Well Integrity Atlas – Review of well integrity R&D needs in CO2 … · 2020. 10. 5. · Well...
Transcript of Well Integrity Atlas – Review of well integrity R&D needs in CO2 … · 2020. 10. 5. · Well...
Well Integrity Atlas – Well integrity R&D needs in CO2 storage/CO2-EOR projects
FEW0191 – Task 7
Jaisree Iyer, Megan Smith, Susan Carroll – LLNL
Greg Lackey, Andrew Bean, Bob Dilmore – NETL
Laura Edvardsen, Pierre Cerasi – SINTEF
U.S. Department of Energy
National Energy Technology LaboratoryCarbon storage project review meeting
2020 Integrated Review WebinarSeptember 8 - 11 2020
LLNL-PRES-814107
Define well integrity research needs based on input from
CO2 storage and CO2-EOR operators
https://www.fortmorgantimes.com/2017/08/01/county-leaders-seeking-input-on-oil-and-gas-injection-wells/
Well Integrity Survey for Site Operators
• Vetted by industry and DOE
• Divided in four sections• Background information
• Well integrity
• Monitoring
• Risk assessment
• Survey sent to 55 site operators• 29 in North America
• Received 22 responses• Responses are anonymous
Site description: Mostly onshore with responses from both CO2 storage and CO2-EOR operators
CO2-EOR (33 %)
CO2 storage in depleted reservoirs (10 %)
CO2 storage in saline aquifer (29%)
Other* (29 %)
Onshore (81 %)
Offshore (19 %)
*Included variants of the other three types of sites like storage in both saline and depleted oil and gas reservoir, acid gas injection in natural gas reservoir
Site type (21 sites) Site location (21 sites)
Comparison with literature survey showed a lack of responses from sites with CO2 storage in coal seams
CO2-EOR (40 %)
CO2 storage in depleted reservoirs (6 %)
CO2 storage in saline aquifer (32%)
Other* (22 %)
Onshore (90 %)
Offshore (10 %)
*Included 14 % of sites storing CO2 in coal seams with or without coal bed methane production
Site type (50 sites) Site location (50 sites)
Injection details: Responses spanning all scales for injection volumes, rates and times
< 1 year (14 %)
1 – 9 years (48 %)
> 9 years (38 %)
0.1 – 1 million tons (24 %)
< 0.1 million tons(43 %)
> 1 million tons (33 %)
Injection duration (21 sites) Injection volume (21 sites)
Literature survey skewed towards shorter and smaller projects
< 1 year (24 %)
1 – 9 years (54 %)
> 9 years (22 %)
0.1 – 1 million tons (18 %)
< 0.1 million tons(52 %)
> 1 million tons (30 %)
Injection duration (50 sites) Injection volume (50 sites)
Reservoir properties
Description Survey Literature
Reservoir depth* Mostly >1000 m deep (94%) Larger fraction of sites with lower depths (30 %)
Pre-injection reservoir pressure At or below hydrostatic (86 %) Larger fraction of overpressured sites (26 %)
Reservoir temperature Mostly below 100 °C (90 %) Larger fraction of high temperature sites (28 %)
Reservoir rock* Mostly sandstone (75 %) Mostly sandstone (60 %)
Caprock 60 % shale, 23 % evaporite Mostly shale and salt
*Sites with CO2 storage in coal seams were typically shallower and had a non-sandstone reservoir
Survey responses form a representative sample of CO2 storage and CO2-EOR operations
Coal bed CO2 storage is not well represented by our survey results
https://www.bizjournals.com/dallas/news/2016/08/22/comerica-oil-slump-not-as-big-of-a-drag-on-texas.html
Impact of well construction issues on well integrity
• No and low impact is the most common response
• For every well construction issue at least one respondent categorized its negative impact as major
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Cement pumping and displacement issues
Loss of circulation
Drillpipe failures
Casing deformation
Borehole Instability
Mud contamination in cemented annulus
Stuck pipe
Hole/trajectory deviation
Other
Survey responses (%)
no impact low medium major not applicable
• Literature review• Poor cementing is generally considered the primary well construction issue at CO2 storage sites
• No systematic study on the impact of well construction issues on well integrity
Adverse impact of operational issues
• No impact is the most common response
• Only “Exceeding caprock fracturing pressure” and “Hydrate formation” had a major negative impact
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Exceeding the caprock fracturing pressure
