Legislature(2023 - 2024)BUTROVICH 205
03/08/2023 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| Carbon Capture and Storage (ccs) | |
| Alliant Insurance Discussion of Carbon Capture | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
^Carbon Capture and Storage (CCS)
CARBON CAPTURE AND STORAGE (CCS)
[Contains discussion of SB 49.]
3:31:03 PM
CO-CHAIR GIESSEL stated that the committee would continue to
discuss SB 49 relating to carbon capture, utilization, and
storage. She welcomed Dr. Tip Merkel to begin his presentation.
3:31:46 PM
TIP MERKEL, PhD., Senior Research Scientist, Gulf Coast Carbon
Center, Bureau of Economic Geology, Jackson School of
Geosciences, University of Texas at Austin, Austin, Texas,
stated that the Gulf Coast Carbon Center (GCCC) is an industry-
sponsored applied research group that helps the private sector
develop an economically viable industry to store CO2. He pointed
to the names and logos of the current GCCC sponsors displayed on
slide 3.
3:34:29 PM
DR. MECKEL reviewed the key points in the presentation:
• Carbon Capture, Utilization, and Storage (CCUS)
is not a new topic.
• CCUS basics: Capture, Transport, Storage.
• Deployment focus is on emission hubs, including
marine ports and other ports where there are
concentrated industrial emissions.
• Economics driving the reduction of atmospheric
emission projects are rooted in tax credits in
IRS Section 45Q.
3:35:37 PM
DR. MECKEL reviewed the components of CCUS, paraphrasing the
following:
The CCuS business is evolving, but at its core, it
will likely be populated by emissions sources, service
and technology providers, midstream transport, well
and storage operators, and tax equity driven project
investors / developers.
The diagram shows the CO2 sources on the left that could be
anything that is required to report under the Environmental
Protection Agency (EPA). Each source requires the development of
some type of capture equipment. Transport of the CO2 is by either
pipeline or ship. He noted that the US has about 50 years of
experience with transport by pipeline. Transport by ship is
coming. The last component is a sink to hold the CO2 for some
type of utilization or for permanent sequestration.
3:36:59 PM
DR. MECKEL displayed slide 6 and explained that CO2 emissions
from different industrial processes come out at different
pressures, temperatures, and concentrations. The pictures on the
top row of a coal power plant, a gas power plant, and air
capture typically have low concentration emissions. The emission
sources on the bottom row of a natural gas processing plant, an
ammonia plant, an ethanol plant, and a cement plant typically
have higher concentrations of pure CO2, which will be less
expensive to address. The point is that there is no single cost
associated with CO2 capture; it is highly variable among emission
sources.
3:37:58 PM
DR. MECKEL stated that the purpose of slide 7 is to convey the
experience Texas has had with CCS. Over the past decade, nearly
1 gigatons of carbon dioxide has been injected into subsurface
formations throughout Texas. It is primarily used for enhanced
oil recovery in the Permian Basin of west Texas. He stated that
1 gigaton of CO2 over a decade is on the scale that makes pure
sequestration feasible.
DR. MECKEL said the map on slide 8 shows the locations of major
US Department of Energy funded projects in the US and throughout
the world over the last 20 years. The projects identified in red
reflect the flagship carbon capture programs in the last 10
years. These led to opportunities in other states and regions.
3:39:20 PM
SENATOR CLAMAN joined the committee.
DR. MECKEL said slide 9 provides an overview of carbon storage.
He clarified that the injection sites depicted have nothing to
do with shallow underground sources of drinking water that are
protected under the Safe Drinking Water Act (SDWA). The
injections go 1-2 miles below the surface, into the depths from
which hydrocarbons are recovered. These are either depleted oil
fields or saline formations. The CO2 that's injected stays in
place much the same way as buoyant hydrocarbons that are trapped
in the subsurface. The physics are the same.
3:40:30 PM
DR. MECKEL directed attention to the graphic on slide 10 that
includes an example of offshore transport, CO2 injection, and
geological storage. He spoke to the following:
Why Offshore?
• Emissions hubs are at coast/ports
• Single land/mineral owner (GLO)
• Avoid NUMBY/Unitization
• Data availability
• Fewer, younger legacy wells
• Avoid USDW Class VI focus
• Monitoring easier?
• Long term liability GLO
• Vessel transport flexibility
3:41:26 PM
DR. MECKEL said slide 11 highlights the Porthos Project in the
Netherlands. It illustrates the industrial emitters, the
pipeline network, and/or offshore infrastructure that's being
developed to inject CO2 from the port sector. This model has been
replicated throughout the world, including the Gulf Coast, UK,
and the Baltics.
