bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Bit Design with Rotary Steerable System Unlocks Next Drilling Chapter: Improving DLS Capability and Drilling Performance
Authors: Al-Meer Ali , Nesaif Jawad , Osman Ahmed , Fakhrylgayanov Ayrat , Radhakrishnan Venkat , Alibrahim Eman , Varela Rodrigo , Silva Paul , Alabdullah Mansour , Gassas Reema 
Published: February 2024

Abstract
One of the biggest challenges in drilling operations is achieving the required dogleg severity (DLS) while drilling the landing curve section in 3D complex wells, especially the wells targeting shallower reservoirs that demand high DLS. This manuscript describes the first use implementations of a new bit design in the Middle East with a Rotary Steerable System (RSS) that achieves demanding DLS with avoiding usage of Positive Displacement Motor (PDM) in the directional bottom hole assembly (BHA), which could have compromised the drilling performance.
Dynamic modeling was performed to simulate the interaction of RSS and motorized RSS with the new bit design to model the DLS capability, shock and vibration, stick and slip, and BHA stability. The formation properties and response to different steering ratios were also included to have a comprehensive study of the fields. Furthermore, optimized drilling parameters regarding the flow rate, weight on the bit (WOB), and rotation per minute (RPM) were modeled to reach the best performance with increasing efficiency to mitigate shocks and vibrations and, at the same time, reduce stick and slip. The complex 3D design was drilled with shallow true vertical depth (TVD), successfully meeting the client’s requirement.
The challenge of the high DLS and having low performance is now a thing of the past, as a new chapter has been opened with the new bit design with rotary steerable BHA. The first trials with the new bit were successful. The required shallow TVD was achieved with up to 6 deg/100 ft of DLS. Moreover, there was no need to set the maximum steering ratio for the RSS tool, as the required DLS was achieved by using only 50% of its capability. On the other hand, operating the RSS tool with half its energy has increased its reliability, almost doubling its life span, which means longer sections can be drilled with one run in the future. However, with these new technologies, there is no need to run the motors with a high bend angle to get the DLS; this can be done by using the new bit design and the RSS tool. Furthermore, controlling the rate of penetration (ROP) to get a higher DLS was not necessary, as it resulted in increased performance with a smooth well trajectory.
The Influence of Red Mud Additive on Drilling Fluid Performance: Comparison Between Calcite in Conventional Drilling Mud and Red Mud Additive
Authors: AlBoraikan R. , Bageri B. , Solling T. 
Published: February 2024

Abstract
The main objective of this paper is to utilize red mud waste in drilling fluid design. Around the globe, there is a significant demand for energy and the global demands for technology keenness in providing an ecological solution. In recent years, there has been attentiveness toward finding sustainable solutions for waste prevention for upstream companies. This paper proposes a waste management solution as the red mud characteristics and composition show a potential drilling fluid application. Different techniques and evaluation procedures have been followed to characterize and evaluate the red mud additive. The differences in performance between red mud and a conventional calcite mud system were the core of the performance evaluation in this paper. The study was conducted to utilize red mud waste in the drilling fluid design and provided some information and guidance for the possibilities and challenges associated with using red mud additive in drilling mud systems. Red mud consists of coarse and fine particles, and to determine whether red mud can be considered an inert material in the drilling fluid design. The material undergoes a preparation process. Then, the particle size distribution analysis was performed to ensure the quality of the starting material. Finally, the material dissolution in acids was tested in 15 % HCl. Then, the investigation covers the solid characteristics and the elemental composition.
Moreover, the study highlights the effect of red mud dry additive in a drilling fluid system. Both rheological characteristics and filtration properties at 150 °F were highlighted in the paper. The filtration performance was tested based on the American Petroleum Institute (API) standard at LPLT and HPHT conditions. The practical applicational angle for this study exhibits similar rheological and filtration performance compared with calcite mud under HPHT conditions. By utilizing the red mud additive in the water-based drilling mud fluids system under HPHT conditions, the product gives relatively lower rheological characteristics, good solid suspension behaviour, and excellent filtration control. Red mud presents a possible example of a material where waste by-products can be seen as a potential product. The possibility does exist for the red mud to be used as an inert additive to optimize various drilling fluid properties.
Alkaline/Surfactant/Polymer (ASP) Flooding: Laboratory Evaluations, Simulation Studies and Pilot Planning for a Matured Carbonate Reservoir in Bahrain
Authors: Konwar L. , Anaisi I. AL. , Alwawainati E. , Matar O. 
Published: February 2024

