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Graphene nanoplatelets reinforced cement as a solution to leaky wellbores reinforcing weak points in hydrated Portland cement with graphene nanoparticles improves mechanical and chemical durability of wellbore cements
In this work, to improve the performance of wellbore cement under subsurface environments, graphene nanoplatelets (GNPs) were added in various percentages to Class-H cement slurry. Microstructural characterization of cement slurries cured at 90 °C and 95% RH indicates that GNP modifies the microstructure of hydrated cement by reinforcing pore spaces. As a result, the mechanical properties, such as Young's modulus and axial peak stress, obtained from high temperature triaxial compression tests are significantly improved based on different percentages of added GNPs. Furthermore, the hydrated 1 × 2 inch GNP- Portland cement cores tested under simulated deep wellbore conditions of high-temperature and high pressure (HTHP), appear to have a ductile-like behavior, when compared to a typical brittle nature of Portland cement pastes. From our observations and published data on graphene resistance to fracture, GNP addition to cement is evidently enhancing the flexibility of cement. These improvements would reduce the risks associated with wellbore cement deterioration and a consequent leakage in fossil fuel production, geothermal energy production, CO 2 storage as well as long-term sealing materials in plugging and abandonment of all wellbores at the end of their service life.
Structural and chemical changes from CO2 exposure to self-healing polymer cement composites for geothermal wellbores
Wellbore cement is subjected to a number of mechanical, thermal and chemical stress regimes over its lifetime. Therefore, next generation wellbore cement formulations need to be evaluated in conditions relevant to these environments. In this work, we investigate the mechanism of the alteration of a novel self-healing polymer-cement composite recently reported by our group after exposure to a CO2-rich environment by using synchrotron based X-ray Fluorescence (XRF) and X-ray absorption near edge structure (XANES) and scanning electron microscopy coupled with energy dispersive spectroscopy. Results showed that chemical alteration of the polymer-cement follows the rim carbonation mechanism, similar to conventional cement although carbonation takes place to a lesser extent in polymer-cements despite the higher porosity. Along with detailed mechanistic insights on carbonation in polymer-cement composite, the performance of these in CO2-rich environment is further studied using standard compressive strength analysis.
Wellbore Stability and Mud Loss Management in Geothermal Drilling: Optimizing Mud Weight to Mitigate Tensile Wellbore Fracturing at The Geysers, California
As part of a U.S. Department of Energy (DOE) Geothermal Technologies Office-funded initiative, Geysers Power Company, LLC, a subsidiary of Calpine Corporation, has been working to enhance drilling performance at the world’s largest geothermal field, The Geysers, in northern California. In a recent drilling operation of the GDC-36 well, excessive mud losses were encountered, initially addressed through repeated but largely ineffective cement plugging. Ultimately, the most effective strategy was to drill blind through the loss zones, made feasible by the high rate of penetration (ROP) achieved with PDC bits, allowing significant progress before the mud tanks were depleted and water-sensitive argillic formation layers could collapse. In response to these challenges, the project team explored alternative methods to minimize downtime and risks associated with cement plugging and continuous mud loss and to contemplate the driving mechanisms for the losses. Wellbore imaging using Formation MicroImager (FMI) and Ultrasonic Borehole Imager (UBI) tools revealed longitudinal tensile fractures, which were attributed to mud weights exceeding the minimum circumferential stress resulting from the native stress field and formation pressure. This study examines the mud losses encountered and leverages wellbore imaging data to understand the mechanisms behind mud induced tensile fracturing in specific rock facies. Understanding fracture behavior across different lithologies is crucial, as fractures within the reservoir can enhance steam migration throughout the system. The reservoir at The Geysers lies within the Mesozoic Franciscan Assemblage, a tectonic mélange formed by subduction. It consists of metamorphosed turbidite sandstone (greywacke) and mudstone (argillite), oceanic upper crust (including greenstone and chert), and serpentinized ultramafic rocks - each exhibiting distinct geomechanical fracturing properties. The structural fabric of the Franciscan Assemblage was shaped by low-angle Mesozoic thrust faulting and later overprinted by sub-vertical strike-slip structures related to the Pacific-North American plate boundary. A wellbore stability model was developed using core measurements and logs to simulate fracturing scenarios during drilling under varying stress conditions. These simulations guided the development of an optimized mud weight management strategy that should enable adaptive adjustments during drilling, reducing the likelihood of tensile fracturing and mud losses, ultimately improving operational efficiency.