3:42:23 PM
DR. MECKEL turned to slide 12 that describes the Inflation
Reduction Act of 2022 (IRA), noting that it followed the
Bipartisan Infrastructure Law that passed in 2021. The graphic
on the right illustrates the estimated 2022-2031 energy
transition spending in the IRA and BIL. He said there was
actually more funding for CCS in the BIL than the IRA, which has
a lot to do with the Section 45Q tax credits. Their structure
and effect are similar to the wind and solar tax credits. He
said he can imagine capital engagement to develop CCS projects
as the tax credits were expanded and made transferable in the
IRA. He reminded the committee that the 45Q credits were
introduced in 2009 and have enjoyed bipartisan support over the
last decade.
3:43:30 PM
DR. MECKEL advised that slide 13 lays out how the 45K tax credit
works. It has a base fee that is increased if prevailing wage,
hour, and apprenticeship requirements are met. The credit for a
CO2 storage project is $85/tonne without enhanced oil recovery
and $60/tonne with enhanced oil recovery. Congress is
considering a bill that offers $85/tonne for both types of
project. The example on the slide suggests a project with 1
million tonnes of carbon capture and injection per year, which
would accrue an $85 million tax credit/year. The credit is
available for 12 years which brings the tax credit value into
the $1 billion range. The credits are available for direct pay
and now are transferable. This has stimulated interest in these
projects.
3:44:43 PM
DR. MECKEL described slide 14 as dense with information about
jobs and the economic impact of carbon capture deployment in
Texas. He pointed to the link on the upper right that may have
information about Alaska. He said most of the studies indicate
that developing the CCS industry results in significant job
growth and retention associated with long-term wealth
generation.
3:45:27 PM
SENATOR WIELECHOWSKI joined the committee.
DR. MECKEL spoke to the following to discuss injection well
permitting.
• EPA Class II CO2 used for enhanced oil recovery
(EOR).
• EPA Class VI CO2 injected for storage/disposal.
• State Primacy
He noted that only North Dakota and Wyoming have Class VI
primacy, although several other states, including Alaska, were
applying for or thinking about applying for Class VI primacy.
3:46:35 PM
DR. MECKEL directed attention to the color-coded map of the US
and spoke to the following in slide 16:
State legislative sessions are underway in 2023 in
most states across the country and more than 70 carbon
management, hydrogen, and procurement-related measures
and bills of interest are under consideration.
He noted that the website cited on the bottom of the slide
provides information about what other states are doing regarding
CCS.
3:47:19 PM
DR. MECKEL stated that slide 17 provides a summary of his
comments. It read as follows:
SUMMARY
• Carbon Capture Utilization and Storage (CCUS) is
not a new topic.
• CCUS basics: Capture, Transport, Storage.
• Deployment focus is on emission hubs, including
marine ports.
• Economics are rooted in tax credits.
• CCUS is an economic growth opportunity.
The takeaway is that CCUS is an opportunity for growth in many
areas.
3:48:43 PM
DR. MECKEL described the following resources listed on the final
slide of the presentation. It read as follows:
RESOURCES
• DOE-NETL CCS Newsletter:
https://listserv.netl.doe.gov/scripts/wa.exe?SUBED1=SE
QUESTRA TION&A=1
• GCCSI: https://www.globalccsinstitute.com/
• Gulf Coast Carbon Center:
https://www.beg.utexas.edu/gccc/
3:49:15 PM
CO-CHAIR GIESSEL asked if he would talk briefly about the slides
that discuss shipping liquefied CO2, because that topic is of
significant interest to the committee.
DR. MECKEL turned to slide 20 and conveyed that he was a
scientific advisor on the Norwegian Northern Lights Project that
has liquid CO2 built into the process. He continued to speak to
the following:
Liquefied CO2 (LCO2) Shipping
Topics of interest: rapidly evolving full-chain
maritime solutions for low-C energy development and
use.
• Capture of emissions from powering vessels
• Transport of low carbon energy (carbon-neutral
hydrocarbons, Hydrogen, Ammonia)
• LCO2 transport; synergy with LPG/LNG transport and
design
• Leapfrogging into offshore storage without
pipelines FPSO/FSO for CCS, injection
capabilities
• Onshore buffer storage capacity aspects
He turned to slide 21 and explained that it is a rendering of a
site west of Bergen, Norway. It has two berths for vessels that
will bring CO2 from southern Norway where it will be offloaded
into tanks and then transferred offshore through a subsea
pipeline to a storage location. He said both the Southeast Asian
and the greater North Sea communities are looking closely at
shipping LCO?2, and it is also becoming an important part of the
US deployment of this technology.
CO-CHAIR GIESSEL noted that the last few slides had different
maps of the US.
DR. MECKEL stated that the maps come from the tracker website he
referenced earlier. They show different elements of CCS. Slide
22 shows in teal the states that are evaluating pore space
ownership issues related to CCS. He noted that in Texas, and a
number of other states, the surface owner is deemed to own the
pore space into which CO2 would be injected. Negotiating a lease
requires negotiation with the surface owner, who is not
necessarily the mineral owner.
3:53:09 PM
He noted that, as mentioned earlier, the next slide addresses
the topic was Class VI primacy. Several states have applied but
only North Dakota and Wyoming have received Class VI primacy.
