Measurement, Monitoring And Verification Research Articles

Securing the Australian CCS project rollout by improving aspects of the GHG storage legislation: a discussion paper

The respective Federal petroleum and greenhouse-gas (GHG) storage legislation was examined in detail to understand the interactions between the technical requirements in the legislation, the overarching emissions-policy framework and the existing and likely future technical capabilities of the carbon capture and storage (CCS) industry. Key elements of the GHG legislation were then stress-tested using CCS project examples to determine applicability. The number of CCS projects required to meet the nation’s emission reduction targets over the next 5–25 years is high (probably between 20–40 projects of 4 million tonnes per annum (Mtpa)), but the existing 8–10 year approvals timeline provides only a maximum of 2.5 full project cycles to undertake 20–40 projects, a goal not considered possible without substantial regulatory reform. Opportunities for improvement should focus on facilitating a robust and rapid CCS project rollout and could include the following: changing the legislation to facilitate the accelerated utilisation of depleted petroleum fields to storage facilities, including allowing the progressive expansion of the awarded injection licence (IL); changing the concept of containment to emphasise carbon dioxide (CO2) plume management via assessing risk and potential impacts, not by artificial constraints into GHG permits and licences; including unitisation and combination pathways in the GHG legislation; ‘CO2 plume’ is not defined in legislation, even though the spatial location of a plume is central to numerous approvals, such as declaration of storage, demonstrating containment and all measurement, monitoring and verification (MMV) programs; developing a framework to manage future CCS project interactions at a basin scale, as is undertaken in groundwater management onshore.

Integration of subsurface dynamic coupled modelling and monitoring technologies for CCS: examples from existing projects


 Introduction
 Host rock injectivity and storage complex integrity (containment) for CO2 sequestration are critical factors to ensure that capacity targets are met while preventing CO2 leakage over time and confirm permanent storage.
 
 Figure 1 sketches the typical CO2 injectivity problem. Evaluating injectivity, capacity and containment requires assessing key phenomena such as: seal and faults capillary controls, non-isothermal reactive flow, geomechanical failure induced in the seal, along faults and/or fractures and in the vicinity of the wells. Additional analyses will also be needed to evaluate the completion integrity of the wells (injectors, monitoring and existing wells) under variable load conditions in terms of pressure, temperature and chemistry. The listed phenomena, and their likely effects, are analysed by means of dynamic coupled modelling, considering co-existing (geo)mechanical and dynamic flow simulations. Therefore, coupled modelling improves the risk analysis allowing to evaluate the Thermo-Hydro-Mechanical-Chemical (THMC) processes associated to CO2 injection.
 Analyses
 In this presentation we will provide some examples of integration of subsurface dynamic coupled modelling and monitoring technologies for CCS. Some of these examples are derived from existing projects.
 
 Injectivity impairment during CO2 injection is a well-known issue often observed at well and field scale (e.g. Snøhvit, Ketzin, Decatur projects [1], [2]). Loss of injectivity is governed by the interactions between CO2-brine phase behavior, CO2-solid phase (rock) behavior, salt precipitation, multi-phase flow. Characterizing zonal injectivity and developing mitigation strategies will be therefore important for project success. Figure 2 (left and center) shows an example of time-lapse CO2 saturation evolution during injection and consecutive non-isothermal processes associated to Joule-Thompson effect (H2O vaporization, cooling and induced salt precipitation due to dry-out). Temperature and pressure changes can lead to near wellbore failure (thermal and pressure induced fracturing) impacting injection performance due to near wellbore fracturing and consecutive permeability changes (Figure 2 right).
 To close the evaluation loop, the integrated subsurface characterization workflow is completed by measurements to image the subsurface before and after CO2 injection. This provides essential insights into the storage complex quality before injection and effective monitoring during injection and permanent storage, tracking the position of the CO2 pressure and concentration plumes, assessing surface heave, and detecting any risks or potential leakage paths. There is a tight link between subsurface dynamic coupled modelling and existing monitoring technologies. This link expands the well-known MMV (Measurement, Monitoring and Verification) process into a more integrated 3MV process (Modelling, Measurement, Monitoring and Verification), opening to the definition of a subsurface digital twin supporting successful CCS operations. We will briefly introduce methods and technologies enabling the subsurface dynamic modelling and monitoring of CO2 injection and storage. Seismic and borehole petrophysical and geophysical measurements for initial subsurface characterization and consecutive monitoring will be described.