Abstract
The Mauddud reservoir discovered in 1932 in Bahrain is now in a mature stage of development. A detailed feasibility study is carried out for identifying the most appropriate enhanced oil recovery (EOR) process for Mauddud reservoir and defining a strategy for further evaluation and implementation of the most promising EOR options. Detailed laboratory studies have identified alkaline-surfactant-polymer (ASP) process as the most technically attractive EOR process to increase the ultimate recovery from Mauddud reservoir by significantly improving the volumetric sweep and displacement efficiency. This paper aims to present detailed design of laboratory experiments and results en route to sector modeling studies in three (3) selected large areas. A 3.6 acres area is selected in Mauddud waterflooded reservoir for piloting. Detailed cost estimate is carried out using laboratory design data and simulation results.
Extensive laboratory design and testing such as polymer rheology, thermal stability tests, polymer injectivity, viscosity, adsorption, ASP phase behavior and coreflood tests are performed. 1-D coreflood simulation model was conducted using University of Texas Chemical Compositional Simulator (UTCHEM). Polymer rheology and surfactant phase behavior laboratory test data were matched to generate input parameters for the ASP injection simulation forecast. Representative sector and pattern simulation models were developed to estimate the EOR production potential from the Mauddud reservoir. The sector model developed was calibrated to the historical production, injection, and pressure data. The history matched sector model was used to select and develop pattern simulation models that were used to estimated EOR production potential.
Based on the evaluation of laboratory results, polymers are identified to give adequate viscosifying power and thermal stability. ASP formulations are identified for designing coreflood. Coreflood tests provided the process recovery data on residual oil saturation, chemical retention facilitating optimum slug design resulting in maximum oil recovery with minimum amount of chemical mass. The chemical formulation selected showed good phase behavior at different oil/water ratios, equilibrated quickly, good aqueous solubility, and generated ultra-low interfacial tension (IFT). The surfactant formulation showed great promise in the coreflood tests. The ASP coreflood tests recovered 63 to 70% of the waterflood residual oil and left a residual oil saturation after chemical flood (Sorc) of 9%. ASP pattern simulations showed incremental oil recovery factors between 26.7 and 31.9 percent of the original oil-in-place (OOIP).
The laboratory and sector simulation results are crucial to explore the feasibility of EOR project and will serve as inputs to detailed economic evaluation as well as pilot design and facilities planning.
Unpacking the Technical and Financial Challenges of Carbon Capture and Storage in Depleted Gas Fields for a Sustainable and Economically Viable Energy Future: Insights from the Egyptian Nile Delta
Authors: Abdelrahman Mohamed Mahmoud , Hoolahan Shaun 
Published: February 2024