This means that there is a state agency that is permitting the
CO2 injection wells under a permitting process that is at least
as rigorous as the EPA Class VI process.
DR. MECKEL said the states shaded green on the next slide are
those that have a combination of ownership interests. His
understanding is that this is about the interaction between
hydrocarbon development and CO2 storage. He noted that in
Louisiana there's been a lot of discussion about whether
entities can drill through a CO2 storage complex to access
minerals. The state has indicated that CCS projects will not
condemn mineral development in any way. The details on what this
means has to be worked out, particularly if the mineral and
surface estates are separate.
He said the states shaded red on slide 25 reflect those that
have long-term state stewardship. These states have existing
legislation that addresses the long-term liability of a project
so the process for closure and after a project ends is clearly
laid out. He noted that companies and investors typically are
hesitant to proceed with a project if there isn't some assurance
of how the long-term liability will be handled.
DR. MECKEL said the last slide shows in dark blue the states
that have considered how the trust will be funded, managed, and
used.
3:56:24 PM
CO-CHAIR GIESSEL asked about the manufacturer of the vessels
that will ship liquified CO2 to Bergen, Norway, because the
vessels would need to be highly specialized to handle the highly
corrosive LCO2.
DR. MECKEL answered that Mitsubishi is designing the vessels.
They will have more but smaller and lower pressure containers
that will hold 99.9 percent pure CO2 with no water component
because that's the catalyst for corrosion. His understanding is
that the vessels currently under construction have some
specialized engineering, but not as much specialized metallurgy
as he had anticipated. Other companies that are interested in
designing these types of ships have experience with LPG and LNG.
He expects to see one of these vessels in the Gulf of Mexico
within 2-5 years.
3:59:07 PM
SENATOR DUNBAR asked if it was fair to say that no CO2 tankers
were operating in the Pacific.
DR. MECKEL said he wasn't aware of any that were on the water.
SENATOR DUNBAR recalled that he anticipated the tankers would be
built in 2-5 years.
DR. MECKEL clarified that he anticipates seeing one on the water
in the Gulf of Mexico in 2-5 years and in Asia or Europe late
this year or next year.
SENATOR DUNBAR noted Alaska's experience with hydrocarbon spills
and asked what the impact would be if a tanker spilled an entire
load of CO2 into the water.
DR. MECKEL replied that it would look very different than a
release of hydrocarbons. CO2 is a natural compound in the
environment and if it were released under pressure it would go
to the gas phase and dissipate quickly. He noted that when a CO2
well is out of control, the CO2 vapor vents and forms dry ice
until the well is under control. He also noted that when the
Nord Stream Pipeline was damaged, there was a lot of dry ice
formation that dissipated rapidly.
CO-CHAIR GIESSEL thanked him for the excellent presentation.
^Alliant Insurance Discussion of Carbon Capture
ALLIANT INSURANCE DISCUSSION OF CARBON CAPTURE AND SEQUESTRATION
4:02:13 PM
CO-CHAIR GIESSEL announced the next two speakers from Alliant
Insurance Inc. would discuss carbon capture and sequestration
(CCS).
4:03:06 PM
AUSTIN CAHILL, Managing Director and Lead of the Tax Insurance
Team, Alliant Insurance Inc., stated he was a tax attorney by
trade, which was how he got involved in the carbon capture
industry. As Dr. Merkel discussed previously, the economics of
these projects are related to the use of carbon capture
sequestration and the tax credits derived therefrom.
He conveyed that he spent time with the international
restructuring group KPMG before moving to insurance broking,
where a large portion of what they do is to secure tax credits
for tax credit investors. With passage of the Inflation
Reduction Act, being a tax credit investor includes carbon
capture. Alliant Insurance has been eager to become involved in
this space to help de-risk these extremely large carbon capture
projects and potential challenge from a taxing authority.
MR. CAHILL stated that Alliant Insurance Services was
established in California in 1925 and is one of the largest
insurance brokerages in the United States. Their tax insurance
brokerage is the largest tax insurance brokerage worldwide by
volume of premium placed. In policy limits, these tax credits
account for tens of billions of dollars per year in protection,
which shows this is already a very large industry. He said he
and Mr. Ballan agree with Dr. Merkel that this is going to be a
very economically fruitful area in terms of energy transition
and carbon capture specifically.
4:05:10 PM
HARRY BALLAN, Managing Director, Alliant Insurance, stated he
was a tax attorney who practiced at Davis Polk and Wardwell LLP
from 1993 until a couple of years ago. He became a partner in
1999. He'd also been a professor of tax law since 2003, teaching
mostly at NYU, and he spent a few years as a law school dean.
He agreed with the previous speaker that Section 45Q of the tax
law and in particular Section Q, as amended and extended, and
the Inflation Reduction Act was a game changer in the sense that
the economic benefits that are available to participants in the
capture and sequestration of carbon were unprecedented. As Dr.
