MVA in CO2 Storage Project - Subsurface Monitoring & Lessons Learned
Monitoring, Verification and Accounting (MVA) plan is critical for ensuring safe and permanent storage of CO2 in all types of subsurface formations. MVA plans need to be flexible and site-specific to account for variability inherent in subsurface geologic formations.
This article provides overview of subsurface monitoring in CO2 storage in saline aquifer and CO2 / EOR projects. It highlights tools, techniques, regulatory requirements and lesson learned in subsurface CO2 monitoring. In future article we will address the near-surface and atmospheric monitoring for MVA planning.
A detailed subsurface reservoir characterization and monitoring plans is critical first step for the success of CO2 storage project. Key elements include; identification of key risks, potential controls and risk mitigation options to manage adverse consequence. The main objective of subsurface monitoring is the evolution of the CO2 plume, assessing area of elevated pressures caused by the injection for safe operation that meet regulatory requirements.
The operator of a Class VI well is required to perform specific subsurface monitoring activities.
A pressure fall-off test is to be performed at least once every five years.
Extent of the injected CO2 plume must be monitored
Presence of elevated pressure front by direct measurement in injection zone or indirect method (eg. seismic, electrical, gravity or electromagnetic survey)
Yearly, demonstration of mechanical integrity of well
Subsurface Monitoring Techniques
The subsurface MVA techniques may include single well or two or more wells. Collected data may be processed to image, 1-D (near well), 2D (image a plane or 3D (image volume). Subsurface techniques do not directly detect CO2; rather they detect change in some property.
1. Wireline Logging Tools:
Well-logging using wireline logs is a mature technology. Well logs can be open-hole i.e. carried before casing is installed or cased-hole , after casing is installed. Open-hole logs are used in reservoir characterizing before injection start-up. Tools discussed below are used for monitoring and quantifying during and after injection.
Pulsed Neutron Logs: Can be run in tubing and/or casing and are useful in quantifying CO2 saturation, to detect arrival of a CO2 plume or out-of-zone migration. They can be conducted in time-lapse mode to record/compare changes before/after. Changes in salinity can impact the measurements.
Lessons learned: PNT/tool provide the most quantitative data on CO2 saturation changes.
Acoustic/Sonic Logs: Can be run in casing and are useful to monitor changes in pore fluid composition as CO2 plume moves pass a wellbore. The log measures compressional & shear waves and transit times and can detect sharp velocity contrast between water and CO2. They cannot be run thru tubing and require well cemented casing.
Induction Logs: Can be used measure conductivity of formation due to large contrast between CO2 and water. Induction logs are based on Electromagnetic induction principles. The technique cannot be used in metal casing, and require use of fiberglass casing.
Lessons learned: Sonic/Induction logs successfully measured CO2 arrival in Nagaoka pilot in Japan
2. Wellbore Integrity Tools
Wellbore monitoring tools are designed to monitor well bore integrity
Cement Imaging Tool (CIT): CIT are used in cased-hole conditions to assess the quality of the cement bond between the borehole rock wall and the casing
Oxygen-Activation (OA) Logs and Temperature Logs: These tools are used to assess external mechanical integrity of the wellbore. OA logs are able to measure the direction and velocity of water movement around the casing suggesting poor cement bond.
Temperature logs: Are used to identify fluid temperature fluctuations that may indicate a poorly sealed rock-casing annulus.
Radioactive Tracer Survey: Radioactive tracers can be used to monitor well and casing performance during injection. A radioactive tracer is released within the casing, and the subsequent gamma ray response is measured through a series of detectors. Movement of the radioactive tracer indicates fluid movement and can reveal leaks
3. Wellbore Deployed Tools (Pressure & Temperature) :
Reservoir pressure:is a key parameter in EPA Class VI well program. Both temperature and pressure also affect CO2 fluid density and its super-critical state. The technology is mature and several gauges are available for temporary, intermittent and permanent deployment. They have advantage of providing direct measurement. Gauges must communicate with reservoir; inside casing gauges require perforation (risk), outside casing gauges are not retrievable.
Lessons learned: Continuous in-zone pressure measurements in a shut-in observation well open to the storage reservoir were collected in Cranfield CO2/EOR project.
Distributed Temperature Sensor (DTS) Systems: DTS systems can be used to measure temperature profiles along the length of a wellbore. DTSs are based on fiber-optic technology and have CO2 monitoring applications similar to those for temperature gauges.
Lessons learned: DTS was successfully tested in CO2 project in Ketzin, Germany
Distributed Thermal Perturbation Sensor: Distributed Thermal Perturbation Sensors (DTPSs) is a new method designed to estimate the CO2 saturation in the injection zone by measuring the thermal conductivity of the formation
4. Wellbore Fluid Monitoring Tools:
EPA’s UIC Class VI requires quantification of opposition of the injected fluid. Sampling can be done at injection well and at wells distant from injection wells to detect geochemical changes and CO2 plume front arrival. The also serve to model the response of the reservoir to CO2 injection.
Lessons learned: Long-term sampling has been successfully used in Cranfield project (EOR) in southern Mississippi, Ottway project, Australia and Weyburn project (EOR), Canada.
5. Seismic/Geophysical Techniques:
Measuring acoustic energy can help image the subsurface architecture and fluid distribution. Both Active seismic (Surface seismic, VSP, and cross-well seismic ) and Passive seismic techniques (natural subsurface/ fracture/fault development) can be used.
Surface seismic monitoring (time-lapse): of pre-injection and post-injection can help track CO2 Plume movement or out of zone detection. The advantage of seismic methods is that they cover large areas.
Lessons learned: Time-lapse surface 3D seismic was successfully used at Sleipner CO2 injection in aquifer.
Borehole seismic (cross-well, VSP): can provide higher resolution near wellbore and between well bores and are useful when injection volumes are small. They, however require a wellbore.
Lessons learned: VSP was used in Shell’s Quest project withDistributed Acoustic Sensing or DAS. Time-lapse cross-well survey was used in Citronelle project in Alabama to detect velocity differences over time
indicating increase in CO2
Passive seismic: also referred as microseismic monitoring is useful to detect natural seismic and induced seismic resulting from CO2 injection. It can map faults and fractures and track the fluid & plume front.
Lessons learned: Micro-seismicity associated with Co2 injection was measured at Illinois. Basin Decatur field project indicating increasing area of elevated pressures
6. Gravity Methods:
Gravity measurements has the advantage of direct measurement of massif CO2, unlike the other subsurface tool. The can monitor changes in fluid density resulting from CO2 injection. The technology is still developing.
Lessons learned: Small but detectable time-lapse response was observed in Cranfield project to CO2 injection using gravity methods. Seafloor gravity measurements were also used to constrain the extent of CO2 dissolution in the injection reservoir at Sleipner
7. Electrical Methods:
Electrical techniques like Electrical Resistance Tomography (ERT) and Electromagnetic Tomography (EMT) can provide resistivity contrast between injected CO2 and brine which can be used to estimate CO2 saturation distribution.
These techniques can be used in time-lapse mode to map the spatial extent of CO2 plume and to track plume migration in saline aquifer CO2 storage projects. They may not be useful in CO2/EOR as as they do not detect contrast between CO2 and hydrocarbon.
Lessons learned: Electrical techniques were tested at the CO2 sink project site in Ketzin, Germany, from 2007 to 2010 to monitor CO2 injection and plume migration. An experimental cross-well ERT system operated successfully for more than one year obtaining time-lapse electrical resistivity images during the injection in Cranfield project.