Caprock Failure Research Articles

A New Methodology for Quantitative Risk Assessment of CO2 Leakage in CCS Projects

Summary Assessing risks during carbon dioxide (CO2) sequestration involves a systematic process to identify them (risk assessment), analyze, prioritize, score them (risk analysis), develop mitigation strategies, and plan for measurement, monitoring, and verification (MMV) activities. In this context, risk assessment and analysis are often conducted involving qualitative approaches and/or subjective evaluations based on experts judgments. In this paper, we propose to use numerical results of dynamic subsurface modeling to assess risks in a more precise, less subjective, and quantitative manner, enabling a comprehensive definition of effective MMV plans. In this context, MMV evolves into modeling, measurements, monitoring, and verification [(M)MMV]. The conceptual model used for this study integrates flow and geomechanical-coupled behavior to assess caprock integrity, faults reactivation, and ultimately the risk of CO2 leakage. Uncertainty analysis and a 4D probabilistic workflow are used to quantify the likelihood and consequences of CO2 leakage and to score risks. The proposed approach offers a general framework to enable subsurface-modeling-based quantitative risk assessment (QRA) for the definition of successful (M)MMV plans. In this study, we have focused on the QRA of leakage risks through the fault and intact caprock. Other applications are possible, such as: (1) leakage risks through the caprock resulting from caprock failure; (2) lateral CO2 migration leading to permit limits violation or inducing interferences with neighboring activities; (3) leakage risks resulting from loss of well integrity; (4) risks of faults reactivation; (5) risks of surface heave; and (6) risks of induced seismicity. All these results can be used to formulate effective (M)MMV strategies for an optimized and cost-effective risk mitigation.

Geomechanics analysis of caprock integrity in injection and production operations of aquifer gas storage

ABSTRACT The safety of aquifer gas storage (AGS) depends on the mechanical stability of the caprock to a great extent. The injection and production operation of AGS will cause the disturbance of the in-situ stress due to the change of pore pressure in the reservoir and caprock, which may lead to the failure of caprock. The con AGS is established based on geological structure and hydrogeological information. By using the finite element method, the factors such as boundary condition, properties of reservoir and caprock, and in-situ stress coefficient are considered, respectively, and the variation of formation pressure and disturbed stress in the process of injection and production are analyzed. The results show that the boundary conditions are of significant influence on the stress field. The shear failure risk of reservoir–caprock interface under closed boundary is the greatest. The in-situ stress coefficient has the greatest influence on the failure risk of the caprock, followed by the permeability of the reservoir and caprock.

Shear Wave Velocity Applications in Geomechanics with Focus on Risk Assessment in Carbon Capture and Storage Projects

Shear wave velocity (Vs) has significant applications in geoengineering investigations. With the ongoing rise in carbon capture and storage (CCS) initiatives, the role of Vs in monitoring the CO2 sequestration sites is escalating. Although many studies have been conducted to assess CCS-induced risks, no inclusive research has been conducted integrating those investigations. This study strives to collate and integrate the applications of Vs in geoscience with an emphasis on CCS risk assessment. Based on this research, major CCS-induced risks were detected: induced seismicity, caprock failure, groundwater contamination, fault reactivation, and reservoir deformation. These risks were inclusively described, and the mathematical formulations incorporating the Vs parameter in risk analysis were elaborated. It was concluded that Vs applications can be further extended in monitoring CO2 plume migration, optimizing CO2 injection pressures, preventing shallow water contamination, and predicting CCS-induced seismic events. All these applications require fully coupled hydromechanical analysis based on poroelasticity theory. Hence, various factors including pore pressure, in situ stresses, faults distribution, and poroelastic parameters must be carefully determined before the CO2 injection phase. The mathematical formulations presented in the present study are quite applicable for granting the safety and long-term success of subsurface carbon sequestration.

