Wellbore Leakage Research Articles

Laboratory evaluation of distributed coaxial cable temperature sensors for application in CO2 sequestration well characterization

AbstractDownhole monitoring plays a crucial part in a geological carbon dioxide (CO2) sequestration project, especially in providing early warnings of failure. However, most downhole monitoring technologies are often low in spatial resolution and time‐consuming, or expensive and have system longevity issues. To address this issue, a robust and cost‐effective distributed coaxial cable Fabry‐Perot interferometer‐based temperature sensor is proposed for real‐time downhole monitoring. The coaxial cable sensor (CCS) was made in house and tested using a high pressure high temperature (HPHT) testing apparatus to study the sensor accuracy, sensitivity, stability, and crosstalk effect in simulated downhole conditions. The laboratory test results indicate that the sensor can work under simulated downhole conditions of pressures up to 1000 psia and temperatures up to 110°C. At 1 ATM, the sensor has an accuracy of about 1%. At 1000 psia, the hysteresis phenomenon is observed, but it is reduced and tends to stabilize after repeated heating and cooling treatments. The pressure crosstalk effect was observed on the flexible cable sensor and minimized on the rigid cable sensor. The temperature and pressure range of the distributed CCS allows long‐term in situ monitoring for a well depth up to 2500 feet, which would prove of great value in detecting temperature change associated with wellbore leakage that may lead to groundwater contamination. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd

Progress in monitoring strategies for risk reduction in geologic CO2 storage

Commercial, demonstration and pilot geologic CO2 storage (GCS) projects have provided a wealth of practical experience in monitoring technologies. In this manuscript we review a few key projects, specific geophysical methods, well-based methods, geophysical workflows and some suggested best practices. These practices are often driven and governed by regulatory requirements (e.g. U.S. Environmental Protection Agency [US-EPA] Class VI underground injection regulation) and the need for effective reservoir management of pressures and volumes as well as the site-specific risks to containment, plume migration, and underground sources of drinking water. Reducing uncertainty in monitoring is likely to lead to reducing uncertainty in risk. One of our conclusions is the need for field experiment testing that is risk-driven. It is notable that GCS pilot projects have been designed for safe storage, and to date they have been successful. Technical challenges at all geologic CO2 storage sites include assuring injectivity and capacity predictions are reliable, the fate and subsurface topology of the CO2 plume is acceptable, regulatory permitting and compliance are accomplished in a timely manner, needed business assurances are supported by quantitative technical data, and the storage operation is acceptable to stakeholders. There is risk associated with all of these challenges necessitating a monitoring program utilizing both direct and indirect monitoring methods. Geophysical monitoring is viewed as a key component in approaching risk assessment because of the direct association of risk and monitoring in GCS. In this review we provide a framework for monitoring and then present some specific monitoring tools that may be useful for regulatory compliance, as well as technologies that are applicable to leakage detection. Since the Department of Energy National Risk Assessment Program (DOE NRAP) is focused on quantitative risk assessment, we focus on quantitative geophysical monitoring. Important concepts for a successful integration of monitoring and risk assessment include the following: Characterization of key parameters of risk and methods to monitor those parameters, the feedback between risk and monitoring, and the development of risk-based strategies to assess and update monitoring plans and tools. We briefly review current work in assessing uncertainty in important monitoring technologies, such as seismic and electrical geophysical surveys, and acknowledge that there is both temporal and spatial uncertainty in monitoring, in addition to the measurement uncertainty of specific tools. In our opinion monitoring approaches for subsurface imaging, such as 3D-reflection seismic, 3D-Vertical Seismic Profiling (VSP), cross well seismic, electromagnetic and electrical technologies, and well-log based measurements produce proxies for saturation and mass that, when properly calibrated and interpreted, are robust quantitative estimates of these key storage parameters. Understanding the uncertainty in these proxies is important in risk-driven monitoring. The cost of high-potential geophysical monitoring technologies impacts application of these methods to quantitative risk assessments. We therefore examine the concept of value of information (VOI) that is expected to play a role in selection of monitoring tools. We also conclude that monitoring of leakage scenarios has had minimal field validation and thus quantifying and reducing risk will require dedicated experiments that probe and test uncertainty in fault/fracture-zone and wellbore leakage.