Insights into the physical and chemical properties of a cement-polymer composite developed for geothermal wellbore applications
To isolate injection and production zones from overlying formations and aquifers during geothermal operations, cement is placed in the annulus between well casing and formations. Wellbore cement can fracture due to chemical and physical stress. A polymer-cement (composite) with self-healing properties, stable at high temperatures, was recently developed by our group. Here we present data on the elemental distribution, mineral composition, internal microstructure, and tensile elasticity of this composite and how it compares to cement without polymer (control cement). Entrapped air porosity was similar between control cement (0.44% by volume) and composite (0.22% by volume). Total voids increased with polymer content in the cement (10% and 25% composite), and polymer was found to fill most of these voids. Polymer appears to act as a (cement hydration) retarder increasing the amount of unhydrated silicate minerals in the matrix. Tensile elasticity was improved for composites as compared to control cement, suggesting that the composite materials perform better under mechanical stress. Density-functional calculations reproduce the drop in Young’s modulus by about 60% observed experimentally when polymer is added to the cement. In addition, calculations indicate that the bonding interactions between the cement and polymer remain stable over the range of strain studied.
Oklahoma Wellbore Rasters
Seven raster surfaces generated from wellbore information that are thought to influence fluid and or gas migration in the subsurface. Wellbore information was originally retrieved from the IHS Energy Group (current as of April 2015), which is a proprietary, commercial database containing information for most oil and gas wells in the U.S. Processing of wellbore information into gridded cells was performed to provide a graphic solution to overcome the problem of displaying proprietary well data. No proprietary data are displayed or included in the cell maps. These rasters were developed to serve as inputs to the SIMPA (Spatially Weighted Multivariate Probabilistic Assessment) tool. Each raster surface is a derivative product of wellbore dataset. Each raster represents a single wellbore attribute or combination of attributes that speak to the following wellbore characteristics: number of recompletions, year spud, year abandoned, year completed, number of abandoned wells, hole direction, switch from production to injection. The original wellbore information, retrieved from the IHS Energy Group, are in the form of points – these derivative rasters aggregate point attributes to approximately 1,000-meter resolution grid cells. Each raster only includes cells that contain wellbores with the characteristics represented in each surface (i.e. if the wellbores in a given cell have no year abandoned data, the cell is not included in the raster). Since the raster cells combine data from multiple points in many cases, methods such as the average, minimum, and count are used to summarize the information in each cell. The specific operations used to develop each raster are detailed in its metadata.
Novel ductile wellbore cementitious composite for geologic CO 2 storage
CO 2 leakage through damaged wellbore cement sheaths is a major risk of geologic CO 2 storage (GCS), as conventional wellbore cement is brittle and can be damaged due to acid attack and downhole stresses during CO 2 injection. Here we examine a novel fiber-reinforced engineered cementitious composite (ECC) proposed as a substitute to conventional wellbore cement due to its superior ductility and intrinsic crack width control. ECC and conventional wellbore cement coupons were exposed to water in equilibrium with CO 2 at 50 °C and 10 MPa. The samples were retrieved after several days and their mechanical performance was evaluated using a four-point bending test, microhardness, and compressive strength analyses. Optical microscopy and mercury intrusion porosimetry were used to characterize the progression of the carbonation front and pore structures of the specimens. Control experiments were conducted under the same temperature and pressure conditions but with a N 2 headspace to isolate the impact of CO 2 . It was found that carbonation increased the ultimate flexural strength of ECC but decreased its ductility. However, the ductility of carbonated ECC remained higher than that of conventional wellbore cements that exhibited brittle failure under all test conditions. Additionally, ECC exhibited minimal material loss and continued resistance to deformation in comparison to conventional wellbore cements. This suggests that while the exposure of ECC to CO 2 will alter its mechanical properties, altered ECC will continue to exhibit mechanical performance superior to conventional wellbore cement, and therefore shows promise as a highly durable wellbore cementing material for GCS applications.
