bluuebunny/crossref_metadata_2025_split huggingface dataset:
Swinging Water Injection Targets SWIT
Authors: Al Musalhi Abdullah , Al Mawali Salim , Al Ruqaishi Ali 
Published: December 2021

Abstract
With increasing wells connected to central facilities, it is hard to manage water flood using traditional technique. Therefore, a novel control concept named Swinging Water Injection Targets (SWIT) was developed in PDO to manage the challenges and satisfies both surface/subsurface requirements. The objectives of SWIT are:
Maximize water injection well compliance. Minimize oil deferment due to water disposal restriction. Automated system that manages the variations in produced water flow with minimum interventions.
SWIT concept is using the tolerance of ± 20% of desired injection target (Compliance limit) for each water injection (WI) well. So rather than having a fixed target, a minimum and maximum injection flow are giving to each WI well flow controller. Those range are provided by subsurface to ensure minimal impact for the rate fluctuation. The injection flows are driven by WI header pressure controller. When the produced water, the WI header pressure increases then the pressure controller to control the pressure asks all WI wells simultaneously increasing their injection flow at the same relative portion (Optimized distribution). Also, when the produced water decreases all WI flow starts reducing in the same way.
SWIT concept proved success in PDO and it became a standard. It was first introduced in small field. Later, it was replicated across the company fields. The biggest scale implementation was in a cluster with more than 500 WI wells. Previously, in that cluster the WI header pressure was fluctuating indicating issues with water balance. Many manual adjustments were required to manage the situations when the produced water is more than the injection demand by closing oil producers leading to a considerable deferment due to water disposal restriction. Also, when the supply water is less than injection demand many WI wells start under injecting leading to low injection compliance. After SWIT was introduced in the cluster and all injectors started swinging in harmony via automatic control, it managed to balance the water system (controlled WI header pressure) regardless of the variation in produced water production.
This resulted in increase of WI compliance by 5% after implementation. As SWIT optimized the water distribution to the injectors, roughly around 50 m3/d of additional oil production was achieved. It also minimized deferment from disposal restriction to a minimum level. All of this without the hustle of manual interventions.
Design Improvement of a Generic Catofin Reactor Air Outlet Header to Reduce the Erosion Using Computational Fluid Dynamic CFD
Authors: Parihar Ajay Singh , Lott Philippe Thomas 
Published: December 2021

Abstract

Objectives/Scope
The objective of the current work is to study the erosion inside the air outlet header of a generic catofin reactors which are used to produce the propylene. During the regular maintenance cycle of these plants, it was found that at several places in the air outlet header region erosion and material removal were reported.

Methods, Procedures, Process
Erosion wear is the loss of material due to repeated impact of solid particles on a surface and causes major economic losses across diverse industries such as oil and gas, hydraulic transportation, and chemical processes. Erosion severely damages flow passages, valves and pipe fittings, leading to higher replacement costs as well as the loss of valuable production time. For example, some oil and gas fittings can fail after just 30 minutes of operation due to high erosion rates. Engineers need to quickly evaluate the erosion on dozens of design variations to find ways of stretching the part's lifespan in order to reduce costs and maximize process up-time. Erosion is a complex phenomenon that depends on many parameters. Particle parameters can include the following: Particle shape or angularity, particle size and erodent particle hardness. Flow parameters, on the other hand, have a stronger effect on erosion as it determines particle concentration, particle impact angle, and impact velocity. Other parameters affecting erosion are properties of target surface, i.e. surface hardness and multiphase effects Progress in understanding the erosion due to solid particles has been achieved by the use of computational fluid dynamics (CFD). CFD allows the accurate modelling of fluid flow and particle trajectory through pipelines and bends. Once the impact velocity and angle of the particles colliding against the surface are calculated, empirical correlations to quantify the erosion rate can be implemented. Computational Fluid Dynamics (CFD) methodology was used to understand the cause of material removal and further perform design iterations to come up with new design to reduce the erosion drastically.

Results, Observations, Conclusions
Many design iterations were performed in virtual environment by performing CFD simulations to understand the flow physics as well as impact of various parameters affecting erosion rate inside air outlet header. Each design modification and its impact on erosion rate is compared with base design to check the effectiveness of modification. Finally, with the help of simulation, three better designs were identified, which reduces the erosion drastically.