Quantifying the benefit of wellbore leakage potential estimates for prioritizing long-term MVA well sampling at a CO2 storage site.

This work uses probabilistic methods to simulate a hypothetical geologic CO2 storage site in a depleted oil and gas field, where the large number of legacy wells would make it cost-prohibitive to sample all wells for all measurements as part of the postinjection site care. Deep well leakage potential scores were assigned to the wells using a random subsample of 100 wells from a detailed study of 826 legacy wells that penetrate the basal Cambrian formation on the U.S. side of the U.S./Canadian border. Analytical solutions and Monte Carlo simulations were used to quantify the statistical power of selecting a leaking well. Power curves were developed as a function of (1) the number of leaking wells within the Area of Review; (2) the sampling design (random or judgmental, choosing first the wells with the highest deep leakage potential scores); (3) the number of wells included in the monitoring sampling plan; and (4) the relationship between a well’s leakage potential score and its relative probability of leakage. Cases where the deep well leakage potential scores are fully or partially informative of the relative leakage probability are compared to a noninformative base case in which leakage is equiprobable across all wells in the Area of Review. The results show that accurate prior knowledge about the probability of well leakage adds measurable value to the ability to detect a leaking well during the monitoring program, and that the loss in detection ability due to imperfect knowledge of the leakage probability can be quantified. This work underscores the importance of a data-driven, risk-based monitoring program that incorporates uncertainty quantification into long-term monitoring sampling plans at geologic CO2 storage sites.

A response surface model to predict CO2 and brine leakage along cemented wellbores

Potential CO2 and brine leakage from geologic sequestration reservoirs must be quantified on a site-specific basis to predict the long-term effectiveness of geologic storage. The primary goals of this study are to develop and validate reduced-order models (ROMs) to estimate wellbore leakage rates of CO2 and brine from storage reservoirs to the surface or into overlying aquifers, and to understand how the leakage profile evolves as a function of wellbore properties and the state of the CO2 plume. A multiphase reservoir simulator is used to perform Monte Carlo simulations of CO2 and water flow along wellbores across a wide range of relevant parameters including wellbore permeability, wellbore depth, reservoir pressure and saturation. The leakage rates are used to produce validated response surfaces that can be sampled to estimate wellbore flow. Minima in flow rates seen in the response surface are shown to result from complex nonlinear phase behavior along the wellbore. Presence of a shallow aquifer can increase CO2 leakage compared to cases that only allow CO2 flow directly to the land surface. The response surfaces are converted into computationally efficient ROMs and the utility of the ROMs is demonstrated by incorporation into a system-level risk analysis tool.

Experimental calibration of a numerical model describing the alteration of cement/caprock interfaces by carbonated brine

Deep wells provide a possible pathway for CO2 and brine leakage from geologic storage reservoirs to shallow groundwater resources and the atmosphere. The integrity of wellbore cement in these environments is of particular concern, because it is not known if changes in cement properties resulting from reaction with CO2-rich brines will lead to enhanced leakage over the life cycle of the storage reservoir. Assessment of wellbore leakage will ultimately be answered through models that capture both the chemical and physical processes and the uncertainty of key parameters within the wellbore environment. Towards this end, we use the results for 13 core–flood experiments conducted at variable partial pressures of CO2, flow rate, durations, and cement–caprock apertures to constrain a wellbore model that couples chemical processes important to assessing the long-term integrity of wellbore cements in geologic carbon storage environments. X-ray computed microtomography collected prior-to and following the experiments was employed to spatially resolve the interface and the extent of the reaction zones, and time dependent solution chemistry was used to track the chemical alteration over the course of the experiments.In this manuscript we focus on the development of geochemical model that describes the alteration of both the cement and the caprock. In our experiments, chemical alteration of the cement significantly exceeded any dissolution of carbonate minerals within the caprock and fracture geometry played no role on the extent of reaction. The experimental data was used to calibrate a numerical model of wellbore-caprock interfaces coupling reaction-front chemistry, fluid flow and transport of dissolved species. The geochemical model adopts an idealized representation of the cement chemistry in which appropriate equilibrium conditions are enforced at a series of discrete reaction fronts. The equilibrium conditions are coupled by diffusive transport between the fronts, which also determines the rate of front propagation. Despite its simplicity, the calibrated model accurately reproduces the reaction-zone growth and effluent chemistry for the range of experimental conditions considered and allowed key parameters to be confirmed or calibrated. These include the use of portlandite, calcite, and analcime solubility as equilibrium controls at specific reaction fronts within the cement; the use of constant effective diffusivity for each alteration zone; and diffusive growth of the alteration layers.

