bluuebunny/crossref_metadata_2025_split huggingface dataset:
ABYSS. II. Identification of Young Stars in Optical SDSS Spectra and Their Properties
Authors: Saad Serat , Lane Kaitlyn , Kounkel Marina , Stassun Keivan G. , López-Valdivia Ricardo , Kim Jinyoung Serena , Peña Ramírez Karla , Stringfellow Guy S. , Román-Zúñiga Carlos G. , Hernández Jesús , Wolk Scott J. , Hillenbrand Lynne A. 
Published: February 2024

Abstract
We developed a tool that measures equivalent widths of various lines in low-resolution optical spectra, and it was applied to stellar spectra obtained as part of SDSS-V and LAMOST programs. These lines, such as Li i, which directly indicates stellar youth, or optical H i and Ca ii, which in emission indicate activity associated with stellar youth, are commonly seen in YSOs. We observe several notable differences in the properties of these lines between YSOs and the field stars. Using these data, we devise a set of criteria through which it is possible to confirm the youth of stars that have been observed by the ABYSS program, as well as to identify likely young stars that have serendipitously been observed by other programs. We examine the decrement of H lines seen in emission in CTTSs, and estimate the properties of the accretion stream that is responsible for the production of these lines. Finally, we examine the evolution of Li i as a function of age, and characterize the scatter in its abundance that appears to be intrinsic in young M dwarfs.
Large-scale Mapping Observations of DCN and DCO+ toward Orion KL
Authors: Taniguchi Kotomi , Rayalacheruvu Prathap , Yonetsu Teppei , Takekoshi Tatsuya , Hatsukade Bunyo , Kohno Kotaro , Oshima Tai , Tamura Yoichi , Yoshimura Yuki , Gómez-Rivera Víctor , Rojas-García Sergio , Gómez-Ruiz Arturo I. , Hughes David H. , Schloerb F. Peter , Majumdar Liton , Saito Masao , Rodríguez-Montoya Iván , Sánchez-Arguelles David , Kawabe Ryohei 
Published: February 2024

Abstract
We present emission maps (

1

.′

5

×

1

.′

5

scale, corresponding to 0.18 pc) of the DCN (J = 2 − 1) and DCO+ (J = 2 − 1) lines in the 2 mm band toward the Orion KL region obtained with the 2 mm receiver system named B4R installed on the Large Millimeter Telescope. The DCN emission shows a peak at the Orion KL hot core position, whereas no DCO+ emission has been detected there. The DCO+ emission shows enhancement at the west side of the hot core, which is well shielded from the UV radiation from OB massive stars in the Trapezium cluster. We have derived the abundance ratio of DCN/DCO+ at three representative positions where both species have been detected. The gas components with V
LSR ≈ 7.5–8.7 km s−1 are associated with low abundance ratios of ∼4–6, whereas much higher abundance ratios (∼22–30) are derived for the gas components with V
LSR ≈ 9.2–11.6 km s−1. We have compared the observed abundance ratio to our chemical models and found that the observed differences in the DCN/DCO+ abundance ratios are explained by different densities.
Detection of Solar-like Oscillations in Subgiant and Red Giant Stars Using 2 minute Cadence TESS Data
Authors: Zhou Jianzhao , Bi Shaolan , Yu Jie , Li Yaguang , Zhang Xianfei , Li Tanda , Long Liu , Li Mengjie , Sun Tiancheng , Ye Lifei 
Published: February 2024

Abstract
Based on all 2 minute cadence TESS light curves from Sector 1 to 60, we provide a catalog of 8651 solar-like oscillators, including frequency at maximum power (

ν

max

, with its median precision σ = 5.39%), large frequency separation (Δν, σ = 6.22%), and seismically derived masses, radii, and surface gravity values. In this sample, we have detected 2173 new oscillators and added 4373 new Δν measurements. Our seismic parameters are consistent with those from Kepler, K2, and previous TESS data. The median fractional residual in