Novel/Additive Information
With the help of CFD simulation, one can test various design modifications as well as find a solution in less time and with less cost as compared to cost associated with inspections and repair.
Challenges and Achievements of Drilling Record MRC Wells for Appraising and Developing an Offshore Tight Carbonate
Authors: Alyan Mohand Ahmed , Duguid Jamie Scott , Shahzad Atif , Alobeidli Amna Ahmed , Al Suwaidi Alunood Khalifa , Prim Matthew Thomas , Wills John Andrew 
Published: December 2021

Abstract
This paper describes the field development planning strategy for appraising and developing an offshore reservoir area via extended reach extra-long maximum reservoir contact laterals drilled from an artificial island. These single production and injection laterals are completed in excess of 20,000 ft on top of tens of thousands feet of drilled well path to reach the drain landing point. These laterals have a dual purpose, as in addition to reservoir appraisal, is to maximize the productivity and injectivity in an on-going development of a tight carbonate reservoir.
The well planning process starts from a careful selection of reservoir target coordinates to maximize the oil in place being developed from the artificial island and to enable reservoir testing and appraisal. From this data, initial 3D well designs are generated based on island location and rig capability to ensure ability to drill and run completion to total depth. The generated well tracks are used in a reservoir model to forecast production uplifts and inflow/outflow profiling along laterals. A strategic drilling step-out program has been implemented to extend drilling reach and completion deployment incrementally along with a reservoir surveillance program. The program was designed with built-in risk mitigations for any potential drilling and completion issues. The implemented program has enabled drilling into new areas and testing the reservoir properties at a small incremental cost of extending horizontal laterals. This has led to huge cost savings versus a very expensive appraisal program from a wellhead platform that included drilling a new well in addition to topside facility changes and pipelines conversions along with associated maintenance costs. The data gathered from these wells have enabled reduction of geologic uncertainty and de-risking of future developments. As a result, the field development footprint of developed oil resources was extended by additional 20% without the requirement of building additional drilling structures. Additionally, there is a well count reduction via lateral extension thus leading to capital costs saving. There were initial challenges encountered during lower completion deployment but they were resolved successfully in subsequent wells. An outcome of this strategy was the successful drilling of maximum reservoir contact wells with tens of thousands feet of drilled well path to reach the drain landing point and then with single horizontal drains exceeding 20,000 ft. The drilled wells resulted in unprecedented records in UAE and globally in terms of well total length, horizontal drain length and completion deployment.
Enabling Extended Reach Wells with the Aid of an Ultra-High Speed Rotational Reamer Shoe
Authors: Naknaka Manchukarn , Nkwocha Chimere , Prasongtham Pattarapong , Tongkum Tossapol , Phu Trinh Dinh , Siritheerasas Khamawat 
Published: December 2021

Abstract
Well X is an infill horizontal well designed for the Gulf of Thailand. It is challenging due to the following factors - A long 8 ½ inch open hole section, An extended reach section at horizontal or near horizontal, the presence of loss circulation zones, an Extended Reach Drilling (ERD) ratio of 2.725 and a Drilling Difficulty Index (DDI) of 6.762. The key challenge was to successfully deploy the 7 inch casing across 12,350 ftMD of open hole, with potential loss circulation zones. In spite of these difficulties, the 7 inch casing was successfully landed with the use of an Ultra-High Speed Rotational Reamer Shoe.
Historically, losses of circulation have posed significant challenges to well delivery in the Gulf of Thailand wells. In Well X, this is further complicated by a long open-hole section with a step-out of over 10,000 ftMD. It was determined that the successful deployment of the 7 inch casing would require some degree of agitation at the nose, and such a device must be tolerant to the Lost Circulation Materials (LCM) type and the composition of the drilling fluid and the cement. An ultra-high speed rotational reamer shoe was specially configured to meet the LCM requirements in the displaced fluid, for use in deploying the casing.
While deploying the 7 inch casing, losses of up to 20 bbls/hr occurred from 7,043 ftMD while running at 15 joints/hr. A loss circulation recipe comprising of 60 bbls of 30 ppb Tiger LCM was mixed and successfully displaced through the customized ultra-high speed reamer shoe to cure losses. The casing was washed down from 10,569 to 11,610 ftMD, filling casing each stand.
The 7 inch casing was successfully landed at the target depth of 12,353 feet and subsequently cemented. Drill out operations took 1.5 hours to complete. A formation integrity test (FIT) showed good shoe strength which was later confirmed by the cement evaluation logs. The comprehensive Ultra-High Speed Reamer Shoe was configured with a minimum restriction of 15mm, which is 5 times the diameter of the maximum particle size in the LCM of 3 mm. The tool was designed to tolerate the prescribed loss circulation materials, making it possible to cure the losses while running the casing string.
The innovative Ultra-High Speed Reamer Shoe has demonstrated its usefulness by providing a higher probability for successfully deploying the 7 inch production casing over the extended reach section of Well X. The application of this technology can mitigate against non-productive time such as wiper trips or excessive washing down or casing rotation. It has proven to be a reliable technology that can be used in the industry in challenging well designs.
Autonomous Corrosion and Scale Management in Electric Submersible Pump Wells
Authors: Van Spankeren Michael Hendrik , Hernandez Miguel Angel 
Published: December 2021