Effect of Dynamic Loading on Wellbore Leakage for the Wabamun Area CO2-Sequestration Project

Summary The most viable options for permanent removal of carbon dioxide (CO2) from the atmosphere include large-scale injection of CO2 from stationary sources, such as coal-fired power plants and heavy-oil production, into brine-filled formations. One of the main risks identified with storing CO2 in the subsurface is the potential for leakage through existing wells penetrating the caprock. The wellbore system has several components that can fail and create leakage pathways, including type and placement of wellbore casing and cements, completion method, abandonment, and wellbore expansion or contraction by changes in temperature and pressure. Of the 1,000 wells in the study area near Wabamun Lake, Alberta, 95 wells penetrated the immediate caprock above the proposed Nisku injection formation and were identified as potential leakage pathways. The leakage risk of these wells was evaluated on the basis of knowledge of the well design, current well status, and historical regulations in the area. Only four wells, for the subset of 27 wells studied, were identified as requiring workover, which was less of a problem than anticipated. To evaluate the risk of creating leakage pathways by thermal and pressure changes caused by CO2 injection, a 3D finite-element model was built by use of poroelastoplastic material models for cement and formation. Multistage simulations for casing/cement and cement/ formation interactions with temperature-enabled elements were conducted. A parametric study of cement properties was conducted to investigate cement design and its mechanical properties for injection wells. The simulation results indicated that thermal cooling might reduce near-wellbore stresses, which would increase the risk of integrity loss in casing/cement and cement/formation. The parametric study revealed that the risk of debonding and tensile failure would increase with increasing Young’s modulus and Poisson’s ratio of the cement under dynamic-loading conditions. In addition, low mechanical cement strength would increase the risk of shear failure in the cement.

Reduced Order Models for Prediction of Groundwater Quality Impacts from CO2 and Brine Leakage

Abstract A careful assessment of the risk associated with geologic CO2 storage is critical to the deployment of large-scale storage projects. A potential risk is the deterioration of groundwater quality caused by the leakage of CO2 and brine leakage from deep subsurface reservoirs. In probabilistic risk assessment studies, numerical modeling is the primary tool employed to assess risk. However, the application of traditional numerical models to fully evaluate the impact of CO2 leakage on groundwater can be computationally complex, demanding large processing times and resources, and involving large uncertainties. As an alternative, reduced order models (ROMs) can be used as highly efficient surrogates for the complex process-based numerical models. In this study, we represent the complex hydrogeological and geochemical conditions in a heterogeneous aquifer and subsequent risk by developing and using two separate ROMs. The first ROM is derived from a model that accounts for the heterogeneous flow and transport conditions in the presence of complex leakage functions for CO2 and brine. The second ROM is obtained from models that feature similar, but simplified flow and transport conditions, and allow for a more complex representation of all relevant geochemical reactions. To quantify possible impacts to groundwater aquifers, the basic risk metric is taken as the aquifer volume in which the water quality of the aquifer may be affected by an underlying CO2 storage project. The integration of the two ROMs provides an estimate of the impacted aquifer volume taking into account uncertainties in flow, transport and chemical conditions. These two ROMs can be linked in a comprehensive system level model for quantitative risk assessment of the deep storage reservoir, wellbore leakage, and shallow aquifer impacts to assess the collective risk of CO2 storage projects.

