bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Innovative Approach to Perform Cement Packer in a Well with Multiple Leak Issues
Authors: Choo D. J. , Farazell S. I. 
Published: October 2024

Abstract
Reserves was realized above top packer and a barrier was needed to segregate the new producing zone from the gas lift. Cement packer job was called forth to spot cement in tubing-casing annulus (casing). A conventional cement packer job will punch a hole in the tubing above a set plug. This allows circulation from tubing into casing to spot cement in the casing. For the job to be successful, the tubing integrity, casing integrity and top packer integrity must be intact for proper placement of cement in the casing. However, a well's completion integrity was found to be compromised. This well has multiple leaks in the completion rendered the conventional cement packer methodology ineffective. The complexity of the challenges had led to compare the options of performing cement packer using coiled tubing (CT) against performing well workover. A new cement packer methodology was devised to tackle the leaks in short string, leaks in long string and leaks at top packer. Sealant was used to reduce the leak at top packer. Retrievable bridge plug was used to control the leak in long string. Modified cement retainer and CT tension set packer were deployed for a successful cement placement in the casing via short string, bypassing the leaks in short string. New producing zone was perforated through the cement packer and no communication between producing zone to the gas lift area was seen indicating a successful cement placement in the casing that act as packer. This successful method had safe client from doing workover on the well. Plus, this method allows future possibility of performing cement packer with tubing integrity issue, unlocking more potential reserves behind casing to be produced.
Reducing Mud Loss in Drilling Operations with High-Performance Plugging Agent
Authors: Xiao Fengfeng , Zhu Jun , Ran Qihua , Liu Gang , Jiang Guancheng , Zhao Zhengguo , Zhang Wei , Li Jingzhe 
Published: October 2024

Abstract
This study aims to evaluate the efficacy of a new high filtration loss consolidation plugging agent in addressing the persistent challenges associated with fluid loss. By conducting comprehensive laboratory experiments and field trials, the aim is to precisely quantify the agent's ability to mitigate fluid loss and enhance wellbore stability. The overarching goal is to provide actionable insights that empower drilling engineers and operators to make informed decisions, leading to improved drilling performance and cost-effectiveness. A methodical approach was employed to assess the high filtration loss consolidation plugging agent's performance. Laboratory experiments simulated downhole conditions by varying temperature, pressure, and salinity, while field trials across diverse drilling sites validated its effectiveness. The agent was applied alongside oil-based drilling fluids, with continuous monitoring of wellbore stability and fluid properties. Advanced analytical techniques, including fluid loss measurements and core sample evaluations, quantified its efficacy. Data analysis guided the optimization of drilling practices. The plugging agent's versatility was demonstrated through its ability to adjust slurry density within the range of 1.0 g/cm3 to 2.2 g/cm3, ensuring applicability across diverse density segments encountered in field operations. With a filtration time of under 60 seconds and a robust consolidation strength exceeding 4 MPa, the agent swiftly forms a solid plugging wall within the leakage channel, effectively enhancing plugging efficiency. In conclusion, field trials were successfully conducted in 25 wells, exemplified by the MX019-H5 well, showcased a remarkable 91.9% reduction in leakage rates, while the WBQ020-H1 well successfully achieved pressure plugging without leakage during circulation at 35 L/s, validating its operational effectiveness. By leveraging the unique properties of the high filtration loss consolidation plugging agent, significant advancements have been made in mitigating fluid loss and improving wellbore stability. The economic implications of these improvements are substantial, with potential cost savings attributed to reduced non-productive time and enhanced drilling performance.
Tailored Solution for Mitigating PDC Bit Balling Challenges in Drilling Sticky Shale
Authors: Feroze Nouman , Case Matt , Al lawati Yousuf , Al Wardi Yasser , ALRawahi Mohammed , Parasher Mukesh 
Published: October 2024