Caprock integrity at Çanakkale-Tuzla hydrothermal system inferred from magnetotelluric modeling using particle swarm optimization

The impermeable caprock within a geothermal system serves the purpose of effectively sealing the reservoir, resulting in the elevation of both pressure and temperature. This sealing mechanism plays a crucial role in the long-term preservation of the system, while also contributing to its overall sustainability. Caprock failure subsequent to seismic activity near a geothermal site can lead to the permeation of the caprock structure, resulting in diminished sealing capabilities and a decline in the reservoir temperature. Additionally, this process alters the geochemical composition of the water by creating a hydrothermal mixture zone that disrupts the resistivity structure of the caprock, which is typically characterized by low resistivity values due to its substantial clay content and mineral alteration. This study focuses on investigating the integrity of the caprock at ơnakkale-Tuzla geothermal field in Turkey, where the water temperature and conductivity were reported to have decreased after a moderate magnitude earthquake and subsequent aftershocks. For this purpose, we performed magnetotelluric (MT) measurements, a method known for its sensitivity to geochemical reactions. These measurements were conducted along two parallel profiles that encompassed a total of 32 stations. Particle swarm optimization (PSO) technique was employed to overcome subtle difficulties associated with conventional inversion methods when modeling the MT data of complex formations. This is the first study that overcomes the difficulties emanating from the caprock failure by modeling MT data using PSO. Our modeling approach produced resistivity images that we interpreted as the signature of the failed caprock following the earthquake at the study site. Our results appear to confirm the documented geochemical changes or hydrothermal mixture zone about caprock structure.

Probabilistic Evaluation of Geomechanical Risks in CO2 Storage: An Exploration of Caprock Integrity Metrics Using a Multilaminate Model

The probabilistic uncertainty assessment of geomechanical risk—specifically, caprock failure—attributable to CO2 injection, as presented in a simplified hypothetical geological model, was the focus of this study. Our approach amalgamates the implementation of a multilaminate model, the creation of a response surface model in conjunction with the Box–Behnken sampling design, the execution of associated numerical modeling experiments, and the utilization of Monte Carlo simulations. Probability distributions to encapsulate the inherent variability (elastic and mechanical properties of the caprock and reservoir) and uncertainty in prediction estimates (vertical displacement, total strain, and F value) were employed. Our findings reveal that the Young modulus of the caprock is a key factor controlling equivalent total strain but is insufficient as a stand-alone indicator of caprock integrity. It is confirmed that the caprock can accommodate significant deformation without failure, if it possesses a low Young’s modulus and high mechanical strength properties, such as the friction angle and uniaxial compressive strength. Similarly, vertical displacement was found to be an unreliable indicator for caprock integrity, as caprock failure can occur across a broad spectrum of vertical displacements, particularly when both the Young modulus and mechanical strength properties have wide ranges. This study introduces the F value as the most dependable indicator for caprock failure, although it is a theoretical attribute (the shortest distance between the Mohr circle and the nearest failure envelope used to measure the sensitivity to failure) and not physically measurable in the field. Deviatoric stress levels were found to vary based on stress regimes, with the maximum levels observed under extensive and compressive stress regimes. In conjunction with the use of the response surface method, this study demonstrates the efficacy of the multilaminate framework and the Mohr–Coulomb constitutive model in providing a simplified, yet effective, probabilistic model of the mechanical behavior of caprock failure, reducing mathematical and computational complexities.

Geomechanical risk and mechanism analysis of CO2 sequestration in unconventional coal seams and shale gas reservoirs

With global greenhouse gas emissions hitting record highs in 2021, CO2 geological sequestration (CGS) is the most realistic and feasible technology to ensure large-scale carbon reduction to achieve global carbon capping and carbon neutrality goals. Both coalbed methane and shale gas have the characteristics of self-generation and self-storage, which is considered to be a valuable target reservoir for geological sequestration of CO2. After a high volume of CO2 is injected into unconventional coal seams and shale gas reservoirs, many geomechanical issues may be induced, resulting in leakage. Therefore, it is crucial to evaluate the geomechanical risks of CO2 geological sequestration. In this article, global CO2 emissions and geological resources available for sequestration are teased out. The effects of coupled CO2-water-rock-driven geomechanical, geophysical, and geochemical interactions on the evolution of rock physical properties and pore characteristics, as well as caprock sealing, are discussed. The caprock failure and its inducing mechanism are analyzed, and the criteria for predicting the occurrence of risk are summarized, which is necessary for pressure management and risk prevention. To serve as a benchmark for CO2 sequestration in unconventional coal seams and shale gas reservoirs.

