bluuebunny/crossref_metadata_2025_split huggingface dataset:
Change and Characterization Method of Formation Sand from Reservoir to Wellbore
Authors: Shanshan Liu 
Published: October 2024

Abstract
The factors affecting sand production in weakly consolidated reservoir include formation characteristics, well completion and production parameters, etc. The flow space of oil and sand includes porous media, sand control media and production wellbore, which is continuous in space (reservoir - bottom hole - wellbore). In view of the key problems of sand production management, the concept of integration in the sand control completion project is applied to carry out the research on the sand particle change law in the whole flow area from the reservoir to the wellbore. A fractal dimension of the formation sand particle size which reflects the distribution characteristics is proposed to depict the migration change law of the formation sand from the reservoir to the wellbore production system. CFD-DEM (Computational Fluid Dynamics - Discrete Element Method) simulation method is conducted to study the micro sand blocking process of slot screen and a prediction model for cumulative sand production quality and particle size distribution were established. This article studies the filtration of sand control media and the migration law of sand particles in the wellbore. Considering the influence of sand particle size distribution characteristics on solid-liquid two-phase flow, a horizontal wellbore sand concentration prediction model was established based on single factor analysis method and Buckingham's theorem. The influence of different flow conditions on the sand concentration in the wellbore section was revealed. The innovation of the paper is introducing the fractal dimension of sand particles into the establishment of quantitative sand production prediction models and wellbore sand concentration models.
Application of Vapor Acid Matrix Acidizing in Clastic Reservoir: Laboratory Test and Field Trial
Authors: Razali A. Mohammad , Berok S. M. James , Lee Q. Z. , Yeap W. J. , Ahmad N. A. , Ismail W. R. Wan , Sidek S. , Jeffry S. Mohd , Mohamad W. A. Wan , Madon B. , Dzulkarnain I. 
Published: October 2024

Abstract
A new method of acid matrix stimulation treatment was deployed in offshore Field S to remove formation damage in one of the gas producers. The new method involved deploying an inert stable solid chemical stick downhole via wireline. Once deployed downhole and activated to burn, heated vapor of Hydrochloric Acid (HCl) and mud acid is generated in sequence to react with the formation and the well is then ready for flowback after four hours of soaking. This new method has effectively simplified acid stimulation treatment operations by eliminating pumping operations using barge, which resulted in a more cost-effective solution.
The treatment consisted of HCl and mud acid only, which is an uncommon practice for a typical acid matrix treatment for clastic formation. Without additives, solid precipitations are a major concern as it can cause further damage to the near wellbore region. Hence, extensive laboratory analysis were conducted on the reservoir core samples to investigate the effect of 15% HCl and mud acid without any additives. The main objective was to determine the return permeability post acid treatment and subsequently evaluate potential solid precipitations. The laboratory analysis conducted were coreflood, dissolution and compatibility test.
Coreflood test results showed reduction in permeability post treatment by 25% due to solid precipitations which was further identified through mineralogy and Inductive Coupled Plasma (ICP) analysis after the acid treatment. The dissolution test showed 10% to 11% of overall sample weight loss. This paper describes the details of the laboratory analysis and findings from the job execution of pure acid stimulation treatment (without additives) for a clastic formation. Best practices and lessons learnt during job preparation and execution will be discussed to provide insights for future technology replications.
Underground Gas Storage Thermal Effects on Wellbore Integrity and Operation Safety – a Case Study from a Carbonate Reservoir in High Tectonic Stress Region
Authors: Yu Huijuan , Sinaki AmhadReza Younessi , Yang Ying , Wang Yan , Mao Chuanqin , Tang Zhiping , Li Liming , Salter Tim , Ma Xiyu 
Published: October 2024