Abstract
Drilling in sticky shale formations presents a tough challenge due to bit balling, where traditional solutions such as oil-based mud not only strain finances but also harm the environment. Conversely, while water-based mud offers a more economical alternative, it increases the risk of bit balling, resulting in frequent bit trips and reduced rates of penetration (ROP), thereby escalating overall well costs.
To combat the risk of bit balling in water-based mud, the focus must be directed towards three pivotal factors: 1. suitable drilling mud composition, 2. appropriate drill bit design, and 3. proper drilling parameters. Neglecting any of these elements can lead to decreased ROP and increased bit trips.
This paper will focus on the design features of PDC drill bits tailored specifically to address PDC bit-balling challenges, such as effectively evacuating cuttings from the cutter's face out of the junk slots and providing sufficient space on the bit face to avoid creating formation cuttings lumps. Two key features crucial for addressing these challenges in PDC drill bits are: 1. optimizing bit face volume and 2. hydraulic enhancement through computational fluid dynamics (CFD).
A pioneering approach utilizing CFD optimization has been devised to customize fluid distribution based on the displacement of the formation by each cutter. This innovative technique ensures that cutters exerting greater work on the formation receive proportionately higher fluid volumes, effectively mitigating bit balling. Additionally, the study examines the optimization of PDC bit face volume without compromising diamond volume.
Test conducted on a bit design employing these methodologies yielded promising results, affirming their ability to overcome bit-balling challenges.
Retrofitting Conventional Wells With Sub-Surface Safety Valve Without a Rig
Authors: Ubedulla Shaik Saheb , Maclurg Michael , Negi R. S , Menon A. , Bota D. 
Published: October 2024

Abstract
It is widely accepted that the absence of safety valves in the completion tubing compromises operational integrity, exposing
operators to potentially severe consequences. This underscores the need for robust safety measures. In the past, a workover was the only way to tackle this problem. The technique we have developed effectively addresses this challenge. Coupled with a penetration point at the wellhead, this system employs a retrievable packer with a safety valve giving the flexibility for the Safety Valve to be retrofitted at any depth within the tubing.
The implementation of this system necessitates the modification of the wellhead to accommodate an inlet for the control line. The safety valve is hung directly off the bottom of the retrievable packer. A stinger is then inserted into the receiving profile in the system at the same time as the control line hanger is located into the penetration profile in the wellhead. Hydraulic communication is thereby created from the safety valve hung below to the control line hanger landed in the wellhead.
The control line transmits safety valve control line pressure through the control line hanger, down to the stinger, and finally into the safety valve ensuring proper valve operation. With the help of this system old wells can be brought back into production without the need of costly workovers and with minimal footprint.
With the pressure on oil and gas industry to move towards sustainable development and reduce carbon emissions, this system presents an innovative approach to installing safety valves into a well without rig intervention, thereby contributing to carbon emission reduction. This system can not only be used on wells with no safety valves but can also be used when the nipple profile, the seal bore, or the flow tube has been damaged or if there is a leak in the previously installed control line.
Pioneering Sustainable Well Cementing in Brunei: Reduced Portland Cement Blends With Locally Sourced Fly Ash
Authors: Suri Chitra Charan , Yeo Chun Kiat , Hugentobler Kory , Simmadorai Dinesh 
Published: October 2024