Anisotropic Poroelastic Modelling of Depletion-Induced Pore Pressure Changes in Valhall Overburden

Stress and pore pressure changes due to depletion of or injection into a reservoir are key elements in stability analysis of overburden shales. However, the undrained pore pressure response in shales is often neglected but needs to be considered because of their low permeability. Due to the anisotropic nature of shales, the orientation of both rock and stresses should be considered. To account for misalignment of the medium and the stress tensor, we used anisotropic poroelasticity theory to derive an angle-dependent expression for the pore pressure changes in transversely isotropic media under true-triaxial stress conditions. We experimentally estimated poroelastic pore pressure parameters of a shale from the Lista formation at the Valhall field. We combined the experimental results with finite element modelling to estimate the pore pressure development in the Valhall overburden over a period of nearly 40 years. The results indicate non-negligible pore pressure changes several hundred meters above the reservoir, as well as significant differences between pore pressure and effective stress estimates obtained using isotropic and anisotropic pore pressure parameters. We formulate a simple model approximating the undrained pore pressure response in low permeable overburden. Our results suggest that in the proximity of the reservoir the amplitude of the undrained pore pressure changes may be comparable to effective stresses. Combined with the findings of joint analysis of locations of casing deformation and total and effective stresses, the results suggest that pore pressure modelling may become an important element of casing collapse and caprock failure risk analysis and mitigation.

Well-Integrity Risk-Assessment Strategy Applied to CO2 Sequestration Project

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22348, “Scrutinizing Well Integrity for Determining Long-Term Fate of a CO2 Sequestration Project: An Improved and Rigorous Risk-Assessment Strategy,” by Parimal A. Patil, SPE, Asyraf M. Hamimi, and M. Azuan B. Abu Bakar, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but a high density of wells penetrating the carbon dioxide (CO2) storage reservoir could compromise containment performance in a carbon capture and sequestration (CCS) project. A risk-management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term viability of CO2 sequestration projects. The complete paper evaluates well-integrity and CO2 leakage risks along the wells in a depleted field that penetrates the CO2 storage reservoir. Background The identified CO2 storage site offshore Malaysia is a depleted hydrocarbon field discovered in the early 1980s. Subsequently, two appraisal wells were drilled to further assess the field’s development potential. The structure is a north/south anticline with an aerial extent of approximately 35 km2 and a vertical closure of 100 m on top of the reservoirs. Eighteen major and minor gas-bearing reservoirs exist in the field. The hydrocarbons from deeply buried reservoirs were produced over a period of approximately 15 to 25 years through deviated wellbores. In total, 24 wells are in the targeted field; of these, three are abandoned exploration and appraisal wells and 21 are development wells drilled from the platform. All exploration and appraisal wells are P&A, while 21 development wells are still accessible from the platform. High uncertainties are associated with the P&A wells because the well sites were restored per a regulatory requirement in which the casings were cut below mudline and a surface cement plug was placed with no intention of re-entering these wells. Development wells, on the other hand, were assessed and screened for reuse by conversion into CO2 injectors. Understanding Well Integrity for CO2 Storage Potential leakages that may occur through various mechanisms during geological storage of CO2 in the storage field include failed caprock and trap integrity and leakage along existing wellbores. Parameters that could cause leakage of CO2 because of failed caprock include existing faults or fractures, reactivation of faults, development of new fractures during injection, and caprock failure caused by pressures exceeding fracture pressure during or after injection. The geological analysis of the depleted field for potential development as a future CO2 storage site must understand and mitigate associated risks by integrating information from various databases. However, the integrity of wells in the storage project must be ensured over very long time scales, in the thousands of years.

Assessment and uncertainty quantification of onshore geological CO2 storage capacity in China

We provide a probabilistic assessment of CO2 storage capacity in major sedimentary basins in China. Our approach embeds constraints associated with the increase of reservoir pore pressure due to injection of CO2 in the presence of resident brine. Pressure build-up must be limited to avoid fault reactivation, caprock failure, and possible leakage, resulting in more conservative estimates of CO2 storage capacity as compared to volumetric estimates.We rely on a numerical Monte Carlo framework considering uncertainty in the values of reservoir size and major geological formation attributes (i.e., absolute permeability, porosity, and reservoir compressibility). Our work shows that 10 major basins can potentially store, on average, 1350 Gt of CO2 during the next 30 years (lower and upper quartiles being 1100 and 1700 Gt of CO2, respectively). This far exceeds the likely amount (up to 175 Gt of CO2) required to be stored by 2050. Our analysis also suggests that 6 basins (located close to the largest emission areas) can store about 93 Gt (on average) of CO2 during the next 30 years. Underground carbon storage in China, coupled with other possible solutions, could meet the aims of the Announced Pledges Scenario (International Energy Agency) to mitigate global warming by 2060.We also perform a global sensitivity analysis to determine how our predictions of storage capacity may be affected by uncertainties in the simulation model input parameters. Moment-based global sensitivity metrics suggest that geological formation attributes are major sources of uncertainty, significantly affecting model outputs and the associated uncertainty.

