Legislature(2023 - 2024)BARNES 124
02/10/2023 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB50 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | HB 50 | TELECONFERENCED | |
HB 50-CARBON STORAGE
1:02:27 PM
CHAIR MCKAY announced that the only order of business would be
HOUSE BILL NO. 50 "An Act relating to the geologic storage of
carbon dioxide; and providing for an effective date."
1:03:39 PM
JOHN BOYLE, Commissioner-Designee, Department of Natural
Resources (DNR), presented HB 50 on behalf of the sponsor, House
Rules by request of the governor. He stated that HB 50 had the
potential to make history in Alaska by diversifying the state's
revenue stream by monetizing the empty space underground as a
new resource. He said HB 50 was proposed in response to the
rising corporate demand to obtain net zero emissions by
sequestering carbon underground. He reported that many of the
companies operating on the North Slope have adopted objectives
to achieve net zero status for their current projects and for
any new oil fields and developments. He explained that this
bill would establish the framework for Alaska to provide the
corporations working in the state with opportunities to meet
their emission goals through the capture and utilization of
carbon. He stated that the underground pore space on state land
that would be used for the carbon storage is classified as a
mineral resource, which means that HB 50 would allow this new
revenue stream to build up Alaska's general fund and the
permanent fund at the same time.
COMMISSIONER-DESIGNEE BOYLE argued that Alaska has two main
competitive advantages that make developing this new resource
through a permitting and regulatory structure a prudent choice.
First, he explained, the state has sole ownership of a broad
amount of land with geological features that are conducive to
carbon storage. He opined that this is an advantage over other
states that practice carbon storage but must negotiate with
multiple landowners before bringing a new carbon sequestration
program online. Second, he explained, the scale of viable land
in Alaska creates a capacity for storage that is much larger
than other areas of the country and the world. For example, he
reported that the Cook Inlet area alone has the capacity to
store 50 years of carbon output from an entire country.
COMMISSIONER-DESIGNEE BOYLE opined that the administration and
the legislature have the opportunity to change the landscape of
the state simply by allowing others to store carbon within the
land. He explained that the science behind this practice was
not new or unknown and that there are companies operating in
Alaska which have extensive knowledge and experience with
injecting gas underground and understand how the gas interacts
with the rock underground over geologically significant periods
of time. He emphasized that HB 50 would provide the state with
the opportunity to move toward the future in a way that
diversifies its revenue streams through new industry growth. He
opined that the permitting regulations in Alaska are better than
what exists in other states or countries and that storing carbon
under those regulations would build Alaska's credentials as an
area of the world known for responsible resource development.
1:09:07 PM
AARON O'QUINN, Division of Oil and Gas, Department of Natural
Resources, began a Power Point presentation [hard copy included
in the committee packet], titled "Carbon Capture, Utilization,
and Storage," and drew attention to an overview on slide 2,
which read as follows [original punctuation provided]:
What is it?
Carbon Capture, Utilization, and Storage (CCUS) is a
process to capture carbon dioxide (CO2), either from
industrial processes or directly from the atmosphere,
for the purpose of utilizing it for other activities
or storing it underground in geologic formations
Why Now?
The CCUS market is rapidly expanding, both within the
U.S. and worldwide
Federal legislation in the prior 18 months has
included direct grants and tax incentives for CCUS,
increasing industry interest, including outreach to
the Department of Natural Resources (DNR)
Federal funds are available for states seeking Class
VI well permitting, showing federal support for state
primacy
Protracted project timelines and milestone
requirements in the tax credit structure necessitate
prompt action
Sets the stage for potentiating continued development
of Alaska's oil resources, and potential major gas
development
What is the potential in Alaska?
Alaska's depleted oil & gas fields, saline aquifers,
and deep coal seams have significant CO2storage
potential
Alaska has important competitive advantages we own
the pore space & we know the reservoirs
Fifteen other states have passed CCUS omnibus
legislation that we have learned from
1:10:51 PM
MR. O'QUINN moved to slide 5, which depicted a carbon molecule,
and described the carbon capture, utilization, and storage
process as injecting these molecules into the subsurface while
in a hypocritical state. He shared the US Department of
Energy's (DOE) definition of the process on slide 6, which read
as follows [original punctuation provided]:
Carbon capture, utilization and storage (CCUS) is a
process that captures carbon dioxide emissions from
industrial processes, point sources like coal-fired
power plants, or from the air and either reuses or
stores it so it will not enter the atmosphere.
Carbon dioxide storage in geologic formations includes
oil and gas reservoirs, unmineable coal seams and deep
saline reservoirs --structures that have stored crude
oil, natural gas, brine and carbon dioxide over
millions of years.
MR. O'QUINN emphasized the natural security found in the
geologic tracts that would be utilized for storage. He
described a diagram of the CCUS process, on slide 7, and
provided a brief overview. He explained that the carbon was
captured at the source of emission, which could be an industrial
facility, direct air-capture facility, or from an oil or gas
field. He said that the carbon dioxide (CO2) is then
transported by pipeline overland to the injection site. He
added that there have been some inroads into transporting CO2 by
boat. Next, he related that the carbon dioxide is compressed at
the injection site and then pumped into the subsurface via an
injection well.
MR O'QUINN explained the capture stage of the process on slide
8, which read as follows [original punctuation provided]:
Myriad technologies in various stages of commercial
development:
1. Pure stream carbon capture from certain industrial
processes such as the production of methanol or
ammonia or removing naturally-occurring carbon from
natural gas
2. Capturing carbon dioxide following the combustion of
fossil fuels, such as from a coal-fired power plant
3. Capturing carbon dioxide directly from the atmosphere
MR. O'QUINN detailed the ways in which captured carbon can
be utilized through a pie chart depicted on slide 9 and
stated that while there are many uses for CO2, the most
common utilization is enhanced oil recovery. He explained
that enhanced oil recovery is a process where an oil and
gas operator will inject captured carbon dioxide into an
existing oil or gas formation to enhance the production of
the reservoir as a tertiary means of extraction. He
described the process as shown in the other visual on the
slide, stating that water and CO2 are alternatively
injected into the formation to push remaining oil towards
the production well, which can result in additional barrels
of oil produced in Alaska from wells already in operation.
