CCS Challenges, Realities, History, and Future Development Prospects

 

     It’s no secret that carbon capture, transport, utilization, and storage is expensive and subject to multiple risks. CCS is not new, but each project or type of project tends to be unique and so there are technological risks. As with any new tech being scaled up there are scaling risks including availability of materials, parts, and supply chains. This has already slowed some projects. There are also permitting risks which need to be worked out as permitting can be expensive and time consuming. That is not conducive to fast, economic, and smooth project rollouts. Along with the risks it needs to be understood that CCS it has similarities to pollution abatement in that there are few financial benefits to CCS aside from utilization, the U in CCUS, and in created carbon markets. The goal is to decrease or mitigate a negative business externality in the form of an atmospheric waste product by capturing it from a combustion source or from the air, transporting, and storing it underground, by using it to do something as in enhanced oil recovery, using it as a working fluid, or transforming it into other materials, chemicals, or fuels. CCS refers to just capturing, transporting, and storing, while CCUS adds utilization. Utilization means the gas is used in a process or a product that is then sold. Thus, CCUS has some economic benefits compared to CCS. That is why most of the carbon captured up to now (73%) has been utilized for enhanced oil recovery. It has economic benefits.

     Most of the CCS projects sequestering carbon in deep saline reservoirs (69%) have been termed a part of ‘natural gas processing’ since in many cases the CO2 was produced as a component of natural gas in sour gas production from marine carbonates. The CO2 came from the gas production itself so the net CO2 stored is actually much lower than would have if that natural gas had never been produced. The IEEFA report referenced below points out that the net carbon sequestered after subtracting the production of CO2 from gas and the CO2 enabling more oil production through EOR to be burned and to make more CO2, results in much less CO2 avoided than it may appear. This is undoubtably true but it does not inform nor address the new phase of CCS now commencing that will sequester CO2 from power and industrial sources in deep saline reservoirs, much of it without utilization. This new phase will be powered by the 45Q tax credits in the U.S. and by other government incentives elsewhere. It will also be aided by newer and improved technologies and economies of scope and scale that will develop as the new CCS industry matures. The costs and timelines of permitting need to be streamlined and will be more affordable and simpler in the future. Business models and financial structure should improve modestly.

     Currently there are about 45 million tons of CO2 being sequestered annually around the world. Decarbonization goals given by the IEA and others are to have 2 billion tons sequestered annually by 2030 – that is almost 50 times what is sequestered now, and 3-5 billion tons sequestered annually by 2050 – about 100 times more than now but only double what is projected for 2030. Certainly, ramping up something to 50 times current levels in less than 7 years seems much more daunting than doubling something in 20 years! Like many decarbonization timeline pathways it is front-end loaded, and the reality may end up being less in the near-term, with catch-up later. We need more realistic timelines. Since 2010 CCS has been growing at a rate of about 10% per year so to grow it by 5000% in less than 7 years would require an annual growth rate of about 725%. However, if we only consider the 2050 goal the annual growth rate required would be about 372%, still daunting but only about half of what their timelines require in the near-term.

 

The 45Q Upgrade, The IRA, and the New Era of CCS Projects

  

     Calling the new post-revamped 45Q CCS projects commercial deployments is a stretch as it is only the tax credits that offer financial benefits unless there are carbon market benefits. In new hub models there can be benefits to small point sources to capture carbon and feed it into a communal pipeline that delivers it to communal wells. The operators of the pipelines and wells can collect fees from the point source plants to help cover operation and maintenance costs. In the EFI webinar referenced below it was pointed out that carbon capture and use does occur routinely and economically in some industries. There are about 350 acid gas plants using natural gas feedstock that capture CO2 and use it to make urea ammonium nitrate at fertilizer plants at a capture cost of about $36 per ton. In contrast, there are many different sources of CO2 in refineries which are hard and costly to capture, some uneconomic at up to $350 per ton.

     Unfortunately, a big increase in inflation has coincided with the roll-out of new CCS tax credits and that will buffer the benefits. Thus, the costs in the graph below may be higher now. Ethanol plants and natural gas processing plants are among the ‘low-hanging fruit’ that will make up many projects but overall, these sources only represent a small amount of total plant CO2. Ethanol plants just make CO2 and steam so after simply evaporating the steam there is just CO2. Thus, there are high capture rates.  