Hydrate formation
Wax/asphaltene issues
Pressure cycling
Injection of chemicals (other than water/CO2)
Sustained casing pressure, gas migration, or surface casing vent flow
Salt precipitation
Thermal cycling
Scale formation
Others
Survey responses (%)
no impact low medium major not applicable
Severity of operation issues based on literature survey
• Exceeding caprock fracturing pressure: Loss of site integrity• US EPA mandates that Class VI CO2 injection wells should not exceed fracturing pressure
• Sites potentially affected by this include:• Tubåen formation in the Snøhvit natural gas field
• InSalah
• Hydrate formation: Safety hazard• Can form rapidly and travel at high speeds that can result in extensive damage
• Prevention and risk mitigating measures are commonly implemented
• Sustained casing pressure (SCP), surface casing vent flow (SCVF), and gas migration: Well leakage issues• Frequency of these issues vary from region to region (2 - 30 %)
• Low levels of SCP and SCVF are manageable but high levels can lead to leakage outside the well system
10.1146/annurev-chembioeng-061010-114152
Severity of operation issues based on literature survey
• Asphaltene, wax, salt and scale precipitation: Well injectivity issues• CO2-EOR and CO2 storage sites have reported these problems
• Snøhvit, Midale, Ketzin, Aquistore
• Several preventative and remediation techniques are available
• Thermal cycling: Potential well integrity issues• No reported well integrity issues in the field due to thermal cycling
• Temperature variation due to frequent interruption in injection can degrade strength properties of wellbore materials
https://www.researchgate.net/publication/336208676_Salt_Precipitation_at_an_Active_CO2_Injection_Site
Material degradation
• Cement degradation• Cement porosity, permeability and mechanical properties are affected due to reaction with CO2
• Impact not adverse if original cement is competent
• Metal corrosion• Some field studies have reported extensive damage due to metal corrosion
• Corrosion rates dependent on variables like ion concentrations
• Rubber degradation• Not widely studied
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Cement
Well casing
Well tubing and packer
Survey responses (%)
no impact low medium major not applicable
Alternative wellbore materials
• Cement• Formulations substituting Portland cement with fly ash, silica
fume and other non-reactive material
• CO2-resistant cement not commonly used due to cost and
adequate performance of conventional cement formulations
• Casing and tubing• Carbon steel coated with plastic, epoxy, or glass reinforced epoxy
• Higher grades of carbon steel or corrosion resistant alloys are used when severe corrosion is expected
• Elastomers and seals• Swell resistant materials like hardened, Buta-N and nitrile rubber
• Teflon and nylon
Portland cement (80 %, 4 responses)
CO2-resistant cement (20 %, 1 response)
Steel (60 %, 3 responses)
Stainless steel (40 %, 2 responses)
R&D Recommendations
• Material degradation• Impact on hydraulic and mechanical properties of
cement
• Impact of different variables on corrosion rates
• New materials that can resist adverse impact of reactions with CO2
• Cost effectiveness in the context of the lifecycle of a well
• Techniques to remediate sustained casing pressure/surface casing vent flow• Applicability of methods in the presence of CO2
• Impact of thermal cycling on well integrity
• Relationship between well construction and well integrity
https://the-journal.com/articles/81784
Utility of monitoring methods to detect leakage outside the well
• Active seismic most useful
• Other geophysical techniques aren’t considered very useful• May be due to limited need for monitoring outside the well in traditional oil and gas operations
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Geophysical: active seismic
Water chemistry from groundwater wells
Pulsed neutron log
Soil gas flux sampling
Pressure from groundwater wells
Geophysical: electrical resistance tomography
Geophysical: magnetotellurics
Geophysical: gravity
Other
Survey responses (%)
critical useful not useful not applicable