Abstract
High injection and production rate is a typical feature of underground gas storage (UGS) wells at each seasonal circle, which cause temperature change due to Joule-Thomson effect. Through an UGS case study of Southwest China, this paper demonstrates that cooling effect augments pressure related in-situ stress changes, which has impact on wellbore and cap rock integrity and UGS operation safety.
Cooling effect was clearly observed in high-rate wells at the crest of the reservoir during injection and production cycles. Thermal analysis was carried out to investigate the risks associated to the UGS operation.
The results of analytical Energy Balance Equation (EBE) indicates that the 20°C-temperature drop can happen at the near wellbore 15-80m region, and the 10°C-temperature drop can happen at the near wellbore 30-150m region. Rreservoir thermal modelling which accounts for heat transfer between the reservoir and its overlying and underlying formations show a temperature reduction of 4 ~ 18 °C in vicinity of the well, with an impact radius of 15~150 m from the injection boreholes. This was more pronounced around the higher injection rate wells. From thermoelastic equations, these results are used to evaluate the range of stress reduction induced by thermal contraction of overlaying and underlaying rocks. Subsequently, the upper pressure limit for caprock integrity was modified.
It is not paid much attention to thermal/cooling effect in the many of UGS operations, and its impact on rock stress change by high-rate injection and production is ignored. This paper showed that the cooling effect shouldn't be ignored during UGS safety operation to ensure the wellbore integrity and formation sealing integrity. The methodology established in this case study can be referred by other UGS and gas storages projects.
Analysis of Technologies and Methods of Hydrogen Storage in Liquid Organic Hydrogen Carriers
Authors: Zhang Xi , Li Yiheng , Zhang Chenjun , Zhang Lin , Yu Huidi , Zhang Lanqiong , Liu Xiaodan , Miao Sheng , Wang Xiaoqi , Wang Shanyu , Jin Xu 
Published: October 2024

Abstract
For hydrogen storage and transportation, liquid organic hydrogen carriers (LOHCs) are got into focus within the latest years since their volumetric storage density and the similarity in their material properties to currently common fuels. This paper mainly evaluates four most promising LOHC systems. Then a detailed examination of the four systems is given, with particular focus on the hydrogenation and dehydrogenation reactions and the required catalysts. The main drawback of LOHCs systems and the potential for heat integration and efficiency improvements are presented at the last section.
Coal Seams as an In-Situ Filter for Hydrogen Separation
Authors: Sayyafzadeh M. , Camilleri M. , Heryanto D. , Sander R. 
Published: October 2024

Abstract
Coal exhibits a selective sorption mechanism, making it a potential natural filtration system for gas purification. This study explores the use of coal seam gas reservoirs for the simultaneous separation and storage of carbon dioxide (CO2) from a mixture of hydrogen (H2) and CO2, the main products of Steam Methane Reforming (SMR). In this work, we present the results of two experimental tests, conducted on a core sample from the Bowen Basin. First, we measured and characterized H2 sorption onto the coal sample. Then, we performed a proof-of-concept experiment—a binary-component coreflooding test— to assess the competitive sorption behavior of H2 and CO2. The sorption measurements confirmed the low affinity of coal to H2, consistent with earlier observations in the literature. We also compared the results of H2 sorption with the CO2 sorption measurements of the same core sample. The comparison demonstrated that the coal sorption capacity for CO2 is approximately seven times greater than its capacity for H2 at a pressure of 10 MPa. The coreflooding test verified that a similar sorption contrast can be expected when the coal is exposed to a mixture of H2 and CO2. For this test, first, we equilibrated the sample with pure hydrogen and then continuously injected a mixture of H2 and CO2 with a molar ratio of 4:1. The coreflooding process showed that the injected CO2 displaced the adsorbed H2, despite its lower partial pressure, and an efficient CO2 separation and storage from this mixture, was achieved. These findings highlight the potential of coal seams for dual-purpose CO2 storage and gas purification. The results suggest that coal's selective sorption can be potentially exploited for CO2 capture and storage, thereby contributing to the improvement of the sustainability of hydrogen production from fossil fuels with carbon capture, utilization and storage (CCUS).
Overcoming Uncertainty in Pore-Pressure While Drilling Through Integration of Logging-While-Drilling and Managed Pressure Drilling; a Case Study from the Gulf of Thailand
Authors: Phettongkam Numan , Espinoza Irina Baca , Singh Harpreet Kaur Dalgit , Phumtabtim Panu , Ngo Hien , Homchaem Keeradit 
Published: October 2024