 

 

 

Levelized cost of CO2 capture by sector and initial CO2 concentration, 2019 (Last updated 26 Oct 2022). IEA. With New US 45Q Tax Credits Given for Enhanced Oil Recovery ($60/ton), Geological Storage ($85/ton), and Direct Air Capture ($180/ton)

     

   Modified from IEA

    

     In the U.S. current tax credits for CCS are at about $10 billion per year and are expected to rise to about $36 billion per year in 2031. Financers say that after grants will come the need for loans for O&M costs so that grants and loans need to be stackable. Tax credits will be transferrable, and ease of transferability is important. Data availability for each project will also be required for informed investor participation. This is true for capture, transport, and sequestration data. Open-source formats will be needed. Although there are only about 30 significant CCS projects running worldwide, there have been announcements for about 157 new projects in North America alone. Some may not be built, however, but these numbers do show that a major new CCS push is definitely on the way since the numbers for North America alone represent over 5 times or 500% growth in number of projects. And these numbers do not include micro-projects. Another aspect of the 45Q upgrades is that now smaller CO2 sources are eligible. Previously it was projects that captured 500,000 tons or more per year that were eligible. Now those smaller facilities that produce at least 25,000 tons per year are eligible. This is another way the IRA will have a big positive impact on projects. That could also aid bigger projects at the same hub or cluster at the same time by providing CO2 pipeline and well owners with additional income as they offer CO2 transport or storage as service contracts.

     It can be seen from the graph above that nearly all of the CCS projects will fall within the tax credit costs with the exception of the direct air capture projects of which only a few will. Even so, it is a very attractive framework to get the CO2 removal industry up and running.

 

Sequestration Geology

 

     It should be noted that some CCS projects have failed on the sequestration side and that successful sequestration that goes according to plan for the duration of the project is a major key to overall project success. Sequestration success is based on geology, particularly on accurate reservoir characterization. There needs to be a porous and permeable reservoir with a structural and/or stratigraphic trap, and a seal over the trap made by impermeable rock. Both buoyant and capillary traps can work. Saline aquifers can meet these conditions. Certain types of reservoirs, depths, and reservoir pressure are ideal for CO2 sequestration. Depths of at least 2400-4000ft are required. This is because CO2 needs to be compressed into a supercritical state in order to inject it in sufficient amounts. Its pressure needs to stay well below natural reservoir pressure which increases with depth in general. The supercritical state gives it properties of both a liquid and a gas. It is buoyant compared to other reservoir fluids and tends to move upward. That is why trapping and seals are very important with CO2. Normally pressured reservoirs are much better than overpressured reservoirs. This is because reservoir pressure will naturally increase as CO2 is injected and if that pressure exceeds the frac gradient then there may be inadvertent hydraulic fracturing of the reservoir which could lead to a breach of the reservoir seal and migrating of CO2 up above the intended zone. An already overpressured reservoir will have less room to avoid exceeding the frac gradient. Rocks that are too deep may also have pressures high enough that seal rupture through induced seismicity – causing an earthquake due to injection pressure rising too high or too fast - is possible. Thus, a ‘Goldilocks’ zone in terms of depth, pressure, and porosity/permeability is desired. Supercritical CO2 has a high solubility rate so over time it dissolves into the formation brine and sinks. The CO2 also reacts with rock to form minerals which can be considered another type of sequestration. Marine sands can be ideal reservoirs since they tend to be continuous in their porosity and permeability both laterally and in 3D. Carbonates can work as well but have some potential drawbacks. Faults and fractures, especially unsealed ones, need to be avoided. Mechanical properties of the reservoir rock need to be known through stress tests.

 

Geological Sequestration Analysis of Five CCS Mega-Projects

 

     This analysis was done by geologist Jason Eleson, owner of Geointegra Consulting, in an excellent webinar titled CCS: Flop or the Future? As Jason is a geoscientist like me, I especially found his geological analyses useful. First, he covers Sleipnir Project in the North Sea run by Equinor. The Sleipnir project sequesters CO2 derived from their nearby natural gas field with high CO2 content so it can be considered a gas processing CCS project. Gas processing CCS projects are limited to the reservoirs available near the natural gas source. Since beginning injection in 1996 it has run continually and has been a success. It was injected via a lateral well with 125 ft of perforations into a thick marine sand at the center of the Viking Graben with structural and stratigraphic trapping. The CO2 plume was expected to move out away from the well at a rate of about 100 meters per year but ended up moving out at a rate of 300 meters per year. It is expected to meet final injection goals soon and will likely be abandoned after that as planned. Seismic lines shot through time for monitoring have confirmed expected amplitude changes due to CO2 infiltration into the reservoir. Pressure has remained constant and near hydrostatic in the reservoir throughout injection. The IEEFA report attributed Sleipnir’s capturing success to Norwegian government incentives, notably the tax on CO2 introduced in 1991. While that no doubt was a key motivation for initiating the project, the main reason for the success was favorable geology.