Quest CCS facility: Time-lapse seismic campaigns

In August 2015, CO2 injection commenced at the Quest Carbon Capture and Storage (CCS) Facility located near Fort Saskatchewan, Alberta, Canada. Quest is a fully integrated CCS operation with a capture target of just over one million metric tonnes of CO2 per year. CO2 is injected into a deep saline aquifer, the Basal Cambrian Sandstone (BCS), at a depth of about two kilometers below ground.In order to demonstrate containment and conformance of the injected CO2, a Measurement, Monitoring and Verification (MMV) plan has been implemented. Multiple domains are monitored as part of the plan, including the atmosphere, biosphere, hydrosphere, geosphere, and wells. Time-lapse seismic methods are utilized primarily for conformance monitoring and secondarily for containment monitoring of the CO2 plume within the Geosphere domain. These methods currently include 3D surface seismic (SEIS3D), 2D surface seismic (SEIS2D) and 2D multi-azimuth walk-away borehole vertical seismic profiles with distributed acoustic sensing (VSP2D).The first goal of this paper is to summarize the role of seismic, subsurface modeling efforts and the different baseline and monitor datasets that have been acquired at the Quest CCS Facility. The second goal is to describe the current Quest time-lapse strategy. Five key seismic acquisition campaigns have occurred at Quest through the pre- and post-start of injection periods, including an initial SEIS3D acquisition, a pre-injection baseline VSP2D acquisition, and three monitor VSP2D acquisitions. SEIS2D acquisitions have also been acquired as part of two of the most recent monitor campaigns. All campaigns have occurred over the winter season, to facilitate surface access, minimize impact on the land and farming/harvest activities, and to ensure maximum repeatability. Time-lapse seismic methods yield an image of the CO2 that is injected into the BCS pore space, displacing some of the brine in the saline aquifer. Since the injected CO2 is more compressible and less dense than brine, the velocity of seismic primary-waves traveling through the BCS is reduced in those places containing CO2 and remain unchanged elsewhere.Petrophysical data from the injection wells (IWs) were used to calculate the acoustic properties of the BCS. Gassmann fluid substitution was used to model the effect of CO2 saturation on the expected seismic response. Modeling showed that differences in the seismic images of the BCS obtained before and during CO2 injection should be seen in two characteristics ways:1) Travel-times across the BCS increase due to the slower primary-wave velocity inside the BCS.2) Reflections from the base of the BCS become stronger as the impedance contrast with the underlying granite basement increases. The contrast between the BCS and underlying basement is much larger than between the BCS and the overlying sediments. The large contrast between the BCS and basement produces a prominent reflection which is easily mapped during baseline and monitor surveys and is more practical for amplitude extractions.Modeling also indicated that, while the acoustic changes are sufficient to define the CO2 front qualitatively, it is unlikely that they can be used to quantify the distribution of CO2 saturations within the plume.The initial time-lapse seismic strategy called for SEIS3D to be employed after a few years of injection. Borehole distributed acoustic sensing (DAS) VSPs were proposed as a cost-effective and flexible alternative to SEIS3D while injection volumes are small. With the optical fiber cemented in place behind the casing, data can be acquired at any time without suspending injection, something not achievable with conventional VSPs that use retrievable downhole geophone arrays. The effectiveness of VSPs is inherently dependent upon the injection volume, plume offset from the IWs and acquisition geometry. After evaluating the concentric plumes predicted from dynamic modeling results and considering the acquisition logistics at the Quest CCS well sites, a VSP2D program was executed.In 2017 and 2019, SEIS2D was recorded in addition to the VSP2D surveys. Surface geophones were deployed along the VSP2D shot locations, recording a pseudo-3D or cross-spread survey. SEIS2D will be evaluated as another seismic method to potentially monitor CO2 plume development in the BCS.

