bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Overlooked Intricacies of Wellbore Cleanout in Sub-Hydrostatic Conditions with Coiled Tubing: Lessons Learned Toward an Effective Approach
Authors: Hamid Saad , Abulhamayel Nahr M. , Ahmed Danish , Hamidon Zahaezuani Rafiq 
Published: December 2021

Abstract
This study focuses on horizontal wells completed with pre-perforated liners installed in open holes, and which produce under sub-hydrostatic conditions. During workover operations, loss circulation materials (LCM) are routinely pumped, thus requiring coiled tubing (CT) cleanout interventions to enable well production afterwards. The sub-hydrostatic nature of the reservoir makes it challenging to maintain optimum bottomhole pressure (BHP) and have the ideal downhole conditions, without significant losses and with sufficient annular velocities, for an effective cleanout.
During CT cleanout operations, the LCM plugging the formation may falsely create a perception that the well is able to sustain a column of fluid. However, as the LCM is cleaned out and the wellbore starts communicating with the reservoir, sudden fluid losses may occur, causing solids in the annulus to fall and leading to a stuck pipe scenario. Constant control of the balanced downhole conditions is therefore critical in such operations—yet frequently overlooked during job design. The use of real-time downhole pressure sensors thus not only ensure effective cleanout but also act as a stuck pipe prevention measure.
Based on job executions in similar wells, several lessons learned were compiled. The ability to maintain optimum downhole conditions by adjusting liquid and nitrogen rates during cleanout has proven to be key to a successful cleanout. Additionally, in one of the wells where CT did get stuck, the team was able to prevent debris from falling, thus addressing the root cause, and facilitating the implementation of an effective contingency plan to get the pipe free.
The need for live downhole monitoring is even more important when operating in the pre-perforated liner sections that are exposed to the open hole. Common designs calculate annular velocities based on the internal diameter of the liner, but in reality, the much bigger openhole diameter shall be taken into consideration, which result in much lower values of annular velocities in reality.
Additionally, selection of the right bottomhole assembly (BHA) is critical for the overall system performance. In the presented case, the motor and mill configuration was observed to be more effective compared to a high-pressure rotary jetting tool. However, as the motor and mill combination creates significant vibrations while operating, it becomes critical to use a ruggedized version of the live downhole CT acquisition system to ensure maximum reliability.
The observations compiled throughout operations enabled the development of best practices. Risks involved in a cleanout operation are often underestimated, especially in a well with a depleted reservoir. As more reservoirs face depletion in mature fields globally, the ability to clearly understand the downhole dynamics during such operations makes the difference between a successful job and a catastrophic failure.
API Process Safety Site Assessment Program PSSAP®: Significant Program Updates and Future Focus
Authors: Frazier Colin M. , Burr Alexa S. , Meng Ryan D. 
Published: December 2021

Abstract
The American Petroleum Institute (API) and the U.S. oil and natural gas industry have long been committed to protecting the health and safety of our workers, contractors and neighbors. For more the 75 years, API has led the development of industry standards, sharing lessons learned as well as the establishment of training and certification programs.
In recent years, despite safety improvements by the refining industry, incidents have increased attention on process safety by industry, governments, non-government organizations (NGOs), and the media. Recognizing these concerns, API and our memebrs are working collectively to improve or develop new programs improve process safety performance.
As part of the industry's ongoing commitment, API, in collaboration with industry partners, has developed a Process Safety Site Assessment Program (PSSAP®), an assessment program focused on evaluating higher risk activities in a refining, petrochemical, or chemical facility. This program is intended to:
Promote process safety performance improvement industry wide; Promote learnings from industry practices; Provide benchmarking through the consistent use of industry-developed good practice protocols; Serve as a feedback mechanism for an analysis of industry performance; and, Encourage safety collaboration among participating sites and industry experts.
PSSAP benchmarking, a key aspect of the program, allows sites to judge their performance against that of their peers in a blinded fashion. In addition to this benchmarking, the consistent use of our good-practice protocols enables API to analyze where companies may still be working to improve. Taking that information, API has implemented other programs to assist industry in those areas. Further, it has allowed API to quantify PSSAP protocol scoring improvements across the industry, seeing positive momentum in benchmarking scoring across the life of the program.
PSSAP® is also a primary resource to support API Energy Excellence® implementation. API Energy Excellence is another critical API program in which all API members commit to enhance the integrity of operations across the industry by applying standards, implementing workforce training programs, and participating in performance initiatives. Downstream and petrochemical operators can use these PSSAP protocols to help demonstrate conformance to their API Energy Excellence requirements.
PSSAP® is flexible so that sites can tailor assessments to specific needs and operations. It provides options for smaller sites that do not have on-site internal assessment capabilities or do not think a full PSSAP General Assessment is warranted. It is intended that assessments focus on higher risk activities and includes an evaluation of both the quality of written programs at a site and the effectiveness of field implementation of those programs.
A Novel Approach to Drilling Through Challenging Formations With Complex Logging Bottomhole Assembly in an Exploration Well, North Sea
Authors: Kallhovd Anders , Kelsall Neil R , Haaland Erik , Haugestaul Jon , Akutsu Erik , Veiberg Tormod , Oreskovic Antonio , Nagy-Korodi Istvan , Vestergaard Anders 
Published: December 2021