Merkel said, 45Q has been in the law for some time, but the
availability of $85/metric ton allocated between capture and
sequestration makes it quite profitable for all the parties
involved.
MR. BALLAN stated that their role at Alliant Insurance Services
was to insure the credits. Because there are questions around
qualification, the party also has to qualify for the credit by
capturing and sequestering the carbon. That means having a Class
VI well or a Class II well that is properly certified by the
federal government or by states that have applied successfully
for primacy. Then there is the possibility of the recapture of
the credits as a consequence of leakage, although experts say
that is a remote possibility when sequestering in certified
wells that are one or two miles below the surface of the earth
in saline formations. He suggested that others could speak to
that.
MR. BALLAN stated that robust insurance has developed and will
continue to develop around qualification and recapture. This
will be important for those who get the credits directly and for
those who benefit from the capture and sequestration. It's
possible for parties to enjoy tax exemption, and even
governments are able to enjoy the credits through direct
payments. Even non-taxpayers can enjoy the credits. And because
it's also possible to transfer credits, the insurance of those
credits is particularly important under that new bill.
4:08:38 PM
MR. BALLAN said one other aspect of the new legislation that has
attracted a lot of attention is that in exchange for or as part
of the deal relating to the $85/metric ton, the credit is
structured as a base credit amount of $12/metric ton and a bonus
credit rate of $85/metric ton. Everybody they've spoken to
expects to get the bonus credit rate.
He explained that in order to get that bonus credit rate of
$85/metric ton, it will be necessary to comply with prevailing
wage requirements or prevailing wage and apprenticeship
requirements. That is an aspect of qualification that needs to
be developed and monitored. There is guidance from the Treasury
Department about the type of record keeping that is necessary,
including that the prevailing wage and apprenticeship
requirements apply to the construction, repair, and maintenance
of the capture and sequestration equipment and technology. They
apply to both employees and independent contractors and all the
people engaged in the subcontracts.
MR. BALLAM said there are perceived and real social cost
benefits associated with complying with the prevailing wage and
apprenticeship requirements. Insurance plays a very important
role by helping with the maintenance of the appropriate records
to ensure compliance so the parties are able to qualify for the
credits.
4:11:10 PM
MR. CAHILL said key concerns their clients have are the specific
risk associated with qualifying as a capture and sequestration
facility and then meeting the wage and apprenticeship
requirements. He suggested Mr. Ballan provide his insight and
briefly describe what the recapture risk is and how it operates
in Section 45Q. Doing so will set the stage for the discussion
around how the insurance operates.
4:11:55 PM
MR. BALLAN explained that the carbon recapture risk relates to
leakage. Once the sequestration has occurred in a Class VI well
with permanent and secure geological storage, the occurrence of
any leakage could result in the loss of the production tax
credits in a subsequent year through recapture.
MR. CAHILL added that recapture provisions are typically limited
to three years plus the open year of whatever period of credit
year you are in. As Dr. Meckel alluded to, a client might
receive production credits for 12 years, but if in year six they
had a mass leakage event and all of the carbon that had been put
into the ground leaked out, they would only be able to recapture
three years plus whatever was put into the ground plus that open
year. There is a cap on the liability resulting from recapture.
He said that is important for the insurance piece.
4:13:54 PM
MR. CAHILL restated that the parties they work with want to
ensure that that they are entitled to the tax credits worth
$85/metric ton. He noted that while solar and wind involve an
additional sale of electricity and revenue stream, the full
value of carbon sequestration projects is derived from the
capture and sequestration of the carbon. He emphasized that it
is critical to all parties that these credits are protected
whether it is the capture company that is working with the
emitter to take the carbon, the company that is taking
responsibility for the storage and sequestration, or both
companies that are vertically integrated. They all want
protection.
4:14:45 PM
MR. CAHILL explained that tax attorneys offer the protection.
Traditionally, this was an insurance solution that was required
by large banks for traditional tax equity investors on large
solar and wind projects. The large banks wished to transfer the
risk of loss to an A-rated counterparty. There are many sponsors
that will be working in renewable energies and not all the
companies will be A-rated as a counterparty. The insurance wraps
the risk of credit recapture or failure to qualify, thereby
transferring that risk to an A-rated insurer. He noted that the
insurance allows the original tax equity investor to be
comfortable enough in this emerging technology to invest heavily
in these projects. He added that while carbon capture and
sequestration (CCS) and Section 45Q are not new, the projects
have gained momentum as a result of the Tax Cuts and Jobs Act
and the Inflation Reduction Act and are now going at full steam.
He remarked that his group determines the best insurance for
these projects by using the solar and wind model as a reference
point.
MR. CAHILL continued to explain that the client, either the
capture or the store company, is indemnified for the risk of
loss associated with the qualification piece or the recapture
piece. He compared the process to a seamless solution that
transfers any risk of challenge from the Internal Revenue
Service (IRS). The insured client would be whole, which de-risks
the main value of the assets of these transactions, primarily
the credits. All things considered, the cost of the insurance is
relatively inexpensive. He summarized that the policy covers
leakage risk and qualification risk. The latter involves wage
and apprenticeship, which is difficult to comply with.