Assessment of chemo-mechanical impacts of CO2 sequestration on the caprock formation in Farnsworth oil field, Texas

This study evaluates the chemo-mechanical influence of injected CO2 on the Morrow B sandstone reservoir and the upper Morrow shale caprock utilizing data from the inverted 5-spot pattern centered on Well 13-10A within the Farnsworth unit (FWU). This study also seeks to evaluate the integrity of the caprock and the long-term CO2 storage capability of the FWU. The inverted 5-spot pattern was extracted from the field-scale model and tuned with the available field observed data before the modeling work. Two coupled numerical simulation models were utilized to continue the study. First, a coupled hydro-geochemical model was constructed to simulate the dissolution and precipitation of formation minerals by modeling three intra-aqueous and six mineral reactions. In addition, a coupled hydro-geomechanical model was constructed and employed to study the effects of stress changes on the caprock’s porosity, permeability, and ground displacement. The Mohr–Coulomb circle and failure envelope were used to determine caprock failure. In this work, the CO2-WAG injection is followed by the historical field-observed strategy. During the forecasting period, a Water Alternating Gas (WAG) injection ratio of 1:3 was utilized with a baseline bottom-hole pressure constraint of 5500 psi for 20 years. A post-injection period of 1000 years was simulated to monitor the CO2 plume and its effects on the CO2 storage reservoir and caprock integrity. The simulation results indicated that the impacts of the geochemical reactions on the porosity of the caprock were insignificant as it experienced a decrease of about 0.0003% at the end of the 1000-year post-injection monitoring. On the other hand, the maximum stress-induced porosity change was about a 1.4% increase, resulting in about 4% in permeability change. It was estimated that about 3.3% of the sequestered CO2 in the formation interacted with the caprock. Despite these petrophysical property alterations and CO2 interactions in the caprock, the caprock still maintained its elastic properties and was determined to be far from its failure.

Simulation and Prediction of Injection Pressure in CO2 Geological Sequestration Based on Improved LSO Algorithm and BP Neural Networks

In order to avoid the occurrence of caprock integrity damage and gas escape due to injection pressure overrun in CO2 sequestration, an optimized back propagation (BP) neural network model based on Monte Carlo simulation (MCS) and an improved lion swarm optimization (ILSO) algorithm is proposed for the maximum sustainable injection pressure prediction. Firstly, a hydromechanical model is constructed to simulate the damage changes of the reservoir caprock during injection by ABAQUS. Secondly, in view of the uncertainties of formation parameters that could lead to deviations between the model calculation results and actual geological condition, the MCS method is used, and then, the probability distribution interval of the maximum injection pressure with high probability of caprock failure under different formation parameters is obtained by MATLAB. This effectively reduces the uncertainty and improves the calculation accuracy. Finally, based on the numerical simulation results, the maximum injection pressure prediction model is constructed. Aiming at the problems of the sensitivity of the BP neural network to initial weights and its poor convergence, tent chaotic mapping and difference mechanism are introduced to improve the LSO algorithm. Following this, the neural network is optimized by ILSO algorithm whose superiority is verified through 8 benchmark functions, and the maximum injection pressure is effectively predicted according to porosity, permeability, and other parameters. Experimental results show that, compared to the other three optimization methods, the ILSO_BP model has a faster convergence speed, higher prediction accuracy, and stability, which can provide a powerful guide for the safe injection of CO2 and efficient sequestration management.

