bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geomechanical Modelling of Salt Caverns under Operational Loading from Hydrogen Storage
Authors: Speirs D. C. D. , Bere A. , Roberts D. 
Published: November 2022

Abstract
The anticipated prevalence of salt caverns for hydrogen storage makes it increasingly important to establish good numerical modelling techniques to simulate cavern behaviour. This involves many modelling aspects to be addressed including a proper representation of the particular material characteristics of salt and a recognition of the importance of cavern geometry. In this paper we demonstrate a 3-D finite element modelling methodology for simulating salt caverns under the type of cyclic loading expected from seasonal hydrogen production and retrieval. 3-D modelling offers the possibility to represent more complex cavern geometry than is usually represented in such work. The simulations represent generic scenarios but are used to investigate the effect of cavern geometry and variations in model size and boundary conditions. We make use of the recent constitutive model advanced by Reedlunn et al., 2022 which includes an allowance for pressure solution effects contributing to creep, and show that this can have a significant effect on cavern closure.

Introduction
Hydrogen is widely expected to play a major part in the migration away from a carbon-based energy economy and demand for high volume storage solutions is likely to grow considerably in the near future. The use of salt caverns is among the storage methods attracting the most attention.
Salt caverns are subterranean voids in domal or bedded salt formations, usually created artificially by a process of leaching. They are well suited for hydrogen storage because they can offer large capacity, rapid injection/withdrawal rates, safety advantages and long term cost effectiveness. In addition the technology is proven – such caverns being widely used over many years for the storage of other substances and more recently in limited numbers for hydrogen.
Analysis of Re-Fracturing Effect of Horizontal Wells in Jimsar Shale Oil Field
Authors: Zhao Kun , Lu Linmao , He Yongqing , Li Zeyang , Ren Guangcong , Ma Xinfang , Duan Guifu 
Published: November 2022

Abstract
As the low permeability and porosity, some severe problems including rapid production decline and low recovery ratio usually occur in Jimsar Shale Oil Field. Re-fracturing of horizontal wells is a good treatment to improve oil production and recovery ratio by enlarging the contact area between the wellbore and reservoir. Therefore, the field tests of horizontal well re-fracturing were carried out in Jimsar shale oil reservoir. However, it varied in effect. In this paper, based on the engineering parameters of primary fracturing, a fuzzy evaluation model was established firstly to quantify the potentiality of candidate horizontal wells for re-fracturing. For the test wells, a production history match was completed using reservoir numerical simulation method and the oil saturation before re-fracturing was obtained. By comparing the location of high-saturation area and new perforation, rationality of re-fracturing stages selection is determined. Finally, comprehensively using fracturing pressure and microseismic data, the initiation and propagation areas re-fractured was obtained, which showed the location of new fractures. Above all, the reason for poor re-fracturing effect is analyzed. The results show that quantitative index of each test well ranks low among the candidate wells, which means the test wells have the low potentiality to be re-fractured. For the test wells, numerical simulation results show that new perforations of re-fracturing are not located in high-oil-saturation area. The fracturing pressure of re-fracturing stages is generally smaller than primary fracturing, and the microseismic event locates in highly depleted area, which means large quantities of fluid flow into primary fractures and few new fractures are created during re-fracturing.
Toward Understanding Capillary Residual Entrapment of Hydrogen and Carbon-dioxide in Reservoir Rocks for Underground Gas Storage
Authors: Bawazeer Saleh A. 
Published: November 2022

Abstract
Underground hydrogen storage and carbon dioxide capture and sequestration in geological formations present a prominent solution for a low carbon economy. One of the main trapping mechanisms of the injected gas is the capillary residual entrapment controlled by the wettability characteristics of the reservoir rock. In the literature, there is a scarce of information about the influence of key parameters such as pressure, temperature, and organic content on the storage security. The present work discusses a fundamental capillary-based analysis using Laplace and Young equations to understand the interfacial characteristics of the gas–brine- rock system using experimental contact angle measurements of quartz and calcite samples conducted over a wide range of pressures (5, 10, 15, and 20 MPa) and temperatures (308°K, 323°K, and 343°K) using relevant reservoir brine. The analysis was carried out using typical pore throat radii (1μm) at the up-mentioned reservoir conditions. Furthermore, a correlation for the gas column height as a function of the reservoir pressure and temperature are developed. These results help for better understanding the reservoir efficiency for secure storage of H2 and CO2.

