bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pioneering Beetaloo Shale Appraisal: Case Study of Australia's Largest Multistage Fracturing Operation
Authors: Li H. , Kalinin D. , Bruce A. , Bukovac T. 
Published: November 2023

Abstract
In the Beetaloo Sub-basin within the Northern Territory, Australia, the shales of the Velkerri and Kyalla Formation are highly prospective. The Carpentaria-3H well was drilled in the B Shale of the Amungee Member of the Velkerri Formation with a lateral length of more than 2,632 metres and completed over a 1,989-metre section. Beyond the appraisal nature of work, the observation of natural fractures and faulting coupled with geomechanical complexity posed multiple challenges to the planning, design, execution, and evaluation of Australia's largest stimulation job to date.
This paper provides a comprehensive review of the Carpentaria-3H fracturing design and operation, following incorporating data from the Carpentaria-2H well. Completion design included developing the fracture stage interval spacing, number of clusters per stage, and cluster perforation density. For the fracturing treatment, decisions were refined for selection of fluid and proppant type, job volume optimisation and differentiation. Design optimisation is based upon both the simulator and evaluation measurements from the Carpentaria-2H reference well. Furthermore, observations from field execution, including formation response, experimental fracturing stages, and onsite design optimization, were incorporated.
The largest multi-stage fracturing operation to date in Australia was completed with 12.8 million pounds of sand and proppant successfully placed without screen out across 40 stages. Across the multiple stages trials of sleeve-perforation comparison, out-of-target stages, variable sand size and ceramic proppant were successfully executed. During post-fracturing cleanup, the Carpentaria-3H produced at an average rate of 2.6 MMscf/D over 27 days prior to being shut-in for a period of "soaking". The success of the well completion through a multi-stage fracturing operation marked a breakthrough in Beetaloo Sub-basin appraisal and demonstrated that long lateral drilling and large-scale fracturing treatments can be a viable pathway to improve efficiency and return on investment. This is despite the limitations imposed by scarce infrastructure and challenging logistics in the Australian outback.
Knowledge from the evaluation work undertaken in the previously stimulated and tested Carpentaria-2H wells was critical to advancing the Carpentaria-3H project. The Carpentaria-2H well's multi-arm calliper measurements offered enough precision to evaluate the perforation erosion following proppant placement. This generated a new technique for indirect evaluation of fluid and proppant distribution among the clusters. Production logging and chemical tracers also provided useful information for calibration and design optimization. Furthermore, advanced software tools were applied to integrate reservoir modelling, fracture and reservoir simulation, and data analysis.
A New Coupled Approach to Simulating Fault Reactivation During CO2 Sequestration
Authors: Saber Erfan , Qu Qingdong , Aminossadati Saiied M. , Li Jimmy , Chen Zhongwei 
Published: November 2023

Abstract
Carbon Capture and Storage (CCS) is considered an important means to reducing CO2 emissions. One of the key technical risks associated with large scale CCS implementation is the potentially induced fault reactivation. To assess this risk, a coupled numerical approach was established by integrating three different software packages over four steps. Firstly, a field-scale structural geological modelling was conducted using the JewelSuite based on available geological, geophysical, and logging data. Secondly, dynamic CO2 injection was simulated using the reservoir simulator IMEX to predict reservoir pressure build-up. Thirdly, the pressure build-up and the associated reservoir uplift were simulated in the Finite Element software Abaqus. Finally, the Finite Element output database was re-imported into the JewelSuite to delineate the risk areas of fault reactivation.
The feasibility of this new approach was tested on a real geological site featuring two faults. The results suggest that, for a given fault setting, the horizontal well placement and bottom hole injection pressure (BHIP) are two critical factors in determining the risk of fault reactivation. To minimise the risk, horizontal wells should not be placed within the intermediate region between faults. Where the borehole placement cannot be optimised, the critical BHIP should be estimated and controlled during operation.
Operational Solution Framework: Leveraging Machine Learning and Natural Language Processing for Automatic Well Test Validation
Authors: Gao Chao , Vo Nghia Tri 
Published: November 2023

