Distributed Strain Sensing Rayleigh Frequency Shift (DSS-RFS) provides measurement of multiple physical phenomena along an entire internal borehole, allowing for geologic carbon sequestration and monitoring conditions of the near-wellbore region and outside of pipe subsurface rock formations, supporting verification and accounting of geologic carbon sequestration projects.
JIM MCMAHON, Neubrex Energy Services
Geologic carbon capture storage (CCS), or geologic sequestration (GS), is an emerging technology to permanently store or sequester separated and captured anthropogenic CO2 from industrial sources into deep geologic formations. Some large-scale anthropogenic CO2 sources include coal-fired or gas-fired power plants, oil and gas refineries, steel mills and cement plants.
Operators typically compress CO2, to convert it from a gaseous state to a supercritical fluid state, where it exists at high pressure, exhibiting properties of both a liquid and a gas. The CO2 is transported in gaseous form to Class VI well GS injection site super-areas, where cryogenic cooling converts it to a supercritical phase prior to injection. It is then injected into rock formations to depths greater than 800 m (2,645 ft), for the purpose of maximizing capacity and storage.
When injected into an appropriate receiving formation, CO2 is sequestered by a combination of trapping mechanisms, including physical and geochemical processes. Physical trapping occurs when the relatively buoyant CO2 rises in the formation until it reaches a stratigraphic zone with low permeability that inhibits further upward migration. Physical trapping can also occur, as residual CO2 is immobilized in formation pore spaces as disconnected droplets or bubbles at the trailing edge of the plume, due to capillary forces.
A portion of the CO2 will dissolve from the pure fluid phase into native groundwater and hydrocarbons. Geochemical trapping occurs when chemical reactions between the dissolved CO2 and minerals in the formation lead to the precipitation of solid carbonate minerals. The timeframe over which CO2 will be trapped by these mechanisms depends on properties of the receiving formation and the injected CO2 stream.
Due to the relative buoyancy of CO2, its mobility within subsurface geologic formations, its corrosivity in the presence of water and the potential presence of impurities in the captured CO2 stream, the EPA has determined that existing Underground Injection Control (UIC) regulations for Class VI wells are necessary to manage the unique nature of CO2 injection for GS. A critical component of these regulations encompasses monitoring, reporting and verification (MRV).
MONITORING, REPORTING AND VERIFICATION
Monitoring, reporting and verification associated with GS injection projects is an important component of the UIC program. MRV data can be used to verify that the injectate is safely confined in the target formation, minimize costs, maintain the efficiency of the storage operation, and confirm that injection zone pressure changes follow predictions. The EPA’s established MRV requirements for GS projects are designed to prevent CO2 movement into Underground Source of Drinking Waters (USDWs) by addressing the potential pathways through which injected CO2 fluids can migrate into USDWs and cause endangerment to human water usage supplies.
These mandates address the following:
Site characterization, with an assessment of the geologic, hydrogeologic, geochemical and geomechanical properties of the proposed GS site, to ensure that wells are located in suitable formations;
Well construction, using materials that can withstand contact with CO2 over the life of the GS project;
Computational modeling that accounts for the physical and chemical properties of the injected CO2, based on available site characterization, monitoring and operational data;
Periodic re-evaluation to incorporate monitoring and operational data and verify that the CO2 plume and the associated area of elevated pressure are moving, as predicted, within the subsurface.
GS sites are required to develop and implement a site-specific MRV plan which, once approved by EPA, would be used to verify the amount of CO2 sequestered and to quantify emissions, if injected CO2 leaks to the surface. The GS reports must include information to outline how monitoring will achieve surface detection and quantification of CO2, and the amount (flowrate) of injected CO2 for the mass balance equation that will be used to quantify the amount of CO2 sequestered by a facility.
Robust oversight must be maintained for the CO2 stream, injection pressures, integrity of the injection well, groundwater quality and geochemistry, as well as monitoring of the CO2 plume and position of the pressure front throughout injection. Additionally, comprehensive post-injection monitoring following cessation of injection is required to show the position of the CO2 plume and the associated area of elevated pressure to demonstrate that neither poses an endangerment to USDWs.