T2Well/ECO2N Version 1.0: Multiphase and Non-Isothermal Model for Coupled Wellbore-Reservoir Flow of Carbon Dioxide and Variable Salinity Water
T2Well/ECO2N is a coupled wellbore and reservoir model for simulating the dynamics of CO2 injection and leakage through wellbores. It can be seen as an extension to standard TOUGH/ECO2N V2.0, and can be applied to situations relevant to geologic CO2 storage involving upward flow (e.g., leakage) and downward flow (injection). The new simulator integrates a wellbore-reservoir system by assigning the wellbore and reservoir to two different sub-domains in which flow is controlled by appropriate physical laws. In the reservoir, we model flow using a standard multiphase Darcy flow approach. In the wellbores, we use the Drift-Flux Model and related conservation equations for describing transient two-phase non-isothermal wellbore flow of CO2-water mixtures. The mass and thermal energy balance equations are solved numerically by a finite difference scheme with wellbore heat transmission to the surrounding rock handled either semi-analytically or numerically. The momentum balance equation for the flow in the wellbore is solved numerically with a semi-explicit scheme.
Time-reversed nonlinear acoustics for wellbore integrity characterization
A pulsed sinusoidal acoustic signal transmitted through a subsurface volume of a wellbore may be detected. A time-reversed acoustic signal of the pulsed sinusoidal acoustic signal may be transmitted through the subsurface volume of the wellbore. Transmission of the time-reversed acoustic signal through the subsurface volume of the wellbore may result in generation of focused acoustic signal in the subsurface volume of the wellbore. The focused acoustic signal in the subsurface volume of the wellbore may be detected, and the integrity of the wellbore may be determined based on the focused acoustic signal in the subsurface volume of the wellbore.
Relative permeabilities for two-phase flow through wellbore cement fractures
Multiple fluids are likely to exist in fractures and flow paths associated with leaky wellbores, including liquids (e.g., crude oil) and gases (e.g., gas exsolved from liquid). These fluids occupy and move through different portions of the pore spaces within the fractures depending on many factors, including fluid properties, fracture size, and the amount of the different fluids. Upward leakage of any phase, through the fracture, can contaminate water-bearing formations, create hazardous surface conditions, and compromise the functionality of the wellbore. Early signs of wellbore leaks may be expressed by anomalous pressure behavior at surface monitoring points on cavern storage wells. These pressure anomalies are difficult to interpret, necessitating knowledge of the factors that affect the multiphase flow in fractures and porous media. These parameters are critical to modeling multiphase flow in fractures. This insight can guide further diagnosis and maximize leak remediation. Here, our study focuses on the relationship of the liquid–gas relative permeabilities for representative variable-aperture wellbore cement fracture. To obtain the relative permeability of each phase, two-phase flow tests were conducted where both fluids were flowing simultaneously through a fractured wellbore cement specimen under a range of factors, namely (1) aperture size, (2) capillary numbers, and (3) viscosity ratio. The flow experiments were conducted under a range of confining stresses and flow velocities, using nitrogen gas and silicone oils (of different viscosities) in a specially designed pressure vessel. The sum of gas and oil relative permeabilities were found to be less than one under all conditions, which indicates that the presence of one phase affects the permeability of the other phase, and vice versa. Since the gas phase flow conditions include a significant inertial flow component in addition to viscous flow, the inertial flow coefficients at different saturation states are presented. The factors affecting the relationship between the relative permeabilities are discussed in detail. A new mathematical model for estimating the relative permeability of wellbore cement fracture is presented and experimentally validated.
