Monitoring Verification & Accounting (MVA) 


We can help with a wide variety of tools and techniques that are available for monitoring CO2 stored in deep subsurface geologic storage sites, as well as conducting surveillance to assure that unlikely but potential release from storage is not occurring. 

We can develop comprehensive lifecycle MVA plans to deliver monitoring at all levels:





We can help with range of tools thought life cycle of the storage project

Primary Tools

Proven mature tools or applications are capable of providing the information required to meet permitting requirements under the U.S. EPA UIC program for classes I, II, and V injection wells and applicable and deployable in all settings (atmospheric, near surface, or deep subsurface, depending on the tool type and function) regardless of project location.

Secondary Tools

Available tools/protocols that can aid in accounting for injected CO2 and can provide insight into the behavior of CO2 by refining results obtained from primary tools. Secondary tools are typically more advanced and are complimentary to primary tools. However, they are typically not required to satisfy existing UIC (classes I, II, and VI) monitoring requirements

Potential Tools

Tools and protocols that are technologically advanced and may help answer fundamental questions concerning the behavior of CO2 in the subsurface and may prove useful as monitoring tools after further development and/or field testing.

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Sleipner CCS – CO2 plume in map view based on time-lapse seismic (Courtesy Equinor)


Optical CO2 Sensors (Handheld)

Description: Sensors for intermittent/continuous measurement of CO2 in air.
Benefits: Sensors can be relatively inexpensive and portable.
Challenges: Difficult to distinguish release from natural variations in ambient-CO2 emissions.

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Optical CO2 Sensors (LIDAR)

Light Detection & ranging (LIDAR).  LIDAR implies probing the atmosphere optically, and then gathering information based on the returned scattered signal.The advantage of LIDAR lasers is that one can have an on-line monitoring system that is non-intrusive, giving real-time profiles over a range of altitudes.

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Optical CO2 Sensors (CRDS)

Cavity ring-down spectroscopy (CRDS) is a direct quantitative absorption technique that utilizes an enhanced light-matter interaction length inside a high-finesse optical resonator for ultrasensitive trace gas monitoring with high-spatial and temporal resolutions.


Atmospheric Tracer Sampling

Natural and introduced tracers in the atmosphere can also

be used for monitoring of a possible CO2 release from 

geologic storage reservoirs.


Natural tracers are chemical compounds that are associated with CO2 in the subsurface, near-surface, or atmosphere. These include CH4, radon, noble gases, and isotopes of CO2.


Introduced tracers, such as sulfur hexafluoride (SF6) and perfluorocarbon tracer (PFT), are chemical compounds that may be injected into a geologic reservoir along with the CO2 in order to give the injected CO2 a unique fingerprint that can be recognized in aboveground emissions. 


Eddy Covariance Sampling

The EC technique (also known as eddy correlation and eddy flux) has become a popular tool for evaluating
net CO2 exchange from terrestrial ecosystems to the atmosphere, and in recent years, it has been tested for its potential ability to detect CO2 releases from underground storage reservoirs.


Instruments mounted on towers above the land surface are used to measure CO2 gas concentration, vertical wind speed, relative humidity,and temperature. Carbon dioxide flux is then calculated from these field measurements based on the covariance of CO2 concentration and instantaneous vertical wind velocity above or below their mean values. 




Pulsed Neutron Logs

PNTs have been proven useful tools for estimating CO2  saturation in the storage reservoir and shallower strata.  They can be run inside tubing (e.g., in an injection or production well) and is not very sensitive to well casing, although measurements can be altered by a change in salinity near the wellbore. They measurement can be conducted in time-lapse mode to record changes in reservoir fluids before, during, and after CO2 injection. 


Acoustic Logs

Sonic logs can be used to monitor changes in pore fluid composition as a CO2 plume moves past a wellbore because the velocity contrast between water and CO2 is strong. Sonic sources require large diameter wellbores and good coupling to the formations and so cannot be run through tubing. The casing must be properly cemented or the tube wave along the casing will overwhelm the signals of interest.