WELL-BASED MONITORING TECHNOLOGIES FOR GEOLOGIC CARBON STORAGE
Various geophysical techniques have been used to monitor subsurface CO2 plumes in geologic carbon storage and provide crucial information to mitigate potential leakage risks. The EPA recognizes that monitoring and testing technologies used at GS sites will vary and be project-specific, influenced by both geologic conditions and project characteristics.
Geodetic monitoring—including global positioning system (GPS) monitoring, and Interferometric Synthetic Aperture Radar (InSAR)—involves measuring displacements and strains, both on the surface and within the interior of the Earth. Space-based InSAR is a geodetic technique for remote monitoring of land-based storage sites.
CO2 injection may cause the Earth’s surface to deform, and geodetic monitoring is an approach to monitor reservoir integrity and detect possible CO2 leakage. The technique involves repeated measurement of the deformation of Earth’s surface.
Subsurface micro-seismic monitoring. Seismic monitoring can use active seismic surveys or micro-seismic events induced by CO2 injection and migration. Micro-seismic monitoring uses sensors/geophones, which are deployed on the surface covering the monitoring region. Another application is deploying sensors/geophones in one or more boreholes, to monitor induced micro-seismic events that are smaller than what surface seismic arrays can detect.
Active seismic monitoring uses time-lapse seismic reflection/transmission data. The underlining physical principle of this method is based on the effects of supercritical carbon dioxide on subsurface elastic parameters. CO2 injection and migration alter elastic parameters, such as density, compressional and shear velocities, and seismic attenuations in geologic formations.
Time-lapse 3D or 4D seismic monitoring is considered an effective tool for 3D subsurface monitoring of CO2 injection and migration. However, timelapse 3D seismic surveys and data processing are costly and time-consuming.
Gravity monitoring. CO2 storage sites cause subsurface mass redistribution. Lower-density CO2 displaces higher density brine, which results in reduction of bulk formation density. Time-lapse gravity monitoring is sensitive to the bulk density changes. Gravity sensors can be deployed on the ground surface or in a borehole.
Because a CO2 storage reservoir is often located at a large depth, and spatial resolution of gravity monitoring decreases with depth, there are limited applications where gravity monitoring can be applied.
Electrical Resistivity Tomography (ERT). The injection of carbon dioxide results in increased resistivity, which may be detected by electrical and electro-magnetic (EM) imaging techniques, such as electrical resistivity tomography, magnetometric resistivity and complex resistivity. With downhole electrodes close to the target of interest, ERT can characterize the temporal and spatial resistivity changes effectively.
Geochemical sampling. Geochemical sampling is used to assess CO2 rock-water interaction, to better understand the ultimate fate of emplaced CO2 and assess the integrity of reservoir seals.
Numerous methods have been devised to obtain representative downhole samples while maintaining reservoir pressure conditions.
DISTRIBUTED FIBER OPTIC MULTI-FUNCTION SENSORS
More recent CO2 sequestration projects have implemented significantly more sophisticated strings of multi-function deployed sensors, aimed at increasing the amount and quality of information available from boreholes. This is to more fully understand the movement and distribution of CO2.
The deployment of fully distributed fiber optic sensors into deep wells to monitor acoustic vibrations, mechanical strain, reservoir temperature and reservoir pressure distribution—in support of oil and gas downhole applications and CO2 injection—has advanced considerably over the last decade.
Distributed fiber optic sensing (DFOS) is a technology that enables continuous, real-time measurements along the entire length of a fiber optic cable at very fine spatial intervals. Unlike conventional sensor systems that rely on discrete sensors measuring at pre-determined points, distributed sensing does not rely upon manufactured, discrete sensors. In contrast, it utilizes the optical fiber itself as both the sensing device and as the two-way transmitter of the signal (light). The optical fiber is the sensing element, without any additional transducers in the optical path.
