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)
