A review of cement sheath integrity evaluation techniques for carbon dioxide storage

Abstract

Cement sheath integrity is a critical concern in the successful implementation of geologic carbon capture and storage (CCS) projects. Conventional ordinary Portland cement (OPC) is not thermodynamically compatible with the carbon dioxide (CO₂) present in CO₂ storage media. When OPC cement sheaths interact with aqueous CO₂, they undergo degradation, producing calcium bicarbonate. This bicarbonate readily dissolves in the formation aquifer and can create leakage pathways, compromising the integrity of the wellbores. This study comprehensively reviews the state-of-the-art techniques for evaluating cement sheath integrity, providing a comprehensive compendium of available methods in a single article. The paper’s objective is to support the deployment of successful CCS projects, facilitate the remediation of affected wellbores in CO₂ storage systems, and offer guidelines for evaluating improved cement slurry designs and formulations. Additionally, the study identifies the factors that influence cement sheath integrity when exposed to aqueous CO₂, including in-situ temperature and pressure, reservoir fluid characteristics, cement slurry formulations, and wellbore operations. Furthermore, various modes of mechanical failure in cement sheaths are identified, such as radial cracking, plastic deformation, inner and outer debonding, and channeling. Understanding these failure mechanisms is crucial for designing robust cementing strategies in CCS applications. Evaluation techniques for assessing the integrity of cement sheaths exposed to aqueous CO₂ encompass a range of approaches. These include direct experimentation with samples that mimic the in -situ conditions of storage sites, well logging for monitoring leakages, analytical, numerical, and statistical modeling, and risk assessments. Direct experimentation plays a vital role in understanding the carbonation kinetics and changes in cement sheaths' mechanical and transport properties. Techniques such as scanning electron microscopy, back-scattered electron image detectors, energy-dispersive spectroscopy, mercury intrusion porosimetry, optical microscopy, X-ray diffraction, electrical resistivity imaging, electron probe microanalyzers, inductivity-coupled plasma optical emission spectrometry, X-ray computed microtomography, Raman spectroscopy, direct image correlation, and particle velocimetry are utilized for direct experimentation. Analytical and numerical modeling approaches include reactive transport modeling, multi-scale modeling, computational fluid dynamics (CFD), and artificial intelligence (AI)-based modeling. In field operations, the integrity of the cement sheaths can be evaluated using cement bond evaluation tools, pressure transient test tools, cement coring tools, or sustained casing pressure analysis. These techniques collectively enable a comprehensive assessment of the integrity of cement sheath exposed to aqueous CO₂, aiding in optimizing and monitoring carbon storage systems. Every CO₂ storage medium is unique. Optimal assessment of the cement sheaths' integrity of its wellbore systems, when exposed to aqueous CO₂, would require a different combination of suitable evaluation techniques. Future studies should focus on developing standardized guidelines that combine laboratory testing, field-scale testing, and numerical modeling to predict the evolution of cement sheath integrity when exposed to aqueous CO₂. Additional research is necessary to determine the optimal combinations of cement additives that enhance long-term resilience and resistance to carbonic acid attacks, enabling successful geologic sequestration. Furthermore, there are ample research opportunities to advance numerical modeling techniques for evaluating the effects of aqueous CO₂ on cement sheath integrity and identifying potential failure mechanisms.

Introduction

The thirteenth goal of the 2030 Sustainable Development Goals (SDGs) is “Climate Action,” it involves climate change mitigation and impact reduction. Carbon capture and storage is considered a valuable urgent action that could combat climate change and reduce its impacts. Carbon capture and sequestration (CCS) is a valuable technology to efficiently handle CO₂ emissions from hydrocarbon combustion operations, it represents a crucial transitive technology to sourcing for alternative cleaner green energy sustainably, to minimize dependence on fossil fuels. However, cement sheath integrity management is critical for the successful implementation of any carbon dioxide geosequestration project. Efficient management requires sound evaluation techniques suitable to adequately and promptly identify any integrity issue. Cooper (2009) summarized reports from a large CO₂ capture project sponsored by eight of the world’s major oil and gas industries. The study utilized analogy from practical experiences of oil and gas industry operations to explain the feasibility of storing CO₂ geologically, it considered the main applications that would facilitate efficient storage and the geologic management operations that would boost the conviction of all interested parties involved or interested in the storage operation. For CCS projects to be successfully embarked upon, availability to top-notch storage sites is a necessary prerequisite with a well-clarified legal and regulatory scheme that identifies transparency over rights, possible risks, and long-term preparatory measures for managing CO₂ storage sites. Though risks are inevitable in CO₂ geosequestration projects, experiences from tantamount tasks in the energy industry suggest that these risks can be managed, therefore, should be tolerable to every stakeholder involved or affected. An unbiased regulative scheme that handles risks astutely and admits that they can change with time will support the development and evolution of CCS technology. Though reports suggest more than five billion tons of CO₂ every year can be effectively stored safely underground, potential leak pathways may be created during and after injection due to the chemical interactions of the stored CO₂ with the cement sheath (Tiong et al. 2019).

Wellbore integrity is a key concern in the life span of all wellbores. loss of wellbore integrity amounts to enormous gloomy outcomes and adverse environmental impacts, like underground aquifer contamination, gas leakages, and formation fluids spillages. Factors influencing wellbore integrity can be chemical, mechanical, and operational (Kiran et al. 2017). Many researchers identify wellbore integrity as the main risk factor for the viability of any geologic CCS projects (William Carey et al. 2010; Zhang and Bachu 2011; Choi 2013; Sminchak et al. 2014; Wang and Taleghani 2014; Kiran et al. 2017). However, wellbore integrity immensely depends on the integrity of the cement sheath. (Crow et al. 2010; William Carey et al. 2010; Wang and Taleghani 2014).

Emphasizing the petroleum industry advanced improved techniques for the safe, efficient, and economic injection of CO₂ over the past several decades, whereby projects involving injection of CO₂ into the formation rocks were accomplished, cutting across several depths range and reservoir characteristics, both within the formation aquifers and oil and gas reservoirs; Wilkinson et al. (2009) suggested experiences gained about “site selection, storage site design, and monitoring” can be utilized to successfully carryout CO₂ storage projects. Reliable, safe, and structured long-lasting carbon dioxide storage would depend upon apprehension and adherence to defined limits on caprock fracture pressures and establishing the highest injection rates required to prevent unfavorable gravity-related sweep override of the injected CO₂. Using certain examples covering a variety of feasible storage scenarios, their study showed that the combination of location-specific data and comprehensive dynamic modeling is essential for an absolute assessment of the sequestration site’s integrity. Every storage site would require specific subsurface characterization and analysis, guaranteeing satisfactory integrity since all storage sites are unique.

Reiterating studies and experience suggest wellbores are the most likely destination for storing CO₂, Syed and Cutler (2010) suggested a sound CO₂ injection wellbore design and wellbore integrity, operations, and monitoring are of key significance, especially for long-term geologic storage (1000 years or more). Some of the facts presented include: (i) It is important to construct suitable injection wellbores specifically for CO₂ storage. (ii) The carbon dioxide storage site requires adequate integrity, which guarantees the mechanical integrity of the whole wellbore system. (iii) Cement slurry and casing string designs must be adequate to ensure CO₂ confinement is maintained and mechanical integrity is not compromised throughout the storage wellbores' lifecycle. (iv) It is necessary to appraise the cement’s bond quality to the casing string and the formation rock using both cement sheath assessment tools like ultrasonic image tool/ segmented cement bonding tool (USIT/SBT) and formation integrity tests (FIT) to ensure zonal isolation at the casing shoe. (v) During completions of CO₂ storage wellbores, acid corrosion resistance alloys (CRA) could be used to replace the conventional low-carbon steel casing strings. (vi) Degradation of cement sheath in CO₂ storage sites could be minimized by replacing conventional Portland cement with CO₂-acid-resistant cement. (vii) Tools like ultrasonic leak detection tools could be useful to detect very small leaks. (viii) Automatic monitoring systems that continuously monitor the wellbore’s temperature and pressures within both the annulus and the tubing could facilitate automated shutdowns of the wellbore system once defined limits are exceeded. Also, the maximum injection pressure ought to be lower than the formation fracturing pressure.

Hossain and Amro (2010) investigated the principal mechanisms associated with wellbore integrity issues in CO₂-injected wells, with an emphasis on cap rock and cementing integrity. Their investigation involved reviewing different field case studies available in the literature. The paper identified critical wellbore integrity issues, including wellbore design failures, failure to contain reservoir fluid pressure, corrosion problems, tubular leakage, cement sheath issues, and wrong choices of downhole equipment for wellbore completion. To minimize the chances of integrity failure, their study proposed screening criteria that provide optimal design and completion of carbon dioxide injection wellbores for either EOR or carbon dioxide storage. The article also highlighted the necessity to perform a series of experiments in the laboratory to evaluate the stability or integrity of the cement sheath to be used in either an EOR or CO₂ storage project.

Zhang and Bachu (2011) reviewed available articles that discussed the failure of wellbores reused for CO₂ storage or constructed in CO₂-rich environments by looking into experiments carried out in the laboratory, field case studies, and numerical modeling and simulations performed in the past, in an attempt to establish the characteristics of the cement sheath exposed to aqueous CO₂. Although significant carbonation of cement sheath exposed to CO₂ environment was reported by several investigators, severe cement degradation required the dissolution of the calcite from the carbonated cement sheath before a leakage pathway can be established. Since most geological storage of CO₂ is mostly in carbonate formation, the aqueous CO₂ is expected to be in equilibrium with the carbonate environment present; therefore, cement degradation would be unlikely. The article suggested that for CO₂ storage or CO₂ injection, it is preferable to construct wellbores specifically for CO₂ injection that would meet the expected rigid zonal confinement specification instead of reusing existing wellbores for CO₂ injection purposes.

