bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Three Thru-Tubing Sand Control Remedial Works Using Ceramic Screen in ACG Field: Design, Execution, Evaluation and Strategy for Next Jobs
Authors: Jafarov Emin , Susilo Yoliandri , Agayev Farid , Mikayilova Aydan , Gafarov Nadir , Guliyev Imran , Allahverdiyev Matin , Guliyev Ilkin , Sadigov Teymur , Hasanov Zahid , Pashayev Ahad , Eyyubbayli Turan 
Published: March 2024

Abstract
The Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. The major reservoir zones are comprised of poorly sorted and weakly consolidated multi-layer sandstone formations. While Open-hole Gravel Pack (OHGP) completions have become the standard design for production wells, there are also several Cased & Perforated (C&P) wells from early field development along with some opportunistic Up-hole Re-completion (UHRC) C&P wells that were converted from OHGP. As the field matures with increasing depletion, water cut and gas/oil ratio (GOR), OHGP wells with vulnerability in the pack (incomplete pack) and C&P wells start to produce sand. Consequently, those wells are choked back resulting in sand-induced production deferral.
Several sand control remedial work technologies were evaluated for the field and ceramic screen technology was chosen due to higher erosion resistance to cope with high flow rates and GOR in ACG wells. Three thru-tubing sand control remedial works using ceramic screen has been trialed successfully, both inside C&P well and high angle OHGP wells with unpacked section at the toe which previously isolated by bridge plug. The ceramic screen bottom-hole assembly (BHA) was deployed using coiled tubing with total BHA string length up to 178m. A snap type connector was used to minimize number of runs into each well, by allowing running string of multiple sections of ceramic screen and blank pipe in one trip.
The ceramic screen installation inside C&P well demonstrated higher post-job skin compared to OHGP application, however having ceramic screen in the well allowed to produce with 3x higher drawdown at higher water cut up to ~40% with limited sand production and extend the well life considering typical C&P well failed with much smaller water cut. The ceramic screen installed in OHGP screen across unpacked section shows minimal skin change. In average there was ~2,500 bbls/day immediate incremental oil gain after each sand remediation work. This successful result demonstrates the viability of this remedial works to unlock production potential of producer wells and reduce sand-induced production deferrals in the field.
This paper primarily discusses design, execution, result and learning from the first three thru-tubing sand control remedial work that was done in the ACG field.
Increasing Efficiency in Well Abandonment Utilizing Hydromechanical Slotting Tool
Authors: Munir Waqas , Dahlberg Knut Inge 
Published: March 2024

Abstract
As the number of the wells designated for the abandonment or slot recovery operations increase, multiple challenges are faced during the barrier placement and removal of the casing. Achieving operational efficiency is crucial. Till now, conventional solutions included milling of the casing, throughout history, conventional solutions involved milling processes and the use of charges to establish channels for either barrier placement or cement remediation or reduction of stuck forces, thereby enhancing casing removal efficiency.
This paper will explain the new technology which includes a hydro-mechanical tool that creates the slots into the casing to allows the access behind. This innovative approach aims to significantly improve efficiency during the well abandonment phase. The tool's capability extends to breaking down the barite accumulation behind the casing or facilitating the precise placement of cement for sustained casing pressure solutions or annular cement remediation. The incorporation of this advanced technology marks a paradigm shift in addressing the challenges associated with well abandonment, offering a more streamlined and effective solution.
Safe and Successful Restoration of Wellbore Accessibility by Wellhead Gate Valve Milling
Authors: Almulhem K. F , Mubarak M. , Muhammad A. , Mansour A. 
Published: March 2024

