bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Geological Hydrogen Storage Simulator For Cyclic Injection and Withdrawal Processes: Coupled Flow and Geomechanics With Capillary Hysteresis
Authors: Sarkar P. , Kim J. 
Published: September 2024

Abstract
We have developed a high-fidelity, coupled flow and geomechanics simulator specifically designed for geological hydrogen storage. This simulator integrates non-isothermal multiphase multicomponent flow of hydrogen and water with geomechanics, accounting for elastoplastic behavior such as Mohr-Coulomb failure, essential for maintaining the geomechanical integrity of storage reservoirs. Additionally, the simulator addresses capillary hysteresis resulting from repeated drainage and imbibition cycles induced by periodic hydrogen injection and production. To model capillary hysteresis robustly, we employ a thermodynamically consistent return mapping algorithm utilizing the van Genuchten model for the capillary pressure curve. The coupling between flow and geomechanics is achieved through the fixed-stress sequential method. We validated our simulator using three test cases (1D, 2D, and 3D) to assess its numerical stability and capabilities. In the 1D case, we evaluated numerical stability during repeated hydrogen injection and production, where both capillary hysteresis and geomechanical failure occur simultaneously. The results demonstrated stability, accurately capturing Mohr-Coulomb failure and capillary hysteresis curves. For the 2D and 3D cases, which focused on wellbore integrity and field-scale simulation, respectively, the simulator consistently provided reasonable and stable results for capillary hysteresis and effective stress, confirming its applicability to real field scenarios.
Accurate Measurement of Relative Permeability as Crucial Step for Carbon Capture, Utilization, and Storage: Case Study
Authors: de Itriago Yani C. Araujo , Devier Sarah , Singletary Phillip , Watkins Henderson 
Published: September 2024

Abstract
Carbon Capture, Utilization, and Storage is one of the key technologies that can help meet the goal of reducing carbon emissions in the atmosphere by pulling out CO2 emissions from different industries. CO2 storage can provide a way to continue using hydrocarbons while minimizing their environmental impact, making the process valuable for the energy transition. To implement a CO2 storage project, it is necessary to meet existing regulatory framework for planning, implementation, and monitoring, which includes the evaluation of rock-fluid properties. These properties are necessary to ensure that the selected geological formation is suitable for long-term CO2 storage, to predict the CO2 movement through the reservoir during the life of the process, to anticipate changes in the rock, to monitor the evolution of the CO2 and make sure that its injection is efficient and safe. This study was performed aimed to measure CO2-brine relative permeability as one of the most complex rock-fluid properties to comply with current CCUS regulations.
In this study, the experimental results of the relative permeability measurements performed in core plugs from a well located in the Gulf of Mexico and six synthetic sandstones are presented and discussed. Well permeability ranges from 2.36 mD to 763.00 mD and porosities between 18.44% and 28.43% respectively. The permeability of the synthetic cores was between 25.65 mD to 1389.76 mD with an average porosity of 21.81%. Reservoir samples were taken from the target areas where the CCS project is planned. The basic petrophysical properties were measured at net confining stress. Supercritical CO2 and Synthetic Brine were used. A proposed CO2 injection scheme was simulated in the laboratory to evaluate the injectivity. Relative permeability tests were performed by SteadyState method with In-Situ Saturation Monitoring (ISSM) by Linear X-ray attenuation. Parameters used in the experimental design were the initial water saturation, temperature, reservoir pressure, brine composition, and flow rate.
A good injectivity associated with low pressure drop was observed in the reservoir target zones. The results obtained in this study show that during CO2 flooding, the CO2-Brine relative permeability decreases as a function of the absolute permeability. The resulting curves have different shapes and end points depending on the permeability, which indicates the importance of performing the evaluation of this property in the selected zones and not only in zones with high permeability. A map created with the end points shows the behavior of the relative permeability with brine and CO2 saturation. The saturation map can be used as a tool to select the more feasible zone for CO2 storage minimizing risks of leakage and environmental problems in long-term applications.
Capillary Dynamics of Nanoconfined Water and CO2 Induced by Time-Dependent Wettability Alteration
Authors: Pan Ziqing , Zhang Kaiqiang 
Published: September 2024