By conducting risk assessments of the Weyburn-Midale CO₂ storage project, wellbore integrity was recognized as a key risk concern for the long-lasting sequestration of CO₂. The type and standard of cement sheath between the formation rock and the casing string are of key significance to wellbore integrity, which could be compromised by corrosion. Poor cementing leads to inadequate preservation of the casing string and increases the tendency of corrosion significantly. Therefore, a meticulous assessment of the cementing job is an indispensable aspect of the corrosion prediction and prevention procedure, thus it is a valuable assurance of wellbore integrity. Choi (2013) confirmed investigators’ reports that the rate of corrosion of low-carbon steel in contact with a high CO₂ partial pressure environment without protective FeCO₃ passivation film is significantly high, approximately 20 mm within just one year, while under certain circumstances, the rate of corrosion of low-carbon steel exposed to a large CO₂ pressure environment can substantially reduce to a much lower value, approximately 0.2 mm within a year, resulting from the development of protective FeCO₃ passivation film. Interestingly, laboratory and field experience reveals the likelihood of localized corrosion for low-grade steel even when corrosion inhibitors are used, and this can significantly reduce the steel casing string’s lifespan.

Noting that one of the disturbing issues with CO₂ storage ventures is the deterioration of conventional Portland cement when exposed to supercritical carbon dioxide, Abid et al. (2015) reviewed some reported laboratory work carried out to understand the changes to expect with the cement sheath’s mechanical and transportation properties when exposed to a carbon dioxide-rich terrain. The authors showed that the carbonation of the cement sheath resulting from the interactions between the cement sheath and aqueous CO₂ was initially a self-sealing mechanism that lowers the porosity and boosts the mechanical strength of the cement sheath. However, because of the prolonged diffusion of HCO₃⁻, bicarbonation of the CaCO₃ occurs, which causes the deterioration of the cement sheath. The deterioration of the cement sheath is expressed by a reduction of its mechanical strength and transport properties. Based on the laboratory experimental studies, factors influencing the carbonation rate of conventional Portland cement can be grouped as either controllable or uncontrollable parameters. Uncontrollable parameters are the prevailing reservoir in-situ conditions, while the controllable parameters constitute cementing techniques and formulations that reduce or increase the cement sheath’s protection from CO₂ aggressions. Examples of uncontrollable parameters include reservoir temperature and pressure, formation’s water saturation, the salinity of the formation fluid, and reservoir static or dynamic conditions, among others while examples of controllable factors include the proportion of water in the cement, inclusion of pozzolanic material in the cement slurry formulations, reducing the porosity and permeability by adding suitable additives, among others.

Carroll et al. (2016) reviewed related articles that remarkably improved the perception of the causes and effects of wellbore leaks in CO₂ storage systems. Confirming that conventional Portland cement sheath was prone to alterations in CO₂ storage environments, they reported that the alterations were limited to the diffusion of reactants and products. Low-carbon steel (which is mostly utilized in casing wellbores) is significantly prone to corrosion due to the presence of aqueous CO₂. With abundant aqueous CO₂ in place, low-carbon steel corrodes at significantly high rates (as high as millimeters per year). However, if the contact between the cement sheath and the steel is good enough, the high pH of the cement sheath facilitates passivation of the cement sheath and casing, which in turn, protects the low-carbon steel casing. Passivation is also important when CO₂ migrates through the cement sheath–steel interface since FeCO₃ precipitation provides extra defense against corrosion, lowering the rate of corrosion by an order of magnitude in some cases. Highlighting that the understanding of how chemical alteration of cement sheath affects its physical attributes was still in the early stages, they identified that evidence suggested well permeability may decrease due to the carbonation reaction, thereby reducing the possibility of leakages in plugged wellbores. Geochemical and geomechanical reactions between the wellbore cement sheath and supercritical CO₂ or aqueous CO₂ may, in some instances, facilitate the sealing and closure of leak pathways. Carbon dioxide-facilitated sealing depends on portlandite abundance and cement sheath permeability and porosity, as well as the fluid velocity and residence time within the leakage pathways. They indicated that the role of stress in the wellbore environment is not properly investigated, especially the effect of thermal stress on wellbore integrity. They also highlighted the importance of defining the pressures that would lead to ruining the interfacial bonds within the wellbore. It is interesting to note that tools and models to simulate and forecast these phenomena are studied and developed within a reasonable scheme to appraise and harmonize wellbore leakage risks. To improve the awareness of the likelihood of wellbore leakage at carbon dioxide geologic storage sites, the authors suggested it is imperative to conduct rigorously designed field investigations at pilot-scale projects so that firsthand observation from field site characterization and monitoring campaigns could assist in developing subsequent test to substantiate the complex integrated models required to access the likelihood of wellbore leakages.

Shenold and Teodoriu (2016), an extensive literature review provided information about cement integrity evaluation, emphasizing the need to assess long-term cementing conditions. The article noted that there was not any distinctive technique for accessing well integrity for wellbores used for hydrocarbon production, CO₂ underground sequestration, or geothermal energy generation purposes. Both interim and long-lasting wellbore integrity evaluations require other supplementary cement sheath attributes, which are not usually sufficiently incorporated into the integrated workflow. Supplementary cement sheath attributes, like its tensile strength and cyclic fatigue, usually not defined based on recent API standards, have to be assessed and incorporated in modern wellbore simulations. Recent risk-based viewpoints would significantly improve wellbore integrity predictions, especially if ample experimental data is available. For example, long-term cement sheath integrity details are hardly ever documented, while cement sheath tensile strength specifications are either undependable or misplaced. The authors suggested combining risk-based decision tools and finite element methods (FEM) simulations offers the best platform suitable to support predictions. Accurate cement sheath attributes, subsurface conditions, and cementing logging details are needed for this kind of organized methodology, and hence, it could be a valuable tool for the petroleum industry.

Kiran et al. (2017) reviewed the causes of failure of wellbore integrity, noting that wellbore integrity is key in the lifespan of every wellbore and its deterioration could result in unpleasant financial implications and adverse environmental impacts, such as pollution of subsurface aquifers, gas leaks, and fluid spillage, among others. Therefore, maintaining safe wellbore integrity over the lifecycle of the well is essential and would require thorough assessment and periodic monitoring of chemical, mechanical, and physical factors influencing integrity. Wellbore integrity evaluation techniques involve experimentations, wellbore logging, analytical, numerical, and statistical modeling, and risk assessment. The assessment of changing reservoir in-situ conditions, like temperature and pressure variations, may enhance the conception of an appropriate system to resolve the aberrations. Chemical impact assessments, like cement sheath properties assessment, cement sheath deterioration assessment, and casing string monitoring, are required to minimize deterioration of the cement sheath and casing string and to guarantee the provision of an intact isolation system. The mechanical integrity of borehole systems is influenced by subsurface environmental conditions, such as pressure, temperature, material characteristics, and the system’s stress distribution and evolution, it also depends on the operations of the wellbore systems.

Achang et al. (2020) reviewed the body of knowledge to identify the issues encountered during wellbore plugging and abandonment and provided suggestions to aid in mitigating the occurrence of failures, such as using novel plugging and abandonment materials and improved technology geared towards restoring inadequate sealing barriers. The review concluded that achieving permanent plugging would require solving two main issues: (1) enhancement of the sealant medium and (2) improvement and innovations in the barrier placement techniques. Therefore, permanent barrier placement would involve engineered materials and processes suitable to provide adequate barriers both in the early stage (1–50 years) and for the long term (thousands of years to geologic time).

Teodoriu and Bello (2020) reviewed existing methods and laboratory equipment for testing cement integrity under carbon dioxide sequestration conditions. Proposing the need for standardization of cement sheath integrity evaluation technique in CO₂ sequestration sites, the authors suggested that cement sheath degradation test should include: (i) Autoclave testing at reservoir temperature and pressure with a reference test conducted at room temperature; (ii) measurements of mechanical attributes of the altered and unaltered cement sheath (compressive and shear strength, and Young’s modulus); (iii) permeability measurements before and after exposing samples to aqueous CO₂; (iv) microscopic tests of mineralogy and structural variations in the cement sheath. (v) X-ray diffraction measurements of samples before and after exposure to aqueous CO₂; (vi) autoclave setup should maintain steady carbon dioxide saturation by either circulating CO₂-saturated fluid continuously or by continuously injecting CO₂ into the experimental setup.

Gholami et al. (2021) also reviewed the different mechanisms that could result in the creation of leak pathways in CO₂ geosequestration sites and emphasized that cement sheath evaluation strategies are crucial to improving the well-being of injection and sequestration operations. Due to the limitations in the time spent conducting tests in laboratories, the intricacy of processes entailed, and the relatively large response time required for the several chemical reactions that take place in the CO₂ sequestration sites, the results declared from the laboratory investigations are still ambiguous and cannot be compared with field examinations or expectations. The study concluded that geochemical interactions, pressure, and temperature are the key factors that influence leakages in storage sites. However, poor cementing jobs are most likely chiefly responsible for initiating CO₂ leakages around the near-wellbore precinct when injecting and storing CO₂. The study recommended a pilot CO₂ storage project would be required to understand the likely integrity issues of storage sites rather than depending only on laboratory experiments and/or numerical simulations.

Wellbore cement sheath interactions with stored CO₂

Kutchko et al. (2007) performed sets of experimental tests to evaluate the stability of the cement sheath in contact with CO₂ under geologic sequestration conditions (50 °C, 30.3 MPa) for 9 days. For comparison, similar experiments were conducted with cement slurry cured for 28 days at different curing conditions, namely at geologic sequestration condition (50 °C, 30.3 MPa); at ambient condition (22 °C, 0.1 MPa); at high-temperature condition (50 °C, 0.1 MPa); and at high-pressure condition (22 °C, 30.3 MPa). To visualize the carbonation phenomenon of the cement sheath subjected to interaction with aqueous carbon dioxide under simulated geologic CO₂ sequestration conditions (50 °C, 30.3 MPa), a scanning electron microscope (SEM) equipped with a backscattered electron (BSE) image detector and energy-dispersive spectroscopy (EDS) was utilized. The analysis conducted includes measuring the carbonation depth and determining the changes in the cement sheath chemistry and structure [please refer to Kutchko et al. (2007) for details of the procedure]. Figure 1 shows an SEM-BSE image of a cement sheath cured for twenty-eight days at a geologic sequestration condition (50 °C, 30.3 MPa) and exposed to aqueous CO₂ at sequestration condition (50 °C, 30.3 MPa). It illustrates the three distinct regions of the degraded cement sheath sample as visualized via SEM-BSE imaging, naming: 1. calcium hydroxide depleted region; 2. completely carbonated region; and 3. porous silica region. Interestingly, the cement slurry cured at geologic sequestration condition (50 °C, 30.3 MPa) exhibited the best resistance to CO₂ or carbonic attack due to an increased level of hydration resulting in an alteration in the cement sheath’s microstructure and more evenly distribution of portlandite in the cement sheath, which provided a homogeneous and effective fortification to carbon dioxide attack.