1:15:34 PM
MR. O'QUINN addressed the storage of captured carbon with a
diagram on slide 10 and explained that storing CO2 within the
earth is accomplished by injecting it at a depth of 2,600-3,000
feet, which ensures that there is enough pressure to keep the
CO2 in its supercritical state. He reported that typically
these injection sites are depleted oil and gas reservoirs,
aquifers, or not mineable coal seams. He emphasized the
importance of porosity for CO2 storage and referred to the
visual on the slide that showed increased storage capacity with
increased porosity of the injection layer.
REPRESENTATIVE SADDLER asked for the definition of the
supercritical state for CO2.
MR. O'QUINN replied that CO2 is stored at a certain pressure; it
can reach a supercritical state where it is still gaseous but
behaves more like a liquid.
REPRESENTATIVE SADDLER questioned at what temperature and pounds
per square inch (PSI) of pressure CO2 becomes supercritical.
MR. O'QUINN shared his understanding that the required pressure
is about 2,600 PSI but deferred to the geology expert for
confirmation.
1:17:23 PM
DAVID LEPAIN, PhD, Director, Division of Geological and
Geophysical Surveys, Department of Natural Resources (DNR),
replied that he was unsure of the data for temperature but noted
that CO2 reaches the supercritical state at 1,100 PSI. He
explained that "supercritical" describes a state of matter
halfway between a gas and a liquid.
Mr. O'Quinn explained why CCUS would be beneficial for Alaska,
as outlined on slide 12, which read as follows [original
punctuation provided]:
Bolster development of Alaska's abundant oil and gas
Federal incentives are driving investment in peer
states
Environmental, Social, and Governance (ESG) concerns
driving capital to projects with carbon management
options
Alaska should participate in global uptick in CCUS
projects
Project timelines require the state to act promptly
because of the federal incentives' deadlines
Additional state revenue
1:20:39 PM
REPRESENTATIVE MEARS requested more in-depth information
regarding the federal incentives for projects with decreased
emissions.
MR. O'QUINN replied that he would be addressing this more in a
later slide but could also provide the committee with additional
information outside of the hearing.
1:21:07 PM
The committee took a brief at-ease.
1:21:51 PM
REPRESENTATIVE SADDLER referenced Mr. O'Quinn's statement about
the timeline for projects to qualify for the federal incentives
and asked how much of a commitment the state would have to make
to qualify for the federal credits and how quickly they would
have to act.
MR. O'QUINN responded that in order to receive the federal tax
credits being offered, companies must begin construction on new
projects by January 2033. He confirmed that the state would
have until then to get permitting structures in place but
reported that CCUS projects have a development timeline similar
to gas and oil projects, which he stated can be lengthy. He
argued that having the regulatory statues already in place would
allow project proponents the certainty to make initial
investments in exploration and further development decisions
along the process and ensure their access to the federal credits
once the projects are completed.
MR. O'QUINN showed a map on slide 13 of worldwide CCUS projects
in various states of completion, from permitted to operational.
He pointed out that there are several operational projects in
other parts of the U.S. and many others being developed in oil
and gas jurisdictions across the world. He reported that
government-imposed carbon taxes are the main driving factor for
these projects in other areas of the world, but while there are
some statewide caps on emissions or anticipated carbon taxes in
the U.S., the main driving force for U.S. projects are the
federal tax credits. He reiterated that there are also capital
market pressures towards projects with lower carbon footprints
that are pushing interest in the CCUS industry.
1:24:58 PM
REPRESENTATIVE MCCABE sought clarification that HB 50 is not
seeking to place any taxation on the CCUS projects but rather to
provide the service of carbon storage for companies that want to
reduce their carbon output.
MR. O'QUINN confirmed that HB 50 does not address adding a
carbon cap or tax on any industry in Alaska. He asserted that
the intent of the bill is to turn the porous rock located
underground in Alaska into a resource for the state and to take
advantage of the market for carbon storage being created by
carbon emission restrictions and offset requirements in the rest
of the world.
REPRESENTATIVE MCCABE asked for confirmation of his
understanding that the term "sequestration" is a synonym for
storage.
MR. O'QUINN replied that is correct.
1:27:52 PM
REPRESENTAIVE MCCABE asked about Alaska's history of injecting
CO2 underground, sharing his understanding that HB 50 would
allow companies outside of the state to partake in the same
process that has been done by Alaska projects since the 1970s.
MR. O'QUINN responded that there are oil and gas operations that
will reinject the CO2 they produce as a means of pressure
support. He used the project at Prudhoe Bay as an example of
experts at handling CO2 that have the appropriate infrastructure
to do so at that facility. He reported that there has been
continued production of oil as a result of injecting CO2 into
the gas cap at that site.
MR. O'QUINN continued his presentation by describing the graph
on slide 14, which depicted the projections for how many carbon
capture facilities would need to be in operation across
different sources of emission to meet the goal of removing all
emissions from the atmosphere by the year 2070. He reported
that there are currently 35 commercial CCUS projects actively
injecting CO2 and that the projection shows that an additional
2,500 facilities would be needed to meet the 2070 goal. He
suggested that these findings prove there will be a huge growth
in the CCUS industry that Alaska is prime to take advantage of
due to the state's geology and strategic position in the Pacific
Ocean.