Abstract
Carbon capture and storage (CCS) technologies are increasingly seen as a promising solution to the challenge of meeting rising energy demand while reducing greenhouse gas emissions. However, CCS projects face significant initial costs, and their viability depends on their ability to offer a return on investment. In addition, the unique characteristics of CCS projects, such as containment, capacity, phase behavior, sustained injectivity, and regulatory permissions, pose distinct challenges that require fresh analytical methods.
To address these challenges, this paper provides a comprehensive assessment of the technical and financial aspects of applying CCS in depleted gas fields operated by Dana Gas in the Egyptian Nile delta. The assessment covers a range of technical and financial aspects, including the evaluation of subsurface resources and wells, assessment of surface facilities and infrastructure, analysis of market demand, and financial and commercial viability. Using extensive data obtained from the gas fields and industry best practices, our analysis explores infrastructure repurposing opportunities, including pipeline CO2 capacity, CO2 compression scenarios, and CO2 processing requirements, with insights into the CCS value chain and market analysis.
Our findings demonstrate that the implementation of CCS in Dana Gas's depleted gas fields can be viable from both technical and financial perspectives. The estimated CO2 capture and transportation costs range from USD$16-17.5 per tonne of CO2 storage, depending on the emitter, making the project economically feasible for a reasonable range of estimated tariffs. The paper also highlights the importance of considering regulatory permissions, long-term verifiable containment, capacity, phase behavior, and sustained injectivity in the implementation of CCS projects. By providing a clear and detailed assessment of the technical and financial aspects of implementing CCS in depleted gas fields, our paper contributes to the literature on CCS technologies and informs future decision-making. Our findings also highlight the potential benefits and impact of implementing CCS in depleted gas fields, and the importance of advanced analytical methods in assessing such projects.
Our detailed analysis, which is based on extensive data obtained from the gas fields and industry best practices, provides valuable insights that can help to de-risk actual CCS project applications and facilitate informed decision-making. Our findings also contribute to the literature on CCS technologies, highlighting the potential benefits and impact of implementing CCS in depleted gas fields, and the importance of advanced analytical methods in the assessment of such projects.
Successful Implementation of Foam Batch Jobs for Gas Well Deliquification
Authors: Al Hadhrami Taher , Ghaempanah Babak , Al Aamri Ghusun , Kusela Ardia , Al Rashidi Ahmed 
Published: February 2024

Abstract
Liquid loading is a general threat to gas wells, hindering performance and recovery factor. Foam batching is a common deliquification technique that under right conditions offers significant results. Depending on the well performance foam batching can be applied as both a secondary and a primary means of deliquification. However, the key to success lies in proper selections of well candidate and foamer plus proper execution. Hence, a comprehensive understanding of foam batching suitability and monitoring for improvements are crucial for its successful implementation. Following trial phases on different foam assisted lift designs, PDO has currently landed on foam batch job as an optimum low-cost option and started its large-scale implementation to enhance its gas well deliquification capacity as well as to secure a secondary means of deliquification. This paper shares PDO’s experience from this implementation phase of foam batch jobs and contributes to practical and theoretical aspects of foam batch application for gas well deliquification.
Improving Well Productivity Through Better Perforation Design
Authors: Fituri M. A. , Munoz J. , Al Harbi A. , Abouganem A. 
Published: February 2024

Abstract
Formation damage in the near wellbore region, causes impairment to fluid flow, perforations are designed to bypass the near-wellbore drilling damage by generating deep perforation tunnels and bypassing the damaged zone, however, perforation tunnels are affected by additional damage surrounding the tunnel (crushed zone) and by the debris filling the tunnel that are generated during the creation of the tunnel.
Several perforation techniques developed and used to overcome the perforation damage; some techniques consider living with the perforation damage and create small fractures in this damage to improve permeability, such as Extreme Over Balance (EOB), other techniques consider removing all crushed zone and debris out from the perforation tunnels, such as Under Balance (UB), and Dynamic Under Balance (DUB), these different techniques are suitable for different environment as will be stated in this paper. By tailoring the perforations to the specific environment, a significant productivity improvement can be achieved. All the techniques are briefly explained in the paper with more details on the DUB which was successfully utilized for the case study.
A tailored perforation design was implemented for KOC, that utilized the deep penetration charges combined with dynamic underbalance method, which further improved the perforation tunnel cleanout. This improved design resulted in achieving more than 30% increase in production in comparison to conventional Over Balance (OB) perforation design that was implemented in nearby wells.
Distributed Temperature Survey (DTS) Technology Application in Optimization of Injector Well Coiled Tubing (CT) Acid Stimulation, A Case Study Review
Authors: Shokry A. , Bigno Y. , Agrawal P. , AlAli S. A. , AlHammadi I. A. , Sulaiman A. Y. , AlGhafeli S. K. , ElSheikh H. , Prossaird S. , Baioumy B. , Rivas J. 
Published: February 2024

