Wellbore Leakage Research Articles

Wellbore trajectory control tool seal system leakage analysis based on steady gap flow

Lubricant leakage will inevitably occur during the working process of wellbore trajectory control tools. Even including the lubricant compensation system, serious leakage will still cause lacks lubrication of the internal mechanical structure as well as electronic system damaged by external infiltration fluid, especially when it comes to battery sub and other electronic equipment. Seal system leakage prediction method was presented based on the assumption of steady gap flow. It is assumed that there is a constant gap between the lip seal and the rotating shaft, the gap height is determined by oil film thickness, and the length of the gap was determined by the contact analysis using the Mooney–Rivlin constitutive model. The analysis results show that the contact length between the primary seal lip and the rotary shaft is about 0.1 mm under the condition of ensuring the contact between the deputy seal lip and the rotary shaft. The overall lubricant leakage finite element analysis model was established, and the relationship between the internal lubricant pressure of the tool and the total leakage was obtained. The results of analysis indicate that under the internal pressure of 0.03 MPa, the lubricant leakage is approximately 6 mL/h, which was verified by experiments.

Potential increase in oil and gas well leakage due to earthquakes

Earthquakes occurring naturally or induced by human activities can damage surface and subsurface infrastructure. Oil and gas wells represent a category of subsurface infrastructure that can act as leakage pathways connecting oil and gas reservoirs, groundwater aquifers, and the atmosphere. The integrity of these wells can be compromised through a wide range of processes and contribute to groundwater contamination, greenhouse gas emissions, and air quality degradation. We estimate the increase in such subsurface leakage potential due to seismic activity through geospatial analysis of 579,378 oil and gas well and 196,315 earthquake (magnitudes greater than 1.0) locations in Oklahoma, California, and British Columbia. We perform density-based clustering analysis and point density mapping using ArcGIS. We combine the well and earthquake point density maps to identify hot spots of joint high well and earthquake densities. We find that oil and gas wells and earthquakes are clustered in space, with densities reaching ∼60 wells per km2 and ∼40 earthquakes per km2 in California. There are at least two hot spots where these clusters overlap in each state/province. In Oklahoma and British Columbia, the hot spots are more correlated with earthquake densities; while, in California, the hot spots are more correlated with well densities. Our findings indicate the need to investigate the role of earthquakes on wellbore leakage through additional analysis of earthquake characteristics, wellbore attributes, improved data collection, and empirical field studies for all oil and gas wells, including those that are abandoned. In particular, large scale geospatial analysis establishing the scope of the problem and empirical field studies focusing on identified hot spots are needed to understand potential environmental impacts of earthquakes, especially those induced by oil and gas activities.

A portrait of wellbore leakage in northeastern British Columbia, Canada.

Oil and gas well leakage is of public concern primarily due to the perceived risks of aquifer contamination and greenhouse gas (GHG) emissions. This study examined well leakage data from the British Columbia Oil and Gas Commission (BC OGC) to identify leakage pathways and initially quantify incident rates of leakage and GHG emissions from leaking wells. Three types of leakage are distinguished: "surface casing vent flow" (SCVF), "outside the surface casing leakage" (OSCL), and "cap leakage" (CL). In British Columbia (BC), the majority of reported incidents involve SCVF of gases, which does not pose a risk of aquifer contamination but does contribute to GHG emissions. Reported liquid leakage of brines and hydrocarbons is rarer. OSCL and CL of gas are more serious problems due to the risk of long-term leakage from abandoned wells; some were reported to be leaking gas several decades after they were permanently abandoned. According to the requirements of provincial regulation, 21,525 have been tested for leakage. In total, 2,329 wells in BC have had reported leakage during the lifetime of the well. This represents 10.8% of all wells in the assumed test population. However, it seems likely that wells drilled and/or abandoned before 2010 have unreported leakage. In BC, the total GHG emission from gas SCVF is estimated to reach about 75,000 t/y based on the existing inventory calculation; however, this number is likely higher due to underreporting.