Fig. 1

SEM-BSE image of cement sheath cured for 28 days at geologic sequestration conditions (50 °C, 30.3 MPa) and exposed to aqueous CO₂ for 9 days under the same conditions. The image reveals the general degradation that occurs. The degraded portion can be divided into three distinct regions: 1. Ca(OH)₂ depleted region; 2. completely carbonated region; and 3. porous silica region. [With kind permission of the American Chemical Society from Kutchko et al. (2007), Environmental Science and Technology, Vol. 41 (13), Fig. 2, p 4789]

Since most of the wellbores in depleted hydrocarbon provinces would be recycled in cases where depleted reservoirs are targeted for CCS applications, Rimmelé et al. (2008) undertook an experimental study to understand how such existing wellbores, which were cemented with conventional Portland cement, would behave when in contact with CO₂-saturated fluids. For the experiment, samples of set Portland cement were placed in contact with aqueous CO₂ under representative pressures and temperatures that simulate hydrocarbon reservoir in-situ conditions. Two methods were used to establish the chemical interaction of the samples: The transformation of the universal porous network was determined using mercury intrusion porosimetry, while BSE (back scatter electron) image analysis was used to quantify the localized porosity ratios experienced along the samples in contact with CO₂-rich fluids. Both techniques indicated an initially increased confinement capability resulting from produced calcium carbonate precipitates plugging some of the pore spaces in the cement sheath. Afterward, the precipitates of calcium carbonate react with more CO₂ to produce soluble calcium bicarbonate, resulting in a noticeable rise in the cement sheath’s porosity.

Duguid and Scherer (2010) used an experimental approach to determine the consequence of flowing aqueous CO₂ through a wellbore cement sheath. Class-H cement pastes were exposed to carbonated brine at temperatures and pH ranges of 20–50 °C and 2.4–5, respectively. The exposed cement pastes and reactor emissions were later examined using several methods, namely optical microscopy, X-ray diffraction, electron probe microanalyzer (EPMA), and inductivity-coupled plasma optical emission spectrometry (ICP-OES). The findings confirmed that the simulated reservoir conditions during CO₂ storage, with an acidic pH and temperature range of 20–50 °C, resulted in rapid degradation of the Class-H cement in a sandstone environment. The rate of degradation was influenced by the dissolution rate of the CaCO₃-rich layer after its formation. The study indicated the rate of degradation was more influenced by a 30 °C temperature change than a reduction in pH of 2.6 units. Additionally, a 6% bentonite cement sheath degraded faster than a neat cement sheath under similar conditions. The most severe condition with the highest severity in degradation was at pH 2.4 and 50 °C, which corresponds to a 1-km deep sandstone storage terrain. On the other hand, the least severe condition was at pH 5 and a temperature of 50 °C in a calcium-saturated brine environment, which showed no degradation (representing prevailing sequestration conditions at a 1-km deep limestone terrain). It is worth noting that though possible reservoir temperature was simulated in this investigation, the experiments were unfortunately conducted only at atmospheric pressure rather than at typical reservoir pressures. A schematic of the experimental framework is shown in Fig. 2.

Fig. 2

Schematic of flow-through reactor systems indicating the sandstone-like environment reactor (top) and limestone-like environment reactor (bottom) [With kind permission of Elsevier from Duguid and Scherer (2010). International Journal of Greenhouse Gas Control, Vol. 4, Fig. 1, p 547

Emphasizing the long-lasting integrity of wellbores used for carbon dioxide storage as vital in guaranteeing the effectiveness of geologically sequestering CO₂ to alleviate greenhouse gas-induced climate change, Crow et al. (2010) conducted laboratory tests to identify the sealing efficiency of a 30-year-old wellbore located in a natural carbon dioxide production site. The experiments include a wireline review to determine wellbore conditions, mineralogy and hydrology analysis of 10 composites of casing string/cement sheath/formation rock, reservoir fluid sampling, and permeability measurements under reservoir conditions. CO₂ migration through the carbonated cement sheath was observed, and the effective permeability of the composite ranged between 0.5 and 1mD. Interestingly, only minimal fluid migration occurred due to the following reasons: (i) the magnitude of carbonation reduced as the distance from the CO₂ source increased, (ii) the cement sheath possessed very low permeability (approximately 0.3–3 micro-Darcy), (iii) the cement sheath/casing string and cement sheath/ reservoir rock interfaces were solid, (iv) the casing string did not corrode, (v) the sampled reservoir fluids did not contain CO₂, and (vi) the pressure difference between the reservoir rock and the caprock was sustained. They concluded that even after 30 years, the barrier system performance was satisfactory. Based on their study, Portland cement is suggested to be efficient in constructing adequate isolation systems for permanent carbon dioxide sequestration, especially when recommended best practices are followed during wellbore creation. Some of the recommended best practices include centralization of the casing string, complete wellbore mud displacement, and proper cement slurry placement, among others.

Suggesting that in carbon dioxide sequestration wellbores, most of the leakages would occur either through the casing string/cement sheath interface, through the fractures within the cement sheath matrix, or along the cement sheath–caprock interface, William Carey et al. (2010) conducted core-flooding tests to investigate the casing string–cement sheath microannulus. For the experiment, an imitative wellbore system comprising a 5-cm-diameter cement sheath sample, treated with a rectangular steel casing string implant that possessed channels to allow fluid flow, was used. Figure 3 shows a schematic diagram of the core-flooding experimental framework. The reservoir conditions were mimicked by experimenting with a temperature of 40 °C and a pressure of 14 MPa for 394 h. A 6.2-L mixture of 30,000 ppm NaCl-rich brine and supercritical CO₂, in equal ratio, was flown along a 10-cm limestone specimen and then along the 6-cm-long composite cement sheath–casing sample. SEM images of the samples indicated the carbon dioxide-brine mixture affected both the casing string and the cement sheath. The carbonation depth within the cement sheath ranged between 50 and 250 µm, indicating a diffusion-dominated process, while the steel casing string corroded to a depth of 25–30 µm, which aligns with the results obtained from a basic corrosion mode. The authors reported that the cement sheath did not experience any significant erosion, suggesting that a neat Portland cement sheath in a carbon dioxide-brine-rich environment is durable. However, the low-carbon steel casing string corroded and produced substantial quantities of FeCO₃ and CaCO₃ mixture. The sensitivity test of the casing string to corrosion indicates that using straightforward wireline logging to detect corrosion on the outer part of the casing string is a valuable clue of leakage flowing behind the casing string. This study reinforces the finding of other similar studies, suggesting that the rate of Portland cement sheath degradation is low, even when exposed to substantial CO₂-brine-rich fluid flows.

Fig. 3

Schematic of the core flooding experimental set-up [With kind permission of Elsevier from William Carey et al. (2010), International Journal of Greenhouse Gas Control, Vol. 4, Fig. 1, p 273]

Using batch reactors, X-ray microtomography (XMT), and CFD, Um et al. (2014) conducted experimental studies to investigate the changes expected in cement sheath fracture surfaces, fluid flow pathways, and permeability of a composite of Portland cement sheath–basalt caprock. The composite was artificially fractured and placed in a CO₂-saturated aquifer at 50 °C and 10 MPa for three and a half months under fixed conditions to determine the geochemical and geomechanical influences on the integrity of wellbores with defects in their cement sheaths. XMT was used to visualize the orifice and the linkage of a cracked cement sheath, induced by a 27 MPa mechanical stress, shortly before its interaction with CO₂. Additionally, XMT was used to visualize numerous CaCO₃ precipitates inside the cracks present in the cement sheath matrix. However, only a few precipitates of CaCO₃ were observed along the cracks in the cement sheath–basalt interface. The permeability estimated through CFD simulation aligned with the experimentally determined permeability. Their investigation suggests that the fractured matrix of the wellbore cement sheath would likely heal when exposed to a carbon dioxide-saturated aquifer under steady conditions, while the cracks in the cement sheath–caprock interface would most likely continue to pose a risk, providing pathways for CO₂ leakage. Furthermore, in deep subsurface storage sites, geochemical processes and geomechanical activities have a synergistic influence on the growth of wellbore cement sheath fractures and the flow of fluids through the cracked surfaces. These observations and suggestions were validated by Panduro et al. (2017) through similar experiments.

Kjøller et al. (2016) emphasized that preventing carbon dioxide leaks from sequestration sites is crucial for ensuring safe and cost-effective CCS projects. They noted that this can only be achieved by focusing efforts on maintaining wellbore integrity throughout the entire lifespan of the storage wellbores. They reported that cement sheath integrity is particularly important in this regard, as the cement sheath/formation rock interface and cement sheath/casing string interface have been identified in several studies as the most vulnerable regions for potential CO₂ leakage. They studied the effect of flooding a composite of cement sheath/sandstone samples with CO₂-brine water-alternating-gas (WAG) flooding. They observed a reduction in the permeability of the sample after WAG flooding, from 200 to 100 mD. This reduction in permeability was caused by the closure of the fracture system within the cement sheath due to the precipitation of CaCO₃ into the fractures. The closure of the fracture system (self-sealing) was confirmed through various techniques, including visual observation of the sample before and after the flooding procedure, µ-CT scanning data, SEM/EDX data, and chemical data obtained from the effluent during the flooding. Figure 4 presents the micro-computed tomography (µ-CT) images obtained before and after the WAG flooding experiment was performed. The self-healing phenomenon resulting from the carbonation reaction suggests the potential for sealing the existing fracture system within the cement sheath, enhancing its confinement attribute temporarily, provided that the CO₂-saturated brine is not excessive and sufficient to facilitate the bicarbonation of the CaCO₃ precipitate formed within the cement sheath (facilitated by the short residence time of aqueous CO₂ within the cement sheath matrix).