Abstract
Formation wettability alteration (WA) is ubiquitous in nature and relevant to many applications spanning from geological CO2 storage to enhanced oil/gas recovery. WA and the induced capillary dynamics are of great significance in caprocks and shale reservoirs. However, the impact of nanoconfinement effect has rarely been studied. In this work, we developed a new dynamic capillary pressure model for nanoconfined water and CO2 considering time-dependent WA. A sorption-based WA model was adopted to describe the variation of wettability over time. Dynamic capillary pressure model was then established by coupling the time-dependent WA model and numerical modelling of H2O-CO2 drainage and imbibition in nanoscale bundle-of-tubes. To adapt to the nanoconfined environment, slip and entrance/exit loss modified Lucas-Washburn flow model was developed by molecular dynamics (MD) simulations and interfacial tension (IFT) was predicted using nanoscale-extended Cubic-Plus-Association equation of state and the density gradient theory. Cycles of H2O-CO2 drainage and imbibition were implemented in the nanoscale bundle-of-tubes, until the wettability of all the tubes reached its final state. Based on the results, a quantitative dynamic capillary pressure model was established with a term characterizing the speed and extent of change. The impact of nanoconfinement was investigated, where slip and entrance/exit loss effect accelerated the capillary pressure alteration, while IFT shift due to fluid-wall interaction slowed it down. The influence of pore structure was also examined. The capillary pressure of pores with triangular cross-sections changed fastest, followed by those with square cross- sections, and circular cross-sections; tortuosity reduced the speed of capillary pressure change. This new nanoscale-extended dynamic capillary pressure model accounts for the rock-fluid interaction and long-term WA induced by WA agent adsorption, which are usually ignored by conventional capillary pressure models.
A Hybrid Tabular-Spatial-Temporal Model with 3D Geo-Model for Production Prediction in Shale Gas Formations
Authors: Wang Muming , Wang Hai , Chen Shengnan , Hui Gang 
Published: September 2024

Abstract
The evolution of shale gas production has reshaped North America's energy profile. Utilizing the vast amounts of data generated from production and operations, machine learning offers significant advantages in production forecasting and performance optimization. This study proposed a pioneering hybrid model integrating tabular, spatial, and temporal modalities to enhance production forecasting in unconventional shale gas reservoirs. Despite traditional methods such as artificial neural networks (ANN) and XGBoost, which rely solely on tabular data for training and prediction, this study proposes a novel 3D-parameterization method. This approach tokenizes the formation property distribution into 3-axis tensors, enabling a more comprehensive representation of spatial data. Then, a 3D-convolutional neural network (3D-CNN) with the attention mechanism module was established to process the created spatial data. For temporal modality, the long short-term memory (LSTM) module was used to accept the dynamic input and predict the monthly production simultaneously. A total of 677 wells data from Duvernay formation was collected, pre-processed and fed into the according module based on their modality. The results show that the model combined three modalities achieved an impressive level of accuracy, with a coefficient of determination (R2) of 0.8771, surpassing the tabular (0.7841) and tabular-spatial (0.8230) modalities models. Additionally, global optimization was applied to further enhance the model performance by optimizing the architecture of each module and model hyperparameters, and a 1.88% improvement was achieved from the empirical design. These advancements set a new benchmark for predictive modelling in unconventional shale gas reservoirs, highlighting the importance of utilizing data from different modalities in improving production forecast prediction.
Exploring Feasibility and Optimization of CO2 Sequestration in Depleted Methane Hydrate Reservoirs
Authors: Sambo Chico , Gupta Ipsita 
Published: September 2024