Introduction
Geo-storage technologies have been suggested as a method to store and withdraw large quantities of H2 and CO2. The geologic formation is one of the options that provide a large storage capacity. Structural trapping is the primary mechanism that holds H2 and CO2 in the subsurface geologic formations. The structural trapping is affected greatly by the capillary forces and the pore radius of the formation rocks. The capillary forces, in their turn, depend on the pressure and temperature of the subsurface geologic formations. Therefore, it is vital to assess the effect of these parameters on the storage capacity of H2 and CO2 via structural trapping under given geothermal conditions. Quartz and calcite rocks are among the most common rocks in underground formations. Hence, they are considered in the present study. This work would help in economical industrial-scale prediction of underground storage in the considered rock formations.
Prediction of Borehole Caliper Log Using Machine Learning for Multi-Stage Frac Completions
Authors: AlTammar Murtadha J. , Khan Khaqan , Alfaraj Rima T. , Altwaijri Mohammad H. , Alruwaili Khalid M. , Almarri Misfer J. 
Published: November 2022

Abstract
The objective of this paper is to highlight a new machine learning application to predict a synthetic caliper log using other available Logging While Drilling (LWD) well logs. LWD logs and wireline (WL) mechanical caliper logs for 17 tight gas wells, with more than 120,000 depth data points, were used to train a machine learning model. LWD logs included gamma ray, sonic, density, azimuthal density, porosity, photoelectric log, and mineralogy. The LWD logs were used as main input parameters in the model together with the maximum hole dimeter (Cmax) from wireline data. The model output being the synthetic maximum borehole diameter (Cmax_P) was compared with the measured caliper log. The model was trained with various machine learning algorithms including ensemble algorithms such as XGBoost and recurrent neural network (RNN). In the training process, Leave-One-Out method was implemented where 16 wells were used for training to predict the maximum borehole diameter in the remaining blind well. The results of current dataset showed good prediction accuracy with an average absolute percentage error of less than 6%. In addition, we demonstrated incorporating a physical feature related to geological layering by training the RNN with a window of multiple depth points, which clearly resulted in a predicted caliper curve that was significantly less noisy and had closer characteristics to the measured caliper curve.

Introduction
In multi-stage fracturing well completions, running a wireline mechanical caliper log is critical to obtain reliable measurements of borehole geometry along the lateral to identity packers’ placement depth for achieving adequate zonal isolation between successive fracturing stages. However, in many instances, wireline caliper logs cannot be run due to borehole conditions and drilling challenges. In such cases, various logging-while-drilling (LWD) well logs could be utilized to derive a synthetic caliper log.
Application of Machine Learning for Real-Time Prediction of Sonic Well Logs Using Surface Drilling Parameters and Gamma Ray
Authors: Alfaraj Rima T. , AlTammar Murtadha J. , Hamid Osman 
Published: November 2022

Abstract
The objective of this study is to utilize drilling parameters and gamma-ray (GR) well logs to predict compressional and shear sonic logs while drilling using machine learning techniques. Surface drilling parameters and various wellbore logs of 10 horizontal gas wells were used in this study to train the machine learning model. The drilling parameters include the rate of penetration (ROP), weight on bit (WOB), drillpipe rotation (RPM), torque (T), standpipe pressure (SPP), and mud flowrate (GPM). Petrophysical logs included GR, compressional wave slowness (DTCO), and shear wave slowness (DTSM). GR and drilling parameters were used as inputs in the model, with the model output being DTCO and DTSM. The model was trained with the XGBoost algorithm, and the prediction results on two blind wells showed an average absolute percentage error of less than 10%. Utilizing drilling parameters to predict well logs could have a significant business impact. This study demonstrates the application of machine learning for log prediction using drilling parameters in deep, long horizontal gas wells.

