For safe operation of a CCS demonstration project - JAPAN August 2009 Carbon Dioxide Capture and Storage (CCS) Study Group
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For safe operation of a CCS demonstration project
August 2009
Carbon Dioxide Capture and Storage (CCS) Study Group
Industrial Science and Technology Policy and Environment Bureau
Ministry of Economy, Trade and Industry
JAPANPreface In June 2008, the joint statement by G8 energy ministers at the meeting held in Aomori incorporated the content of “20 large-scale Carbon Dioxide Capture and Storage (CCS) demonstrations projects need to be launched globally by 2010”. And, also in the leader’s declaration of G8 Hokkaido Toyako Summit held in July in which Japan acted the chairperson of the G8, the above-mentioned statement by G8 energy ministers was supported. In response to this, in “Action Plan for Achieving a Low-carbon Society” approved by the Cabinet on 29 July, 2008, it was clarified that “Japan will start a large-scale CCS demonstration project at an earlier stage than FY2009 and aim for the practical use of CCS until 2020”. Meanwhile, Japan CCS Co. Ltd. was established in May 2008, funded by 29 domestic companies (and funded by 37 companies as of 31th July, 2009), and has been steadily investigating the potential locations and technological possibilities for carrying out the CCS demonstration project in an area in Japan on consignment from the national government and New Energy and Industrial Technology Development Organization (NEDO). Under these circumstances, CCS study group (private study group hosted by Director General, Industrial Science and Technology Policy and Environment Bureau, Ministry of Economy, Trade and Industry) was re-established in October 2008 in order to study the matters need to be observed from the safety and environmental perspectives in implementing a large-scale CCS demonstration project. Two working groups were set up to perform the practical study work. The document “For safe operation of a CCS demonstration project” presented here is a standard desired to be followed from the safety and environmental viewpoints in implementing a large-scale CCS demonstration project and is not a preliminary safety rule to be set up when putting CCS into practice in the future. The corporations executing the demonstration projects are expected to set up a more practical system (organization, internal regulations and procedures, etc.) to keep safety depending on the project-executed sites based on this standard. CCS-related regulations including safety are being studied by the concerned countries and international organizations, and regulatory networks are also developed and have started to operate. Putting CCS into practice in the future, we shall need not only the knowledge gained through demonstration projects executed in Japan but also the know-how gained through studies carried out by CCS projects executed in other countries, of the most advanced approach required to keep CCS projects safe, and of the trend of regulations in other countries. We hope that the result of the study group will be effectively used in the demonstration projects, contribute to adequate and smooth execution of the project, and lead to practical application of CCS including high cost-benefit performance through the accumulation of experience gained by the demonstration project.
Contents
1. Things to be assessed for CO2 storage from geological aspects 1
1-1 Formulation of hydrogeological and geological structure model 1
(1) Formulation of regional (conceptual) model
(2) Formulation of detailed (numerical simulation) model
1-2 Things to be assessed to perform large-scale demonstration project 2
(1) Confirmation of the existence of reservoir and cap rock
(2) Setting of adequate CO2 injection plan (injection rate and amount)
(3) Sealing property of cap rock
(4) Seismic activities occurred in the past in the vicinity of CO2 injection site
1-3 Data to be acquired, acquisition methods, and time-frame for acquisition 4
(1) Data to be acquired before drilling the exploration well
(2) Data to be acquired before CO2 injection
2. Transportation Standard 8
3. Safety consideration for placing CCS-related facilities 9
4. Environmental Impact Assessment (EIA) 11
4-1 Basic idea for EIA 11
4-2 Studies about EIA related to CCS technology 12
4-3 Implementation of demonstration project in the future 12
(1) Seepage scenario of CO2 injection
(2) Temporal change of the risk
(3) Understanding of range of the natural environmental change
(4) Items to be surveyed in the EIA
(5) Method of EIA
(6) Points to be considered
5. Safety consideration for the drilling, completion and P&A (plugging and
abandonment) for CO2 injection and storage wells 16
5-1 Drilling and Completion of wells 16
(1) Formulation of casing plan
(2) Blowout prevention procedure
(3) Cementing to prevent CO2 leakage
(4) Well completion
(5) Explosion protection
(6) Conformity with safety measures according to related laws and
regulations in Japan
5-2 Plugging and abandonment (P&A) of the well 17
5-3 Recording the well 17
6. Safety considerations for CO2 injection and operation 20
6-1 Formulating plans for CO2 injection and operation 20
6-2 Optimizing CO2 injection and operation through updating the detailed
models of the storage system 20
6-3 Relationship with other items 20
i7. Concentration standard of CO2 to be injected 21
7-1 For storage into sub-seabed geological formation 21
(1) CO2 captured in the process of existing chemical plants
(2) CO2 captured from gas emitted by IGCC
7-2 For storage into onshore geological formation 21
8. Monitoring 24
8-1 Things to be taken before starting CO2 injection 24
(1) Formulation of the detailed models of the CO2 storage system including
the reservoir and the upper stratum
(2) Improvement of the accuracy of reservoir simulation model in evaluating
CO2 behavior before starting CO2 injection
(3) Acquisition of background data related to monitoring items
8-2 Things to be taken after starting CO2 injection 24
(1) Monitoring to be implemented during CO2 injection phase
(2) Monitoring of geological formation, etc., after starting CO2 injection
(3) History matching
(4) Evaluation of long-term CO2 behavior
(5) Monitoring of integrity of CO2 injection well and exploration well(s)
(6) Duration of monitoring after finishing CO2 injection
8-3 Formulating monitoring plans 26
9. Measures to be taken when abnormalities occur 32
9-1 Possible abnormalities 32
9-2 Setting standards to detect abnormalities 32
9-3 Assumption, preparation and implementation of measures required when
abnormalities occur 33
9-4 Measures to be taken after settling abnormalities 34
9-5 Actions to be prepared to deal with abnormalities 34
(1) Setting of the rules for prevention of danger and the safety control system
(2) Screening of important scenarios such as CO2 seepage, etc.
(3) Installation of safety control facilities, etc.
