Bury or Use Captured Carbon, or Just Avoid It?

Aug 29, 2018

Carbon dioxide, or CO2, which is the primary greenhouse gas (GHG) known to be causing climate change, is commonly called “carbon.”  The other GHGs in the “basket” set in the Kyoto protocol are weighted by their global warming potential as “CO2 equivalents”: methane (CH4, about 23 times as strong a greenhouse gas as CO2), nitrous oxide (N2O), and the so-called F-gases (hydrofluorocarbons and perfluorocarbons) and sulfur hexafluoride (SF6). Besides CH4 and N2O, the other GHGs are man-made chemicals. CO2 and CH4 and N2O are natural atmospheric components, and were in long-term balance in the ecosystem before humans began to release all three, from fossil hydrocarbon sources in the case of carbon, and/or from other human activities like agriculture. 

For well over a decade, Nexant has been assisting a broad spectrum of clients including the US Department of Energy, private companies, and NGOs in carbon capture, utilization, and sequestration (CCUS), generally addressing CO2 in combustion stacks.  For example, in 2016, Nexant completed a pre-feasibility study of a proposed post-combustion capture (PCC) pilot plant at a natural gas-fired combined-cycle (NGCC) power plant in Mexico. This study, sponsored by the World Bank Group (WBG), included a comparative techno-economic evaluation of six advanced amine-based PCC technologies and a generic amine-based conceptual pilot plant design (the carbon capture aspect). Related WBG-sponsored work by others looks at piping and supplying this CO2 for enhanced oil recovery (EOR – the utilization aspect), and assesses whether and how a CO2-EOR project could qualify as a permanent storage project and earn carbon credits (the sequestration aspect). 

Upon reflection, it becomes clear that this value chain, while more desirable than sequestration without a commercial return, is fraught with many risks and uncertainties, has limited applicability, and, except for the EOR, relies for its monetization on public policy – carbon trading credits, or a carbon tax. Its applicability is limited because it relies on special geographical circumstances – that is, you would have to have carbon capture reasonably close to oil wells in need of EOR, and the special geology that might make the EOR a viable strategy for permanent carbon storage (not always the case).

How does Enhanced Oil Recovery work?

CO2 can be a valuable commodity as used in EOR to squeeze more from depleted petroleum reservoirs. During large-scale commercial EOR “floods,” CO2 that comes back up with oil during EOR is separated, compressed and re-injected and thus recycled numerous times.  Under these conditions, venting to the atmosphere is rare and constitutes an insignificant fraction of the injected CO2. The purchased CO2, minus any vented during EOR activity, is sequestered in the reservoir by a combination of capillary, solution and physical trapping mechanisms. It was reported in 2013 that approximately 600 million metric tons of purchased CO2 had been utilized in the southwest U.S. Permian Basin (PB) alone, the rough equivalent of 30 years-worth of CO2 from a half dozen medium-sized coal-fired power plants.  Too bad this does not seem a broadly applicable commercial strategy. The default is to simply pipeline CO2 and inject it into saline aquifers with no economic benefit.

Many streams of already-concentrated CO2 are available – just do it!

We must develop solutions that are alternatives to EOR and non-economic sequestration all along the value chain for CCUS, beginning with “capture.”  We are questioning whether in the short run society should focus on capturing CO2 by separation from combustion stacks (at around 20 percent), or worse, on trying to extract it expensively from the atmosphere at 400 ppm (e.g., as with Carbon Engineering’s direct air capture [DAC] technology.)  Rather, should we not first exhaust all options for implementing CCUS strategies on every stack with high CO2 concentrations, from fuel ethanol plants, breweries, pharma fermentations, ethylene oxide and other petrochemical partial oxidations, steam-methane reforming, natural gas processing, biogas and LFG processing, and non-urea integrated ammonia plants? Many of these stacks have nearly pure CO2 available with little or no cleaning or further concentration needed, or consist of easily separable methane/CO2 mixtures.  