Carbon capture and storage (CCS)

Carbon Capture and Storage (CCS) is an important tool for the decarbonization of the energy system to achieve the mid-century global climate change targets. CO2 is captured using different industrial processes that involve membrane filtering or enhanced combustion. The CO2 is then transported, preferably by pipeline, to a storage site where it is injected into a permeable reservoir. Sealing capacity of the storage site is of paramount importance for safe CO2 sequestration, to avoid any geological leakage. Each CCS project must have a dedicated MMV (Measurement, Monitoring and Verification) programme to ensure conformance with the expected evolution of the CO2 plume and its containment within the storage site. Eni is committed to the implementation of CCS, with several ongoing projects.

Seismic velocity characterisation and survey design to assess CO2 injection performance at Kızıldere geothermal field

The noncondensable gases in most geothermal resources include CO2 and smaller amounts of other gases. Currently, the worldwide geothermal power is a small sector within the energy industry, and CO2 emissions related to the utilisation of geothermal resources are consequently small. In some countries, however, such as Turkey and Iceland, geothermal energy production contributes significantly to their energy budget, and their CO2 emissions are relatively significant. SUCCEED is a targeted innovation and research project, which aims to investigate the reinjection of CO2 produced at geothermal power production sites and develop, test, and demonstrate at field scale innovative measurement, monitoring and verification (MMV) technologies that can be used in most CO2 geological storage projects. The project is carried out at two operating geothermal energy production sites, the Kızıldere geothermal field in Turkey and the CarbFix project site at the Hellishei?i geothermal field in Iceland. Together with a brief description of the project, this paper presents the details of the two field sites and the progress made in seismic velocity characterisation and modelling relevant to the Kızıldere geothermal field in Turkey.

SUCCEED: A CO2 storage and utilisation project aimed at mitigating against greenhouse gas emissions from geothermal power production

The non-condensable gases in most geothermal resources include CO2 and smaller amounts of other gases. Currently, the worldwide geothermal power is a small sector within the energy industry, and CO2 emissions related to the utilisation of geothermal resources are consequently small. In some countries, however, geothermal energy production contributes significantly to their energy budget and their CO2 emissions are relatively significant. SUCCEED is a targeted innovation and research project which aims to investigate the reinjection of CO2 produced at geothermal power production sites and develop, test and demonstrate at field scale innovative measurement, monitoring and verification (MMV) technologies that can be used in most CO2 geological storage projects. The project is carried out at two operating geothermal energy production sites, the Kizildere geothermal field in Turkey and the CarbFix project site at the Hellisheiði geothermal field. Together with a brief description of the seismic monitoring technologies proposed in the project, this paper presents the details of the two field sites and the progress made in installing and testing of the surface fibre-optic cables at the Hellisheiði geothermal field in Iceland.