Abstract
For a significant operator in the offshore Middle East, performing a production logging operation before an acid stimulation, either on an oil producer or a water injector well, is a common practice. Access to this data just before the intervention is critical to optimize the treatment and even to define the need for acid stimulation. The production logging tool (PLT) can be run with wireline (WL) or coiled tubing (CT) units; in both cases, the footprint gets increased due to the need for the WL unit and the increased time and cost due to the additional PLT runs.
Knowing all these factors makes the use of Distributed Temperature Sensing (DTS) for water injector wells cost-efficient since the operation can be done with only one CT reel without the need for WL unit and PLT tools. In fact, the injectivity profile can be done with just an Inconel-encapsulated fiber optic installed inside the CT string; this configuration allows to pump acid treatments with a single CT string reducing the footprint and rig-up/rig-down times of WL unit and swap between conventional and e-coil reels. However, the technology and methodology have yet to be proven in-house to be included as a common practice and replace the PLT operation pre & post-acid stimulation until this case study was conducted. This paper will review a first-in-the-region case study for an offshore water injector CT acid stimulation operation performed using DTS Technology to replace PLT logging, which introduced noticeable optimization to the acid stimulation operations. The paper will also quantitatively evaluate the performance optimizations that emanated from this new technology application.
Digital Integration Scope in Fracturing: Leveraging Domain Knowledge for Intelligent Advisors—Part I
Authors: Khan Abdul Muqtadir 
Published: February 2024

AbstractFracturing treatments in reservoirs with high tectonic effects or soft rock can lead to multiple challenges during fracturing treatment placement. Challenges like low injectivity and increasing pressure require expertise at each step. The decision-making process can be time consuming, which impacts operational efficiency. On the other hand, making a suboptimal decision affects the well performance. This study investigates how digital frameworks and infrastructure can enable imbibition of domain knowledge for efficient decision making.The scenario management can enhance operational efficiency by enabling faster and efficient decision making. Precision and consistency in flush volume can also be achieved, and the amount of proppant placed can be optimized, thereby avoiding premature termination and screenouts. A near-wellbore screenout contingency utilizing the surface well testing manifolds can help avoid CT cleanout in certain cases. Stimulation efficiency can be significantly increased by lowering the number of stages skipped due to low injectivity. Seven scenarios were considered in a wide spectrum of treatments and completion types. Detailed contingency workflows were developed in different rock types for (1) design considerations for flush volume, (2) increasing pressure during the fracturing treatment, (3) overflush criteria in case of premature treatment termination, (4) screenout, (5) low injectivity, (6) reperforating, and (7) tubing-annulus communication. During the workflow development, the reservoir quality index, degree of rock consolidation, rock strength, and completion rathole were important factors considered.A state machine automaton approach was utilized here to treat each action and condition in the flowchart as a state which advances based on rules and conditions. The solution was realized in two modes, interrogator, and simulator. The interrogator mode can be used by the user in a static case in pre-treatment or post-treatment scenarios. The simulator mode is built to integrate with the time series data stream and provide recommendations based on the data received, hence acting as an intelligent advisor on the wellsite. Comprehensive validations of the solution package have been conducted with synthetic and real data sets to show the experience of using the advisor. The solution has potential to enhance operational efficiency and reduce cost in multiple ways.
Unlocking New Solution in Brown Field Production: Innovative & Advanced THM (Tubing Heavy Wall Mechanical) Pump Improvement Method with Cost-Effective Approach
Authors: Dewanata Dionisius , Suryantoro Rahma Wisnu , Oktoviyanto Yusuf , Kurniawan Iwan , Andri Sailin , Akbar Despredi 
Published: February 2024