Risk-based monitoring designs for detecting CO2 leakage through abandoned wellbores: An application of NRAP’s WLAT and DREAM tools

As geologic CO2 storage (GCS) moves towards industrial-scale deployment, strategies must be developed to ensure long-term environmental risks related to potential leakage are managed. One approach to is to perform risk-based subsurface monitoring targeting early leak detection. Early detection is particularly important to address the risk associated with leakage along legacy wells. The challenge in risk-based monitoring is that leakage impacts are expected to be small in comparison with the footprint of the stored CO2 plume and could occur over considerable depths, ranging from the storage formation up to surficial aquifers. Here we demonstrate the application workflow of two of the National Risk Assessment Partnership’s (NRAP) computational tools, WLAT (Wellbore Leakage Analysis Tool) and DREAM (Designs for Risk Evaluation and Management), to a hypothetical CO2 storage site based on a study area in the Midwestern United States. By incorporating site specific wellbore integrity analyses, results show how fluid leakage may be estimated, evaluated, and monitored in terms of risk. For the selected site, three monitoring wells were ultimately needed to detect all possible CO2 leaks and six monitoring wells were needed to minimize time to leak detection. Such analyses inform stakeholders about long-term liability and monitoring costs of GCS projects.

Barometric-pumping controls fugitive gas emissions from a vadose zone natural gas release

Subsurface natural gas release from leaking oil and gas wells is a major environmental concern. Gas migration can cause aquifer contamination, explosive conditions in soil gas, and greenhouse gas emissions. Gas migration is controlled by complex interacting processes, thus constraining the distribution and magnitude of “fugitive gas” emissions remains a challenge. We simulated wellbore leakage in the vadose zone through a controlled release experiment and demonstrate that fugitive gas emissions can be directly influenced by barometric pressure changes. Decreases in barometric-pressure led to surface gas breakthroughs (>20-fold increase in <24 hours), even in the presence of low-permeability surficial soils. Current monitoring strategies do not consider the effect of barometric pressure changes on gas migration and may not provide adequate estimates of fugitive gas emissions. Frequent or continuous monitoring is needed to accurately detect and quantify fugitive gas emissions at oil and gas sites with a deep water table.

Assessment of geophysical monitoring methods for detection of brine and CO2 leakage in drinking water aquifers

We evaluated and compared the effectiveness of four surface-based geophysical monitoring methods to downhole pressure and chemical methods to detect brine and CO2 leakage in underground sources of drinking water overlying a CO2 storage reservoir. This assessment uses synthetic monitoring data generated from 400 simulated aquifer impact data sets. The six monitoring techniques can detect impacted groundwater once 20,000 tonnes of CO2 have leaked into the drinking water resource. Geophysical methods are most effective at detecting shallow plumes. Although downhole monitoring methods outperform geophysical methods in detecting deep plumes, geophysical methods may help reduce the false negative during the post injection site care because they detect impacted groundwater where downhole sensors may be absent.This analysis informs future monitoring plans by defining the size of leaks that can be detected for a range of techniques and the need for using complementary methods that measure CO2 gas and changes in groundwater chemistry spatially in addition to discrete point source measurements. A comprehensive monitoring plan consists of (1) site specific reservoir, wellbore leakage and geochemical models to predict likely aquifer impact; (2) downhole TDS sampling to provide an early indication of brine and CO2 leakage; (3) downhole pressure monitoring to track migration of the CO2 plume; and (4) surface-based geophysical methods to track the shallow leakage plumes. It is important to combine downhole measurements with geophysical methods that are sensitive to CO2 gas and TDS to improve leak detection and add confidence that “no detection” means no leak.

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.