Abstract
High uncertainty in pore pressure trend possesses drilling challenges which pore pressure need to be updated and managed while drilling. The expected pore pressure trend includes pressure ramp and pressure regression in the area based on the offset well profile. Managing mud weight in this pore pressure is a challenging task without tool to update the pore pressure in real-time. Pressure ramp possesses risk of formation kick if mud weight is too low. In the regression trend, casing point to isolate the pressure regression interval need to be optimized. Uncertainty of casing point selection during regression trend could lead to significant overbalance and fracking of the formation. Updating pore pressure trend in real-time becomes critical in this drilling challenge.
Managed Pressure Drilling (MPD) and Logging-While-Drilling (LWD) formation testing (FT) are deployed to overcome the challenge of uncertain pore pressure. MPD static pore pressure testing (SPPT) with reducing surface back pressure (SBP) applied is performed to update the pore pressure ramp until max pressure depth where regression trend is expected. During regression trend, LWD FT is performed to acquire pore pressure while SBP is still applied to avoid the kick from max pressure trend above the regression point. Regression trend of pore pressure is updated till limit of differential pressure then section total depth (TD) is decided. After casing isolation from high pore pressure trend, drilling in deeper section is continued with lower mud-weight to optimize differential pressure till TD is achieved.
Pore pressure increasing trend was updated with multiple MPD SPPT in multiple sands encountered in expected target layer and LWD FT acquired formation pressure in regression trend after each sand is encountered. Pore pressure trend is closely monitored to identify the regression trend until desired differential pressure is achieved. Casing point for intermediate section was decided which leads to lower mud weight in the deep section for better efficiency in the deep section. Planned TD was achieved by penetrating multiple sand in this appraisal/exploration (A/E) well despite of the uncertainty in pore pressure trend of pressure ramp and regression. Integration of MPD SPPT and LWD FT enabled pore pressure to be updated in both ramping and regression trend in real-time.
Proven workflow with integration of MPD and LWD FT enable operators to drill through challenging formation pore pressure trend, uncertainty in drilling window and able to achieve target TD. Best practices of MPD and LWD operation in this pore pressure challenge could be applied for future drilling in the area with such pore pressure trend and thus able to manage the potential risk of drilling in such challenging environment.
Multi-Phase Flow Metering and Water Cut Testing Device and its Application in CO2 Huff & Puff Wells
Authors: Deng Feng , Li Yunzi , Liu Huabing , Chen Guanhong , Chen Shiwen , Liu Zhaolong , Wang Mengying , Zhang Lei , Shi Junfeng , Zhao Ruidong 
Published: October 2024

Abstract
CO2 stimulation is a production stimulation technology that utilizes the expansion, extraction, and dissolution of CO2 to replenish formation energy, increase recovery, increase oil well production in high water-cut heavy oil and bottom water reservoirs. It is also an excellent carbon sequestration method, has become a research hotspot in recent years. The water cut of wellhead multi-phase flow rate are important parameters for calculating CO2 stimulation efficiency, evaluating the effect of CO2 stimulation, and carrying out working condition diagnosis. However, the existing water cut sampling and testing methods, in oil fields have several problems such as low efficiency, poor precision, low frequency, changes in fluid physical properties during the sampling process, and high cost, which cannot meet the requirements. In addition, currently, for the gas-liquid two-phase flow and even the oil, gas and water three-phase flow produced by CO2 huff & puff Wells, three-phase separator metering technology is generally used. The frequency and accuracy of the metering are not high, making it difficult for engineers to accurately understand the production dynamics of oil and gas wells. The series of CO2 huff & puff wells water cut, or multi-phase flow rate measurement methods and devices based on water cut meters or multi-phase flow-meters are proposed, which solves the problem of online, high-frequency, and accurate measurement of water cut or three-phase flow in huff and puff wells in an integrated manner. The proposed method of diagnosing the working conditions of carbon dioxide huff and puff wells based on multi-parameter water cut meter can realize the "gas slug", "continuous pumping and spraying", "oil blockage", "gas continuous phase", "ice blockage" and other working conditions diagnosis and alarm, that occurs in carbon dioxide huff and puff wells during the production stage, and proposes "monitoring and observation", "exhaust pressure control", "hot washing", "Variable flush times", "heating pipeline" and other corresponding treatment methods.
Advancing Flaring Measurement Systems in Oil and Gas Fields Through Validation with Visible Infrared Imaging Radiometer Suite (VIIRS) Data
Authors: Al Ghefeili Hilal. M. , Waily Najma. A. , Ajmi Mohammed. I. , Hinai Ashraf. S. 
Published: October 2024

Abstract
This study investigates the differences between on-site flaring measurement systems (ultrasonic meters) in oil and gas facilities and data from the Visible Infrared Imaging Radiometer Suite (VIIRS) Night Fire. The focus is on Petroleum Development Oman (PDO), which has made significant efforts to reduce flaring and supports the World Bank's Zero Routine Flaring Initiative. VIIRS Nightfire (VNF) data was used to estimate annual gas flared volumes and compared to measurements from PDO ultrasonic meters at various facilities. Key parameters such as flare average temperature, VIIRS detection frequency, ellipticity, and flow rate were investigated to determine their effect on data accuracy. The analysis found significant differences between the two datasets, with relative errors ranging from 7% to 30% between 2019 and 2023. Some facilities, like facility A, showed an exact match from the past year, while other facilities, like station C, showed a low meter reliability. This study contributes to improving flaring measurement practices, ensuring environmental regulatory compliance, and reducing the environmental impact of flaring activities in the oil and gas industry.
Optimization of Shallow Shale Gas Reservoir in Mountainous Area Development Strategy and Well Type - A Case Study of Zhaotong Shale Gas Demonstration Area in Southern China
Authors: Liu Yunyi , Xian Chenggang , Huang Xiaoqing , Zhang Muyang , Liu Yang , Chen Xin , Wang Jianjun , Liu Cheng , He Yong 
Published: October 2024