Mature oil fields have various obstacles in producing oil efficiently. In Rantau Field, the reservoir pressure has already been depleted and nowadays the development using waterflood technology initiated to deploy for Zone Z-AAA. Evaluation of various strategies conducted to maximize production in waterflood Zone development (Z-AAA), minimizing cost and extending the field's economic life. Sucker rod pump (SRP) is the most artificial lift used in Rantau Field because SRP is one of the low -cost artificial lift, about 68.61% in total. The cost-efficient solution is done by repairing the downhole pump for SRP (tubing pump / THM Pump) after well service and re - installed it.
The challenge from using repaired tubing pump is the leakage of the pump. The authors conducted FMEA analysis to solve that p roblem. The tubing pump has a hold-down mechanism on its standing valve assembly and does not have backup seal when the hold-down ring is damaged, and yield strength of the hold-down ring is less than the seating nipple. A finite element simulation with mess skewness 0.2 was carried out to support the analysis to determine the improved design of standing valve assembly.
From the simulation, the hold-down ring with fit interference could not hold the force from the operational load, especially for bump- down jobs when the pump gets stuck. The stress that impacts the hold-down ring could reach 392 MPa (156% of its yield strength). The author modified the hold-down ring design into a threaded design complete with O-ring sealing, then called TSV. The stress impacted to TSV could reach 144 MPa (57% of its yield strength) in the simulation. To validate the finite element result, the author conducted a pressure test with a vacuum tester. The pressure test was applied at 500 Psi and could be held for 5 minutes. The next step i s the installation of TSV in three wells.
As the result of improving the design of standing valve assembly, the repaired tubing pump could be reinstalled in another we ll without changing the standing valve components and it has decreased the pump failure during the operation of the pump. Since the repaired tubing pump could be used repeatedly, new purchases of tubing pumps could be minimized, and it can suppress the production cost of mature oil fields in general.
A New Ensemble Machine-Learning Framework for Analyzing EUR of Future Deployed Wells in Tight Gas Reservoir
Authors: Jia Ying , Huang Lei , Zhao Chunlan , Ren Guanglei 
Published: February 2024

AbstractTight sandstone gas reservoir is the main type of unconventional natural gas reservoir, and is also the largest unconventional natural gas reservoir in the world. Its significance and role in natural gas resource are becoming more and more obvious[1]. Tight gas reservoirs are generally defined as having less than 0.1 millidarcy (mD) matrix permeability and less than 10% matrix porosity. [2]China's tight gas reservoirs are widely distributed in more than 10 basins such as Ordos, Sichuan, Songliao, Bohai Bay, Qaidam, Tarim and Junggar etc. In recent years, with the advancement and large-scale application of hydraulic fracturing technology, the exploration and development of tight gas reservoir have made significant progress. Two gigantic gas zones in the Sulige Basin in the Ordos Basin and the Xujiahe Formation in the Sichuan Basin was discovered and developed. The prospective resources of low permeability sandstone gas reservoirs exceed 17-24 trillion square meters, accounting for 1/3 of the total natural gas resources in China[3–5]. Nowadays, the main tight gas field of Sinopec has entered a declining stage, facing the challenge of tapping the potential of remaining gas and improving oil recovery. How to analyze the production capacity of future deployed wells and optimize EUR based on clarifying the remaining gas in the gas reservoir is a key issue for efficient development.At present, the evaluation of production capacity and EUR is divided into three categories: theoretical methods (evaluating production capacity based on test data and analyzing EUR based on production data analysis methods, such as RTA)[6–9], empirical methods (such as various experience decline models)[10], and data-driven methods (based on machine learning, neural network algorithms, and other modeling)[11–13]. Although theoretical methods have clear physical meaning, they are difficult to handle the contradiction between the full factor assumptions of physical models and the efficiency of model simulation; Empirical methods establish empirical production decline models based on the analysis of a large amount of production data, but they lack of strict seepage theory support and have poor applicability; Data driven methods mostly reflect the mapping relationship between data and data, and prediction accuracy directly depends on the quality of training data and the suitability of algorithms. The above methods were applicable to gas wells that have been in production for a period of time and show significant production decline characteristic. However, EUR predictions for newly deployed wells in a block are not applicable.