During 2011, the Williams Group investigated CO2 enhanced oil recovery (EOR) as a CCS market launch opportunity for coal and natural gas energy conversion systems without and with biomass coprocessing, low-carbon synthetic gasoline production from coal and coal + biomass, and the co-gasification approach to coproduction. During this period, collaborations with Chinese and Italian colleagues intensified.


CO2 enhanced oil recovery: a CCS market launch opportunity

Since early 2011, Robert Williams and colleagues have been exploring the potential for launching CO2 capture technologies in the market by selling captured CO2 into EOR markets. In CO2 EOR, a commercially established technology, CO2 is injected into suitable mature oil fields to enable more oil production (typically CO2 dissolves in the oil, reducing its viscosity and enabling more oil to flow to the well bore for recovery).

The Williams Group is carrying out analyses on the oil import reduction/carbon mitigation nexus for CO2 EOR, the prospective economics of EOR, and public policy issues relating to EOR. These issues are discussed below in relation to five systems with CO2 capture listed in Table 1, which are compared to an old “written-off” pulverized coal plant (WO PC-V) that vents CO2 to the atmosphere. (Acronyms used to distinguish these plants are given at the bottom of Table 1.)’

All coal options have the same coal input rate as the written‐off pulverized coal plant being displaced (1613 MW). All natural gas options have the same gas input rate of 1102 MW. Acronyms: PC = pulverized coal power plant; WO = written off (a very old plant); V = CO2 is vented; CCS = CO2 is captured and stored; NGCC = natural gas combined cycle power plant; XTLE = plant that makes from X synthetic FTL fuels + electricity as a major coproduct, where X = G (natural gas), X = C (coal), X = GB (natural gas + biomass), CB (coal + biomass), TLE = “to liquids and electricity,” FTL = Fischer‐ Tropsch liquid fuels (diesel + gasoline). Percentages appended to options coprocessing biomass are the percent of biomass in energy input.

The first system is a widely discussed approach to CCS for coal power: the retrofit of a “CO2 scrubber” to capture dilute CO2 from the flue gases of a pulverized coal plant (PC-CCS retrofit). An attraction of this option is that it requires a relatively low capital investment. The scrubber uses a strong solvent to absorb CO2 from the plant’s flue gases. Then the CO2 is recovered from the solvent via an energy intensive process, pressurized, and transported via pipeline to an EOR site.

The other four systems are plants that use coal or natural gas to make electricity plus Fischer-Tropsch liquid (FTL) synthetic diesel and gasoline with CO2 capture, providing CO2 for EOR. For these systems, the energy and cost penalties for CO2 capture are much less than for the PC-CCS retrofit—both because the CO2 is captured from pressurized synthesis gas streams at high concentrations, and because some CO2 has to be removed from synthesis gas as an inherent part of making synthetic fuels.

Two of the four co-production plants are coal-based “repowering” options, in which existing written-off pulverized coal plants are scrapped and replaced with new plants: one is a coal only plant (CTLE-CCS); the other coprocesses 9.2% switchgrass with coal (CBTLE-CCS-9.2%). The remaining two coproduction plants are natural-gas based systems located at the natural gas wellhead (GTLE-CCS and GBTLE-CCS-4.8%, with 4.8% switchgrass).


The oil import reduction and carbon mitigation nexus for CO2 EOR

There are currently 114 U.S. CO2 EOR projects producing 272,000 barrels/day of crude oil (6% of U.S. production), using 50 million tonnes/year of CO2 delivered from CO2 sources to oil fields via 5800 km of CO2 pipelines. Most projects use naturally occurring geologic CO2, the supply of which is limited. However, EOR could be greatly expanded by using CO2 captured from energy conversion facilities. A recent DOE report estimates that by 2030 some 3.4 million barrels per day of additional crude oil could potentially be produced from such anthropogenic sources (equivalent to 62% of U.S. crude oil production in 2010).

If all CO2 captured at a PC-CCS retrofit plant like that described in Table 1 were used for EOR, incremental crude oil production would be 37,000 barrels/day. For the coproduction options in the table, each barrel of synfuel produced using captured CO2 leads to ~ 1.5 incremental barrels of crude oil in the natural gas cases and ~ 2.7 incremental barrels in the coal cases.

