Overview, Status, and Future of the Fort Nelson CCS …...Fort Nelson CCS Project James A. Sorensen,...
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Overview, Status, and Future of the Fort Nelson CCS Project James A. Sorensen, Charles D. Gorecki, Lisa A. Botnen, Edward A. Steadman, and John A. Harju Energy & Environmental Research Center, University of North Dakota, Grand Forks, North Dakota EERC Energy & Environmental Research Center ® Putting Research into Practice © 2012 University of North Dakota Energy & Environmental Research Center Overview GHGT-11 – 2012 The Plains CO 2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center (EERC), and Spectra Energy Transmission (SET) are investigating the feasibility of a carbon capture and storage (CCS) project to mitigate carbon dioxide (CO 2 ) emissions produced by SET’s Fort Nelson Gas Plant (FNGP). The FNGP is located near the town of Fort Nelson in northeastern British Columbia, Canada. The gas stream produced by the FNGP will include up to 5% hydrogen sulfide (H2S) and a small amount of methane (CH4) and, as such, is referred to as a “sour” CO 2 stream. The sour CO 2 gas stream would be injected into a deep saline carbonate formation. The Fort Nelson demonstration project provides a unique opportunity to develop a set of cost-effective, risk-based monitoring, verification, and accounting (MVA) protocols for large-scale (>1 million metric tons a year) storage of sour CO 2 in a deep saline formation. The role of the PCOR Partnership is to provide the project with reservoir modeling and simulation, risk assessment of subsurface technical risks, and an MVA plan to address these risks. The PCOR Partnership applies a philosophy that combines geologic characterization, modeling, risk assessment, and MVA strategies into an iterative process to produce superior-quality results during the project feasibility and development periods. Elements of any of these activities are crucial for understanding or developing the other activities (Gorecki and others, 2012). Status To date, a variety of site characterization, modeling, risk assessment, MVA planning, regulatory permitting, and public outreach activities have been conducted. Collection of baseline data for shallow groundwater characteristics has been initiated. A comprehensive suite of existing well data, 2-D and 3-D seismic surveys, log analyses, and core testing results have been acquired and used to create static geologic models. The static geologic models have supported dynamic modeling, including history matching and the development of predictive simulations for selected injection scenarios. Results thus far suggest that the geology and hydrogeology in the vicinity of the FNGP are amenable to long-term geologic storage of CO 2 . The output from the characterization and modeling exercises has provided the basis for two iterations of a comprehensive risk assessment of the geologic risks associated with the Fort Nelson CCS project. The combined results of the characterization, modeling, and risk assessment activities provide a basis for MVA planning and will ultimately support the selection of a site-specific injection strategy. Key permitting application documents have been developed for submission to British Columbia regulatory authorities. A poster and fact sheet have been developed to provide supporting materials for public outreach efforts. Future Future plans call for drilling an additional exploration well and collecting new 3-D seismic data. This will be followed by further refinement of the static model and new dynamic simulations, which will support the selection of a final injection strategy. Once a final injection strategy has been defined, the risk assessment will once again be updated, which will, in turn, be used to guide a specific MVA strategy. The updated MVA plan will include specific technologies, spatial locations of measurements, monitoring schedule, and baseline data necessary to address critical project risk and regulatory requirements and identify any deviations from expected conditions in a timely manner. Although specific techniques and procedures may change as the project proceeds, the project’s integrated philosophy of geologic characterization, modeling, and risk assessment will ensure that MVA strategies remain fit for purpose and cost-effective, with the greatest potential for success throughout the project’s lifetime. EERC JL41534.CDR 2045 2048 2030 2031 2025 EERC JL41528.CDR Sags (hydrothermal pipe remnants) Faults Slave Point B Pool Area Graben Sour CO2 Injection General Area Sulphur Point Structure Cl = 10 meters SECCS Milo Test Well C-61-E/94-J-10 Apache 3-D Available 2-D Only 3-D Survey Required 3-D Seismic Acquired EERC JS40108.CDR Observations • CO 2 Plume does not contact adjacent gas pools in 100 years • Plume migrates upwards to top