MR. O'QUINN provided an overview of the federal tax incentives
on slide 15, which read as follows [original punctuation
provided]:
45Q (CCS) Tax Credit -Inflation Reduction Act
Enhancements
Deadline to start construction 1/1/2033
$85/ton for CCUS from industrial facilities and power
plants stored in geologic formations
$60/ton for utilization of captured CO2/CO for
enhanced oil recovery (EOR) or to produce low and
zero-carbon fuels, chemicals, and building materials
$180/ton for direct air capture (DAC) carbon stored in
geologic formations and $130/ton for DAC carbon used
in EOR
MR. O'QUINN reported that the tax code that grants these credits
has been in place for some time but that enhancements have been
recently added to further incentivize the development and use of
CCUS projects to reduce emissions. He explained that collecting
carbon through direct air capture (DAC) facilities has a higher
rate of credit to encourage more development of these frontier
technologies.
1:31:15 PM
REPRESENTATIVE ARMSTRONG referred to the proposed state fee of
$2.50 per ton in the fiscal note from the Department of Revenue
(DOR) and posited that adopting the federal tax credits would
reduce the state's corporate income tax. She asked how long it
would take for CCUS projects to become revenue positive and what
that process would entail.
MR. O'QUINN explained that the $2.50 per ton of CO2 stored is
the minimum amount the state can charge and would be the direct
source of income to the state. He stated that he is unsure how
tax credits may affect total corporate income tax.
1:32:47 PM
JOHN CROWTHER, Deputy Commissioner, Department of Natural
Resources, offered to meet with DOR and bring information about
the forward value of the federal tax credit and the state
corporate income tax to the committee at a later date.
REPRESENTATIVE MEARS asked about how the tax credits change with
the different oil well classes.
MR. O'QUINN replied that the tax credit is not tied to the class
of oil well but to how the captured CO2 is used. He explained
that injection well class is dictated by the concentration of
CO2 that is being injected into it. He stated that he can come
back to supply the committee with more information on how the
class of well will affect the tax credit.
REPRESENTATIVE MEARS clarified that she was inquiring about the
transition period between changing the use of a well from
enhanced oil recovery to only sequestration and that she wanted
to ensure the transition process was well defined.
MR. O'QUINN emphasized that any tax credits would be scrutinized
by the Internal Revenue Service (IRS)and that the Alaska Oil and
Gas Conservation Commission (AOGCC) would be certifying and
monitoring injection volumes and barrel outputs; whether or not
a company qualifies for the sequestration credit versus the EOR
credit would be tracked by the state. He reported that
companies would only be able to claim the credits if they met
the very specific requirements laid out in the internal revenue
code.
1:36:52 PM
REPRESENTATIVE DIBERT asked for an example of a DAC facility.
MR. O'QUINN answered that there are some DAC facilities
operating in Iceland but reported that because they require a
large amount of energy to run, the economic benefits can be
tricky unless the site has access to a renewable or low-cost
source of energy.
REPRESENTATIVE MCCABE questioned whether DAC could be a solution
to some of the inversion air quality issues in parts of Alaska
that rely heavily on wood stoves.
MR. O'QUINN clarified that the federal tax credits are available
only for capture of CO2 and that many areas affected by air
pollution have issues with the accumulation of other pollutants,
so any capture projects targeting those pollutants would not be
eligible.
REPRESENTATIVE SADDLER shared his surprise in learning that CO2
had value in commercial uses and asked how CO2 is currently
obtained for the purpose of manufacturing chemicals and zero-
carbon fuels and what the market for CO2 looks like.
MR. O'QUINN replied that he is unfamiliar with the details of
the CO2 market but that he is aware of its use in the medical
industry and in some food production, for example, fountain
soda. He stated that there are purity standards that must be
achieved for the CO2 to be used for those purposes and that most
CO2 is reduced to a usable material in small plants. He
mentioned that the most common source he is aware of for CO2 is
through Ammonia (NH3) production.
MR. O'QUINN returned to his presentation on slide 16 where he
walked the committee through a diagram of the IRS timeline for
companies to avail themselves of the tax credits, reiterating
that construction on a CCUS project must start construction by
2033 to qualify. He explained that the process for project
development consisted of multiple steps that can each take
months or even years to complete. He stated that first the
company will conduct an initial screening to select a location,
which includes geological surveillance and extensive research.
After an area is selected, he said that the company would ask
the state for an exploration permit which will be granted after
a public and competitive process to ensure the project is in the
best interest of the state.
MR. O'QUINN explained that further exploratory drilling may be
done after the permit is granted to better understand the
characterization of the resource before development. While in
the exploratory stage, he stated, operators would begin securing
the sources of carbon and designing the project infrastructure.
He said that once designs have been completed the project would
go to the AOGCC for construction permits. If the permits are
approved, the next step is for the project's capital providers
to finalize their investment decisions and then the construction
process can commence, followed by operation of the project. He
detailed the approximate timelines for each stage and reported
that the initial exploration and permitting period can take up
to five years.
MR. O'QUINN reiterated that construction must begin by 2033 to
be eligible for tax credits and suggested that the unique
factors of building in Alaska can further expand the amount of
time needed to get a project ready for construction. He argued
that because of the relatively short amount of time in which
operators would need to initiate their projects, it is important
to have a regulatory framework for CCUS projects already
established as soon as possible.
1:44:43 PM
REPRESENTATIVE MEARS asked how long a project can continue to
receive the tax credit once it qualifies and whether that would
be for the life of the project or for a set number of years.
MR. CROWTHER shared his belief that there is a time horizon in
which the tax credits are eligible for an approved project but
that he would return to the committee with a definite answer.