Practical Leakage Risk Assessment for CO2 Assisted Enhanced Oil Recovery and Geologic Storage in Ohio's Depleted Oil Fields

A method for estimating the expected liability (risk) associated with wellbore leakage during and after geologic storage operations is presented using three of Ohio’s oil fields as case studies. The risk framework described in this study uses the bowtie method with features, events, and processes (FEPs) descriptors to identify and assess risk posed by legacy wells. The bow-tie framework allows simple visualization of top risk events (hazards). The probability of triggering the hazard is quantified based on estimation of the wellbore’s integrity while the consequences are modeled based on low- and high-cost outcome scenarios. This method builds upon previous work. It estimates current wellbore integrity using characteristic categories to develop a proxy for leakage likelihood. Proxy categories were: Spud Date, Treatment, Well Status, Plugging and Abandonment (P&A) Date, Well Type, Plug, Surface Cement, and Primary Cement. Separate risks were developed for each well and each scenario. The consequence of a leakage event was estimated based on costs to businesses and property owners for each leakage scenario. Using the likelihood of leakage calculated for each field and the cost of potential consequences, the risks for each field were estimated to be between $10 million to $63 million for the three fields of interest. Overall, the identification of threats, hazards, and consequences and the identification of barriers to lessen the likelihood of occurrence or minimize consequences aids in the development of a targeted CCUS strategies.

CO2 Migration in the Overburden: Rates, Pathways and Barriers to Fluid Flow

Large-scale geological heterogeneities and their potential to enhance fluid flow or hinder migration in the subsurface are reviewed. Evidence for flow or fluid containment by faults and fractures, fluid flow features, submarine mass movement deposits, buried tunnel valleys, hydrofractures and glacitectonic features is presented. Wellbore-related flow paths and well integrity studies are summarised; the risk of wellbore leakage may be best understood by simulations of predicted long-term behaviour of well barriers. Rates of fluid flux at natural seepage sites and controlled experimental releases of carbon dioxide (CO2) are compiled and compared, and lessons learnt for monitoring of CO2 storage sites identified. The overburden sequences to five operational or planned CO2 storage sites are compared and those characteristics in common that promote subsurface containment of fluids are highlighted.

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.

Study on Sealing Failure of Wellbore in Bedded Salt Cavern Gas Storage

The wellbore tightness of a salt cavern gas storage must be tested before solution mining. According to the test results, it will be evaluated whether the wellbore can meet the cementing requirements of gas storage. However, there are many complex reasons that may cause wellbore leakage; hence, how to comprehensively analyze the test results and accurately expose the causes, locations, and scale of the leakage pose many challenges. These mainly include the incomplete test method and lack of theoretical analysis model. A nitrogen leak test was carried out for five wellbores that have been completed in Jintan (Jiangsu, China). The results show that two of them had leakage risk. To clarify the leakage causes and leakage types, we carried out an investigation of engineering geological data of the wellbores and further conducted laboratorial tests and theoretical analysis. The studies of drilling design and engineering geology show that the wellbores have good integrity and initially reveal that a mudstone interlayer intersecting the open hole between the casing shoe and the top of the salt cavern is a potential leaking layer. Furthermore, the permeability experiments and CT scans confirm that this mudstone interlayer is a leaking stratum and that the internal cracks develop severely. They are the key reasons leading to wellbore tightness failure. The proposed seepage theoretical model determines that the leakage type is horizontal flow in the mudstone interlayer. Comparing the theoretical results with the field test data, we find that the leakage rate curves of the two are in good agreement, which completely confirms that the mudstone interlayer is the fundamental cause of the wellbores tightness failure. This research not only identifies the leakage causes and leakage types of wellbores, but also enriches the leakage rate analysis method of gas storage and provides a theoretical and experimental analysis method for tightness evaluation of bedded salt cavern storage.

Methane Leakage From Hydrocarbon Wellbores into Overlying Groundwater: Numerical Investigation of the Multiphase Flow Processes Governing Migration