10. CCS Study Group meetings held in the past 38
11. Committee member list, etc. 41
iiReferences
(Reference 1-1) Things studied by Research Institute of Innovative Technology for
the Earth (RITE) in CO2 gas storage demonstration project carried out in
Nagaoka (based on Document No.5, The First Joint Meeting of WG for Study
on Safety Standard Associated with CCS Implementation and WG for Study on
Long-term Safety Ensuring, etc.) 5
(Reference 1-2) Desirable geological conditions and necessary geological
information for underground CO2 storage clarified by the experience of
petroleum and natural gas developments in the past (based on Document No.1,
The Second Meeting of WG for Study on Safety Standard Associated with CCS
Implementation, etc.) 6
(Reference 1-3) Things to be studied to select the site considering seismic activities
(based on Document No.1, The Third Meeting of WG for Study on Safety
Standard Associated with CCS Implementation, etc.) 7
(Reference 2-1) Related regulations in current domestic laws 8
(Reference 2-2) Related regulations in other countries 8
(Reference 3-1) Case example of implementing CO2 gas storage project by RITE in
Nagaoka (by RITE) 9
(Reference 3-2) Example of CO2 separation and capture equipment
(by interview to companies) 10
(Reference 4-1) Potential leakage route shown in IPCC Special Report “Carbon
Dioxide Capture and Storage” Summary for Policymakers and Technical
Summary (ISBN 92-9169-119-4, p.32, Figure TS. 8.) 11
(Reference 4-2) Partially extracted from IPCC Special Report “Carbon Dioxide
Capture and Storage” Summary for Policymakers and Technical Summary
(ISBN 92-9169-119-4, p.13) 12
(Reference 4-3) Related regulations in current domestic laws 14
(Reference 4-4) Related regulations in other countries 15
(Reference 5-1) Current safety standard for drilling petroleum and natural gas wells 18
(Reference 5-2) Current safety standard for P&A of petroleum and natural gas wells 19
(Reference 6-1) Related regulations in other countries 20
(Reference 7-1) Regulations of London Convention 1996 Protocol (from ANNEX 1) 22
iii(Reference 7-2) Regulations of the Law Relating to the Prevention of Marine
Pollution and Maritime Disaster 22
(Reference 7-3) Related regulations in other countries 23
(Reference 8-1) RITE’s studies in the CO2 storage demonstration project in Nagaoka
(based on the Document No.5, The First Joint Meeting of WG for Study on
Safety Standard Associated with CCS Implementation and WG for Study on
Long-term Safety Ensuring, etc.) 27
(Reference 8-2) Effective monitoring for quantitative assessment of storing volume
and early leakage detection (based on the Document No.2, The Third Meeting
of WG for Study on Long-term Safety Ensuring, etc.) 29
(Reference 8-3) Things to be requested for monitoring based on the relationship with
earthquakes (based on the Document No.1, The Third Meeting of WG for
Study on Safety Standard Associated with CCS Implementation, etc.) 31
(Reference 9-1) Equipments and facilities to be required from the viewpoint of
preventing CO2 leakage (Example) (based on Articles 29 to 40 of the
Petroleum Pipeline Business Law) 35
(Reference 9-2) Measures actually taken by RITE against the earthquake which
occurred while CO2 storage demonstration project was being carried out in
Nagaoka (refer to Document No.5, The First Joint Meeting of the WG for
Study on Safety Standard Associated with CCS Implementation and the WG
for Study on Long-term Safety Ensuring, etc.) 35
(Reference 9-3) Related regulations in other countries 37
iv1. Things to be assessed for CO2 storage from geological aspects
1-1 Formulation of hydrogeological and geological structure model
In order to assess a CO2 storage project from geological aspect, following conceptual and
detailed models of hydrogeological and geological structures should be formulated to
investigate the appropriateness of the project.
(1) Formulation of regional (conceptual) model
Regional (conceptual) model of hydrogeological and geological structure including CO2
reservoir, cap rock, and their upper section should be formulated using existing
materials. In constructing the model, the target region should include major geological
structure related to the fluid trap or entire anticlinal structure and cover the range from
the reservoir to the ground surface or seafloor surface.
This model should be used to roughly assess and forecast the injected CO2 behavior in
the targeted regional formation to specify the impacted extent with consideration of the
groundwater flow as much as possible, to perform the forecast and specification of the
impacted extent. If necessary, this model should be used to set the boundary condition in
formulating the detailed model described in (2) as well.
(2) Formulation of detailed (numerical simulation) model
Using the regional (conceptual) model formulated in above (1), the impacted extent by
injection of all planned CO2 volume should be estimated and a detailed model should be
formulated to assess the hydrogeological and geological structure of the extent
(reservoir) including the cap rock. In order to update the model and perform further
elaboration, the formulated model is to be reconstructed through feedback of the data
obtained as results of geophysical loggings, core tests or in-situ tests implemented at the
injection well and observation well(s) (Note 1-1) before starting CO2 injection or the data
obtained from monitoring implemented after starting CO2 injection. This model is to be
used to confirm that the injected CO2 remains in the aimed region in the planning of
CO2 injection and storage demonstration project. If necessary, it is to be used to improve
the original project plan, and used as the base to forecast the long-term CO2 behavior.
And, this model is also used to assess environmental impact or possibility of leakage of
injected CO2 (Note 1-2).
(Note 1-1) On implementation of a demonstration project, it is desirable to drill one or more
observation well(s) in addition to injection well in order to acquire enough data in
advance. However, it is also possible to admit that the existing data is effectively used
to complement data from observation well, the exploration well is used as injection
well, or the exploration well is used as an observation well, and this problem should be
considered depending on the site situation.
(Note 1-2) In this issue, the term “leakage” means migration from the targeted reservoir, and the
term “seepage” means migration to drink-use groundwater or that from underground to
the atmosphere or to water column of the sea.
11-2 Things to be assessed to perform large-scale demonstration project
(1) Confirmation of the existence of reservoir and cap rock
[Basic idea] (Note 1-3)
The storage possibility and assumed reservoir volume should be confirmed based on
adequate assumption and foundation, according to hydrogeological and geological
structure model (detailed model) for the region including reservoir and cap rock.
It should be confirmed that there is no large-scale fault in the reservoir region or in
its vicinity where the injected CO2 is expected to permeate and spread, no discharge
of subsurface fluid, and the continuity of geological strata (respective layers) to serve
as reservoir and cap rock. If a fault is found, the sealing property and leakage risk
should be carefully studied.