MR. O'QUINN restated that it is important for the regulatory
systems for CCUS to be in place quickly so that project
operators have the certainty they need to start the long process
of project development before the deadline. He reported that
there is a section of the bill that allows for AOGCC to seek
primacy for class 6, or CO2 injection, wells, giving them
primary authority to permit those wells. He explained that this
authority would be sought from the Environmental Protection
Agency (EPA). He reported that the EPA has over $50 million
available in funding to help states start permitting programs
for class 6 wells. He stated that passing HB 50 would allow the
AOGCC to seek primacy, which would give Alaska access to that
funding and build that program on federal money rather than
state funds. He shared that primacy also makes the state more
attractive to industry operators as many investors have stated
their preference for working directly with state governments
rather than the EPA for permitting and are choosing to invest in
projects located in states that have or are seeking permitting
primacy.
MR. O'QUINN continued his presentation on slide 17, highlighting
the net zero gas emission plans for several companies currently
operating on Alaska's North Slope. He stated that the companies
listed are some of the largest oil and gas operators in the
world and described their goals for reducing emissions as
aggressive. He reported that there was a specific focus from
all of these entities on the reduction of Scope 1 emissions,
which he defined as direct emissions made by the company during
their operation. He reiterated that HB 50 would give those
companies the opportunity to meet their emission reduction goals
in the state where they are operating and opined that the state
should be able to take advantage of that economic opportunity.
1:48:43 PM
REPRESENTATIVE ARMSTRONG referenced the previous statement that
companies in Alaska are already using CO2 injection for EOR and
questioned how many oil and gas operations in Alaska are using
CCUS currently and whether HB 50 would change the permitting,
tax credit eligibility, or any other factors for already
existing CCUS projects.
MR. O'QUINN replied that the only use of CCUS technology in
Alaska is at the Hilcorp operation in Prudhoe Bay and that they
are exclusively injecting their own CO2 emissions to enhance oil
production. He restated that there are many projects around the
world and in the U.S. that are capturing carbon for
sequestration only.
1:50:44 PM
REPRESENTATIVE MCCABE reiterated that oil and gas companies are
seeking out opportunities for carbon sequestration of their own
volition and that HB 50 would not impose CCUS requirements but
rather create carbon storage for those companies to utilize.
MR. O'QUINN confirmed that Alaska would not be introducing any
CCUS requirements or emission caps and that the move towards
carbon sequestration is being driven by corporate governance,
shareholder input, capital markets, and informed jurisdiction
taxes imposed by other areas.
MR. O'QUINN continued his presentation on slide 18 and argued
that building a regulatory structure for CCUS would help address
the legal challenges from the EPA to oil and gas operations
located on Alaska's federal lands. He reported that the EPA has
brought forth challenges against proposals such as the Willow
Project for violating the National Environmental Policy Act
(NEPA) by not considering the projects contribution to global
carbon emissions. He suggested that by offering carbon
sequestration in Alaska, the state can help those companies
reduce their Scope 1 carbon liability and will hopefully reduce
the amount of challenges filed by project opponents.
1:53:35 PM
MR. O'QUINN discussed the revenue possibilities on slide 19,
clarifying that HB 50 is not promising any revenue to the state
but stated that if operators choose to sequester carbon in
Alaska, they will have to pay for the use of the underground
pore space. He used the Red Trail Energy Project in North
Dakota as an example of how a state can profit on carbon
sequestration and explained that Red Trail captures the CO2
produced while fermenting soybeans and corn for ethanol and
injects it into the earth for storage. He explained the picture
of the project on the slide by pointing out the site of the
injection well, the area occupied by the injected plume, and the
monitoring well that ensures the injection site does not exceed
the subsurface area. He reported that Red Trail is expected to
inject up to 3,480 acres of subsurface area and capture 180,000
tons of carbon per year.
MR. O'QUINN stated that DNR created a projection to calculate
the possible revenue a project with the same dimensions operated
in Alaska would generate under the rates proposed under HB 50.
He explained that the minimum rate for rent of the space during
the pre-injection period would be $70,000 per year and could
last about three years. After injection begins, he projected
that there would be $500,000 of income from the amount of carbon
captured per year. He explained that there is a price step
built into the bill to account for inflation that would increase
the rate per ton of carbon by five percent which would go into
effect in year six of this projection. He stated that this
projection is a conservative estimate for how much revenue a
single, small energy plant could bring into the state, but the
department assumes most companies would pay more than the bare
minimum rate.
1:56:48 PM
REPRESENTATIVE DIBERT asked for more details on the monitoring
process and what would happen if the injected plume exceeded the
expected subsurface area.
MR. O'QUINN described the project model pictured in more detail
and reported that the predictive modeling technology is very
accurate and calculates based on the shape of the geologic
feature, the pressure, and the volume. Therefore, he posited,
it would be unlikely that a plume would expand beyond what is
predicted. In the case that the plume did exceed the monitoring
area, the operator would be responsible for continual reporting
to AOGCC, which would develop regulations for those occurrences.
He reported that AOGCC would be empowered to bring additional
property rights into the project if necessary and the owner of
the additional property would be compensated. He clarified that
the state is the primary pore space owner in Alaska and would be
able to seek additional compensation if more area is utilized.
No matter who the owner of the additional pore space is, he
explained, the company would have to revisit its permit to
account for the extra usage.
1:59:57 PM
The committee took an at-ease from 1:59 p.m. to 2:05 p.m.
2:05:21 PM
DR. LEPAIN took over the presentation on slide 21 by describing
the physical and chemical properties of CO2 and stated that at
surface pressure it presents as an odorless, colorless gas.