Slave Point / Bottom of Muskwa/Fort Simpson shale Post-History Match – Simulation 25 years of injection + 75 years postinjection side view Model Observations • Sufficient storage capacity to accommodate target injection volumes for 25 years. • CO 2 plume does not contact the adjacent gas pools during the 100- year simulation period. • Good pressure dissipation in open reef system. • Injection pressure increase approximately equal to the before- production 1961 area pressure. Formations Pore Volume, m 3 Storage Mass* (E = 1.00%), tonnes Storage Mass* (E = 2.00%), tonnes Slave Point 4,340,000,000 18,000,000 36,000,000 Sulphur Point 2,920,000,000 12, I 00,000 24,200,000 Keg River 22,200,000,000 92,100,000 184,200,000 Summary 29,460,000,000 122,200,000 244,400,000 *A CO 2 density of 415 kg/m 3 was used to calculate the storage mass (average CO 2 density in the reservoir). Effective Storage Volume of the 2000-km 2 Study Area at the Fort Nelson CCS Site C A N A D A U N I T E D S T A T E S EERC CG41185.CDR J = 54 Permeability Distribution Vertical Exaggeration = x10 Sulphur Point Shelf Margin Dolomite U and L Slave Point Shelf Margin Dolomite Shoal or Ramp Dolomite L Keg River Upper Foreslope Dolomite Restricted Shelf Dolomite Deep Marine Shelf Limestone_Dolomite L Keg River Unstable Slope Limestone_Dolomite Restricted Shelf Platform Dolomite_Anhydrite Deep Shelf Limestone Otter Park Calcareous Shale Muskwa and U Keg River Shale_Limestone Sags Watt Mountain Silty Dolomite_Limestone Facies Sag Features Watt Mountain Breached (zero thickness) • Subregional model • 39 km x 67 km x 800 m thick • 13 Domains • Ten Formations Site Characterization Risk Assessment Design Modification Modeling and Simulation Monitoring, Verification, and Accounting P o s t c l o s u r e E N D S T A R T F e a s i b i l i t y S t u d y C l o s u r e I n j e c t i o n D e s i gn P h as e Fort Nelson Fort Nelson Gas Plant Exploratory Well Proposed CO 2 Injection Well Next Steps 1. Gather more data as required to improve reservoir characterization combined with reservoir sensitivity modeling – next RA report 2. MVA Technology Screening – Risk based and assessed (Bayesian Analysis Techniques) to optimize selection and confidence in risk management Injectivity Transfer Matrix E H&S F PA CI 1 2 3 4 5 1 2 3 4 5 2 3 4 5 5 Physical Consequences Strategic Consequences Injectivity Capacity Containment Others Environment Health Finance Public Corporate and Safety Acceptance Image 1 2 3 4 5 1 2 3 4 5 5 4 3 2 1 4 3 X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X 2 1 Severity (1–5) Frequency (1–5) The 31 risks identified have been grouped into four main categories: 1. Loss of injectivity (local pressure issues or geochemical reactions) 2. CO 2 migration and adverse pressure effects on existing production 3. Loss of containment – brine to groundwater via old wells 4. Lack of capacity – restriction by regulation 5 The risk management process used for managing the subsurface technical risks of the Fort Nelson CCS project, complies with International Organization for Standardization (ISO) 31000, an international standard for risk management. The risk management methodology integrated the ISO 31000 framework with existing Spectra Energy risk management processes, practices, and risk tolerance standards. The scope of the risk management work performed included all subsurface, technical risks resulting from the geologic storage of CO 2 . Gamma and lithology logs from existing exploratory, with marked sample locations from the Fort Simpson, Muskwa, Otter Park, Slave Point, Sulphur Point, and Keg River Formations. Acquired and available seismic survey locations within the Fort Nelson study area. Natural Resources Canada MVA Risk Modeling [1] [2] Characterization References [1] Gorecki, C.D., Liu, G., Bailey, T.B., Sorensen, J.A., Klapperich, R.J., Braunberger, J.R., Steadman, E.N., and Harju, J.A., The role of static and dynamic modeling in the Fort Nelson CCS Project: Paper 375 presented at the International Conference on Greenhouse Gas Technologies (GHGT-11), Kyoto, Japan, November 18–22, 2012, 8 p. [2] Gorecki, CD, Sorensen, JA, Klapperich, RJ, Botnen, LS, Steadman, EN, and Harju, JA. A risk-based monitoring plan for the Fort Nelson feasibility project. Paper CMTC 151349 presented at the 2012 Carbon Management Technology Conference, Orlando, Florida, USA, February 7–9, 2012, 14 p. Acknowledgment This material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FC26-05NT42592. A structure map of the top of the Sulphur Point Formation in the vicinity of the existing exploratory well. Core sample of the Muskwa formation collected from the exploratory well. The Muskwa Formation is a shale that will serve as a seal.
Transcript of Overview, Status, and Future of the Fort Nelson CCS …...Fort Nelson CCS Project James A. Sorensen,...