It is also required to confirm that the cap rock has enough thickness, overlies the
reservoir continuously, is in condition to retain the injected CO2 in the reservoir and
prevent any leakage.
If there is any artificial structure like a well, it is required to figure out the position
and condition sufficiently to confirm that there is no possibility that the structure
becomes a leaking route.
[Things to be assessed before starting CO2 injection]
Using public information, detailed seismic reflection survey (hereinafter called
“seismic survey”) data, and/or results of core analysis or in-situ test, it is required to
confirm the existence and extent of the reservoir and to evaluate if the reservoir may
retain the planned volume of CO2.
Based on the public information or data related to seismic survey and existing
geological structure, it should be confirmed that there is no fault or discontinuous
plane in the reservoir and the cap rock. If a fault is found, the sealing property and
leakage risk should be carefully evaluated.
And, if a fault or discharge point of subsurface fluid is expected to be present on the
surface of the ground or seafloor surface, it is required to assess the location where
the fault plane comes closest to the stored CO2 and the distance between them, to
evaluate the impact possibility based on reconnaissance or bibliographic survey of
the vicinity of CO2 injection point.
Based on public information, seismic survey, and analysis of existing core sample, it
should be evaluated if it is highly favorable that there is a cap rock serving as CO2
seal and the aimed amount of CO2 may be retained in the lower formation.
And, based on analysis of lithofacies and rock components (minerals) of the reservoir,
water sample from the formation, and the cap rock, it is required to investigate the
impact of chemical reaction assumed to take place during CO2 injection and to assess
the impact on storing capacity and injectivity.
(Note 1-3) [Basic idea] shows items to be confirmed in principle and [Things to be assessed before
starting CO2 injection] shows the specific methods.
2(2) Setting of adequate CO2 injection plan (injection rate and total amount)
[Basic idea]
Based on the depth of the injection formation and the petrophysical property data, it
is required to confirm whether it is possible to inject the CO2 gas at the planned
injection rate.
Using the formulated detailed model, it is required to conduct a reservoir simulation
to confirm whether it is possible to inject and store the planned volume of CO2.
[Things to be assessed before starting CO2 injection]
Based on public information, the results of seismic survey, sampling and analysis of
the core, and in-situ test, it is required to confirm the existence and extent of the
reservoir as well as to measure the porosity and permeability of the reservoir to
estimate whether it is adequate to inject CO2 at the planned injection depth by
conducting a reservoir simulation.
(3) Sealing property of cap rock
[Basic idea]
It should be confirmed that the cap rock existing over the reservoir may retain
necessary sealing capability.
It should be confirmed that the cap rock may not be broken down when the planned
CO2 injection pressure is applied.
[Things to be assessed before starting CO2 injection]
It is required to measure the threshold pressure of the cap rock in the laboratory
experiment using core samples to confirm that the reservoir pressure stays within the
threshold pressure in principle after starting CO2 injection. As need arise, it is
required to measure the cap rock property (permeability, etc.) to evaluate the sealing
property also by the laboratory experiment using core samples.
And, it is required to confirm by in-situ test that the breakdown pressure of the
formation serving as the cap rock is far larger than the pressure occurred at the
planned CO2 injection rate.
(4) Seismic activities occurred in the past in the vicinity of CO2 injection site
[Basic idea]
It is required to identify the seismic activities (such as hypocenter distribution)
occurred in the past in the vicinity of CO2 injection site and acquire the background
data that may be compared with the monitoring data.
[Things to be assessed before starting CO2 injection]
Based on the investigation results of the geology and stratigraphy in the vicinity of
CO2 injection site, as well as the analysis results of the existing public information on
seismic activities occurred in the past, it is required to confirm that the seismicity in
the vicinity is not remarkably higher than that in other areas.
And, in order to acquire background data for a reasonable period (about one year as
standard), it is required to place seismometers prior to CO2 injection at the CO2
injection site and the sites where monitoring will be conducted after starting CO2
injection.
31-3 Data to be acquired, acquisition methods, and time-frame for acquisition
(1) Data to be acquired before drilling the exploration well (Note 1-4) (Note 1-5)
Data to be acquired and acquisition method Purpose
Acquisition of public information and Existence of geological structure trapping CO2
existing data related to geological condition, Estimation of regional hydrological structure
and implementation of seismic survey
Confirmation of existence of cap rock and reservoir
and estimation of storing capacity
Evaluation of continuity of reservoir and cap rock
(such as pinch out of reservoir and presence of fault)
(Note 1-4) When a seismic survey is conducted immediately after drilling the exploration well or before
drilling the injection well, it is not required to conduct the survey before drilling the
exploration well.
(Note 1-5) If a discharge point of subsurface fluid is present on the ground surface, it is required to
investigate various water and gas properties in order to investigate the fluid origin.
(2) Data to be acquired before CO2 injection
Data to be acquired Acquisition method Purpose
Formation data obtained by Geophysical loggings Identification of cap rock and
various loggings reservoir (lithofacies, fluid
saturation, permeability, etc.)
Stratigraphy and lithofacies Mud logging, analysis of Confirmation of lithological
cuttings, etc. character, formation depth, and
stratigraphy
Mineral composition of rocks in Analysis of core sample, Confirmation of lithological
the reservoir, cap rock and analysis of cuttings, etc. character and stratigraphy, type
upper formation and response of chemical
reaction assumed to take place
during and/or after CO2
injection
Porosity of reservoir, cap rock Geophysical logging, core test, Estimation of reservoir capacity
and upper formation analysis of cuttings, etc.
Permeability of reservoir, cap Core test, pressure test, analysis Evaluation of sealing property
rock and upper formation (Note of cuttings, etc. and injectivity
1-6)
Capillarity pressure of reservoir Core test Evaluation of maximum gas
saturation
Threshold pressure of cap rock Core test Evaluation of sealing capability
of cap rock and upper-limit of
storing pressure
Breakdown pressure of reservoir Core test and step rate injection Evaluation of reservoir rock
test strength and upper-limit of
injection pressure
Breakdown pressure of cap rock Core test and leak off test (Note Evaluation of cap rock strength
1-7)
and upper-limit of injection
pressure
Temperature and pressure Measurements of temperature Evaluation of CO2 solubility
and pressure (including and adequacy of injection
temperature gradient and pressure
pressure gradient) during
drilling and by well logging
4Data to be acquired Acquisition method Purpose
Chemical components of Component analysis of Evaluation of CO2 solubility
formation water formation water samples and reactivity with rocks
(Note 1-6) If the cap rock permeability is extremely low, accurate measurement of permeability and
porosity of the cap rock is not necessarily required.