Artificial Neural Network-Based Caprock Structural Reliability Analysis for CO2 Injection Site—An Example from Northern North Sea

In CO2 sequestration projects, assessing caprock structural stability is crucial to assure the success and reliability of the CO2 injection. However, since caprock experimental data are sparse, we applied a Monte Carlo (MC) algorithm to generate stochastic data from the given mean and standard deviation values. The generated data sets were introduced to a neural network (NN), including four hidden layers for classification purposes. The model was then used to evaluate organic-rich Draupne caprock shale failure in the Alpha structure, northern North Sea. The train and test were carried out with 75% and 25% of the input data, respectively. Following that, validation is accomplished with unseen data, yielding promising classification scores. The results show that introducing larger input data sizes to the established NN provides better convergence conditions and higher classification scores. Although the NN can predicts the failure states with a classification score of 97%, the structural reliability was significantly low compare to the failure results estimated using other method. Moreover, this indicated that during evaluating the field-scale caprock failure, more experimental data is needed for a reliable result. However, this study depicts the advantage of machine learning algorithms in geological CO2 storage projects compared with similar finite elements methods in the aspect of short fitting time, high accuracy, and flexibility in processing different input data sizes with different scales.

3D Field-Scale Geomechanical Modeling of Potential CO2 Storage Site Smeaheia, Offshore Norway

Injection-induced rock mechanical failure risks are critical in CO2 sequestration, and thus there is a need to evaluate these occurrences to ensure safe and reliable subsurface storage. A stress–strain-based numerical simulation can reveal the potential mechanical risks of any CO2 sites. This study investigated the hydromechanical effect on geomechanical failure due to injection-induced stress and pore pressure changes in the prospective CO2 storage site Smeaheia, offshore Norway. An inverted-seismic-property-driven 3D field-scale geomechanical model was carried out in the Smeaheia area to evaluate the rock failure and deformation risks in various pressure-build-up scenarios. A one-way coupling between the before- and after-injection pressure scenarios of nine different models has been iterated using the finite element method. The effect of the sensitivity of total pore volume and pore compressibility on rock mechanical deformation is also evaluated. Although various models illustrated comparative variability on failure potential, no model predicted caprock failure or fracture based on the Mohr–Coulomb failure envelope. Moreover, the lateral mechanical failure variation among different locations indicated the possibility to identify a safer injection point with less chances of leakage. In addition, the pore volume and pore compressibility significantly influence the mechanical behavior of the reservoir and caprock rocks. Although this analysis could predict better injection locations based on geomechanical behavior, a fluid simulation model needs to be simulated for assessing lateral and vertical plume migration before making an injection decision.

Evaluating the mechanical properties of carbonate and evaporite caprocks in the Sichuan Basin

Caprocks are nearly impermeable rocks that inhibit the migration of hydrocarbons. Caprock efficiency at sealing hydrocarbon reservoirs is contingent upon maintaining its integrity, or the absence of features that enhance fluid flow such as fractures/faults. Caprock lithology is an important factor in sealing efficiency, as it controls caprock mechanical behavior and brittleness. Evaluating caprock failure due to chemo-thermo- mechanical forces requires an understanding of the deformation and failure properties consistent with effective caprocks. Core samples of caprocks from the northeast Sichuan Basin – primarily evaporites, limestones and dolostones – were tested under laboratory conditions to determine the relationships between lithology and geomechanical properties of different caprocks. The results of hardness, ultrasonic velocity, and axial deformation tests of the caprock samples indicate that caprock brittleness is strongly correlated with high values of hardness, peak and yield strength, Young’s modulus and coefficient of internal friction. Lithologic heterogeneity in caprocks is found to enhance sample failure in most cases, though the inclusion of minor phyllosilicate and evaporite minerals may conversely decrease caprock brittleness. Evaporites and dolostones consistently exhibit the least and most brittle characteristics, respectively, though individual mechanical properties can indicate contradictory caprock behavior. These results suggest evaluation of the geomechanical-risk to caprocks can thus be enhanced by combining mechanical properties to map trends in caprock effectiveness. When combined with accurate in- situ conditions, the mechanical properties of a caprock allow for a quantitative interpretation of caprock integrity.