AbstractMethane leakage due to compromised hydrocarbon well integrity can lead to impaired groundwater quality. Here we use a three‐dimensional, multiphase (vapor and aqueous), multicomponent (methane, water, salt), numerical model (TOUGH2 EOS7C) to investigate hydrogeological conditions that could result in groundwater contamination from natural gas wellbore leakage that migrates upward toward a freshwater aquifer. The conceptual model used for the simulations assumes methane leakage at 20–30 m below groundwater. We perform 180 simulations for a sensitivity analysis, examining (1) multiphase flow parameters related to storage, capillarity, and relative permeability, including porosity (ϕ), initial fluid‐phase saturation (SL), and van Genuchten n and α, (2) geostatistical variations in intrinsic permeability (ki), and (3) methane source‐zone pressure. Simulated mean ki values are 10−18 and 10−13 m2 with variances of 1 and 5 m4. Simulated source‐zone pressures range from just over ambient hydrostatic pressure at the depth of leakage (100 kPa) to the maximum pressure that steel casings are commonly rated to withstand (20,340 kPa). ki, initial SL, ϕ, and van Genuchten's n and α were the most important parameters in determining the volume of methane reaching groundwater during a given time period. Multiphase parameterization of formations underlying freshwater aquifers and overlying hydrocarbon production zones is fundamental to assessing aquifer vulnerability to methane leakage.

Assessment of two-phase flow on the chemical alteration and sealing of leakage pathways in cemented wellbores

Wellbore leakage tops the list of perceived risks to the long-term geologic storage of CO2, because wells provide a direct path between the CO2 storage reservoir and the atmosphere. In this paper, we have coupled a two-phase flow model with our original framework that combined models for reactive transport of carbonated brine, geochemistry of reacting cement, and geomechanics to predict the permeability evolution of cement fractures. This addition makes the framework suitable for field conditions in geological storage sites, permitting simulation of contact between cement and mixtures of brine and supercritical CO2.Due to lack of conclusive experimental data, we tried both linear and Corey relative permeability models to simulate flow of the two phases in cement fractures. The model also includes two options to account for the inconsistent experimental observations regarding cement reactivity with two-phase CO2-brine mixtures. One option assumes that the reactive surface area is independent of the brine saturation and the second option assumes that the reactive surface area is proportional to the brine saturation.We have applied the model to predict the extent of cement alteration, the conditions under which fractures seal, the time it takes to seal a fracture, and the leakage rates of CO2 and brine when damage zones in the wellbore are exposed to two-phase CO2-brine mixtures. Initial brine residence time and the initial fracture aperture are critical parameters that affect the fracture sealing behavior. We also evaluated the importance of the model assumptions regarding relative permeability and cement reactivity. Our results illustrate the need to understand how mixtures of carbon dioxide and brine flow through fractures and react with cement to make reasonable predictions regarding well integrity. For example, a reduction in the cement reactivity with two-phase CO2-brine mixture can not only significantly increase the sealing time for fractures but may also prevent fracture sealing.

An experimental and numerical study of wellbore leakage mitigation using pH-triggered polymer gelant

The potential leakage of hydrocarbon fluids or carbon dioxide from subsurface formations is a primary concern in wellbore integrity, oil and gas production, and CO2 storage. Leaky wells with fractured cement or debonded microannuli are common sources of subsurface fluid leakage. The hydrocarbon fluid or CO2 can migrate through such pathways to shallower formations and ultimately to surface. Cement fractures may have apertures on the order of microns, which are difficult to seal with typical workover techniques.A material that provides low viscosity during the injection but much higher viscosity after injection, with a minimum pressure gradient to yield flow at the target zone, is a potentially effective approach to seal the leakage pathways through cement fractures. pH-triggered polymers are such a material: aqueous solutions with low viscosity at low pH, containing pH-sensitive microgels which viscosify upon neutralization to become highly swollen gels with substantial yield stress that can block fluid flow. For the wellbore leakage application, the large alkalinity of wellbore cement provides the required neutralization. Our coreflood and rheological experiments show that pH-triggered polymer sealants such as polyacrylic acid polymer provide a robust seal if the process is properly designed; however, its long-term applicability depends on the dynamic geochemical environment of the wellbore. The process comprises three stages: (1) injection of a chelating agent as the preflush to ensure a favorable environment for the polymer gel, (2) injection of polymer solution, and (3) shut-in for the polymer gelation. A systematic study was done to understand the conditions under which the polymer gel remains stable and effectively seals the leakage pathways.A numerical model, based on polymer rheological properties and governing mechanisms observed in the laboratory experiments, was developed to simulate the reactive flow and transport of pH-triggered polymers in narrow fractures. Comparison with experiments shows a generally good agreement, despite the relative simplicity of the model. The numerical model was used to investigate further the underlying mechanisms of the process. The results can be used to design effectively the remediation process for a known fracture aperture size of the target zone.