ν

max

is 1.63%, with a scatter of 14.75%, and in Δν it is 0.11%, with a scatter of 10.76%. We have detected 476 solar-like oscillators with

ν

max

exceeding the Nyquist frequency of Kepler long-cadence data during the evolutionary phases of subgiants and the base of the red giant branch, which provide a valuable resource for understanding angular momentum transport.
A Gradient-Accelerated Two-Stage Multi-Objective Optimization Algorithm for WAG Injection
Authors: Liu Shuaichen , Yuan Bin , Zhang Wei , Huang Gang , Fu Tingting 
Published: February 2024

AbstractSummaryThe multi-objective optimization of CO2-water-alternating-gas (CO2-WAG) injection identifies the optimal well control scheme that co-optimizes NPV and CO2 storage. Considering the expensive computational cost of the compositional simulation, a popular approach is to use a surrogate model to replace the costly numerical simulation in the optimization process. The data-driven surrogate model, on the other hand, has poor generalization, and each round of optimization requires the addition of sample points to calibrate the surrogate model, which significantly increases the cost and time required for optimization. In this paper, a two-stage optimization strategy is proposed to address the above issues. The strategy includes two stages. The first stage performs the surrogate-assisted single-objective optimizations of each considered objective. It is designed to find the endpoints of the Pareto front that connects all solutions of the multi-objective optimization, this preparation stage not only provides important search directions for the subsequent multi-objective optimization, but also improves the accuracy of the surrogate model near the Pareto front. The second stage is the surrogate-assisted multi-objective optimization, which aims to find all the solutions along the Pareto front based on the Pareto endpoints obtained from the first stage. In addition, this study successfully combines the gradient of the objective functions with the meta-heuristic algorithms during the multi-objective optimization, which ensures a faster convergence to the global optimum. The proposed multi-objective optimization algorithm shows faster convergence than the conventional optimization methods when applied to the three classical multi-objective optimization problems. Finally, a comparison with the conventional multi-objective optimization is conducted based on one test function and one benchmark reservoir simulation model to verify the efficiency of the proposed method. It is confirmed that the proposed method outperforms the conventional ones for the optimization of CO2-WAG injection.
Geomechanical Risk Analysis for Feasibility Assessment and Evaluation of CO2 Injection and Long-Term Storage
Authors: Tan C. P. , Musa I. H , Kamaruddin N. F. Nik 
Published: February 2024

Abstract
One of the efforts to reduce the impact of climate change is by reducing carbon dioxide (CO2) emission through carbon capture and storage (CCS) operation. As part of CCS feasibility study, geomechanical risk analysis is conducted on the field of interest to determine maximum injection pressure as well as the associated geomechanical risks during injection and long-term storage.
In geomechanical risk analysis, first fully calibrated and validated 1D geomechanical models are developed from the available log data of the wells in the field of interest. Using the rock mechanical properties as input, caprock integrity analysis is conducted and maximum injection pressure is determined to ensure the caprock does not experience tensile or shear failure during CO2 injection. If there are faults penetrating the caprock and reservoir of interest, fault stability analysis is conducted on the faults to ensure the faults remain stable. Finally, reservoir expansion and seabed uplift analyses are conducted to determine the maximum seabed uplift.
This methodology has been applied to one of the CO2 storage site candidates located in offshore Peninsular Malaysia. 1D geomechanical models for the wells in the field are constructed and calibrated with pore pressure and stress measurement data. Wellbore stability analysis was conducted and validated with drilling experience and caliper log. Rock mechanical properties and stress data were extracted at formation of interest for caprock integrity analysis. Changes of minimum horizontal stress at caprock due to reservoir pressure increase due to CO2 injection was calculated to determine the injection pressure that will cause tensile or shear failure. Safety factor is applied to the pressure for final maximum injection pressure in the formation. Fault stability analysis was conducted on all the faults intersecting the formations of interest using the rock strength properties and stress data from the 1D geomechanical model of the nearest well to the fault. Normal and shear stresses plotted in the shear stress-normal stress plot for pre- and post-injection showed that all the faults remain stable. Finally, reservoir expansion was calculated and used as part of the input for seabed uplift analysis. Low seabed uplift was determined at the end of injection, and it will not impact the surface facility integrity.
Application of 3D Geomechanical Research for De-Risk and Improve High Pressure and High Temperature Well Drilling
Authors: Gao Xiang. , Xing Yangmei. , Wang Mengcong. , Xu Miao. , Long Xuechen. , Huang Xingning. 
Published: February 2024

