Enhanced oil recovery applications of CO₂ capture technologies

Toward understanding the costs of early-mover gasification energy projects

Attractive economics are key to the ultimate commercial success of the coal-based, low-carbon energy systems providing synthetic liquid fuels and/or electricity that the Capture group has investigated. Gasification is the key enabling technology. The group’s previous economic analyses have provided a credible basis for understanding how advanced gasification-based energy systems compare with one another, but estimates of absolute costs have to be reconciled with real-world experience in order to provide a good understanding of costs for first-of-a-kind (FOAK) projects and the subsequent evolution to mature technology costs.

A new project launched in 2013 is aimed at creating this understanding. In this project the capture group is collaborating with Chris Greig, Director of the University of Queensland (AU) Energy Initiative. Greig was formerly CEO of ZeroGen, Australia’s flagship 400 MW integrated gasification combined cycle plant with CCS (IGCC-CCS). That project was ultimately cancelled (Nov. 2011) because it was deemed to be too costly and the geologic formations targeted for CO₂ storage were judged unsuitable.

Recent coal gasification experience in the U.S. has been for power generation via IGCC. In June 2013, the 618 MW Edwardsport (Indiana) IGCC plant (with CO₂ venting) came on line; the 582 MW Kemper County (Mississippi) plant, for which captured CO₂ will be sold for enhanced oil recovery, will come on line by December 2014 (Figure 1). Edwardsport ended up costing more than twice as much as first estimated, and the same will be true for Kemper County. These cost overruns took place even though the design studies were carried out by top-flight engineering firms.

The Capture group is pursuing a multi-pronged investigation into the costs of large energy projects. The goals are to: 1) reformulate their methodology for estimating capital costs for FOAK gasificationbased processes that match the best available empirical evidence; 2) understand in detail why FOAK costs are so high; 3) identify the most promising opportunities for reducing costs via accumulated experience (often termed “learning by doing”); and 4) clearly and quantitatively articulate a methodology for estimating plausible capital costs for mature technologies starting from FOAK cost estimates.

The researchers will strive to understand the cost overruns at the Edwardsport and Kemper County projects, accepting that much of the desired cost information is closely held. The project will also analyze data from available design studies carried out for projects that ended up being cancelled (including ZeroGen).

An early finding from this project represents learning from ZeroGen. Greig spent tens of millions of dollars on engineering studies for this project that probably looked in much more detail at costs than was the case for the early design studies carried out for Edwardsport and Kemper County. These studies suggest that the final costs of Edwardsport and Kemper may not be so surprising after all, because the cost (in $/kW) of the ZeroGen IGCC-CCS (if built in the U.S.) would somewhat exceed that of the Kemper plant.

 

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Technology cost buydown for CCS technologies linked to enhanced oil recovery

CCS projects are being deployed at a much slower pace that had been anticipated—thus jeopardizing the future of CCS as a carbon-mitigation option. Progress is slow largely because: (a) capital costs for “early-mover” projects have turned out to be much greater than estimates made by industrial bodies, government agencies and academic groups, and (b) such projects cannot go forward without substantial subsidies that governments will have difficulty providing.

During 2013, Williams carried out a preliminary technology cost buydown analysis for costly FOAK projects for several power-only systems with CCS and for the two coproduction systems listed in Table 1. This study analyzed the potential role of government subsidies in enabling cost-reduction via experience for systems selling captured CO₂ for enhanced oil recovery (EOR) and thereby advancing CCS technologies more rapidly

Williams showed that, if there is “learning by doing” at the same rate as was achieved for the sulfur dioxide (SO₂ )scrubbers at coal power plants, it is plausible that, in the absence of a price on GHG emissions, government subsidies for a relatively small number of early-mover coproduction plants could reduce costs to market-clearing levels for EOR market applications. However, such an outcome is unlikely for new plants making only electricity.

This analysis suggests that coproduction systems be given careful scrutiny as candidates for cost buydown via government subsidy. Unfortunately, the extent of cost reduction via experience is a priori unknowable.

However, important insights into the cost buydown process can be gleaned from a consideration of the costs and benefits of subsidies for FOAK coproduction plants. Assuming that these plants are deployed as “rebuild” units at sites of old coal power plants that are retired, they would offer not only carbon mitigation benefits but also significant public health benefits associated with PM2.5 air pollution health damage costs avoided in generating electricity (Figure 2).