Simulation of wellbore construction in offshore unconsolidated methane hydrate-bearing formation
The unconsolidated nature of offshore methane hydrate-bearing formation poses concerns for sustainable methane gas production as the weak formation is susceptible to disturbance during wellbore construction. Furthermore, this could contribute to loss of well integrity which could manifest as sand production and error in the interpretation of downhole tests such as mini-frac tests. In this study, a simulation methodology of wellbore construction process is proposed. A finite element model adopting this methodology is developed in order to assess the effect of wellbore construction process on the integrity of the unconsolidated methane hydrate-bearing formation in the Nankai Trough, Japan. The primary objectives are (i) to develop a modelling methodology of well construction process for numerical simulations, (ii) to assess the zone and magnitude of well construction-induced stress/strain disturbance in the formation and (iii) to evaluate relative impact of each well construction stage on the integrity of the formation. The results from this study show that the zone of horizontal stress disturbance from the geostatic state due to wellbore construction could extend to more than three times the radius of the wellbore. Following the wellbore construction, the deviator stress is concentrated in the hydrate reservoir sublayers with high hydrate saturation while plastic deviatoric strain has accumulated in the sublayers with low hydrate saturation. The results also show that modelling of cement shrinkage process is crucial in predicting the concentration of deviator stress in the high hydrate saturation layers.
Wellbore cement fracture permeability as a function of confining stress and pore pressure
Cemented annulus fractures are a major leakage path in a wellbore system, and their permeability plays an important role in the behavior of fluid flow through a leaky wellbore. The permeability of these fractures is affected by changing conditions including the external stresses acting on the fracture and the fluid pressure within the fracture. Laboratory gas flow experiments were conducted in a triaxial cell to evaluate the permeability of a wellbore cement fracture under a wide range of confining stress and pore pressure conditions. For the first time, an effective stress law that considers the simultaneous effect of confining stress and pore pressure was defined for the wellbore cement fracture permeability. Here the results showed that the effective stress coefficient (λ) for permeability increased linearly with the Terzaghi effective stress ( -p) with an average of λ = 1 in the range of applied pressures. The relationship between the effective stress and fracture permeability was examined using two physical-based models widely used for rock fractures. The results from the experimental work were incorporated into numerical simulations to estimate the impact of effective stress on the interpreted hydraulic aperture and leakage behavior through a fractured annular cement. Accounting for effective stress-dependent permeability through the wellbore length significantly increased the leakage rate at the wellhead compared with the assumption of a constant cemented annulus permeability.
NRAP-Open-IAM: Open Wellbore Component (V.2.0)
The Open Wellbore component of NRAP-Open-IAM is applicable to the calculation of Area of Review at a carbon storage site and fast estimation of dense gas dispersion from multiple continuous CO 2 surface leakage sources for risk assessment. The Open Wellbore Component of NRAP-Open-IAM is a lookup table model based on the drift-flux approach. The National Research Assessment Partnership’s second-generation integrated assessment model, NRAP-Open-IAM, is open-source software written in Python for use in performance and quantitative risk assessment of geologic carbon storage (GCS) systems. The look-up table for open well leakage is an updated version the previous model which provides finer resolution of reservoir depth and more accurate fluid properties than the previous open well look-up table, especially in calculating the gas (CO 2 -rich) phase properties. The component model input parameters include the reservoir transmissivity, aquifer transmissivity, brine salinity, well radius, and well top and bottom depths. The reservoir transmissivity and brine salinity were set to values consistent with the reservoir component, and the well top and bottom depths varied with location. The possible outputs from the Open Wellbore component are leakage rates of CO 2 and brine to either an aquifer or atmosphere, depending on the depth of the well top. Several python test scripts are presented that demonstrate that the Open Wellbore component works correctly. Use of the open wellbore model in NRAP-Open-IAM may result in a large CO 2 leakage rates, comparable to the leakage rates of CO 2 blow out.