Introduction
Accurate determining rock mechanical and petrophysical properties is crucial in mitigating drilling risks and optimizing well productivity. Compressional and shear sonic travel time logs are critical rock petrophysical parameters, especially when it comes to formation evaluation and rock characterization for geophysical applications to predict rock elastic properties (Hossain et al., 2010; Wollner et al., 2017). Poor prediction of sonic log parameters may lead to improper estimation of rock elastic parameters resulting in severe consequences in investment decisions (Potter & Foltinek, 1997).
Hydrogen Wettability Measurement of Saudi Basaltic Rocks at Underground Storage Conditions
Authors: Alanazi Amer , Al Malallah Murtadha , Mowafi Mahmoud , Badeghaish Wael , Hoteit Hussein , Al-Yaseri Ahmed , Al-Hamad Jafar 
Published: November 2022

Abstract
Underground hydrogen (H2) storage is a prominent technique for enabling H2-based economy via offering a large-scale storage medium. Recently, volcanic basaltic formations have been investigated as a potential medium for gas storage due to their thickness, vast extension, and potential volumetric capacity. Wettability is one of the essential parameters studied to understand the capillary-entrapment of the stored gas in porous media. Therefore, in this study, we evaluate the wettability of rock/H2/brine system of two different saudi basaltic rock samples by measuring the contact angles using relevant reservoir brine (10% NaCl) under storage conditions at temperature of 323K and varying pressures (3 to 28 MPa). The measurements were conducted using the modified sessile drop method and surface roughness was determined to ensure accurate results. The results showed relatively low variation with pressure. Saud basalt-1 with higher Si-O-Si and hydroxyl group bondings from FTIR demonstrated better sealing conditions for H2 storage than Saudi basalt-2. Additionally, the pore throat radius has a proportional relationship with 𝑝𝑐𝑒 and ℎ𝑔𝑚𝑎𝑥. Smaller pore-size basaltic rocks are better for safe and secure storage, and a potential effective capillary entrapment of H2.

Introduction
Governments and countries worldwide are adapting strict environmental regulations to reduce harmful anthropogenic emissions of greenhouse gases such as carbon dioxide (CO2), attributed mainly to the burning of fossil fuels (Hashemi et al., 2021; IEA, 2018). Alternatively, hydrogen (H2) emerges as a promising clean fuel to support decarbonization by converting energy production from fossil fuels into a more environmental-friendly form and supporting clean energy from renewable resources such as wind turbines and solar power (Pan et al., 2021). However, wide-scale implementation of an H2-based economy requires a medium of Giga to Tera scale storage capacity, which can be theoretically offered by geological formations such as saline aquifers, depleted oil and gas reservoirs, and salt caverns (Heinemann et al., 2021).
Feasibility Evaluation of Hydraulic Fracture Penetrating Propagation in Sand-Mud Interlayer Reservoirs under Different Combinations of Fracturing Parameters
Authors: Wu Guangai , Tao Lei , Jiang Hu , Guo Xu , Zhang Anshun , Tang Xuanhe , Zhu Haiyan 
Published: November 2022