Fig. 4

Micro-computed tomography data for the cement sheath before and after the WAG flooding experiment. a Pore volume in the cement sheath plug before flooding, b Pore volume in the cement sheath plug before flooding together with the cement cylinder c Pore volume in the cement sheath plug after flooding d Pore volume in the cement sheath plug after flooding together with the cement cylinder. [With kind permission of Elsevier from Kjøller et al. (2016), Energy Procedia, Vol. 86, Fig. 7, p 347]

Brunet et al. (2016) developed a process-based reactive transport model to identify the main transport attributes influencing the eventful self-healing (self-sealing) or fracture propagation of cement sheath fractures that are in contact with aqueous CO₂ at in-situ CO₂ geologic storage conditions. Simulations with their model produced an identical interaction network as in the diffusion-dominated systems without flow, where the aqueous CO₂ enhanced the dissolution of the portlandite content in the cement sheath fractures, facilitating the release of Ca²⁺ ions, which reacts with carbonic acid to form CaCO₃. Using the model for CO₂-flooding numerical experiments in 250 cement fractures with different initial hydraulic aperture sizes (b) and residence time (T) [where T is the ratio of the fracture volume to the flow rate], they were able to identify the critical residence time, T_C, which is defined as the minimum residence time required for the self-sealing or self-healing phenomenon to occur. Figure 5 shows a plot of residence time against the initial hydraulic aperture sizes. It visually illustrates the correlation between the critical residence time (T_C) and the initial hydraulic aperture size (b). The value for the critical residence time (T_C) for any given aperture size (b) can be obtained using:

Fig. 5

Predicted self-sealing (self-healing) or fracture opening phenomenon for the CO₂-flooding numerical experiments in 250 cement sheath fractures (Class H) samples with different initial aperture sizes and initial fracture residence times. The black dots indicate the self-sealing phenomenon, while the gray dots represent the fracture opening phenomenon after a 100-day exposure to aqueous CO₂. The thick dash line represents the critical residence time above which self-sealing occurs; the light gray area shows a transition zone, where little changes in the initial fracture residence time and aperture size facilitate a switch between the opening or closing of the fracture; the red line indicates the estimated critical residence time using Eq. 1 [With kind permission of Elsevier from Brunet et al. (2016), International Journal of Greenhouse Gas Control, Vol. 47, Fig. 9, p 35]

$${\mathrm{T}}_{C}=0.00098{b}^{2}+0.254b$$

(1)

From Fig. 5, it is evident that for any given hydraulic aperture, as long as the residence time is greater or equal to the critical residence time, self-sealing occurs because there is sufficient time for the cement sheath matrix and aqueous CO₂ to interact adequately, thereby facilitating the increase of the pH, Ca²⁺ concentration, and CaCO₃ precipitate formation. However, for residence time lower than the critical residence time, due to rapid replenishment of aqueous CO₂, the pH and Ca²⁺ concentration is reduced, leading to the continual dissolution of the cement sheath matrix, thus the fracture opening phenomenon dominates.

Bagheri et al. (2019) suggested that numerical simulations can be used to forecast the life span of cement sheaths exposed to carbon dioxide by incorporating the geochemical processes occurring with the observed geomechanical modifications inside the cement sheath matrix. The authors provided a framework capable of forecasting the potential interaction of the cement sheath with the CO₂-bearing fluids in CO₂ storage scenarios under various reservoir conditions. It was reported that the geochemical reactions and geomechanical alterations in the cement sheath matrix resulted in either radial compaction or radial cracking which may cause CO₂ leakage and compromise the integrity of permanent CO₂ storage sites.

Jahanbakhsh et al. (2021) used prepared sets of composite specimens that mimic the cement sheath–formation rock interface to investigate the geochemical reactions that would occur between the cement sheath–formation rock interface and CO₂-bearing fluids to assess the integrity of the wellbore cement sheath and its interface with the formation rock. The experimental tests simulated a deep wellbore environment to enable the investigation of possible variations in petrophysical, mechanical, and chemical attributes of the prepared samples due to exposure to NaCl-CO₂-rich fluids over an extended period. The specimens were examined using X-ray micro-computed tomography (X-ray µ-CT), X-ray diffraction (XRD), scanning electron microscopy energy-dispersive X-ray (SEM–EDX), and inductively coupled plasma optical emission spectrometry (ICP-OES). This analysis confirmed that the cement sheath deteriorated as a result of its chemical reaction with the NaCl-CO₂-rich fluids. Their observations are consistent with previous findings, namely, initial carbonation increases the mechanical strength and decreases the permeability of the cement sheath, while dissolution increases the permeability of the composite mainly within the sandstone matrix used for the investigation, and reduces the mechanical properties of the composite sample. The geomechanical changes of the sample and the extent of their effects on wellbore integrity depend on various factors, including the acidity of the storage site, the concentration of brine, the pressure within the reservoir, its pore pressure, and the residence time. Figure 6 depicts the experimental system used to measure the stress–strain permeability of a 38-mm-diameter composite sample, while Fig. 7 illustrates the schematic of a hydrothermal high-pressure high-temperature reactor used to execute the flooding procedure.

Fig. 6

Experimental system used to measure the stress–strain permeability of a 38-mm-diameter composite sample [With kind permission of MDPI, from Jahanbakhsh et al. (2021), Energies, Vol. 14, Issues 16, Fig. 2, p 6 of 20]

Fig. 7

Schematic of a hydrothermal high-pressure high-temperature reactor used to execute the flooding procedure (Not drawn to scale) [With kind permission of MDPI, from (Jahanbakhsh et al. 2021), Energies, Vol. 14, Issue 16, Fig. 3, p 7 of 20]

Wang (2021) investigated the self-sealing phenomenon of the wellbore cement sheath in contact with aqueous CO₂ under geologic sequestration conditions by conducting a core flooding experiment with aqueous CO₂ and cement sheath specimens cured at various pressures. The microstructure and mineral compositional modifications were observed using micro-computed tomography (µ-CT), scanning electron microscopy (SEM), and Raman spectroscopy. [Details of the sample characterization techniques used can be found in Wang (2021).] Figure 8, extracted from the paper, illustrates a flowchart of the CT scanning and image analysis program. The µ-CT images of cement sheath specimens after exposure to aqueous CO₂ indicated a dissolution–precipitation–dissolution trend mainly at the outer part of the sample due to the abundant presence of aqueous CO₂. However, the interior orifice of the samples experienced more CaCO₃ precipitation and a reduced degree of dissolution due to a limited supply of aqueous CO₂. This suggests the possibility of the self-sealing phenomenon occurring within the fractures of the cement sheath exposed to aqueous CO₂. The influence of curing pressure on the composition of the resulting cement sheath was determined through CT scans and SEM characterization. Higher curing pressures resulted in the production of more calcium hydroxide during the hydration of the cement slurry, leading to increased precipitation of CaCO₃ when exposed to aqueous CO₂. Interestingly, higher curing pressures favored the production of larger CaCO₃ crystals within the fractures of the cement sheath, which is beneficial for the self-sealing phenomenon. Furthermore, post-carbonation analysis using Raman spectroscopy revealed the disappearance of the –OH band and the appearance of the C=O band within the cement sheath samples. This confirms the transformation of Ca(OH)₂ into CaCO₃ due to the carbonation of the cement sheath in contact with aqueous CO₂. The characteristic peak of the Raman spectra was located at approximately 280 cm⁻¹, indicating the formation of calcite as the CaCO₃ product.

Fig. 8

CT scanning and image analysis program [With kind permission of Elsevier, from Wang (2021), Applied Geochemistry, Vol. 126, 104,937, Fig. 2]

Gan (2022) conducted a series of experiments to investigate the modification of the flow conduit width in cement sheath exposed to aqueous CO₂ at in-situ CO₂ geologic storage conditions. The study aimed to identify the influence of effective stress and flow rate of the aqueous CO₂ on the microstructural modification of the flow conduit. Various flow conditions, including flow-through and static conditions, were examined under effective stress conditions of 3 MPa and a condition without effective stress. X-ray micro-computed tomography was utilized to visualize and identify the microstructural changes in the flow channels and the locations of the dissolved Ca(OH)₂/C–S–H and calcite precipitation regions near the flow conduit after interaction with aqueous CO₂. Interestingly, the results indicate that flow channels or fractures propagate (open) when the flow rate (or velocity) is relatively high and the residence time is short. Conversely, under static conditions (or low flow rate) with a longer residence time, the self-sealing phenomenon of the flow channel occurs. This finding is consistent with the findings of Brunet et al. (2016). Notably, the effective stress and flow rate of aqueous CO₂ synergistically influences the microstructural changes in the flow channels or fractures present in the cement sheath. Consequently, a cement sheath exposed to a high concentration of CO₂ is at a high risk of experiencing CO₂ leakage.

Mechanism of cement sheath failure in CO₂ storage sites

Extracted from Kutchko et al. (2007), Fig. 9 illustrates the mechanism of cement sheath degradation due to its interaction with aqueous CO₂ or carbonic acid in CO₂ storage sites.