Abstract
The southern part of the North Sea continental shelf is known for large intervals of hard, compact, cretaceous chalk formations that historically have proven to be challenging to drill through in one run. In recent years technology has been developed to drill specifically through these types of sedimentary successions as effectively as possible to be durable and competitive in similarly challenging drilling settings. Formations that previously would require multiple bit runs are now being drilled in one. The exploration well 2/9-6 S Eidsvoll, operated by MOL Norge AS, was drilled in this area of the North Sea continental shelf, with this specific type of chalk being drilled in the 12 ¼-in. section.
Because the 12 ¼-in. section consisted of several different lithologies, it was vital to design the bottom hole assembly (BHA) to handle the diversity of rock formations to be drilled. Lithologies ranging from soft, swelling clay to hard compact chalk with an Unconfined Compressive Strength (UCS) as great as 20,000 psi were expected. In addition to managing the challenging drilling environment, determining the casing setting depth was of the highest priority because a pressure ramp was expected near the planned setting depth. This pressure ramp is located in the Base Cretaceous Unconformity (BCU), which is a well-known seismic reflector in the area. The top of this reflector had an uncertainty of ±75 m, which is not ideal following a decision to set the 9 ⅞-in. casing as near as possible to the reservoir. Seismic-while-drilling technology was applied to reduce this uncertainty and better tie-in the acoustic velocities to the pre-drilling seismic model. In addition, a geomechanics team was tasked with creating and updating the prognosed pore pressure estimation model. This information was important in making the mud-weight decision when drilling the 8 ½-in. section.
Improved Safety: The Importance of Aggregated Safety System
Authors: Hendi Farshad , Rashed Mohamed Hassan 
Published: December 2021

Abstract
In this paper we review why there is a need not just for persistent monitoring and validation of critical safety KPI's at an individual safety-related system level, but an aggregate view of safety performance across units, plants, sites and even regions. Can providing a holistic view of risk at the enterprise layer be the answer to eliminating the events that jeopardize a more sustainable performance and future?
New technologies and the Digital Transformation enable operator companies to control and manage their process safety risks in real or near-real time. Imagine something like a process safety risk meter: a digital device that collects, analyzes, and provides data from processes, equipment assets and protection layers. In essence, this tool would allow visualization of past, present and future operating risks so decision makers can make better, faster operating and business decisions in real time. As the world and global economy becomes more digital, market changes and pressures are becoming more dynamic. First, the speed of business continues to increase at a remarkable rate, which means business risks and variables, everything from fluctuating energy and feedstock costs to cybersecurity threats, are changing almost daily. Second, global policy initiatives and regulations that strive to create a more sustainable world mean companies now need to operate more efficiently, reliably, and safely than ever. But despite the trends driving a more dynamic operating and business environment, many companies still rely on static process hazard analysis—PHA—to identify and evaluate their process safety risks. While it's a trusted and reliable approach, PHA does not meet the needs of today's real-time business environment.
Identifying, mitigating, and managing business, operating and environmental risks in real time or near-real-time has become essential for the short- and long-term success. With that in mind, it is time to revisit risk-management strategies, particularly the strategies used to mitigate process safety risks, and explore how they can help you optimize your operations for a more sustainable performance.
Human Factors in HSE Performance – Role of User-Friendly HSE Documentation
Authors: Al Hammadi Saud Mohamed , Akula Ramakrishna 
Published: December 2021