4:17:00 PM
MR. CAHILL continued to explain that a client works with a
broker to transfer the risk to an insurer. To underwrite the
risks, the broker needs the client's federally mandated
Measurement, Reporting, and Verification (MRV) plan, and tax due
diligence provided by a reputable tax advisor that has reviewed
the project's implementation and determined that the project
should qualify for the tax credits. If the underwriter
determines that the project properly qualifies, the credits are
insured with a one-time payment for a policy that will last ten
years. Any challenge to credits from the federal government for
the ten years that the project is in service will be protected.
This is a true risk transfer. He explained that the client
purchases the insurance and submits a one-time payment of two to
five percent of the amount of insurance being purchased.
4:18:17 PM
MR. CAHILL advised that risk tolerance determines how much
insurance a client purchases. For an extremely conservative
party, 100 percent of the value of the credits is insured.
Conservative clients choose this option because a loss of 100
percent of the credits is possible if a well blows up in year
three, extinguishing the use of the well. In that circumstance,
the party would lose the projected value of the credits in
future years three through twelve. The policies also cover any
interest, penalties, defense fees, and the extent to which the
proceeds themselves will be taxable in gross-up. These policies
place clients in the same position as never having been
challenged by the IRS. He also spoke about transferring the
credits to unrelated parties who were previously uninvolved,
similar to municipal bonds. Wrapping the risk with insurance
creates overall project economics. Investors who previously may
have been reticent to invest in this technology, now are willing
to put significant amounts of capital into these projects.
MR. CAHILL reported witnessing large amounts of capital pour
into this space from all different types of investor classes. He
witnessed investments from family offices, large alternative
investment funds, big banks, and local banks. Additional
investors include emitters who are not able to avail themselves
of carbon capture technology because of jurisdiction or
location. He opined that everybody wants these credits. The
credits are worth a lot of money and the insurance solution
makes these credits safe from all but things like fraud. He
described these insurance policies as relatively
straightforward.
MR. CAHILL added that the payment history on tax insurance is
extremely high. He assured the committee that he has a 100
percent claim payment history for tax insurance policies. He
reiterated that the policies can be trusted to backstop risk
related to the Section 45Q credit qualification. He added that
credits could be used to collateralize projected future cash
flows. He stressed the benefit of carbon capture insurance and
mentioned trusted companies that are involved in this space. He
remarked that working with a trusted insurance broker can help
to de-risk the transaction, bring certainty to projects, and
create a new stable revenue source.
4:21:30 PM
MR. CAHILL suggested that they spend the remaining time
discussing the model that Alaska might choose to use. The
approach could be to rent the land and certify through primacy
the Class VI certifications and charge fees through that.
MR. CAHILL said a more profitable opportunity would involve
ownership of the wells, the injection sites, and pipelines. That
option establishes the ability to build pipe into various
locations. He noted that the largest problem encountered in the
Lower 48 was the ability to construct pipe over long distances.
The pipe construction problems are complicated by private land
ownership. He opined that anybody that can build pipe over long
distances would be at a considerable advantage.
4:22:41 PM
SENATOR CLAMAN asked if the notion of making money off tax
credits relies on having a federal tax structure that creates
the credit so that there is a benefit to doing all this. He then
asked if this would all stop working if Congress were to
suddenly change its mind and stop the tax credits.
4:23:38 PM
MR. BALLAN said he would answer the question more as a tax
professor than as an Alliant employee. One possibility was if
the cost of emitting carbon was $20/metric ton and as a
consequence of capturing, transporting and sequestering, it was
worth $85/metric ton. For example, if the emitter were an
ethanol plant, there might be a ratio of 85 to 20, the credit
over the invested amount. Another scenario might be cement
manufacturing where natural gas is converted to produce hydrogen
with carbon as the byproduct. The cost of production doesn't
approach $85/metric ton. The models have different production
costs per metric ton, but the production costs tend to be less
than the credit per metric ton. That's what's so powerful;
invest $1 and get more than $1 credit. To the question of
whether the tax credit can be taken away, he said the obvious
answer is that any tax credit can be taken away. But if the
question is what's different about the structure of this credit
as compared to prior iterations of energy-related credits, the
answer is that there is something quite extraordinary about this
credit.
MR. BALLAN explained that many of the credit schemes that have
existed in the tax law have involved phase-downs and phase-outs
over sometimes long periods of time. But something that caught
everyone's notice and was quite deliberate in the Inflation
Reduction Act was that in the investment tax credits, the firm
level of 30 percent, assuming compliance with prevailing wage
and apprenticeship requirements, was not set with a phase-down
or phase-out. It was set as 30 percent. The message was that
this was intended to be a permanent credit. Because this is a
production credit, a carbon capture credit that goes over 12
years, it would be difficult, as a matter of tax policy, to
change a 12-year promise midstream. He expressed his belief that
Congress intended this to be long term. There is some degree of
bipartisanship, even around the Inflation Reduction Act at this
point. He opined that the smart money is betting on it being a
permanent credit.