Quest CCS Facility: Microseismic System Monitoring and Observations

In August 2015, CO2 injection commenced at the Quest Carbon Capture and Storage (CCS) Facility located near Fort Saskatchewan, Alberta, Canada. Quest is a fully integrated CCS facility with a capture target of just over one million metric tonnes of CO2 per year. CO2 is injected into a deep saline aquifer, the Basal Cambrian Sandstone (BCS), at a depth of about two kilometers below ground. In order to demonstrate containment and conformance of the injected CO2, a Measurement, Monitoring and Verification (MMV) plan has been implemented. Although Quest is in an extremely quiet tectonic location, induced seismicity has been recognized as a potential risk for all large-scale injection sites. As a result, microseismic monitoring is a key component of the Quest MMV Plan to ensure the continued assessment of that risk and to provide early notice of any changes. The aim of this presentation is to detail why we monitor for microseismic activity and how we do this efficiently using proactive technical monitoring (PTM) and exception based surveillance (EBS), to report on six years of microseismic monitoring observations through the pre- and post-start of injection periods and to describe the empirical analysis that has allowed the Quest CCS Facility to de-risk microseismicity as an active threat to containment. Microseismic data is continuously recorded at the Quest CCS storage site using a commercial downhole geophone array installed in a deep monitoring well (DMW). The data are processed to produce trigger files using a common algorithm for event detection and triggering, based on the ratio of short-time-average to long-time-average (STA/LTA) amplitudes. The triggered events are analyzed, classified and reported daily. Categories for various trigger types are defined based on the characteristics of each event. Operationally, the status of the microseismic array is continually assessed by the presence of trigger events. A trigger event is defined to be locatable when it shows clear primary (P) and secondary (S) wave field arrivals. The locatable events are processed and located using an anisotropic velocity model. The p-wave velocities were derived from a vertical seismic profile survey, and the s-wave velocities were obtained from sonic well logs. Pre-CO2 injection recording of microseismic data began in November 2014. Most of the trigger files generated were related to surface, automatic and noise triggers. These events were used to assess the health of the system. No locatable events were detected during the pre-injection monitoring phase. The first locatable event was recorded 10 months after start of CO2 injection in July 2016 with a magnitude of -1.3. Since January 2017, sustained low level, small magnitude microseismic activity have been located within the Quest microseismic area of review (AOR) within the Precambrian basement. The AOR as defined in the 2017 Quest MMV plan, extends 10 km radially outwards from each active injection well (IW). As of December 31st, 2020, 486 locatable events have been detected, with an average magnitude of -0.7, a maximum magnitude of 0.8 and a typical occurrence rate of 1-2 events per week. Using the current methodology, all locatable events have been located within the Precambrian basement, below the injection zone. None of this microseismic activity has represented a risk to containment.

Modelling the DAS Response for Offshore CO2 Storage Sites

Using fiber-optic cables as distributed sensors to monitor the subsurface is one of the fastest growing acquisition technologies in the hydrocarbon energy sector. Since the first exploration and production downhole field trial of a Distributed Acoustic Sensing (DAS) system for seismic monitoring in 2009, the technology has boomed. It has already proven to be an effective tool for acquiring vertical seismic profiles (VSP), performing passive interferometric measurements, and monitoring of microseismic earthquakes. DAS cables record seismo-acoustic wavefields and ground motions because ground-motion-induced changes in strain on the fiber affect the phase of back-scattered light in the fiber. Commercially available systems already provide sub-meter spatial resolution in sensing fibers up to 50 km in length with a frequency response up to several kHz. This exceeds the frequency range and spatial coverage of conventional seismic sensors. As a result, surface and borehole monitoring with DAS in addition to traditional sensors will most likely form a central component of future Measurement, Monitoring and Verification (MMV) systems for CO2 storage. DAS, however, does possess some key disadvantages in that it only provides a single component measurement which is most sensitive to motions in line with the fiber. DAS also measures linear strain rather than particle motion, meaning the recorded signals are not directly comparable to conventional sensors. In order to better understand the response of DAS it is therefore necessary to understand the seismic source, path, site and instrument effects. The ACT DIGIMON project aims to develop and demonstrate an affordable, flexible and societally embedded Digital Monitoring early-warning system, for monitoring CO2 storage sites. Within the DIGIMON concept fiber-optic monitoring will form a key component, therefore a thorough understanding of the response of DAS systems, including the transfer function, is a fundamental issue to be addressed. In this paper we present our modeling approach for the DAS response for a fictive CO2 storage site. The workflow exploits geometrical models of different complexity which in the end are representative of North Sea geology. Using ray tracing techniques and the seismic waveform modelling packages: SW4 and SPECFEM3D, we were able to analyze and compare these modeling approaches in relation to the response of a DAS system. With varying model complexity, we accurately capture and analyze the DAS response for realistic cable geometries. These geometries represent both vertical and horizontal deployments, which replicate fiber placed in wells and deployed on the seabed and or in shallow trenches.