Surface instruments, called interrogator units (IU), send a series of laser light pulses into the fiber and record the return of the naturally occurring, back-scattered light signal as a function of time. In doing this, the distributed sensing system measures at all points along the fiber, which are at a pre-determined clock-time interval, over periods of well operational time.
Because a fiber optic cable can be installed in harsh environments for long periods of time, the technology shows promise for environmental monitoring of sensitive subsurface operations.
Many geofluid systems, including GS, require dynamic acoustic, temperature, strain and pressure monitoring at great pressure, depth and temperature. Sensing systems that employ downhole fiber optic cables serve particularly well for long-term well monitoring and well-integrity monitoring.
Distributed fiber optic sensing provides the critical capability of measuring multiple physical phenomena along the entire length of an internal borehole, as well as monitoring the conditions of the near-wellbore region, outside of pipe subsurface rock formations, supporting verification and accounting of geologic carbon sequestration projects.
DFOS technologies that support GS include:
Distributed Acoustic Sensing (DAS)
Distributed Temperature Sensing (DTS)
Distributed Pressure Sensing (DPS)
Distributed Temperature Strain Sensing (DTSS)
Distributed Strain Sensing Rayleigh Frequency Shift (DSS-RFS)
Distributed Acoustic Sensing (DAS). DAS is mainly used to listen to hydraulic fracturing-related signals, listen to fluid and gas flow signals or sense seismic source response, such as in a Vertical Seismic Profile (VSP). DAS senses the changes in very small physical acoustic vibrations along a glass fiber optic strand that is encased in a cable to measure vibrations. There are thousands of detection points along the fiber in the subsurface fiber optic cable.
DAS technology permits tens of thousands of points down the well to be measured simultaneously every 2 m. The continuous glass fiber strand inside the cable can sense very small acoustic vibrations at a large range of frequencies. These vibrations are most often related to injected fracturing fluid dynamics and fracture propagation, and growth associated with hydraulic fracturing physics. These measurements are very valuable to engineers who use the data to sense what is occurring deep in a well, where they cannot see.
Distributed Temperature Sensing (DTS). DTS measures temperatures by means of optical fibers functioning as linear sensors. Temperatures are recorded along the optical sensor cable, not at points, but as a continuous profile. A high accuracy of temperature determination is achieved over great distances compared to other methodologies. Typically, DTS systems can locate the temperature to a spatial resolution of 1 m, with accuracy to within ±1° C.
Distributed Pressure Sensing (DPS). The measurement of pressure by using distributed optical fiber sensors has represented a challenge for many years. While single-point optical fiber pressure sensors have reached a solid level of technological maturity—showing to be very good candidates in replacing conventional electrical sensors—distributed sensors are still a matter of intense research activity, aimed at determining the most proper and robust pressure-sensitivity enhancement mechanism.
Distributed Temperature and Strain Sensing (DTSS). DTSS technology augments DPS and DAS. The combination of all of these sub-surface measurements produces simultaneous and independent measurements that inform engineers and scientists about the distribution of physical changes in, or near, the external wellbore environment, at centimeter-order to meter-order spatial resolution.
DTSS provides not only temperature, but also the absolute, differential and dynamic strain deformation profiles along the full length of optical fiber, over distances reaching up to tens of kilometers. In addition, the spatial resolution of the DTSS measurements is typically an order of magnitude better than DAS. Spatial resolution is a measurement to determine how small an object should be for an imaging system to detect it. It is measured in line pairs per centimeter (lp/cm).
DISTRIBUTED STRAIN SENSING RAYLEIGH FREQUENCY SHIFT (DSS-RFS)
As good as DAS, DTS, DPS and DTSS technologies are, the increasing demand for monitoring geofluid systems, like geologic sequestration, has encouraged further development of specialized technologies capable of very high sensitivity and reliability, along with the mechanical robustness suitable for harsh operational environments. One of these more recently developed technologies, Distributed Strain Sensing Rayleigh Frequency Shift (DSS-RFS), represents a significant breakthrough for geologic sequestration MRV. It leverages significant advancements in hydrocarbon production operations and has clear crossover applications to GS applications.