However, he explained that when CO2 is subjected to enough
pressure it becomes a super-critical liquid, which he described
as a state of matter somewhere between a liquid and a gas. He
stated that due to the hydrostatic gradient under the earth's
surface, the pressure in underground geologic formations
increases as the depth increases. He reported that injecting
super-critical CO2 at a depth of 2,600 feet or below the
naturally occurring pressure is enough to keep the CO2 super-
critical, which is important to the CCUS process because the
same reservoir can hold more CO2 when it is in a compressed,
super-critical state. He emphasized that subsurface formations
must meet a particular set of criteria to be used for storage.
REPRESENTATIVE SADDLER asked about the density of CO2 in
comparison to the water within the subsurface and questioned why
the less dense CO2 does not rise above the water.
DR. LEPAIN answered Representative Saddler's question by
continuing to slide 22 and explaining the required
characteristics for an underground formation to be used as
storage. He stated that sandstone formations were primarily
targeted for storage because sandstone has a high porosity
within its structure, which he illustrated through a picture of
sandstone at the microscopic level. He emphasized that porosity
and permeability must be present in the rock to make it a
candidate for storage. He used an illustration on the slide
depicting a cross section of the earth underneath the Kenai gas
field to show that sandstone can often be found either within
formations where it is in layers that are folded upwards or in
an anticlinal fold. He confirmed Representative Saddler's
assumption by explaining that when CO2 is injected into these
bent, water-saturated layers of sandstone, the CO2's buoyancy
will cause the CO2 to rise towards the crest of the fold.
However, he pointed to another picture on the slide of a
microscopic view of mudstone, or shale, with visibly less space
between particles making it non-porous. He explained that when
the sandstone within a formation is layered with mudstone, the
impermeable mudstone acts as a trap to prevent the CO2 from
rising.
REPRESENTATIVE SADDLER asked whether there is typically a single
layer of mudstone within a formation or multiple layers.
DR. LEPAIN replied that the drawing on the slide is a good
example of the typical formation that could be a candidate for
storage; it shows stacked layers of sandstones separated by
mudstones. He stated that each layer of sandstone is sealed by
the mudstone, creating multiple reservoirs with their own seals.
DR. LEPAIN summarized slide 22 by stating that a viable
underground formation would have porous and permeable sandstone
layers in an entrapping formation with nonporous mudstone seals
at a depth of at least 2,600 feet to provide enough pressure
that the CO2 stays super-critical.
2:11:24 PM
DR. LEPAIN explained the four types of CO2 trapping on slide 23,
starting with "buoyant trapping," which uses the buoyancy of CO2
to trap it within the formation as he described in detail in the
previous slide. He stated that the second type is called
"residual trapping," which occurs when CO2 is injected into a
structure. He explained that while most of the CO2 rises to the
top, there will be some left behind in the pore network. He
called the third type "solubility trapping," which happens when
some of the CO2 dissolves into the water within the formation.
He stated that the fourth type is called "mineral carbonation,"
which is a process where mineral precipitates will form after
CO2 is injected into rock. He reported that there is a pilot
project in Iceland that involves injecting CO2 into basalt
formations and creating iron carbonate precipitates; however, he
stated that this kind of carbon trapping is not applicable to
the rock formations found in Alaska.
2:13:26 PM
REPRESENTATIVE SADDLER asked what percentage of each applicable
type of carbon trapping is found in carbon injection projects.
DR. LEPAIN replied that it is difficult to give a broad answer
because the percentages are dependent on many geologic variables
that are very specific to each formation.
2:14:07 PM
REPRESENTATIVE MCCABE shared his understanding that the
reservoirs that would be used for CO2 storage previously held
oil or gas, thus the seals capping off these reservoirs are
already established as being capable of containing similar
substances.
DR. LEPAIN confirmed this understanding and stated that depleted
oil and gas reservoirs is one class being considered for CO2
injection. He mentioned that he will touch on the other two
classes of reservoir in a future slide.
2:15:12 PM
REPRESENTATIVE ARMSTRONG noted that other projects have
experienced issues due to increased seismic activity and have
had to halt operation. She questioned whether there is
something specific to Alaska's geology or the injection process
that would put the state at less risk for seismic interference.
DR. LEPAIN stated that the way CO2 is injected into the
formation will determine its effect on seismic activity and
suggested that the injection rates should be closely monitored
to prevent inducing seismic activity.
CHAIR MCKAY restated Representative Armstrong's question to ask
what would happen to the operation of an injection well in the
case of a large seismic event.
DR. LEPAIN replied that he will address that issue specifically
regarding possible Cook Inlet operations, as that is a very
geologically active area.
MR. O'QUINN responded to the topic of seismic activity by
clarifying that the presentation will address both human induced
seismic events and the risk natural seismicity has to potential
projects. He mentioned that the goal of injection for
sequestration is to keep the reservoir intact and not to
increase the porosity of the rock, unlike other projects like
disposal wells that actively break up the rock underneath, and
so it is unlikely that sequestration would trigger seismic
activity.
2:17:45 PM
DR. LEPAIN continued the presentation on slide 24 by listing
several reasons why depleted oil and gas fields are the top
choice for storage reservoirs. He stated that the reservoirs
within the depleted fields in Cook Inlet and on the North Slope
are proven to have effective traps and seals as they previously
held hydrocarbons for millions of years without any leaks. He
argued that there is no reason to believe that CO2 would act any
differently within these reservoirs which makes them attractive
options for storage. He suggested that the reservoirs are known
entities because of the extensive data sets characterizing their
properties such as shape, temperature, pressure, and water
salinity. He reported that the data included robust estimates
of the original oil in place (OOIP) within the reservoirs which
allows geologists a better understanding of how much pore space
is available. He reiterated that injecting CO2 into declining
oil fields can enhance oil production.