Abstract
Producers find a considerable amount of their operating expense (OPEX) comes from managing risks associated with corrosion and scale. Monitoring and chemical adjustment workflows are typically manual, and performed at low frequencies, leading to delays in event detection. As a result, the potential for negative events such as production shutdowns and well failures increase. This project's scope integrates chemistry domain experience with edge analytics, machine learning models, and intelligent equipment, to transform manual processes into an autonomous solution. The goal is to optimize operations, reduce well failures and workover costs, and maximize production. This solution is currently deployed in an oilfield, that has been historically challenged with a high number of electric submersible pump (ESP) failures due to corrosion and scale that resulted in significant production losses and unforeseen workover costs. The designed digital architecture supports autonomous management of scale and corrosion through remote monitoring and automated chemical injection. Real-time data is acquired from connected equipment, processed in an edge device running artificial intelligence, and autonomously sent to chemical pumps. Data from sensors, connected devices, and models are visualized in cloud applications, or integrated into existing client systems for end user analysis and full visibility of the entire process. The results show highly accurate models, precise chemical injection, and a reduction of well failures.
Big Data IAOM Project Management and Workflow Automation in a Giant Gas Field Digitization Drive
Authors: Alsaeedi Ayesha Ahmed Abdulla Salem , Elabrashy Manar Maher Mohamed , Alzeyoudi Mohamed Ali , Albadi Mohamed Mubarak , Soni Sandeep , Isambertt Jose , Tripathi Deepak , Shah Ankit 
Published: December 2021

Abstract
Integrated asset modeling, application of big data, and automation are among the top emerging trends in the oil and gas industry. The value associated with such implementation projects is very closely linked with the efficient use of the project management approach and a robust strategy to handle the technological challenges. This paper puts light on such initiatives implemented in a giant gas field.
In this giant gas condensate field, a vast amount of data is generated and monitored on a daily basis. The frequent need to deliver the dynamic production target was driving this project implementation so that a value-driven system can be established while achieving the business KPIs. A phased approach was used to target multiple requirements into business deliverables where the early offline phases provided a robust base for full online integration. This project followed the agile approach focusing on getting insights from multiple stakeholders and domain experts and developing a lesson-learnt repository in all the project phases.
The online integration solution is a critical differentiator in the workforce and process efficiency improvement. The multiple technical solution workflows helped in reducing manual efforts and streamlining the methodology in a standardized fashion. In addition, the standard project management practices, such as initializing the phases in a planned manner, followed by an interactive execution, monitoring, and controlling stages, ensured delivering project outcomes in an efficient way. This implementation also established a robust collaborative team effort to identify various different roles and responsibilities for stakeholders. This helped in the end phase when the project sustainability was essential. A strong team base maintained and updated the integrated system while delivering daily well and facility surveillance objectives and KPIs from users ranging from planning, engineering, operation, and management team. A special focus on IT team involvement throughout the project phase led to a successful data integration and diagnostic, as the core of the solution was a data-driven analytical framework integrated with multiple corporate and real-time data sources. In addition, this solution was equipped with various one-of-its-kind solution features such as business intelligence, advanced surveillance, dynamic-reservoir integration, manage-by-exception workflows, intelligence alerts, along with a strong digital framework and data architecture.
The unique hybrid and agile project management approach focusing on delivering emerging trends and technologies to end-users in the most efficient way paved the way for achieving asset digitalization and standardization goals.
World'S First Successful Dual String Installation of a Digital Intelligent Artificial Lift DIAL - Interventionless Gas Lift Production Optimization System, Offshore Malaysia
Authors: M Ghazali M Haziq , Rozlan M Rizwan , Bakar M Farris , Ishak M Faizatulizuddin , Samuel Orient Balbir , Misron Mohd Al Perdaus , Ismail Mohamad Sazwan , Salleh Nurfarah Izwana , Rizwan Badroel , Amara Abdel Ben , Faux Stephen , Ahmad Azhari Ahmad Hafiz , Muara Azis Anak 
Published: December 2021