Abstract
The objective of this study is to summarize a proven solution workflow to address the challenges to handle the high volume of well tests daily incorporating information from operational activities, and especially, potential delays and errors in validation impacting other dependent business processes. The proposed solution aims to reduce processing time, minimize human error, and enhance accuracy in well test analysis. Having up-to-date and reliable well test data, engineers can improve engineering workflows, and optimize production.
The solution covers data consumption, data preparation, machine learning (ML) solution, cooperating with dependent business processes, deployment and retrain strategy. The ML solution learns from historical well test data with accepted and rejected flag to build a rule-based deterministic ML model to automatically validate and detect the invalid well test with probability. The solution does not only consume structure data but also textual data with natural language processing (NLP), such as well test comments provided by well testing engineers and operational activities in Daily Operational Reports (DORs). Data consumption, operational activities, dependent workflow control are customizable based on different projects. Retrain strategy is based on model prediction accuracy trend and defined during deployment. The solution triggers insights with confidence scores, suggesting acceptance/rejection or review of new well tests. Early detection of possible rejections enables timely actions, including retesting if necessary.
The solution was implemented and significantly reduces well test validation time from weeks to hours, enhancing the accuracy of production analysis and optimizations. The data-driven approach offers flexibility and adaptability to meet operation needs, presenting a robust alternative to rule-based validation. By integrating ML and NLP, the solution provides a comprehensive and efficient framework for well test validation, improving decision-making and ensuring compliance with Standard Operation Procedure (SOP).
This study introduces a novel approach to well test validation by leveraging ML and NLP. By considering both historical data and manual operational event inputs from engineers, the solution enhances the accuracy and efficiency of the validation process. It contributes to improved production performance analysis, diagnostics, and issue detection. The solution deployment can be customized and adaptable to different data storage and availability, to automate well test validation process in the oil and gas industry.
Development of a Mathematical Model for Optimization of Rod Guide Spacing to Mitigate SRP Failures Due to Tubing Buckling
Authors: Rajvanshi Saurabh , Sharma Aman , Gargmukh Shilpy , Gunwant Deepak , Kumar Avinav , Yadav M. P. , D. Narayan K. J. , Nischal Rajiv 
Published: November 2023

Abstract
Tubing buckling is a common and persistent problem encountered in Sucker Rod Pump (SRP) wells in onshore fields. This paper discusses about the optimization of rod guide spacing below the neutral point in SRP wells and development of a mathematical model for rod guide spacing.
In SRP wells, tubing below the neutral point buckles during the pump upstroke, causing frequent tubing and rod failures due to rod-on-tubing wear. The friction caused by tubing buckling increases polished rod load, pump wear and decreases lift efficiency. To avoid tubing buckling, tubing anchors and tail pipe are used for balancing of compressive force. Additionally rod guides are placed in SRP wells to prevent rod-tubing contact load but accurate spacing of rod guides is challenging task. To address this challenge, a mathematical model for rod guide spacing has been developed and validated with field data.
Lubinski et al. (1957) have analyzed tubing buckling phenomena in details and provided charts for rod guide spacing for 2″ and 2 1/2″ tubing sizes. In this paper, the work of Lubinski et al. has been carried forward. Analysis has been done for more accurate differential pressure across plunger for calculation of the compressive force in different scenarios and also generated charts for the most common tubing sizes of 2 7/8″ and 3 1/2″ for spacing of rod guides.
The developed mathematical model considers various parameters, such as specific gravity of fluid, dynamic liquid level, tubing size, and plunger diameter etc. to estimate the neutral point and optimization of rod guide spacing. The developed model has been used for more than 100 SRP wells of Indian onshore fields. This study can also be helpful in production of unconventional resources such as shale oil production and dewatering of Coal Bed Methane.
The proposed mathematical model provides accurate placement of rod guides according to the neutral point in the tubing string resulting in increased the mean time between failures. From the findings of this study, charts for spacing of rod guides have been generated for most common tubing sizes of 2 7/8″ and 3 1/2″ which will be a valuable reference for oil and gas operators in onshore fields.
Analyzing Wellbore Breakout in Deep Shale Oil Reservoirs of Western China Using Poro-Elastic Dynamics
Authors: Yang Shuai , Liu Yingbiao , Meng Xiangyan , Ding Kun 
Published: November 2023

Abstract
The deep shale oil reservoir in the Junggar Basin of China is facing challenges due to elevated deviatory stress conditions and extensively developed fracture features, which increase the risk of wellbore breakout during drilling. This paper presents a poro-elastic dynamic based mechanical model to characterize the wellbore stress response and breakout features for deep shale oil reservoirs. Different from the conventional method, this proposed model includes the fluid-solid coupling and the effects of fluid and solid inertia. The Mohr-Coulomb failure criterion is applied to evaluate shale matrix failure and the weak-plane failure criterion is applied to evaluate the failure of shale bedding/fracture plane in this model. Rock mechanical properties and permeability anisotropy is also considered in this model. Then, a set of deep well parameters were taken as the examples to calculate the near-borehole stress field. The failure behaviors were also analyzed and compared with the pore-elastic static model.
The results show that compared with the poro-elastic static model that does not consider inertia, the poro-elastic dynamic model can reflect the dynamic response characteristics of pressure and stress around the wellbore after excavation. Static models tend to underestimate the severity of wellbore instability, while dynamic models are more accurate in predicting borehole breakout. The study on the factors affecting the wellbore breakout shows that Biot coefficient, in-situ stress difference, fracture parameters and bottomhole pressure have a great influence, while the elastic modulus and matrix permeability have minor influence on the wellbore breakout. This model offers insights into the dynamic mechanisms underlying wellbore instability in deep shale oil reservoirs, serving as a valuable tool for accurately predicting breakout pressure, optimizing drilling mud density, and ensuring wellbore stability.
Geophysics Based Reservoir Characterization of an Unconventional Reservoir of the Cretaceous Sembar Formation, Lower Indus Basin for Delineation of Reservoir Quality and Completion Quality
Authors: Dasgupta S. , Siddiqui F. H. , Khan F. A. , Bhatti A. I. , Nafie T. Y. , Ahmad N. , Saqib M. , Gakkhar R. A. 
Published: November 2023