DR. LEPAIN stated that saline formations are another option for
storage and defined them as underground formations that have
never been host to oil or gas and have pore spaces filled with
non-potable salt water. He reported that there are extensive
saline formations within existing Alaskan oil fields that could
have significant storage potential; however, unlike depleted oil
and gas fields, these formations are largely uncharacterized but
could be a possibility for the future.
2:20:12 PM
CHAIR MCKAY asked for further explanation of the pressure
required for the proposed CO2 injections and whether it would be
less than the pressure used in fracking.
DR. LEPAIN reported that the oil and gas industry is very
experienced in monitoring the pressure within underground
formations. He asserted that this knowledge allows operators to
have a better understanding of how much pressure to use while
injecting and how much stress a formation can endure. He stated
that the oil and gas industry has well-tested technology that
ensures any additional stress added by injection does not exceed
the amount that would induce fracturing.
DR. LEPAIN continued the presentation on slide 25 to describe a
third possibility for CO2 storage. He reported that there are
many coal deposits within Cook Inlet that are too deep to be
economically viable for mining but could be used for CO2
storage. He explained that CO2 molecules have a high affinity
for coal and will attach to the coal matrix very easily and
strongly. He stated that lower ranks of coal can store more CO2
than higher ranks and reiterated that that much of the coal in
Cook Inlet is both too deep and too low ranked to be used in
mining, making it an attractive potential option for storage.
2:22:43 PM
DR. LEPAIN summarized the CCUS process on slide 26, which read
as follows [original punctuation provided]:
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 pinchout)
Formations must be overlain by effectively zero
permeability formations seals
Monitoring during and after CO2injection is important
DR. LEPAIN began explaining the specifics of CO2 storage in
Alaska with a list of the pros for utilizing the oil and gas
projects in Cook Inlet on slide 27, which read as follows
[original punctuation provided]:
Thousands of feet of interbedded sandstone, mudstone,
coal
10 oil fields 5 relatively large (data rich)
38 gas fields (data rich)
Proven reservoirs and traps
1.4 billion barrels of oil produced
8.9 trillion cubic feet of gas produced
Saline formations
Large volume of pore space potentially available for
CO2
Large volume of coal
Infrastructure
DR. LEPAIN addressed the previous discussion on the seismic
activity of the area, characterizing Cook Inlet as a
geologically active basin. He used an image that depicted the
location of the oil and gas fields within Cook Inlet to show
that most of these fields are located on large subsurface fold
structures that owe their existence to their proximity to fault
lines and subsequent geologic activity. He reiterated that the
folds have been proven to hold hydrocarbons without any leaks
for millions of years.
CHAIR MCKAY posited that the CO2 injection process is the
inverse of the oil and gas extraction process that has been
taking place in Alaska for 60 years and that it would make sense
to refill the now empty subterranean "containers" with a similar
type of gas to what was taken out of them.
DR. LEPAIN confirmed that the Chair's statement was correct. He
then moved on to share a list arguments for storage in the North
Slope that he described as very similar to those for Cook Inlet,
which read as follows [original punctuation provided]:
1000s 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
OOIP >1 billion barrels oil
18.7 billion barrels produced through September 2022
(AOGCC)
Proven reservoirs and traps many large fields in
decline
Saline formations are extensive
Large volume of pore space potentially available for
CO2 storage
Coal
Infrastructure
DR. LEPAIN stated that the main difference between the two areas
is that the North Slope has much less seismic activity than Cook
Inlet. He moved briefly to slide 30 to mention that the U.S.
Geological Survey (USGS) has estimated that 0.9 billion tons of
CO2 could be stored in the depleted reservoirs within the North
Slope and noted that USGS refers to the process as recovery
replacement storage.
CHAIR MCKAY sought clarification that the USGS estimate accounts
only for the already evacuated oil and gas deposits and not for
potential storage in coal seams or saline formations and posited
that there is even more potential capacity for storage than that
number suggests.
DR. LEPAIN confirmed this assumption and pointed to another
study from geology experts in 2010 that estimated North Slope
coal seams could store an additional 5.83 billion tons of CO2.
2:29:13 PM
DR. LEPAIN addressed the possibility of storing CO2 in the
interior sedimentary basins of Susitna, Nenana, and the Yukon
Flats on slide 31 and reported that they would require a lot of
work to develop for CCUS projects as they are currently data
poor areas, and they have very little existing infrastructure.
2:30:39 PM
MR. O'QUINN continued the presentation on slide 33 with an
overview of the origins of HB 50. He reported that the
department researched CCUS in three ways prior to writing the
legislation. He said they started by reviewing similar
legislation from peer states, particularly states with active
oil and gas operations who are pursuing CCUS projects. He
stated that the second step was for DRN to reach out to other
state agencies, such as AOGCC and the Department of
Environmental Conservation (DEC), to obtain their perspective on
CCUS and how it would impact their jurisdictions. He shared
that the last piece of research consisted of garnering
stakeholder input and stated that DNR did so by creating a
statewide CCUS stakeholder work group that included industry
stakeholders and government agencies. He reported that the
workgroup met several times which culminated in a full day
workshop to decide the key points that the bill would need to
address and the best way to handle them.
MR. O'QUINN talked about the specific peer states that were
examined during the research project using a graphic on slide 34
which illustrated the states that have comprehensive CCUS
legislation in place. He stated that DNR also examined the
applications for class 6 primacy submitted by other states,
which would allow state agencies to control the regulatory
process for CO2 injecting.
MR. O'QUINN reiterated on slide 35 that DNR worked with partner
agencies to complete the research necessary for this legislation
and named DEC, the Division of Geologic and Geophysical Surveys
(DGGS), the Division of Oil and Gas, and the AOGCC as the main
partners.