Abstract
With the climate crisis intensifying, reducing carbon dioxide (CO2) emissions is critical. Current CO2 sequestration methods face limitations due to geological integrity risks and slow reaction rates, hindering long-term reliability. This underscores the urgent need for innovative, sustainable solutions. Increasing interest is growing in underground solid-state CO2 storage, particularly in depleted CH4 hydrate reservoirs, which are less prone to leakage and offer a more reliable option for long-term storage.
This study developed a Thermal-Hydrological-Chemical (THC) model to simulate the reactions involved in the formation and dissociation of CO2 and CH4 hydrates. Initially, the model was used to simulate methane hydrate production through depressurization. After 15 years of methane hydrate production and depletion, CO2 injection was initiated and continued for 30 years.
The simulation results indicated that the depressurization method effectively induced the dissociation of methane hydrates, leading to significant changes in reservoir properties such as porosity, hydrate concentration, permeability, and temperature. These changes facilitated methane gas production from methane hydrate, which in turn enhanced CO2 storage capacity.
To further understand these dynamics, the developed model was used to conduct a sensitivity analysis, investigating the impact of porosity, permeability, reaction frequency factor, and bottom hole flowing pressure on methane hydrate production and CO2 storage. The analysis revealed that low porosity, a high reaction frequency factor, and high permeability result in higher methane production from methane hydrate reservoirs. Improved methane recovery was also correlated with increased 0ϋ2 storage capacity. However, in this particular study, some factors seemed not to affect the storage capacity significantly because the amount of CO2 injected was much lower than the amount of methane recovered from methane hydrates.
The study found that CO2 injection for 30 years was feasible in almost all cases explored, especially when the injection rate was below 5,000 m3 and the bottom hole pressure was less than 55.5% of the initial pressure in the methane hydrate formation. It is possible that at higher injection rates, the injectivity of CO2 storage might be compromised.
Overall, the results of this work indicate that injecting CO2 into depleted methane hydrate reservoirs is a feasible and effective method for long-term CO2 storage. This approach is particularly suitable when the production well operates with minimal bottom hole pressure, leading to the recovery and dissociation of a significant amount of methane hydrates.
Detection of Low Contrast, Low Resistivity Pay (lclr) Challenge in Shaly Sand Gas Reservoir Through Acoustic Data in the on Shore Nile Delta, Egypt
Authors: Abdelwareth A. Wafik , Abdelrahman M. 
Published: September 2024

Abstract
In the onshore Nile Delta gas fields, the Upper Miocene Abu Madi clastic reservoir show significant challenges for effective gas production, development, and exploration. The Abu Madi Formation contain unconventional reservoirs, including thin-bedded intervals and low resistivity zones, which are usually overlooked by normal petrophysical evaluation techniques and conventional logging tool analyses. These challenges are mostly clear in areas with significant facies changes, typical of the complex depositional environment of the Nile Delta, or in exploratory wells. Detecting these hidden Abu Madi reservoirs is difficult due to their high shale content, which complicates formation evaluation. The maximum deep resistivity reading in these wet sand reservoirs can reach up to 1.6 ohm.m., while pay intervals exhibit low resistivity readings of less than 2.58 ohm.m. due to high water content. This narrow resistivity range often leads to misinterpretations and affects the pay calculations, reducing the reserve estimation for the whole field. The volume, distribution, and type of clay minerals present in the shale significantly affect the readings which come from conventional logging tools, especially resistivity reading. The conductive nature of clay can mask high resistivity values indicative of gas-bearing intervals, especially when these intervals are thinner than the vertical resolution of the conventional resistivity tools. This study explains that combining conventional logging data (such as gamma ray, resistivity, density, and neutron data) with acoustic data (such as shear and compressional sonic data) can effectively detect these hidden pay reservoirs. This integrated approach depends on the theory that says, while the compressional sonic waves are influenced by reservoir fluids, the shear waves are not affected by it. This methodology helps to mitigate the masking effects of shale conductivity and establishes a strong framework for detecting these hidden reservoirs. Identifying and analyzing these hidden pay zones can significantly increase commercial reserves and production, which is necessary for maintaining low water cut values and ensuring the long-term production of these gas fields. This integrated assessment ensures that valuable resources within low resistivity and thin-bedded intervals are not overlooked, thereby enhancing the identification and understanding of various unconventional reservoirs, including tight formations and shaly sand.
The Role of Miscible Gas Mixing on CO2-Enhanced Methane Recovery
Authors: Yamada Kenta , Delshad Mojdeh , Lake Larry W. , Sepehrnoori Kamy , Fernandes Bruno Ramon Batista , Farajzadeh Rouhi 
Published: September 2024