(Note 1-7) Concerning the breakdown pressure of the cap rock, the method of estimating the stress
without breaking the cap rock is being studied on Petroleum and Mine Safety Subcommittee,
and adoption of such technology is admitted under the assumption that it should pass through
technological study on this subcommittee.
(Reference 1-1) Things studied by Research Institute of Innovative Technology for the Earth
(RITE) in CO2 gas storage demonstration project carried out in Nagaoka
(based on Document No.5, The First Joint Meeting of WG for Study on
Safety Standard Associated with CCS Implementation and WG for Study on
Long-term Safety Ensuring, etc.)
1. “High sealing property and continuity of cap rock”
[Background idea]
This is based on points that the injected CO2 should be stably stored for a long period
and the gas leakage from the injected formation to the upper formation should be
prevented.
2. “Desirable depth of deep saline formation is 800 to 1,200 m”
[Background idea]
To inject CO2 with a minimized volume, it is preferable to store CO2 in supercritical
state into the deep saline formation. This criteria of 800 m is set up to meet the
formation temperature and pressure that cause this supercritical state (about 31°C or
higher and 7.4 MPa or higher).
(The lower limit of 1,200 m may be set up in consideration of drilling cost and
injection efficiency.)
3. “Deep saline formation with effective continuous thickness of about 10 m or larger is
preferable”
[Background idea]
The formation should have a thickness enough to retain the planned amount of CO2
(8,000 to 10,000 tons).
4. “Slopes of cap rock and deep saline formation should be moderate”
5. “There is no fault or impermeable formation that may affect on the vicinity of cap rock
and deep saline formation (within range of 1.5 km2 area)”
[Background idea]
There is almost no fault whose angle with respect to the ground surface is less than
60°. Therefore, it is sufficient to confirm that there is no fault that may cause CO2
leakage in a range of circular cone spreading towards the ground surface and that the
formation retains continuity, assuming that the angle of generatrix with respect to the
ground surface is 60°. The injection depth is about 1,200 m and the injection point is
vertex in this case.
5(Reference 1-2) Desirable geological conditions and necessary geological information for
underground CO2 storage clarified by the experience of petroleum and natural gas
developments in the past (based on Document No.1, The Second Meeting of WG for Study on
Safety Standard Associated with CCS Implementation, etc.)
1. Geological structure
[Basic idea]
It is necessary that a geological structure to trap CO2 definitely exists. As a specific
structure, it may be anticlinal trap, fault trap, or stratigraphical trap. Judging from the
experience of petroleum and natural gas developments, anticlinal trap is primarily
desired as a targeted potential location. However, if another type of trap is identified
based on enough technical sources, it should satisfy the conditions. In any case, the
presence of the trap should be confirmed.
2. Reservoir
[Basic idea]
It is necessary to confirm that there is storing capacity enough to release the pressure
rise along with CO2 injection. And it is required to confirm the possibility of injection at
the planned injection rate, by conducting injectivity measurement as well as simulation
if necessary.
In addition, it is necessary to confirm that the reservoir has enough extent and
continuity (no heterogeneity, no fault, etc.).
3. Cap rock
[Basic idea]
The cap rock should have enough thickness so that the injected CO2 may not leak out,
and fully cover the reservoir. And, it is required to securely prevent CO2 leak by the
effect of capillarity pressure.
In addition, the cap rock should have enough strength so that it may not be broken down
by CO2 injection pressure.
6(Reference 1-3) Things to be studied to select the site considering seismic activities (based
on Document No.1, The Third Meeting of WG for Study on Safety Standard
Associated with CCS Implementation, etc.)
1. Presence of fault
[Basic idea]
It is required to conduct surveys on active fault, active fold, geological condition, and
ground structure in the vicinity of CO2 injection site. If an active structure or fault is
present in the vicinity, it is required to confirm its impact on the reservoir and cap rock.
No fault in the vicinity of CO2 storing site is desirable. However, even if there exists
such a fault, it may be possible to execute a CCS project if the scale and the sealing
(shale formation) properties of the fault are appropriate.
2. Seismic activities
[Basic idea]
It is important to investigate earthquakes in the past, active structures, and
micro-seismicity in the vicinity of the injection site to confirm that there is no
abnormality, and to sufficiently figure out the background related to seismicity in the
vicinity to contribute to the monitoring after CO2 injection.
72. Transportation Standard
Since CO2 is inert gas and the CO2 gas transported for CCS meets certain standards such as
volume concentration of impurities (refer to Section 7), it may not be required to set up new
standards specified for transportation of the gas for CCS, for safety and environmental
protection. Therefore it is required to follow and apply the related laws and regulations shown
in (Reference 2-1).
(Reference 2-1) Related regulations in current domestic laws
Among current domestic laws, there is the High Pressure Gas Safety Act as a law related to
CO2 transportation. In this Act, CO2 corresponds to “high pressure gas” due to temperature
and pressure conditions (Article 2, Paragraph 1, Item 1 of the act), and is obliged to be taken
necessary safety measures when transporting the gas in accordance with Article 23, Paragraph
1 of the act.
The standards for practical safety measures are specified in Article 48 for gas transportation
by vehicles and in Article 51 for that by conduit pipes, respectively, in the General Rules on
the High Pressure Gas Safety Act.
In addition, as other related laws and regulations, transportation using vehicles requires
passage admission based on the Road Act relating to loading method and weight.
For transporting CO2 by use of ships, necessary measures are specified in the rules for ship
transportation and accumulation of dangerous matters on the Ship Safety Act and the public
notice to set standards on transportation of dangerous matters by ship.
More specifically, CO2 is classified into high pressure gas (Article 2, Paragraph 1-b of the
rules), hazardous materials (Article 2, Paragraph 1-i of the rules), or liquefied gas materials
(Article 2, Paragraph 1, item 2-a of the rules), depending on the state (gas, liquid, or solid)
and transportation method (transportation by individual matters or by bulk matters) and
necessary transportation measures are specified in those regulations.