Integration of wellbore pressure measurement and groundwater quality monitoring to enhance detectability of brine and CO2 leakage

Leakage detectability is a key consideration in evaluating the effectiveness of a measurement, monitoring and verification (MMV) plan for a geologic carbon storage (GCS) project. While studies have shown that surface-based, geophysical monitoring methods may be sensitive enough to detect CO2 leakage, these methods are an indirect indicator of leakage. A drawback to relying on direct geochemical monitoring is that by the time a significant leak is confirmed, it may be too late to mitigate or remediate the environmental impacts. In this study, we combine information from geophysical and geochemical monitoring methods to provide an integrated diagnosis of leakage events. The detectability for various monitoring parameters (pH, TDS, alkalinity, Ca, Cl, Na, and pressure) collected from monitoring wells are evaluated by leakage detection probability, using simulated wellbore-leakage/plume-migration events and monitoring scenarios for a hypothetical GCS operation at the Kimberlina site in California, USA. The NUFT code is used to model these events, by coupling wellbore-leakage simulations to 3-dimensional reactive, multi-phase, flow and transport simulations of brine and CO2 leakage-plume migration in aquifers overlying the GCS reservoir. Wellbore leakage in legacy wells located 1.4, 3.4 and 6.8 km from the CO2 injector is evaluated for a range of (1) wellbore bottom-hole pressure and CO2 saturation determined by GCS simulations, (2) regional groundwater gradient in the aquifers, and (3) wellbore permeability. Simulated leakage-induced changes in seven monitoring parameters at different depths are used to calculate the corresponding detection probabilities, based on the background distribution data and selected monitoring-technology detection thresholds. The responses for these monitoring parameters are tested and combined to enhance the overall detectability. The results indicate the leakage signals are more easily detected at shallower depths where buoyant CO2 has migrated and flashed from supercritical to gas phase, causing a large increase in CO2 volume. While the results suggest pH monitoring is more responsive to the simulated leakage events than TDS monitoring at shallower depths, TDS changes may be more readily observed at greater depths. The addition of carbonate alkalinity can confirm CO2 leakage detection and help distinguish CO2 leakage from other contamination sources. Direct pressure change measurements are very sensitive to leakage, but the rapid and broad propagation of the pressure response hinders using such measurements to easily locate the origin of leakage. Combining measurements could greatly improve the confidence of leakage diagnosis. High bottom-hole CO2 saturation, such as that for a leaky well close to the injector (˜1.4 km), high regional groundwater gradient, and high wellbore permeabilities all increase the leakage plume size, and thus the leakage detectability. Our analysis suggests pressure monitoring is a valuable indicator of leakage events at early stages, while pH, TDS and carbonate alkalinity monitoring can directly diagnose leakage impacts by providing more detailed information in the groundwater receptor. Finally, an example Bayesian belief network model is presented for evaluating the effect of risk reduction options in terms of joint monitoring detection probability using the associated simulation scenarios. This framework is demonstrated to inform how pressure and groundwater quality information can be integrated into site MMV and risk management plans.