Abstract
Well control has been one of the most important items in oil and gas production engineering. The wellhead plays a vital role in well control as it consists of many valves, including the master valve (MV), crown valve (CV), and wing valve (WV). The MV is the lower valve in the wellhead that is directly exposed to well pressure. Therefore, it's very important to ensure the valves holding in terms of functions tests and greasing. Passing the MV that is stuck in a partial closed position is considered a tremendous challenge, not only in well integrity but also for well intervention. The valve cannot be opened to allow for well intervention and cannot be totally closed to withstand well pressure to act as surface barrier in line with API standards. This challenge presents an opportunity to capitalize on milling the MV utilizing a gate valve drilling unit (GVDU). This paper presents a solution that addresses stuck valves across wellhead trees.
The conventional practice is to utilize either a workover (WO) rig or coiled tubing (CT) to mill the MV and secure the well to change a defective MV. However, it is more challenging when the well does not meet the minimum barrier requirements and the operation is costly. A new generation of GVDU has been deployed to especially mill such a stuck/defective MV, with no need to utilize (CT) unit nor a wireline (WL) unit -.
A 15K pneumatic GVDU has successfully been demonstrated and proven its ability to mill the gate valves to safely restore and gain wellbore accessibility. During the planning phase of this operation, several elements were considered to ensure safe and efficient execution, including conducting a series of peer reviews, comprehensive risk assessments along with well integrity and well intervention peer review team members. During the operation, several challenges have arisen such as rising pressure because of the compressed gas while run in hole (RIH), which was tackled by a modification of the gas bleed-off needle. Moreover, killing the well was challenging due to the fact the MV was in stuck position. Thus, a circulation path was added through pumping water,. Nonetheless, there were three main advantages through utilization of a GVDU; one of which was the easy and light rig-up. Second was safe and quick operation, which was completed in only 2.5 hours. Third was the cost optimization unless idea is to indicate that no cost was involved?
This success of this operation has unlocked the well potential after regaining wellbore accessibility. It also resolved the well integrity/control challenge in a safe, an extraordinary expedited intervention, a cost-effective method, and an environmentally safe and minimal environmental footprint.
First Rigless Intervention in Bonga Deepwater
Authors: Okosun Augustine , Ugbor Ifeanyi , Ezeokafor Tobechukwu 
Published: March 2024

Abstract
In the Bonga Deepwater project, while exploring subsea well intervention and stimulation campaign opportunity, the subsea Rigless intervention strategy, which has been in the SNEPCo team's technology maturation funnel for some years, re-surfaced. In the first quarter of 2017, the Shell Nigeria Exploration and Production Company (SNEPCo) Deepwater team led the industry to deploy the first ever riser-less technology for well intervention operations in Nigeria. The main objective was to prove the rigless intervention concept and capability in the Bonga Deepwater project. The team focused on improving production enhancement and sustaining well integrity on the Bonga Main Project by minimizing well-intervention cost without compromising process safety, achieving incident free operation, and delivered the project at 50% less than what this scope of work would have cost using a Mobile Offshore Drilling Unit (MODU). Additionally, the acid stimulations added 9,200 barrels of crude oil per day to the company's production.
As with every new project, several challenges were encountered, and new ideas were developed. The team acquired a lot of learning from the planning phase, vessel mobilization to execution. These learnings have been integrated into the team's standard operating procedure and shared with other stakeholders. Additionally, the knowledge and learnings gained from this project have been harnessed in collaboration with the service provider and Original Equipment manufacturer (OEM) to modify and upgrade an existing in-house well intervention well control package (EDP/LRP) for riserless intervention access in the Bonga Deepwater project.
Automation – Continuing to Improve Service Delivery of Coiled Tubing Operations
Authors: Craig S. , Pinero L. , Terry A. , Lindsey B. 
Published: March 2024

Abstract
Coiled tubing operations become ever more complex to meet the demands within the industry. A worldwide challenge is a smaller group of highly qualified field personnel to meet these expectations and without such can lead to a potential compromised service delivery. To alleviate this our focus is on the increased level of unit automation providing the unit operator with greater monitoring, feedback, technical advice and, if needed, intervention on the unit to prevent failures.
The combined solution is derived from three main areas: automatically update the CT force limits, continuous monitoring of key parameters to provide operational advice, and if required to prevent a potential failure, automatically intervene with control of the appropriate injector functions. Core to the system has been taking a highly complex CT flow and force model and transferring it to run automatically with only minimal intervention from field operators or specialists.
The paper will detail the multiple system capabilities and the associated historic service delivery issues that created the need for the automated system. For example, the injector control system utilizes five different limit measurements to auto stop the injector to prevent failure. This includes the ability to auto monitor downhole force measurements during logging operations, which liberates wireline personnel to attend to other tasks during CT deployment and recovery. System enhancements such as the ability to easily recalibrate force modeling by adjusting friction and surface loads will be detailed. The system has further enhanced the ability for field crews to track expected vs actual loads and take preventative action without the need for a field engineer to be present.
The system is being utilized across the service provider's fleet of units. Statistics on reduction of incident rates will be presented.
Many operating companies are fully engaged and supportive of the journey to operational automation/remote monitoring and service delivery improvements. The majority of the features covered above have never been presented in a technical paper. This paper would provide valuable industry insight into the current and future expectations of technology that will aid the operating companies’ goals.
Fit-For-Purpose Heavy-Duty Fishing Equipment Designed to Safely Retrieve a Damaged Wireline Cable from an Active, Sour Gas Well Located Offshore
Authors: Amri M. N , Macaulay R , Aboelnaga S , Abouganem A , Al Dahhan M 
Published: March 2024