(Reference 2-2) Related regulations in other countries
For implementing the CCS, there is no special regulation newly set up for safety and
environmental reasons concerning the CO2 transportation in the US, EU and Australia.
83. Safety consideration for placing CCS-related facilities
Respective facilities and equipment installed to implement the CCS demonstration project
should follow and/or apply existing laws and regulations such as the Mine Safety Act.
(Reference 3-1) Case example of implementing CO2 gas storage project by RITE in
Nagaoka (by RITE)
Related laws and regulations that RITE complied with about the facilities in implementing the
project of storing about 10,000 tons of CO2 in Nagaoka and installation of the facilities, are as
follows.
Facilities
Practically installed facilities Related laws and regulations followed
(Major items)
Well Injection well Mine Safety Act
Observation well Mine Safety Act
Injection Liquefied carbon dioxide tank (Note 3-1) Mine Safety Act
facilities (Facilities to manufacture high
pressure gas)
Evaporation-by-heating equipment for Mine Safety Act
storing liquefied carbon dioxide (Note 3-1) (Facilities to manufacture high
pressure gas)
Booster pump (Note 3-1) Mine Safety Act
(Facilities to manufacture high
pressure gas)
Liquefied carbon dioxide gas pressure Mine Safety Act
pump (Note 3-1) (Facilities to manufacture high
pressure gas)
Power receiving facilities and demand Mine Safety Act
facilities (Note 3-2) (Electrical equipment)
Water receiving facilities
Water supply tank
(Note 3-1) These items among the injection facilities complied with the “High Pressure Gas Safety Act”.
Application for approval of facility installation as “Facilities to manufacture high pressure
gas” based on the Mine Safety Act was carried out. Facilities related to the safety (safety
valve, emergency shutoff device, CO2 gas leakage detection alarm device, and notification
system) are also included.
(Note 3-2) Installation of these facilities was approved as Electrical equipment on the Mine Safety
Act.
9(Reference 3-2) Example of CO2 separation and capture equipment (by interview to
companies)
As a result of surveyed the installation of CO2 separation and capture equipment based on
chemical absorption technique (such as amine absorption technique) in Japan, the related laws
and regulations followed when installing the facilities are as follows.
Facilities
Practically installed facilities Related laws and regulations followed
(Major items)
CO2 separation Desulfurization equipment Poisonous and Deleterious Substances
and capture Control Law
equipment (NaOH for high desulfurization:
Deleterious substance)
Absorption tower High Pressure Gas Safety Act
Regeneration tower (including Industrial Safety and Health Act
reboiler) (First-class pressure vessel)
Absorbent replenishing tank Poisonous and Deleterious Substances
Control Law
(KOH: Deleterious substance)
Compressor High Pressure Gas Safety Act
(Note 3-3) Applicability of above related laws and regulations varies depending on practical content of
chemical absorption techniques and gas pressure.
104. Environmental Impact Assessment (EIA)
4-1 Basic idea for EIA
It has not been long since CCS was internationally recognized as a promising option in terms
of a measure against global warming. The world’s first CO2 injection into subseabed aquifer
to mitigate global warming began in 1996 in Sleipner, Norway. Contrary to this, the duration
expected to isolate CO2 by CCS is incomparably long.
IPCC Special Report on Carbon Dioxide Capture and Storage (2005) was compiled by the
world’s best expertise in CCS field. About the possibility and extent of impact of CCS on
environment, the description of IPCC special report can be regarded as the most reliable
authority for starting the study.
This report shows “the fraction retained in appropriately selected and managed geological
reservoirs is very likely to exceed 99% over 100 years and is likely to exceed 99% over 1,000
years.” And also, the risk that may occur if the injected CO2 leaks out is classified into
global-scale risk and local risk, describing that the former may affect climate change and the
latter may affect human body, ecological system and groundwater.
On the other hand, CO2 stored by CCS is the gas that might be emitted to atmosphere and
separated and captured only for the purpose of measure against global warming. It should be
noted in advance that the requirements such as volume concentration that should be met by
the separated and captured CO2 are distinct (See also reference 7-1 and 7-2).
In storing CO2, the study necessary to select a site capable of safely and steadily storing the
planned volume of CO2 is also conducted (See also section 1). And it should be noted that
after starting CO2 injection, even if an unusual situation such as CO2 leakage occurs, the
measures necessary to detect such an event as earlier as possible through monitoring is
already taken (See also section 8).
(Reference 4-1) Potential leakage route shown in IPCC Special Report “Carbon Dioxide
Capture and Storage” Summary for Policymakers and Technical Summary
(ISBN 92-9169-119-4, p.32, Figure TS. 8.)
1) The case where CO2 leaks due to failure of injection well and abandoned well
2) The case where CO2 gradually leaks through undetected faults and fractures
A. CO2 gas pressure exceeds capillary pressure & passes through siltstone
B. Free CO2 leaks from A into upper aquifer up fault
C. CO2 escapes through ‘gap’ in cap rock into higher aquifer
D. Injected CO2 migrates up dip, increases reservoir pressure & permeability of faults
E. CO2 escapes via poorly plugged old abandoned well
F. Natural flow dissolved CO2 at CO2 / water interface & transports it out of closure
G. Dissolved CO2 escapes to atmosphere or ocean
114-2 Studies about EIA related to CCS technology
To obtain necessary scientific knowledge to assess the long-term impact in case CO2 stored
under the seabed leaks out to ocean, some studies (ex. Storage on natural CO2 leakage in
marine area: RITE) are carried out but these are no studies to make standard method or
approach.
Meanwhile, the EIA on benthos as well as plankton is recently studied.
(Reference 4-2) Partially extracted from IPCC Special Report “Carbon Dioxide Capture and
Storage” Summary for Policymakers and Technical Summary (ISBN
92-9169-119-4, p.13)
“At these levels of pH change, some effects have been found in organisms that live near the
ocean's surface, but chronic effects have not yet been studied. A better understanding of these
impacts is required before a comprehensive risk assessment can be accomplished.”
4-3 Implementation of demonstration project in the future
(1) Seepage scenario of CO2 injection
Concerning the potential leakage routes in IPCC Special Report shown above
(Reference 4-1), the routes where the leakage may actually occur are classified into
1) escape along the injection well or abandoned well, 2) escape along the fault or
fracture, 3) escape along the injection stratum, and 4) escape through the cap rock, and
actual seepage may occur by combination of these leakages.