Heterogeneity, pore pressure, and injectate chemistry: Control measures for geologic carbon storage

Desirable outcomes for geologic carbon storage include maximizing storage efficiency, preserving injectivity, and avoiding unwanted consequences such as caprock or wellbore leakage or induced seismicity during and post injection. To achieve these outcomes, three control measures are evident including pore pressure, injectate chemistry, and knowledge and prudent use of geologic heterogeneity. Field, experimental, and modeling examples are presented that demonstrate controllable GCS via these three measures. Observed changes in reservoir response accompanying CO2 injection at the Cranfield (Mississippi, USA) site, along with lab testing, show potential for use of injectate chemistry as a means to alter fracture permeability (with concomitant improvements for sweep and storage efficiency). Further control of reservoir sweep attends brine extraction from reservoirs, with benefit for pressure control, mitigation of reservoir and wellbore damage, and water use. State-of-the-art validated models predict the extent of damage and deformation associated with pore pressure hazards in reservoirs, timing and location of networks of fractures, and development of localized leakage pathways. Experimentally validated geomechanics models show where wellbore failure is likely to occur during injection, and efficiency of repair methods. Use of heterogeneity as a control measure includes where best to inject, and where to avoid attempts at storage. An example is use of waste zones or leaky seals to both reduce pore pressure hazards and enhance residual CO2 trapping.

Temperature analysis for early detection and rate estimation of CO2 wellbore leakage

Wellbore leakage of carbon dioxide (CO2) injected into storage zones can induce significant temperature anomalies. These thermal signals arise from expansion of the leaking CO2 associated with the pressure drop across the leak, known as the Joule-Thomson effect, which has the potential to reveal the nature of leakage and determine the wellbore leakage rate of CO2. We investigate the strength of the temperature signal as a function of leakage rate and develop a control volume analysis to relate these two in the complex two-phase leakage conditions. This analytical thermal model for CO2 leakage enables quick analysis with sufficient accuracy to estimate the leakage rate. The application range of this approach is identified from the results of comprehensive investigations. The nature of the thermal signal is sensitive to the balance between the Joule-Thomson effect and heat conduction. The ratio of these two effects and newly defined JT/cond Number provide general criteria for the applicability of modeling these thermal signals in the range of 40–90% and 1.6-4, respectively. Furthermore, in the case of higher leakage rate, we extend the analytical model to predict the leakage transmissibility with improved accuracy compared to the direct rate estimation from leakage thermal model in this scenario. The general procedure and flow chart to apply the proposed approach to a practical problem are provided, which is suitable for both injection and post-injection periods for a CO2 storage project. This analytical model breaks a new ground to apply recent temperature wellbore monitoring developments for CO2 leakage detection and characterization purposes. Field applications of this model can complement other leakage rate estimation techniques and be an essential part of the CO2 leakage detection tool if other approaches are not viable.

Influence of Chemical, Mechanical, and Transport Processes on Wellbore Leakage from Geologic CO2 Storage Reservoirs.