4:27:02 PM
MR. CAHILL added that there are other uses for sequestered
carbon. Even if the carbon credit were taken away, the pie-in-
the-sky concept is that as carbon capture develops as an
industry, smart industrial entrepreneurs will figure out better
uses of carbon and manufacturing processes, and that will
increase the demand for carbon such that, if the credit were
taken away, there would be other industrial uses of carbon once
sequestered. He opined that, at this point, it is fairly clear
that the value of the projects are from the carbon credits. That
is the asset. Carbon is being produced, and right now the
federal government is a buyer of carbon. As Mr. Ballan pointed
out, the carbon credit has been around since 2009 and isn't
being phased down. It has bipartisan support so it will probably
be here for the foreseeable future.
CO-CHAIR GIESSEL thanked the presenters.
Introduction to Geologic Carbon Storage
Introduction to Geologic Carbon Storage
4:28:31 PM
CO-CHAIR GIESSEL announced a presentation on geologic carbon
storage by the state geologist.
4:29:03 PM
DAVID LEPAIN, State Geologist and Director, Division of
Geological and Geophysical Surveys, Department of Natural
Resources (DNR), Anchorage, Alaska, reviewed the outline of the
presentation on slide 2:
• Physical and chemical characteristics of CO2
• Requirements for geologic CO2 storage
• CO2 storage mechanisms
• Storage in depleted oil fields and saline formations
• Storage in unmineable coal seams
• Geologic carbon storage in Alaska
• Cook Inlet
• North Slope
• Interior sedimentary basins
4:30:21 PM
MR. LEPAIN displayed slide 3 and described the physical and
chemical properties of CO2. He made the following points:
similar On the surface of the earth, CO2 is an odorless, colorless
gas.
similar If CO2 is sufficiently compressed, it takes on the
characteristics of a liquid and a gas, but it is neither one
nor the other. It is referred to as supercritical CO2.
similar Hydrostatic pressure increases with depth due to the weight of
the overlying column of rock and water.
similar If supercritical CO2 is injected below a depth of about 2,600
feet from the subsurface, the pressure is great enough that
the CO2 will remain supercritical.
similar Supercritical CO2 is more dense, so more will fit in a
reservoir.
similar Supercritical CO2 is buoyant. It is less dense than H2O so it
will rise up through a formation, which is important.
4:31:52 PM
MR. LEPAIN referred to slide 4 to discuss the criteria for
subsurface formations to be attractive as reservoirs for storing
CO2. He made the following points:
similar Sandstone is one of the most prospective sedimentary rock
types for storing CO2.
similar Geologists are most interested in sedimentary basins that have
interlayers of sandstone and shale.
similar The sandstones are prospective as storage containers for CO2
but there must be impermeable formations overlying the
sandstones.
similar CO2 that's injected into sands rise through the water column
until it reaches an impermeable layer and is trapped.
similar The sandstones must have porosity or void space.
similar The photo on the upper right is a sandstone in the Tyonek
Formation in Cook Inlet, and the blue spaces around the sand
grains are porosity.
similar The pores must be interconnected for the supercritical CO2, or
any other liquid, to move through the rock.
similar The sands must be in a trapping configuration, as shown in the
diagram on the left. It's a schematic cross section through a
part of the Kenai Gas field. The sedimentary layers originally
were deposited horizontally; they're domed due to large scale
stresses in the earth's crust.
similar The structure is called a fold, and when rocks are domed it's
called an anticlinal fold.
similar The yellow reflects sand, the brown and green are mudstones,
and red is sand that's saturated with gas.
similar Gas is lighter than water so when a gas molecule goes into a
sand bed it will migrate up until it reaches the apex of the
fold structure with an overlying mud rock. At that point it's
trapped.
4:36:08 PM
SENATOR CLAMAN asked what happens when the increased pressure
from injecting the CO2 causes a fracture, similar to what
happens in the fracking process to produce oil.
MR. LEPAIN said it depends on how far the induced fracture
propagates. If the induced fracture is contained in the
sandstone formation into which the CO2 is being injected, there
probably wouldn't be any damage. But if the fracture propagates
into the overlaying mudstone, CO2 could migrate into that seal.
SENATOR CLAMAN commented that the CO2 would be lost.
MR. LEPAIN said yes, but there may be other opportunities for
the CO2 to be trapped and sealed in subsequent layers of
mudstone. He added that this is well known technology and the
industry understands how to keep the injection pressures below
the frack pressure.
4:38:30 PM
MR. LEPAIN directed attention to the images on slide 5 to
discuss the mechanisms for storing CO2 in porous and permeable
formation.
similar Buoyant trapping is illustrated in the image in the center
that shows an injection well on the right. The CO2 is buoyant
and will migrate up to the crest of a fold structure.
similar Residual trapping is shown on the lower left. Some CO2 is left
behind as the CO2 flows.
similar Solubility trapping occurs when CO2 is dissolved in the
formation water. It forms a weak acid that is trapped.
similar Mineral trapping takes place over hundreds of thousands to
millions of years, so it's not relevant in this context.