Among these, leakage routes 3) and 4) are thought to have possibilities to configure a
portion of a seepage scenario for very long term (100,000 to 1,000,000 years), and
leakage routes 1) and 2) are thought to be a scenario that may lead to seepage even in
short term.
For the EIA, these leakage routes, seepage scenario, and leakage driving force such as
buoyancy, pressure, etc. corresponding to the scenario should be also considered.
(2) Temporal change of the risk
As shown in the report (2008) of International Risk Governance Council (IRGC),
concerning the temporal change of the CO2 seepage risk, it is generally thought that the
seepage risk gradually increases after the start of injection and reaches the highest point
when the injection completed, then the seepage risk gradually decreases as time passes
after closing the site.
In the EIA process, it is adequate to conduct studies in consideration of the temporal
change of the risk.
(3) Understanding of range of the natural environmental change
In implementing the CCS demonstration project, it is important to confirm the natural
fluctuation of the EIA target items to evaluate the impact onto the environment.
Therefore, when the demonstration site is determined, collection of such data to be
12surveyed in the EIA should be begun as soon as possible before starting to implement the
demonstration project.
(4) Items to be surveyed in the EIA
The item indicated in the Law Relating to the Prevention of Marine Pollution and
Maritime Disaster shall be surveyed, and the EIA items desired to be surveyed including
onshore storage, before, during and after injection, are thought to be as follows.
[Environmental impact assessment items required to be studied]
Air quality Carbon dioxide
Sulfur oxide
Nitrogen oxide
Dust
Noise
Vibration
Water quality (Shallow groundwater) pH
HCO3-
Contamination
Turbidity
Water temperature
Concentration of hazardous substances
(including metal)
Chemical properties of seawater CO2 concentration index
Hydrogen ion concentration
Concentration of hazardous substance
(including metal)
Organism and ecosystem Appropriate item according to the site
Scenery situation to be selected
Opportunities for human beings to contact the
nature
Waste
Ground, geological formation, and geological
condition
Soil contamination
(5) Method of EIA
To implement the EIA, firstly the CO2 seepage scenario should be clarified by the
consideration of leakage route and leakage driving force as mentioned above (1),
secondly the survey method and plan which reflect it should be made.
(6) Points to be considered
The EIA on the CCS are characterized by some points, which are, 1) existence of
environmental impacts by CO2 seepage is not clear, 2) environmental impact by CO2
seepage might arise in far-distant future, and 3) no similar example exists in other
13development activities that requires EIA and its implementation method is not clear
internationally.
Based on such circumstances, when practical application of CCS is progressed in the
future following the demonstration projects to be implemented from now on, the content
of the EIA and its method are desired to be re-assessed in consideration of knowledge
accumulated in domestic demonstration project so far implemented and up-to-date
trends of international discussion at that time.
(Reference 4-3) Related regulations in current domestic laws
For dumping CO2 stream into subseabed formation based on the Law Relating to the
Prevention of Marine Pollution and Maritime Disaster, “Preliminary Assessment Document
for Dumping Waste Under the Seabed (PADDWUS)” should be attached with application for
the permission (Article 18, Paragraph 8, Item 2 of the law) to be submitted to Minister of the
Environment (note: The PADDWUS is used to survey impacts on marine environment caused
by CO2 stream dumping under the seabed). Items required to be written in this PADDWUS
are as follows (7 items), as specified in Article 4, Paragraph 1, Item 1 to 7 of the ordinance
relating to permission, etc. of dumping of specified CO2 into subseabed formation
(Regulation No. 23 released by the Ministry of Environment in 2007).
1) Characteristics of CO2 stream to be dumped into subseabed formation
2) Point and extent, volume and the estimation method of CO2 stream seepage on the
assumption that CO2 stream dumped into subseabed formation seeps out to the sea
3) Potential Marine Environmental Impact Assessment Items (PMEIAIs)
4) Current state and survey method of the PMEIAIs
5) Degree, spatial extent and the forecast method of the changes on the PMEIAIs on the
assumption that CO2 stream seeps out to the sea
6) Analysis of degree of the impacts on marine environment and the result of preliminary
assessment based on the analysis on the assumption that the CO2 stream seeps out to the
sea
7) Other reference items available related to preliminary assessment based on the survey
results about the impacts of CO2 stream dumping under the seabed on marine
environment
Necessary matters included in creating the PADDWUS are stated in “Guideline to apply
permission for dumping of specified CO2 into subseabed formation (released by the Ministry
of Environment in January, 2008).
14(Reference 4-4) Related regulations in other countries
1. EU regulations (CCS directive)
As revision of related directives by CCS directive supplementary provision,
1) conduit pipes to transport CO2 (over 800 mm in diameter, over 40 km in entire
length) and,
2) CO2 storage site and CO2 capture equipment (limited to capture of over 1.5 million
tons),
are described as items required to be assessed on environmental impact in governmental
or private projects, and the EIA is performed in accordance with conventional
assessment directives (EC directive 85 / 337 / EEC).
2. US UIC program Class VI
Implementation of preliminary EIA related to CCS-related facility installation is not
specially sought and necessary EIA is coped in accordance with respective state laws.
However, in the UIC program, the minimum standard (§146.83) that needs to be met by
the site for CO2 injection is shown. The project-executing company must prove that
geological structure of the site is adequate to store the planned volume of CO2, and the
possibility of CO2 leakage, for example, will be studied during the process.
155. Safety consideration for the drilling, completion and P&A (plugging
and abandonment) for CO2 injection and storage wells
5-1 Drilling and Completion of wells
(1) Formulation of casing plan
Prior to the commencement of drilling a well, a casing plan should be formulated. Its
purpose is to protect underground fresh water zones used for drinking, industrial and
other purposes, which exist at shallower depth than the reservoir for CO2 injection. It is
also used to avoid drilling difficulties such as lost circulation, hole caving, blowout and
so on.
(2) Blowout prevention procedure
The drilling of each well should be carefully planned to prevent blowout. It may be
done by analyzing all available data regarding the geological structure and pore pressure
versus depth, and introducing multiple casing if necessary. During drilling, the
hydrostatic pressure of the drilling-fluid column should be controlled by adjusting the
mud density in proportion to the estimated formation pressure, which is estimated by
constant monitoring.