Abstract
The CN oilfield is the main block of the X oilfield to increase reserves and production. However, the wells in this area are ultra-deep, and many sets of complex and difficult-to-drill formations are encountered in top-down drilling, which brings significant challenges to the drilling engineering. Based on triaxial and shear experiments, transverse isotropy theory and weak surface criterion, and integrating the mechanical damage under stress unloading and hydration in drilling wells, a borehole stability model under the synergistic effect of stress unloading and hydration has been established, and an analysis of the factors influencing the stability of the borehole of the formation has been carried out. The study shows that stress unloading occurs after drilling. The greater the confining pressure and axial stress, the more significant the shale strength weakening caused by stress unloading, and the magnitude of stress unloading is positively correlated with the degree of mechanical strength weakening. The more developed the laminations are, the easier it is to damage along the laminations. When stress unloading occurs, the weak structural surface acts synergistically with stress unloading, and the higher the degree of shale strength weakening is, the worse the mechanical stability is and the higher the risk of borehole instability. External fluids are prone to intrude along the bedding and promote shale hydration, making the shale mechanically less stable and reducing the borehole's stability. The effect of stress unloading on shale formation collapse pressure mainly occurs in the pre-drilling stage, and the effect of hydration damage on borehole instability mainly occurs in the late drilling stage. Beddings, stress unloading, and hydration affect the borehole stability together. The shale borehole stability model under stress unloading-hydration synergistic effect considers the influence of the three comprehensively. The prediction results align with the drilling actuality with good reliability after the field application test.
Predicting the Microbial Effects on Hydrogen Storage Quality - A McKee Reservoir Study
Authors: Katterbauer Klemens , Qasim Abdulaziz , Al Shehri Abdallah , Yousef Ali 
Published: February 2024

AbstractThere has been a lot of interest in hydrogen storage in subterranean reservoirs in order to overcome some of the challenges in the seasonal differences in supply and demand for energy and support the energy transition. The combustion of hydrogen produces energy and water as an output, making it a good energy transporter that may also be used to store energy. The high energy density of hydrogen makes it an excellent reactant for a variety of chemical reactions that may be utilized. Given that hydrogen is increasingly being used to assist the energy transition, it may be stored in a variety of forms, including metal tanks and subterranean subsurface storage reservoirs. In addition, hydrogen may be kept in deep geological formations and mixed with natural gas and other minerals. Given the enormous volumes of hydrogen that need to be stored, subsurface hydrogen storage has garnered a lot of interest. Underground natural gas storage has been conducted for a very long time in salt caverns and porous rock formations with extensive amount of experience being acquired. Given the lack of expertise with underground hydrogen storage, which has mostly only been done in salt caverns, there are several uncertainties that arise in the hydrogen storage in subsurface formations. For the investigation of microbial effects on subsurface hydrogen storage, we have created a data-driven approach in order to assess the impact of the microbial effects on hydrogen subsurface storage. In order to examine their composition and determine possible implications on the hydrogen production from the reservoir, the framework incorporates 16S rRNA sequencing data from subsurface hydrogen storage locations to identify bacterial populations. A simulated hydrogen storage was used to assess the framework, and it demonstrated high classification performance as well as accurate prediction of the expected hydrogen recovery from the subsurface environment.
Application of In-Situ Stress Evolution and Its Impact on Infill Well Fractures Propagation in Unconventional Reservoir
Authors: Jiang Lin. , Sun Chaoya. , Luo Tongtong. , Huang Xingning. 
Published: February 2024