Fig. 9

Schematic diagram revealing the dissolution, calcium migration, and creation of distinct regions within the cement sheath in contact with aqueous CO₂. Equation numbers denote chemical interactions that occurred at each stage as presented below. Note: Within the cement sheath structure, local pH is buffered by CaCO₃ and Ca(OH)₂. [With kind permission of American Chemical Society from Kutchko et al. (2007), Environmental Science and Technology, Vol. 41 (13), Fig. 3, p 4789]

Stored aqueous CO₂ dissolves with available aquifer within the CO₂ storage sites to form carbonic acid (Eq. 2)

$${\text{CO}}_{2} \left( {aq} \right) + {\text{H}}_{2} {\text{O}} \to {\text{H}}_{2} {\text{CO}}_{3} \left( {aq} \right)$$

(2)

Initially, the pH of the cement sheath is around 12.5. As the aqueous CO₂ diffuses into the cement sheath matrix, the carbonic acid dissolves the cement sheath's portlandite content (Ca(OH)₂).

$${\text{Ca}}\left( {{\text{OH}}} \right)_{2} \left( s \right) \to {\text{Ca}}^{2 + } \left( {aq} \right) + 2\left( {{\text{OH}}} \right)^{ - } \left( {aq} \right)$$

(3)

This dissolution action increases the porosity of the cement sheath matrix and facilitates the leaching of Ca²⁺ out of the cement sheath matrix. The leached Ca²⁺ reacts with HCO₃⁻ in the incoming carbonic acid to form CaCO₃(s) precipitates in the cement sheath matrix.

$${\text{Ca}}^{2 + } \left( {aq} \right) + {\text{HCO}}_{3}^{ - } \left( {aq} \right) + {\text{OH}}^{ - } \left( {aq} \right) \to {\text{ CaCO}}_{3} \left( s \right) + {\text{H}}_{2} {\text{O}}\left( l \right)$$

(4)

As shown in Fig. 9, the precipitation of CaCO₃ is facilitated by the interaction of Ca²⁺ diffusing from the cement sheath and the inward diffusion of the aqueous CO₂. The produced CaCO₃ initially improves the confinement capability of the cement sheath and is less soluble than the portlandite content (Ca(OH)₂). However, when the Ca(OH)₂ content has been depleted, the produced CaCO₃ precipitate starts to dissolve due to the presence of excess carbonic acid, forming Ca(HCO₃)₂.

$${\text{CaCO}}_{3} \left( s \right) + {\text{H}}_{2} {\text{CO}}_{3} \left( {aq} \right) \to {\text{Ca}}\left( {{\text{HCO}}_{3} } \right)_{2} \left( {aq} \right)$$

(5)

This bicarbonation phenomenon is the primary cause of the deterioration phenomenon of cement sheaths exposed to aqueous CO₂. Due to the bicarbonation of CaCO₃(s), the cement sheath can no longer buffer the pH, and the enduring C–S–H phase within the vicinity converts to amorphous silica gel.

$${\text{C}} - {\text{S}} - {\text{H}}\left( s \right) \to {\text{Ca}}^{2 + } \left( {aq} \right) + {\text{OH}}^{ - } \left( {aq} \right) + am.{\text{SiO}}_{2} \left( s \right)$$

(6)

The resultant degraded cement sheath becomes highly porous and weakened, potentially facilitating CO₂ leakage pathways.

While mechanical and chemical degradation is two mechanisms that can result in cement sheath failure in CO₂ storage sites, Bois et al. (2013) proposed an integrated perspective to consider all events and lifecycle of the wellbore, focusing on the mechanical mechanisms that may cause cement sheath failure before and during the CO₂ injection phase. The integrated perspective includes two sets of assessments: The first investigates the chemical alteration of the cement sheath in a CO₂-enriched environment, while the second examines the potential mechanical damage of the cement sheath. The chemical alteration investigation involves the kinetics of the CO₂ reaction and provides a mathematical equation to simulate the mechanical action of a chemically degraded cement sheath. The second investigation provides information on the mechanical behavior of the cement sheath under in-situ reservoir conditions and presents a set of mathematic equations to simulate all phases of the wellbore life cycle. This study demonstrates the feasibility of assessing mechanical damage in the wellbore and utilizing a chemo-thermo-poro-mechanical model to determine the effect of the CO₂-enriched environment.

Walsh et al. (2014a, b) conducted core flooding experiments to examine the influence of aqueous CO₂-induced reaction regions on the mechanical and hydraulic properties of fractures and interfaces in the cement sheath. They introduced carbonated brine (aqueous CO₂) into artificially created fractures within the cement sheath and tight-sandstone core samples for their experiments. The altered cement sheath/caprock interfaces were characterized using X-ray computed microtomography (XRCT) before and after the carbonation process. They also investigated the effect of the modified mechanical properties on hydraulic aperture using X-ray computed micro-tomography particle image velocimetry (XRCT-PIV), direct nano-indentation, and digital image correlation. Based on the experimental data, they developed a model that correlates the reaction zones with the mechanical response of the cement sheath interfaces. This model employs numerical simulations to characterize cement sheath interfaces over the long term.

Highlighting the importance of wellbore cement sheath in providing support and confinement throughout the lifecycle of the wellbore and noting that variations in temperature and pressure in the wellbore system could lead to various failure mechanisms endangering the integrity of the cement sheath, De Andrade and Sangesland (2016) conducted an elaborate numerical study using the finite element method (FEM) to assess the dominant factors contributing to the development of cement sheath integrity loss, with a special focus on thermal-related situations. The study suggested that the main physical attributes affecting the failure mechanism of the cement sheath are the Young’s modulus of the cement sheath and the formation, with their ratio (E_cem-to-E_for ratio) being load-case dependent. Loss of cement sheath integrity caused by a significant increase in casing string internal pressure depends significantly on the E_cem-to-E_for ratio. The probability of tensile radial cracks reduces substantially when the ratio of E_cem-to-E_for is less than unity (1). In thermal-related events, such as the commencement of production or injection in a wellbore, the ratio does not significantly influence failure. However, cooling events are more likely to lead to cement sheath defects compared to heating events. Debonding failures are predominantly associated with a reduction in temperature while tensile radial cracks are mainly associated with pressure testing. The presence of initial defects, such as fractures, voids, or debonded areas, and lack of casing string centralization usually leads to a higher likelihood of localized cement sheath impairment near the thinner part of the cement sheath. Shear and radial cracks and debonding defects are closely correlated with in-situ stress. Interestingly, increased in-situ stresses result in reduced occurrences of cement sheath impairment. For thermal-related events, the occurrence of cement sheath failures is influenced by differences in thermal expansion factors and other mechanical properties, such as Young’s modulus and Poisson’s ratio at reservoir in-situ conditions. Therefore, manipulating only the cooling and heating rates of the wellbore has limited benefit in addressing the risk of cement sheath failure. Extracted from Gasda et al. (2004), Fig. 10 illustrates a schematic of the wellbore leakage mechanism in a plugged and abandoned wellbore.

Fig. 10

Schematic representation of wellbore leakage mechanism in plugged and abandoned wellbores. Migration pathways could occur along the casing-cement sheath interface (a, b), via cement sheath matrix permeability (c), through corroded steel casing (d), or fractures within the cement sheath (e), or along the cement sheath–rock interface (f). [With permission of Springer Science and Business Media, from (Gasda et al., 2004), Environmental Geology, Vol. 46, Fig. 1, p 709]

Figure 11 presents an example of the FEM methodology used to assess the cement sheath failure mechanism, in this case describing the shear failure.

Fig. 11

Methodology for assessing cement sheath failure mechanisms, described for shear failure. [With kind permission of Elsevier from Andrade and Sangesland (2016), Journal of Petroleum Science and Engineering, Vol. 147, Fig. 7, p 688]

Li et al. (2016) utilized the principle of geometric analogy and stress conformity to design a wellbore simulator. The simulator was used to simulate the actual casing schedule, reservoir temperature, and pressure, regular variations in the internal casing string pressure, and even produced a sealing phenomenon analogous to the real cement sheath under fluctuating dynamic situations The simulation revealed that at low storage pressures, the cement sheath suffered tensile fractures, resulting in radial cracks. At high storage pressures, the pore volume is reduced, leading to a decrease in the overall volume of the cement sheath and the formation of microannuli in the interfacial space between the casing string and the cement sheath (debonding). CT and EDS scans of the cement sheath interior revealed a notable disparity in the particle distributions between the cement sheath matrix and the interface. Particles with higher strength moved away from the interface, while particles with lower strength were pulverized at the interface. The density at the interior was higher than the density at the interface. The study suggests that the loss of confinement integrity of the cement sheath can be attributed to two main causes: tensile fracture at low storage pressure and segregation of the cementing plane at higher storage pressure, resulting in microscopic pore volume reduction and the pulverization or movement of lower strength particles at the interface.

To study the impact of thermal expansion annular pressure on the mechanical integrity of the cement sheath in high-pressure high-temperature (HPHT) gas wellbores, Zhang and Wang (2017) proposed a model that incorporates thermal expansion annular pressure to calculate the cement sheath safety factor. The study reported that the cement sheath safety factor reduces vastly with increasing thermal expansion annular pressure and may widen the failure pathway in the cement sheath. The authors also noted that the cement sheath safety factor is highest when the disparities in the thermal expansion coefficient of the casing string, cement sheath, and formation are minimal. The isosurfaces of the cement sheath at various thermal expansion annular pressures and temperatures were used to determine the critical values of factors that ensure cement sheath mechanical integrity, including thermal expansion coefficients, temperature, elasticity modulus, and Poisson’s ratio. The article suggests the introduction of annular pressure management during production to periodically release annular pressure after significant pressure build-up to ensure safe production, especially in HPHT gas wellbores.

Zeng et al. (2019) presented a large-scale scaling evaluation equipment suitable for determining the mechanisms of cement sheath failure under cyclic loading conditions at a reservoir in-situ environment. The equipment consists of a wellbore, pressure control, and data acquisition systems. The equipment has a pressure limit of 120 MPa and a temperature limit of 150 °C, with accuracies of 0.01 MPa and 0.12 °C, respectively. This facilitates precise pressure change recording, accurate automatic gas channeling detection, and measurement of vent gas volume. Using finite element methods (FEM), the stress and strain of the wellbore system and the sealing equipment under internal pressure were studied. Based on the test results and the FEM calculations, the mechanisms for the loss of confinement integrity were deduced. Plastic deformation occurs during the loading phase at higher internal pressures due to the residual strain remaining after unloading the cement sheath, leading to incompatible deformation and an increase in tensile stress at the cement sheath interface. With cyclic loading (repeated loading and unloading), the plastic deformation increases, and so does the residual strain and interfacial tensile stress. When the interfacial tensile stress exceeds the bond strength at the interface, a microannulus is created between the casing and the cement sheath, resulting in an issue with the integrity of the cement sheath.