Well Integrity Assessment of a 68 year old Well at a CO2 Injection Project

Abstract As part of the United States Department of Energy (DOE) National Energy Technology Laboratory (NETL) sponsored project, The Quantification of Wellbore Leakage Risk Using Non-destructive Borehole Logging Techniques, the construction and integrity of a 68 year old well was studied. This study builds upon previous work examining the integrity of existing wells through shale formations. The objective of this study was to measure well integrity through potential caprocks and aid in understanding the potential leakage risk posed by old wells that intersect CO2 injection projects. The well was originally completed as a production well in the Gulf Coast region in 1945 and then plugged and abandoned in 1969. The well was re-entered and re-completed as an observation well for a CO2 injection project in 2008. It was replugged and abandoned after completing its observation role in 2013. For this study the well was logged using cement bond log and ultrasonic mapping tools, tested and sampled using a dynamic tester, and cored using a sidewall coring tool. The age of this well makes it the oldest well to be studied in this manner and this is the first well to be studied this way in the region. The results of the study indicate that much of the material behind the casing is unconsolidated cement. Logging results in many places in the well show poor isolation potential and indicate a microannulus. The logs also indicate removal of material during hydraulic testing which was confirmed by laboratory analysis. Of the six cores collected, four consisted of unconsolidated, soft, cement or rock, one consisted of heavily altered cement, and one consisted of slightly altered cement. The results of study are an interesting contrast to earlier field studies because they show an old well that lacked integrity at most of the test and sample points. However, the logging and a core sample in the squeezed zone indicate that there was zonal isolation between the injection and monitoring zones. The logging and mapping data along with the analysis of the “core” material collected provide insight into the potential leakage pathways within the well.

Numerical modeling of cemented wellbore leakage from storage reservoirs with secondary capture due to thief zones

Abstract A 3D, multi-phase, multi-component numerical model of injection into a storage reservoir with an abandoned wellbore is developed. A shallow aquifer is modeled above the storage reservoir separated by a caprock layer. An intermediate permeable layer assumed to be a thief zone is modeled. The abandoned wellbore penetrates the entire model from the surface, through shallow aquifer and thief zone to the bottom of the primary storage reservoir. The amount of CO 2 captured within the thief zone and released to the shallow aquifer and atmosphere is assessed. A Latin Hypercube sample evaluates the effects of variations in CO 2 injection rate, depth of the reservoir, relative depth of the thief zone, and permeability of the wellbore, thief zone, and shallow aquifer. In addition, full factorial design parameter studies evaluate the effect of differing wellbore permeabilities above and below the thief zone. Analyses of the Latin Hypercube sample and parameter studies provide indications of the necessary conditions for secondary capture in thief zones and potential for leakage to the shallow aquifer and atmosphere.

Wellbore leakage mitigation using engineered biomineralization

Abstract Research on microbially induced calcite precipitation (MICP) is reported. MICP may serve to reduce near-wellbore permeability, reduce CO 2 – related corrosion, and lower the risk of unwanted migration of CO 2 or other fluids. MICP research on the lab scale has demonstrated the ability to seal sandstone cores using injection strategies engineered to control precipitation. Experimentation was also aimed at transitioning MICP strategies for field implementation. MICP was evaluated in the field in a hydraulically fractured sandstone formation at a Walker County, Alabama well. The field experiment resulted in greatly reduced injectivity indicating that the fractured formation was plugged after MICP treatment.