The role of geomechanical modeling in the measurement and understanding of geophysical data collected during carbon sequestration

As fluids are injected into a reservoir, the pore fluid pressure changes in space and time. These changes induce a mechanical response to the reservoir fractures, which in turn induces changes in stress and deformation to the surrounding rock. The changes in stress and associated deformation comprise the geomechanical response of the reservoir to the injection. This response can result in slip along faults and potentially the loss of fluid containment within a reservoir as a result of cap-rock failure. It is important to recognize that the slip along faults does not occur only due to the changes in pore pressure at the fault location; it can also be a response to poroelastic changes in stress located away from the region where pore pressure itself changes. Our goal here is to briefly describe some of the concepts of geomechanics and the coupled flow-geomechanical response of the reservoir to fluid injection. We will illustrate some of the concepts with modeling examples that help build our intuition for understanding and predicting possible responses of reservoirs to injection. It is essential to understand and apply these concepts to properly use geomechanical modeling to design geophysical acquisition geometries and to properly interpret the geophysical data acquired during fluid injection.

Coupled Large Scale Hydromechanical Modelling for Caprock Failure Risk Assessment of Gas Storage in Aquifer

The rapidly increasing demand for the consumption of natural gas has attracted the interests to store natural gas in aquifer reservoir. However, natural gas injected into the aquifer reservoir, which could cause ground surface deformation and mechanical integrity destruction of caprock. Taking the aquifer gas storage of S trap as the research object, according to the geological structure and hydrogeological information, a coupling large-scale hydromechanical model is established to evaluate the damage risk of the gas reservoir in S aquifer. The proposed methodology is based on the development of fluid-solid coupling and application of FEM. The different failure mechanisms of S aquifer gas storage caprock can be evaluated on the basis of the tensile failure criterion and Mohr-Coulomb shear failure criterion. To analyze the change of caprock in gas injection and production process more clearly, a reference model is defined as an ideal calculation condition to discuss the mechanical response, pore pressure variation, and surface deformation characteristics of the caprock during injection and production. On this basis, the second scheme of sensitivity analysis is defined. The pressure injection rate, reservoir parameters, in situ stress, and other factors are considered, respectively, and the influence of different input parameters on mechanical stability and surface deformation of caprock is analyzed. Finally, the mechanical stability is analyzed and combined the above two criteria to predict the upper limit injection pressure of S. Simulation results show that the permeability and in situ stress have a significant influence on ground surface deformation and mechanical integrity of caprock, but Young’s modulus and Poisson’s ratio can be ignored; the upper limit pressure coefficient of S is 1.908.

Reservoir fluid effect on caprock properties in the Horda Platform area, northern North Sea

Upper Jurassic organic-rich shales' caprock properties in the Horda Platform area are crucial due to their importance as primary seals for the Middle Jurassic reservoir sandstones. The reservoir sandstones are Sognefjord, Fensfjord, and Krossfjord formations. These reservoir sandstones are overlain by the Upper Jurassic Draupne and Heather Formation Shales. Caprock failure due to injection-related pore pressure change is one of the critical risks for CO2 storage. The thick gas column in Troll East Field, located in the Horda Platform area, can consider an analog for a CO2 post-injection scenario in the area. Evaluating the caprock properties above the thick gas column in the Troll Field helps to understand the area's caprock integrity qualitatively. This study assesses Draupne and Heather Formation Shales' caprock properties using petrophysical and rock physical analyses. Four exploration wells from the Troll East area consider in this study where wells 31/3-1 and 31/6-1 have gas columns of approximately 224 and 222 m, respectively, and two other wells (31/3-3 and 31/6-3) are water wet. The exhumation correction suggests that Draupne and Heather Formations of four studied wells' maximum burial depth experienced only mechanical compaction. Two rock physics templates, such as Vp versus density and Young’s modulus versus Poisson’s ratio, are used to evaluate the caprock behavior due to HC accumulation-related overpressure. The caprock shales in wells with gas columns show a significantly soft nature compared to the shale in the dry well 31/3-3. However, a dry well (31/6-3) also shows remarkably low stiffness. The pressure changes due to the HC accumulation might change the pressure above the reservoir. The caprocks may behave more ductile due to the generation of non-connected micro-fractures. However, fracture connectivity might initiate the caprock's mechanical failure, which poses a significant risk in CO2 post-injection scenario. Moreover, a significantly thick caprock in well 31/6-3 may have influenced the caprock properties differently compared to the other dry well. The caprock mechanical behavior is complex and influenced by several factors.