_{Figure 2. Health damage costs caused by PM2.5 particles for the US average coal power plant in 2010 (leftmost bar) and for alternative new power plants—assuming health damage costs ($ per kg) of primary pollutant emissions as estimated in the 2010 National Research Council report Hidden Cost of Energy: Unpriced Consequences of Energy Production and Use. (PM2.5 particles are those having diameters less than 2.5 microns that are either emitted directly from power plants or formed in the atmosphere from gaseous precursor emissions of SO2 and NOx.) The average health damage costs in 2010 are equivalent to 36% of the average electricity generation price in that year. The estimated damage costs for the two coproduction options on the far right are less than 1% of the average generation price in 2010. Sup PC = Supercritical pulverized coal; V = Venting; CCS = Carbon Capture & Storage; IGCC = Integrated Gasification Combined Cycle; CTLE= Coal-to-liquids and electricity; CBTLE = Coal-biomass-to-liquids and electricity.}

The main findings of this analysis for FOAK plants are:

•  The required large subsidies are likely to be less than the public benefits of carbon mitigation and air pollution health damage cost avoidance;
• If captured CO₂ is sold for enhanced oil recovery, federal revenues (mainly corporate income taxes) from new domestic liquid fuels produced would be comparable to required subsidies; and
• Government can afford to “find out” what the rate of learning is by providing the subsidies required because, in effect, providing the subsidies would be approximately “revenue-neutral” for government.

The quantitative results of this analysis are shown in Table 2, the notes of which list the assumptions.

 

_{Assumptions: (a) the capital cost for each FOAK plant = 2X the corresponding N^th-of-a-kind capital cost estimated in earlier Capture group publications (roughly consistent with Edwards-port/Kemper County experience); (b) the subsidy is sufficient to reduce the levelized cost of electricity (LCOE) to that for a natural gas combined cycle plant; (c) these plants displace equivalent crude oil-derived products and electricity provided by old coal power plants retired in favor of these coproduction plants; (d) carbon mitigation benefits are valued at $55/t CO2e [the “social cost of carbon” (SCC) levelized over the 20-year economic lifetimes of new plants coming on line in 2021 (based on SCC estimates made in the 2013 report of the US government’s Interagency Task Force on the Social Cost of Carbon)]; and (e) the public health benefits are for PM2.5 air pollution emissions avoided in power generation based on calculations presented in Figure 2.}

_{The last column in Table 2 shows, relative to the required government subsidy (RGS), the gross new federal revenues (GNFR) generated in the form of corporate income taxes and royalty payments from the new domestic liquid fuel production arising as a result of deployment of these coproduction systems that sell captured CO2 for EOR.}

 

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Expanding the US/China collaboration on clean, low-carbon energy from coal

During 2013, Williams urged officials at the Shenhua Corporation (a Chinese coal company – the world’s largest) and at Southern Company (a large investor owned electricity utility in the Southeastern United States) to consider collaborating to advance clean, low-carbon energy from coal – adding a new industry-led, government-assisted, action-oriented initiative to the ongoing China/US collaboration on clean coal technology. The proposed collaboration would build on the strengths of the two companies:

Shenhua:

•  Extensive experience with coal gasification (for chemicals/synfuels manufacture)—a key enabling technology for low-carbon energy from coal;
•  Strong interest in “polygeneration” systems providing high value products—might also turn out to be key for making low-carbon energy from coal more profitable;
•  The technological and financial capacity to carry out megascale energy projects;
•  Commitment to advance clean coal technology [including via Shenhua’s National Institute for Clean and Low Carbon Energy (NICE)]; and
•  CEO/President Dr. ZHANG Yuzhuo’s vision for coal’s future in a carbon-constrained world:

“Clean coal conversion can lead to the realization of the transformation from high carbon, to low carbon, to carbon free coal utilization with broad prospects for technological andcommercial markets in the future.”

 

Southern:

• Has long operated a small US DOE national energy laboratory at Wilsonville, Alabama that is now called the National Carbon Capture Center (NCCC);
• Has brought to commercial readiness with long-term US DOE support KBR’s transport gasifier (TRIG^TM) for low-rank coals—a gasifier that has (as a result of discussions to date about a possible Shenhua/Southern collaboration) generated considerable interest on the part of Shenhua for use with its extensive low-rank coal resources (for which it believes no other commercially-ready gasifier is suitable);
• Will bring on line by the end of 2014 the Kemper County Project, the world’s first commercialscale gasification power plant with CCS; this TRIG^TM-based IGCC is uses Mississippi lignite and sells captured CO₂ for enhanced oil recovery (see Figure 1); and
• Has conducted tests (2009-2012) on the NCCC experimental TRIG^TM gasifier showing that up to 30% biomass can be cogasified in oxygen (as required for making synfuels) with low-rank coals— without technical difficulty and resulting in no change in syngas quality.