Abstract
PETRONAS completed well H-X on B field in Malaysia with a digital intelligent artificial lift (DIAL) gas lift production optimization system. This DIAL installation represents the first ever successful installation of the technology in an Offshore well for Dual String production. This paper provides complete details of the installation planning and operational process undertaken to achieve this milestone.
DIAL is a unique technology that enhances the efficiency of gas lift production. Downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention.
This paper focusses on a well completed in November 2020, the fourth well to be installed with the DIAL technology across PETRONAS Assets. The authors will provide details of the well and the installation phases: system design, pre-job preparations, improvements implementation, run in hole and surface hook-up. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits.
DIAL introduces a paradigm shift in design, installation and operation of gas lifted wells. This paper will briefly highlight the justifications of this digital technology in comparison with conventional gas lift techniques. It will consider value added from the design stage, through installation operations, to production optimization.
This DIAL system installation confirms the ability to be implement the technology in a challenging dual string completion design to enable deeper injection while avoiding interventions on a well with a greater than 60-degree deviation. With remotely operated, non-pressure dependent multi-valve in-well gas lift units, the technology removes the challenges normally associated with gas-injected production operation in a dual completion well – gas robbing and multi-pointing.
Despite the additional operational & planning complications due to COVID-19 restrictions, the well was completed with zero NPT and LTI. Once brought online, this DIAL-assisted production well will be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS’ upstream digitization strategic vision.
STEP Change in Preventing Stuck Pipe and Tight Hole Events Using Machine Learning
Authors: Bahlany Salah , Maharbi Mohammed , Zakwani Saud , Busaidi Faisal , Benvenuti Ferrante 
Published: December 2021

Abstract
Wellbore stability problems, such as stuck pipe and tight spots, are one of the most critical risks that impact drilling operations. Over several years, Oil and Gas Operator in Middle East has been facing problems associated with stuck pipe and tight spot events, which have a major impact on drilling efficiency, well cost, and the carbon footprint of drilling operations. On average, the operator loses 200 days a year (Non-Productive Time) on stuck pipe and associated fishing operations.
Wellbore stability problems are hard to predict due to the varying conditions of drilling operations: different lithology, drilling parameters, pressures, equipment, shifting crews, and multiple well designs. All these factors make the occurrence of a stuck pipe quite hard to mitigate only through human intervention.
For this reason, The operator decided to develop an artificial intelligence tool that leverages the whole breadth and depth of operator data (reports, sensor data, well engineering data, lithology data, etc.) in order to predict and prevent wellbore stability problems.
The tool informs well engineers and rig crews about possible risks both during the well planning and well execution phase, suggesting possible mitigation actions to avoid getting stuck. Since the alarms are given ahead of the bit, several hours before the possible occurrence of the event, the well engineers and rig crews have ample time to react to the alarms and prevent its occurrence.
So far, the tool has been deployed in a pilot phase on 38 wells giving 44 true alarms with a recall of 94%. Since mid-2021 operator has been rolling out the tool scaling to the whole drilling operations (over 40 rigs).
First Use of Novel High Temperature Water-Based Reservoir Drilling Fluid to Access Depleted Deepwater Reserves
Authors: Morrison Alexandra Clare , King Conan , Rodrigue Kevin 
Published: December 2021

Abstract
A combination of divalent base brine and high wellbore temperature presents significant challenges for high density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Non-aqueous drilling fluids are thermally stable but complete removal of the filtercake is challenging and this can lead to formation damage. This paper describes the qualification and first deepwater drilling application of a unique aqueous reservoir drilling fluid at temperatures above 320°F.
A high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and a solids-free screen running fluid (SF-SRF) were designed, both utilizing the same novel synthetic polymer technology. Calcium bromide brine was selected for use to minimize the total amount of acid-soluble solids in the drilling fluid. A comprehensive qualification was undertaken examining parameters such as rheology performance across a range of temperatures, long-term stability, fluid loss under expected and stress conditions (16 hours at 356°F), production screen test (PST), and various fluid-fluid compatibility tests. Return permeability tests were conducted on the final formulations to validate their suitability for use.
The synthetic polymer technology provided excellent rheology, suspension, and fluid loss control in the fluid systems designed in the laboratory. To prepare for field execution multiple yard mixes were performed to verify the laboratory results on a larger scale. Additionally, a flow loop system was utilized to evaluate fluid performance under simulated downhole temperature and pressure conditions before field deployment. The final high temperature drilling fluid as designed provided rheological properties that met the necessary equivalent circulating density (ECD) requirements while drilling the reservoir. The fluid loss remained extremely stable and there were no downhole losses despite the depleted nature of the wellbore. Production screens were run straight to total depth (TD) with no wellbore stability issues after a three-day logging campaign.
High temperature aqueous reservoir drilling fluids have historically been limited by the lack of suitable viscosifiers and fluid loss control additives. This paper outlines the design, mixing and logistical considerations and field execution of a novel polymer-based reservoir drilling fluid.