Overview, Status, and Future of the Fort Nelson CCS ProjectJames A. Sorensen, Charles D. Gorecki, Lisa A. Botnen, Edward A. Steadman, and John A. Harju
Energy & Environmental Research Center, University of North Dakota, Grand Forks, North Dakota
EERCEnergy & Environmental Research Center®
Putting Research into Practice
© 2012 University of North Dakota Energy & Environmental Research Center
Overview
GHGT-11 – 2012
The Plains CO2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center (EERC), and Spectra Energy Transmission (SET) are investigating the feasibility of a carbon capture and storage (CCS) project to mitigate carbon dioxide (CO2) emissions produced by SET’s Fort Nelson Gas Plant (FNGP). The FNGP is located near the town of Fort Nelson in northeastern British Columbia, Canada. The gas stream produced by the FNGP will include up to 5% hydrogen sulfide (H2S) and a small amount of methane (CH4) and, as such, is referred to as a “sour” CO2 stream. The sour CO2 gas stream would be injected into a deep saline carbonate formation.
The Fort Nelson demonstration project provides a unique opportunity to develop a set of cost-effective, risk-based monitoring, verification, and accounting (MVA) protocols for large-scale (>1 million metric tons a year) storage of sour CO2 in a deep saline formation. The role of the PCOR Partnership is to provide the project with reservoir modeling and simulation, risk assessment of subsurface technical risks, and an MVA plan to address these risks. The PCOR Partnership applies a philosophy that combines geologic characterization, modeling, risk assessment, and MVA strategies into an iterative process to produce superior-quality results during the project feasibility and development periods. Elements of any of these activities are crucial for understanding or developing the other activities (Gorecki and others, 2012).
StatusTo date, a variety of site characterization, modeling, risk assessment, MVA planning, regulatory permitting, and public outreach activities have been conducted. Collection of baseline data for shallow groundwater characteristics has been initiated. A comprehensive suite of existing well data, 2-D and 3-D seismic surveys, log analyses, and core testing results have been acquired and used to create static geologic models. The static geologic models have supported dynamic modeling, including history matching and the development of predictive simulations for selected injection scenarios. Results thus far suggest that the geology and hydrogeology in the vicinity of the FNGP are amenable to long-term geologic storage of CO2. The output from the characterization and modeling exercises has provided the basis for two iterations of a comprehensive risk assessment of the geologic risks associated with the Fort Nelson CCS project. The combined results of the characterization, modeling, and risk assessment activities provide a basis for MVA planning and will ultimately support the selection of a site-specific injection strategy. Key permitting application documents have been developed for submission to British Columbia regulatory authorities. A poster and fact sheet have been developed to provide supporting materials for public outreach efforts.
FutureFuture plans call for drilling an additional exploration well and collecting new 3-D seismic data. This will be followed by further refinement of the static model and new dynamic simulations, which will support the selection of a final injection strategy. Once a final injection strategy has been defined, the risk assessment will once again be updated, which will, in turn, be used to guide a specific MVA strategy. The updated MVA plan will include specific technologies, spatial locations of measurements, monitoring schedule, and baseline data necessary to address critical project risk and regulatory requirements and identify any deviations from expected conditions in a timely manner. Although specific techniques and procedures may change as the project proceeds, the project’s integrated philosophy of geologic characterization, modeling, and risk assessment will ensure that MVA strategies remain fit for purpose and cost-effective, with the greatest potential for success throughout the project’s lifetime.
EERC JL41534.CDR
20452048
20302031
2025
EERC JL41528.CDR
Sags(hydrothermal pipe remnants)
Faults
Slave Point BPool Area
Graben
Sour CO2 InjectionGeneral Area
Sulphur Point StructureCl = 10 meters
SECCS Milo Test WellC-61-E/94-J-10
Apache 3-DAvailable
2-D Only3-D Survey Required
3-D SeismicAcquired
EERC JS40108.CDR
Observations• CO2 Plume does not contact adjacent gas pools in 100 years• Plume migrates upwards to top Slave Point / Bottom of Muskwa/Fort Simpson shale
Post-History Match – Simulation25 years of injection + 75 years postinjection side view
Model Observations• Sufficient storage capacity to accommodate target injection
volumes for 25 years.
• CO2 plume does not contact the adjacent gas pools during the 100- year simulation period.
• Good pressure dissipation in open reef system.
• Injection pressure increase approximately equal to the before- production 1961 area pressure.