Abstract
Shallow shale gas reservoirs in mountainous terrains are influenced by "low formation pressure, significant variations in burial depth, steep formation dips, and the presence of fractures and microstructures", posing challenges in aligning well types and development strategies with geological characteristics.
This research introduces an innovative "tectonics-driven, multifaceted integration" approach to development and well optimization techniques. Utilizing the Petrel platform, this study constructed a detailed 3D geomechanical model for a geologically complex body, incorporating various stress patterns. The model delineates the area based on gas enrichment status, tectonic styles, stress regimes, and fracture development. Comparative analyses of stress distribution around the wells in different drilling orientations were conducted using near-wellbore geomechanical models. Additionally, production capacity evaluations and numerical simulations were employed to analyze the effectiveness of different development strategies and well types. The near-wellbore geomechanical model indicates that well placement along tectonic contours (at certain angles to the minimum horizontal principal stress) enhances wellbore stability and ensures a more uniform stress distribution conducive to homogenous modifications. Simulations reveal minimal differences in production capacity under identical fracturing processes, advantageous for efficient "water drainage and gas production". This well distribution method suits the extensively developed steep zones within the study area. Addressing the challenges in strike-slip to thrust transition zones and thrust areas, where bedding planes and low-angle fractures are prone to activation and horizontal wells face difficulties in vertical layer penetration, a pilot test for a comprehensive three-dimensional development strategy using clustered directional wells from a controlled platform was conducted. The feasibility of deploying directional wells in reverse fault stress regime zones was validated through simulations. Ultimately, considering the life-cycle benefit goals and maximized reserve utilization, the study advocates for a "tectonics-driven, multifaceted integration" concept, leading to the creation of a decision-making framework for a capacity-focused, integrated development model.
Based on the mechanistic understanding that complex structure and strong non-homogeneity are essential in forming complex fracture networks, this study challenges the traditional practice of orienting wells along the direction of minimum horizontal principal stress. It innovatively proposes the method of well placement along the direction of tectonic contours or principal controlling faults, offering valuable insights for the production of other unconventional resources.
Augmenting Well Control Safety Through Cloud-Based Real-Time Dynamic Simulation: A Mechanism for Ensuring Safety in Openhole Deep Transient Testing
Authors: Ashish Shubham , Lopes Velerian Sanjao , Kumar Arvind , Jain Anurag , Wydiabhakti Tety Benedicta , Solohaga Dario 
Published: October 2024

Abstract
Wellbore dynamics are essential in reservoir testing, acting as a vital connection between the reservoir and surface measurements. This study addresses the challenges in well control and emphasizes the advantages of utilizing wellbore dynamic simulation to enhance the safety of formation tester (FT) sampling and deep transient tests (DTT). The research particularly focuses on pre-job simulations and multi-parameter sensitivity analysis to improve our understanding of how hydrocarbons interact with wellbore mud during and after FT pump-out operations, thereby addressing the critical challenges of well control in the oil and gas industry. FT typically involves the use of specialized tools to extract fluid samples from the formation, allowing for the analysis of pressure, temperature, and fluid properties. DTT, on the other hand, involves isolating a section of the wellbore and flowing fluids to the surface, providing real-time data on the reservoir's productivity. Both FT and DTT are complex operations that require precise control over various parameters to ensure accurate data collection and to avoid operational hazards. One of the most critical aspects of these operations is well control, which involves maintaining the balance between formation pressure and wellbore pressure to prevent uncontrolled fluid flow. Well control is particularly challenging during DTT due to the dynamic nature of the wellbore environment. Well control is a fundamental aspect of safe and efficient drilling operations. It involves managing the pressure in the wellbore to prevent kicks (influx of formation fluids) and blowouts (uncontrolled release of fluids). This paper examines 3 case studies that explore different types of hydrocarbons and overbalance conditions. In these cases, cloud-based wellbore fluid simulations were performed under various flow rate scenarios to predict potential well control issues. Emphasis is placed on near-critical hydrocarbon fluids, including condensate, volatile oil, and wet gas.