Utility of monitoring methods to detect leakage inside the well
Almost all monitoring methods were considered useful more than 50% of the respondents
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Downhole pressure sensors
Wellhead pressure
Downhole temperature sensors
Packer isolation test
Mechanical integrity pressure test
Cement bond log
Wellhead temperature
Supervisory control and data acquisition
Ultrasonic imaging tool
Wellhead flowrate sensors
Multi-finger caliper
Cross well electrical resistance tomography
Sidewall coring tool
Other
Survey responses (%)
critical useful not useful not applicable
Cost effectiveness of monitoring methods
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Wellhead pressureWellhead temperature
Measure water chemistry from groundwater wellsWellhead flowrate sensors
Cement bond logPacker isolation test
Downhole pressure sensorsDownhole temperature sensors
Mechanical integrity pressure test of tubing and casingSupervisory control and data acquisition (SCADA) of well properties
Measure pressure from groundwater wellsPulsed neutron logMulti-finger caliper
Soil gas flux samplingUltrasonic imaging tool
Active seismicGravity
Electrical resistance tomographyCross well electrical resistance tomography
MagnetotelluricsSidewall coring tool
Other
Survey responses (%)
cost effective too expensive not applicable
R&D Recommendations
• Advancement of technology for outside well monitoring
• Reducing the cost of important monitoring techniques like active seismic • Finding cheaper alternatives
https://production-technology.org/cement
Risk assessment of legacy wells
• Cement location and well design, status, and type are considered critical
• Well orientation is considered less important• Published studies suggest well
orientation and age are also important
• Historical well records are considered most relevant for risk assessment• Published studies suggest that
subsurface conditions should also be considered
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Cement through reservoir & caprock fraction
Cement through reservoir & entire caprock
Well design
Cement through reservoir to surface
Well status: Abandoned
Cement over a fraction of reservoir
Well type: Storage
Well type: Disposal
Construction diagram availability
Mechanical integrity test availability
Age
Well log availability
Well type: Gas
Well status: Inactive/suspended
Well status: Active
Well type: Oil
Well orientation: deviated
Depth
Well orientation: vertical
Other
Survey responses (%)
not a risk factor potential risk factor risk factor critical risk factor not applicable
R&D Recommendations
• Methods to evaluate well integrity based on well attributes• Quantitatively converting well attributes to well risk
• Quantifying uncertainty when information is unavailable
• Risk assessment combining well attributes and reservoir performance
Concluding remarks
• Loss of well integrity are low frequency events
• Survey did not result in as many responses as we had hoped for
• Well integrity workshop to facilitate candid exchange of information between operators, researchers, regulators, etc.
Project overview
FY18-19$114k
FY19-20$112k
FY20-21$24k
2021$k
Generate survey for operators
Deploy survey for operators
Analyze the survey responses
Review literature
Summarize results into document describing well integrity research needs for CO2-storage sites
Solicit and incorporate expert feedback
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Chart Key
# TRL Score Milestone
Key Accomplishments/Deliverables Value Delivered
2019: Field based assessment of issues related to well integrity, monitoring and risk assessment of legacy wells at CO2 storage/CO2-EOR sites.
• Guiding document with R&D recommendations regarding well integrity in CO2 storage and CO2-EOR sites
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Impact
Acknowledgments
• Part of this work was performed under the auspices of the U.S. DOE by LLNL under contract DE-AC52-07NA27344 and NETL under Field Work Proposal Task 26. The work was funded by the Office of Fossil Energy, U.S. DOE
• Part of this work was performed by SINTEF with funding from NCCS
LLNL-PRES-814107