Abstract
The oil and gas industry in Brunei is increasingly focused on sustainable practices, particularly in well cementing, which is a crucial operation with environmental considerations. To contribute to this effort, the service company has introduced a novel reduced Portland cement (RPC) blend system. This system incorporates locally sourced fly ash, which provides a high-performance and environmentally responsible solution that aligns with the commitment to sustainable development. The RPC system prioritizes environmental stewardship with a decrease in carbon dioxide (CO2) emissions associated with clinker production through a 25% reduction in Class G Portland cement content. Additionally, the system uses readily available fly ash, a recycled material, to minimize reliance on imported ordinary Portland cement (OPC) and strengthen supply chain efficiency.
This focus on localization not only reduces transportation emissions but also fosters a more adaptable and resilient supply network in Brunei. Rigorous laboratory tests have qualified the RPC blend system and have demonstrated that RPC blends maintain or even exceed the compressive strength of conventional, higher-density OPC systems. This helps ensure effective wellbore isolation, despite the lower density of the RPC blend, a crucial factor for long-term well integrity. Additionally, RPC blends exhibit lower equivalent circulating densities, which makes pressure management during wellbore construction simpler and enhances operational efficiency.
The RPC system provides several advantages beyond its environmental benefits. The enhanced ductility and toughness of these blends, compared to traditional cement, allow the cement sheath to better withstand downhole stresses and strain throughout the well's life. This promotes long-term zonal isolation and helps mitigate the potential risk of leakage. Furthermore, the lower permeability of RPC blends provides superior resistance to corrosive fluid and gas that migrate through the wellbore to help ensure the long-term integrity and production efficiency of the well.
Since May 2023, the RPC blend system has been successfully implemented in Brunei. This innovative approach not only minimizes the environmental impact but also delivers strong wellbore integrity. The RPC blend system represents a significant advancement in sustainable well cement operations, which paves the way for a more environmentally acceptable future for the oil and gas industry in Brunei.
Addressing Operational Complexities: Successful Zonal Isolation in Deep Production Liners Through Innovative Cementing
Authors: Quintero E. , Gomez G. , Martanto R. , Edgar D. , Masoud R. , Pohl J. , Iturrios C. 
Published: October 2024

Abstract
This paper explores the complexities involved in achieving zonal isolation within deep production liners with a narrow operational window (pore-fracture pressure). It examines the technical hurdles encountered in this process and presents two comprehensive case histories that illustrates the successful application of innovative cementing techniques. By showcasing these advanced methods, the paper highlights effective strategies for overcoming the inherent challenges of zonal isolation, thereby enhancing the integrity and performance of deep production liners.
The approach involved utilizing an expandable liner hanger system, managed pressure cementing (MPC), environmentally conscious lost circulation spacer, and an engineered cement slurry. Thorough consideration of fluid properties and multiple placement simulations enhanced the accuracy of cement placement. The cases examined a 7-inch and 4½-inch liner, where the deviated sections were drilled from a preceding 9⅝-inch casing string to a target depth of 13,300 feet using a managed pressure drilling (MPD) technique for both cases. An expandable liner top packer was deployed, and contingency measures were implemented to mitigate risks associated with top packer failure.
The application of these innovative cementing techniques achieved successful zonal isolation despite the challenging well conditions. The deployment of the expandable liner hanger system and implementation of contingency measures effectively addressed operational complexities. Managed pressure cementing and eco-friendly lost circulation spacers contributed to the achievement of zonal isolation. Extensive simulations ensured achieving stability of the well during the cementing operation. The engineering procedures and consideration of potential contingencies were critical in accomplishing the objective. This case study underscores the importance of adaptive design and careful planning in cementing operations, providing valuable insights for enhancing zonal isolation practices in deep production liners within the drilling and cementing industries.
This case study introduces a novel approach to achieving zonal isolation in deep production liners by effectively utilizing advanced cementing techniques. The successful application of expandable liner hanger systems, managed pressure cementing techniques, and environmentally friendly lost circulation spacers provides insights for enhancing cementing practices. Additionally, this study explores the integration of advanced technologies and methods that improve the reliability and efficiency of cementing operations.
Identification of Poor Hydrocarbon Chargeability in Initially Pressured Reservoir Using Initial Water Saturation, Formation Tester Mobility, and Movable Hydrocarbon, Basal Alam El Bueib 3A Reservoir, AEB-3C Field, Western Desert, Egypt
Authors: Orban A. , Vaughan R. D. , Ragab I. 
Published: October 2024