Microseismic Monitoring of CO2 Injection at the Penn West Enhanced Oil Recovery Pilot Project, Canada: Implications for Detection of Wellbore Leakage

A passive seismic monitoring campaign was carried out in the frame of a CO2-Enhanced Oil Recovery (EOR) pilot project in Alberta, Canada. Our analysis focuses on a two-week period during which prominent downhole pressure fluctuations in the reservoir were accompanied by a leakage of CO2 and CH4 along the monitoring well equipped with an array of short-period borehole geophones. We applied state of the art seismological processing schemes to the continuous seismic waveform recordings. During the analyzed time period we did not find evidence of induced micro-seismicity associated with CO2 injection. Instead, we identified signals related to the leakage of CO2 and CH4, in that seven out of the eight geophones show a clearly elevated noise level framing the onset time of leakage along the monitoring well. Our results confirm that micro-seismic monitoring of reservoir treatment can contribute towards improved reservoir monitoring and leakage detection.

Pre-injection Baseline Data Collection to Establish Existing Wellbore Leakage Properties

Poor wellbore integrity is a risk in CO2 storage that must be evaluated at any geologic sequestration site. The conditions of five wells from two fields in Wyoming were studied to better understand pre-injection leakage potential in existing wells. Ultrasonic and sonic logging tools mapped the condition of the casing and cement in each well. Permeability testing outside the casing was conducted using two different dynamic testing tools making point and vertical interference test measurements Permeability was also measured through laboratory testing of cased-hole sidewall cores. The results of laboratory measurements were generally in the microdarcy-to-nanodarcy range and indicate that the well cements have not degraded from exposure to the formation brines. The results of vertical interference tests when compared to lab measurements imply interfaces between casing and cement or cement and formation are more significant with respect to leakage than the quality of the cement at the tested location.

Leakage Fingerprints During Storage: Modeling Above-zone Measurements of Pressure and Temperature

Since non-negligible leakage rates from injection and storage zones are possible along wellbores, it is important to be able to diagnose whether leakage is occurring. We show that concurrent pressure and temperature measurements are especially valuable because they independently constrain the effective permeability of a leakage path along wellbore. We describe a set of coupled analytical models for identifying the characteristic features of wellbore leakage in above-zone monitoring data. Application to data from an observation well (EGL7) during two years of steady CO2 injection in Cranfield (Mississippi, USA) shows that the observed pressure elevation requires an extremely large leakage rate, and that this rate would be large enough to raise the temperature in the monitoring zone significantly. Because the latter temperature “fingerprint” is not observed, we conclude that the observation well is unlikely to be leaking.

Experimental Evidence for Self-Limiting Reactive Flow through a Fractured Cement Core: Implications for Time-Dependent Wellbore Leakage

We present a set of reactive transport experiments in cement fractures. The experiments simulate coupling between flow and reaction when acidic, CO(2)-rich fluids flow along a leaky wellbore. An analog dilute acid with a pH between 2.0 and 3.15 was injected at constant rate between 0.3 and 9.4 cm/s into a fractured cement core. Pressure differential across the core and effluent pH were measured to track flow path evolution, which was analyzed with electron microscopy after injection. In many experiments reaction was restricted within relatively narrow, tortuous channels along the fracture surface. The observations are consistent with coupling between flow and dissolution/precipitation. Injected acid reacts along the fracture surface to leach calcium from cement phases. Ahead of the reaction front, high pH pore fluid mixes with calcium-rich water and induces mineral precipitation. Increases in the pressure differential for most experiments indicate that precipitation can be sufficient to restrict flow. Experimental data from this study combined with published field evidence for mineral precipitation along cemented annuli suggests that leakage of CO(2)-rich fluids along a wellbore may seal the leakage pathway if the initial aperture is small and residence time allows mobilization and precipitation of minerals along the fracture.