     The Quest Project in Alberta Canada injects CO2 from hydrogen production by steam methane reforming (blue hydrogen) into a thick basal Cambrian marine sand with structural and stratigraphic trapping and good seals made by shale and salt bodies. The reservoir, seals, and pressures have all worked according to plan and injection rates are maintained. They did have some problems with salt accumulation due to CO2 dehydrating the reservoir brine. They clean out the salt with glycols. Monitoring wells have shown that the CO2 infiltrated the reservoir porosity as intended.

     The Snohvit project in the Norwegian Sea injected first into a downblock graben into fluvial-deltaic sandstones. The formation was overpressured. Although cores showed very good porosity and permeability there were also shales intermingled, as is the nature of fluvial-deltaics, which created barriers or baffles. This caused the reservoir to pressure up faster than expected. They had hoped that faults would cause CO2 to leak out which would drop pressure, but this did not happen. They then switched to Plan B, which was to inject into a shallower marine sand. This has worked much better.

     The Gorgon project in Australia run by Chevron injects CO2 into 9 wells into a porous turbidite sandstone with 4 water wells drilled updip to draw off water to lower pressure to stay below frac gradient. Trapping is stratigraphic and capillary. CO2 injection has worked well. However, the water wells have clogged with sand so pressure was not drawn down enough and they were ordered by Australian regulatory authorities to lower injection rates and ended up venting CO2. They hope to soon get back to regular injection rates of 4 million tons per year (about 10% of current global CO2 injection). Another problem they encountered is that when the pressure drops after the water is drawn off, the sand, which is coated with chlorite clays, has a tendency to crumble which can lower permeability.

     The In Salah project in Algeria sequesters CO2 from another high CO2-content gas field. Initial injection rates were satisfactory. They were injecting into an estuarine sandstone with variable porosity, downdip from the higher porosity gas field. That lower and lack of uniform porosity caused pressure to rise above frac gradient and likely hydraulically fractured the reservoir and broke the seal. This is what likely caused the CO2 to move along faults and fractures which was not intended. The project was abandoned with only 3.8 million tons injected of the total planned of 17-23 million tons.

     He also noted some other geologic risk factors for CO2. In carbonates there are sometimes vugs and caverns which can have the same effect as faults and fractures and invalidate capillary trapping. Salt plugging as mentioned can be problematic. CO2 hydrates can form when there is water injected with CO2 which can react with carbonates. This can also be an issue but is usually less of a problem than salt plugging.

 

Past CCS Mega-Projects Were Dominated by Enhanced Oil Recovery and Natural Gas Processing of Gas with High CO2-Content

 

     The IEEFA report points this out and also shows that most of the CCS projects of the past were involved with producing hydrocarbons and had little or nothing to do with emissions reductions except that when were a response to compulsory emissions reduction mandates or CO2 taxation. There are some sour gas reservoirs with very high CO2 content. Sometimes in the past those were vented into the atmosphere. The Indian Creek field in West Virginia was developed in 1960’s in the Silurian aged Tuscarora Sandstone. The field produced about an equal amount of CO2 and natural gas. The CO2 was sold to Coca Cola for use in beverages. I worked on a Tuscarora test well in the 90’s about a county away from there. We ran a gas detector for methane, an H2S detector, and a CO2 detector. When we drilled into the formation the CO2 detector maxed out – the most it could read was 10% CO2 - so I noticed what the reading was on the methane detector when it maxed out and compared the final reading on the methane detector to estimate the total CO2 content which was found to be close to 50% of the total gas stream. There was an attempt to flare the gas but as CO2 is a natural fire retardant the gas would not light. I believe that well was plugged and abandoned soon after drilling. Equinor’s Sleipnir field in contrast has a CO2 content of 4-9% and their Snohvit field in the Norwegian Sea has a CO2 content of 5-8%.  

     Exxon’s Shute’s Creek Field CCS project in Wyoming is the third oldest in the world and the largest. It was commissioned in 1986 with the vast majority of the CO2 sold for EOR. The CO2 content of the gas is a whopping 65%, with methane only at 21%. The project was successful at selling CO2 for EOR when there was a demand for it but when there was not a demand for it the CO2 was vented into the atmosphere. As the second graph below from the IFEEA report shows the planned venting over the project life was 54 million tons but the actual venting was 120 million tons – equivalent to three years of global sequestration now. Thus, in terms of carbon emissions the project was a complete disaster. 