2:33:59 PM
REPRESENTATIVE MEARS sought to confirm that the trigger for
Alaska to seek class 6 well primacy is the passage of HB 50.
MR. O'QUINN responded that is correct; the bill includes an
amendment to allow AOGCC to seek primacy for class 6 wells in
addition to the existing authorization for class 2 wells.
2:34:46 PM
REPRESENTATIVE SADDLER asked for the other well classes to be
defined.
MR. O'QUINN responded that to his knowledge class 1 wells are
for disposal, class 2 wells deal with injecting oil fill fluids
into oil and gas formations, and class 5 wells are geothermal.
He stated that he was unsure about what class 3 and 4 wells are
used for but reported that states can seek primacy for all 6
classes. He explained that the EPA prefers states to build a
comprehensive regulatory system by seeking primacy for all
classes at once, but it has allowed exceptions for class 2
primacy and is extending this exception for class 6 primacy, as
well.
MR. O'QUINN addressed the specifics of the regulatory work group
on slide 36, stating that a regulatory framework committee
consisting members from various stakeholder groups was created
to inform the regulatory decisions made in the bill. He shared
that the House Resources Standing Committee had been supplied
with the resulting document of the regulatory framework
committee's work, which he referred to as the "stakeholder white
paper." He said that it includes a general consensus from
stakeholders on many of the regulations proposed under HB 50.
He emphasized that the bill was not created solely by the
government in "a vacuum," but that it truly reflects the input
from many industry stakeholders. He reported that there were
other committees created, including one that is looking into
funding opportunities from DOE to help fund further storage
resource characterization studies and other data collection. He
shared that there is a CCUS roadmap work group which looks at
the different engineering technologies available for CCUS
projects and how effective they would be in Alaska. He said the
final committee created was for public outreach and education
and that its purpose is to keep the public as informed as
possible, and he stated that DNR is planning to create a website
and provide opportunities for community outreach.
2:39:49 PM
MR. O'QUINN summarized the specifics on what the proposed
legislation would do, on slide 38, stating that the main purpose
is to authorize use of public land for CCUS as an extension of
energy production and to structure the licensure similarly to
exploration licensing which allows companies to use public land
and compensate the state for it. He explained that the bill
will provide for AOGCC to unitize property rights and protect
the correlative rights of property owners. He reiterated that
in most cases the pore space will be owned by a single entity,
usually the state or a native corporation, but DNR made sure to
include public protections in the case that there are private
owners. He reported that the bill outlines how the injection
and extraction industries would interact with each other as they
would often be operating in the same area and stated that the
bill empowers the AOGCC to oversee those relationships. He
stated that HB 50 provides for the permitting and authorization
of CO2 pipelines to be built on land leased by the state and
that it codifies court findings that categorizes pore space on
state land as being of "mineral character." He reiterated that
the bill would allow for the state to seek primacy for
regulation of class 6 wells from the EPA, which he emphasized
was an important part of making Alaska an attractive place for
companies to store their carbon.
2:43:24 PM
REPRESENTATIVE SADDLER asked whether using pore space for carbon
sequestration would automatically prohibit any future
exploration within or through that pore space.
MR. O'QUINN replied that HB 50 specifically addresses any
potential conflict between injection and extraction by giving
AOGCC the power to oversee any future projects that would
require drilling through a storage site to access other pore
space for extraction or vice versa. He emphasized that DNR does
not see designating space for storage as condemning it from
being used for extraction.
REPRESENTATIVE SADDLER asked what the estimated increase of
cost, resources, and time would be for the additional workload
this oversight would create for the AOGCC.
MR. O'QUINN replied that the fiscal note includes two new full
time equivalent positions for the AOGCC and confirmed that the
workload would increase as the number of permit requests for
CCUS projects increased. However, he reported that there is a
provision in the bill for a regulatory cost charge which would
manifest as a per ton injection fee that would be established
within the permit or through regulation by AOGCC. He stated
that the intent of that fee is for AOGCC to utilize it for
staffing the review of new permits.
2:45:57 PM
REPRESENTATIVE MCCABE asked what the above ground footprint of
an injection well would be on average and how that size would
compare to other types of wells.
MR. O'QUINN returned to slide 19 of the presentation and
referred to an arial view picture of an existing injection well
in North Dakota. He stated that the above ground requirements
are an injection well and a monitoring well, which he described
as "a pipe sticking out of the ground," a small processing
facility, and a pipeline to run the CO2 to the well. He
mentioned that typically the pipes are laid underground and
could be done as such in areas like Kenai, but they would have
to be above ground on the North Slope. He asserted that the
total amount of above ground space would be very minimal.
CHAIR MCKAY shared his understanding that the well count for
injecting is far less than what is used for extraction.
REPRESENTATIVE MCCABE reported that his constituents have
concerns about above ground footprint size but he posited that
an acre or two for the facility and a minimal addition of well
heads seemed to be reasonable.
CHAIR MCKAY expressed his understanding and hope that most
injection projects would make use of existing pads and
infrastructure with very little new impact.
MR. O'QUINN confirmed the Chair McKay's understanding.
2:49:13 PM
REPRESENTATIVE DIBERT questioned whether the state or the
corporation would be liable for any damages that occurred to
future facilities in the event of seismic activity.
MR. O'QUINN explained that the operator of the facility would
remain responsible for any damage to or because of the injection
sites for the duration of the operation and for a 10-year period
after the project concludes. He stated that after the 10 years
are over the corporation can obtain a closure certificate from
AOGCC if all compliance standards set under HB 50 are met. He
reported that when a closure certificate is granted the title of
the CO2 and all liability transfers to the state. In order to
help the state pay for any costs after closure, he explained,
that while the injection site is still in operation AOGCC will
collect post closure fees, which get put into a joint trust fund
for all facilities and are marked for the post closure period
and can be used for any incidents that arise. He mentioned that
the 10-year time period is what has been used in other states
and is considered by the industry to be enough time for
stabilization post closure. He noted that having an end to an
investor's liability was very important to stakeholders.