In addition, at least one or more blowout preventers (BOP) should be installed to
prevent the blowout of high pressure fluid.
During the drilling of wells, all possible measures to detect any indication of
abnormally high formation pressure and any influx of formation fluid into the wellbore
should be applied. It may include continuous monitoring of the gas content of return
mud and the mud flow rate. Blowout should be assiduously avoided during simple
injection and other operations as well, for example, changing the tubing pipe.
(3) Cementing to prevent CO2 leakage
CO2 injection wells must have wellbore integrity to ensure that there is no CO2 leakage
during the injection period, as well as during the long-term shut-in period thereafter.
Cement should be properly placed in the required sections between casings and the
wellbore. CO2 resistant cement should be used to fill-in the spaces where the cement is
expected to be exposed to injected CO2.
(4) Well completion
The tubing and packer should be used to isolate casing from the injected CO2 and a
system should be put in place to detect any indication of leakage of the injected CO2 by
monitoring the annulus pressure during the injection period.
In the drilling and completion of the injection well, the planned CO2 injection pressure
and rate, and strength of the casing and tubing should be comprehensively studied to
ensure the wellbore integrity.
To prevent corrosion by injected CO2 and to ensure the long-term integrity, the wellbore
equipment should be composed of CO2 corrosion-resistant material or undergone
16surface treatment to ensure resistance to CO2 corrosion as required.
The connections of production casings and well-heads should have adequate sealing
capability in accordance with the planned injection pressure of the CO2.
(5) Explosion protection
Explosion proof equipment should be used in the vicinity of the well-head to secure a
level of safety equivalent to that for drilling oil and gas wells.
(6) Conformity with safety measures according to related laws and regulations in Japan
Based on the Mining Act, the Mine Safety Act, and the Petroleum and Combustible
Natural Gas Resources Development Act in Japan, requirement for the drilling of wells
and the installation of related facilities must secure a level of safety equal to that for oil
and gas development in Japan.
5-2 Plugging and abandonment (P&A) of the well
To secure safety for the P&A of the injection wells, the observation wells, and the monitoring
wells, the regulations related to the Mine Safety Act, etc., in Japan should be applied
correspondingly and long-term stability should be considered.
Therefore, for the cement plug of the portion that may be in contact with CO2, CO2 resistant
cement and additives should be applied. Then the necessary measures to reduce residual CO2
especially in the vicinity of the wells should be studied.
5-3 Recording the well
To clearly identify the existence of the wells after P&A, the project-executing company must
keep their precise records. The records include their locations, the method used for plugging
and abandonment, and the associated conditions to be ready to submit to the authorities
concerned as requested.
17(Reference 5-1) Current safety standard for drilling petroleum and natural gas wells
1. Mining Act
Under Article 63, Paragraph 1 and 2 of the Mining Act, the operation plan must be
notified to the Director-General, Bureau of Economy, Trade and Industry or be
authorized by the Director-General.
According to Article 27 of the regulations for enforcement of the Mining Act, the
exploration right holder or the exploitation right holder who conducts the application
must submit the operation plan according to the provisions of Form No. 20 designed in
the regulation, with explanatory drawings.
2. Petroleum and Combustible Natural Gas Resources Development Act
According to Article 35, Paragraph 1 of the Petroleum and Combustible Natural Gas
Resources Development Act, the mining right holder must submit the spudding
application to the Director-General, the Bureau of Economy, Trade and Industry. The
spudding application form is specified in Article 41, Paragraph 9 of the regulations for
enforcement of the act.
3. Mine Safety Act
According to Article 13 of the Mine Safety Act, after filing the operation plan based on
the Mining Act or upon receiving the permission, the mining right holder must submit
the construction project plan including the placement of the drilling facility to be used.
The drilling facilities are specified in No. 5 “Drilling facilities in oil and mine” of
Appendix No. 2 of the regulations for enforcement of the act. The construction project
plan is applied using Form No. 1 of the regulations, and the entries to be made in the
form are separately specified in “Entries for construction project plan”.
Also, the technical standards for drilling facilities, etc. are specified in “Ordinance to set
technical standards on work pieces, etc., to be used on mining”. For example, the
standard for blowout preventers is specified in Article 17, Paragraph 4, Item 11 of the
ordinance, while the standard for offshore drilling vessels used in offshore exploration
work is specified in Article 18 of the ordinance, respectively. The detailed specifications
are stated in “Chapter 15: Drilling equipment” and “Chapter 16: Drilling barge”, in the
technical guideline for the ordinance.
The anti-explosion measures to be taken by the mining right holder are specified in
Article 15 of the regulations for enforcement of the Mine Safety Act. The “Examples of
measures to be taken by mining right holder” is shown in “Chapter 13: Handling of
products causing fire”. This chapter, for example, specifies that the electrical facilities
within 8 m from “Keep Fire Away” sign or the facilities that may cause fire or explosion
should be a type of explosion-proof.
18(Reference 5-2) Current safety standard for P&A of petroleum and natural gas wells
The details for the P&A of petroleum and natural gas wells are specified in Article 8 of the
Mine Safety Act and Article 25 of the Ordinance for enforcement of the Act. The detailed
specifications are stated in Chapter 22 of “Examples of measures to be taken by mining right
holder”.
(1) Measures for wells for oil or natural gas production from structural reservoirs
If there is a completion layer or a test layer in the open hole, the well shall be sealed
with a cement plug except for the part which is within 30m above and below the
layer.
If there is an open hole under the last casing, cement plugs of 30m or longer shall be
inserted both above and below the casing shoe, or a bridge plug shall be placed
immediately above the casing shoe.
A cement plug of 30m or more in length shall be positioned above the top end of the
perforation section or a bridge plug shall be placed immediately above the
perforation section.
The well shall be sealed near the ground surface by a cement plug of at least 30 m in
length placed in the vicinity of the ground surface.
All of the casings, well-heads, etc., shall be removed to a depth of at least 2 m from
the ground surface. After removing them, the vicinity of the wellhead shall be
covered with cement or sand to be restored to original state.
(2) Measures for wells for production of natural gas dissolved in water
The well shall be sealed by a cement plug of at least 30m immediately above the top
end of the perforation section.