Abstract
Wireline operations play a crucial role in the oil and gas industry, facilitating essential tasks like well maintenance, data collection, and intervention. These operations involve deploying substantial downhole tools and large cables into the wellbore, but this endeavor is not without its challenges. Particularly, when a wireline cable breaks downhole, it poses significant risks.
Unplanned wireline breakages result in demanding heavy-duty fishing operations when they occur in challenging offshore environments and unfavorable downhole conditions. In this work, strategic planning and execution were applied in a complex e-line cable recovery in a live, sour gas well without the need for well kill operations. This undertaking necessitated a unique approach to safety and setup, starting with a thorough assessment of the challenging well conditions. A comprehensive fishing plan was then developed to embrace all potential scenarios. The operation involved the use of advanced heavy-duty fishing tools and solutions specifically designed to withstand the well conditions.
The success of this endeavor is evident in the completion of two recovery operations, all resulting in the successful retrieval of the wire. This first achievement enables customers to restore wellbore access and proceed with their planned interventions. One of these operations involved recovering ~ 4000ft of 5/16in Eline cable and upper section of the fish using mechanical wireline and coiled tubing.
While SPE-218323-MS (ICOTA A. Abouganem 2024) provides details about the first recovery, this paper aims to present a more comprehensive overview of the second recovery. Specifically, this recovery involved retrieving a 0.350-in Polymer encapsulated wireline cable using a 5/16-in Heavy Duty braided wireline cable within a 7-in. tubing., representing the first occurrence of such a cable recovery on a global scale. The paper delves into the specific techniques employed and the substantial effort and planning invested in successfully recovering this distinctive cable, recognized for its unique shape characterized by elevated breaking strength and rigidity. The distinct nature of this recovery necessitated the utilization of specialized tools and techniques for both latching and recovery.
An Artificial Intelligence Model to Synthesize Measurements While Drilling Sensors for Coiled Tubing Drilling
Authors: Urdaneta C. , Jeong C. , Zheng A. 
Published: March 2024

Summary
This paper presents a comprehensive methodology for developing an artificial intelligence (AI) model to synthesize downhole measurements as a digital backup for measurement while drilling (MWD) sensors, ensuring uninterrupted drilling in coiled tubing drilling operations (CTD). The MWD tool plays a pivotal role in CTD, acquiring critical measurements for safe drilling operations. These measurements are critical for decision-making, monitoring, and managing the drilling process. One significant challenge faced during CTD is the occurrence of sensor failures in MWD tools, which hinders the real-time assessment of downhole conditions. Such failures can lead to operational downtime due to the need to trip out the bottomhole assembly (BHA) for sensor replacement. To address this issue, an AI based model using synthesized downhole measurements as backup for MWD tools has been developed for CTD. The proposed AI model leverages custom regression models for each MWD sensor, using various machine learning techniques such as Random Forest, Gradient Boosted Trees, and more to predict sensor values when a sensor fails. The model is continuously updated with new data and uses predefined thresholds and AI-based models to detect sensor failures and assess the uncertainty of predictions. To evaluate the model's effectiveness, various machine learning models are compared using metrics such as mean absolute error (MAE), and r-squared score (R2). The results indicate high accuracy in predicting sensor data, even in the absence of failed sensors, for annulus pressure, pipe pressure, and weight on bit (WOB). This approach could reduce nonproductive time (NPT) and costs associated with sensor failures in CTD operations. It provides a robust framework for using AI to maintain uninterrupted drilling operations by synthesizing sensor data when needed, ensuring the seamless execution of drilling operations.
Through-Tubing Snake Tool Installation Enables Remedial Intervention in a Niger Delta Condensate Gas Well
Authors: Osode P. I , Soro A. O , Olugbade O. R , Alake S. A , Uwakwe R. O , Samaila I. A , Nwadiogbu L. C , Nicoll D. A , Ugboaja C. C , Iyamah A. I , Shehu A. H , Aworanti O. A 
Published: March 2024

Abstract
Single string-single interval completion design has been traditionally adopted for high-rate Niger Delta condensate gas wells because of ease of the large-size tubing installation and integrity of the bottom production packer assembly. Following the incident of leaking packer and the loss of safety barrier above the bottom completion interval, wells were re-entered with workover rig for integrity repair. A pragmatic approach taken was to install a new production string and packer after tubing cut and retrieval with the old packer stump assembly remaining in hole.
The resulting gap between the top and bottom completion configuration has hampered through-tubing tool conveyance into the sump during subsequent rigless remedial intervention. To overcome this challenge, a tubing conduit (snake tool) with maximum possible internal diameter was configured to be stabbed into the lower completion tubing stump and hung-off at the landing nipple profile within the top completion. The snake tool was made of conformable material for the corrosion risk environment due to presence of corrosive CO2 gas in the produced condensate gas and existing downhole completion string made of 13Cr tubing plus accessories. Reliability and robustness of the tool was evaluated based on the expected well operating envelope including analysis of the mechanical strength, stresses, and erosional risks at expected downhole conditions.
The 3.78-inch snake tool was able to restore seamless wellbore access to the lower tubing break, approximately 25ft below. This tool will facilitate planned through-tubing remedial activities such as perforations, mechanical water-shut off, zonal isolation and chemical stimulation interventions. The wireline snake tool deployment which took only 6 days has proven to be highly cost efficient given the elimination of a rig workover.
This paper enumerates the investigation and preparation of the snake tool application from the design stage to the field execution in the 10,700-foot-deep gas well. It is expected that this low-cost repair technique will be extended to many other similar gas wells in the region.
Advancing Pipe Integrity Assessment in Multi-Barrier Well Completions: Full-Scale Test with Seven Pipes
Authors: Dai Junwen , Sheng Huiwen , Fouda Ahmed E. , Saada Mahmoud , Ostermann Neil , Roy Sushovon 
Published: March 2024