4:40:20 PM
MR. LEPAIN turned to slide 6 to discuss what attracts geologists
looking for CO2 storage opportunities.
He described the well understood declining or depleted oil and
gas fields as the low hanging fruit. He spoke to the following
bullet points:
• Depleted oil and gas fields have:
• Proven reservoir, trap, and seal
• Extensive datasets that characterize reservoir
properties, temperature, pressure, and water
salinities
• Sandstone body geometries and associated pore
volumes are well-characterized
• Known original oil-in-place and production
history
• Existing infrastructure
• Declining oil fields CO2 for enhanced oil recovery
(EOR)
MR. LEPAIN stated that saline formations are much less well
understood because there hasn't been the economic incentive
to study them. The subsurface formations in Cook Inlet and
the North Slope don't host hydrocarbons, but they have
saline formation waters and have great potential to store
CO2. He spoke to the following bullets:
• Saline formations:
• Total dissolved solids >10,000 parts per million
• Non-potable water
• Isolated from potable water sources saline
aquifers deeper and separated from aquifers by
seals
• Depositional environment of sedimentary formation
influences depth to non-potable water
• Marine shallower
• Non-marine deeper
• Data may be lacking - not as well-known as
depleted oil fields
4:44:23 PM
MR. LEPAIN turned to slide 7 to discuss the storage
possibility of injecting CO2 into unmineable coal seams. He
described coal seams in the deep subsurface as largely
unmineable because of the economics. He continued to say
that most coals are naturally fractured. The primary
fracture system runs throughout the coal seam, and
secondary fractures connect primary fractures. CO2 that's
injected into the primary fractures helps in gaining access
to the microform network in the body of the coal matrix. He
continued to speak to the following bullets:
• CO2 in coal is stored in naturally occurring
fractures (cleats) and micropores in coal
• Cleats provide permeability and access to larger
surface area (micropores)
• Methane (CH4 ) and CO2 strongly attracted to coal
particles
• CO2 molecules attracted more strongly to coal
particles than methane displaces methane
• Coal rank influences storage capacity (IPCC, 2005)
- Low rank coal lignite
CO2 storage capacity >10x methane -Anthracite
CO2 storage capacity = methane
• Fate of displaced methane (CH4)?
MR. LEPAIN pointed to the image on the lower right that shows a
50 foot coal seam from the Tyonek Formation in Cook Inlet. The
point it intends to make is that there is a lot of coal in the
subsurface of Cook Inlet, and the same applies to the North
Slope and several other Interior basins.
4:46:43 PM
SENATOR CLAMAN asked where the coal in Cook Inlet and the North
Slope was located relative to the oil.
MR. LEPAIN replied that it depends on the formation, but
strictly speaking they are separate. Most of the reservoirs on
the North Slope are in sandstones that were deposited in a
marine environment, which is different than the environment
where the coals form. However, there is some interfingering, so
some reservoirs on the North Slope may be in relatively close
proximity to coals.
4:47:47 PM
SENATOR KAUFMAN wondered whether the displaced methane could be
used as the fuel to provide compression and drive topside
equipment.
MR. LEPAIN said yes, there are a lot of uses for the methane.
SENATOR KAUFMAN posited that the gas would be dry and fairly
easy to condition.
MR. LEPAIN replied it would be similar to the gas that's
produced from Cook Inlet today.
SENATOR KAUFMAN asked whether the materials used for this
purpose were high alloy.
MR. LEPAIN said that was outside his area of expertise.
4:49:19 PM
MR. LEPAIN provided the following summary of geologic carbon
storage on slide 8:
• Geologic storage options include depleted and
declining oil and gas fields, saline formations,
unmineable coal seams
• Subsurface formations must be deeper than
approximately 2,600 ft
• Formations must have porosity and permeability
• Formations must include traps (folds, faults,
stratigraphic pinch-out)
• Sandstones must be overlain by impermeable
formations seals
• Monitoring during and after CO2 injection is
required must make sure CO2 is going where
intended; if leakage is detected, must take
corrective action
4:50:21 PM
MR. LEPAIN transitioned to discuss Alaska-specific
possibilities, starting with Cook Inlet. He directed attention
to the colored column on the lower left of slide 9 and made the
following points:
similar All the producing oil and gas fields in Cook Inlet are hosted
in the younger stratigraphy.
similar The thick black bars reflect the coal-bearing stratigraphy.
similar The Hemlock Formation is a major oil reservoir in Cook Inlet.
similar Gas reservoirs are largely in the Tyonek Formation, which is
overlain by the Beluga and Sterling Formations.