Hydrogeological assessment of CO2 containment assurance and wellbore integrity at a Gulf Coast storage site
Abstract A large-scale carbon capture and storage (CCS) initiative on the Texas Gulf Coast serves as a premier demonstration of the U.S. Department of Energy’s CarbonSAFE program. Targeting deep saline formations, specifically Oligo-Miocene deltaic sequences, the project aims to establish technical and commercial viability for geologic CO2 storage within a major industrial corridor. This study provides a rigorous hydrogeological assessment to support Class VI permitting by quantifying the high degree of containment security. Utilizing a compositional reservoir simulator, we developed a suite of 27 distinct simulation cases to evaluate vertical plume dynamics near both planned injection wells and proximal legacy infrastructure. To ensure numerical accuracy near wellbores, we implemented a refined mesh strategy, determining that a 5.6 ft × 5.6 ft grid refinement offered the optimal balance between computational efficiency and descriptive precision. The modeling framework utilized a systematic sensitivity-based approach to evaluate the mechanical redundancy of the subsurface system by performing a bounding analysis of wellbore interfaces against hypothetical high-permeability microannuli. By systematically isolating competing physical drivers, including permeability, porosity, gas hysteresis, thermal gradients, salinity, and solubility trapping (quantified via Henry’s law with dynamically adjusted coefficients), this work moves beyond binary assessments to establish a nuanced hierarchy of containment factors. The results confirm that primary trapping mechanisms (e.g., gas hysteresis and solubility), combined with the site's unique geomechanical stratigraphy, significantly restrict vertical mobility and reinforce the robust containment security of the reservoir. Baseline results demonstrate substantial vertical separation between the CO2 plume and the upper confining system, ensuring robust containment. Sensitivity analysis reveals that even under highly conservative bounding scenarios—assuming theoretical 10-Darcy pathways at specific wellbore locations—the 2,900-ft thick multi-layered confining zone remains a reliable barrier. In these hypothetical upper-bound cases, peak upward fluxes of CO2 and saltwater after 15 years of injection remain localized and dissipate rapidly within the lower sections of the confining interval, leaving the integrity of the seal uncompromised. Furthermore, the study identifies that while localized wellbore pathways define theoretical upper bounds of vertical migration, the Area of Review (AoR) is primarily sensitive to regional thermal gradients and hysteresis, which can influence the AoR by over 3,000 acres in pessimistic configurations. Also, primary trapping mechanisms, specifically gas hysteresis and solubility, work in tandem with the Gulf Coast’s unique geomechanical stratigraphy to significantly restrict vertical mobility. Ductile, smectite-rich mudstones facilitate natural borehole convergence and the self-healing of potential conduits, creating a natural geomechanical bridge that effectively mitigates migration potential at both current injection points and legacy-well locations. This comprehensive modeling effort demonstrates that the integration of high-resolution wellbore simulations and regional geomechanical observations confirms the long-term storage security of the studied site, providing a physics-based foundation for industrial-scale CCS deployments. This modeling framework establishes a baseline for future research into coupled geomechanical effects, such as time-dependent borehole convergence, to further refine long-term containment projections. Acknowledgements We thank the Gulf Coast Carbon Center (GCCC) at the Bureau of Economic Geology for foundational research support. We appreciate Alex Bump for technical guidance and David Hoffman for model mesh generation. This work used TACC’s Frontera cluster for simulations and CMG Ltd. software licenses provided to UT-Austin. This material is based upon work supported by the Department of Energy under Award Number DE-FE0032338. Disclaimer This material is based upon work supported by the U.S. Department of Energy’s Fossil Energy and Carbon Management Office under the CarbonSAFE program, award Number DE-FE0032338. The views expressed herein do not necessarily represent the views of the U.S. Department of Energy or the United States Government.