As the latest generation of fiber optic sensing systems employed to monitor deep well conditions, DSS-RFS is a truly transformative technology for augmenting operational performance in GS. Providing critical data about the downhole well environment from distributed fiber optic sensing, DSS-RFS improves the ability of engineers and scientists to more efficiently and effectively understand strain and temperature dynamics of the subsurface and support engineering operational, monitoring, reporting and verification activities and goals that support GS.
DSS-RFS uses Rayleigh Wavelength, optically sourced backscatter in a non-engineered single mode silica (glass) fiber, to measure strain and temperature changes along the fiber. Advanced through research, development and field application by Neubrex Ltd., Kobe, Japan, distributed fiber optic-based strain and temperature sensing measurements are made, based on the frequency shift of the Rayleigh optical scattering spectrum, which is linearly dependent on strain and temperature changes applied to the sensing fiber. Strain changes along the wellbore are measured continuously at fine spatial scale during operations of the GS well.
The principle of the DSS-RFS method can be explained accordingly: when an optical fiber is manufactured, random inhomogeneities of the glass density are created in the fiber core. The random density heterogeneities manifest as a variation of refractive index along the fiber. For a certain laser frequency, the constructive and destructive interferences between the Rayleigh backscatters cause irregular but unique amplitude fluctuations in the coherent optical time-domain reflectometer along the fiber length. For each discrete fiber segment, a unique Rayleigh scattering spectrum (like a fingerprint) is obtained by scanning the fiber with a coherent optical time-domain reflectometer with a range of laser frequencies, using a tunable-wavelength laser system. This unique Rayleigh scattering spectrum shifts in frequency space, if the temperature and/or mechanical strain on the fiber section changes, which causes the spacing and optical delay to vary between the scatterers. This change is detectable and measurable with Neubrex technology.
DSS-RFS technology permits tens of thousands of points down a fiber that is attached to a tubing string or casing string to be measured very quickly every 20 cm along the entire fiber length deployed in or along the wellbore. The continuous glass fiber strand inside the cable can sense very small physical length changes at a large range of frequencies. These measurements of thermally or mechanically driven strain change, as a function of time and depth, are valuable to engineers, who use the data to gain an understanding of what is occurring deep down in the well. No other technology provides such insight.
Changes in temperature (degrees), strain (micro-strain unit), acoustics (dB, noise) and pressure (psi) can be made in real time, while CO2 injection is occurring. This helps field engineers understand what is happening in these deep wells much better than with previous discrete sensor-position technologies. Data-driven changes or adjustments to operational plans or maintenance plans can then be made when warranted, to optimize the GS operation and make wells with better long-term sequestration performance, efficiency and efficacy.
DSS-RFS is employed in application by Neubrex Energy Services, the U.S. division of Neubrex Ltd. The company's DTSS product line is known as Neubrescope®. It is actively deployed in North America in different operational settings, such as oil and gas, CCS and geothermal operations.
“Neubrescope DSS-RFS is well-designed for monitoring geologic sequestration operations," said Dana Jurick, executive vice president and general manager of Neubrex Energy Services. "Nevertheless, companies involved in GS are still in the learning, testing qualification and acceptance phase of using fiber optics and how they can be reliably, safely and economically installed, and used in a well and long-term well operations.”
“Once installed in a well, operators are learning what measurements can be made, and how it differs from competing technologies,” added Jurick. “The value proposition of this technology application is actively being explored by many GS companies, both domestically in the U.S. and internationally in numerous CCS projects."
TECHNOLOGY SUPPORT FOR GS SITES
Progress towards commercial-scale geologic sequestration is resulting in the rapid adoption of existing and new tools and technologies for monitoring CO2 storage in the subsurface.
Primary among these technologies is the latest evolution in distributed fiber optic sensing, which provides the critical capability of measuring multiple physical phenomena along the entire length of an internal borehole, supporting verification and accounting of geologic carbon sequestration projects. WO
JIM MCMAHON writes on industrial, manufacturing and technology issues. His features have appeared in more than 4,000 business and trade publications worldwide.