Abstract
Organizational Multi layered documentation frameworks, complex document writing styles, cross referencing, poor document integration, end user language barriers and psychological factors for searching relevant information under pressure complicates the understanding of a technical document. Complex technical documents intimidate the end user and shrinks the user understanding. Document engineering or Usability mapping of documents is proven scientific method for writing technical documents in a simplified and user-friendly manner. The document engineering concepts are based on human psychology, that helps the user to navigate through document content rather searching for specific keyword or information. Safety intensive industrial sectors such as Aviation industry, Oil and Gas are already adopting the document engineering concepts in their technical documentation. It is proven in many organizations that the usage of document engineering concepts simplifies the document complexity and the end users feel much comfort in understanding the documents in their work.
In this paper an attempt has been made suggest adoptable user engineering concepts to simplify technical HSE documents. Also, the paper discusses some of the in-built hidden readability features in Microsoft word for checking reading ease and reading grade levels to improve simplification of documents. The paper discusses the psychological aspects behind document reading, understanding, cognitive linking for reaching the required information. Also, the paper discusses some of the best practices to be considered for technical document writers.
Evaluation of Hydrocarbon Producability Below FWL Onshore Abu Dhabi Oil Field Case Study
Authors: Eriavbe Francis , Vadakkeveetil Abdurahiman , Alkhatib Mohamad , Khattak Iftikhar , Lazar Raffik 
Published: December 2021

Abstract

Objectives / Scope
This paper addresses the field development planning challenges of a green onshore South East Abu Dhabi oil field with limited production data. Tectonic movements have created strike slip faults dissecting the structure and uplifting the main body. Tilting of the flanks has resulted in the accumulation to leak some of its initial hydrocarbon and a rebalancing showing a titled FWL.
A novel workflow was used to address the challenging reservoir physics including hydrocarbon below FWL. The paper takes a holistic approach in integrating multiple domains data such as Drilling, Petrophysics, Geology and Reservoir / Production Engineering.

Methods, Procedures, Process
An integrated approach was adopted to address the complexity and challenges of characterizing and modelling the field with hydrocarbon below FWL. Extensive range of data was collected to contribute to better understanding and evaluation of the field. The producibility of hydrocarbon below FWL have a significant impact on field development planning.
The used workflow was specifically suitable to drive subsurface team right reservoir characterization:
Improve fluid contacts understanding Explain the log responses The discrepancies between dynamic and static responses De-risk the volumetric uncertainties

Results
Following an extensive multi-disciplinary technical analysis of all available datasets, the most robust, accurate and reliable reservoir characterization, that can be seamlessly integrated into dynamic reservoir modelling phase.
A systematic approach was adopted starting from core measurement and lab visits, drilling data such as mud logs, Petrophysical evaluation of multiple complex physics such as hydrocarbon presence below FWL, micro porous intervals, Micritic minerals and imbibition effect, geological regional understanding of faulted reservoirs, and dynamic data such as formation well tests.
The study demonstrated that multi-domain integration played a key role in addressing the complex and challenging reservoir dynamics.

Novel / Additive Information
Large subsurface uncertainty combined with an extensive domain integration required cutting-edge reservoir de-risking and data gathering to provide the optimal reservoir characterization. These unique workflows can be readily used in similar green fields and will be described in full details in the paper.
Enhance the Plant Operating Capacity - Maximize the Revenue/Asset Utilization
Authors: Javed Atif 
Published: December 2021

Abstract
To explore the opportunity for maximum utilization for a Sales Gas Compression Facility (SGCF) in line with ADNOC strategy to enhance profitability and asset utilization. A technical study was conducted to increase the processing capacity up to 133% of its design limit by utilizing the available design margins. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options (if bottlenecks are there).
The Technical study covered the following activities:
Simulation:
Process simulation was performed and H&MB (Heat and Material Balance) was generatd.
Engineering: Compressor adequacy checks on increased plant throughputs. Static Equipment rating and adequacy checks performed with the concurrence of original equipment menufacturerers. Line sizing adequacy checks and detailed evaluation of the piping. Adequacy check for In-line instruments like control valves, flow elements/transmitters (Note 1) Relief, blowdown and flare system adequacy check. Utilities adequacy checks. Risk assessment workshop was conducted before the capacity test run. Preparation of Test Run procedure before the actual test run. Actual plant capacity test run to verify the study findings.
Note 1: Adequacy check of thermowells had been peformed separately prior to the study. It had already been established that the thermowells were adequate for the increased plant throughputs.
The study has concluded the following observations for processing 133% of the design capacity
Theoratically, the Sales Gas Compression Plant is adequate to handle the sales gas throughput up to 600 MMSCFD (2 running machines) considering the facts that Sales Gas Compressor suction pressure must always be kept at 32 barg through close monitoring by the operaters.If compressor suction pressure starts dropping below 32 barg, the study outcome would no more valid and the plant throughput would be reduced back to the original design capacity of 450 MMSCFD.
Moreover, it was recommended to perform a field test run to validate the study outcome by following the Manageement of Change Procedure as applicable.
Based on the successful 48 hours test run, it was established that the facility could handle the increased plant throughput of 600 MMSCFD by following the instructions given in the adequacy study.
Zohr Field Process Safety Operative Self-Assessment
Authors: Lisandrelli Vincenzo , Pozzi Niccolo' 
Published: December 2021