Abstract
Well completions typically involve a series of multiple barriers that serve as the structural foundation for both production activities and safeguarding aquifers against contaminants. Monitoring the integrity of these completions holds immense importance for the reliability of oil and gas production as well as environmental preservation. In instances where wells experience diverse pressure gradients, geological complexities, or corrosive settings, the number of barriers might extend beyond five, seeking heightened protection. This intensifies the complexity of assessing pipe integrity within such wells. Even if the tubing could be pulled out, the presence of several permanent barriers exacerbates the challenge for existing non-destructive testing methodologies to accurately evaluate metal loss within each barrier. In this paper, we demonstrate how a new technology based on a multi-frequency multi-spacing electromagnetic tool is used to estimate the individual wall thicknesses of up to seven barriers. A full-scale fixture comprising seven pipes with outer diameters ranging from 2-7/8″ to 24″ was built. The pipes have non-uniform machined defects to mimic realistic metal loss profiles akin to ones caused by corrosion. The tool's efficacy within well scenarios featuring seven pipes is showcased through the utilization of both the yard test and real field data. These tests substantiate the tool's precision in accurately determining the extent and position of corrosion within each individual barrier up to seven simultaneous pipes.
How a New On-Command Downhole Control System is Breaking the Efficiency and Sustainability Paradigm in Multilateral Stimulations
Authors: Ramondenc Pierre , Molero Nestor , Hofacker Mark 
Published: March 2024

Abstract
Over the past two decades, coiled tubing (CT) has been the preferred intervention method in multilateral wells, given its ability for deeper reach, smaller displacement volumes, more controlled placement, and flexibility on the scope of work. Nonetheless, as the lateral mapping and entry processes have relied on hydraulically actuated downhole tools, interventions tend to be lengthy and fluid consuming, requiring more than 400 bbl of water per lateral just for mapping purposes.
Stimulation treatments in multilateral wells are usually preceded by wellbore conditioning on each lateral. The placement of the treating fluids is conducted through a high-pressure jetting module that, when activated permanently, isolates the multilateral entry components of the hydraulically actuated toolstring. Therefore, interventions with cleanout and stimulation scope of work cannot be conducted in a single run, extending the overall intervention time. The recent introduction of an acid-resistant, electrical multilateral entry tool with direction and inclination measurements allows lateral entry on the first attempt. The system also features a downhole on-command, electrically actuated circulation valve (EACV), which redirects fluid to either exit jetting nozzles or to downhole tools, thus avoiding isolation of any toolstring component.
A dual-lateral carbonate water injector well, completed as a 6 1/8-in. open hole, was selected for the first implementation of the acid-resistant, multilateral entry assembly. The CT string was equipped with a hybrid electro-optical cable that provides continuous downhole power and enables dual telemetry (optical and electrical) capabilities for a virtually unlimited operational time. Following cleanout work on the main lateral (L-0), entry into the second lateral (L-1) was completed on the first attempt. In both cases, the wellbore conditioning stage was conducted by circulating fluids through the jetting nozzles of the EACV. Before the matrix stimulation of each lateral, the flow path of the EACV was switched, redirecting the flow through a high-pressure jetting tool. Close to 5,000 bbl of reactive fluids were pumped throughout the stimulation stage with an average pumping rate of 3.5 bbl/min. The entire scope of work was completed in a single CT run, saving more than 48 hours of operating time. The optimized intervention workflow saved more than 1,000 bbl of water and reduced CO2 emissions by nearly 25%.
The experience gained from the first implementation of the acid-resistant, multilateral entry assembly validates the technology as a step-change for enhanced CT multilateral intervention. This technology paves the road for new intervention workflows leveraging optical and electrical CT downhole telemetry with the EACV acting as the key building block to provide full control of the selective actuation of part of the hydraulic bottomhole assembly.