Assessment of pore pressure, wellbore failure and reservoir stability in the Gabo field, Niger Delta, Nigeria - Implications for drilling and reservoir management

This work investigates a 3400m thick Tertiary succession from the prolific Gabo hydrocarbon field in the Niger Delta and presents a well-scale geomechanical model to address the pore pressure, borehole stability and fault slip potential attributes. The Tertiray stratigraphy is dominated by cyclic clastic sedimentation and it produces hydrocarbon from the Eocene Agbada Formation. An average vertical stress gradient of 0.85-0.90 PSI/feet is interpreted from the density logs. Extensive direct downhole measurements indicate a sub-hydrostatic pressure gradient of 0.325 PSI/feet in the Upper Agbada reservoir sands, while the lower producers are presently in hydrostatic regime (0.435 PSI/feet). Pore pressure against the shales are estimated by Eaton’s disequilibrium compaction method, which are found to be mildly overpressured (0.49 PSI/feet). The minimum horizontal stress (Shmin) gradient ranges between 0.59 and 0.70 PSI/feet. Wellbore stability is addressed by the Mohr-Coulomb failure model and the assessed failures are corroborated with the caliper log observations. Drilling mud weight used in the studied wells were found to be less than the shale collapse pressure gradient, resulting in selective wellbore over-gauging in the Eocene shales, intercalated with the sandstone reservoir intervals. Safe and effective downhole pressure window is inferred from the interpreted pore pressure, collapse pressure and Shmin to avoid any kick, loss or compressive wellbore failures by optimum mud weight designing. Inferences on drilling optimization are discussed which will be helpful for better planning of the infill injector wells. A fault slip analysis indicates that pore pressure could be increased by 1100-1200 PSI during the repressurization in the Upper and Lower Agbada reservoirs without inducing reservoir instabilities as well as caprock failure.

Effects of Different Penetration Patterns on a Fault during Underground Fluid Injection

At underground fluid injection sites with natural faults, understanding how to avoid the subsequent fault reactivation and induced seismicity plays a crucial role in the success of subsurface anthropogenic activities. In this work, with the objective of avoiding risky faults in site selection in the Shengli Oilfield, we investigated the faults that are usually encountered in the target demonstration zone; based on the geophysical observations of fault structures, we designed different fault tectonic scenarios to investigate the different penetration patterns of faults. We used the finite element-based numerical method to assess the influence of the effective lateral and vertical reservoir transmissivity in each fault penetration pattern. Our results indicate that when a permeable fault intersects into the target reservoir, it presents both barrier effect to reservoir transmissivity within the target reservoir and hydraulic connection between reservoirs. The effective lateral reservoir transmissivity is dominated by the barrier effect of the fault, and the effective vertical reservoir transmissivity is dominated by the hydraulic connection between reservoirs. Relatively impermeable faults with less contact with the target aquifer make higher effective lateral reservoir transmissivity and lower effective vertical reservoir transmissivity, which would mitigate the risk of caprock failure and the magnitude of the induced seismicity.

Effect of sedimentary heterogeneities in the sealing formation on predictive analysis of geological CO2 storage

Numerical models of geologic carbon sequestration (GCS) in saline aquifers use multiphase fluid flow-characteristic curves (relative permeability and capillary pressure) to represent the interactions of the non-wetting CO2 and the wetting brine. Relative permeability data for many sedimentary formations is very scarce, resulting in the utilisation of mathematical correlations to generate the fluid flow characteristics in these formations. The flow models are essential for the prediction of CO2 storage capacity and trapping mechanisms in the geological media. The observation of pressure dissipation across the storage and sealing formations is relevant for storage capacity and geomechanical analysis during CO2 injection.This paper evaluates the relevance of representing relative permeability variations in the sealing formation when modelling geological CO2 sequestration processes. Here we concentrate on gradational changes in the lower part of the caprock, particularly how they affect pressure evolution within the entire sealing formation when duly represented by relative permeability functions.The results demonstrate the importance of accounting for pore size variations in the mathematical model adopted to generate the characteristic curves for GCS analysis. Gradational changes at the base of the caprock influence the magnitude of pressure that propagates vertically into the caprock from the aquifer, especially at the critical zone (i.e. the region overlying the CO2 plume accumulating at the reservoir-seal interface). A higher degree of overpressure and CO2 storage capacity was observed at the base of caprocks that showed gradation. These results illustrate the need to obtain reliable relative permeability functions for GCS, beyond just permeability and porosity data. The study provides a formative principle for geomechanical simulations that study the possibility of pressure-induced caprock failure during CO2 sequestration.