Abstract
Unconventional reservoirs are found to have complex minerology and are strongly heterogeneous. Porosity and permeability are generally low and spatially variable. To optimize and efficient production of hydrocarbons from such reservoirs requires understanding of the reservoir quality variability for well placement and stimulation. Seismic data plays a critical role in understanding and mapping heterogeneity. Characterization of spatial variations of elastic lithofacies, associated mineralogical composition, kerogen and porosity can be achieved by integrated reservoir characterization. Formation pressures and stresses in this kerogen rich source rock is another crucial property for successful frac propagation, geometry and producibility. Herein, we present results of integrated reservoir characterization for estimation of reservoir quality and completion quality derived by integrating geophysical, petrophysical, geochemical, geological, and geomechanical information in the Lower Indus Basin, in Pakistan.
Energy-Based Fracture Network Reconstruction of Shale Gas Reservoir
Authors: Lu Ji , Lin Botao 
Published: November 2023

Abstract
Microseismic monitoring is a commonly used technique in characterizing hydraulic fractures. However, fracture network reconstruction remains challenging due to the heterogeneity and complex stress field of shale gas reservoirs. An Energy-based 3D Fracture Reconstruction method (EFR3D) is proposed to derive the complex fracture network from microseismic data in a shale gas reservoir. The EFR3D method mainly combines the Propose Expand and Re-Estimate Labels algorithm (PEARL), the Density-Based Spatial Clustering of Applications with Noise algorithm (DBSCAN), and the Alpha-shape algorithm to detect the fracture orientation and fracture shape. This method formulates fracture orientation detection as an energy minimization task to improve reconstruction accuracy. The effectiveness of the proposed method was evaluated by performing a verification procedure against different fracture numbers, fracture orientations, and fracture scales using the Monte Carlo simulation. The results show that the proposed method has good adaptability and high accuracy in various fracture configurations. Furthermore, a field application of six horizontal wells located in the southern Sichuan basin, southwest China, was conducted to illustrate the robustness and practicability of the proposed method. The proposed method can serve as a practical and reliable approach to characterize hydraulic fractures.
Application of a Fully Coupled Fracture-Reservoir-Wellbore Model in Shale Gas Development: Perspectives on Inter-Well Fracture Interference
Authors: Yu Wenfeng , Wang Wendong , Zheng Shuang , Su Yuliang , Zhang Qian 
Published: November 2023

Abstract
In the unconventional oil and gas domain, shale gas development adheres to the technical concept of "tight well spacing and infill well." Infill wells, along with large-scale hydraulic fracturing, have become effective strategies for increasing shale gas production. Nevertheless, during hydraulic fracturing operations in the horizontal wells, there is often a risk of frac hits due to geological and engineering factors, which has a significant adverse impact on on-site operations, resulting in lower individual well production and posing challenges to the efficient development of shale gas. Managing frac hits is critical for the industry's growth rate in future. Therefore, based on the current state of hydraulic fracturing in the southern Sichuan shale gas, this study aims to clarify the mechanisms of frac hits and the influencing factors, and to propose effective methods for preventing frac hits, thereby improving the performance of gas wells.
In this article, we employed a fully coupled reservoir-fracture-wellbore geomechanical simulation method originated from Zheng (2019a), combined with the establishment of shale gas diffusion properties, to establish a frac hits model. A detailed analysis of the mechanisms and influencing factors of frac hits between shale gas wells under different interference patterns were conducted, and the effectiveness of mitigation methods for each pattern was validated. The results indicate that in reservoirs with developed natural fractures, the fractures in stimulated wells tend to propagate easily along these natural fractures, affecting offset wells. To some extent, this impact can be mitigated by avoiding fracturing in the risky stages. Similarly, the depletion of offset wells leads to a rapid decrease in rock pressure around the fracture tip. Due to the influence of pore elastic effects, rocks undergo elastic deformation, resulting in low-stress zones. The fractures in stimulated wells are affected by this phenomenon and tend to propagate towards offset wells, causing frac hits. The application of pre-pressurization in offset wells can lower the occurrence rate of frac hits.
The simulation of inter-well interference between offset wells and stimulated wells provides a theoretical foundation for understanding the frac-hit phenomenon in the southern Sichuan shale gas. This method can be used to predict or mitigate the risk and damage associated with frac hits.
Data and Model Base of Customized Hydraulic Fracturing for Continental Shale Oil
Authors: Mei Qiliang , Ma Fujian , Lei Qihong , He Youan , Luo Yin , Wang Bo , Niu Li , Liu Yuan 
Published: November 2023