Abstract
Zohr field has developed a smart tool for the Process Safety compliance self-assessment. Scope of the tool is to evaluate field Process Safety Management system performance as well as driving a step change in field culture by making Process Safety a transversal target for all departments, not only HSE.
To reach this scope, an internal Field multidisciplinary team has been created with the scope to verify the Process Safety pillars compliance through a simplified check list and scoring model.
The initial 8 key elements are:
ESDs Alarm management Safety Critical Elements Overrides Loss of Primary Containment Management of Change Permit to Work Manuals/Procedures
For each elements a weighted scoring model from 0 to 5, composed by multiple questions, has been defined; a detailed guidance is supporting and assisting the team during the assessment.
Once completed the scoring model a traffic lights system integrated with a spider diagram will automatically represents the field compliance with the elements.
A quick and immediate graphic representation identifies then the main gaps for each elements.
Based on those results the multidisciplinary team defines an Action Plan to be addressed to the relevant dpt for improvement and follow-up.
The assessment frequency has been set to 6 months and the multidisciplinary team is appointed on rotation basis by Zohr Field General Manager and the relevant Department General Manager.
The first PS self-assessment performed in Zohr in September 19 showed the PTW system and SCE management as the main points of strength while the Management of Change implementation and the ESD tracking as the elements to be improved.
In particular Zohr has already set a robust system for the PTW management through a dedicated technical process team SIMOPS and developed a robust override and leak management system across the related departments.
As all the plant modifications have been managed so far thorough a DCN (Design Change) System with project support, as action plan was foreseen to implement a dedicated system for the electronic management of the MoC.
The first assessment highlighted also the need to improve the actions monitoring to keep traced all the findings coming from the RCA of the plant ESD and PSD.
Moreover as additional benefit the interactive self-assessment tool effectively contributed to spread across all the departments the Process Safety terminology and culture in order to allow the team to get familiar with the pillars with a smart and user friendly approach.
Big Data Analytics Maximizes Value from Smart Well Completions
Authors: Al-Hajri Nasser M. , Javed Muhammad Imran , Barghouti Akram R. , Al-Shuwaikhat Hisham I. 
Published: December 2021

Abstract
This paper presents a workflow based on big data analytics to model the reliability of downhole Inflow Control Valves (ICVs) and predict their failures. The paper also offers economic analysis of optimum ICV stroking frequency to maintain valves functionality at the lowest possible cost to the oilfield operator.
Installing an ICV in a petroleum well is a costly process and is done by a drilling or workover rig. As such, maintaining a fully functional ICV throughout the lifecycle of a well is important to ensure proper return on investment. ICVs are known to malfunction if not periodically stroked/cycled. The action of stroking ensures that each valve opening is free from obstructing material that would prevent the ICV from operating between one valve opening step to another. When an ICV malfunctions, a costly functionality restoration operation is sometime required without guaranteed results. In other cases, the valve is declared no longer useful and the asset cannot be further utilized due to malfunction.
In this paper, an analytical decision making model to predict failures of ICVs is presented that is based on rigorous big data analytics. The model factors in the frequency of stroking before a valve fails. Then, an economic analysis accounting for the CAPEX & OPEX of an ICV is included to optimize the stroking frequency. The utilized techniques include ICV failure and stroking records and classifying the data into pre-defined criteria. Cumulative probability distribution functions are defined for each data set and used to generate failure probability functions. The probability equations are factored into an asset management cost scheme to minimize expected maintenance costs and probability of ICV failure.
The results of applying this novel methodology to any smart well clearly showed maximized ICV service life and proper return of investment. The results demonstrate that ICVs lifecycle was prolonged with low maintenance cycling cost. Methodologies similar to the one presented in this paper are true manifestation of the fruitful impact IR4.0 technologies have on oilfields day-to-day operations.