Vrålstad and Skorpa (2020) proposed an experimental approach that utilizes X-ray computed tomography to visualize the fractures and microannuli in wellbore cement sheaths. Their methodology provided valuable insights into cement sheath failure mechanisms: Radial cracks do not usually form in predictable and symmetric forms; instead, they typically result from a single crack that propagates to subsequent cracks. These cement sheath cracks eventually propagate into the surrounding formation. The geometries of microannuli are usually random and non-uniform, with a heterogeneous aperture around the circumference, they depend mainly on how they were formed. As a result, fluid flow through the microannuli and cracks cannot be accurately modeled using Darcian linearity due to localized heterogeneities and complex flow patterns. The authors reported that their methodology could be a valuable approach to validate existing simulators used for predicting hydraulic and mechanical cement sheath integrity and could also support improvements in the generated models. Figure 12 shows the X-ray computed tomography 3D visualization of interior fractures created in a cement sheath with numerous initial defects undergoing thermal cycling.

Fig. 12

X-ray computed tomography 3D visualization of internal fractures created in a cement sheath with numerous initial defects during thermal cycling. (The resolution of CT images is approximately 200 µm) [With kind permission of MDPI, from Vrålstad and Skorpa (2020), Sustainability, Vol. 12, 4128, Fig. 5]

To assess cement sheath integrity in CO₂ injection wells, Dong et al. (2020) demonstrated that using a single-phase flow model for 100% carbon dioxide, the temperature and pressure profile of the wellbores could be estimated using finite difference methods. Their proposed mechanical model could predict the stress state-of-the-art wellbore segment under the plane-strain condition and the stress intensity factor at the radial crack tip. The study identified four failure modes: shear cracking (compressive failure), radial cracking, interfacial debonding, and fracture propagation. Through parametric studies, the impact of various injection parameters on the identified failure modes was revealed, including injection temperature, injection rate, and injection duration. The study suggests that the injection rate was the most significant influencing parameter on cement sheath integrity. Higher injection rates may lead to radial cracking and/or its propagation and interfacial debonding while reducing the occurrence of shear cracking. Lower temperature and/or longer injection time could compromise the cement sheath’s tensile strength, and interfacial strength or support the propagation of existing radial cracks in the cement sheath. The study was projected to provide valuable insights into optimizing CO₂ injection activities for permanent wellbore integrity in CO₂ injection wellbores.

Procedures for evaluating cement sheath integrity in wellbores used for CO₂ storage

There are several available techniques for evaluating the integrity of cement sheaths used in completing subsurface wellbores. Some of the commonly available techniques include:

• Cement bond logs (CBL): CBLs are acoustic measurements that assess the bond between the casing and the cement sheath. The tool emits sound waves that bounce back from the cement sheath, providing information about its thickness and quality.

• Ultrasonic logs: Ultrasonic logs utilize high-frequency sound waves to evaluate the quality of the cement sheath. This technique can detect voids, cracks, and other defects in the cement sheath.

• Temperature logs: Temperature logs can be employed to identify the movement of fluid behind the casing by detecting temperature changes in the wellbore. If the fluid is flowing through gaps in the cement sheath, it will create detectable temperature anomalies.

• Pressure testing: Pressure testing involves applying pressure to the wellbore and monitoring the pressure response. This method can identify leaks or other integrity issues within the cement sheath.

• Tracer tests: Tracer tests involve injecting a chemical tracer into the wellbore system and monitoring its movement. If the tracer is detected in unexpected locations, it may indicate an integrity issue within the cement sheath.

Each of these techniques has its advantages and limitations, and the choice of the most appropriate technique(s) depends on the specific wellbore environment and the objectives of the evaluation. A combination of multiple techniques may be used to provide a comprehensive evaluation of the cement sheath integrity.

When the cement sheath is in contact with aqueous CO₂, there is the risk of degradation of the cement sheath and the potential of CO₂ leakage through the cement sheath matrix or interface with the formation rock or casing string. The following are additional techniques that could be used to evaluate the integrity of cement sheath exposed to aqueous CO₂:

• X-ray diffraction (XRD): XRD is a technique used to identify the mineralogical modifications within the cement sheath resulting from exposure to aqueous CO₂. It can detect the formation of carbonates and other minerals that can affect the strength and stability of the cement sheath.

• Scanning electron microscopy (SEM): SEM is a microscopy technique that visualizes the microstructure of the cement sheath and identifies any damage caused by exposure to CO₂. It can detect the formation of micro-cracks, porosity, and other defects that affect the integrity of the cement sheath.

• Permeability testing: Permeability testing measures the ability of the cement sheath to resist fluid flow. By exposing cement sheath specimens to aqueous CO₂ and measuring changes in permeability, the integrity of the cement sheath can be evaluated.

• Mechanical testing: Mechanical testing evaluates the strength and stability of the cement sheath of cement sheath in contact with aqueous CO₂. It involves subjecting the cement sheath to stress and strain to identify changes in its mechanical properties caused by CO₂ exposure.

• Electrical resistivity imaging (ERI): ERI is a geophysical technique that evaluates the distribution of fluids and solids around the wellbore. By measuring changes in electrical resistivity, it is possible to identify leakage pathways or other integrity issues within the cement sheath.

It should be noted that some cement sheath integrity evaluation techniques are already introduced or discussed in Sects. "Mechanism of cement sheath failure in CO₂ storage sites" and "Procedures for evaluating cement sheath integrity in wellbores used for CO₂ storage" of this article, where factors influencing the cement sheath’s integrity and failure mechanisms were discussed. However, additional references will be discussed below to present more evaluation techniques that were not adequately addressed earlier.

Regarding CO₂ leakage, it is most likely to occur through various routes within a wellbore, particularly around the “disturbed zone” near the casing string. The disturbed zone refers to the region next to the outer surface of the casing string, including the cement sheath, the damaged region of the formation rock, and the interfaces between the casing string and the cement sheath, as well as between the cement sheath and the formation rock. (Gasda et al. 2011) conducted a study to analyze the integrity of wellbores exposed to aqueous CO₂ for an extended period. They highlighted the significance of the effective permeability of the disturbed zone as a crucial parameter for numerical model validation of wellbore integrity. The effective permeability determines the cement sheath’s ability to maintain or lose its confinement attribute over time and prevent or facilitate CO₂ leakage. If the effective permeability of the disturbed zone is too high, a leakage pathway may be created, compromising the integrity of the cement sheath. The effective permeability is influenced by factors such as long-term exposure to hostile reservoir fluids, faulty wellbore completions, or adverse effects resulting from fluid withdrawal (production) through the wellbore. The authors presented results from a new investigation involving multiple CO₂-producing wellbores. One notable test conducted was the vertical interference test (VIT), which involves perforating the wellbore casing in two distinct regions: the shale region and a region of the cement sheath with inferior-quality bonding. The test aimed to determine the hydraulic communication level through the wellbore casing periphery. By isolating the perforated intervals using an expandable packer, the setup was pressurized at a fixed pressure, and the transient pressure response of the lower interval was recorded. The extent of hydraulic communication in the system could be calculated from the pressure transient data, providing an estimate of the effective wellbore permeability. The authors also compared two types of automated wellbore permeability evaluation techniques, namely “nonlinear regression and shuffled complex evolution metropolis technique,” and demonstrated that key parameters crucial to wellbore integrity can be identified from VIT field test data, reducing the unpredictability associated with wellbore integrity. Figure 13 presents a simplified diagram of the VIT experimental setup.

Fig. 13

Schematic of vertical interference test (VIT) experimental set-up [With kind permission of Springer Science and Business Media, from Gasda et al. (2008), Environmental Geology, Vol. 54, Fig. 1, p 1208]

Noting that approximately 45% of the wellbores in the Gulf of Mexico (GOM) experience sustained casing pressure resulting from leaks, Johns et al. (2011) proposed an effective and accurate method of detecting leaks. Unlike conventional methods such as temperature tools, spinners, noise logs, calipers, and isolation packers, their proposed method, the ultrasonic leakage detection approach, is an adequate and cost-effective approach capable of detecting even small leaks as little as 0.024 gpm. The frequency spectrum produced by leaks depends on the differential pressure, leak magnitude, and leak geometry, determining whether the leak frequency is audible, ultrasonic, or both. The authors developed an ultrasonic logging tool based on this premise. The tool includes a set of bandpass filters capable of isolating all audible noise resulting from tool motion, enabling uninterrupted logging. Additionally, since ultrasonic energy can travel through compressed gases and carbon steel, the tool can also be used to locate leaks through the casing strings. The ultrasonic energy dissipates rapidly, allowing for precise leak detection. The authors proposed utilizing their method in conjunction with other conventional logging techniques to facilitate a comprehensive evaluation of the wellbore integrity. The use of the ultrasonic leakage detection tool is expected to aid in better planning and execution of remedial works. The authors even indicated that ultrasonic leak detection tools are capable of detecting small leaks that may be undetectable by conventional alternatives. They revealed their methodology is capable of promptly detecting leakages as little as 0.005 gpm with a high precision of less than a foot.

Highlighting the importance of collecting data to estimate CO₂ leaks through abandoned wellbores for evaluating CO₂ geosequestration sites, (Deisman 2013) developed a field-scale testing scheme to assess wellbore integrity for the “International Energy Agency Green House Gas Weyburn-Midale CO₂ Monitoring and Storage Project”. Two borehole tools were fabricated to support this field-scale testing scheme: a pressure transient test (PTT) tool and a cement coring (CemCore) tool. The PTT tool was designed to create two perforated slots along the casing string and cement sheath, with a regulated pressure applied to the upper slot while measuring the pressure response at the lower slot. The PTT tool also has a four-packer system with pressure and temperature detectors installed within and transported via coiled tubing. The four packers can withstand a 1000 psi pressure difference and are regulated separately. The detectors and packer pressure lines are accommodated within a 1000-m coiled tubing reel and it is wielded by a regular coiled tubing rig. The PTT tool is regulated and data is obtained via the transient control unit, which accommodates the packer pressure control board, data acquisition system, and pumps that transfer the transient pulse to the tool. Data generated from the PTT tool are used to estimate the vertical permeability of the near-wellbore region and the cement sheath, including its interfaces with the casing string and the reservoir rock. Figure 14 shows a photograph of the complete PTT tool revealing the internal instrumentation, packers, and receiving ports. The CemCore tool, adapted from the MaxPERF technology developed by Penetrators, is capable of collecting cement sheath and formation rock specimens during field operations.