Abstract
Hydraulic fracturing of horizontal wells is an effective development mode for low-permeability reservoirs, while new drilling can enhance reservoir recovery. The drilling, fracturing, and production processes all induce changes in reservoir stress, affecting the infill wells’ fracture design. Adoption of finite element-based discontinuous discrete fracture numerical method. The extension of wellbore and fracture is described by dynamic mesh technology during drilling and fracturing, and the discontinuous discrete fracture model can be computed by using a conventional finite element mesh, which can be perfectly matched with the discrete fracture model, so as to realize the integrated numerical simulation of drilling-fracturing-production. Use the construction of infill wells in low-permeability reservoirs in Area 8 as an example, the integrated simulation of drilling-fracturing-production is carried out for the wells to be constructed in the encrypted well area, and the maximization of the exploitation economy of the well area guides the optimization of the infill wells’ fracturing. The simulation results show that the long-term production process of the old well reduces the formation pressure and ground stress in the encrypted well area, and the direction of the maximum horizontal principal stress is deflected. Considering the influence of the old well production, the drilling fluid density during the drilling of the encrypted well can no longer be designed using the original formation pressure profile. With the drilling fluid column pressure not greater than the minimum horizontal principal stress at this stage, the direction of maximum horizontal principal stress around the encrypted well is further deflected after the wellbore is drilled open, causing the initial expansion direction of the fracture to be deflected along the wellbore; injecting water to boost the pressure of the old well prior to the fracturing of the encrypted well can improve the fracturing effect of the encrypted well. The established numerical method can realize the simulation of reservoir stress evolution in the whole process of drilling-fracturing-production and the integrated numerical simulation of fracturing-production, which can optimize the design of fracturing in infill wells and improve the single-well production.
Integrating Fiber Optic Surveys with Petrophysics and Geomechanics for Sanding Monitoring and Sand Control Decisions in a Mature Field
Authors: Khaksar A. , Younessi A. 
Published: February 2024

Abstract
Identifying the sand-prone zones and the severity of sanding in wells with multi-layered hydrocarbon producing reservoirs or commingled completions is the key to designing fit-for-purpose sand control measures to ensure the continuation of safe operations, enhancing productivity and recovery. Sanding evaluations are commonly calibrated against either surface sand observations, hole fill events, hold up points or rock mechanical simulations. Although advanced geomechanical and petrophysical analyses can identify the likely sand producing intervals, in the absence of direct and independent downhole observations, the validity of such analyses can often be a concern. This study shows results of the emerging technology of Distributed Acoustic Sensors (DAS) from fiber optic surveys in live wells used for downhole sand detection in a mature offshore gas field in SE Asia. The integration of DAS signal processing with production logging (PLT), surface sand detectors and independent geomechanical and petrophysical evaluations proved very useful for through tubing sand control decisions in the study wells. The results of the petrophysical and geomechanical sanding evaluation provided in-depth insights into the likely sand-prone zone under varying flow rates and given reservoir pressures. Sand-prone zones are identified for current conditions and the severity of sanding with further depletion or flow rates is assessed for individual wells. DAS signal interpretation results in the second trial well are in full agreement with PLT data, surface sand monitors and the independent geomechanical evaluations. In the first well, further fine-tuning of DAS signal processing or a re-run may still be needed. Geomechanical analyses indicate that in both study wells, sand face failure will be very likely, even at the lowest tested flow rates of less than 15 MMSCFPD where no or limited sands were detected at the surface. DAS signals also indicate sand ingress signals at low flow rates in both wells. The workflow developed appears applicable to different well trajectories, depletion, and drawdown conditions. The technology has the potential for advanced production management that optimizes production and improves sand management decisions in existing wells with sanding issues.
Finite Element Modelling for Refined Assessment of Subsea Slope Stability
Authors: Adzim Abdul , Abdullah Hafizzi 
Published: February 2024