Shutes Creek CO2 Targets, Utilization and Sequestration, and Total Emissions 

Shutes Creek Planned CO2 Emissions vs. Real CO2 Emissions

     Equinor’s Snohvit project is an LNG development in the Barents Sea off Northern Norway, commissioned in 2007. The raw gas is delivered to shore, and the CO2 is solidified into dry ice and removed from the gas, then pumped back into the offshore reservoir for storage. As mentioned, this project was also a technical and geologic success, after changing the storage reservoir to a marine sand with uniform properties.

 

 The Strong Anti-CCS Bias of the IEEFA Report

 

     The IEFFA paper: The Carbon Capture Crunch: Lessons Learned, notes that these gas processing CCS projects that involve natural gas with high CO2 content do not adequately address Scope 3 emissions. It merely minimizes production-related Scope 1 emissions from gas with excessive CO2 content. Total emissions are barely dented. The same is true as I have argued, with venting methane from so-called ‘gassy’ coal mines. Mitigating that methane simply involves flaring it rather than venting it which reduces the total greenhouse gas emissions. If Shutes Creek and some of the gassy mines in Southwest Virginia had been subject to CO2 taxes like those in Norway or methane taxes in the case of the mines, they likely would not have been developed. Energy extraction companies are Scope 3-heavy, with up to 90% of their emissions being from end-use combustion. Of course, one might also attribute those Scope 3 emissions to their buyers like power plants. The IEFFA report notes: “In general, due to its association with EOR and historic capture rate issues, carbon capture in the natural gas processing sector has minimal environmental and social credibility as a decarbonisation option.” I agree with them concerning natural gas processing of gas with high CO2 content but EOR does sequester significant amounts of CO2 and utilizes the CO2 for oil production that otherwise would not occur. Of course, EOR from CO2 captured from power plants or industry would not have the added CO2 from the gas field and so would be much better from a decarbonization standpoint.  

     While the IEEFA report is informative and useful I also see some pretty heavy bias. Here is an example regarding gas processing CCS projects:   {they} “… would be operating through the next one or two decades until renewables, green hydrogen and battery technologies take up the whole energy system.” One to two decades? That is way off the mark even by super-fast decarbonization standards and basically an irresponsible statement due to its infeasibility. The paper goes on to show the underperformance of several of these early CCS projects, some just mild underperformance. As many of these were pilot projects or first-of-their-kind projects there would be some expectations of not meeting targets. The Petro Nova coal CCS project was just slightly under target projections and though shut-down after COVID due to low oil prices, is slated to finally start back up. It was a technical success with pretty high capture rates. The paper emphasizes CCS opex costs and operations emissions as failures but in most cases, those were factored into the projects, although going over cost is not unexpected with new and pilot projects. Another biased statement in the report is this declaration: “The era of fossil-based power plants is over.” Last I heard China, India, Pakistan, South Africa, and South Asian countries were planning on building many new coal plants and new natural gas plants are being built and will be needed in the U.S. and in many other countries. Gas and coal still make more electricity by far than any other source. Retrofitting coal plants is more complicated and expensive compared to combined cycle natural gas plants where carbon capture can be more standardized. However, more CO2 can be captured at the coal plants since they produce more CO2. It is quite true that the Kemper plant in Mississippi was a complete failure, both technically and economically. Some of those failures came before the decision to capture carbon. There were big problems with its unproven coal gasification systems.

     In considering blue hydrogen the paper invokes work done by strongly biased scientists at Cornell and Stanford who wildly overestimate methane emissions from natural gas production to argue that even with CCS blue hydrogen is emissions intense. This is incorrect. As the paper was written in 2022 when gas prices were high they note that makes these projects uneconomic. However, since then gas prices, elevated due to shortages in Europe due to avoiding Russian gas, have come down. Even so, blue hydrogen will work best in places where gas prices are likely to remain low, such as pipeline-constrained Appalachia where gas is abundant and cheap. It will not work in Europe, except maybe in Norway. While its economics are subject to the volatility of gas prices, certain regional gas prices have remained constantly low for years with the exception of 2022.

     The paper also points out several times that total CO2 captured does not reflect CO2 avoided since energy is consumed operating the capture, transport, and sequestration processes. Of course, this is well known, and I do not think there is anyone suggesting that total CO2 captured = total CO2 avoided.