Formations Pore Volume, m3 Storage Mass* (E = 1.00%), tonnes
Storage Mass*(E = 2.00%), tonnes
Slave Point 4,340,000,000 18,000,000 36,000,000
Sulphur Point 2,920,000,000 12, I 00,000 24,200,000
Keg River 22,200,000,000 92,100,000 184,200,000
Summary 29,460,000,000 122,200,000 244,400,000
*A CO2 density of 415 kg/m3 was used to calculate the storage mass (average CO2 density in the reservoir).
Effective Storage Volume of the 2000-km2 Study Area at the Fort Nelson CCS Site
#*
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!.
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Shallow Ground Water Wells
0 105
km
C A N A D A
U N I T E D S T A T E S
PCOR Partnership
Region
EERC CG41185.CDR
J = 54Permeability Distribution
Vertical Exaggeration = x10
Sulphur Point Shelf Margin DolomiteU and L Slave Point Shelf Margin DolomiteShoal or Ramp DolomiteL Keg River Upper Foreslope DolomiteRestricted Shelf DolomiteDeep Marine Shelf Limestone_DolomiteL Keg River Unstable Slope Limestone_DolomiteRestricted Shelf Platform Dolomite_AnhydriteDeep Shelf LimestoneOtter Park Calcareous ShaleMuskwa and U Keg River Shale_LimestoneSagsWatt Mountain Silty Dolomite_Limestone
Facies Sag Features
Watt Mountain Breached(zero thickness)
• Subregional model• 39 km x 67 km x 800 m thick• 13 Domains• Ten Formations
Site Characterization
Risk Assessment
Design Modification
Modeling and Simulation
Monitoring, Verification, and
Accounting
P
ostc
losu
re
END START
Feasibility Study
Closure Injection
Desig
n Ph
ase
Fort Nelson
Fort Nelson Gas Plant
Exploratory Well
Proposed CO2 Injection Well
Next Steps
1. Gather more data as required to improve reservoir characterization combined with reservoir sensitivity modeling – next RA report
2. MVA Technology Screening – Risk based and assessed (Bayesian Analysis Techniques) to optimize selection and confidence in risk management
Injectivity Transfer MatrixE H&S F PA CI
12345
12345
23455
Physical Consequences Strategic ConsequencesInjectivity Capacity Containment Others Environment Health Finance Public Corporate
and Safety Acceptance Image
12345
12345
54321
4
3
X
X
XXX
X
X
X X
X
XXX
X
X
XXX
X XXX X
X X X
X
XXX
X
2
1
Severity (1–5)
Freq
uenc
y (1
–5)
The 31 risks identified have been grouped into four main categories:
1. Loss of injectivity (local pressure issues or geochemical reactions)
2. CO2 migration and adverse pressure effects on existing production
3. Loss of containment – brine to groundwater via old wells
4. Lack of capacity – restriction by regulation
5
The risk management process used for managing the subsurface technical risks of the Fort Nelson CCS project, complies with International Organization for Standardization (ISO) 31000, an international standard for risk management. The risk management methodology integrated the ISO 31000 framework with existing Spectra Energy risk management processes, practices, and risk tolerance standards. The scope of the risk management work performed included all subsurface, technical risks resulting from the geologic storage of CO2.
Gamma and lithology logs from existing exploratory, with marked sample locations from the Fort Simpson, Muskwa, Otter Park, Slave Point, Sulphur Point, and Keg River Formations.
Acquired and available seismic survey locations within the Fort Nelson study area.
Natural ResourcesCanada
MVA
Risk
Modeling
[1]
[2]
Characterization
References[1] Gorecki, C.D., Liu, G., Bailey, T.B., Sorensen, J.A., Klapperich,
R.J., Braunberger, J.R., Steadman, E.N., and Harju, J.A., The role of static and dynamic modeling in the Fort Nelson CCS Project: Paper 375 presented at the International Conference on Greenhouse Gas Technologies (GHGT-11), Kyoto, Japan, November 18–22, 2012, 8 p.
[2] Gorecki, CD, Sorensen, JA, Klapperich, RJ, Botnen, LS, Steadman, EN, and Harju, JA. A risk-based monitoring plan for the Fort Nelson feasibility project. Paper CMTC 151349 presented at the 2012 Carbon Management Technology Conference, Orlando, Florida, USA, February 7–9, 2012, 14 p.
AcknowledgmentThis material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FC26-05NT42592.
A structure map of the top of the Sulphur Point Formation in the vicinity of the existing exploratory well.
Core sample of the Muskwa formation collected from the exploratory well. The Muskwa Formation is a shale that will serve as a seal.