Williams was inspired to encourage the collaboration when he visited the NCCC in April 2013 and learned about successful TRIG^TM tests with up to 30% biomass—a percentage that can lead to ~90% reduction in GHG emissions for coal/biomass systems with CCS that provide transportation fuels and electricity (CBTLE-CCS plants). This empirical work plus substantial experience with biomass supply logistics (the US has several biomass power plants consuming 0.5 million tonnes of wood per year) implies that the CBTLE-CCS concept is ready to be demonstrated at commercial scale. Williams’ personal goal is to catalyze via the collaboration FOAK CBTLE-CCS projects in both the US and China.

Williams has had several discussions with Southern and Shenhua officials regarding the possible collaboration, including two private meetings with Dr. ZHANG Yuzhuo, who told Williams that a first step should be to have a technical delegation from Shenhua visit the NCCC and Kemper County IGCC-CCS project (see Figure 1), which he asked Williams to help arrange. This “Southern tour” took place on 2-3 January 2014, with Kreutz, Larson, and Williams accompanying the four Shenhua engineers. Subsequently, Southern and Shenhua have had discussions regarding possible dimensions of a collaboration.

In late 2013, the US Departments of Defense and Energy issued a call for proposals on coal-based technological pathways that could lead to commercial production of jet fuel with lower GHG emissions than for crude oil-derived jet fuel and with the potential to be cost-competitive. In response, in early 2014 the Capture group submitted a proposal (invited as a result of acceptance by the funding agencies of a December 2013 Concept Paper outlining the proposed project) for a prefeasibility study of a FOAK coal/biomass to jet fuel plant. The group has assembled a team (including collaborators from Southern Company; Chris Greig and a colleague at Queensland University in Australia; Worley-Parsons Engineering; and from the CMI Fluids & Energy Group, Michael Celia and Karl Bandilla) to propose a commercialization analysis for a coal/biomass-to-jet fuel facility at a Mississippi site located near a CO₂ pipeline network that can deliver captured CO₂ to enhanced oil recovery operations. The team will analyze alternative designs for a facility that cogasifies local lignite and woody biomass and converts the resulting gas to a Fischer-Tropsch synthetic jet fuel. Alternative system designs will be considered and one specific design will be modeled in detail. If the project goes forward, it will represent a step toward the goal of launching FOAK CBTLECCS projects in U.S. and China via the Southern/Shenhua collaboration.

 

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Biomass-based strategies for reducing emissions in transportation

Global climate models project that negative emissions will be needed by the 3_^rd quarter of this century to avoid dangerous warming. In 2013, the CMI Capture group teamed up with ecologists David Tilman and Clarence Lehman at the University of Minnesota to submit a winning proposal to the Stanford University Global Carbon and Energy Project (GCEP) for work to identify, analyze, and articulate promising systems for negative carbon emission transportation energy by mid-century.

The project will begin in 2014. Its goal is to quantify and articulate for policy makers the extent to which different biomass energy technologies with CCS (BECCS) are likely to be able to contribute to meeting U.S. demands for liquid fuels later in this century. Two mechanisms for achieving negative emissions will be studied: i) storage of photosynthetic carbon in biomass roots and soil (R/S) and ii) geologic storage of CO₂ captured during feedstock conversion (CCS), with particular attention to the use of CO₂ in EOR as a near-term, large-potential strategy for commercial introduction of geologic CO₂ storage.

Princeton will do detailed and self-consistent process simulations and lifecycle carbon and economic analyses of: 1) gasification-based thermochemical conversion systems; 2) biochemicallybased conversion via fermentation to ethanol and/or butanol or via microbial metabolism to liquid hydrocarbons; 3) pyrolysis-based liquids; and 4) gasification-based conversion to electricity (for electric transport).

Minnesota colleagues will develop a comprehensive understanding of the ecological dynamics and R/S carbon storage potential with perennial grasses grown on degraded land in the U.S. that is currently ill-suited for conventional agriculture. A comprehensive, multi-disciplinary set of new sustainability metrics will be developed to characterize alternative biomass resource/conversion systems in terms of lifecycle energy and GHG balances, ecosystem and land-use impacts, and prospective economics.