Abstract
The integration of initial water saturation (Swi) with movable hydrocarbon (Smo) can demonstrate the charging capacity of a reservoir under initial pressure regardless of the hydrocarbon fluid gradient.
In an initially pressured reservoir with oil gradient, high initial calculated water saturation, good mobility, and low calculated movable hydrocarbon (Smo), in which the study integrates these reservoir characteristics, the risk of running casing or encountering a well test with 100% water cut can be mitigated.
The AEB-3C field was discovered in August 2010 by El Hamra Oil Company (EHO) with the drilling of AEB-3C-1X well to be the first commercial oil discovery in the field through production testing at about 500 BOPD of 23.3°API from the AEB-3A sands reservoir.
The Basal AEB-3A (B.AEB-3A) reservoir comprises three distinct sand bodies was formed in a depositional setting characterized by lower intertidal-subtidal conditions and distributary mouth sand bars. The environmental setting allows for penetrating various sand bars under initial conditions within the same field.
In Well AEB-3C-6, the third sand body within the B.AEB-3A reservoir exhibits a fluid gradient of 0.39 psi/ft, alongside an average mobility of 30 mD/CP (millidarcies per centipoise). Initial water saturation (Sw) was determined using the Archie Equation and used in establishing a water saturation (Sw) height function to describe the difference in initial water saturation (Swi) by porosity band, assuming a clean sandstone reservoir concluded from Cation Exchange Capacity (CEC). The reservoir yielded an average Sw of 60%. The movable hydrocarbon, however, was interpreted conservatively, consistently remaining below 5% and far from the expected value. The primary challenge involved casing installation and reservoir testing. This paper aims to illustrate the integration between Swi and Smo concerning initial reservoir pressure in comparison to the producing wells, while also addressing associated risks and results.
Cost-Effective Solution to a Tar Pump Perennial Performance Problem
Authors: Abidogun Kamorudeen 
Published: October 2024

Abstract
Two identical gear pumps, designed for a maximum speed of 800 RPM, are each rated for a flow of 2.5 m3/hr, 1.5 break horsepower, 160 RPM speed, and a discharge pressure of 750 kPa a. The electric motor driving the pumps through a gear reducer has an output speed of 1800 RPM. With a gear reducer ratio of 5.6:1, the maximum speed of the gear pump is 320 RPM. The pumps are designed to recycle residual styrene tar back to the process as inhibitor in a Styrene plant. Since commissioning, the pumps discharge pressure is insufficient to return the tar back to the process per design. Instead, it is delivered to low pressure utilities area to be flared. Flaring of the styrene tar, due to insufficient pump head, resulted in the loss of inhibitor and styrene monomer. An estimated sum of $ 0.7 MM is lost per year to procure the required inhibitor due to this problem. The investigation commenced with the review of the gear pump as-built datasheet and characteristic curve. A field sample of the tar was taken for lab analysis to determine, among others, its viscosity and specific gravity. The viscosity of the actual tar in the field is multiple times the viscosity of the tar in the as-built datasheet. Parametric studies were conducted that confirmed that the pump performance is in line with the characteristic curve but limited in the discharge pressure due to the limiting pump speed. An appropriate limiting pump speed was calculated, based on the actual fluid properties in the field, to be 600 RPM. As such, the gear reducer ratio was proposed to be changed to 3:1 from the current ratio of 5.6:1. The proposal was implemented first on the installed spare pump and tested with astounding result – the perennial gear pump problem was resolved. The gear reducer was subsequently changed on the main pump as well. The low pump head problem was resolved with negligible CAPEX, no downtime nor major redesign of the piping system.
Novel Wellbore Strengthening Spacer and Managed Pressure Cementing Facilitates Cement Placement in Deep and Shallow Sections Under Narrow Operating Window and Partial Losses
Authors: Shafqat A. , Al-Jadhar A. , Kharchi S. , Mclellan J. , Pohl J. 
Published: October 2024