Abstract
Depleted gas reservoirs are viable choices for large-scale CO2 storage and to displace remaining methane volumes to further increase the storage capacity (EGR). However, deployment of such projects depends on an informed knowledge of the magnitude of mixing of the miscible gases, efficiency in displacing in-situ methane by CO2, composition of the produced gas, and CO2 storage capacity. This study focuses on the fundamental analysis of mixing during CO2-EGR using a numerical approach.
We propose to conduct very fine grid compositional simulations to provide insights into the mixing of CO2 and methane in a gas reservoir at different reservoir and operational conditions. We first analyze a stratified layer model to understand the basic mechanisms of scale-dependency of dispersion and the significance of reservoir heterogeneity on fluid mixing. To consider more realistic reservoir heterogeneity, a two-dimensional stochastic reservoir model is analyzed to estimate dispersivity generated as fluids flow in porous media at different scales. Reservoir heterogeneity is represented by the Dykstra Parsons coefficient (VDP) and autocorrelation length, and fluid properties are modeled depending on pressure and temperature conditions. Field-scale simulation is also performed to discuss the way dispersion is modeled in reservoir simulation affects simulated gas recovery.
Our study shows that the variance of permeability and convective spreading are the primary causes of fluid mixing at any scale. In addition, molecular diffusion is not always negligible in gas mixing even in large-scale heterogeneous reservoirs since gas has much larger diffusivity than liquid. Furthermore, the mechanism of fluid mixing during CO2-EGR is complex with the interplay between convective spreading, transverse dispersion (including molecular diffusion), and gravity segregation. Although geoscientists often assume numerical dispersion can represent physical dispersion, our study indicates this is an oversimplification and could cause significant errors in calculated gas recovery. Permeability heterogeneity is essential for the dispersion growth process and the final displacement behavior. Reservoir heterogeneity should be modeled with high-resolution grid models to analyze mixing behaviors more accurately.
A Digital Rock Physics Approach to Modeling Permeability Changes with Solid Phase Formation in Reservoir Porous Media
Authors: Rathmaier D. , Zerpa L. E. 
Published: September 2024

Abstract
This paper illustrates the application of pore-scale numerical simulation to evaluate permeability changes due to solids precipitation with Digital Rock Physics (DRP). A DRP modeling workflow is used to quantify permeability changes due to solid phase formation (precipitation of gas hydrates) based on their deposition morphology on the pore scale. Virtual representations of a sandstone sample from the Bentheimer outcrop are created using micro-computer-tomography (micro-CT) scanning images and state-of-the-art segmentation algorithms. The binarized images (pores and grains) are systematically altered with morphological operations, i.e., erosion and dilation, to represent precipitation of solids in a pore filling and a grain/pore coating morphology, respectively. The Lattice Boltzmann Method (LBM) for single-phase fluid flow simulations is used to calculate the absolute permeability of the original and the altered 3D rock models directly on the pore structure. The changes of permeability are plotted against the solid saturation to compare to empirically derived and idealistic, mathematical descriptions. We verify the suitability of the high-resolution micro-CT images for fluid flow simulations using guidelines from the technical literature. Due to the high permeability and porosity of the sample, a threshold algorithm for image binarization based on the Otsu criterion is used and yields a sample porosity of 0.28 and permeability of 4.77 Darcy in z-direction. These values for porosity and permeability are validated from measurements using a CMS-300 apparatus on the actual rock sample. Erosion is applied to the segmented pore space to represent the pore filling deposition morphology and dilation is applied to the segmented grains to represent the grain/pore coating deposition morphology of methane hydrates. A third-degree polynomial trend relating the permeability reduction with the hydrate saturation is established for the first time using the actual pore structure rather than idealized and empirically derived laws, which are non-unique, depending on which theoretical method is chosen. The presented methodology could be used to evaluate the effect of solids precipitation on scenarios like the productivity of petroleum reservoirs, and injectivity in carbon sequestration or gas storage projects.
Three-Phase Flowback Rate Transient Analysis of Shale Gas Reservoirs
Authors: Yang Chia-Hsin , Emami-Meybodi Hamid , Zhang Fengyuan , Kordestany Amin 
Published: September 2024