Induction Logging

Induction logging is a type of resistivity logging that uses EM induction principles to measure the conductivity of a formation. Induction logging is useful for CO2 monitoring applications because of the large resistivity contrast between CO2 and water.  The EM induction technique cannot be applied with conductive metal casing


Pulsed Neutron Logs

PNTs have been proven useful tools for estimating CO2  saturation in the storage reservoir and shallower strata.  They can be run inside tubing (e.g., in an injection or production well) and is not very sensitive to well casing, although measurements can be altered by a change in salinity near the wellbore. They measurement can be conducted in time-lapse mode to record changes in reservoir fluids before, during, and after CO2 injection. 

Cement Imaging Logs (Well Integrity)

Cement Imaging Tools: Cement imaging tools are used in cased-hole conditions to assess the quality of the cement bond between the borehole rock wall and the casing. Acoustic characteristics are the dominant measurement.

Oxygen-Activation Logs and Temperature Logs:

These tools are used to assess external mechanical integrity of the wellbore. Oxygen-activation logs are able to measure the direction and velocity of water movement around the casing. If water is detected moving upward outside of

the casing, this may signal a loss of external mechanical integrity.

Temperature Logs (for Casing Integrity)

Temperature logs can be used to identify fluid temperature fluctuations that may indicate a poorly sealed rock-casing annulus.

Temperature logs are based on the principle that fluid leaking from the well will cause a temperature anomaly adjacent to the wellbore. Fluid leaking from the well will usually be of a different temperature than the geothermal conditions at the location of the leak. This will cause the temperature of the formation in the vicinity of the leak to change (in most cases, a cooling effect is observed), resulting in a temperature anomaly

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 through casings or between the casing-rock annulus.


Wellbore Pressure Monitoring

Pressure is a key component in complying with the EPA UIC Class VI Requirement, both showing that injection pressure is less than the permitted maximum and that the area of pressure elevation is within the prepared and permitted AoR.


Pressure and temperature sensors located near the injection interval which reduce uncertainty. Wells are instrumented with pressure and temperature gauges in the wellhead or flow line that may be recorded by a technician or transmitted to a central location. 

The value of the pressure signal can be enhanced by changing injection rates and observing the response of the reservoir. Changes in pressure response can thus be indicative of loss of containment in the well or reservoir. Gauges open to zones above the injection zone may be useful for detecting CO2 release through the geologic seals. Downhole pressures and temperatures can also be used as inputs for history-matching simulation models to better predict the migration of injected CO2.

Distributed Temperature Sensing (DTS)

Temperature Sensor (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. DTS systems can operate at depths up to 15,000 meters and can incorporate distributed, point-acoustic, or pressure sensors 

Distributed Thermal Perturbation Sensing (DTPS)

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 .


An increase in CO2 saturation and a decrease in the brine saturation results in a decrease of the bulk thermal conductivity. DTPS measurements involve installation of an electrical heater with the DTS fiber-optic cables. The heater is energized for a set time period, providing a source of heat along the wellbore. Temperature decay curves after the heater is turned off are inverted to provide estimates of formation thermal conductivity, and thereby CO2 saturation.


Subsurface Sampling


EPA specifies periodic monitoring for geochemical changes above the confining zone(s) that may be a result of CO2 movement through the confining zones; the injection zone may also be a zone of interest.

Subsurface fluid sampling involves the collection of liquid or gas samples via wells that penetrate a geologic zone of interest.

In addition to migration detection, subsurface samples can provide information on CO2 arrival at a sample point (known as breakthrough) and geochemical changes taking place in the reservoir due to interaction of the CO2 with fluids and minerals.


Seismic monitoring strategies include

  1. Surface seismic (2D/3D) 

  2. Borehole seismic Crosswell & VSP)

  3. Passive seismic techniques


 1- Surface Seismic (2D/3D Seismic)


A seismic reflection survey (3-D survey) can be used for site characterization prior to injection and can serve as the baseline against which repeat surveys can provide time-lapse monitoring (4-D surveys). Changes in reflectivity between surveys can be interpreted as the result of the migration of a CO2 plume in the subsurface, and in some cases increase in pressure.

Two-dimensional seismic surveys have relatively low collection and processing costs, but the geometry of the area probed may be difficult to resolve. 