Abstract
Drilling hydrocarbon-producing wells frequently involves challenges such as narrow operating windows and lost circulation. This paper details the design, execution, and evaluation of primary cementing operations in two case studies of primary cementing operations for intermediate and production sections. This includes operations with complex conditions such as high-pressure/high-temperature (HPHT) conditions, narrow equivalent circulating density (ECD) operating windows due to narrow annular clearances, high pore pressure, and fragile carbonate formations that have a tendency for lost circulation scenarios.
Managed pressure cementing (MPC) techniques have been implemented to allow faster operational response to formation fluids influx or fluid-loss scenarios, thus controlling drilling fluids in the well below the formation pressure by adding a surface annular pressure through a choke manifold. A novel wellbore strengthening spacer, coupled with an environmentally friendly lost circulation material, was successfully deployed, enabling the placement of cement slurries and ensuring wellbore isolation. In these case studies, the combination of the managed pressure system, wellbore strengthening spacer, and the lost circulation additive proved to be effective in addressing and preventing lost circulation scenarios under challenging conditions.
Reservoir Characterization Using 3d Obn Seismic Survey - Cheleken Asset Case Study
Authors: Khdhaouria Mourad , Rondon Aldrin , Ameish Giamal , Rouis Lamia 
Published: October 2024

Abstract
The Cheleken Area lies in the Turkmenistan sector of the South Caspian Sea, over an area of 920 Km2 and in water depth of 10 to 40 m.
Located in a complex wrench faulted system orientated WNW-ESE from the Apsheron Peninsula in Azerbaijan to the Cheleken Peninsula in Turkmenistan, the cheleken fields have a large thickness of stack sand and shale reservoirs, with significant areal and vertical variation.
The field is covered by legacy 3D OBC seismic data acquired and processed in 2004 and reprocessed in 2017 which served as a guide during the exploration and appraisal wells however it presented a lot of limitations in data quality and resolution.
In 2022, another step change in data quality was achieved with the acquisition of the first ever Ocean Bottom Node seismic survey acquired in Turkmenistan. Using high-resolution seismic parameters leads to much better image quality and overcome the majority of subsurface challenges.
The image quality enhancement over this area of shallow water depth was the results of good seismic survey design and a proper seismic processing workflow based mainly on a good velocity model building.
The targets in the current oilfield are variable in depth and thickness and to end up with a better understanding and delineation of the several reservoirs in the studied area, a seismic inversion, as an important tool used in reservoir characterization, was carried out as well as a pore pressure prediction evaluation using seismic velocity.
By combining well data and seismic data, we were able to predict rock properties away from borehole and get better understanding of the reservoirs extension.
Seismic inversion and attribute techniques could be the solution to predict reservoir quality. During the current reservoir characterization study, we used seismic data, well logs, seismic velocity as well as the interpreted horizons to generate impedance data and describe vertically and laterally the different reservoirs in a proper way and minimize the risk for the future drilling activities.
Dynamic Neural Network Modulation Associated with Rumination in Major Depressive Disorder: A Prospective Observational Comparative Analysis of Cognitive Behavioral Therapy and Pharmacotherapy
Authors: Katayama Nariko , Shinagawa Kazushi , Hirano Jinichi , Kobayashi Yuki , Nakagawa Atsuo , Umeda Satoshi , Kamiya Kei , Tajima Miyuki , Amano Mizuki , Nogami Waka , Ihara Sakae , Noda Sachiko , Terasawa Yuri , Kikuchi Toshiaki , Uchida Hiroyuki , Mimura Masaru 
Published: October 2024

Abstract

Cognitive behavioral therapy (CBT) and pharmacotherapy are primary treatments for major depressive disorder (MDD). However, their effects on the neural networks associated with rumination, or repetitive negative thinking, remain poorly understood. This study included 135 participants, whose rumination severity was measured using the rumination response scale (RRS) and whose resting brain activity was measured using functional magnetic resonance imaging (MRI) at baseline and after 16 weeks. MDD patients received either CBT or pharmacotherapy. Using a hidden Markov model, we observed that MDD patients exhibited increased activity in the default mode network (DMN) and decreased occupancies in the sensorimotor and central executive networks (CEN). The DMN occurrence rate correlated positively with rumination severity. CBT reduced DMN activity and improved transitions to the CEN. Pharmacotherapy shifted DMN activity to the posterior region of the brain. CBT and pharmacotherapy affect brain networks involved in rumination differently in MDD patients, suggesting distinct therapeutic pathways.