Abstract
We present a three-phase flowback rate transient analysis (RTA) of the multi-fractured horizontal wells (MFHWs) in shale gas reservoirs by considering condensate dropout once the hydraulic fracture (HF) pressure drops below the dewpoint. We have developed a semi-analytical three-phase flowback model that considers multiphase flow in the HF and two-phase water and gas flow in the matrix to analyze flowback data. Three HF flow regimes are considered, including two-phase water and gas infinite-acting linear flow (IALF), two-phase boundary-dominated flow (BDF), and three-phase water, gas, and oil BDF that appears once the HF pressure falls below the dewpoint. Meanwhile, IALF is considered in the matrix domain. Pressure diffusivity equations for the water, gas, and oil-phase flow are derived, and the material balance approach is used to obtain the average HF pressure with the modification of the matrix distance of investigation (DOI). We define new pseudo-variables for pressure and time to linearize the governing equations and construct the diagnostic plot for flow regime identification and the specialty plot for HF properties characterization. We obtain a diagnostic plot for each phase using the proposed semi-analytical solution. A half-slope straight line is observed in the early flowback period for the water and gas-phase diagnostic plots, indicating the IALF regime. This is followed by a unit slope line, implying the BDF regime. Furthermore, a unit slope line representing BDF is examined for the oil phase diagnostic after the HF pressure reaches the dewpoint. The numerical simulations are conducted to validate the developed flowback RTA model. Estimated HF permeability and half-length from the three-phase flow model closely match the set values in the numerical model with relative errors &lt; 10%, confirming the proposed model's accuracy. The proposed three-phase flowback model is useful in understanding the early stages of HF dynamics and its attributes.
The Advent of a Novel Selective Zonal Isolation with Thermosetting Gels
Authors: Sherief M. H. , Abdulal H. J. , Almohsin A. M. , Alabdrabalnabi M. I. 
Published: September 2024

AbstractChemical shut-off operations have the capability to remediate complex sweep unconformities particularly in mature reservoirs. Planning and executing those jobs require through understanding of sweep profile, wellbore dynamics and setting clear job objectives. Many chemicals were tried in the past decades, however, in recent years, thermosetting gels gained industry attention due to their superb physical characteristics. Those characteristics opened the door not only for great innovative applications but also making operations quicker and safer.This article delves into the practical and essential aspects to ensure successful and safe treatment targeting water and gas shut-off operations, as well as casing repairs utilizing thermosetting gels.Based on shut-off objectives, the gel type and required treatment volume are determined. The performance of the selected gel is then thoroughly evaluated in the laboratory and validated through yard testing to ensure that lab results can be replicated at the well site.During the intervention and prior to delivering the treatment volume, the treated zone is flushed to maximize the gelation process efficiency concurrently while conducting an injectivity test to assess the impact of the pumping rate on wellbore temperature. Based on observed wellbore temperature transients, the pumping schedule is optimized accordingly which is one of the critical advents of this new deployment method. Another key innovation in this new approach is to achieve simultaneous zone isolation while delivering the treatment to leave no residual gel or solid plugs that may restrict the wellbore or require post-treatment interventions. In addition to eliminating risk of getting stuck or plugging the wellbore, it reduces operation time significantly from days and weeks to less than a day and the well can be produced immediately after treatment.Overall, this approach represents a substantial advancement in chemical shut-off operations with thermosetting gels promoting efficiency, safety while meeting the evolving demands of mature reservoirs management.