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 2-Borehole Seismic (VSP & Crosswell Seismic)

Borehole seismic techniques follow the same principles as surface seismic, but in borehole seismic surveys the receivers, sources, or both are placed in a well

2.1-Vertical Seismic Profile (VSP)

Time-lapse VSPs provide vertical resolution that allows detection of reservoir properties such as fluid saturation changes caused by injection or production activities relatively near the borehole containing the receivers .


Walk-away VSPs and array of receiver wells can be used to monitor the CO2 plume as it migrates away from the injection well.

2.2-Crosswell Seismic

Crosswell seismic is a borehole approach that uses a seismic source located in one well and a receiver array located in an adjacent well. The travel times for each source-receiver pair can be used to create a network of overlapping ray paths, and these are used to make a velocity map (or tomogram) between the wells

The image shows the difference in velocities from before and after CO2 injection. Lower velocity in warm colors. “There is a remarkable correlation between reflection event terminations and discontinuities in the tomogram difference”


2.3-Distributed Acoustic Sensing (DAS)

DAS is a relatively recent development in the use of fiber- optic cable for measurement of ground motion. Local changes in the optical backscatter, because of changes in the environment of the fiber, can thus become the basis for using the fiber as a continuous array of sensors with nearly continuous sampling in both space and time


3-Passive Seismic Monitoring

Passive seismic monitoring is a tool used to map seismic events (earthquakes) in the subsurface, and can be designed to detect events with energy too small to be felt at the surface, known as micro-seismicity.  


In geologic storage applications, microseismic monitoring is useful for evaluating the natural seismicity that may be present in a storage complex and for detecting potential induced seismicity resulting from injection.

Passive seismic monitoring (Pre-Injection)

Prior to injection can be used to establish a baseline of background seismicity. Pre-injection microseismicity monitoring should be coupled with collection of geomechanical properties of the reservoir and surrounding strata, and in-situ stress mapping (which relies on borehole breakout data, drilling-induced fractures, anisotropic

acoustic logging, and available focal mechanism solutions) to determine the state of reservoir stress prior to injection.

Passive seismic monitoring (during and post- injection)

Canbe used to detect and locate induced seismic events potentially resulting from CO2 injection. Induced seismic events may occur if fluid injected into the reservoir raises the pore pressure such that it exceeds the frictional resistance on faults or fractures and triggers slippage. Recording background and induced microseismic events can lead to

a better understanding of:

  1. Potential seismic risk in a CO2 injection site,

  2. Geomechanical properties of the reservoir, and

  3. More accurate mapping of the fluid pressure front representing the advance of the injected CO2 plume.

Passive seismic surveys are carried out using geophones installed in a wellbore, as isolation from surface noise such as wind and traffic is needed, and good coupling
is essential. These geophones are capable of detecting extremely small microseismic events (between -4 and -1 on the moment-magnitude scale). However, natural seismic attenuation in the crust limits the range of monitoring of such small events to several hundred meters from the detectors in most situations.



High-precision gravity measurements can be used to detect changes in density caused by CO2 injection into a storage reservoir. This is because CO2 is less dense than the formation fluid that it displaces in the reservoir. A change in the vertical gravity gradient may also indicate a change in reservoir pressure.


Time-lapse gravity surveys may be used to track the migration and distribution of CO2 in the subsurface, although the resolution of gravity surveys is much lower than that of seismic surveys. The resolution of a gravity survey can be improved if gravimeters are placed in a wellbore in close proximity to the reservoir of interest, and recent developments of instrumentation suitable for this deployment is substantive progress. Carbon dioxide detection thresholds are site-specific, but, as a general rule, deeper reservoirs are less suitable for gravity monitoring.

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Electrical methods can be used to detect the conductivity contrast between CO2 (less conductive) and saline water (more conductive) in a geologic formation. Specific electrical techniques that have been tested to monitor CO2 include electrical resistance tomography (ERT), EM tomography, and controlled-source electromagnetic (CSEM) surveys.


ERT and EM can provide a 3-D image of the resistivity distribution of the storage reservoir. In time-lapse mode, these techniques can be used to map the spatial extent of an undissolved CO2 plume in a saline reservoir to monitor changes in fluid saturation and to track plume migration.