomass rates for recycle and coproduction. The FTL finding is especially important in light of the greater need for diesel than for gasoline – which implies that much more FTL capacity than MTG capacity is likely to be built. Table 1 presents IRRE values for these four coal/biomass options when the crude oil price is $90/bbl.

 

 

 

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CO₂ capture technology cost buydown

Because, in the absence of a price on GHG emissions, required levels of subsidy for launching CO₂ capture technologies in the market are likely to be so high that it would not be feasible to use general federal funds (GFF) to fill the “cost gap,” Williams has been exploring an innovative strategy for government support of early launch of CO₂ capture technologies for systems that sell CO₂ into enhanced oil recovery (EOR) markets. The strategy involves using federal tax revenues from new crude oil production via CO₂ EOR and synfuel production to help finance (via competitively-bid grants proportional to the captured CO₂ amount) early plants selling captured CO₂ for EOR. The aim is capture technology cost “buydown”—i.e., cost reduction through experience (“learning by doing”).

 

 

The Capture group has focused on estimating NOAK costs for energy conversion systems. For this CO₂ capture technology cost buydown analysis, it is assumed that: (a) FOAK costs for capital and operation and maintenance (O&M) costs for new technology are 2.0 X NOAK² costs (b) capital and O&M costs decline with experience at the same rate as the learning-by-doing (LBD) rate for SO₂ scrubbers (11% for each cumulative doubling of production), and (c) the subsidy must be large enough to reduce the cost of generating electricity to that for a natural gas combined cycle power plant venting CO₂ , currently the technology of choice for new power plants in the United States. To the extent possible, subsidies would be financed with the new federal revenue streams associated with new domestic liquid production. Required subsidies in excess of what can be provided by these new federal revenue streams would be paid for out of GFF.

For NGCC the required subsidy declines slowly with the cumulative number of plants built (see Figure 7); the Nth (59th) plant still requires a $30/tCO₂ subsidy, and GFF contributions to the subsidy are needed until after 44 plants have been built. In sharp contrast, for the coproduction options the required subsidy declines rapidly. No subsidy is required for the 12th plant, and GFF subsidy contributions are needed only for the first CBTG plant and the first three GBTL plants. Moreover, new federal revenues (net of required subsidies) from domestic liquid production for the first 12 plants amounts to $17 billion for CBTG and $2.6 billion for GBTL. This suggests that market launch for both coproduction technologies and the associated biomass supply logistics technologies can be accomplished in the absence of a price on GHG emissions. Moreover, this can be done in a way that contributes significantly to federal deficit reduction rather than to its buildup, despite huge subsidies for early projects (e.g., $1.8 billion for the first FTL project and $2.9 billion for the first MTG project).

 

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1. Invented by the Capture group, GHGI is a carbon mitigation metric defined as a system’s total GHG emissions divided by the GHG emissions for the conventional fossil energy displaced; the latter are assumed to be the equivalent crude oil-derived liquid fuels and electricity from new supercritical coal plants that vent CO₂.
2. This is the actual ratio of FOAK to NOAK costs for the Edwardsport IGCC plant being built by Duke Energy in Indiana.