Abstract
This paper presents work undertaken at the project front-end stage of reducing to ALARP the risk of subsea flowline rupture from impact of debris flow upon collapse of a slope due to a seismic event. The scope involved soil sample testing, novel finite-element analysis techniques and development of site-specific probabilistic seismic hazard assessment (PSHA).
The subsea flowline traverses a route which has steep local slopes in close vicinity. Preliminary seismic slope stability assessment indicated the slopes have marginal factors of safety and would fail during a seismic event, causing mass gravity flow. Seabed topography will channel the mass gravity flow to impact the flowline. Landslide runout modelling of the slope failure quantified the mass gravity flow impact forces onto the flowline, and subsequent calculation demonstrated the flowline would instantaneously rupture under these impact forces.
Finite-element modelling was used to refine the preliminary slope stability assessment, to remove the conservatism assumed in initial work and obtain a more representative actual stability of the slope.
ABAQUS software was used to build a model of the slope. Site specific geotechnical input parameters were required for the model. As such, a suite of specialized tests on borehole samples were performed to generate these parameters and used in the model. A site response dynamic analysis was run using a purpose-built non-linear program to analyze the response of the slope under seismic acceleration forces. Initial input motions for the dynamic analysis were derived from the PSHA of an adjacent site. Concurrent work was performed to develop site-specific PSHA for later comparison.
The dynamic slope stability demonstrated that the slope remains stable under the most onerous motions of a 4000-year return period Abnormal Level Earthquake (ALE), with significant margin.
Additional analyses were performed to assess the severity of an event that might be required to cause slope failures by factoring the acceleration time histories by factors of up to 3.6. The slopes still remained stable throughout the intensified accelerations.
The site-specific PSHA acceleration time histories were compared to those used in the analysis. It was found that input motions used in the analysis exceeded the site-specific 10,000-year return period seismic event motions, and in the case of the analysis using the factor of 3.6, by a very large margin. This provided project confidence that the steep slopes within the vicinity of the flowline are indeed stable under a seismic event. The flowline is demonstrated to be free from the threat of a mass gravity flow impact.
Implementation and Application of Active Slug Control on Production System: a Real Field Case Study Workflow
Authors: Lim S. , Rahim A. , Chong M. , Mansor M. 
Published: February 2024

Abstract
Slugging is a dynamic flow behavior observed in many multiphase production systems. It is due to the rapid change in volumetric phase flowrates within a process. Various slug mitigation strategies have been implemented in production facilities over the world to ensure stable production and maximum field recovery. This paper aims to present the project overview, workflow and use cases for the implementation of an active slug control technology based on real-field project experiences.
An active slug control algorithm can be used for slug mitigation on upstream production systems. The purpose is to stabilize production flow from the flowline inlet to the first stage separator so that stable and safe production is ensured within the system design constraints. This in turn has the potential to increase production flow and further extend field life of aging production facilities. This paper presents examples of feasibility assessments and field implementations, covering both conventional oil and gas-condensate production. An active slug control technology can be applied to both deep-water and shallow-water facilities. Installation of this slug control system requires only an update to the existing flow controller to include an additional algorithm for slug suppression at the riser top choke valve. This simple addition eliminates the requirement of active operators’ intervention in the event of slugging, as well as reducing the frequency of process trips. In comparison with other slug control methods, this technology is cost-effective since no additional process equipment is required to be installed and maintained. As a result, this significantly reduces the project execution time, avoids production disruptions, and minimizes potential HSE issues. The technology can be implemented within a year from the outset of a feasibility study. However, the technology is not appropriate for all situations due to differences in slugging nature and other subsurface issues and therefore its applicability needs to be evaluated on a case-by-case basis.
With increasing number of aging offshore assets and competitiveness in the energy market, it is expected that active slug control technology will become a crucial tool to reduce production downtime and deferment. This paper also presents a workflow which aims to provide a general guideline for the feasibility assessments and implementation of this slug control technology on producing assets. The objectives of slug mitigation may vary from asset to asset due to differences in production conditions, slugging characteristics and facilities design. Therefore, strong client engagement is necessary to ensure the most optimal workflow for the technology to be implemented.