Wells are considered to be high-risk pathways for fluid leakage from geologic CO2 storage reservoirs, because breaches in this engineered system have the potential to connect the reservoir to groundwater resources and the atmosphere. Given these concerns, a few studies have assessed leakage risk by evaluating regulatory records, often self-reported, documenting leakage in gas fields. Leakage is thought to be governed largely by initial well-construction quality and the method of well abandonment. The geologic carbon storage community has raised further concerns because acidic fluids in the CO2 storage reservoir, alkaline cement meant to isolate the reservoir fluids from the overlying strata, and steel casings in wells are inherently reactive systems. This is of particular concern for storage of CO2 in depleted oil and gas reservoirs with numerous legacy wells engineered to variable standards. Research suggests that leakage risks are not as great as initially perceived because chemical and mechanical alteration of cement has the capacity to seal damaged zones. Our work centers on defining the coupled chemical and mechanical processes governing flow in damaged zones in wells. We have developed process-based models, constrained by experiments, to better understand and forecast leakage risk. Leakage pathways can be sealed by precipitation of carbonate minerals in the fractures and deformation of the reacted cement. High reactivity of cement hydroxides releases excess calcium that can precipitate as carbonate solids in the fracture network under low brine flow rates. If the flow is fast, then the brine remains undersaturated with respect to the solubility of calcium carbonate minerals, and zones depleted in calcium hydroxides, enriched in calcium carbonate precipitates, and made of amorphous silicates leached of original cement minerals are formed. Under confining pressure, the reacted cement is compressed, which reduces permeability and lowers leakage risks. The broader context of this paper is to use our experimentally calibrated chemical, mechanical, and transport model to illustrate when, where, and in what conditions fracture pathways seal in CO2 storage wells, to reduce their risk to groundwater resources. We do this by defining the amount of cement and the time required to effectively seal the leakage pathways associated with peak and postinjection overpressures, within the context of oil and gas industry standards for leak detection, mitigation, and repairs. Our simulations suggest that for many damage scenarios chemical and mechanical processes lower leakage risk by reducing or sealing fracture pathways. Leakage risk would remain high in wells with a large amount of damage, modeled here as wide fracture apertures, where fast flowing fluids are too dilute for carbonate precipitation and subsurface stress does not compress the altered cement. Fracture sealing is more likely as reservoir pressures decrease during the postinjection phase where lower fluxes aid chemical alteration and mechanical deformation of cement. Our results hold promise for the development of mitigation framework to avoid impacting groundwater resources above any geologic CO2 storage reservoir by correlating operational pressures and barrier lengths.

Dynamic reduced-order models of integrated physics-specific systems for carbon sequestration

$$\text {CO}_2$$ leakage from a deep storage reservoir into a shallow groundwater aquifer through a wellbore is simulated using physics-specific models conceptualized as nonisothermal two-phase flow in a deep storage reservoir and through the wellbore, and reactive transport in the aquifer. Supercritical $$\text {CO}_2$$ is injected into the reservoir subsystem with uncertain permeabilities of reservoir and injection strategies (rate and duration as decision variables). The simulated pressure and $$\text {CO}_2$$ saturation at an uncertain location are connected to the wellbore model as a boundary condition to output $$\text {CO}_2$$ flux to the reactive transport model in the shallow aquifer. Uncertainties are propagated from the deep reservoir model, to the wellbore leakage model, and eventually to the reactive transport model, thus contributing to system performance. To minimize the risk associated with the $$\text {CO}_2$$ leakage, we develop dynamic reduced order models for quantifying and managing the uncertainty propagation.

Reaction-driven casing expansion: potential for wellbore leakage mitigation

It is generally challenging to predict the post-abandonment behaviour and integrity of wellbores. Leakage is, moreover, difficult to mitigate, particularly between the steel casing and outer cement sheath. Radially expanding the casing with some form of internal plug, thereby closing annular voids and fractures around it, offers a possible solution to both issues. However, such expansion requires development of substantial internal stresses. Chemical reactions that involve a solid volume increase and produce a force of crystallisation (FoC), such as CaO hydration, offer obvious potential. However, while thermodynamically capable of producing stresses in the GPa range, the maximum stress obtainable by CaO hydration has not been validated or determined experimentally. Here, we report uniaxial compaction/expansion experiments performed in an oedometer-type apparatus on precompacted CaO powder, at 65 °C and at atmospheric pore fluid pressure. Using this set-up, the FoC generated during CaO hydration could be measured directly. Our results show FoC-induced stresses reaching up to 153 MPa, with reaction stopping or slowing down before completion. Failure to achieve the GPa stresses predicted by theory is attributed to competition between FoC development and its inhibiting effect on reaction progress. Microstructural observations indicate that reaction-induced stresses shut down pathways for water into the sample, hampering ongoing reaction and limiting the magnitude of stress build-up to the values observed. The results nonetheless point the way to understanding the behaviour of such systems and to finding engineering solutions that may allow large controlled stresses and strains to be achieved in wellbore sealing operations in future.

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 &amp; Sons, Ltd