Integration of Wellbore Pressure Measurement and Groundwater Quality Monitoring to Enhance Detectability of Brine and CO2 Leakage

Abstract Leakage detectability is a key consideration in evaluating the effectiveness of a measurement, monitoring and verification (MMV) plan for a geologic carbon storage (GCS) project. While studies have shown that surface-based, geophysical monitoring methods may be sensitive enough to detect CO2 leakage, these methods are an indirect indicator of leakage. A drawback to relying on direct geochemical monitoring is that by the time a significant leak is confirmed, it may be too late to mitigate or remediate the environmental impacts. In this study, we combine information from geophysical and geochemical monitoring methods to provide an integrated diagnosis of leakage events. The detectability for various monitoring parameters (pH, TDS, alkalinity, Ca, Cl, Na, and pressure) collected from monitoring wells are evaluated by leakage detection probability, using simulated wellbore-leakage/plume-migration events and monitoring scenarios for a hypothetical GCS operation at the Kimberlina site in California, USA. The NUFT code is used to model these events, by coupling wellbore-leakage simulations to 3-dimensional reactive, multi-phase, flow and transport simulations of brine and CO2 leakage-plume migration in aquifers overlying the GCS reservoir. Wellbore leakage in legacy wells located 1.4, 3.4 and 6.8 km from the CO2 injector is evaluated for a range of (1) wellbore bottom-hole pressure and CO2 saturation determined by GCS simulations, (2) regional groundwater gradient in the aquifers, and (3) wellbore permeability. Simulated leakage-induced changes in seven monitoring parameters at different depths are used to calculate the corresponding detection probabilities, based on the background distribution data and selected monitoring-technology detection thresholds. The responses for these monitoring parameters are tested and combined to enhance the overall detectability. The results indicate the leakage signals are more easily detected at shallower depths where buoyant CO2 has migrated and flashed from supercritical to gas phase, causing a large increase in CO2 volume. While the results suggest pH monitoring is more responsive to the simulated leakage events than TDS monitoring at shallower depths, TDS changes may be more readily observed at greater depths. The addition of carbonate alkalinity can confirm CO2 leakage detection and help distinguish CO2 leakage from other contamination sources. Direct pressure change measurements are very sensitive to leakage, but the rapid and broad propagation of the pressure response hinders using such measurements to easily locate the origin of leakage. Combining measurements could greatly improve the confidence of leakage diagnosis. High bottom-hole CO2 saturation, such as that for a leaky well close to the injector (˜1.4 km), high regional groundwater gradient, and high wellbore permeabilities all increase the leakage plume size, and thus the leakage detectability. Our analysis suggests pressure monitoring is a valuable indicator of leakage events at early stages, while pH, TDS and carbonate alkalinity monitoring can directly diagnose leakage impacts by providing more detailed information in the groundwater receptor. Finally, an example Bayesian belief network model is presented for evaluating the effect of risk reduction options in terms of joint monitoring detection probability using the associated simulation scenarios. This framework is demonstrated to inform how pressure and groundwater quality information can be integrated into site MMV and risk management plans.

Monitoring the Complete Life-cycle of a CO2 Storage Reservoir – Demonstration of Applicability of Geoelectrical Imaging

In this paper, the applicability of deep downhole geoelectrical monitoring for detecting CO2 related signatures is evaluated after a nearly ten year period of CO2 storage at the Ketzin pilot site. Deep downhole electrode arrays have been studied as part of a multi-physical monitoring concept at four CO2 pilot test sites worldwide so far. For these sites, it was considered important to implement the geoelectrical method into the measurement program of tracking the CO2 plume. Analyzing the example of the Ketzin site, it can be seen that during all phases of the CO2 storage reservoir development the resistivity measurements and their corresponding tomographic interpretation contribute in a beneficial manner to the measurement, monitoring and verification (MMV) protocol. The most important impact of a permanent electrode array is its potential as tool for estimating reservoir saturations.