He said the column on the right reflects the older rocks that
are present below the younger rocks described in the left
column. He continued to make the following points:
similar When the younger rocks were deposited, the water in the pores
was fresh.
similar The older rocks were deposited in an ancient ocean so the
water in the pores was saltwater.
similar Over time the shallow pore waters increased in salinity. Today
they are fairly concentrated brines.
similar The formation waters in the younger stratigraphy has dissolved
material in it from long contact with the rocks. It's referred
to as saline formation water but it wasn't seawater
originally.
MR. LEPAIN described Cook Inlet as a long-lived sedimentary
basin. He relayed the following about Cook Inlet:
similar It has thousands of feet of interbedded sand, mudstone, and
coal
similar Cook Inlet hosts 10 oil fields, 5 of which are relatively
large. They are all data rich.
similar There are about 28 gas fields that are also data rich. Not all
are in production.
similar As of November, 2022, 1.389 billion barrels of oil have been
produced from Cook Inlet fields; a little more than 7.5
trillion cubic feet of natural gas has been produced.
similar These numbers can be used to give a rough qualitative idea of
the vacant pore space that could be used for CO2 storage.
similar There are saline formations in Cook Inlet with a lot of coal,
so unmineable coal seams are a possibility.
similar The seismic activity in the area is responsible for the fold
structures that form the traps for the existing oil and gas
fields in Cook Inlet.
similar Despite the seismic activity in the area, those seals have
held back the hydrocarbons for millions of years.
similar With careful attention to injection pressures, there is every
reason to believe that those formations can store CO2 for a
long time.
4:54:07 PM
MR. LEPAIN paraphrased the following summary of the CO2 storage
potential in Cook Inlet on slide 10:
CO storage in depleted and declining oil fields
• Proven reservoir (porosity, permeability), trap,
and seal
• Existing infrastructure
• 1.389 billion barrels of oil and 7.5 trillion
cubic feet of gas production as of end November
2022 (AOGCC)
• Field sizes and cumulative production volumes
provide a measure of CO2 storage potential in
existing oil and gas fields
• Seismic activity trapped hydrocarbons prove
seal capacity of mudstones not impacted
CO Storage in saline formations
• Large pore volume huge potential
• Uncharacterized
Unmineable coal seams
• Huge coal resource in basin
• Estimated storage potential 43 billion tons
(Shellenbaum and Clough, 2010)
• Fate of displaced methane? Must be captured
4:55:29 PM
MR. LEPAIN advanced to slide 11 and spoke to the following
bullets to describe the CO2 storage potential on the North Slope:
• Thousands of feet of interbedded sandstone and mudstone
• Abundant coal west of Umiat (Federal and Native land)
• More than 70 oil accumulations and several gas
accumulations discovered since 1944 several with
original oil in-place > 1 billion barrels
• 17.88 billion barrels oil produced through November 2022
(AOGCC)
• Proven reservoirs and traps many large fields in
decline
• Saline formations are extensive but uncharacterized
• Large volume of pore space potentially available for CO2
• Marine and nonmarine rocks
• Coal
• Infrastructure
• Low seismic activity
• Numerous folds and faults
• Hydrocarbons trapped for millions years
4:57:32 PM
MR. LEPAIN paraphrased the following summary of the CO2 storage
potential on the North Slope on slide 12:
• Cumulative oil production from North Slope fields through
November 2022 17.88 billion barrels of oil
• Many fields with original oil-in-place volumes estimated
>1 billion barrels and recoverable oil volumes > 300
million barrels
• Large legacy fields have been in decline for decades
EOR potential
• Field sizes and cumulative production volumes provide
measure of CO2 storage potential in declining fields
U.S. Geological Survey estimates 0.9 billion metric tons
mean recovery replacement storage
• U.S. Geological survey estimates mean total CO2 storage
potential at 270 billion metric tons (USGS Circular 1386;
includes only deep saline formations and existing oil
fields)
• Storage in unmineable coal seams estimated at 5.83
billion tons (Shellenbaum and Clough, 2010) displaced
methane must be captured
4:59:10 PM
MR. LEPAIN advanced to slide 13 to describe the Interior
sedimentary basins. He noted that the retired land manager from
Doyon referred to this area as Middle Earth.
• All basins are data poor
• Best known are Susitna, Nenana, and Yukon Flats
• Sedimentary rocks filling basins are nonmarine
(river, coal swamp, flood plain, and lake deposits)
• Potable water extends to greater depths
• Nonmarine settings tend to have laterally
discontinuous reservoirs and seals
• No infrastructure
5:00:23 PM
CO-CHAIR GIESSEL thanked Dr. LePain for the helpful
presentation.
5:00:49 PM
There being no further business to come before the committee,
Co-Chair Giessel adjourned the Senate Resources Standing
Committee meeting at 5:00 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2023 03 08 SRES DGGS Geological Carbon Sequestration Presentation.pdf |
SRES 3/8/2023 3:30:00 PM |
|
| 2023 03 08 SRES CCS Presentation - Meckel.pdf |
SRES 3/8/2023 3:30:00 PM |