The oil provided via CO2 EOR makes it possible to displace oil that would otherwise be imported, while enabling carbon mitigation at the plants providing CO2. Assuming that the CO2 sold for EOR stays underground after oil recovery operations are concluded, the emission rate (kg CO2eq per MWh) for the PC-CCS retrofit would be ~ 20% of that for the original coal power plant. The situation is more complicated for coproduction plants. Suppose that the greenhouse gas (GHG) emission rate assigned to electricity generation is that for a new natural gas combined cycle power plant venting CO2 (NGCC-V plant), in anticipation of a plausible near-term regulation specifying that new power plants must have GHG emission rates no greater than that. Under this condition, the Williams Group has estimated (Figure 1) that the GHG emission rate for the F-T liquid fuels produced (red bar) is remarkably low: 50%, 35%, and 50% of the rate for the crude oil products displaced (brown bar) in the GTLE-CCS, GBTLE-CCS-4.8%, and CBTLE-CCS-9.2% cases, respectively.

Figure 1. Carbon and GHG balances for three alternative coproduction options using natural gas, coal, and biomass to produce liquid fuels and electricity listed in Table 1. A) GTLE‐CCS, B) GBTLE‐CCS‐4.8%, and C) CBTLE‐CCS‐9.2%. 1st Bar shows fuel‐cycle‐wide GHG emission rate for crude oil products displaced by FTL; 2nd and 3rd bars show plant’s C balance (C output = C input); 4th bar shows fuel‐ cycle‐wide GHG emissions by component (positive and negative elements); 5th bar shows net fuel‐ cycle‐wide GHG emissions for FTL.


The economics of energy conversion coupled to CO2 EOR

The Williams Group has carried out an internal rate of return on equity analysis for the energy conversion systems listed in Table 1 to illuminate the economics of CO2 EOR in the absence of a carbon mitigation policy. Figure 2 shows that the most attractive option at high CO2 prices is the PC-CCS retrofit, but at low CO2 prices coproduction options are more profitable.

Most CO2 EOR opportunities are in Texas and near the Gulf of Mexico. There are some old coal plants near such sites, the retrofit of which with CO2 scrubbers would be very profitable, because the current price paid for CO2 at the EOR site is $25 to $40 a tonne. But if an adequate CO2 pipeline infrastructure were in place, then coproduction plants located up to a couple of thousand km from EOR sites would be able to compete in EOR markets because these plants would be profitable even at plant gate selling prices of $0/t (Figure 2), while the cost of long-distance transport via trunk pipelines is likely to be in the range $20 to $30 a tonne. This finding implies that with this infrastructure, captured CO2 from as far away as wellhead-sited gas-based coproduction plants in Pennsylvania and New York using Marcellus and Utica shale gas and coal-based repowering coproduction plants in West Virginia could plausibly be competitive in CO2 EOR markets in both the Gulf region and in Texas.

Figure 2. Internal rate of return on equity (IRRE) for the alternatives to a written‐off coal plant (WO PC‐V ‐ Table 1), as a function of the plant‐gate CO2 selling price for EOR markets. Assumed prices: $2.0, $4.5, and $5.0 per GJ for coal, natural gas, and biomass, and $90/barrel for crude oil.


Policy analysis relating to CO2 EOR and early action on CCS

The above analyses show that CO2 EOR offers the opportunity to launch CCS technologies in the market — even in the absence of a carbon mitigation policy, while generating significant reductions in GHG emissions for both power generation and liquid fuels production, using technologies that could be brought into the market now. Technologies making synthetic fuels and synfuels + electricity are key to making CO2 EOR a major CCS activity, because such systems would be able to compete even in distant EOR markets if an adequate CO2 pipeline infrastructure were in place.

But most energy investors and policymakers are unaware of the technologies offering these strategic opportunities, and this situation is likely to persist until one or more of these technologies coupled to CO2 EOR is demonstrated at commercial scale—an undertaking that is likely to require some kind of public sector support. Williams is investigating alternative public policy options by which some support might be provided, giving particular attention to opportunities that don’t require federal government expenditures, in light of fiscal constraints facing the federal government.

One of Williams’ 2011 activities was his participation in the Department of Energy’s Quadrennial Technology Review, the goal of which was to find ways to make the Department more effective in establishing the technologies it is trying to advance in the market. Williams discussed in both QTR meetings and in written submissions to the QTR the strategic importance of CO2 EOR and of tying synfuels and synfuels + electricity projects to CO2 EOR applications. The QTR report released in September 2011, though, made no mention of CO2 EOR.

In October 2011, Energy Secretary Chu asked the National Coal Council to prepare reports on CCS, CO2 EOR, and synfuels. Subsequently the NCC invited Williams to participate in this study. Williams has accepted and intends to bring to that study the perspective discussed here.