Assessment of CO2 Levels Prior to Injection Across the Quest Sequestration Lease Area

The Quest Carbon Capture and Storage (CCS) project in Alberta, Canada, is a fully integrated project, as it involves the capture, transport, injection, storage of CO2, and a measurement, monitoring and verification (MMV) program. The MMV program has two key objectives: a) to ensure containment and b) to ensure conformance. Prior to the start of CO2 injection at the end of August 2015, a number of projects were undertaken to gather data from various domains, namely the atmosphere, biosphere, hydrosphere and geosphere, to provide input to the Quest MMV program. The focus of this paper is on monitoring activities undertaken in relation to the atmosphere and biosphere domains. Activities undertaken across the Quest sequestration lease area (SLA) included an eddy covariance system, soil gas probes, soil flux chambers, and walk-over surveys. In conclusion, understanding the spatial and temporal variability of CO2 levels prior to start of CO2 injection represents an important activity of a CCS MMV program. It provides technical input to the development of such a program, but also provides knowledge for communication to and awareness of project stakeholders (e.g. landowners) regarding CO2 levels within the atmosphere and biosphere across a SLA.

A risk-based framework for Measurement, Monitoring and Verification (MMV) of the Goldeneye storage complex for the Peterhead CCS project, UK

CO2 emissions from the Peterhead CCS gas power plant were planned to be captured, compressed and transported offshore to be injected at a rate of 1 million tons per year for up to 20 years into the depleted Goldeneye hydrocarbon gas field. Although site selection, characterization and engineering designs are considered the prime means of ensuring confidence in the long-term security of CO2 storage, demonstration that they are performing is provided by a comprehensive risk-based Measurement, Monitoring and Verification (MMV) program. The Goldeneye MMV program was designed according to a systematic site-specific storage containment risk assessment to (1) demonstrate containment, (2) monitor for conformance, (3) provide data for emission accounting, and (4) support storage transfer of long-term liabilities. The MMV design process identified a set of appropriate monitoring tasks and candidate monitoring technologies needed to perform them based on comprehensive site-specific feasibility studies. This procedure reduced forty-five candidate monitoring technologies by half to result in a fit-for-purpose monitoring plan that satisfied UK and EU regulations while using less than fifteen different containment and environmental monitoring techniques.

A risk-based framework for measurement, monitoring and verification of the Quest CCS Project, Alberta, Canada

The Quest Carbon Capture and Storage Project will make an early contribution to reducing CO2 emissions generated by upgrading bitumen from the Alberta oil sands by injecting up to 1.08milliontonnes of CO2 per year for 25 years into a deep saline aquifer located north-east of Edmonton, Alberta. Regulatory approvals and societal acceptance for this project are contingent on gaining and maintaining confidence in the safety and long-term security of the storage site. Site selection, characterisation and engineering designs are the prime means of ensuring CO2 storage risks are as low as reasonably practicable. As a further precaution, a comprehensive programme of Measurement, Monitoring and Verification (MMV) will evaluate storage performance.The purpose of MMV is to monitor conformance and containment. Conformance monitoring is designed to track the build-up of pressure and CO2 inside the storage complex to demonstrate the long-term security of storage. Containment monitoring is designed to demonstrate containment and, if necessary, to trigger timely control measures to mitigate any unexpected leak pathways and to protect the environment. To achieve this, the MMV programme is designed according to a systematic site-specific risk assessment, diversified to avoid dependence on single technologies and will be adapted through time according to observed performance.

Jingbian CCS Project, China: Second Year of Injection, Measurement, Monitoring and Verification

Abstract Jingbian CCS-EOR pilot project is the first full chain CCS-EOR project in China. Sponsored by China Ministry of Science and Technology, Shaanxi Yanchang Petroleum (Group) Co. Ltd started to conduct CO2 capture from its coal chemical company and injected CO2 in Jingbian Field which cooperated with Northwest University from 2012. Our target is to inject at least 10,000 tons CO2 in Jingbian Field of Shaanxi Yanchang Petroleum (Group) Co. Ltd. At the same time, we are developing an integrated MMV (Measurement, Monitoring and Verification) technique to monitor the safety of CO2 sequestration from surface to subsurface by using environmental, geophysical monitoring methods and geological analysis. At this low porosity and low permeability reservoir of Jingbian Field, we planned to inject CO2 in more than 5 wells and tried to get enhanced oil recovery ratio about 5% to 8% and form CO2-EOR techniques and a demonstration pilot project so that we may apply CCS-EOR in Ordos Basin which is the largest oil and gas production basement in China. Jingbian CCS-EOR pilot project is the same as the other CCS projects in the world. It includes site selection, CO2 storage and injection equipment construction, CO2 capture equipment construction, CO2-EOR laboratory tests and MMV study.