Abstract
Low-porosity, extra-low-permeability tight sandstone oil and gas reservoirs have become an important research area for hydraulic fracturing. Sand-mud interlayer is often developed in this type of reservoir in the longitudinal direction. The heterogeneous distribution of oil layers and mud shale barrier layers in the longitudinal direction will lead to restrict propagation of hydraulic fractures in the fracture height direction, which affects the effective stimulated reservoir volume significantly. In this paper, a finite element model of hydraulic fracture propagation in sand-mud interlayer was established based on the real characteristics of the target block formation to study the hydraulic fracture penetrating propagation feasibility under different combinations of fracturing parameters in the tight sandstone reservoir in the target block, and the model verification was completed with the field data. A total of three types of variable orthogonal combinations of 7 kinds of viscosities of fracturing fluid, 5 kinds of injection rate and 8 kinds of thicknesses of barrier layer were carried out to explore the penetration feasibility of hydraulic fracture under the commonly used combination of low injection flow rate and high viscosity in offshore and high injection flow rate and low viscosity in onshore shale gas reservoirs. And the feasibility evaluation plate of the hydraulic fracture penetration propagation in sand-mud interlayer is established. The method for evaluating the feasibility of hydraulic fracture penetrating propagation in sand-mud Interlayer under different combinations of fracturing parameters can be well applied to the tight sandstone reservoir in this paper. And it will provide theoretical guidance for hydraulic fracture design and fracturing parameter optimization. In addition, the method can also be applied to the fracturing development of shale reservoirs with sand-mud interlayers.
Compaction and Subsidence Geomechanics: A Case Study from the North Sea
Authors: Green S. , Hickman R. J. , Cox P. 
Published: November 2022

Abstract
We present a case study for the assessment of depletion of the Blythe Field in the Southern North Sea and the potential impact on the overlying Dudgeon windfarm, including an analytical solution, and make comparisons with the well-studied analogue Groningen Field before presenting the results. The key focus of this analysis was to aid in the assessment of how oil and gas activities could co-exist with other operations in the same location, namely the impact between infrastructures at the surface and in the sub-surface. The results of the study, and the validation via the comparison to the analogue Groningen Field, provide confidence that production and depletion of the Blythe Field will have minimal-to-no impact on the Dudgeon windfarm that sits directly above the field on the seabed. Studies of this type allow for conventional oil and gas activities and other types of energy production to be safely risked and assessed in terms of being active in the same location, maximizing the potential for energy generation whilst minimizing the risk to the infrastructure, the environment, and to health and safety.

Introduction
Blythe and Elgood were initially discovered between 1966 and 1990 and now sit under the Dudgeon windfarm. The current operator plans to drill two wells to produce 70 bcf of gas during 6 years of production, with an associated pore pressure decrease and reservoir compaction which may affect the overburden sequence and requires assessment.
Reservoir compaction and land subsidence occur when large amounts of pore fluids have been withdrawn from underground reservoirs. Magnitudes of compaction and subsidence in oil and gas fields vary greatly depending on characteristics of the rock properties and field geometry. The effects of compaction and subsidence range from beneficial to detrimental; examples include seabed subsidence at the Ekofisk Field leading to remedial action required on the jack-up rig and casing damage such as that at the Valhall and Shearwater fields. Therefore, assessment of the potential for large magnitude compaction and subsidence must be carried out during field planning.
Laboratory Experiments on the Cyclic Gas Injection Process Using CO2, C2H6, and C3H8 To Evaluate Oil Recovery Performance and Mechanisms in Unconventional Reservoirs
Authors: Sennaoui B. , Pu Hui , Malki M. L. , Afari A. S. , Larbi A. , Tomowewo O. S. , Araghi R. H. R. 
Published: November 2022