2:53:13 PM
REPRESENTATIVE SADDLER referenced the protests and public
opinion issues that occurred when the state was considering
implementing fracking and asked what challenges, if any, other
states have seen during their early implementation of carbon
sequestration.
2:53:49 PM
MR. CROWTHER responded that one problem that other states dealt
with was due to the location of the CO2 producing facilities.
He explained that sometimes CO2 pipelines needed to be built
across areas that were not familiar with that kind of transport
system and there was resistance to pipeline construction from
some landowners. In contrast, he stated that most CO2 producers
in Alaska are located within regions that are accustomed to this
sort of industrial land use and are much closer to potential
storage sites, which would require less transportation;
therefore, DNR does not anticipate public concern. He suggested
that there could be public concern about other areas of
approving CCUS projects in the state but reiterated that the
department plans on addressing this through thorough
dissemination of information about CCUS, primarily on the
Division of Oil and Gas' website.
2:56:01 PM
REPRESENTATIVE MEARS shared her interest in the development of
the state's business plan for CCUS projects, particularly
regarding the interaction of tax credits and oil exploration
versus sequestration. She opined that the House Resources
Standing Committee has a lot of work ahead on HB 50 as the bill
is referred to only one subsequent committee, and she inquired
about the intended next steps for the process.
CHAIR MCKAY deferred discussion of next steps to later in the
meeting. He sought confirmation that there are no freshwater
aquafers in the North Slope that could possibly be contaminated
by CO2 injections due to the area's permafrost.
DR. LEPAIN confirmed that there was continuous permafrost on the
North Slope [that would prevent water contamination].
CHAIR MCKAY questioned how the revenues from CCUS projects would
be utilized and whether they would follow a similar path as oil
and gas revenue. He additionally asked whether there is data
from other states that have passed carbon sequestration
legislation that also own the subsurface mineral rights like the
state does in Alaska.
MR. O'QUINN replied that the department had looked into "peer
states" and explained that in foreign oil and gas jurisdictions
mineral rights are usually held by the government. He reported
that the State of Louisiana has a substantial amount of state
land it also owns the mineral rights to, and the state has
entered into commercial agreements with operators to sequester
carbon within state lands.
CHAIR MCKAY explained for the public that although the term
"exploration license" is being used in conjunction with CCUS
projects, the bill's intent is to utilize existing reservoirs
that are already well understood formations, and he sought
confirmation from the departments that new exploration for
sequestration would not be occurring.
3:00:57 PM
MR. O'QUINN confirmed the Chair McKay's understanding of the
exploration licenses and stated that in the context of
sequestration, exploration means "taking a closer look" at
already known sedimentary basins and formations to ensure that
the proposed storage sites have the most optimal geological
conditions possible.
COMMISSIONER-DESIGNEE BOYLE clarified that the bill is not
limiting sequestration to any specific geographic locations,
like the North Slope or Cook Inlet, because the department
recognizes that there may be power plant operators in other
areas of the state who would want to conduct exploratory work to
better understand the geology in their area and embark on CCUS
projects. He stated that the legislation was written with as
much flexibility as possible to allow the entire state the
possibility of utilizing carbon sequestration.
3:02:22 PM
REPRESENTATIVE RAUSCHER described his experience in the oil
industry both on the North Slope and on the Kenai Peninsula and
opined that the huge number of wells in operation in Alaska has
resulted in the state obtaining a large amount of experience in
how to responsibly drill new wells and an extensive knowledge of
the properties of the subsurface formations that may be used for
carbon storage. He shared his appreciation for HB 50 being
brought forth as a way to utilize the knowledge and technology
that has been developed in the state since the 60's to monetize
the "leftover" subterranean formations for Alaska. He posited
that introducing injection wells would be using "just an eighth"
of the process currently used for extraction and that HB 50
could be a productive way to capitalize on a new oil related
industry since the state is very familiar with the oil and gas
industry. He expressed his confidence in DNR's research and
knowledge of the existing subsurface formations.
3:05:56 PM
CHAIR MCKAY addressed Representative Mears' previous question on
the next steps for HB 50, stating that any further questions
could be brought to the chair or the presenters to be answered
at subsequent hearings. He said that there will be a hearing
where the sectional analysis of the bill and the attached fiscal
notes will be discussed. He said that there would be an
opportunity for public and invited testimony and that all
meetings would be scheduled with plenty of public notice.
[HB 50 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 50 Transmittal Letter 1.26.2023.pdf |
HRES 2/10/2023 1:00:00 PM |
HB 50 |
| HB 50 DNR DOG CCUS Bill One-Pager 2.1.2023.pdf |
HRES 2/10/2023 1:00:00 PM |
HB 50 |
| HB 50 Sectional Analysis 2.1.2023.pdf |
HRES 2/10/2023 1:00:00 PM HRES 2/15/2023 1:00:00 PM |
HB 50 |
| HB 50 Issue and Policy Review for CCUS in the State of Alaska.pdf |
HRES 2/10/2023 1:00:00 PM HRES 2/17/2023 1:00:00 PM |
HB 50 |
| HB 50 Peer-State Review Report.pdf |
HRES 2/10/2023 1:00:00 PM HRES 2/17/2023 1:00:00 PM HRES 2/20/2023 1:00:00 PM |
HB 50 |
| HB 50 DNR CCUS Presentation to HRES 02.10.2023.pdf |
HRES 2/10/2023 1:00:00 PM |
HB 50 |