Abstract
The challenges of lacustrine shale oil reservoirs include not only subsurface heterogeneity of reservoir quality and but also the effect of natural fractures on propagation of hydraulic fractures and associated fracture hits. The intercalated sandstone and shale in a gravity deposit setting result in significant variation in the reservoir quality. Meanwhile, the subsurface conditions become even more complicated when the reservoirs are naturally fractured. The objective of this study is to characterize reservoir quality, natural fractures, and completion quality with well, seismic, and fracturing data, eventually to provide a base for a customized fracturing job according to the local geology aiming to enhance reservoir recovery.
A geological model and a geomechanical model were built integrating all available data, including logs, core data, and seismic data, and an ant-tracking algorithm was used with variance of the seismic data as the input to delineate natural fractures. The quality check was performed by comparing drilling data, microseismic data, and fracturing data. A distributed fracture network (DFN) model was built with the ant-tracking results. Fracture stability analysis was performed when the natural fracture model and geomechanical model were ready.
The fracturing design was customized and optimized with the models mentioned above and understanding obtained from the analyses. Different fracturing strategies were applied to each stage and to each well of the same pad based on the geoscience models. Some wells were completed with large-volume and high-rate fracturing practice to maintain the long-term reservoir pressure. Alternatively, some wells were subject to an intensive staging with low-volume and low-rate fracturing practice to create better near-wellbore flowing conditions.
The combination of customized fracturing design and real-time adjustments during execution was approved to be a valid and practical geoengineering approach. The benefit of the workflow includes not only high fracturing efficiency, but also the effects on production performance. Production data measured by multiphase flow metering showed that the customized approach results in a 20% production increase.
Separator Sample Analysis and Calculating Wellstream Composition
Authors: Whitson Curtis Hays , Younus Bilal , Nielsen Markus Hays 
Published: November 2023

Abstract
This paper discusses the use of separator gas and separator oil samples as the primary method used in tight unconventional wells. Separator samples provide direct measurement of surface product compositions and properties, but they are primarily used in the calculation of wellstream composition. Our discussion encompasses a comprehensive and quantitative QC and correction of separator sample compositions, also providing improved accuracy in the estimation of wellstream composition, both for conventional and tight unconventional wells.
The standard QC of separator sample compositions assumes that the samples collected should represent equilibrium gas and oil phases at conditions of pressure and temperature in the separator at the time of sampling. The Hoffman-Crump-Hocott method plots the log of component K-value and separator pressure log(Kpsp) versus a component factor F. The Hoffman "KpF" plot should result in a linear trend, with deviations from the linear trend indicating that the sampled phases are not in equilibrium. The problem with this QC method is that it does not provide a method to correct erroneous separator sample compositions. Our paper presents such a correction method for separator gas, separator oil, and wellstream compositions.
The proposed method uses the lab-reported wellstream composition based on the sampled gas and oil separator compositions using a recombination ratio computed from the separator gas-oil ratio at the time of sampling, and separator oil molar volume. This wellstream composition is flashed with K-values applicable at separator temperature and pressure, e.g. from the Standing correlation using a Rachford-Rice phase split calculation, or doing a flash with an appropriate equation of state.
The resulting flash calculation provides corrected separator gas and separator oil compositions that are more accurate than lab-reported separator gas and oil compositions, and can be used to calculate a corrected wellstream composition using the lab-reported recombination ratio.
We have studied the utility of this method for a wide range of wellstream mixtures, separator conditions, and the four potential sources of errors in separator samples: (1) leakage during transportation to the laboratory, (2) samples being collected at different times when pressure-temperature conditions differ for the gas and oil samples, (3) liquid carryover in the separator gas and gas carryover in the separator oil, and (4) gas chromatography errors in laboratory compositional measurements.
We show that the proposed method of correcting separator gas, separator oil, and wellstream compositions are accurate for all fluid types and errors that may be found in separator sampling. The approach is consistent with, but not dependent on, the Hoffman KpF method. The method does require K-value estimates at separator conditions, but this is almost always available from the Standing correlation (often used in connection with the Hoffman KpF QC plot) or an available EOS model.