The well shall be sealed near the ground surface by a cement plug of at least 30m in
length placed in the vicinity of the ground surface.
All of the casings and well-head equipment are removed to a depth of 1.5 m or
deeper from the ground surface. After removing them the wellhead area should be
filled up with cement or sand to be restored to original state.
196. Safety considerations for CO2 injection and operation
6-1 Formulating plans for CO2 injection and operation
In order to inject the aimed amount of CO2 gas and store it over the long term, it is necessary
to implement the CO2 injection and operation appropriately and securely by applying related
laws such as the High Pressure Gas Safety Law, etc. Therefore, before starting the operation,
it is necessary to formulate an execution plan for CO2 injection and operation which will
describe basic idea for setting the CO2 injection pressure, the standard value of injection
pressure, and procedures for setting and managing injection rate.
6-2 Optimizing CO2 injection and operation through updating the detailed model of
the storage system
After starting CO2 injection, the monitoring results of the CO2 behavior are used to verify and
update the detailed model. Furthermore, using the updated detailed models, the execution plan
for carrying out CO2 injection and operation is improved and optimized. More specifically,
the improved models are used to optimize the operational conditions, including injection rate
and injection pressure, until CO2 storage reaches to the aimed amount.
6-3 Relationship with other items
Concerning the monitoring refer to Section 8 and actions to be taken against abnormalities,
refer to Section 9.
(Reference 6-1) Related regulations in other countries
1. EU regulations (CCS Directives)
The contents of the storage permit (Article 9) include the requirements for ensuring
safety in CO2 injection and operation. Maximum CO2 injection rate and pressure are
included in the contents. There is no content aimed specifically at stipulating
operational conditions.
2. US UIC program Class VI
Requirements for CO2 injection well operation are provided in §146.88. This section
stipulates items to be continuously monitored, such as injection pressure, injection rate,
volume, temperature of CO2 stream, annulus pressure and the annulus fluid volume, etc.
In addition to these items, the following requirement is also specified:
“the owner or operator must ensure that the injection pressure does not exceed 90
percent of the fracture pressure of the injection zone”
207. Concentration standard of CO2 to be injected
7-1 For storage into sub-seabed geological formation
The project-executing company must comply with Prevention of Marine Pollution and
Maritime Disaster Act.
As practical application of CCS has advanced through various CCS demonstration
experiments, chemical absorption technique using amine solution is most likely to be used for
CO2 capturing method. However, since CCS demonstrations should be carried out as early as
possible, it is important to implement CCS through capturing CO2 also from coal thermal
power plant with high efficiency such as Integrated coal Gasification Combined Cycle
(IGCC), etc. Considering such important matters, it is necessary to study the following CO2
capturing methods as addition items and the concentration criteria in the Marine Protection
Act should be changed as flexibly and soon as possible to the extent permitted by London
Convention 1996 Protocol to be observed.
(1) CO2 captured in the process of existing chemical plants
Considering the facts that the chemical absorption technique using “potassium
carbonate solution” in ammonia manufacturing process is thought to comply with
London Convention 1996 Protocol and is already commercially available, it is
necessary to verify the component and volume percentage to study the possibility of
dumping CO2 into sub-seabed geological formation through this method.
(2) CO2 captured from gas emitted by IGCC
As for the CO2 standard applied in performing CCS in IGCC, the capturing method and
the concentration also need to be studied in an earliest possibility. More specifically,
captured CO2 is thought to contain H2S. (When amine absorption technique which is
already specified in the Law relating to the Prevention of Marine Pollution and
Maritime Disaster is used, H2S and CO2 are simultaneously absorbed.) Therefore, to
satisfy the required volume percentage, the process of separating CO2 from the mixed
gas of H2S and CO2 is also needed. In addition, physical absorption technique is
actually adopted in IGCC so that it is necessary to study appropriate CO2 capturing
method and concentration regulation corresponding to such current situation.
7-2 For storage into onshore geological formation
There are currently no laws and regulations specifying the standard for injected gas and
storing CO2 into onshore geological formation.
However for a case of storage into onshore geological formation in the future, even if seepage
of the stored CO2 from the underground to atmosphere or groundwater occurs, the seeped
substances other than CO2 should not exceed the rate permitted to be occupied in atmosphere
or groundwater.
21(Reference 7-1) Regulation of London Convention 1996 Protocol (from Annex 1)
Carbon dioxide streams may only be considered for dumping, if:
disposal is into a sub-seabed geological formation; and
they consist overwhelmingly of carbon dioxide. They may contain incidental associated
substances derived from the source material and the capture and sequestration processes
used; and
no wastes or other matter are added for the purpose of disposing of those wastes or other
matter.
(Reference 7-2) Regulations of the Law Relating to the Prevention of Marine Pollution and
Maritime Disaster
1. Regulations
[Regulations of the Law Relating to the Prevention of Marine Pollution and Maritime
Disaster]
In the Article 18, Paragraph 7, Item 2, “Specified carbon dioxide gas (gas that mostly
occupied by CO2 and meets the standard specified by government ordinance)” is
specified, and this specific carbon dioxide gas can be dumped into subseabed formation
through the permission of Environment Minister according to Article 18, Paragraph 8,
Item 1.
[Regulations of the order for enforcement of the Law Relating to the Prevention of
Marine Pollution and Maritime Disaster]
Article 11, Paragraph 5 of the order specifies that the gas is collected by method of
isolating carbon dioxide from other substances using the chemical reaction of amine
and carbon dioxide. The volume percentage of carbon dioxide contained in this gas
should be over 99%. (However, in the case where carbon dioxide is captured by amine
absorption method to produce hydrogen used for petroleum refining, the volume
percentage should be over 98%.)
2. Regulation background
Standard of CO2 in the Law Relating to the Prevention of Marine Pollution and
Maritime Disaster is based on the regulations of London Convention 1996 protocol.
That is to say, regarding CO2 standard specified as “overwhelmingly (at remarkably
high rate)” in the protocol, it is embodied by combination of the capturing method and
volume concentration in domestic laws. The reason why only amine absorption
technique is specified as the capture method is that the technique was already studied by
expertise when the government ordinance was enacted and that the method that may be
put into practice for a while and the concentration was already specified.
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