The following map indicates that the oil-producing and petrochemical producing regions of the United States are co-located with saline aquifers, which are potential media for CO2 sequestration, but fewer than half or the bio-ethanol plants are, so that pipelines would need to be built to bring their CO2 to injection sites.   It is estimated that most of those in the Heartland (IA, NB, SD, MN, and WI) would cost $60-120 per ton for pipeline transfer to the nearest saline aquifer. Others, in the Midwest (IL, IN, MI, OH and KY) and in Texas and Kansas, are better situated.

aquifers and proximitiy to biofuel plans and injection sites

 

The main disadvantage of the idea of sequestration in saline aquifers is that relatively little is known about them, compared to oil or gas fields. Therefore a lot of work is required to prove that they will permanently retain CO2 before it is pumped into them. Unlike storage in oil fields no useful by-product will offset the cost of storage.

Nexant has more recently studied strategies for utilizing cheap and renewable power (it has to be both), to make chemicals, fuels, or other materials from CO2, potentially without relying on a carbon tax or trading regime to make them profitable.  The most widely applicable scenario for profitable CO2 removal is pre-concentrated stream of CO2, along with cheap, renewable power, and production technologies that can make fuels or chemicals using these resources. Two studies addressing such technologies are Biorenewable Insights: Carbon Dioxide to Chemicals and Fuels, and Biorenewable Insights: Electrochemicals and Electrofuels. These reports ask, respectively – (1) how large a carbon tax or trading price, if any, is needed to make certain likely carbon dioxide utilization technologies profitable, and (2) what renewable electricity price will make selected electrochemicals and electrofuels profitable. These latter technologies are not like chlor-alkali and other generally inorganic electro-cell technologies, but are bio-based (metabolic) processes that are enhanced by applying electrical currents.

In all cases, the carbon that ends up in the products is from stack carbon dioxide, and producing them this way avoids using any new (fossil) carbon resources.  Thus, they are not “better than” biomass-based materials, because the plant material that is the ultimate source of biofuels and biochemicals also captures carbon (though with photons, not electrons) from the atmosphere. Nor are they better or worse than processes that ferment carbon monoxide-rich gases from steel mill stacks, such as that of LanzaTech.

The reader might want to follow up for background with other relevant Nexant reports such as Biorenewable Insights: Biogas and LFG that analyzes utilization, and separation in some cases of the main components of the subject gases, methane and CO2.  Another is Biorenewable Insights: Methanotrophs and Syngas Fermentation, which includes the LanzaTech technology to make fuels and chemicals from the carbon monoxide in stack gases by microbial fermentation. 

Biogas and landfill gas (LFG) are alternative sources of fuel methane thereby avoiding carbon from fossil sources from entering the atmosphere.  In early July 2018 SoCalGas and a waste management company, CR&R Environmental, announced they are injecting renewable natural gas (RNG) produced at CR&R’s anaerobic digestion facility in Perris, California, into SoCalGas pipelines.  As more RNG comes on line, this could be a strategy for companies, particularly in the chemicals and plastics industries, to hook into for their gas supply to help meet corporate carbon reduction goals.

RNG is produced from LFG or other biogas by removing CO2 (which is bio-based, i.e., carbon-neutral, and thus can be either used or vented), and cleaning it of other contaminants. On an energy audit for PG&E over 20 years ago, I visited a Morton Salt facility on Southeast end of San Francisco Bay.  They processed brine from those multi-colored ponds (due to different algae growing in them) you see while gliding in for a landing at SFO.  They were concentrating the brine and crystallizing salt from it. They used LFG from the adjacent landfill primarily because it was a cheap fuel (natural gas was then three times as expensive as it is today).

Conclusion

Operators of any facilities that currently produce concentrated CO2 streams, especially in regions where renewable power is cheap and abundant, should investigate the monetization strategies suggested herein, in anticipation of a carbon taxing or trading regime, which is inevitable.