Fig. 14

The complete PTT tool revealing the internal instrumentation, the packers, and the receiving ports [With kind permission of Elsevier, from Deisman et al. (2013), International Journal of Greenhouse Gas Control, Vol. 165, Fig. 32, p 565]

Unfortunately, cement sheath assessment is usually restricted to running a cement bond log (CBL) and attempting to interpret the result to establish the adequacy of the cement sheath’s confinement attributes in the wellbore system. However, interpretations are often done with limited details about the drilling and completion of the wellbore, and information about the cementing systems used is frequently missing. Proper cement evaluation begins with defining the objectives of the cementing operation, identifying any limitations or challenges in the design, executing the job according to the design, and evaluating the job to ensure that the objectives are met. Cement sheath evaluation heavily depends on the substance in the annular space. Cement sheath attributes such as density and strength are key variables required to calibrate the log data. Benge (2015) reviewed several techniques of cement sheath evaluation, including casing and formation pressure testing, and sonic and ultrasonic logs, with the assumptions and limitations of each method identified. Choosing a suitable assessment technique and understanding the type of data needed to apply that technique can enhance the quality of the evaluation.

Proposing that evaluating the wellbore integrity of CO₂ storage facility is feasible only through indirect means that require an elaborate understanding of the relevant thermal, hydraulic, mechanical, and chemical phenomena affecting wellbore integrity, Bai et al. (2015) proposed an evaluation procedure that incorporates qualitative features, events, and processes (FEPs) analysis, scenario analysis, quantitative model development, and consequence analysis. The qualitative analysis facilitates a robust and extensive review of the FEPs that influence the wellbore integrity, while the mechanical model demonstrates the stress distribution of the casing string/cement sheath/formation rock composite system and quantifies the defect dimension resulting from different loading scenarios. The defect dimension can be used to estimate the effective permeability of the cement sheath by using empirical correlations, which is a useful parameter for assessing the likelihood of CO₂ leakage. The proposed integrated approach combines qualitative FEPs and scenario analysis with quantitative model development and consequence analysis as depicted in Fig. 15.

Fig. 15

Flowchart of the proposed integrated approach for wellbore integrity evaluation [With kind permission of Society of Petroleum Engineers, from Bai et al. (2015), SPE Journal, SPE-173000-PA, Fig. 2, p 629]

The first step involves an analysis of all FEPs that affect long-lasting wellbore integrity, whereby features are composed of all static variables and parameters associated with the CO₂ storage system; Processes are defined as all surface and subsurface processes that describe the present and future physical, chemical, and biological dynamic aspects of the storage system, while events are future changes of features and processes or potential occurrences. The general idea of the FEP analysis is to identify rational justifications for the model development which includes a geomechanical model, a chemical model, and a CO₂-leakage model. The simulation results and FEP analysis revealed that the most vulnerable components for leakages include the cap rock, casing string/cement sheath/formation rock composite system, and abandonment elements.

Stating that the porosimetric parameters of wellbore cement sheath and formation rock are the most indicative of the confinement attribute of the cementing system, (Labus and Such 2016) conducted an experimental investigation using mercury intrusion porosimetry (MIP), gas adsorption technique, and X-ray microtomography (XMT) to analyze the porosity of the cement sheath and the formation rock samples. They indicated that XMT is the most suitable technique for visualizing cement sheath deterioration at the formation rock–cement sheath interface, and for studying the microstructural evolution resulting from CO₂-facilitated degradation. Figure 16 shows an SEM image of the CaCO₃ precipitate produced within the interfacial space between the cement sheath and the formation rock. The gas adsorption technique allows for a thorough inspection of nanopores in formation rocks or cement sheath matrices, enabling material classification based on pore structure. XMT enables imaging of cement deterioration at the formation rock–cement sheath interface due to the densities differential of the affected regions, resulting from the dissolution of the formation rock or cement sheath and the production of a new precipitate. Their methodology may be useful for predicting well integrity, particularly when the caprock and reservoir rock differs.

Fig. 16

SEM image of calcite precipitate formation at the contact zone between the cement sheath and the quartzite sandstone formation [With kind permission of Elsevier, from Labus and Such (2016), Journal of Petroleum Science and Engineering, Vol. 138, Fig. 8, p 84]

Islam and Sun (2017) evaluated the feasibility of using temperature as a measure for detecting leaks from wellbores using numerical simulations to mimic temperature distribution through and around the wellbore when leaks occur. Since the leaking fluid is hotter than the surrounding formation, a temperature pulse near the source of the leak around the wellbore is expected which can be detected by deploying distributed temperature sensing (DTS). The temperature signals obtained from the simulations were localized and confined to the close neighborhood of the wellbore within a 3 m radial distance. Although the quantitative results may vary for different geologic formations with different heat transfer coefficients, the authors concluded that their proposed methodology would be useful in monitoring leaks.

Miao (2020) developed an image-processing framework for characterizing the evolution of wellbore cement sheath’s microstructure alteration in contact with aqueous CO₂ at geologic CO₂ sequestration conditions. Their framework enables the mapping of mineral dissolution and precipitation and the characterization of carbonate configuration. The procedure in the framework involves registering X-ray computed tomography images both before and after the cement sheath interactions with aqueous CO₂, generating a difference image to reveal chemical alterations and surveying the difference image to show localized attributes, delineating carbonate configuration, and developing additional images including the skeleton, 3D local thickness, and surface boundaries of the carbonated zones. The framework allows for geometry measurements of the area, thickness, penetration depth, and pore/calcite/portlandite content modifications of the carbonate configuration. The authors reported that the developed framework provides better observable results of aqueous CO₂-induced chemical modification than direct visualization from the original CT images, and the structural characterization of the carbonate configuration offers a clearer understanding of the spatial distribution of the carbonation phenomenon. However, the authors acknowledged that future work is needed to improve the segmentation method for separating intersecting configurations to enable the application of the framework in analyzing time-series cement sheath CT images obtained at different periods for proper quantification and classification of the degree of carbonation.

Discussion of results

This study aimed to address the importance of wellbore integrity in the geological storage of CO₂ and specifically focused on the evaluation techniques for cement sheath integrity. The wellbore integrity is a crucial factor in the success of CO₂ geosequestration operations, as it can prevent the migration of stored CO₂ and ensure the long-term containment of carbon dioxide.

In this study, through a review of the existing body of knowledge, attempts were made to provide and discuss the cement sheath integrity evaluation techniques of wellbore used for geologic carbon dioxide storage operations. Though the main focus of the manuscript was to provide the state of the art, as regards available integrity evaluation techniques of cement sheath of the wellbore in contact with aqueous CO₂, the approach used also considered reviewing articles that discussed cement sheath integrity to be abreast with the factors and variables that affect the integrity of cement sheath exposed to aqueous CO₂. This was to provide a background that explains the long-term interactions of stored CO₂ with the cement sheath within carbon dioxide storage sites and identify the types and mechanisms of cement sheath failures in CCS operations to expect.

In geologic CO₂ storage media, CO₂ interacts with formation fluids to form carbonic acid whose pH is less than 6, while conventional OPC (ordinary Portland cement) used in cementing is alkaline with a pH greater than 12.5. Hence, CO₂ is not thermodynamically compatible with conventional OPC. The calcium hydroxide (portlandite) phase of conventional OPC cement sheath reacts with the carbonic acid to produce calcium carbonate, which initially reduces the cement sheath's porosity and permeability and also increases its mechanical strength, all these effects are desirable because the confinement capabilities of the cement sheath are enhanced. However, the calcium carbonate formed further reacted with more carbonic acid in place to form leachable calcium bicarbonate, which readily dissolves in the formation fluid and gets leached away if a leakage pathway is available. Though the degradation of the cement sheath is slow, the rate of degradation is generally influenced by the in-situ conditions of temperature and pressure of the storage medium; the types/nature of reservoir fluids present, the type and formulation of cement used during the completion of the wellbore, and the operations of the wellbore systems. It is worth noting that the initial carbonation in some instances, aids in self-sealing the cement sheath if there was any crack or fracture present after the cementation of the wellbore. The self-sealing phenomenon of the fractures within the cement sheath matrix due to its exposure to aqueous CO₂ requires sufficient time which must be greater or equal to the minimum critical residence time required to facilitate the increase of the pH and Ca²⁺ concentration and CaCO₃ precipitate. However, if the residence time of the aqueous CO₂ supply is lower than the critical residence time, usually when its flowrate is relatively high, due to rapid replenishment of aqueous CO₂, the pH and Ca²⁺ concentration is reduced, leading to the dissolution of the cement sheath matrix resulting from its bicarbonation, thus facilitating fracture opening or propagation phenomenon dominating the self-sealing process.