Modeling brine leakage to shallow aquifer through an open wellbore using T2WELL/ECO2N

The efficiency and sustainability of CO2 storage in deep saline formations depends on the integrity of the overlying caprocks. Existing oil and gas wells, which penetrate the formations, are potential leakage pathways. In this paper, T2WELL/ECO2N, a coupled wellbore–reservoir flow simulator of carbon dioxide and brine, is employed to analyze the effects of salinity and excess pore pressure (EPP) on brine leakage from an injection reservoir to a shallow fresh aquifer. The effectiveness of the Equivalent Porous Media (EPM) approach, a widely used approximation of wellbore flow in wellbore–reservoir simulations, is also evaluated. A hypothetical model is built to create test cases with EPP of 0.1MPa, 0.5MPa and 1.5MPa under low-, middle-, and high-salinity. The results show that a quasi-steady-state leakage rate will be quickly established if the EPP caused by CO2 injection is higher than the threshold EPP. However, the brine salinity has an important impact on the brine leakage rate including the threshold EPP below which no leakage occurs. The leakage rate decreases with the increase of the salinity whereas the threshold EPP increases with the increase of the salinity. For the same brine salinity, the quasi-steady-state leakage rate increases with the EPP nonlinearly. The leakage rate calculated by the EPM approach is very sensitive to the equivalent permeability of the wellbore, which however, is not an intrinsic parameter of a given wellbore–aquifer system. Although the EPM approach could reproduce the dynamic leakage rate reasonably well with a fitted permeability, it could over- or underestimates the leakage rate by orders in magnitude for the same system depending on whether the true leakage rate itself is smaller or larger than that of the fitting case due to changes in the salinity and/or the EPP through an abandoned well. The dependence of the equivalent permeability on the flow rate makes the EPM approach not to be a viable method for predicting wellbore leakage except for the cases with very small leakage rates.

Collection of baseline wellbore cement data in multiple wells in the same field

Abstract Abandoned wellbores may pose an important risk to the integrity of CO 2 storage formations that have large numbers of existing wells and that risk needs to be better understood. Field and laboratory studies have shown that well cement can be affected by CO 2 at differing levels depending on conditions. However, none of this work has looked at the initial conditions of the well (prior to CO 2 exposure). Understanding the initial conditions will be important for ensuring that the potential risk of leakage from the storage formation is acceptable. The collection of baseline wellbore integrity data allows for comparison during a project and will also identify any potentially problematic wells before a leak may occur. New field data from wells must be used to begin to understand if there are field-wide similarities between existing wells and how the similarities may be used to assess field-wide leakage risk. Existing data are not sufficiently focused (multiple wells in the same field) and there has been no satisfactory method of accelerating laboratory experiments to create realistic wellbore leakage conditions. Similarities between wells in the same fields were examined as part of a project to study the baseline condition and leakage risk of existing wells. Five wells were analyzed. The wells were split between two fields in the state of Wyoming, USA. The investigation used a combination of wellbore logging and sampling tools to analyze well conditions. Logging tools were selected to provide the maximum information on the materials that were used to construct wells and provide zonal isolation. The logging suite included sonic mapping tools, ultrasonic mapping tools, dynamic testers, and sidewall coring tools. Initial results show that there are similarities between wells within the same fields.

Wellbore integrity analysis of a natural CO 2 producer

Long-term integrity of existing wells in a CO 2-rich environment is essential for ensuring that geological sequestration of CO 2 will be an effective technology for mitigating greenhouse gas-induced climate change. The potential for wellbore leakage depends in part on the quality of the original construction as well as geochemical and geomechanical stresses that occur over its life-cycle. Field data are essential for assessing the integrated effect of these factors and their impact on wellbore integrity, defined as the maintenance of isolation between subsurface intervals. In this report, we investigate a 30-year-old well from a natural CO 2 production reservoir using a suite of downhole and laboratory tests to characterize isolation performance. These tests included mineralogical and hydrological characterization of 10 core samples of casing/cement/formation, wireline surveys to evaluate well conditions, fluid samples and an in situ permeability test. We find evidence for CO 2 migration in the occurrence of carbonated cement and calculate that the effective permeability of an 11′-region of the wellbore barrier system was between 0.5 and 1 milliDarcy. Despite these observations, we find that the amount of fluid migration along the wellbore was probably small because of several factors: the amount of carbonation decreased with distance from the reservoir, cement permeability was low (0.3–30 microDarcy), the cement–casing and cement-formation interfaces were tight, the casing was not corroded, fluid samples lacked CO 2, and the pressure gradient between reservoir and caprock was maintained. We conclude that the barrier system has ultimately performed well over the last 3 decades. These results will be used as part of a broader effort to develop a long-term predictive simulation tool to assess wellbore integrity performance in CO 2 storage sites.

Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores

Summary Implementation of carbon dioxide (CO2) storage in geological media requires a proper assessment of the risk of CO2 leakage from storage sites. Leakage pathways may exist through and along wellbores, which may penetrate or be near to the storage site. One method of assessing the potential for CO2 leakage through wells is by mining databases that usually reside with regulatory agencies. These agencies collect data concerning wellbore construction, oil and gas production, and other regulated issues for existing wells. The Alberta Energy Resources Conservation Board (ERCB), the regulatory agency in Alberta, Canada, collects and stores information about more than 315,000 oil, gas, and injection wells in the province of Alberta. The ERCB also records well leakage at the surface as surface-casing-vent flow (SCVF) through wellbore annuli and gas migration (GM) outside casing, as reported by the industry. The evaluation of a leakage pathway through wellbore casing or annuli and what causes these wellbore leaks are the first step in determining what factors may contribute to wellbore leakage from CO2-storage sites. By using available data, major factors that contribute to wellbore leakage were identified. Data analysis shows that there is a correlation between these SCVF/GM and economic activity, technology changes, geographic location, and regulatory changes regarding well completion and abandonment. Further analysis indicates a relationship between low-annular-cement top, external corrosion, casing failure, and wellbore leakage (SCVF/GM). Other factors that could affect the presence of wellbore leakage, such as wellbore deviation, surface-casing depth, and wellbore density, were also investigated. This paper presents the findings of the data analysis and a method to evaluate the potential for leakage along wells in an area where CO2 storage is intended. This information is useful not only for future operations of CO2 storage in geological media, but also for current operations relating to the exploration and production of hydrocarbons.

Acid gas injection and monitoring at the Zama oil field in Alberta, Canada: A case study in demonstration-scale carbon dioxide sequestration

The field validation test, conducted in the Zama oil field of northwestern Alberta, Canada, will evaluate the potential for geological sequestration of CO2 as part of a gas stream that includes high concentrations of H2S (20% to 40%). The results of this project will provide insight regarding the impact of H2S, in conjunction with CO2, on sink integrity (i.e., seal degradation); monitoring, mitigation, and verification techniques; and enhanced oil recovery success within a carbonate reservoir. Monitoring activities are focused on the near-pinnacle environment, including cap rock integrity, wellbore leakage, and spillpoint breach.

Development of a Hybrid Process and System Model for the Assessment of Wellbore Leakage at a Geologic CO2 Sequestration Site

Sequestration of CO2 in geologic reservoirs is one of the promising technologies currently being explored to mitigate anthropogenic CO2 emissions. Large-scale deployment of geologic sequestration will require seals with a cumulative area amounting to hundreds of square kilometers per year and will require a large number of sequestration sites. We are developing a system-level model, CO2-PENS, that will predict the overall performance of sequestration systems while taking into account various processes associated with different parts of a sequestration operation, from the power plant to sequestration reservoirs to the accessible environment. The adaptability of CO2-PENS promotes application to a wide variety of sites, and its level of complexity can be increased as detailed site information becomes available. The model CO2-PENS utilizes a science-based-prediction approach by integrating information from process-level laboratory experiments, field experiments/observations, and process-level numerical modeling. The use of coupled process models in the system model of CO2-PENS provides insights into the emergent behavior of aggregate processes that could not be obtained by using individual process models. We illustrate the utility of the concept by incorporating geologic and wellbore data into a synthetic, depleted oil reservoir. In this sequestration scenario, we assess the fate of CO2 via wellbore release and resulting impacts of CO2 to a shallow aquifer and release to the atmosphere.