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



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



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


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


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


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


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

well integrity atlas – review of well integrity r&d needs in co2 … · 2020. 10. 5. · well...

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