     The Great Plains Synfuels Gasification plant in North Dakota is an example of a lignite coal that is used to produce natural gas from gasifying coal into syngas. Lignite coal is the lowest rank and highest emitting coal. It is the only coal-to-syngas plant in operation in the U.S. and has been operating since 1984. Carbon capture for EOR began in 2000. Before that the CO2 was vented. Thus, this is another example of a plant that emits more CO2 than other plants of its type due to resource quality. Thus, as in the high-CO2 content gas processing and gassy coal mines, the avoided CO2 is much less than the captured CO2. The plant may be purchased for a blue hydrogen project to be made foften stranded associated gas from the Bakken oil fields. That could lower flaring rates as well.

     The report also characterizes an underperforming ethanol CCS project for saline aquifer sequestration and a successfully performing nitrogen fertilizer CCS project for EOR that also uses some of the CO2 in an acid gas process to make urea ammonium nitrate, quite economically as fertilizer plants do. They also talk a bit about a new project in the Middle East aiming to capture carbon from steel-making. Again, they tout currently uneconomic processes like green hydrogen and new and not-ready-for-primetime techniques like so-called ‘green steel’ by direct reducing iron with green hydrogen, and of course, solar, wind, and storage over any fossil fuels.

     I guess I should have noted their bias in their mission statement: “About IEEFA: The Institute for Energy Economics and Financial Analysis (IEEEFA) examines issues related to energy markets, trends, and policies. The Institute’s mission is to accelerate the transition to a diverse, sustainable, and profitable energy economy.”

 

Other CCS Co-Benefits and Risks

 

     One major co-benefit of CCS can be capture of other combustion pollutants including many criteria pollutants with the CO2 stream which can reduce local air pollution.  SO2 in particular, but also NOx, VOCs, particulates and heavy metals may be captured, although many of the latter two end up in the significant volumes of fly ash at coal and biomass plants that must be managed. Waste-to-Energy plants typically have a very low CO2 capture rate, around 10%, so are not good candidates at present for CCS. Another possible risk is the creation of hazardous air pollutants (HAPs) in the breakdown of the solvents used in the carbon capture process. Those need to be mitigated.

 

Conclusions          

 

     While past CCS in particular has been quite expensive, quite dependent on subsidization, with some underperforming and failed projects, that is not unexpected with new and newly implemented technologies without standardization, modularization, supply chains, and economies of scope and scale to lower costs, climb the learning curves faster, and improve success rates. I believe with those improvements and with continued needed subsidization it could be much more successful in the new phase we are entering. Dependence on subsidization will decrease through time. Streamlining permitting will also reduce costs and timelines. Currently, permit approval time is in the range of 18-36 months so a speed up there would be helpful as each type of project gets better understood by regulators and as duplicatory regulation is reduced or eliminated. Such actions would also reduce regulatory uncertainties which can affect financing.  O&M costs can vary quite a bit depending on type of project, generally from 5-25% with some in the past hitting 30%. In the near-term constraints on availability of pipes, steel, chillers, compression equipment, heat exchangers, and labor may slow project development. Cash flow models in various CCS projects are also full of risks and uncertainty and as those become better understood the financial processes can be streamlined. The generous IRA upgrades to the 45Q credits will be helpful.

 

 

References:

 

Energy Futures Initiative Webinar. Turning CCS Projects into Blue Chip Investments: Policy Action. February 14, 2023.

 

Webinar: Geointegra Consulting. CCS: Flop or the Future? A technical evaluation of recent commercial Carbon Capture and Storage projects. February 8, 2023. CCS - Flop or Future? - Bing video

 

Levelised cost of CO2 capture by sector and initial CO2 concentration, 2019. Last updated 26 Oct 2022. International Energy Agency. Levelised cost of CO2 capture by sector and initial CO2 concentration, 2019 – Charts – Data & Statistics - IEA

 

Carbon Capture Is Coming Under Fire For Underperforming. Felicity Bradstock. Oilprice.com. February 9, 2023. Carbon Capture Is Coming Under Fire For Underperforming | OilPrice.com

 

Webinar. Carbon Capture Outlook. Presented on February 1, 2023. Todd Bush. Decarbonfuse.com.

 

The Carbon Capture Crux: Lessons Learned. Bruce Robertson, LNG/Gas Analyst and Milad Mousavian, Energy Analyst. September 2022. Institute for Energy Economics and Financial Analysis (IEEFA). The Carbon Capture Crux.pdf

 

The Tax Credit for Carbon Sequestration (Section 45Q). Congressional Research Service. June 8, 2021. The Tax Credit for Carbon Sequestration (Section 45Q) (fas.org)