Abstract
Low primary recovery percentages (usually 10% or less) in unconventional reservoirs, such as the Three Forks Formation in the Williston Basin, mean that potentially billions of barrels of oil are left behind in the reservoirs. Gas enhanced oil recovery (EOR) pilot studies that were performed in the Three Forks Formation suggest that cyclic gas injection is a viable approach for enhancing oil recovery in unconventional reservoirs. Due to limited knowledge of the cyclic gas injection mechanisms and the interaction between the injected gases and Three Forks reservoir fluids, additional investigations are mandatory despite of the pilot studies and the published findings in the Three Forks Formation. This paper conducts a series of experiments on core samples from the Upper Three Forks (UTF) and Middle Three Forks (MTF) under different constraints. The parameters that affect the performance of the cyclic gas injection during the Huff and Puff (HnP) technique are analyzed, including soaking time in miscible and immiscible conditions, injection pressure, vapor-supercritical states, density change, gas type (CO2), Ethane (C2H6), Propane (C3H8), within these formations (Upper Three Forks, and Middle Three Forks), and the microscopic pore distribution effect on hydrocarbon transport for the production using the Nuclear Magnetic Resonance (NMR) approach. The findings indicated that the soaking time improved recovery factors significantly below and close to the CO2's minimum miscibility pressure (MMP), but its effectiveness decreased for the injection pressures over the MMP. At low injection pressures, propane (C3H8) was shown to be the most effective gas, followed by ethane (C2H6) and then carbon dioxide (CO2). Due to a significant shift in density, ethane (C2H6) and carbon dioxide (CO2) both performed better during increasing pressure. In contrast, increasing the injection pressure of propane (C3H8) above 6.89 MPa did not affect the performance since the density of propane at 6.89 MPa caused a negligible density change. Additionally, the NMR measurements conducted at the UTF indicated that in the first cycle of HnP, oil extraction was dominated by micropores, mesopores, and less by small pores. Increasing the HnP cycles, micropores will be the dominant source of oil production. However, in MTF, the mesopores were the dominant pore distributions, followed by small pores, which affect the micro oil mobilization during the HnP process. This work provides a new insight into understanding the mechanisms of gas HnP enhanced recovery in the Three Forks formation, which is of great significance for the efficient hydrocarbon exploitation and greenhouse gas utilization in the Three Forks.
Geomechanical Feature Classification with a New Logging-While-Drilling Dual Ultrasonic Tool
Authors: Yamamoto H. , Blyth M. , Sakiyama N. , Shrivastava C. , Sagara M. , Barry A. 
Published: November 2022

Abstract
Effective geomechanical analysis requires a thorough understanding of the complexities of the formations drilled, such as stress-induced anisotropy, intrinsic anisotropy, azimuthal heterogeneity, drilling induced and natural fractures, and/or borehole damage. The identification and classification of these features can be complex, particularly when multiple different types are present together. The conventional sonic tools can struggle to differentiate these effects when more than one is present and often are lacking in the capability needed to clearly resolve them mainly because of the limited spatial resolution associated with the probing sonic frequencies. A new logging-while-drilling (LWD) dual ultrasonic tool has been developed, that provides high-resolution, full-azimuth, ultrasonic compressional and shear (P&S) slowness images together with ultrasonic borehole images and caliper that can be used to help address this formation complexity on multiple scales and so to improve geomechanical models and analysis. In this paper, we study feasibility of classifying formation geomechanical features, such as intrinsic anisotropy, stress-induced anisotropy, and azimuthal heterogeneity, using the ultrasonic P&S slowness from the LWD dual ultrasonic tool, and discuss conditions when such classification is expected to be successful and when more integrated approach is needed to address complexity of formations.

Introduction
Understanding the complexity of formation mechanical properties is very important for effective geomechanical analysis, such as the optimal design of hydraulic fracturing or wellbore stability analysis for safe and cost-effective drilling. Conventionally, standard sonic logging has been used to provide key acoustics measurements to characterize the formation mechanical properties axially, azimuthally, and radially (Pistre et al., 2005). These measurements are made at sonic frequencies, which results in an intrinsic limitation for resolving layers smaller than 1-ft thickness, because of the probing wavelength at these operating frequencies. A recently developed LWD dual ultrasonic tool demonstrated the ability to deliver P&S slowness measurements and images that resolve inch-scale bedding (Blyth et al., 2021). The P&S slownesses measured at ultrasonic frequencies deliver measurements with 2-in vertical resolution and in 16 azimuthal sectors around the wellbore. The tool also provides borehole images and calipers with ultrasonic pulse-echo measurements. P&S images from the field test data showed evidence that both intrinsic and stress-induced anisotropy can be revealed using LWD dual ultrasonic data at a similar fine resolution scale.