Investigation of Natural Tracers for MMV at the Quest Carbon Capture and Storage Project, Alberta, Canada

Abstract In 2015, CO 2 injection will start at the Quest Carbon Capture and Storage (CCS) Project in Alberta, Canada. The Quest Carbon Capture and Storage (CCS) project is a joint venture between Shell Canada Energy, Chevron Canada Limited, and Marathon Oil Canada Corporation, and is operated by Shell. The CO 2 is captured from the Scotford oil sands bitumen upgrader, located northeast of Edmonton. Up to 1 Mt of CO 2 per year will be injected into the Basal Cambrian Sandstone (BCS), a saline aquifer located at a depth of about 2 km below ground surface, over a potential time period of 25 years. In order to demonstrate containment and conformance of the injected CO 2 , implementation of a Measurement, Monitoring and Verification (MMV) plan is essential. A number of technologies can be used within a MMV plan, such as geophysical or geochemical techniques. The latter may include chemical and/or isotopic fingerprinting of specific fluid end-members, such as the BCS brine. The aim of this paper is to provide an overview of the work that has been undertaken to assess the use of natural tracers for MMV purposes at the QUEST CCS project. The two key objectives are to a) review chemical and isotopic compositions of the BCS brine compared to overlying aquifer waters, and b) to assess the suitability of the natural abundance C and O isotopic compositions of injected CO 2 as a tracer.

The Laboratory Simulation and Field Verification of Seasonal Soil-respired CO2 flux at a Proposed CCS Project Site

As part of any terrestrial Carbon Capture and Storage (CCS) project, a risk-driven Measurement Monitoring and Verification (MMV) plan may include the measurement of soil gas and related surface CO2 efflux in order to determine the natural (or baseline) concentration range and variation of CO2. Subsequent measurements of these parameters may then act as a measure of stored CO2 containment and conformance during operational, closure and post-closure phases. There are several practical challenges involved in the collection of representative soil-respired CO2 efflux measurements. These include (i) the assessment of natural baseline variations of soil-respired CO2 efflux across potentially large areas expected for commercial CCS operations, (ii) even if field measurements of soil- respired CO2 are recorded over one season or several seasonal cycles, the full concentration and CO2 flux range may not be captured due to reliance upon environmental (i.e. climate) conditions prevalent during field surveys, and (iii) when field based soil CO2 flux measurements are taken, climatic and environmental conditions are likely to change throughout the day, resulting in a number of dislocated flux measurements taken under different conditions. Ideally, it would be useful to be able to carry out an initial field survey measurements, collect soil samples at a project site and develop a simulated baseline in the laboratory under controlled conditions, reducing the seasonal baseline survey duration from one or two years down to several weeks of simulation supported by field verification. Soil cores and bulk material from each soil horizon at selected locations were sampled from the previously proposed Heartland Area Redwater Project (HARP) near Edmonton, Alberta. Soil columns were reconstituted in the laboratory and subjected to a range of temperature and moisture conditions similar to those expected for the CCS project area over a seasonal cycle. Efflux data were directly compared to field-based measurements collected over a 12 month period under a range of climatic conditions. Comparisons between laboratory simulations and field data suggest a strong temperature-efflux correlation consistent with many studies related to the carbon cycle and ecosystem productivity. It is suggested that the simulation of environmental conditions using soils from a CCS area of review may be a useful tool for the prediction of the range of CO2 efflux expected as a function of soil characteristics and environmental conditions, thereby accelerating baseline studies, establishing the range of CO2 efflux to guide monitoring strategies and for the facilitation and validation of remote sensing data in support of large scale CCS site characterization.