Types of cement sheath failure could be categorized as either mechanical or chemical degradation. It is crucial to use cementing best practices when completing a wellbore to avoid mechanical degradation since chemical degradation of a properly completed wellbore would take a longer time for initiation, while the interaction of CO₂ with cement sheath that has any form of mechanical degradation provides a localized soft spot for chemical degradation and rapid propagation of existing fractures which in turn provides a leakage pathway. Some of the recommended cementing best practices are centralization of the casing string, complete wellbore mud displacement, and proper cement slurry placement, among others. Interestingly, the interfaces between the formation rock and the cement sheath or between the casing string and the cement sheath are more vulnerable to creating leakage pathways than through the cement sheath matrix. The mechanical failure mode of cement sheath includes radial cracking, shear cracking (also known as plastic deformation), debonding between the casing string and the cement sheath (inner debonding), debonding between the formation rock and the cement sheath (outer debonding), incomplete cementing also known as channeling (either partially cemented or absence of cement sheath in the annular space between the formation and the casing or in-between casings). Shear and radial cracks are predominantly associated with in-situ stresses with the risk of such failures higher when the formation’s Young’s modulus is larger than the cement sheath’s Young’s modulus while debonding failures are mostly caused by thermal stress (cycling) especially due to rapid cooling of the wellbore; however, the cement sheath safety factor is maximized when the disparities in the thermal expansion coefficient of the casing string, the cement sheath, and the formation rock are minimal. Failure criteria for cement sheath mechanical failure can be categorized based on the different failure modes: (1) Radial cracking occurs when the cement sheath experiences tensile stresses that exceed its tensile strength. The failure criterion for radial cracking is often defined in terms of the maximum allowable tensile stress or strain; (2) shear cracking or plastic deformation of the cement sheath occurs when shear stresses surpass the shear strength of the cement. Its failure criterion can be defined in terms of the maximum allowable shear stress or strain. (3) Inner debonding failure mode can be determined by evaluating the bond strength between the cement sheath and the casing string. Its failure criterion can be defined as the maximum allowable bond strength or debonding length. (4) Outer debonding occurs when the cement sheath detaches from the formation rock, its failure criterion is determined by evaluating the bond strength between the cement sheath and the formation rock. (5) The failure criterion for channeling can be expressed in terms of the maximum allowable void fraction or absence of cement sheath within the annular space between the casing string and the formation rock. These failure criteria are crucial for assessing the mechanical integrity of cement sheaths and ensuring their ability to withstand the loads and environmental conditions encountered in geologic CCS projects. By considering these criteria, engineers and researchers can design cementing operations and wellbore systems that minimize the risk of cement sheath failure and maintain the integrity of the CCS infrastructure.

For chemical degradation, stored CO₂ dissolves with the available aquifer within the CO₂ storage media to produce carbonic acid. Since the pH of the cement sheath is around 12.5, as the carbonic acid diffuses into the cement sheath, the portlandite (Ca(OH)₂) phase gets dissolved to release Ca²⁺ which reacts with the incoming carbonic acid to produce CaCO₃(s) precipitate within the cement sheath matrix. However, once the portlandite content has been depleted, the CaCO₃(s) precipitate begins to dissolve due to the presence of excess carbonic acid to produce calcium bicarbonate (Ca(HCO₃)₂). This bicarbonation process is responsible for the chemical degradation of the cement sheath when in contact with aqueous CO₂ for a long time. Also, due to the dissolution of CaCO₃ precipitate, the cement sheath loses its ability to buffer the pH, leading to the remaining C–S–H phase within the vicinity getting transformed to amorphous silica gel, which is highly porous and weakened and may facilitate the generation of a leakage pathway for the stored CO₂. Failure criteria for cement sheath chemical degradation can be defined based on the extent of degradation or damage caused by chemical reactions in aqueous CO₂. Some commonly considered failure criteria for cement sheath chemical degradation are (1) Degradation depth: the depth of chemical degradation in the cement sheath can be used as a failure criterion. It is determined by measuring the extent of chemical dissolution or erosion that has occurred on the cement surface. A certain maximum allowable degradation depth can be defined to ensure the long-term integrity of the cement sheath. (2) Calcium bicarbonate formation: one of the main chemical reactions that occur between the cement sheath and aqueous CO₂ is the formation of calcium bicarbonate. The failure criterion for chemical degradation can be defined in terms of the maximum allowable amount of calcium bicarbonate formed. Excessive formation of calcium carbonate indicates significant degradation and potential for leakage pathways. (3) Porosity increase: chemical degradation can lead to an increase in the porosity of the cement sheath. Higher porosity can weaken the structure and reduce its ability to confine CO₂. The failure criterion can be defined as the maximum tolerable porosity increase. (4) Reduction in mechanical properties: chemical degradation can also result in a reduction in the mechanical properties of the cement sheath, such as compressive strength or elastic modulus. The failure criterion can be defined as the maximum allowable decrease in these mechanical properties. (5) Leaching or dissolution rate: the rate at which the cement sheath is leached or dissolved by aqueous CO₂ can be used as a failure criterion. The criterion can be defined in terms of the maximum allowable leaching or dissolution rate to prevent excessive damage to the cement sheath. These failure criteria for cement sheath chemical degradation are important for evaluating the long-term performance and integrity of the cement sheath in CO₂ storage environments. By monitoring and assessing these criteria, appropriate mitigation measures can be implemented to prevent excessive degradation and ensure the effectiveness of CCS projects.

Cement sheath integrity evaluation techniques for carbon dioxide sequestration sites could involve direct experimentation of samples that mimic the storage site in its in-situ conditions, well logging for monitoring leakages, analytical, numerical, and statistical modeling, and risk assessment. Direct experimentation assists in establishing the carbonation kinetics and the phenomenology changes of the cement sheath’s mechanical and transport properties. Some of the direct experimentation with cement sheath samples for evaluating their integrity identified include scanning electron microscopy (SEM), back-scattered electron image detector (BSE), energy-dispersive spectroscopy (EDS), mercury intrusion porosimetry (MIP), optical microscopy, (X-ray diffraction (XRD), electrical resistivity imaging (ERI), electron probe microanalyzer (EPMA), inductivity-coupled plasma optical emission spectrometry (ICP-OES), X-ray computed microtomography, Raman spectroscopy, direct image correlation, and particle image velocimetry, among others. Interestingly, all these direct experimentation techniques require comparing results or images obtained before and after core flooding of cement sheath samples in aqueous CO₂ at in-situ geologic sequestration conditions of temperature and pressures. Leaks detection methods include the use of spinners, tracer tests, temperature tools like distributed temperature sensing (DTS), noise logs, calipers, isolation packers’ mechanical means, ultrasonic leak detection, surface leakage monitoring, and material balance, among others. Every CO₂ storage site would require a specific subsurface characterization and analysis because every CO₂ storage site is unique. Storage sites could be evaluated using a combination of the in-situ reservoir and laboratory experiments to validate isolation performance, the required test would include mineralogical and hydrological classification of composite samples of the casing string/cement sheath/formation rock; wireline examination to determine wellbore conditions, fluid sampling, and in-situ reservoir permeability testing. Also, cement sheath integrity could be evaluated using either cement bond log evaluation tools, pressure transient test tools, cement coring tools, direct nanoindentation, or the sustained casing pressure analysis method.

Several numerical modeling and simulation approaches can be utilized to provide cost-effective means of evaluating the impact of aqueous CO₂ exposure on cement sheath integrity and help identify potential failure mechanisms. They also provide valuable insights into the design and optimization of wellbore completion and cementing operations, ensuring the perpetual integrity of CO₂ storage wellbores. Some of the available numerical modeling and simulation techniques are reactive transport modeling, multi-scale modeling, computational fluid dynamics (CFD), and artificial intelligence (AI)-based modeling, among others. Reactive transport modeling is a numerical approach used to simulate the chemical reactions between aqueous CO₂ and cement sheath components. This approach can be used to evaluate the extent and rate of cement sheath degradation due to aqueous CO₂ exposure, as well as the impact of different variables such as temperature and pressure on the reaction kinetics. Multi-scale modeling involves combining different modeling approaches to simulate the behavior of cement sheaths at different length scales. This approach can be used to simulate the interaction between aqueous CO₂ and cement sheath components at the nano or micro-scale, as well as the impact of these interactions on the cement sheath’s macroscopic behavior. Finite element Analysis is a numerical approach used to solve complex engineering problems by dividing a system into many smaller manageable elements. This method can be used to simulate the mechanical behavior of cement sheath exposed to aqueous CO₂, including the effects of cement degradation on the strength and stiffness of cement sheath. Computational fluid dynamics is a numerical method used to simulate the flow of fluids such as aqueous CO₂ in the wellbore or within the storage media. This approach can be used to evaluate the distribution and transport of CO₂ in the cement sheath, as well as the impact of aqueous CO₂ exposure on the rheological properties of the cement sheath. AI-based modeling involves using machine learning algorithms to analyze large datasets and predict the behavior of cement sheaths exposed to aqueous CO₂. This approach can be used to identify the key parameters and variables that influence cement sheath degradation due to aqueous CO₂ exposure, as well as develop predictive models for estimating the lifespan of the cement sheaths.

Conclusions and future works

Conclusions

A comprehensive literature review on evaluation techniques for assessing the cement sheath integrity of wellbores used in CCS projects was conducted. The study also highlighted some of the factors that affect the integrity of cement sheath exposed to aqueous CO₂ and the types of cement sheath mechanical failure mechanisms/modes in CCS applications.

• 1. Evaluation techniques for assessing the integrity of cement sheaths exposed to aqueous CO₂ include direct experimentation with samples that mimic CO₂ storage media at in-situ storage environment, well logging for leakage monitoring, and analytical, numerical, and statistical modeling, as well as risk assessments.

• 2. Some field operations offer additional methods for evaluating cement sheath integrity, including cement bond log evaluation, pressure transient tests, cement coring, and sustained casing pressure analysis.

• 3. Numerical modeling and simulation techniques for assessing cement sheath integrity exposed to aqueous CO₂ identified in this study comprise reactive transport modeling, multi-scale modeling; computational fluid dynamics (CFD); and artificial intelligence (AI)-based modeling.

• 4. Every CO₂ storage medium is unique. Optimal assessment of the cement sheaths' integrity of its wellbore systems, when exposed to aqueous CO₂, would require a different combination of suitable evaluation techniques.

Prospects for future studies

While this study provides a comprehensive overview of existing techniques for evaluating cement sheath integrity in the context of CO₂ geosequestration, there are several avenues for future research:

• Future studies should aim to provide standardized evaluation guidelines that incorporate both laboratory and field-scale testing as well as numerical modeling and simulations, to predict the evolution of cement sheath integrity exposed to aqueous CO₂. This will support the optimization of wellbore completion and cementing operations and ensure the long-term integrity of sequestration media, facilitating the commercial deployment of CCS projects.

• Further research is needed to identify optimal combinations of cement slurry additives and formulations that can produce cement sheaths with sufficient long-term resilience and resistance to carbonic acid or aqueous CO₂ attacks, which is necessary for geologic sequestration.

• There are significant research opportunities available to improve the knowledge base of numerical modeling approaches for evaluating the impact of aqueous CO₂ exposure on cement sheath integrity and identifying potential failure mechanisms.