Hydrogeological assessment of CO2 containment assurance and wellbore integrity at a Gulf Coast storage site
Abstract A large-scale carbon capture and storage (CCS) initiative on the Texas Gulf Coast serves as a premier demonstration of the U.S. Department of Energy’s CarbonSAFE program. Targeting deep saline formations, specifically Oligo-Miocene deltaic sequences, the project aims to establish technical and commercial viability for geologic CO2 storage within a major industrial corridor. This study provides a rigorous hydrogeological assessment to support Class VI permitting by quantifying the high degree of containment security. Utilizing a compositional reservoir simulator, we developed a suite of 27 distinct simulation cases to evaluate vertical plume dynamics near both planned injection wells and proximal legacy infrastructure. To ensure numerical accuracy near wellbores, we implemented a refined mesh strategy, determining that a 5.6 ft × 5.6 ft grid refinement offered the optimal balance between computational efficiency and descriptive precision. The modeling framework utilized a systematic sensitivity-based approach to evaluate the mechanical redundancy of the subsurface system by performing a bounding analysis of wellbore interfaces against hypothetical high-permeability microannuli. By systematically isolating competing physical drivers, including permeability, porosity, gas hysteresis, thermal gradients, salinity, and solubility trapping (quantified via Henry’s law with dynamically adjusted coefficients), this work moves beyond binary assessments to establish a nuanced hierarchy of containment factors. The results confirm that primary trapping mechanisms (e.g., gas hysteresis and solubility), combined with the site's unique geomechanical stratigraphy, significantly restrict vertical mobility and reinforce the robust containment security of the reservoir. Baseline results demonstrate substantial vertical separation between the CO2 plume and the upper confining system, ensuring robust containment. Sensitivity analysis reveals that even under highly conservative bounding scenarios—assuming theoretical 10-Darcy pathways at specific wellbore locations—the 2,900-ft thick multi-layered confining zone remains a reliable barrier. In these hypothetical upper-bound cases, peak upward fluxes of CO2 and saltwater after 15 years of injection remain localized and dissipate rapidly within the lower sections of the confining interval, leaving the integrity of the seal uncompromised. Furthermore, the study identifies that while localized wellbore pathways define theoretical upper bounds of vertical migration, the Area of Review (AoR) is primarily sensitive to regional thermal gradients and hysteresis, which can influence the AoR by over 3,000 acres in pessimistic configurations. Also, primary trapping mechanisms, specifically gas hysteresis and solubility, work in tandem with the Gulf Coast’s unique geomechanical stratigraphy to significantly restrict vertical mobility. Ductile, smectite-rich mudstones facilitate natural borehole convergence and the self-healing of potential conduits, creating a natural geomechanical bridge that effectively mitigates migration potential at both current injection points and legacy-well locations. This comprehensive modeling effort demonstrates that the integration of high-resolution wellbore simulations and regional geomechanical observations confirms the long-term storage security of the studied site, providing a physics-based foundation for industrial-scale CCS deployments. This modeling framework establishes a baseline for future research into coupled geomechanical effects, such as time-dependent borehole convergence, to further refine long-term containment projections. Acknowledgements We thank the Gulf Coast Carbon Center (GCCC) at the Bureau of Economic Geology for foundational research support. We appreciate Alex Bump for technical guidance and David Hoffman for model mesh generation. This work used TACC’s Frontera cluster for simulations and CMG Ltd. software licenses provided to UT-Austin. This material is based upon work supported by the Department of Energy under Award Number DE-FE0032338. Disclaimer This material is based upon work supported by the U.S. Department of Energy’s Fossil Energy and Carbon Management Office under the CarbonSAFE program, award Number DE-FE0032338. The views expressed herein do not necessarily represent the views of the U.S. Department of Energy or the United States Government.